61 results about "Fluid saturation" patented technology

The invention relates to the technical field of geological reservoirs, in particular to a reservoir microcosmic connectivity characterization method based on pore throat boundary intelligent identification, which comprises the following steps of: performing threshold segmentation processing on a rock casting body slice by using image analysis software, and depicting partition images of pore throats and skeleton particles; based on the partition image, combining image analysis software to measure and extract the diameter, perimeter and area of the pore throat, and calculating quantitative parameters of the pore throat structure; constructing a one-dimensional Gaussian distribution model of the nuclear magnetic logging of the reservoir; based on a one-dimensional Gaussian distribution model, establishing a Gaussian collaborative factor for pore structure evaluation; based on the quantitative parameters of the pore throat structure and the established Gaussian collaborative factors, establishing a multi-factor evaluation mathematical method to establish a multi-element evaluation model of the pore structure; and performing multivariate nonlinear fitting on the porous structure multivariate evaluation model, the nuclear magnetic movable fluid saturation and the reservoir pressure measurement fluidity, and constructing a quantitative characterization model for characterizing the reservoir microscopic connectivity. According to the method, the microscopic connectivity of the reservoir can be accurately, rapidly and quantitatively evaluated.

The embodiment of the invention provides a surfactant synergistic flooding parameter optimization method based on core scale simulation, and the method comprises the steps: selecting a real core sample of a target oil reservoir, carrying out the preprocessing of the real core sample, and constructing a three-dimensional digital core model of the target oil reservoir; selecting a surfactant according to reservoir characteristics of the target oil reservoir; according to the synergistic flooding characteristic and the oil-water two-phase flow characteristic of the surfactant in the pore medium of the target oil reservoir, a surfactant synergistic flooding model under the rock core scale is established; carrying out iterative solution on the synergistic flooding model through parallel calculation to realize dynamic simulation of the synergistic flooding process under the rock core scale, and outputting distribution data of a pressure field, a fluid saturation field and a surfactant concentration field in the three-dimensional digital rock core model; and according to the distribution data, determining a target parameter combination for synergistic flooding of the surfactant. The effect of improving the use degree of crude oil is achieved.

Example methods and systems for wellbore fluid saturation mapping are disclosed. One example method includes obtaining, from a resistivity logging tool and during a process of drilling a wellbore in a reservoir formation, resistivity data of the reservoir formation in a first multiple azimuthal directions. Fluid saturation of the reservoir formation in the first multiple azimuthal directions is determined based on the resistivity data. A three-dimensional (3D) model of fluid saturation around the wellbore is determined based on the fluid saturation of the reservoir formation in the first multiple azimuthal directions. One or more steering commands for steering a drill bit during the process of drilling the wellbore is generated based on the 3D model of fluid saturation around the wellbore. A downhole drilling assembly is steered during the process of drilling the wellbore, based on the one or more steering commands.

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 discloses a shale oil reservoir CO2 huff and puff miscible-phase region dynamic discrimination method. The method comprises the steps that nuclear magnetic resonance testing is conducted on a target oil reservoir core sample; the method comprises the following steps: scanning a target oil reservoir core sample, constructing a three-dimensional core pore structure model, introducing nuclear magnetic resonance data to calibrate initial fluid saturation, and establishing a dynamic displacement numerical simulation model in combination with a CO2-crude oil phase equation, an interfacial tension model and a core permeability heterogeneity parameter; designing a plurality of groups of huff and puff experiments, simulating a CO2 injection process, monitoring nuclear magnetic resonance signal changes of the rock core in a displacement process in real time, correcting fluid saturation, a pressure field and interfacial tension parameters in a dynamic displacement numerical simulation model, and dividing a miscible-phase region; and selecting an optimal development parameter combination based on mixed-phase region distribution under different transfer injection opportunities, soaking time and throughput turns. According to the method, accurate division and dynamic discrimination of the CO2 huff and puff mixed-phase region are realized.

