46 results about "Pore fluid" patented technology

The invention relates to a method for quantitatively analyzing the evolution period of paleo-pore fluid in a sandstone reservoir, and belongs to the technical field of oil and gas reservoir exploration and development. According to the method for quantitatively analyzing the evolutionary period of the paleo-pore fluid in the sandstone reservoir, core samples with different oiliness are selected at a target position in a target interval of a research area, fluid activity periods are preliminarily analyzed, and then the core sample with the most fluid activity periods is selected as a standard sample; pore fluid evolution analysis can be carried out on a standard sample, the analysis process is shortened, and the precision of recovering pore fluid evolution is improved.

The invention provides a sodium ion specific fluorescence labeled transparent soil sample as well as a preparation method and application thereof, and belongs to the technical field of rock soil and geological engineering. The method comprises the following steps: firstly, sequentially carrying out hydrophilization treatment, solvent evaporation and dissolution on a sodion combined benzofuran isophthalate probe to obtain a probe mother solution; mixing the probe mother solution, a buffer solution, an inorganic sodium salt solution and a solvent to prepare a fluorescence labeling pore solution; and finally, mixing the sodium polyacrylate particles and the fluorescence labeled pore liquid, and performing vacuum saturation treatment to obtain the transparent soil sample. The transparent soil sample provided by the invention still keeps excellent optical transparency while having sodium ion specific response capability, so that a stable and reliable experimental medium is provided for in-situ, real-time and full-field observation of sodium ion migration.

The utility model provides a chromatographic column head with a pore fluid distribution cover, which comprises a column head bottom plate for storing and discharging liquid and a column head top plate covering the top of the column head bottom plate and used for injecting liquid and exhausting, and a water injection pipe for injecting water into the column head bottom plate is arranged in the center of the top of the column head top plate. A groove used for storing liquid is formed in the column head bottom plate, a plurality of liquid drainage holes communicated with the outside are formed in the bottom of the groove in an arrayed mode, a liquid distribution disc structure with the same projection area as the groove is arranged in the groove, and the liquid distribution disc structure is in an arc shape. The circle center of the liquid distribution disc structure and the axis of the water injection pipe are collinear, the liquid distribution disc structure comprises a water avoiding area arranged under the water injection pipe and a liquid distribution area arranged around the water avoiding area, and the area of the water avoiding area is larger than or equal to the projection area of an inner hole of the water injection pipe. A plurality of liquid separation holes are formed in the liquid separation area around the water avoiding area.

The invention belongs to the technical field of mineral calculation and reservoir evaluation, and particularly discloses an electric imaging logging mineral component quantitative characterization method based on porosity spectrum correction, which comprises the following steps: preprocessing original electric imaging logging data, and generating a high-density pixel image; performing probability density statistical analysis on the pixel value of each depth point in the high-density pixel image to obtain a pixel waveform spectrum; calculating the apparent porosity of each pixel point in the high-density pixel image to generate a pore spectrum; performing pore fluid influence correction on the original electrical imaging data based on the pore spectrum, performing image enhancement to generate a pure mineral pixel waveform spectrum, and performing equalization processing to obtain an imaging mineral probability map; according to mineral content data obtained through core XRD total rock analysis, an imaging mineral spectrum is subjected to quantitative calibration, and distribution cut-off threshold values and pixel point value ranges corresponding to different minerals are recognized and deduced. The method can effectively solve the calculation error caused by the influence of the traditional imaging mineral calculation fluid on mineral calculation.

