315 results about "Fluid property" patented technology

The invention relates to the technical field of numerical simulation, in particular to a grid model generation method for the fluid displacement process of well cementation engineering. The method comprises the following steps: acquiring geological data of a well cementation project area, and constructing an initial geological model; well cementation engineering design data are obtained, well cementation engineering topological structure modeling is carried out, and a well cementation engineering topological structure model is obtained; according to the initial geologic model and the well cementation engineering topological structure model, fluid dynamic simulation is carried out, and a fluid characteristic matrix is obtained; performing fluid displacement process simulation according to the fluid characteristic matrix to obtain fluid displacement process data; performing fluid displacement process optimization on the well cementation engineering design data based on the fluid displacement process data to obtain optimized fluid displacement process data, and performing resource allocation redistribution on the well cementation engineering design data according to the optimized fluid displacement process data to obtain optimized well cementation engineering design data. According to the invention, the accuracy of fluid displacement simulation can be improved.

The invention provides a pore-scale underground natural hydrogen migration and accumulation behavior prediction method, and belongs to the field of underground natural hydrogen exploration and exploitation. Comprising the following steps: reconstructing an underground porous medium according to a real geological structure image; establishing an empirical formula of fluid attributes such as wettability, interfacial tension and viscosity of the hydrogen-water-rock system and temperature, pressure, salinity and rock type; establishing a flow equation of the hydrogen-water two-phase system in the porous medium; after initial conditions and boundary conditions are determined, the initial distribution, migration and aggregation process of natural hydrogen in the porous medium is simulated; and after the flow is stable, a migration and accumulation image of the hydrogen-water-rock system and a hydrogen recovery rate change curve are obtained. The hydrogen-water two-phase migration-accumulation model constructed by the method is suitable for the characteristics of high density ratio and high viscosity ratio of hydrogen and water, and is good at treating a porous medium complex structure and identifying a hydrogen-water interface; and the method is oriented to a real underground reservoir, and is suitable for predicting the hydrogen-water-rock migration and accumulation process under no environmental factors.

A system for measuring changes in a fluid stored within a container is disclosed. The system may include a radio-frequency sensing element disposed externally on the container and configured to generate a signal indicative of at least one dielectric property of the fluid, wherein the fluid undergoes composition-based or environment-driven changes due to interactions with the container. In some aspects, a processing component generates an output representative of at least one time-varying fluid characteristic. In some aspects, the container is a wooden barrel with an interior surface adapted to impart flavor or chemical changes to the fluid. In some aspects, the fluid is a beverage including at least one of wine, beer, and distilled spirits, with the time-varying characteristic including a fermentation parameter that changes over time. In some aspects, the at least one time-varying fluid characteristic of the fluid includes at least one of fluid level or fluid volume.

The invention discloses a reservoir fluid identification method, device and equipment and a medium, and relates to the technical field of oil and gas field exploration. The invention provides a multi-level nested reservoir fluid identification method based on geological mode constraint for double-medium tight sandstone. For different reservoir types, a preset algorithm is utilized to fuse the comprehensive logging parameters and the proposed fluid sensitive factors suitable for the double-medium tight sandstone, and fluid discrimination parameters suitable for different reservoir types are constructed. On the basis, reservoir types are divided by comprehensively considering the coupling action result of the matrix and the tectonic fracture, the difference of fluid characteristics of different reservoir types is determined, and based on the classification constraint of a geological mode, the different reservoir types are divided, and the fluid type of the tight sandstone reservoir is identified by using an integrated identification model. Logging curve data for fluid identification are easy to obtain, the fluid identification precision is high, the identification efficiency is high, and the method can be widely applied to reservoir fluid identification of double-medium tight sandstone.

The invention discloses a multi-parameter distortion compensation method for a fractured rock mass seepage similar model test, and relates to the technical field of rock mass engineering physical model tests. The method comprises the following steps of: firstly, determining two constraint conditions that the fluid property is invariable and the gravitational acceleration is invariable, correspondingly selecting a basic physical quantity and extracting a core criterion; then analyzing three types of distortion sources of geometric dimensions, dielectric materials and boundary conditions, and establishing a distortion function according to result parameters of seepage flow velocity, seepage flow and seepage pressure; secondly, parameters difficult to control are selected as distortion items, parameters easy to regulate and control are selected as compensation items, the distortion items are substituted into a distortion function to obtain a distortion ratio, the optimal distortion ratio of the compensation items is solved based on a compensation balance formula, and the parameters are adjusted; and finally verifying the interval range of the actually measured distortion ratio. According to the method, the multi-source distortion coupling influence is accurately quantified, the compensation pertinence and precision are improved, operation is easy and convenient, universality is high, and reliable support is provided for underground engineering seepage research.

