117 results about "Fluid property" patented technology

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 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.

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 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.

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 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.

Embodiments herein relate to systems and methods for varnish detection and / or monitoring in hydrocarbon fluids. In various embodiments, a system for monitoring varnish compounds in fluids is included herein including a control circuit in communication with a fluid property sensor. The system can measure one or more fluid properties (such as dielectric constant, density, resistivity, viscosity and the like) with the fluid property sensor, monitor the same over a time period, and identify an occurrence of a rate of change in the measured property indicating a presence of the varnish compounds. In various embodiments, a system herein can be configured to measure a fluid property of a fluid with a fluid property sensor, monitor the fluid property value over a time period, and predict a time of the onset of varnish compound formation based on the trend of the fluid property value over time. Other embodiments are also included herein.

This invention discloses a method and apparatus for determining the tripping and running-in pressure in high-temperature and high-pressure wells, relating to the field of oil and gas drilling technology. The method includes: acquiring parameter data during tripping and running-in operations; dividing the well into grid nodes and obtaining the length of micro-segments based on a preset number of nodes and a preset well depth; determining the well inclination angle at the grid nodes based on inclination measurement data; and determining the tripping and running-in pressure under temperature-pressure coupling based on the mass conservation equation, momentum conservation equation, energy conservation equation, micro-segment length, well inclination angle at the grid nodes, and parameter data. This method considers the effects of high temperature and high pressure on drilling fluid properties, improves the accuracy of tripping and running-in pressure calculation, enhances the accuracy of wellbore pressure prediction, effectively meets the requirements for accurate control of tripping and running-in pressure in high-temperature and high-pressure wells, and ensures safe and efficient tripping and running-in operations. This invention can improve the accuracy of tripping and running-in pressure calculation and the accuracy of wellbore pressure prediction.

This invention discloses a method for characterizing the start-up pressure gradient based on heavy oil composition and reservoir pore structure, relating to the field of oil and gas field development technology. This method establishes multiple regression fitting formulas between different parameters and the start-up pressure gradient by considering reservoir microscopic and macroscopic properties, fluid properties, and component composition. These formulas include those for component, temperature, permeability, and start-up pressure gradient; pore radius, viscosity, and start-up pressure gradient; and formulas for component, temperature, pore radius, and start-up pressure gradient, meeting the needs for calculating the start-up pressure gradient using different parameters. To further refine the characterization of the start-up pressure gradient, the results of fitting formulas for different parameters are compared. A piecewise multiple regression fitting of the component ratio formula is proposed, using 0.50 mD / mPa·s as the dividing line. This results in high fitting accuracy, with the fitting curve closely resembling the measured data.

The application belongs to the technical field of oil exploitation, and discloses a high-temperature and high-pressure full-automatic CO2 flooding and burying integrated experimental device and method, which comprises a core clamping system for clamping a core sample, and a pressure measuring system and a confining pressure system are communicated on the core clamping system; a fluid injection system is communicated with the core clamping system; a fluid property measuring system for measuring fluid properties is arranged on the fluid injection system; an output product separation system is communicated with the outlet of the core clamping system through a back pressure adjusting system, and the output product separation system is communicated with a fluid recovery system, a fluid analysis system and a fluid circulation system; and an output product measuring system is communicated with the core clamping system. The application realizes automatic control of the whole set of equipment, is suitable for evaluation of carbon dioxide enhanced oil recovery and in-situ storage, and can also be used for experimental research on related problems such as natural energy depletion development, secondary and tertiary oil recovery, expands the research field and enlarges the application range.

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.

