34 results about "Fluid saturation" patented technology

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.

The invention discloses a fluid identification method based on earthquake-electromagnetic combination, and aims to improve the identification precision of underground fluid, and the method comprises the steps: firstly, constructing and calibrating a forward model based on well data and a rock core experiment, and guaranteeing the theoretical support for the physical property of a stratum; afterwards, AVO inversion is carried out to obtain stratum elastic parameters, and meanwhile, electromagnetic inversion is utilized to obtain spatial distribution of resistivity. Afterwards, the elastic parameters and the resistivity obtained through inversion are substituted into a rock physical model, a joint objective function is constructed, and the difference between observation data and model prediction is quantified. And finally, through combination of global and local optimization algorithms, successive approximation to an optimal solution and inversion, lithology, porosity and fluid property parameters are obtained, fluid saturation is further deduced, and high-precision identification of the underground fluid is realized. The method can be widely applied to the geological engineering fields of oil-gas exploration, underground water resource evaluation and the like, and provides effective theoretical and practical support for accurate estimation of fluid saturation.

The invention relates to 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.

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.

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 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.

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.

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.

The present application relates to a method for determining artificial fracture oil-water relative permeability based on two-dimensional nuclear magnetic resonance, which comprises: oil-water nuclear magnetic signal calibration under reservoir temperature and pressure conditions; two-dimensional nuclear magnetic substrate signal test of shale matrix; artificial fracture filling with fracturing fluid, calculation of single-sided wall surface area of the fracture, estimation of fracture volume; making the conditions of the core and artificial fracture be the initial state of the reservoir after fracturing; nuclear magnetic resonance test of the initial state of the reservoir after fracturing; initial fracture width CT scan test; calculation of absolute permeability of the fracture; fracture fluid saturation test during flowback production process, calculation of water saturation and oil saturation in the fracture at t i ; fracture width test during flowback production process, calculation of fracture width at t 10 ; calculation of artificial fracture oil-water relative permeability; and drawing of a shale oil reservoir artificial fracture relative permeability curve. The present application can non-destructively, in-situ and in real time reveal the dynamic percolation behavior of artificial fractures in multiphase flow process.

The invention discloses a device, a controller and a method for determining rock breakthrough pressure, and the device comprises a pressure difference generation device which is used for providing injection pressure difference for injection fluid; the core holder is used for placing a to-be-tested core with saturated formation water and heating the to-be-tested core to the formation temperature; the confining pressure pump is used for providing the required confining pressure for the clamping device to serve as formation pressure; the nuclear magnetic resonance testing device is used for performing nuclear magnetic testing on the core of the saturated formation water to obtain the water saturation of the core; and the controller is used for controlling each component to work so as to obtain the water saturation of the rock core when the operation of injecting the non-wetting phase fluid into the rock core to be measured is executed under the injection pressure difference of different periods. The rock breakthrough pressure can be efficiently and accurately determined based on the on-line fluid saturation test.

The present application belongs to the field of unconventional oil and gas resource development, and proposes a method for predicting fluid production behavior after shale oil hydraulic fracturing, which comprises: based on the fluid characteristics in the shale oil reservoir hydraulic fracture, the mass conservation equation of fluid flow, the energy conservation equation of fluid flow and the momentum conservation equation of fluid flow, a heat and flow model of fluid nonlinear seepage behavior in the shale oil reservoir hydraulic fracture is established; based on the real geological data of the shale oil reservoir, a reservoir model is constructed, the initial conditions and boundary conditions of the reservoir model are set, and the reservoir model is divided into grids; the reservoir model is input into the heat and flow model to obtain the spatio-temporal evolution results of fluid pressure and saturation in the shale oil reservoir recovery process, and the fluid production behavior after shale oil hydraulic fracturing is predicted according to the spatio-temporal evolution results of fluid pressure and saturation. The present application can effectively capture the transient change of fluid pressure and the accurate characteristics of fluid saturation distribution, and significantly improve the accuracy of prediction.

This application relates to the field of hydrogeology and provides a method for real-time calculation of multiphase flow fluid saturation based on microfluidic technology. The method includes: first, establishing a multiphase flow image dataset; then, cropping original images from different times within the dataset to the target size and rotating them to the target position; identifying the target fluid in the cropped and rotated original images according to a preset RGB range, and adjusting the preset RGB range until the identification result is accurate, identifying the target fluid region; next, generating real-time target fluid saturation data based on the target fluid region; and finally, plotting the saturation evolution curve of the target fluid in the multiphase flow process based on the real-time target fluid saturation data. This improves the accuracy of real-time fluid saturation calculation in multiphase flow displacement and mass transfer processes.