The invention relates to the technical field of shale exploitation, and discloses a shale reservoir wettability dynamic determination method, which comprises: S1, selecting a shale plunger core, carrying out supercritical CO2 cleaning and vacuum drying, and carrying out high pressure saturation by using simulated crude oil to obtain an initial oil saturation; and S2, the saturated rock core is loaded into a high-temperature and high-pressure rock core holder, and under the simulated formation temperature and pressure condition, simulated formation water containing the paramagnetic contrast agent is injected at the constant flow speed for displacement till the water content of the outlet end reaches 98%. According to the invention, dynamic and three-dimensional space representation of wettability is realized: three modal data of nuclear magnetic resonance, resistivity and sound wave are synchronously acquired in the displacement process, so that the limitation of a traditional static method is overcome, and the dynamic process of the wettability changing along with the fluid saturation state can be captured in real time; and finally, a high-resolution three-dimensional wettability distribution map is generated, and non-uniform distribution of wettability in the core is visually revealed.

Methods and systems are provided characterizing a formation traversed by a wellbore, wherein the formation includes at least a flushed zone and an uninvaded zone, which involve obtaining well log data based on plurality of different well log measurements of the formation at multiple depths in the wellbore. The well log data is used to a computational model that solves for a set of petrophysical parameters that characterize a portion of the formation corresponding to the multiple depths in the wellbore, wherein the set of petrophysical parameters include a cementation exponent, a saturation exponent, and a flushed zone water resistivity. The solved-for set of petrophysical parameters can be used to determine a value of water saturation of the uninvaded zone for the portion of the formation corresponding to the multiple depths in the wellbore.

The invention provides a horizontal well fluid holdup inversion interpretation method and system based on a complex impedance method, and relates to the field of fluid holdup inversion, and the method comprises the steps: obtaining complex impedance frequency spectrums of oil-water stratified flow under different holdups, and extracting characteristic parameters reflecting the water holdup; constructing a data set by using the simulation data, and performing fitting research by using an RBF neural network to obtain a relationship between the characteristic parameters and the water holdup; measuring the oil-water two-phase flow by using a fluid holdup measurement system developed based on a complex impedance method to obtain current data of the oil-water two-phase flow; and processing the acquired current data and extracting characteristic values, and performing inversion by using the trained RBF neural network to obtain the fluid holdup. The method has the advantages that the training set is established through simulation to train the neural network model, the oil-water two-phase flow holdup is measured through the fluid holdup measuring system developed on the basis of the complex impedance method, and reliable inversion explanation is provided for measuring the horizontal well fluid holdup through the complex impedance method.

The present disclosure relates to an experimental device and method for simulating shale oil elastic production and CO2 huff and puff, specifically by soaking the pressure-maintained sealed shale core in a simulation liquid to spontaneously escape gas, simulating the elastic production stage, then through the method of high-temperature and high-pressure CO2 huff and puff combined with nuclear magnetic resonance test, simulating the shale oil reservoir gas injection energy supplement production process after the end of the elastic production stage, through the above simulation, the component change of the gas produced by the core in different depletion development stages can be reflected, and the recovery degree of shale oil in the elastic development stage can be calculated, and the change of nuclear magnetic resonance T2 spectrum of shale before and after huff and puff can be tested in situ, giving the movable fluid saturation of shale, realizing the evaluation of the oil production capacity of shale under the original condition, thereby truly reflecting the oil production capacity of the shale reservoir, and effectively solving the problem that the existing technology lacks an experimental device and experimental method for simulating the whole life cycle of shale oil from elastic production to gas injection energy supplement production.

The present application relates to the technical field of reservoir evaluation in petroleum geological exploration and deposition reservoir, in particular to a method for calculating shale movable oil saturation based on nuclear magnetic-centrifugal principle, comprising: obtaining a sample after oil washing; based on real gas-oil ratio in the ground, using crude oil and natural gas to configure, obtaining configured crude oil; pressurizing and saturating the configured crude oil to obtain a saturated oil core sample; calculating the total pore volume V of the core under real underground temperature and pressure conditions; obtaining the total volume V1 of the saturated oil core sample under normal temperature and pressure, calculating the oil saturation S1 of the light hydrocarbon loss part under room temperature conditions; calculating the ground movable fluid saturation S2, and finally calculating the real movable oil saturation S of the shale. Through the method, the gas-oil ratio under the geological real conditions is recovered, the crude oil viscosity is reduced, the real situation is closer, the experimental error is minimized, and the calculation result is more accurate.