The invention discloses a rock physical forward modeling method applicable to formation pore fluid of carbon dioxide, and relates to the technical field of petroleum and natural gas engineering. The method comprises the steps of firstly obtaining a carbon dioxide physical property constraint condition based on a state equation of carbon dioxide under a reservoir temperature and pressure condition, and then based on the constraint condition and according to logging information of a target well, core analysis and a laboratory test result, carrying out formation evaluation to calculate reservoir parameters. Then, based on reservoir parameters, the sandstone content is obtained through calculation, a rock physical volume model of a target well is constructed, and finally, based on the model, corresponding rock physical forward modeling is conducted according to different carbon dioxide saturations by means of the equivalent medium theory to generate stratum elastic attribute parameters. And the change relation between the corresponding saturation and the stratum elastic attribute parameters is quantitatively represented, so that the CO2 quantitative monitoring precision and reliability can be remarkably improved by comprehensively considering the special physical properties of CO2, the fluid replacement mechanism and the seismic wave propagation characteristics.

The invention discloses an organic matter identification method based on seismic wave dispersion, and relates to the technical field of petroleum geophysical exploration, and the method comprises the steps: obtaining a target pre-stack seismic trace set and matched logging data, building an underground medium initial model based on the kerogen content and elastic response characteristics in the logging data, and obtaining an underground medium initial model; a to-be-inverted parameter matrix and a reflection coefficient weight matrix of an incident angle are calculated through a Shaw reflection coefficient calculation equation, frequency-division seismic wavelets are generated through the high sensitivity of organic matter to transverse wave dispersion, and a positive operator is constructed in combination with the wavelets and the reflection weight matrix. A shear wave velocity dispersion gradient which is highly sensitive to organic matters and weak in response to pore fluid is used as a main control inversion parameter, a combined recognition constraint term is constructed by combining a longitudinal wave velocity dispersion gradient and attenuation spectrum morphological characteristics, and a spatial optimal solution of a forward operator and a seismic trace set is calculated through a minimization objective function. And quantitatively associating the spatial optimal solution with the geophysical response characteristics of the organic matters to generate an organic matter spatial distribution diagram of the target reservoir.

This invention relates to the field of experimental equipment technology, and particularly to an NMR combustion-explosion dynamic load multi-field coupling experimental device and method. The technical solution includes a control module, an impact module, a detection module, and a vibration reduction module; wherein, the control module includes an operating platform, a transmission line, an engine, a fuel tank, an oxygen tank, connecting pipes, a high-temperature resistant fuel nozzle, and a high-temperature and pressure resistant gas sealing pipe; the operating platform is located behind the engine. This invention achieves graded control of dynamic load through combustion-explosion-electromagnetic composite loading, integrates simultaneous detection of multiple physical fields such as nuclear magnetic resonance, acoustic waves, and resistivity, sets up multi-level vibration reduction and dissipation structures to absorb residual kinetic energy, adopts a high-temperature and high-pressure resistant sealing design to ensure safety, simulates ground temperature, ground stress, and pore fluid fields to reproduce the deep in-situ multi-field coupling environment, and is centrally controlled and automatically reset by the operating platform, thereby realizing a laboratory simulation of deep dynamic disasters with flexible and adjustable parameters.

The invention discloses a seismic reflected wave response high-fidelity forward modeling calculation method suitable for a deep saline water layer, and the method comprises the steps: S10, building a saline water layer pore fluid rock physical model according to the development characteristics of the saline water layer, and calculating the viscosity, density, longitudinal wave velocity and bulk modulus of the saline water layer pore fluid; s20, according to the development characteristics of the salt water layer, establishing a multi-scale rock physical model of the salt water layer to obtain an equivalent stiffness matrix of the salt water layer; s30, establishing a geology-earthquake forward modeling model; s40, calculating a salt water layer reflection and transmission coefficient matrix by using a propagation matrix method; and S50, calculating the reflected wave seismic response of the salt water layer. According to the method, seismic rock physical modeling and seismic forward modeling technologies are combined, the viscoelastic characteristic and the thickness of the salt water layer are considered, the actual geological condition is better met, the cost is low, the precision is high, the deep salt water layer seismic reflected wave response can be rapidly and accurately calculated, and theoretical support is provided for evaluation and optimization of the carbon storage space.

