261 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 discloses a CO2 storage multi-field coupling safety evaluation method considering fracture evolution, and relates to the technical field of complex oil and gas reservoir development, and the CO2 storage multi-field coupling safety evaluation method comprises the following steps: s1, constructing and solving a multi-field coupling model; s2, virtual crack grid construction and expansion: according to the updated model stress field parameters, judging whether cracks are generated or not, and if so, constructing and expanding a corresponding virtual crack grid; s3, evaluating the integrity of the cover layer: after each time step is finished, evaluating the integrity of the cover layer; and continuing numerical simulation of the next time step until the simulation is finished. According to the method, comprehensive coupling of multiple physical fields such as crack generation and expansion, CO2 seepage, heat transfer between the injected CO2 fluid and the reservoir and between the injected CO2 fluid and the reservoir fluid, geological stress redistribution and the like in the CO2 storage process is fully considered, so that the spatial and temporal change of each physical field in the reservoir in the CO2 injection process can be truly represented, the simulation precision is greatly improved, and the simulation efficiency is improved. And the uncertainty caused by fixed parameters or simplified processing is effectively reduced.

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

The invention provides a tight oil reservoir fluid occurrence type identification method and system based on nuclear magnetic resonance, and belongs to the technical field of petroleum geology exploration and development. The method comprises the following steps: on the basis of comparison between a nuclear magnetic resonance T2 relaxation time cumulative distribution curve of a tight oil reservoir sample and a high-pressure mercury injection pore throat diameter cumulative distribution curve, dividing pore throat types, and converting T2 relaxation time into pore throat diameters; judging occurrence fluids in different types of pore throats through a nuclear magnetic resonance spectrum to obtain fluid occurrence types corresponding to different signal domain ranges, and calculating the relative fluid content of each fluid occurrence type; and based on the signal domain range of each fluid occurrence type of the plurality of samples, establishing a nuclear magnetic resonance fluid occurrence type identification chart, and defining an identification standard of each fluid occurrence type. According to the method, the pore size distribution of the T2 relaxation time is combined with the nuclear magnetic resonance spectrum, the pore size range corresponding to the fluid occurrence type is determined, and the relative content of the fluid is calculated through the signal intensity of each signal domain, so that the accuracy is higher.

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 geophysical exploration, in particular to a high-resolution seismic inversion recognition method for a thin and small reservoir of an oil reservoir. The method comprises the following steps: performing digital core model construction on a thin and small reservoir core sample to obtain a three-dimensional digital core model; carrying out multi-mineral component quantitative analysis on the thin and small reservoir core sample to obtain mineral components and distribution data; performing fracture geometric analysis on the three-dimensional digital core model to obtain fracture geometric analysis data; constructing a microscopic rock physical model according to the fracture geometric analysis data and the mineral composition and distribution data, and calculating physical model parameters to obtain microscopic rock physical parameters; and calculating matrix pore elastic parameters according to the microscopic rock physical parameters to obtain pore-containing dry rock elastic parameters. According to the method, the problems that a traditional method is low in resolution and influences of reservoir fluid and fractures are ignored are effectively solved, and high-precision recognition and fine description of the thin and small reservoir are achieved.

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

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 provides an intelligent oil reservoir simulation and safety prediction system. The system comprises a parameter setting module, a numerical simulation software generation module, an oil reservoir simulation and safety prediction module, an information interaction module, an application management module and a program modularization module, the parameter setting module is used for acquiring numerical simulation parameters set by a user from a user side and importing the numerical simulation parameters into the numerical simulation software generation module; configuring numerical simulation parameters in a human-computer interface in the parameter setting module, wherein the numerical simulation parameters comprise well, reservoir, fluid and well network parameters; the well network parameters comprise a well network type, a well group size, a well name and a well number, grid mapping of a well, a position of the well, a control radius of the well, a grid influence range of the well and yield data of the well; and the numerical simulation software generation module combines the obtained numerical simulation parameters with a preset parameterized model and an intelligent optimization algorithm through a neural network model after receiving the numerical simulation parameters.