The invention relates to the technical field of oil field gas logging, in particular to a fluid property evaluation method based on factors representing gas logging total hydrocarbon form quality, which comprises the following steps of: 1, performing well depth homing on gas logging data in a research area according to lithology, drilling time and logging information, and dividing gas logging abnormal sections; 2, constructing a QTG representing gas logging total hydrocarbon form quality factor, and calculating a QTG value of a gas logging abnormal section; and step 3, analyzing data of a tested oil and gas well in the research area, and establishing a QTG discrimination standard for fluid property evaluation according to a characterization relationship between the characterization gas logging total hydrocarbon form quality factor QTG and an oil-gas-water layer. According to the method, the information contained in the gas logging total hydrocarbon form is fully excavated, the fluid property of the oil and gas well is rapidly, visually and efficiently judged on site, and effective technical support is provided for oil testing layer position optimization and regional exploration and development.

The invention belongs to the technical field of oil and gas field development, and particularly relates to an adaptive adjustment method and management system for perforation water control, and the method comprises the steps: obtaining oil layer geological parameters, fluid properties and water invasion condition data; constructing a dynamic model according to the oil reservoir data, performing analysis according to the dynamic model and the water invasion prediction model, and determining a water invasion risk level according to an analysis result in combination with a dynamic weight distribution algorithm; according to the water invasion risk level and the mining target, perforation parameters are optimized in combination with a genetic algorithm, optimized perforation parameters are obtained, and according to the optimized perforation parameters, a water invasion path is simulated in combination with environmental parameters and an ant colony foraging algorithm, and a corresponding water prevention and control strategy is formulated; and according to the water control strategy, monitoring the dynamic change of the oil layer and the water control effect, adjusting parameters and strategies in time, feeding back data, and updating the water control strategy knowledge base. Therefore, the problems of lagging risk assessment, extensive perforation parameters, single prevention and control strategy, lack of closed-loop feedback and the like in the prior art are solved.

The invention relates to the technical field of unconventional shale oil and gas resource exploration, in particular to a shale shear wave velocity estimation method considering clay directional arrangement influence. According to the technical scheme, a shale compaction model is constructed, a shale directional arrangement background medium is formed, an orientation distribution function is used for simulating the elastic tensor of the background medium under different directional arrangement degrees, and the anisotropic speed of the background medium is calculated; calculating a longitudinal wave speed and a transverse wave speed in an equivalent isotropic background medium according to the anisotropic speed, and then calculating a bulk modulus and a shear modulus of the equivalent isotropic background medium; and adding clay-related pores and sand-related pores into an equivalent isotropic rock matrix by using an Xu-White model to obtain a bulk modulus and a shear modulus of dry shale, and finally simulating the shear wave velocity of the shale under the influence of directional arrangement of the clay. According to the invention, a new rock physical model is established to simulate the influence of clay directional arrangement, pore morphology, mineral and fluid properties on longitudinal and transverse wave velocities in shale.

An autonomous inflow control device includes a body defining a cavity. An inlet is in fluid communication with the cavity. The inlet receives well fluids. A deflection surface within the cavity deflects the well fluids at an angle based on a predetermined fluid property range of the well fluids. An influx outlet is in fluid communication with the cavity. An actuation device is disposed in the cavity and based on the angle the well fluids deflect off the deflection surface, the actuation device moves between an open position and a closed position. In the closed position, the actuation device covers the influx outlet. In the open position, the actuation device exposes the influx outlet to direct a volume of water from the well fluids out of the cavity. An outlet is in fluid communication with the cavity to direct the well fluids out of the cavity.

