181 results about "Fluid property" patented technology

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.

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 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 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 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 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 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 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.

The present invention discloses a method, system, device, and medium for identifying fluids in low-contrast reservoirs, including: obtaining the true formation resistivity RT1D based on the resistivity curve from array sensing; obtaining the ratio coefficient Br of the true formation resistivity RT1D and the deep lateral resistivity RT; determining oil and gas layers and water layers by intersecting the logging acoustic wave time difference curve, porosity curve, and the ratio coefficient; obtaining the movable fluid T2 geometric mean based on the long nuclear magnetic resonance echo interval; and identifying the oil, gas, and water layers of the fluid based on the ratio coefficient Br and the movable fluid T2 geometric mean. The present invention uses the array sensing inversion formation resistivity and deep lateral ratio coefficient method, and the intersection diagram of the movable fluid T2 geometric mean and the array sensing inversion formation resistivity to comprehensively identify fluid properties, effectively solving the problem of identifying fluid properties in low-contrast reservoirs in coastal areas. The method of the present invention is simple, practical, highly operational, and has good application effects.

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

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.

The present application relates to the technical field of well testing analysis, and is a high-temperature and high-pressure deep well perforation early formation fluid property prediction method. The method is performed according to the following steps: establishing a fitting equation of the maximum value of the average density of the downhole mixture of the early production test of the high-temperature and high-pressure deep well of the tested oil in the research area and the static pressure gradient at the perforation section after the normal production test of the high-temperature and high-pressure deep well of the tested oil; establishing a corresponding relationship table of the static pressure gradient T at the perforation section of the high-temperature and high-pressure deep well and the formation fluid property; and obtaining the predicted formation fluid property of the to-be-evaluated oil well from the maximum value of the average density of the downhole mixture of the early production test of the to-be-evaluated oil well. The present application provides a high-temperature and high-pressure deep well perforation early formation fluid property prediction method, fills the blank of the high-temperature and high-pressure deep well perforation early fluid property prediction technology, and has the characteristics of simplicity, high efficiency, low cost, and high accuracy.

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.

The invention discloses a method and system for identifying fluid properties of a tight sandstone fractured reservoir, and the method comprises the steps: calculating neutron difference ratio evaluation indexes at different depths in a fractured reservoir section in a current well according to a neutron logging curve of a to-be-evaluated well in a target region, the neutron difference ratio evaluation index is a ratio of a first difference value to a neutron value at a corresponding depth, and the first difference value is a difference value of the neutron value at the corresponding depth and a neutron standard value of a compact layer section in the well to be evaluated; and according to the neutron difference ratio evaluation indexes under different depths, utilizing a pre-constructed fracture section gas-water layer division standard to identify fracture reservoir fluid properties of different depth sections. The problems that the resistivity of a crack section is reduced and fluid identification is difficult due to mud invasion and leakage are solved, the geological requirement is met, and the actual application effect is good.

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.