The present application relates to a method and system for determining the preservation effect of a sealed frozen core sample based on nuclear magnetic resonance re-saturation contrast, and belongs to the technical field of unconventional oil and gas exploration and development. The method comprises the following steps: first, obtaining and processing the sealed sample, performing a first T1-T2 two-dimensional nuclear magnetic resonance test after thawing, immediately performing re-saturation treatment, and immediately performing a second test after saturation; second, dividing each hydrogen-containing component fluid into regions and extracting signal amounts; third, calibrating the fluids of formation water, crude oil and dodecane, establishing a conversion relationship between oil-water hydrogen signal amounts and volumes, and then obtaining the oil-water volumes under sealed and re-saturated states; fourth, comparing the difference between the total fluid amount under the re-saturated state and the total fluid amount under the sealed state with the total fluid amount under the re-saturated state, and obtaining a ratio, which is defined as a re-saturation response coefficient, for quantitatively evaluating the preservation degree of the original pore fluid. The method can ensure the accuracy and reliability of the test results.

This invention provides a method for enhanced geological sequestration of carbon dioxide through self-emulsification. The method includes: establishing an injection well in a seafloor sedimentary layer; injecting a penicillin-based chemical agent and CO2 into the seafloor sedimentary layer through the injection well; the CO2 carrying the penicillin-based chemical agent and seawater fluid flowing within the sediments of the seafloor sedimentary layer, whereby the CO2 undergoes self-emulsification to form a water-in-water CO2 microemulsion; under the impetus of injection pressure and buoyancy, the mixed fluid containing the water-in-water CO2 microemulsion displaces pore seawater and diffuses within the seafloor sedimentary layer, achieving geological sequestration of carbon dioxide. This method, by injecting the penicillin-based chemical agent and CO2 into the target layer, enables the CO2 to undergo self-emulsification within the target seafloor layer, transforming the pore fluid into a water-in-water CO2 microemulsion with good dispersibility and stability, thereby improving displacement capacity and sweep range.

The application provides a shale pore fluid type and porosity determination method, device and medium. The method obtains nuclear magnetic resonance logging data of shale in a target interval, performs T2 spectrum component stripping processing on the data, obtains a plurality of corresponding nuclear magnetic resonance logging T2 sub-spectra, determines pore fluid type calibration characteristics according to differences in T1-T2 spectrum diagrams of shale with different clay mineral contents and under different core saturation states, calibrates the fluid type of the plurality of nuclear magnetic resonance logging T2 sub-spectra based on the pore fluid type calibration characteristics, obtains the fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum, and then determines the effective porosity and movable fluid porosity of the shale based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid type. The method improves the calculation accuracy of the porosity, and provides a simple and reliable method for fluid type discrimination and porosity calculation of logging that only measures one-dimensional nuclear magnetic resonance logging and has no coring nuclear magnetic resonance experiment.

The application provides a method for exploiting natural gas hydrate and sealing carbon dioxide. The method comprises the following steps: injecting nitrogen into a natural gas hydrate reservoir of an area to be exploited, displacing reservoir pore fluid, making natural gas hydrate decompose to generate natural gas, collecting output fluid of a production well of the area to be exploited; detecting the composition of the output fluid, and when the natural gas content in the output fluid is less than a set value, stopping the injection of nitrogen, injecting carbon dioxide into the natural gas hydrate reservoir of the area to be exploited, forming carbon dioxide hydrate in a natural gas hydrate cavity, and displacing reservoir pore fluid, and collecting output fluid of the production well of the area to be exploited; the above steps can be repeated. The method provided by the application integrates natural gas hydrate exploitation and carbon dioxide sealing, and has the advantages of safety and reliability, wide action range, high working efficiency and the like.

The invention provides a seismic wave dispersion and attenuation prediction method and related equipment, and relates to the field of geophysical fluctuation induced fluid flow. The method comprises the steps that based on the bubble vibration theory and a pore fluid seepage continuity equation, a target elastic modulus is obtained, and the target elastic modulus is an elastic modulus obtained after bubble vibration correction is added; fusing the target elastic modulus into a strain energy function of a classical pore acoustic elasticity theory to obtain the strain energy function; deducing to obtain a wave equation of the fluid saturated porous medium containing a small amount of bubbles under the action of pressure by combining the strain energy function, the kinetic energy function and the dissipated energy function; and solving the simplified wave equation through the plane wave to obtain the seismic wave speed and attenuation. According to the embodiment of the invention, the frequency dispersion and attenuation of seismic waves can be accurately predicted within a certain effective pressure range.