The invention relates to a turbine blade cooling optimization method and device based on non-Newtonian fluid. Comprising the following steps: step 1, carrying out grid division and simulation processing on a three-dimensional geometric model of the micro-channel of the turbine blade containing a shear groove to obtain a simulation grid model; 2, on the basis of the simulation grid model, determining a non-Newtonian fluid constitutive model suitable for the simulation grid model, and associating the non-Newtonian fluid constitutive model to the simulation grid model to obtain a fluid characteristic grid model; step 3, calculating index data based on the fluid characteristic grid model and the target equation; 4, adjusting the structure parameters of the shearing grooves in the simulation grid model, repeatedly executing the step 1 to the step 3 according to the adjusted structure parameters of the shearing grooves, and recording index data corresponding to the structure parameters of each group of shearing grooves to obtain a candidate data set; and 5, selecting the structure parameter of the shear groove with the comprehensive optimal resistance performance and heat transfer performance from the candidate data set according to the index data, and taking the structure parameter as an optimized target shear groove parameter.

The invention relates to the field of flow measurement of electromagnetic flow meters, and particularly discloses an artificial intelligence-based flow prediction method of an electromagnetic flow meter, which comprises the following steps of: analyzing the influence of environmental conditions on a measurement result by acquiring environmental condition information of the electromagnetic flow meter for measuring the flow of a conductive fluid; obtaining fluid property information of the electromagnetic flowmeter for measuring the flow of the conductive fluid, analyzing the influence of the fluid property on a measurement result, obtaining surrounding magnetic field information of the electromagnetic flowmeter for measuring the flow of the conductive fluid, and analyzing the influence of a surrounding magnetic field on the measurement result; the correction amount of the measured data of the electromagnetic flowmeter for measuring the flow of the conductive fluid is further analyzed, the result of the electromagnetic flowmeter for measuring the flow of the conductive fluid is predicted, the influence of factors such as environmental conditions, fluid properties and electromagnetic interference on the measurement of the electromagnetic flowmeter is considered, and then the measured data of the electromagnetic flowmeter are calibrated and rectified. Therefore, the reliability and precision of the measurement result of the electromagnetic flowmeter are improved.

The invention belongs to the technical field of oil development, and particularly relates to a fracture-vuggy carbonate reservoir gas-driven reserve calculation method, which comprises the following specific steps of: obtaining an influence factor correction coefficient of a gravitational differentiation influence factor through a numerical simulation experiment; calculating the obtained gas drive reserve before correction of the actual oil reservoir; and correcting the pre-correction gas-driven reserves of the actual oil reservoir by using the gravitational differentiation influence factor correction coefficient to obtain the corrected gas-driven reserves and the corrected gas-driven degree of the actual oil reservoir. According to actual parameters of the reservoir and injection-production dynamic data simulation, a fine conceptual model is constructed to accurately represent reservoir and fluid characteristics, the influence of gravitational differentiation influence factors on reserve calculation is considered, and by introducing a correction coefficient, a gas-driven reserve calculation result better fits the actual condition of the fractured-vuggy carbonate reservoir, and the reservoir and fluid characteristics are accurately represented. And reliable basis is provided for oil reservoir development.

Methods and systems are disclosed herein. A method may include obtaining a well log of a well and obtaining a first fluid sample at a first one of the plurality of depths within the well. The method may include obtaining a second fluid sample at a second one of the plurality of depths within the well. The method may include determining a first fluid property from the first fluid sample and a second fluid property from the second fluid sample. The method may include determining a transform based on the first fluid property, the second fluid property, and the well log data. The method may include applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The method may include determining a subsurface development plan based on the first predicted fluid property.

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 reservoir fluid identification method and device based on nuclear magnetic resonance T2 spectrum cutoff value backward movement, and relates to the technical field of petroleum logging, and the method comprises the steps: determining T2 spectrum characteristics of a movable fluid according to the obtained production data of a target oil field work area and nuclear magnetic resonance logging data, determining a corresponding T2cutoff critical value based on the peak value of the movable fluid in the T2 spectrum characteristic; determining the target value of the movable fluid based on the maximum T2 value of the spectrum peak in the T2 spectrum characteristic and the T2cutoff critical value; wherein the target value is used for representing the oiliness of the reservoir; analyzing the target values of the movable fluids to obtain a limit value of the target values among the movable fluids; and identifying a target value of the to-be-identified reservoir fluid based on the limit value, and determining the reservoir fluid property of the to-be-identified reservoir fluid according to an obtained identification result. Therefore, the fluid property in the reservoir can be judged according to the nuclear magnetic resonance T2 spectrum.