The invention discloses a method and device for determining the position of a reservoir fluid channeling channel and a storage medium, and belongs to the technical field of oil and gas exploitation and carbon sequestration. The method comprises the steps that in the process of injecting preset gas into a target reservoir, it is determined that a channeling channel exists in the target reservoir; performing grid division on the region where the target reservoir is located to obtain a plurality of reservoir grid regions; acquiring a first reservoir gas flow rate and a first reservoir pressure value corresponding to the current time step of each reservoir grid region, and a second reservoir gas flow rate and a second reservoir pressure value corresponding to the previous time step of each reservoir grid region; and according to the first reservoir gas flow rate, the first reservoir pressure value, the second reservoir gas flow rate and the second reservoir pressure value, determining a target reservoir grid region covered by the channeling channel in the plurality of reservoir grid regions so as to obtain the position of the channeling channel in the target reservoir, according to the invention, the position of the channeling channel in the target reservoir can be accurately determined.

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.

The invention provides a method for identifying the water content of a reservoir based on light hydrocarbon logging. The method comprises the following steps: acquiring light hydrocarbon logging data of an oil and gas reservoir to be evaluated; selecting total hydrocarbon abundance, benzene and toluene / benzene in the light hydrocarbon logging data as light hydrocarbon parameters; establishing a two-dimensional atlas through the intersection of benzene and toluene / benzene in the light hydrocarbon parameters, establishing a three-dimensional atlas through the total hydrocarbon abundance and the change of benzene and toluene / benzene, dividing the boundaries of an oil layer, an oil-water layer and an oil-containing water layer, and quantitatively explaining and evaluating the fluid properties of the reservoir. According to the method, the light hydrocarbon logging technology is utilized, two-dimensional and three-dimensional interpretation maps are formed through intersection by selecting light hydrocarbon parameters such as total hydrocarbon abundance, benzene and methylbenzene, the interface and the water content of the reservoir fluid are quantitatively recognized, the coincidence rate of actual interpretation and evaluation of the reservoir fluid is increased, the exploration and development cost of an oil field is effectively reduced, and the purpose of improving the oil testing effect is achieved; the method is easy to operate, high in identification and evaluation accuracy, high in universality and wide in application range.

A system for generating electrical power may include a flowline having an inlet that receives reservoir fluid at a first pressure, an outlet that outputs the reservoir fluid at a second pressure, a first flow path between the inlet and the outlet, and a second flow path between the inlet and the outlet, in parallel with the first flow path. The difference between the first pressure and the second pressure may include a pressure differential, and the system may include a valve that adjusts the pressure differential. Additionally, the system may include a turbine disposed along the second flow path that generates mechanical energy from a flow of the reservoir fluid induced by the pressure differential, and the mechanical energy may be converted to electrical energy.

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.

There is provided a flow diverter for integration within a production string that is emplaced within a wellbore for effecting separation of reservoir fluid into gas-depleted reservoir fluid and gas-enriched reservoir fluid. The flow diverter is configured for, amongst other things, mitigating corrosion and erosion phenomena.

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.

The invention provides a CO2 migration and storage state monitoring method, system, medium and equipment, and belongs to the field of geophysics comprehensive application. The method comprises the following steps: firstly, respectively calibrating a target interval of CO2 sequestration through different observation systems, and analyzing a difference change range caused before and after CO2 injection through annular VSPs in different directions to obtain a migration boundary of a gas injection well; secondly, processing the ground two-dimensional seismic survey lines before and after CO2 injection by adopting the same processing parameters; and finally, performing qualitative analysis on the states before and after CO2 storage by adopting frequency attribute analysis and impedance inversion results, thereby realizing CO2 migration and storage state monitoring. According to the method, a CO2 monitoring closed loop is formed from collection to processing to explanation by adopting a geophysical monitoring means, and fluid migration and storage states before and after gas injection can be effectively compared by collecting changes of related attributes after reservoir fluid changes.

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.