A workflow for data acquisition and processing to quantify immobile and producible fluids more accurately from log and core measurements is described. Also described are methods of reservoir characterization to distinguish producible from immovable fluids that use NMR measurements on core samples as endpoint references and calibration points for downhole logging. Endpoint signatures of pore fluids are easily identified by the NMR of core samples, thus providing more accurate results on formation fluid porosities and saturations from measured data.

The porous showerhead includes a porous top surface, a porous bottom surface, and a plurality of layers. The layers are stacked between the porous top surface and the porous bottom surface. The layers are arranged to be connected to a distribution plate of a showerhead assembly of a substrate processing system. An uppermost layer of the layers has the porous top surface. A bottommost layer of the layers has the porous bottom surface. Each of the layers contains particles that are partially melted to form pores. The pores of the layers satisfy at least one of lateral alignment with pores in one or more adjacent ones of the layers and fluid coupling with pores in one or more adjacent ones of the layers to provide extended pores. The extending pores extend from the porous top surface to the porous bottom surface.

This specification discloses a forward modeling method and apparatus for rock physics in time-lapse seismic monitoring. This involves determining an initial value S of the target fluid's saturation. G and change value ΔS G According to the initial value S G and change value ΔS G Determine the longitudinal wave velocity V in the target fluid; calculate the compressibility modulus M of the rock saturated with the pure target fluid based on the initial and varying values. G The saturated rock compressibility modulus M when the pore fluid does not contain the target fluid W Based on the compressibility modulus M of the rock saturated with the pure target fluid G The saturated rock compressibility modulus M when the pore fluid does not contain the target fluid W Calculate the compressibility modulus M of saturated rock after the target fluid saturation changes under high frequency conditions. ∞ Based on the compressibility modulus M of the saturated rock after the change in target fluid saturation under the aforementioned high-frequency conditions. ∞ The saturated rock compressibility modulus M after the target fluid saturation changes under the low-frequency conditions. F Calculate the attenuation model.

This invention proposes a corrosion-inhibiting polycarboxylate superplasticizer, its preparation method, and its application. The corrosion-inhibiting polycarboxylate superplasticizer is prepared by a ring-opening grafting reaction between an epoxy-containing polycarboxylate superplasticizer and triethanolamine borate. A functionalized framework is constructed using epoxy-containing monomers, and then corrosion-inhibiting groups are stably anchored to the molecular side chains through a nucleophilic ring-opening reaction, achieving molecular-level integration of water-reducing and corrosion-inhibiting functions. Through the directional adsorption of amino groups onto the surface of reinforcing steel to form a film, combined with the anodic passivation inhibition induced by borate, corrosive media are effectively isolated. Simultaneously, the released borate ions react with calcium ions in the pore fluid to form micro-precipitates in situ, filling capillary pores and significantly optimizing pore size distribution. This invention solves the problems of poor component compatibility and performance interference, significantly reducing the chloride ion permeability coefficient even at low dosages, and significantly improving the mechanical strength and durability of concrete. The process of this invention is simple, the reaction conditions are mild, and it is suitable for the protection of reinforced concrete structures in marine engineering and harsh environments.

The invention discloses a quasi-triaxial mud shale complex fracture conductivity testing device and method, and the device comprises a data monitoring and control system, and also comprises a quasi-triaxial stress loading system, a pore fluid saturation system, a temperature loading system, a fluid displacement system and a strain testing system which are respectively connected with the data monitoring and control system. A complex crack simulation system is arranged in the quasi-triaxial stress loading system; the quasi-triaxial stress loading system is respectively connected with the pore fluid saturation system, the temperature loading system, the fluid displacement system and the strain testing system. According to the method, the mud shale complex fracture flow conductivity damage rule under different geological conditions, different displacement fluid parameters and different stress conditions can be obtained, the optimal flow conductivity matching process scheme is formed, and reference is provided for optimizing the fracture structure and improving the fracturing construction process.

