215 results about "Reservoir fluid" patented technology

The invention relates to an array electric imaging logging based reservoir oil-water identification method and system. Aiming at the resistivity distribution characteristics of mud-invaded formations, a 'five-parameter formation model' is established, which is adapted to the requirement for simulating the resistivity distribution characteristics of different mud types and different invaded formations, and is pioneering in the aspects of forward-inversion models and processing methods of array electric imaging logging; and based on a 'five-parameter inversion' method for array electric imaging logging, an operation of carrying out resistivity distribution profile reconstruction on mud-invaded formations is performed, which reflects the actual differences between different resistivity distribution characteristics or change rules of mud-invaded oil formations or water formations. The method has stronger practicability, and is pioneering in the actual application aspects of qualitative identification and quantitative calculation on reservoir fluid properties.

The invention relates to the technical field of oil and gas geophysical exploration, and particularly discloses a tight sandstone gas reservoir fluid mobility gradient attribute prediction method and system.The method comprises the steps that a reflection coefficient expression containing a fluid mobility item is constructed, and a formula for calculating fluid mobility through frequency dispersion attributes is deduced; constructing a fluid mobility gradient attribute related to the frequency and the incident angle of the seismic wave; the method comprises the following steps: establishing a double-pore rock physical model, generating a synthetic seismic record, applying frequency variation AVO inversion to the synthetic seismic record, and extracting a bulk modulus dispersion attribute and a shear modulus dispersion attribute; and calculating the fluid fluidity changing along with the frequency and the incident angle, and calculating the gradient attribute of the fluid fluidity based on a gradient attribute calculation formula and the fluid fluidity. According to the method, seismic wave frequency dispersion and attenuation response caused by permeability and gas saturation are fully utilized, the seismic gradient attribute of the fluid fluidity and the calculation method are constructed, and high-precision prediction of the fluid fluidity by applying seismic signal elasticity and frequency dispersion rock physical information is realized.

The invention relates to the technical field of oil and gas field development, in particular to an ultra-deep gas well production string multi-mode leakage simulation experiment device and method. According to the technical scheme, the outer side of a shaft temperature and pressure coupling simulation system is connected with a reservoir gas supply simulation system, the middle of the shaft temperature and pressure coupling simulation system is provided with a multi-mode leakage simulation assembly, the lower end of a production oil pipe is connected with a reservoir-shaft coupling connector, and the upper portion of one side of a layered sand filling seepage tank of the reservoir gas supply simulation system is connected with a confining pressure loading unit through a pipeline; the lower portion of the layered sand filling seepage tank is connected with a reservoir fluid supply unit, and the outlet end of the layered sand filling seepage tank is connected with a reservoir-shaft coupling connector through a pipeline. The experimental device has the beneficial effects that the experimental device for coupling the reservoir and the shaft is constructed, and the multi-mode leakage simulation assembly is adopted to realize body perforation leakage simulation and screw thread sealing failure simulation, so that the simulation of the ultra-deep gas well under complex working conditions is realized, and a scientific basis and a technical support are provided for leakage prevention and control of a production string of the ultra-deep gas well.

The invention discloses a displacement potential energy gradient oriented injection-production reconstruction optimization method between fracturing segments, and relates to the technical field of oil and gas field development. The method comprises the following steps: firstly, establishing an oil reservoir three-dimensional numerical model according to oil reservoir interpretation data, simulating in an oil reservoir numerical simulator by using the oil reservoir three-dimensional numerical model to obtain a global pressure field and a fluid flow velocity change condition in the oil reservoir, constructing a fluid potential field model, and determining potential energy gradients among injection-production units; constructing an objective function and setting constraint conditions by taking the most balanced potential energy gradient distribution among all injection and production units in the fluid potential field model as an optimization objective, solving the objective function based on a particle swarm algorithm, and optimizing the horizontal well multi-stage fracturing inter-section injection and production scheme to obtain the optimal horizontal well multi-stage fracturing inter-section injection and production scheme. The control device is used for controlling the injection-production process device between the multistage seam sections of the horizontal well, quantitative characterization and active control of an oil reservoir fluid potential field are achieved, and a basis is provided for improving the injected fluid sweep volume and the crude oil recovery rate of an oil reservoir.