This invention relates to the field of petroleum exploration and development technology, and is a method and system for fluid property identification based on micro-fluorescence thin section technology. The method includes acquiring the micro-fluorescence thin section spectrum of a rock sample; obtaining the true fluorescence area under blue light and the true fluorescence area under ultraviolet light based on the micro-fluorescence thin section spectrum of the rock sample; substituting the true fluorescence area under blue light and the true fluorescence area under ultraviolet light into an extinction index model to obtain an extinction index; and comparing the extinction index with an extinction index evaluation standard to identify fluid properties. This invention establishes an extinction index for identifying reservoir fluid properties. Its extinction index model extracts the pair of sensitive parameters—fluorescence area under blue light and ultraviolet light—by utilizing the spectral variation characteristics between different crude oils and different proportions of water under micro-fluorescence thin section technology. This effectively solves the problem of reservoir fluid property identification, and the method can quantitatively identify reservoir fluid properties.

The present disclosure provides a fluid property measurement apparatus and a fluid property online measurement method. The apparatus includes: a testing cylinder provided with a fluid inlet and a fluid outlet; a liquid stabilizing mechanism including a pre-liquid delivery structure and a gas delivery structure, the pre-liquid delivery structure including a defoaming tank and a detachable pipeline connected thereto, the detachable pipeline being connected to the fluid inlet, and the gas delivery structure including a gas passage capable of injecting gas into the testing cylinder; and a measuring mechanism including a mass detector connected to a bottom of the testing cylinder and a liquid level detector connected within the testing cylinder. The present disclosure solves the problem of online measurement of drilling fluid density in the technical field of fluid measurement.

The application provides an oil and gas underground multiple twin body fusion method and a drilling track design adjustment method. The oil and gas underground multiple twin body fusion method comprises the following steps: obtaining a three-dimensional geological sub-model corresponding to a plurality of first moments based on a pre-constructed three-dimensional geological model; obtaining a three-dimensional oil and gas reservoir sub-model corresponding to a plurality of second moments based on a pre-constructed three-dimensional oil and gas reservoir model; obtaining a three-dimensional wellbore sub-model corresponding to a plurality of third moments based on a pre-constructed three-dimensional wellbore model; and fusing the three-dimensional geological sub-model, the three-dimensional oil and gas reservoir sub-model and the three-dimensional wellbore sub-model according to a spatial relationship to obtain a digital twin body of a target work area. For an oil and gas development area, the digital twin body can be used to output geological properties, fluid characteristics and wellbore data with time stamps according to specific scene requirements of engineering application, so as to achieve the final purpose of speeding up, improving efficiency, improving quality and increasing production.

The invention discloses a dolomitic mudstone reservoir fluid property determination method, device and equipment and a medium, and is applied to the field of exploration. The dolomitic mudstone reservoir fluid property determination method provided by the invention comprises the following steps: performing resistivity detection on a to-be-detected dolomitic mudstone reservoir to obtain a resistivity data set; determining a resistivity abnormal value according to the resistivity data set; determining a resistivity median according to the resistivity data set and the resistivity abnormal value; determining a reservoir space evaluation factor according to the resistivity median and the resistivity characteristic value; and comprehensively analyzing the reservoir space evaluation factor, the resistivity median and the resistivity characteristic value to determine the fluid property of the dolomitic mudstone reservoir to be detected. According to the method, the fluid property of the dolomitic mudstone reservoir to be tested is obtained by comprehensively analyzing and judging three groups of data including the obtained reservoir space evaluation factor, the resistivity median and the resistivity characteristic value, the problem that the fracture-cavity reservoir cannot be accurately evaluated by conventional logging information is solved, and effective and accurate evaluation of the reservoir space is realized.

The invention discloses an oil and gas distribution interpretation method and system, and relates to the technical field of oil and gas exploration and development technology data processing, and the method comprises the steps: calculating a plurality of Pickler ratios based on gas logging component data of a preset region, and further obtaining a DPR / RDPR series index; drawing a curve used for representing the relationship between the calculated DPR / RDPR series index and the depth; and determining an oil-gas distribution result of the preset area based on the drawn curve in combination with a relationship between oil-gas reservoir fluid characteristics and DPR / RDPR series indexes. On the basis of the prior art, the parameter of the DPR / RDPR series index is added, the oil and gas reservoir fluid property can be further quantified into the gas reservoir fluid characteristic, indication of the oil and gas reservoir fluid property is more convenient, direct and effective, and especially the indication effect of a natural gas enrichment layer section is more ideal.