The invention particularly relates to a modeling and frequency response calculation method based on acoustic impedance characteristics of submarine sediments. The method comprises the following steps: firstly, acquiring basic physical parameters such as mineral composition, porosity, solid particle volume modulus, pore fluid volume modulus and density of the sediments; then carrying out weighted average on the multi-mineral components, and calculating to obtain an equivalent bulk modulus of the solid skeleton; further determining a low-frequency limit volume modulus and a high-frequency limit volume modulus by combining a Biot theory and a fluid-solid coupling acoustic model; on the basis, a frequency-dependent effective volume modulus expression is constructed, and the equivalent acoustic impedance under different frequencies is calculated according to the frequency-dependent effective volume modulus expression. According to the method, the influence of the multi-mineral composition of the sediment and the property of the pore fluid can be considered at the same time, and the frequency dependence characteristic is introduced, so that accurate modeling of the equivalent acoustic impedance of the seabed sediment is realized, and the method has the advantages of high theoretical accuracy, wide application range and high engineering realizability.

The application discloses a kind of suitable for deep brackish aquifer seismic reflection wave response high fidelity simulation calculation method, the method includes S10: according to brackish aquifer development characteristics, establish brackish aquifer pore fluid rock physics model, calculate the viscosity, density, longitudinal wave velocity and bulk modulus of brackish aquifer pore fluid;S20: according to brackish aquifer development characteristics, establish brackish aquifer multi-scale rock physics model, obtain brackish aquifer equivalent stiffness matrix;S30: establish geology-seismic forward modeling;S40: utilize propagation matrix method to calculate brackish aquifer reflection and transmission coefficient matrix;S50: calculate brackish aquifer reflection wave seismic response.The application combines seismic rock physics modeling and seismic forward simulation technology, considers the viscoelasticity characteristics and thickness of brackish aquifer, is more in line with actual geological conditions, low in cost, high in accuracy, can quickly and accurately calculate deep brackish aquifer seismic reflection wave response, provides theoretical support for the evaluation and optimization of carbon storage space.

The invention relates to a core pore fluid component identification and quantitative analysis method based on two-dimensional nuclear magnetic resonance, and belongs to the technical field of core analysis. The method comprises the following steps: acquiring core two-dimensional nuclear magnetic resonance spectrogram data; constructing a relaxation time matrix and a signal intensity matrix; calculating a relaxation time ratio matrix; based on a transverse relaxation time boundary and a ratio boundary, mapping the signal to nine fluid components such as clay bound water and adsorbed oil through a classification function; and quantizing the signal intensity of each component by using a Kronecker function, and finally calculating the relative content of each component. According to the method, fluid relaxation characteristic distribution of the T-Tspectrogram is covered by a seamlessly connected polygonal region, so that a signal blind area of a circular plate is eliminated, in-situ quantitative analysis of multi-component fluid in full-scale pores is realized, and high-precision data support is provided for oil and gas reservoir evaluation and development scheme formulation.

This invention discloses a nuclear magnetic resonance (NMR) method for measuring the solid phase deposition of crude oil in porous media, belonging to the field of oil and gas reservoir development technology. By using a single saturation of crude oil in a core sample and leveraging the characteristics of online NMR technology, the method employs a comparison of experimental and NMR measurements, along with a 1:1 standard line reference, to determine the standard echo interval T in the transverse relaxation time T2 measurement acquisition parameters. E This method directly measures the amount of solid phase deposition in pore fluids in situ, solving the technical problems of existing technologies that cannot maintain the original characteristics of the sample, effectively avoid the interference of solid skeleton response and solid phase deposition particles, and are difficult to measure the solid phase deposition content of active oil in situ. It achieves the technical effect of rapid, efficient and accurate measurement of the amount of crude oil solid phase precipitation in cores under specific temperature and pressure conditions. The method is reliable in principle, simple to operate and highly applicable, and the test results are accurate and reliable, making it more suitable for the fine characterization needs of complex oil and gas reservoirs.