The invention discloses a high-pressure CO2 oil displacement micro-fluidic chip device which comprises an upper polar plate, a middle partition plate, a lower polar plate, a speed measurement module, a porous medium radial flow module and a liquid outlet module, the speed measurement module is arranged on the upper surface of the middle partition plate; the porous medium radial flow module and the liquid outlet module are arranged on the upper surface of the lower polar plate; the upper polar plate, the middle partition plate and the lower polar plate are sequentially stacked from top to bottom; the speed measurement module is connected with the porous medium radial flow module; and the porous medium radial flow module is connected with the liquid outlet module. According to the device disclosed by the invention, a pore throat structure in rock is simulated by constructing a micron-sized or even smaller complex flow channel, and the CO2 flooding crude oil flow characteristic and the CO2 distribution rule are simulated; a transparent visualization device structure is designed, and visualization of the action mechanism of the CO2 oil displacement system and the reservoir fluid distribution characteristics is guaranteed.

The invention provides an oil and gas reservoir fluid high-pressure physical property testing device and method, and belongs to the field of oil and gas field development, the device is composed of a constant temperature box, a PVT kettle body, a screw pump, a piston, a camera, a light source module and a stirrer, the PVT kettle body is placed in the constant temperature box, the PVT kettle body is made of a transparent material, a cylindrical inner cavity is formed in the PVT kettle body, and the screw pump is arranged in the inner cavity; a first guide hole and a second guide hole are respectively formed in the upper part and the lower part of the inner cavity to form a channel for fluid to enter and exit from the PVT kettle body, the piston is arranged in the inner cavity, the screw pump is connected with the piston, the stirrer is arranged in the inner cavity, the camera is arranged outside the constant-temperature box, and the light source module is arranged inside the constant-temperature box. The method is implemented through the testing device and comprises a high-pressure fluid sample transfer test and a single degassing test. According to the device and the method provided by the invention, the high-pressure physical property parameters of the fluid can be accurately measured by a small amount of samples, and key technical indexes are provided for oil-gas field development.

The invention provides a method for determining the pore diameter lower limit and the effective pore volume ratio of movable fluid. The method comprises the steps that the temperature of each sample under the stratum in-situ condition is calculated according to the ground temperature gradient and the burial depth; correcting the surface tension coefficient of the water by using the calculated temperature; determining an average contact angle of water and shale; calculating capillary force, enabling the capillary force to be equal to reservoir fluid pressure, and calculating the lower limit of the aperture of the movable water; carrying out carbon dioxide adsorption, liquid nitrogen adsorption and mercury injection experiments on the sample to obtain connectivity pore volume-pore size distribution, and calculating effective pore volume in combination with a movable water pore size lower limit; carrying out a low-field nuclear magnetic resonance experiment, calculating the total pore volume of macropores, obtaining the total pore volume of small pores in combination with a carbon dioxide experiment, and finally calculating the total pore volume; and calculating the pore volume ratio of the effective pores by using the pore volume of the effective pores and the total pore volume. According to the method, the evaluation precision of the lower limit of the pore diameter of the shale reservoir movable fluid and the pore volume ratio of the effective pores is effectively improved, and the test cost is reduced.

A reservoir fluid can be produced from a subterranean formation. The reservoir fluid can include water and hydrocarbons such as oil. It is oftentimes desirable to limit the amount of water that is produced, so a higher ratio of hydrocarbons can be produced. Portions of the subterranean formation can have an initial permeability to water. A relative permeability modifier (RPM) package including a surfactant and a polymer can be used in these portions to restrict or prevent water from being produced. The relative permeability modifier package can increase the hydrophobicity of the portion that allows the hydrocarbons to flow through while substantially limiting the amount of water. The relative permeability modifier can coat the surfaces of substances in the formation whereby the permeability to an aqueous fluid is reduced from the initial permeability. The formation can be a high-temperature formation of 230° F. (110.0° C.) or greater.

A method for acquiring the storage potential of a saline aquifer. The method comprises: acquiring the area of a research zone, the density of carbon dioxide under a stratum pressure, the thickness of an oil reservoir, the porosity of the oil reservoir, the irreducible water saturation of the oil reservoir, a reservoir fluid volume coefficient, a carbon dioxide storage efficiency factor, and stratum data; on the basis of the stratum data, determining estimated storage areas; on the basis of the area of the research zone and the estimated storage areas, determining a target storage area; and on the basis of said values, calculating a storage potential value of a saline aquifer in a target region. Further disclosed are an apparatus (400) for acquiring the storage potential of a saline aquifer, and an electronic device (500), a storage medium, a computer program product and a computer program.