Implementations described and claimed herein provide systems and methods for developing a reservoir. In one implementation, a reservoir model is received. The reservoir model includes a static model and a dynamic model. The static model includes one or more clusters of a three-dimensional volume of the reservoir and an uncertainty quantification generated using a neural network. The dynamic model includes pressure values and fluid saturation values propagated across the three-dimensional volume through a nodal connectivity of neighboring clusters. A set of input features is generated from the static model and the dynamic model. The set of input features is related to a drilling attractiveness of a target region of the reservoir using a set of rules executed by a fuzzy inference engine. A quantification of the drilling attractiveness is generated. A recommendation for drilling in the reservoir is output based on the quantification of the drilling attractiveness.

A controlled rate of propagation of the fluid saturation front or thermal front is desired in may oil and gas and geothermal operations. Natural fractures and fractures created during hydraulic stimulation may have heterogeneous hydraulic properties resulting in uneven flow distributions, therefore leading to short-circuiting and breakthrough issues. The present invention relates to wellbores connected hydraulically by multiple fracture zones; methods are directed to control for even flow distribution among fractures, regardless of heterogeneities in fracture hydraulic properties, and to control propagation of saturation fronts and thermal fronts in subsurface reservoirs.

The application discloses a three-dimensional nuclear magnetic resonance rock sample fluid experiment analysis method and device based on a static gradient magnetic field, and the method comprises the following steps: performing fluid saturation treatment on a to-be-detected core, placing the treated to-be-detected core in a preset environment condition, and simulating fluid occurrence states in a reservoir under different diffusion time conditions; performing nuclear magnetic resonance experiments on the to-be-detected core based on the static gradient magnetic field at each diffusion time point, and collecting nuclear magnetic resonance echo data of the to-be-detected core at multiple different time points; performing three-dimensional inversion calculation on the nuclear magnetic resonance echo data, obtaining T1-T2-t three-dimensional distribution data, and performing visual analysis on the T1-T2-t three-dimensional distribution data, so as to represent the space-time variation characteristics of the reservoir fluid. The application combines the diffusion process of the fluid with the nuclear magnetic resonance T1-T2 distribution, forms three-dimensional nuclear magnetic resonance data, and can effectively capture the space-time variation of the complex fluid occurrence state in the unconventional oil and gas reservoir.

The invention discloses a fluid and pressure decoupling method and device in a time-lapse earthquake, electronic equipment and a storage medium. The method comprises the following steps: determining a longitudinal wave impedance difference body and a transverse wave impedance difference body of a research target region based on time-lapse seismic data of the research target region; substituting the longitudinal wave impedance difference body and the transverse wave impedance difference body into a first transformation formula to obtain a fluid saturation change attribute body, wherein the first transformation formula is a linear function between the first data and the target impedance difference value; substituting the longitudinal wave impedance difference body and the transverse wave impedance difference body into a second transformation formula to obtain a pore pressure change attribute body, wherein the second transformation formula is a linear function between second data and a target impedance difference value; and based on the fluid saturation change attribute body and the pore pressure change attribute body, identifying signals of fluid saturation change and pore pressure change of the research target region in the time-lapse earthquake. According to the scheme, effective decoupling separation of fluid and pressure signals of the target region in time-lapse earthquake can be realized.

The invention relates to a tight sandstone natural gas reservoir performance evaluation method and device. The method comprises reservoir classification evaluation and physical property lower limit evaluation. The reservoir classification evaluation is based on a high-pressure mercury injection curve form, a wide and gentle platform type is taken as a class I reservoir, a gentle platform type is taken as a class II reservoir, and a steep platform type is taken as a class III reservoir; the physical property lower limit evaluation takes a comprehensive physical property lower limit as a reference, and the comprehensive physical property lower limit is a weighted average value of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit and the fourth physical property lower limit; wherein the initial physical property lower limit is determined based on an empirical statistical method, the second physical property lower limit is determined based on a mercury injection parametric method, the third physical property lower limit is determined based on a nuclear magnetic resonance method movable fluid saturation method, and the fourth physical property lower limit is determined based on a movable fluid minimum pore throat radius. The method solves the problems that a traditional single method is large in physical property lower limit determination deviation and incomplete in classification evaluation, and provides technical support for efficient exploration and development of tight gas reservoirs.