The invention discloses a GLS-based vibroseis-near-surface unified modeling method, relates to the technical field of geophysical exploration and vibroseis, constructs a near-surface pore elastic model, and improves the interaction simulation precision among a heavy hammer, a substrate and pore fluid. According to the method, a generalized coordinate system based on a heavy hammer, ground and fluid displacement and velocity is used, an energy structure function constrained by a sweep frequency signal is established under the GLS theory, an Euler-Lagrange equation is substituted, and a kinetic equation considering near-surface pore structure characteristics is derived; and then solving the equation by adopting a Newmark-Beta method to finish the simulation experiment of the input and output signals of the vibroseis. According to the model, near-surface pore structure characteristics and a vibration energy attenuation mechanism thereof are fully considered, the modeling capability of an existing vibroseis system on porous medium response is remarkably improved, and a parameter matrix definitely represents the mass, rigidity and damping coupling relation of a heavy hammer, a base plate, a ground framework and pore fluid.

The application provides a carbonate fault opening and closing evaluation method based on mechanical analysis, and the evaluation method comprises the following steps: S1, obtaining interpretation results of a target layer and a fault; S2, obtaining a plane distribution map and occurrence information of the fault; S3, obtaining compression stress F y suffered in a vertical fault plane direction; S4, calculating the compression resistance F f of pore fluid in a fault rock fracture; and S5, calculating a fault sealing factor R. The carbonate fault section stress is quantitatively obtained, so that an evaluation index for fault opening and closing evaluation is provided, a more effective basis for carbonate rock oil and gas reservoir exploration evaluation is provided, and the analysis and research on the carbonate rock reservoir accumulation rule are facilitated, so that the drilling success rate is improved and the exploration risk is reduced.

The invention provides a transparent soil preparation method for visually simulating and demonstrating the melting and seepage process of ice-rich moraine soil, and belongs to the technical field of geotechnical engineering visual model tests. The preparation method comprises the following steps: preparing quartz glass particles; preparing a mixed liquid from white oil and n-dodecane; preparing a mixed liquid frozen block; preparing test soil from the mixed liquid, quartz glass particles and fused quartz sand; laying a test soil layer; laying a mixed liquid frozen block layer; repeatedly and alternately paving the test soil and the mixed liquid frozen blocks until the total thickness meets the test requirement; freezing at low temperature to obtain the transparent soil. The quartz glass particles, the fused quartz sand, the mixed liquid and the mixed liquid frozen blocks are used for simulating coarse gravels, sandy soil, pore fluid, buried ice and other components in the moraine-rich soil respectively, the refractive indexes of all the components are matched, and the technical problem that the melting and seepage process in the moraine-rich soil is difficult to visualize is solved; the method is of great significance to reveal a moraine soil internal structure degradation mechanism under the freezing and thawing effect.

The application discloses a deep high-temperature high-pressure dry hot rock seismic rock physics modeling method and system, relates to the field of seismic exploration, determines the mineral composition and content of the dry hot rock matrix, and calculates the elastic modulus of the dry hot rock matrix; the differential equivalent medium model is adopted to calculate the elastic modulus of the dry hot rock skeleton containing hard pores; the volume modulus of the rock skeleton of a rock sample under different pressure conditions is tested, and the effective pressure constant is estimated; based on the pore space stiffness theory, the elastic modulus of the dry hot rock skeleton containing cracks affected by pressure is calculated; the volume modulus of the pore fluid affected by temperature and pressure is calculated; and the elastic modulus and density of the dry hot rock containing fluid are calculated. The application quantitatively constructs the analytical relationship between the temperature and pressure conditions and the elastic response and the crack content, provides a theoretical model basis for seismic prediction of the physical property parameters of the dry hot rock reservoir, can significantly improve the seismic prediction precision and resource evaluation efficiency of the dry hot rock reservoir, and provides technical support for the exploration and development of the dry hot rock geothermal resources.