A control system for controlling pressure of fluid within a wellbore includes a rotating control device (RCD). a distribution manifold, a choke and kill (CK) manifold, and a managed pressure drilling (MPD) manifold fluidly connected with each other, a sensor operable to facilitate fluid measurements indicative of a property of the fluid, and a controller communicatively connected with the distribution manifold and the sensor. The controller is operable to receive the fluid measurements, cause the distribution manifold to direct the fluid discharged out of the wellbore via the RCD to flow through the MPD manifold to thereby permit the MPD manifold to control the pressure of the fluid within the wellbore, and cause the distribution manifold to direct the fluid discharged out of the wellbore via the RCD to flow through the CK manifold to thereby permit the CK manifold to control the pressure of the fluid within the wellbore.

The invention discloses a tight sandstone shear wave prediction method based on a fluid saturation dual fracture coupling model, and relates to the technical field of earth exploration physics. According to the method, a saturated rock physical model containing two groups of vertical orthogonal fracture fluids is constructed based on a Chapman multi-scale fracture medium theory framework, and an inter-fracture fluid mass distribution function is introduced to construct a dual-fracture coupling model based on fluid saturation. According to the method, conventional logging information is used as prior information, a rock physical model is used as a drive, an actual longitudinal wave speed and a simulated transverse wave speed are used as nested constraint conditions, a transverse wave speed prediction objective function is constructed, the tight sandstone transverse wave speed and the reservoir multi-group fracture density are estimated, a simulated annealing particle swarm optimization algorithm is introduced, and the reservoir multi-group fracture density is predicted. And the global optimization capability and the local convergence efficiency are enhanced. According to the method, the shear wave velocity prediction error can be effectively reduced, meanwhile, reservoir microstructure parameters are provided, and effective support is provided for reservoir fluid property judgment, lithology accurate recognition and underground fracture system quantitative description.

The invention relates to the technical field of oil exploitation and processing, in particular to a logging-based two-dimensional nuclear magnetic resonance low-permeability conglomerate fluid property identification method, which comprises the following steps of: obtaining the sum of original fluid areas in an original state of a low-permeability conglomerate core through two-dimensional nuclear magnetic resonance; obtaining the sum of manganese-saturated fluid areas of the low-permeability conglomerate core in a manganese-saturated state through two-dimensional nuclear magnetic resonance; according to the sum of the original fluid areas of the low-permeability conglomerate core in the original state and the sum of the manganese-saturated fluid areas of the low-permeability conglomerate core in the manganese-saturated state, the remaining oil index of the low-permeability conglomerate is obtained; and determining the fluid property of the low-permeability conglomerate reservoir according to the remaining oil index of the low-permeability conglomerate. According to the method, the residual oil index of the low-permeability conglomerate reservoir is established in an intuitive representation mode, the calculation formula of the residual oil index is based on extraction of parameter characteristics in a two-dimensional nuclear magnetic resonance original state and a manganese-saturated state, and the low-permeability conglomerate fluid property can be effectively recognized.

The invention discloses a fluid identification method based on earthquake-electromagnetic combination, and aims to improve the identification precision of underground fluid, and the method comprises the steps: firstly, constructing and calibrating a forward model based on well data and a rock core experiment, and guaranteeing the theoretical support for the physical property of a stratum; afterwards, AVO inversion is carried out to obtain stratum elastic parameters, and meanwhile, electromagnetic inversion is utilized to obtain spatial distribution of resistivity. Afterwards, the elastic parameters and the resistivity obtained through inversion are substituted into a rock physical model, a joint objective function is constructed, and the difference between observation data and model prediction is quantified. And finally, through combination of global and local optimization algorithms, successive approximation to an optimal solution and inversion, lithology, porosity and fluid property parameters are obtained, fluid saturation is further deduced, and high-precision identification of the underground fluid is realized. The method can be widely applied to the geological engineering fields of oil-gas exploration, underground water resource evaluation and the like, and provides effective theoretical and practical support for accurate estimation of fluid saturation.