A method for determining CO2 mass flow rate of a multi-phase fluid flowing in a pipeline (100) includes obtaining pressure signals from pressure sensors (302) flush- mounted on the inner wall of the pipe (301) that include a diaphragm (309) for sensing pressure. The pressure signals determine a first time-of-flight of flow eddies and a second time-of-flight of sound waves. Using the first and second time-of-flight, bulk flow velocity and mixture speed of sound is determined. Static pressure sensors (902) obtain a static pressure measurement and temperature sensors (902) obtain a temperature measurement. The static pressure and temperature sensors (902) are placed near the pressure sensors (302). A fluid composition sensor obtains fluid composition data. Based on the static pressure measurement, temperature measurement, and fluid composition data, single-phase fluid properties are determined. Based on the bulk flow velocity, mixture speed of sound, and single-phase fluid properties, CO2 mass flow rate of the multi-phase fluid is determined.

A system can determine a first control point and a second control point in a flowline. The first control point can be located at a first location adjacent to a device for injecting a pressure pulse in the flowline, and the second control point can be located at a second location. The system can determine, based on a distance between the first location and the second location, a sampling rate. The system can determine, based on data sampled in the flowline at the sampling rate, an acoustic velocity of fluid in the flowline. The system can provide the acoustic velocity to the device for transmitting the pressure pulse to facilitate generating and transmitting, based on the acoustic velocity, the pressure pulse into the flowline.

A flow control system for controlling multiphase formation fluid flow in a wellbore may comprise an electric submersible pump, an intake screen, a controller, a sensor, and a heating component, wherein: the intake screen comprises a shape memory alloy (SMA) mesh configured to perform a reversible modification between a first shape and a second shape; the sensor is configured to measure one or more fluid properties; the controller is communicably coupled to the sensor and the heating component and is configured to: determine whether the one or more fluid properties fall outside a predetermined tolerance at the controller, and actuate the heating component upon determining the one or more fluid properties fall outside the predetermined tolerance; and the heating component is configured to modify the SMA mesh from the first shape to the second shape when actuated, and thereby to control the multiphase formation fluid flow through the intake screen.

And measuring fluid characteristics. A method and apparatus for measuring characteristics of a fluid using an integrator connected to a central electrode of a contact conductivity sensor surrounded by an external electrode.

The invention discloses a graduated collection bottle for rapid comparative analysis of drainage liquid characters, and relates to the technical field of collection containers, the graduated collection bottle comprises: a collection bottle body, the interior of which is used for storing drainage liquid; the observation window is formed in the surface of the collection bottle body, and transparent glass is embedded in the observation window and used for observing the liquid level in the collection bottle body; the sealing mechanism is positioned above the collecting bottle body, is connected with the collecting bottle body and is used for sealing the interior of the collecting bottle body; according to the scale collection bottle, a self-negative-pressure system composed of the spring, the base and the connecting pipe can be driven by pressing the body with a single hand, air in the bottle is discharged firstly, then continuous negative pressure is generated by means of rebound, high-coagulation accumulated liquid is instantly pumped into the filter cartridge through the second one-way valve, and the liquid enters the observation cavity with the scales after primary filtration is completed; and synchronously, the rubber diaphragm adsorbs the table top to prevent toppling due to negative pressure of the base.

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 form identification method, device and equipment and a storage medium, and belongs to the technical field of oil and gas extraction. Based on the physical experiment data of the sample rock, a plurality of influence factors influencing the water layer resistivity and the oil layer resistivity can be accurately determined, so that the resistivity model (the first water layer resistivity model and the first oil layer resistivity model) can be established through multi-factor fusion, and the accuracy of the established resistivity model can be improved. The logging sensitive curve is determined on the basis of the first water layer resistivity model and the first oil layer resistivity, so that the resistivity model can be determined in a mode of combining physical experiment data and conventional logging information; therefore, the accuracy of the determined resistivity model (the second water layer resistivity model and the second oil layer resistivity model) is improved, and the accuracy of fluid property identification based on the resistivity model (the second water layer resistivity model and the second oil layer resistivity model) is further improved.