This invention belongs to the field of seismic reservoir prediction and intelligent geophysical interpretation technology, specifically involving an intelligent reservoir prediction method for suppressing strong interference anomalies. The method first preprocesses seismic data and uses the generalized S-transform to obtain the time-frequency spectrum of the seismic signal. Then, based on the frequency component variation relationship, fluid flow properties are constructed to enhance reservoir fluid response characteristics and suppress strong response anomaly interference from non-reservoir areas. Furthermore, seismic data and fluid flow properties are jointly input to construct an intelligent reservoir prediction network based on a residual U-Net structure. Multi-scale feature extraction and fusion are achieved through an encoder-decoder structure and skip connections. Finally, the probability prediction result of the reservoir is output. This method can effectively fuse seismic structural information and fluid flow property information, improving the accuracy and stability of reservoir prediction under complex geological conditions, and has good generalization ability and application value.

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 provides a dense reservoir fluid identification method based on physical data double driving, comprising: performing abnormal value correction and fluid category direct marking on conventional logging data to obtain labeled logging data; performing signal self-adaptive time-frequency conversion on the labeled logging data, and calculating porosity, permeability and water saturation to output physical prior feature channels; inputting two-dimensional multi-channel time-frequency spectrum and the physical prior feature channels into a pre-constructed MDSC-TAM neural network model to extract hidden logging signal frequency domain spectrum series structure and global sedimentary rule to obtain a dense reservoir fluid identification result; and performing physical perception constraint and decision output on the fusion feature representation to obtain a fluid type and confidence. The application solves the data scarcity and model black box bottleneck, improves the engineering practicability of the algorithm, and realizes high-precision identification of the dense reservoir fluid and enhanced physical interpretability.

The invention relates to the technical field of oil and gas exploration, and discloses a device and method for quantitatively representing the occurrence state of oil reservoir fluid with ultrahigh precision, the device comprises a test module, the test module comprises a plurality of flow modules and a plurality of simulation pieces, the simulation pieces are respectively arranged in the flow modules, and the simulation pieces are used for simulating different types of oil reservoirs; one end of the flowing module is communicated with the injection part, the injection part is used for injecting light crude oil, heavy crude oil and methylbenzene into the flowing module, and the other end of the flowing module is communicated with the fluid receiving device; the pressure and temperature adjusting system is used for adjusting the pressure and the temperature in the flow module; and the removing part is positioned on one side of the flowing module and is used for removing the residual fluid on the simulation part. The device has the functions of automatic cleaning, high temperature and high pressure and multi-condition combination, accurately represents the occurrence state rule of light oil and heavy oil in different types of oil reservoirs, and provides a theoretical basis for fluid mobility evaluation and development scheme optimization in the oil reservoir development process.

The application discloses a kind of visualization methods for microcosmic action mechanism of steam displacement heavy oil, which comprises: obtaining the porous structure information of rock sample;According to the structure information of rock sample, design pore network structure and make microfluidic chip;Build steam displacement heavy oil visualization implementation system, and adopt steam displacement heavy oil visualization implementation system to collect the phase distribution and temperature distribution of microfluidic chip in displacement process;Boundary extraction is carried out to experimental picture, and the dynamic change process of each phase in displacement process is obtained and the interaction relationship with temperature distribution change is obtained.The application designs pore network chip according to the pore structure information of rock sample, obtains the phase distribution and temperature distribution in displacement process, and is used to study the microcosmic phase distribution characteristics and temperature distribution characteristics of fluid in heavy oil reservoir reservoir, and then the microcosmic mechanism of reservoir fluid movement is explored, so as to provide a practical visualization method for the research of steam drive oil mechanism.

The invention discloses a hydrate-containing sediment exploitation fluid-solid output prediction method. The method comprises the following steps: carrying out reservoir mud and sand particle stress analysis; based on the moment balance principle, a judgment criterion of reservoir sand falling and migration under the hydraulic condition is established, and a reservoir mud and sand particle migration mathematical model is established in combination with reservoir mud and sand particle mass conservation; constructing a multi-field coupling model of hydrate reservoir fluid-solid output; discretizing the multi-field coupling model by adopting an unstructured grid technology, and carrying out decoupling solution by adopting an alternating iteration method; and on the basis of decoupling solution result data, a nonlinear mapping relation from the characteristic parameters to the gas production rate and the sand production rate is established by utilizing a deep learning model, a fluid-solid output prediction model is established, and accurate prediction of the gas production rate and the sand production rate is realized on the basis of the fluid-solid output prediction model. According to the method, the interaction mechanism between the gas production behavior and the sand production behavior of the reservoir can be disclosed more accurately, so that the fluid-solid production rule of the hydrate reservoir can be predicted more accurately.