The invention relates to a device (1) and to a method for determining a property of a fluid using photoacoustic spectroscopy (PAS). The device (1) comprises a housing (2) which encloses a measuring chamber (3) for receiving the fluid, a radiation source (4) which is designed to generate a modulated electromagnetic excitation radiation for the fluid and emit same into the measuring chamber (3) comprising the fluid; a sound measuring device (5) which is designed in such a way that the sound measuring device can detect sound waves generated by the fluid in the measuring chamber (3); a control device (7) which controls the radiation source (4) in such a way that the excitation radiation is modulated with a frequency bundle having a plurality of narrow-band individual frequencies which are spaced apart from one another; and an evaluation device (6) which is designed to evaluate the detected sound signal of the sound measuring device (5) by determining the distribution of the various frequency values using a Fourier transformation of the signal and determining information about the property of the fluid therefrom. The device allows a very reliable conclusion to be made about the desired fluid property to be determined. The device (1) can obviate complex mechanisms for compensating for temperature fluctuations and fluctuations in the purity of the fluid and is therefore very cost-effective.

A control system for controlling pressure of fluid within a wellbore includes a rotating control device (RCD), a distribution manifold, a choke and kill (CK) manifold, and a managed pressure drilling (MPD) manifold fluidly connected with each other, a sensor operable to facilitate fluid measurements indicative of a property of the fluid, and a controller communicatively connected with the distribution manifold and the sensor. The controller is operable to receive the fluid measurements, cause the distribution manifold to direct the fluid discharged out of the wellbore via the RCD to flow through the MPD manifold to thereby permit the MPD manifold to control the pressure of the fluid within the wellbore, and cause the distribution manifold to direct the fluid discharged out of the wellbore via the RCD to flow through the CK manifold to thereby permit the CK manifold to control the pressure of the fluid within the wellbore.

The present disclosure relates to techniques for prediction of reservoir fluid properties of a hydrocarbon reservoir fluid, such as the density, the saturation pressure, the formation volume factor and the gas-oil ratio of the reservoir fluid. To predict the reservoir fluid properties, a model is generated by selecting a subset of available reservoir samples based on a degree of biodegradation of the samples, generating an input data set comprising input data and target data, the input data comprising measured or predicted mud-gas data; and generating a model using the input data. The application of this technique allows a continuous log of the selected property to be generated using mud-gas data collected during the well drilling process.

The invention relates to the technical field of uranium mineralization prediction, in particular to a uranium ore positioning method for oil and gas dissipation channel control, which comprises the following steps: for a drilling point preliminarily meeting a uranium mineralization standard, determining whether a temperature range of a gas generation threshold meets a mineralization achievement condition or not, and transferring a preliminary drilling area according to a fluid activity path; the direction of moving the preliminary drilling area is determined, and the initial drilling parameters are adjusted; fluid property classification is carried out, and it is determined that the uranium metallogenic potential of the paleoenvironment where the sample is located meets expectation or secondary analysis of the uranium metallogenic potential is needed when the sample is formed; determining composition characteristic types of the samples, judging whether the causes of the samples are related to biological action or not according to the proportions of the samples in different composition characteristic types, and adjusting a judgment standard for determining uranium mineralization potential; and when the uranium mineralization potential meets the expectation or the cause of the sample is irrelevant to the biological action, the coexistence of the uranium ore and the hydrocarbon inclusion is verified through drilling. According to the invention, efficient uranium ore positioning is realized by identifying the oil-gas dissipation channel and the associated ore control elements.

A kind of high temperature and high pressure conditions under the fracture of compacted rock permeation resistivity measuring device and method, including: core holder, fluid injection system, resistivity measurement system, pressure applying device and heating device;The device can be carried out under the condition of high temperature and high pressure simultaneously, simulate the fluid permeation process of fractured rock under different temperature and pressure conditions, wherein resistivity measurement system can measure the rock resistivity of permeation process in real time.The device has high measurement accuracy, the test result is intuitive, the device structure is simple, the sealing property, corrosion resistance and heat insulation effect are excellent, can be applied to rock fracture permeation resistivity measurement under different conditions, can quantitatively analyze the influence of temperature, pressure, fluid properties and rock fracture on rock permeability and resistivity, establish the mathematical model of the relationship between permeability and resistivity of fractured rock, can provide theoretical basis for geothermal development reservoir permeability resistivity prediction and evaluation.