A method for evaluating the reservoir pressure field during in-situ heated shale oil extraction is applied in the petroleum development field. The method comprises the following steps: ① Constructing a three-dimensional grid model of the shale oil reservoir between two horizontal wells; ② Evaluating the porosity of each reservoir grid unit after compression based on the temperature field, porosity, and volumetric thermal expansion coefficient of the reservoir skeleton; ③ Evaluating the volume of each fluid in each reservoir grid unit under constant pore fluid pressure based on the reservoir temperature field, fluid saturation, fluid thermal expansion coefficient, and natural gas solubility characteristics in oil; ④ Evaluating the pore fluid pressure in each reservoir grid unit based on the compressibility coefficient of each fluid at the corresponding temperature, combined with the reduction in porosity and the volume of each fluid after thermal expansion, thereby obtaining the pressure field of the shale oil reservoir.

The application provides a rock sample water content observation method and device. The rock sample water content observation method comprises the following steps: contacting a rock sample with a water sensitive test paper; collecting an image of a contact area of the rock sample and the water sensitive test paper, and calculating a total area S of the contact area; collecting an image of a color developing area of the water sensitive test paper, and calculating an area S1 of the color developing area; calculating a percentage of the area S1 of the color developing area to the total area S of the contact area, and analyzing water content of the rock sample according to the percentage. Compared with the prior art, the application utilizes sensitivity of the water sensitive test paper and convenience of image collection and processing, establishes a rock sample water content observation method suitable for a field, and has the advantages of simple operation, short observation period and intuitive observation result display, thereby providing a new means and method for reservoir fluid identification and evaluation. The method obtains a relative water content, and can be used for fluid saturation sample screening, comparison and analysis of water content of different rock samples and different layers, and provides a basis for formation fluid property evaluation.

Example methods and systems for wellbore fluid saturation mapping are disclosed. One example method includes obtaining, from a resistivity logging tool and during a process of drilling a wellbore in a reservoir formation, resistivity data of the reservoir formation in a first multiple azimuthal directions. Fluid saturation of the reservoir formation in the first multiple azimuthal directions is determined based on the resistivity data. A three-dimensional (3D) model of fluid saturation around the wellbore is determined based on the fluid saturation of the reservoir formation in the first multiple azimuthal directions. One or more steering commands for steering a drill bit during the process of drilling the wellbore is generated based on the 3D model of fluid saturation around the wellbore. A downhole drilling assembly is steered during the process of drilling the wellbore, based on the one or more steering commands.

This specification discloses a forward modeling method and apparatus for rock physics in time-lapse seismic monitoring. This involves determining an initial value S of the target fluid's saturation. G and change value ΔS G According to the initial value S G and change value ΔS G Determine the longitudinal wave velocity V in the target fluid; calculate the compressibility modulus M of the rock saturated with the pure target fluid based on the initial and varying values. G The saturated rock compressibility modulus M when the pore fluid does not contain the target fluid W Based on the compressibility modulus M of the rock saturated with the pure target fluid G The saturated rock compressibility modulus M when the pore fluid does not contain the target fluid W Calculate the compressibility modulus M of saturated rock after the target fluid saturation changes under high frequency conditions. ∞ Based on the compressibility modulus M of the saturated rock after the change in target fluid saturation under the aforementioned high-frequency conditions. ∞ The saturated rock compressibility modulus M after the target fluid saturation changes under the low-frequency conditions. F Calculate the attenuation model.

This application relates to a method, system, equipment, and medium for predicting non-metallic mineral resources based on seismic exploration. The method includes: acquiring current-temporal 3D seismic data and current hydrological monitoring data of the target mining area; obtaining seismic difference data based on preset benchmark 3D seismic data and current-temporal 3D seismic data; performing joint inversion on the seismic difference data based on current hydrological monitoring data and preset benchmark hydrological monitoring data to obtain fluid saturation change data; inverting the current-temporal 3D seismic data to obtain saturated rock elastic parameters; and performing fluid effect stripping processing on the saturated rock elastic parameters based on the fluid saturation change data and benchmark hydrological monitoring data to obtain dry rock elastic parameters; and obtaining a 3D prediction result of the mineral grade of the target mining area based on the dry rock elastic parameters and a preset mineral grade prediction model. This method can improve the accuracy of resource prediction results.