The present application relates to oil and gas geophysical exploration technology field, specifically disclose a kind of tight sandstone gas reservoir fluid mobility gradient attribute prediction method and system, the method includes constructing fluid mobility term's reflection coefficient expression, and deduce the formula for calculating fluid mobility using dispersion attribute, construct and frequency and seismic wave incidence angle related fluid mobility gradient attribute;Establish double-pore petrophysical model, generate synthetic seismogram, apply frequency-variable AVO inversion to the synthetic seismogram, extract bulk modulus dispersion attribute and shear modulus dispersion attribute;Fluid mobility changing with frequency and incidence angle is calculated, based on gradient attribute calculation formula and fluid mobility, fluid mobility gradient attribute is calculated.The present application makes full use of the response of the seismic wave dispersion and attenuation caused by permeability and gas saturation, constructs the seismic gradient attribute and calculation method of fluid mobility, realizes the high-precision prediction of fluid mobility by applying the elastic and dispersion petrophysical information of seismic signal.

A conveyor for a sucker rod pump, for deployment downhole within a passage defined by an inner surface of a reservoir fluid conductor that is emplaced within a wellbore extending into a subterranean formation, for effecting production of reservoir fluids, comprising. The conveyor includes a rod configuration, and a guide configuration. The guide configuration is coupled to the rod configuration, and is defined by at least one protuberance. The protuberance defines an air foil shape.

The invention provides a rock water content obtaining method based on one-dimensional nuclear magnetism, pyrolysis and extraction experiments, and relates to the field of geological prospecting, the method comprises the following steps: extracting hydrocarbon-containing fluid in a rock sample by using an oil-water amphiphilic solvent; carrying out a rock pyrolysis experiment on the sample after extraction to obtain an extraction advance value, an extraction advance value and a post-extraction value, and calculating the hydrocarbon content of the sample; carrying out a one-dimensional nuclear magnetic resonance experiment of the pre-extracted sample to obtain a pre-extracted nuclear magnetic resonance signal; carrying out a one-dimensional nuclear magnetic resonance experiment on the extracted sample to obtain an extracted nuclear magnetic resonance signal; acquiring the fluid content of the sample according to the nuclear magnetic resonance signal before extraction and the nuclear magnetic resonance signal after extraction; and calculating the water content of the sample according to the hydrocarbon content and the fluid content. The technical scheme of the invention is suitable for reservoir evaluation, resource quantity calculation, reservoir fluid monitoring in the development process and other scenes.

A method of determining a validated vug interpretation log for performing a reservoir fluid flow simulation is disclosed. The method including obtaining a set of well logs from a wellbore, where at least one of the set of well logs may be used as a validating resistivity log, producing an initial vug interpretation log based on at least one of the well logs, and determining a scaled resistivity log from the validating resistivity log The method further includes determining a validated vug interpretation log based, at least in part, on the scaled resistivity log and the initial vug interpretation log; and performing a reservoir fluid flow simulation based, at least in part, on the validated vug interpretation log.

The application discloses a kind of fluid identification method and system of water-saturated hydrogen index contrast method, calculate reservoir matrix porosity;Electric imaging and double lateral data are combined to calculate rock fracture porosity, and sum matrix porosity to total porosity;Assume that bedrock reservoir pore is water-saturated, select the dynamic skeleton neutron value of the dense layer section of lowest porosity, high resistivity dynamic skeleton as fixed skeleton value, calculate the dynamic skeleton neutron value of the purpose layer in combination with total porosity;According to dynamic skeleton neutron value, calculate water-saturated hydrogen index of research interval;Water-saturated hydrogen index is compared with neutron actual logging value to calculate neutron difference value;In combination with gas production test data, the relationship between acoustic time difference and neutron difference value and the change relationship between matrix porosity and neutron difference value are analyzed using neutron difference value, and the relationship chart of quantitative identification gas-water layer is obtained.The method eliminates the influence of anisotropy, fracture occurrence and the like of bedrock lithology, highlights the characteristics of reservoir gas layer, and can more accurately identify the properties of reservoir fluid.