The invention discloses transparent soil as well as a preparation method and application thereof, and belongs to the technical field of rock-soil analysis. The fused quartz sand is used as a framework material of the transparent soil, compared with fumed silica, the fused quartz sand has higher transparency in pore fluid and has a refractive index similar to that of nanoscale fumed silica solid, and the fused quartz sand is used as the framework material, so that the strength of the transparent soil is improved, and the transparency of the transparent soil is not influenced; due to the high surface activity and thixotropy of the nanoscale fumed silica particles, a colloidal network can be formed in pore fluid to bond the fused quartz sand particles, and the effect of a cementing agent is achieved; n-dodecane and white oil are adopted to prepare a pore fluid, a gradient refractive index can be constructed, and the light transmission uniformity of a deep soil body is optimized.

The application discloses a shale pore fluid saturation, fluidity and pore wettability measurement method, relates to the technical field of shale oil exploration, and comprises the following steps: obtaining a shale oil sample to be measured, and obtaining a pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be measured; performing a preset extraction operation on the shale oil sample to be measured to obtain an extracted shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum; determining a T1 / T2 change rate of a relaxation peak peak value based on the two nuclear magnetic resonance spectra; determining a hydrogen component of the shale oil sample before and after extraction based on the T1 / T2 change rate, determining a target saturation based on the hydrogen component and a preset saturation calculation method; and determining the fluidity and wettability of the sample based on the target saturation, the T1 / T2 change rate and a preset property measurement method. The application utilizes a theoretical relationship between the calculated T1 / T2 change rate and the saturation of the obtained sample, obtains the fluidity and pore wettability of the sample, losslessly quantitatively represents various rock physical properties of shale, and improves the comprehensiveness and accuracy of the measurement result.

This invention relates to a method and system for judging the fluid preservation effect of sealed frozen cored samples based on nuclear magnetic resonance resaturation comparison, belonging to the field of unconventional oil and gas exploration and development technology. The method includes: First, acquiring and processing sealed samples, performing a first T1-T2 two-dimensional nuclear magnetic resonance test after thawing, followed immediately by resaturation treatment, and then immediately performing a second test after saturation; Second, dividing the fluid into regions and extracting signals for each hydrogen-containing component; Third, calibrating the formation water, crude oil, and dodecane, establishing the conversion relationship between oil-water hydrogen signals and volume, and then calculating the oil-water volume in the sealed and resaturated states; Fourth, comparing the difference between the total fluid volume in the resaturated state and the total fluid volume in the sealed state with the total fluid volume in the resaturated state, and defining the ratio as the resaturation response coefficient, used to quantitatively evaluate the preservation degree of the original pore fluid. This invention ensures the accuracy and reliability of the test results.

The application discloses an acid geological environment microbial induced calcium carbonate precipitation in-situ repair method and system, relates to the technical field of environmental remediation, and comprises the following steps: S1, detecting a microbial induced calcium carbonate precipitation (MICP) reinforced body eroded by an acid geological environment, and measuring the pH value and free calcium ion concentration of a pore fluid; S2, according to the pH value and free calcium ion concentration measured in S1, preparing a specific concentration of sodium carbonate solution as a repair liquid; S3, injecting or permeating the repair liquid prepared in S2 into the damaged MICP reinforced body, so that carbonate ions in the repair liquid and free calcium ions dissolved and released by acid erosion are mixed in pores, and the supersaturation of the solution is regulated; and S4, in the mixing reaction process. The application solves the structural failure problem caused by unstable crystal form in an acid environment in the prior art, and provides a green, efficient and long-acting in-situ self-healing repair scheme for mine tailings, acid slopes and eroded geotechnical engineering.