The embodiment of the invention provides a method, device and equipment for calculating the carbon burying stock of an oil reservoir, and relates to the technical field of oil and gas development and carbon burying, the method comprises the steps that the optimal development simulation scheme in multiple development simulation schemes of the oil reservoir is determined, and each development simulation scheme corresponds to one combination of multiple carbon dioxide composite steam injection parameters; obtaining development dynamic data of the oil reservoir under the optimal development simulation scheme; the development dynamic data at least comprise the sweep efficiency data of the carbon dioxide composite steam and the saturation data of the oil reservoir fluid; according to the development dynamic data, the carbon dioxide burying amount of the oil reservoir is calculated by using the multiphase carbon burying mechanism model; and the multiphase carbon burying model is coupled with the association between the oil reservoir development dynamic state and the multiphase carbon dioxide burying amount. According to the multiphase carbon burying mechanism model, the burying amount is associated with the sweep efficiency and the multiphase fluid saturation, supercomputing resources needed by all-component numerical simulation are abandoned, and low-cost and high-precision carbon dioxide burying amount calculation is achieved.

The invention discloses a fractured reservoir multi-parameter inversion method based on an improved grey wolf optimization algorithm, and relates to the technical field of seismic exploration, and the method comprises the steps: firstly constructing a multi-scale-multi-direction-multi-phase fluid plaque saturated coupling fracture rock physical model based on a Chapman multi-scale fracture theory; secondly, based on an anisotropic reflectivity theory, establishing a frequency and azimuth angle dependent PP wave seismic forward modeling method; and finally, providing an improved grey wolf optimization algorithm (GWO-G) based on a Gaussian threshold search strategy aiming at the nonlinearity and multi-extremum characteristics of an inversion problem, and verifying through three-parameter and six-parameter inversion experiments of a single-interface model under the conditions of no noise and containing 10% Gaussian noise. The method has the beneficial effects that key parameters such as the fracture density, the fracture scale, the porosity and the fluid saturation can be stably, accurately and synchronously inverted, and a powerful technical means is provided for fine description and efficient development of unconventional oil and gas reservoirs.

This invention discloses a method for dynamically identifying miscible regions in CO2 huff and puff of shale oil reservoirs, comprising: performing nuclear magnetic resonance (NMR) testing on core samples from the target reservoir; scanning the core samples to construct a three-dimensional core pore structure model, and importing NMR data to calibrate the initial fluid saturation; establishing a dynamic displacement numerical simulation model by combining the CO2-crude oil phase equation, interfacial tension model, and core permeability heterogeneity parameters; designing multiple huff and puff experiments to simulate the CO2 injection process, while simultaneously monitoring the changes in the core's NMR signal during displacement in real time, correcting the fluid saturation, pressure field, and interfacial tension parameters in the dynamic displacement numerical simulation model, and dividing the miscible regions; and selecting the optimal combination of development parameters based on the distribution of miscible regions under different injection timing, well shut-in time, and huff and puff cycles. This invention achieves accurate division and dynamic identification of miscible regions in CO2 huff and puff.

This invention provides an apparatus, method, and storage medium for measuring the three-phase fluid saturation of an oil and gas reservoir model, belonging to the field of oil and gas reservoir development technology. The apparatus includes a simulation device, a pressure chamber, and a control module. The simulation device is used to simulate formation water, formation oil, and injected gas in a target oil and gas reservoir to conduct oil and gas reservoir displacement simulation experiments on a physical model. The pressure chamber is used to hold the physical model and acquire monitoring data through its configured electromagnetic wave modulation and demodulation system. The control module is used to perform electromagnetic wave inversion on the physical model using the acquired monitoring data and an electromagnetic wave inversion method to obtain an inversion model of the target oil and gas reservoir, thereby monitoring the three-phase fluid saturation of the target oil and gas reservoir. This invention utilizes electromagnetic wave inversion technology to achieve real-time, rapid, and accurate determination of the three-phase fluid saturation of oil, gas, and water in two-dimensional and three-dimensional cores under high temperature and high pressure conditions without damaging the core.