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 relates to a low-permeability oil reservoir channeling control oil displacement strategy obtaining method based on pore network simulation. The method comprises the steps that a three-dimensional pore structure of a core sample is obtained, a pore network model is established, multiphase fluid numerical simulation is conducted, and relative permeability parameters of an oil reservoir are determined; original data of the block oil reservoir are obtained, a three-dimensional geologic model is constructed, and relative permeability parameters are imported; geologic features, fluid properties and production history of an oil reservoir are considered, a well pattern injection-production mode and the optimal positions of an injection well and a production well are determined through the three-dimensional geologic model, and an injection-production scheme is formulated; through numerical simulation, based on sensitivity analysis, sensitive factors influencing the recovery degree are screened from engineering factors and geological factors; through numerical simulation, the recovery degree of each stage is used as an evaluation index, and sensitive factor parameters are optimized; and generating an oil displacement strategy based on the optimized sensitive factor parameters. According to the method, the relative permeability parameters are obtained in a simulation mode, then the oil displacement parameters are optimized through simulation screening, and the recovery efficiency of the low-permeability reservoir is effectively improved.

The invention belongs to the technical field of unconventional shale oil and gas exploration and development, and discloses a shale reservoir physical property and oiliness controlled factor analysis method. Comprising the following steps: determining a reservoir classification standard through a one-dimensional nuclear magnetic experiment and a mercury injection experiment phase; and performing lithogenous phase statistics on the pore ratio and effective porosity controlled factor analysis. And analyzing fluid properties of different lithofacies based on two-dimensional nuclear magnetic oiliness explanation. And analyzing oiliness controlled factors. By analyzing the controlled factors of the physical property and oiliness of the shale reservoir, the sweet spot distribution can be determined, the shale oil momentum can be determined, and the shale oil productivity can be improved.

The invention provides a rock sample pore wettability evaluation method, device and system and electronic equipment, relates to the technical field of reservoir evaluation, and aims to solve the problem that the wettability of different pores of rock cannot be represented. The evaluation method comprises the following steps: acquiring a first three-dimensional grayscale image of a rock sample in a normal state, a third three-dimensional grayscale image of a wet-phase fluid filled with a tracer agent in the rock sample, and a fourth three-dimensional grayscale image of the wet-phase fluid and a non-wet-phase fluid filled with the tracer agent in the rock sample; and determining the pore wettability of the rock sample according to the first three-dimensional grayscale image, the third three-dimensional grayscale image and the fourth three-dimensional grayscale image. According to the evaluation method provided by the invention, the high-resolution three-dimensional imaging technology is combined with the distribution of the interface form of multiphase fluid seepage in a stable state, so that the wetting state in each rock sample pore can be quickly evaluated one by one, and the evaluation method has important significance on exploring the influence of different wetting conditions on fluid properties.

The invention relates to a device 1 and a method for determining a property of a fluid by means of photoacoustic spectroscopy (PAS). The device 1 is provided with a housing 2 that encloses a measuring chamber 3 for receiving the fluid, with a radiation source 4 that is designed such that it generates modulated electromagnetic excitation radiation for the fluid and radiates it into the measuring chamber 3 with the fluid, with a sound measuring device 5 that is designed such that it can detect sound waves generated by the fluid in the measuring chamber 3, with a control device 7 that controls the radiation source 4 such that the modulation of the excitation radiation occurs with a frequency beam having several spaced-apart individual frequencies, and with an evaluation device 6 that is designed such that it evaluates the detected sound signal of the sound measuring device 5 by determining the distribution of the various frequency values ​​by means of a Fourier transformation of the signal and from this, information about the property of the fluid is determined. It enables a very reliable determination of the desired fluid property. This device 1 eliminates the need for complex mechanisms for compensating for temperature fluctuations and fluctuations in fluid purity, making it very cost-effective.

The invention provides a self-adaptive pressure compensation type oil-water separation control system for an oil well, and relates to the field of oil exploitation, and the system comprises a working condition sensing module which is used for collecting state data of an oil-water separation mixture; the working condition pre-judging module is used for identifying a current oil-water separation working condition and a fluid characteristic change trend; the pressure compensation module is used for determining an optimal pressure parameter based on the current oil-water separation working condition and the fluid characteristic change trend; the pressure regulation execution module is used for controlling the operation of the oil-water separation control system based on the optimal pressure parameter; the feedback calibration module is used for collecting the mixing uniformity of an oil-water separation mixture, the water content of separated crude oil and the oil content of water, and optimizing a time window for fluid characteristic change trend identification; and the multi-mode switching module is used for indicating the pressure compensation module to adjust the optimal pressure parameter based on the sand content data and the instantaneous flow data of the oil-water separation mixture, and has the advantage of improving the oil-water separation effect.