A method for determining a viscosity, and / or a property correlated with the viscosity, of a fluid of a fluid system, the method comprising: using a vortex flow sensor to obtain a plurality of measured values, the measured values being indicative of a degree of flow of the fluid; determining, from the plurality of measured values, a measure of dispersion of the measured values; determining the viscosity, and / or the property correlated with the viscosity, of the fluid from the determined measure of dispersion.

Measured values of fluid properties for oil, gas, and water at particular operating temperature and operating pressure in a pipe are used to develop fluid phase equilibrium model to calculate fluid properties at other operating temperatures and operating pressures in the pipe. The developed fluid phase equilibrium model is used to generate a fluid property look-up table that establishes correspondence between values of operating temperatures and operating pressures and values of fluid properties for oil, gas, and water. A flowmeter is configured to directly use the fluid property look-up table to measure flowrates of oil, gas, and water in the pipe.

The invention relates to the technical field of oil exploration and development, and discloses a compact sandstone calcite cement distribution prediction method, which comprises the following steps: S1, collecting and sorting basic data, and collecting regional geological background, logging, layering and core data; s2, sample selection and slice sample preparation: selecting a calcite development typical well, carrying out dense sampling according to a deposition cycle, and preparing a casting body, an inclusion and a laser microcell slice; s3, characterizing the characteristics of the calcite cement; s4, rebuilding diagenetic fluid properties and evolution processes; s5, reconstructing diagenetic environment properties and diagenetic system evolution; s6, diagenesis numerical simulation is carried out; s7, analyzing the cause mechanism of the calcite cement; and S8, establishing a calcite cement development mode. According to the method, lithofacies, in-situ micro-area geochemistry and diagenesis numerical simulation are deeply fused, the precision of compact sandstone calcite cement distribution prediction is remarkably improved, and a scientific basis is provided for favorable reservoir area optimization.

This invention belongs to the field of applied geophysical logging technology, specifically relating to a method for identifying low-resistivity oil layers based on time-frequency joint analysis. The method comprises the following steps: constructing a frequency-varying invasion factor based on multi-frequency array induced resistivity data at different times during drilling and after completion; constructing a time-varying dynamic index based on the frequency-varying invasion factor at different times during drilling and after completion; constructing a weighted dispersion index based on the time-varying dynamic index; calculating the average value of the time-varying dynamic index and the average value of the weighted dispersion index within the layer to be identified, comparing them with preset thresholds, and identifying the fluid properties based on the comparison results. This invention establishes a dual-verification identification mechanism for low-resistivity oil layers by integrating time-series evolution information and multi-frequency dispersion characteristics, and sets dual thresholds to improve the corresponding logging interpretation accuracy.

The invention discloses a quantitative identification method and system suitable for an ancient dolomite hydrothermal fluid source, and relates to the technical field of geological exploration, the method comprises the following steps: S1, multi-scale petrology determination of a hydrothermal fluid; s2, performing micro-area-element quantitative determination on the fluid components of the hydrothermal solution; s3, performing micro-zone-isotope quantitative determination on the fluid property of the hydrothermal solution; s4, quantitatively determining the temperature of the hydrothermal fluid; and S5, performing hydrothermal fluid event reduction based on absolute time limitation. Experiments are performed in combination with multiple scales and multiple methods, and the disadvantage that it is difficult to determine data anomalies is solved; the micro-area micro technology is emphasized, and errors caused by the fact that hydrothermal minerals in small adjacent periods are difficult to distinguish during conventional total rock quantitative analysis sampling are avoided; a dating technology is applied to obtain an accurate hydrothermal age, the accurate hydrothermal age is used as a limit, a regional geological background is traced back, a corresponding basin thermal event is reversely deduced through fluid activity time, and determination of hydrothermal fluid activity events and sources in the ancient dolomite is realized.