The invention relates to the technical field of oilfield development, in particular to a method and system for rapidly predicting the spontaneous imbibition recovery ratio of a tight reservoir, and the method comprises the steps: constructing a control equation for representing the saturation degree of fluid in a matrix according to a current nonlinear seepage equation and a pressure-sensitive characteristic equation in combination with a relation of current capillary force and relative permeability changing along with the saturation degree; according to a current matrix internal fluid saturation control equation, initial conditions and boundary conditions are given, and fluid saturation distribution in the matrix blocks at different moments is determined; determining the average saturation of fluid in the matrix at different moments according to the saturation distribution of the fluid in the matrix block at different moments; and determining a change equation of the imbibition recovery ratio along with time according to the average saturation degree of the fluid in the matrix block at different moments in combination with an imbibition recovery ratio formula. According to the method, the stress sensitivity of the tight reservoir and the nonlinear seepage characteristics of the matrix are considered, the spontaneous imbibition rule of the tight reservoir can be accurately described, and dynamic productivity prediction and optimization evaluation of tight oil and shale oil are facilitated.

The disclosure presents processes to receive at least one set of ultra-deep resistivity data, and at least one additional set of measurements. The set of measurements can be resistivity data or other sensor measurements, for example, nuclear, magnetic resonance, seismic, acoustic, temperature, or pressure. The set of measurements can be data for which a relationship between the formation values and the formation porosity or fluid saturation exists. For example, acoustic or seismic compressional velocity, shear velocity, density or a ratio thereof such as acoustic impedance, compressional wave (vp) / shear wave (vs) velocity ratio, or other relationships. The processes can identify rock physics forward models to utilize as well as respective constitutive equations. Various inversion algorithms can be applied to the resistivity data and set of measurements to generate an inversion output. The inversion output can be utilized to determine subterranean formation characteristics, such as porosity, density, or fluid saturation.

This method for preparing a rock sample with a target initial first fluid saturation profile comprises:providing a rock sample saturated in a first fluid;primary flooding of the rock sample with a second fluid, comprising:feeding the second fluid in the rock sample from an inlet face, andretrieving first fluid and / or second fluid from a first open channel directly connected to an outlet face;secondary flooding of the rock sample with the second fluid, comprising:blocking the first channel;feeding second fluid in the rock sample from the inlet face, andretrieving first fluid from a second channel connected to the outlet face through a porous barrier element, the porous barrier element being permeable to the first fluid and impervious to the second fluid.

Methods for determining in situ the value of a formation fluid parameter using a downhole fluid analysis (DFA) tool. The methods utilize advanced statistical learning tools to build a predictive model to estimate a fluid property given a set of input parameters. In one embodiment the fluid saturation pressure parameter is determined by using the DFA tool to obtain the fluid and to obtain weight fractions of at least C1, C6+, and CO2 of the fluid. The weight fractions and a reservoir temperature are input into a trained statistical learning machine to obtain a determination of the saturation pressure of the fluid.

Implementations described and claimed herein provide systems and methods for developing a reservoir. In one implementation, a reservoir model is received. The reservoir model includes a static model and a dynamic model. The static model includes one or more clusters of a three-dimensional volume of the reservoir and an uncertainty quantification generated using a neural network. The dynamic model includes pressure values and fluid saturation values propagated across the three-dimensional volume through a nodal connectivity of neighboring clusters. A set of input features is generated from the static model and the dynamic model. The set of input features is related to a drilling attractiveness of a target region of the reservoir using a set of rules executed by a fuzzy inference engine. A quantification of the drilling attractiveness is generated. A recommendation for drilling in the reservoir is output based on the quantification of the drilling attractiveness.

The embodiment of the present application provides a shale oil reservoir wettability judgment method and device, and belongs to the technical field of oil and gas development. The shale oil reservoir wettability judgment method comprises the following steps: obtaining the intake rate and / or intake fluid saturation of a rock sample when the rock sample spontaneously absorbs fluid; judging the average wettability of the shale oil reservoir according to the intake rate and / or intake fluid saturation; judging the hydrophilic and oleophilic ability of the shale oil reservoir under the same pore radius according to the signal intensity increment S1 of the rock sample when the water-saturated state is compared with the dry state and the signal intensity increment S2 of the rock sample when the oil-saturated state is compared with the dry state; and judging the wettability of the shale oil reservoir according to the average wettability of the shale oil reservoir and the hydrophilic and oleophilic ability of the shale oil reservoir under different pore radii. The embodiment of the present application comprehensively judges the wettability of the shale oil reservoir by combining the average wettability and the hydrophilic and oleophilic ability of the shale oil reservoir under different pore radii, can reflect the wetting characteristics of oil and water in the shale oil reservoir from multiple dimensions, and makes the evaluation more comprehensive.