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.

The invention discloses a complex reservoir gas-bearing prediction method and device, electronic equipment and a medium. The method comprises the following steps: constructing a low-frequency velocity model based on seismic division; performing convolutional coding and decoding of the seismic data according to the unsupervised closed-loop convolutional network to obtain sparse representation of the seismic data; and based on the semi-supervised closed-loop convolutional network, intelligent inversion of sensitive parameters of the deep reservoir is carried out, and reservoir gas-bearing prediction is realized. According to the method, fluid prediction under the condition of few wells is realized, the method is a demand for complex reservoir exploration situation and a key step for well position arrangement, and the method is of great significance to complex reservoir fluid prediction and subsequent treatment.

The invention discloses a tight oil reservoir depletion type development wave and region evaluation device and method. The device comprises a tight oil reservoir simulation system, a horizontal well system, a pressure monitoring system and a production system, the tight oil reservoir simulation system comprises a reservoir simulation device and a fluid injection device which are connected. The reservoir simulation device can be filled with sand grains in a layered manner so as to simulate a target tight oil reservoir; the fluid injection device is used for injecting simulated formation water and simulated formation oil; the horizontal well system comprises a plurality of horizontal wells; each liquid production pipe is connected with a corresponding horizontal well outlet and is connected with a produced liquid metering device; the pressure monitoring system comprises a signal processor, a pressure sensor and a plurality of pressure probes; and the plurality of pressure probes are arranged in the reservoir simulation device. According to the device, the distribution rule of the sweep area can be identified according to the pressure change, the recovery ratio corresponding to the sweep area can be obtained, and therefore sweep area evaluation is achieved through physical simulation, and production guidance is provided for depletion type development of tight oil reservoirs.

A method for improving thin interbed oil reservoir fluid earthquake prediction precision relates to the field of oil exploration and development, and comprises the following steps: carrying out rock geophysical analysis through logging information, and screening earthquake attribute types sensitive to oil reservoir fluid; based on the sensitive attribute type, performing resolution enhancement processing on the seismic data to generate optimized seismic attribute data; stratigraphic slicing processing is carried out on the optimized seismic attribute data along a target horizon, and seismic fluid sensitive attributes are extracted; performing time calibration and regression modeling on the well logging fluid interpretation result and the seismic fluid sensitive attribute, and establishing a fluid distribution prediction equation; based on the fluid distribution prediction equation, seismic fluid sensitive attributes are converted into an oil reservoir fluid plane distribution diagram, and thin interbed fluid prediction is achieved.

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.

A kind of laboratory quantification permeation flow capacity device, comprising: displacement liquid filling bottle for filling displacement liquid, the top of displacement liquid filling bottle is erected with displacement liquid level gauge communicated with its cavity;Oil filling bottle for filling crude oil, the top of oil filling bottle is erected with crude oil level gauge communicated with its cavity;Permeation material holder, which includes holding cylinder, first push glass and second push glass are oppositely arranged in holding cylinder, the first push glass is fixedly connected relative to holding cylinder, the second push glass is axially movable relative to holding cylinder, glass gasket with aperture and permeation material fixed by glass gasket are arranged between first push glass and second push glass.The laboratory quantification permeation flow capacity device of the present application is simple and durable, and the operation method is simple, which provides test facilities for exploring the mechanism of reservoir fluid multi-effect synergistic oil displacement experiment, and enriches the test method for verifying the permeation capacity of permeation material.

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.

There is provided a system for producing hydrocarbon material from a subterranean formation. The system includes a separator for separating gaseous material from reservoir fluid obtained from the subterranean formation. The system is configured to mitigate interference to the separation.

A pressure-volume-temperature (PVT) system (100) for characterization of a reservoir fluid, includes: a temperature control unit (110); a sample cell (120) disposed inside the temperature control unit (110) for accommodating the reservoir fluid, the temperature control unit (110) includes a housing (112) and an interior chamber (114) defined by a space between the sample cell (120) and the housing (112); and a fluid supply unit (140) that provides a temperature control fluid to the interior chamber (114) to control a temperature of the sample cell (120). The fluid supply unit (140) includes a first container (142) providing a first fluid having a first temperature as the temperature control fluid for a first stage of PVT analysis and a second container (144) for providing a second fluid having a second temperature that is different from the first fluid as the temperature control fluid for a second stage for PVT analysis.

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.