The application discloses a low-resistance oil layer productivity prediction method based on nuclear magnetic movable fluid saturation. The method comprises the following steps: S1, analyzing low-resistance oil layer productivity prediction parameters, and establishing a correlation between core analysis irreducible water saturation and core analysis permeability; S2, obtaining a T2 cutoff value of the low-resistance oil layer, and calculating the irreducible water saturation of the low-resistance oil layer; and S3, establishing a relationship between the nuclear magnetic movable fluid saturation and the permeability. The low-resistance oil layer productivity prediction model based on the nuclear magnetic movable fluid saturation is established, and the precision of the low-resistance oil layer productivity prediction can be improved.

The invention relates to the technical field of oil exploitation, in particular to a method for judging a main control factor of water drive efficiency of a low-permeability reservoir based on relative permeability, which comprises the following steps: determining a target reservoir condition, carrying out an unsteady-state method relative permeability experiment, testing a starting pressure gradient and fitting a formula, and determining the main control factor by adopting grey correlation analysis. Through systematic experimental design and data analysis, the influence degree of each factor on the oil displacement efficiency is quantified, and the movable fluid saturation, irreducible water saturation and starting pressure gradient are determined as main influence factors. According to the method, the main control factors of low-permeability reservoir water drive development can be quickly and accurately identified.

The application relates to a method for evaluating the oil recovery rate during in-situ heating and upgrading of shale oil, and is applied to the field of oil development. The method comprises the following steps: 1, constructing a three-dimensional grid model of a shale oil reservoir between two horizontal wells, and determining the initial temperature, initial fluid pressure, initial porosity, initial oil saturation, initial gas saturation, initial water saturation and initial dissolved gas amount of each three-dimensional grid unit of the reservoir; 2, determining the pressure of each three-dimensional grid unit of the reservoir when the fluid pressure is balanced according to the bottom hole pressure of the shale oil layer and the reservoir displacement pressure gradient; 3, obtaining the temperature and instantaneous fluid pressure parameters of each three-dimensional grid unit of the reservoir according to the temperature field and pressure field of the in-situ heating shale oil reservoir, and determining the porosity and fluid saturation at each time point; and 4, determining the oil, gas and water production and recovery rate of each reservoir grid unit according to the instantaneous fluid pressure and balanced fluid pressure of each three-dimensional grid unit of the reservoir, and combining the oil, gas and water saturations.

The invention discloses a shale gas recovery ratio prediction and evaluation method and device based on a machine vision system. The method comprises the steps that a high-definition image of the surface of shale in a shale reservoir is obtained in real time based on the machine vision system; feature extraction is carried out based on the high-definition image of the shale surface so as to extract shale gas recovery efficiency related features; wherein the related characteristics of the shale gas recovery ratio comprise the number, length, width and direction of cracks on the surface of the shale, and the pore structure and fluid saturation of the shale; and determining the shale gas recovery ratio based on the extracted shale recovery ratio related characteristics and a pre-trained shale recovery ratio prediction model. Non-intrusive monitoring is carried out on a shale gas well through the machine vision technology, underground information is obtained in real time, and the shale gas recovery ratio is predicted and evaluated through image processing and analysis. The method has the advantages of being non-contact, lossless, rapid and accurate, the efficiency and safety of shale gas exploitation can be improved, and better data support and decision basis are provided for decision makers.

The present application provides a shale organic porosity and inorganic porosity determination method and related method, the determination method comprises, shale total porosity is obtained by using preset first rule; shale organic matter porosity is obtained by using preset second rule; shale inorganic matter porosity is obtained according to shale total porosity and shale organic matter porosity, according to preset formula. The present application can calculate shale organic matter porosity and inorganic matter porosity, which is helpful to characterize the development degree of shale organic matter pores and inorganic matter pores, and calculate rock reservoir space, fluid saturation and geological reserves.

The application discloses a kind of experimental device and experimental method for simulating the development of strong heterogeneous multilayer series water-containing gas reservoir, and relates to the technical field of gas field development, including edge water simulation unit, bottom water simulation unit, multilayer series reservoir simulation unit, longitudinal crack-containing reservoir simulation unit, back pressure control unit, gas and water monitoring unit and original fluid saturation unit;The multilayer series reservoir simulation unit is a horizontal multiple-parallel structure, one side of the multiple-parallel structure is connected to the edge water simulation unit, and the other side is connected to the back pressure control unit;The back pressure control unit is connected to the gas and water monitoring unit through a gas and water separation meter;The longitudinal crack-containing reservoir simulation unit includes multiple full-diameter core holders connected in series vertically, and the bottom full-diameter core holder is connected to the bottom water simulation unit at the bottom;The application realizes the simulation of strong heterogeneous longitudinal high-angle crack development in the hydrochloride rock multilayer series water-containing gas reservoir through the effective combination of full-diameter core holders and long core holders.

The present specification relates to the technical field of oil and gas exploration, and particularly relates to a method, device and equipment for establishing a maximum relaxation saturation rock physics model. The method for establishing the maximum relaxation saturation rock physics model comprises: determining a fluid-solid composite medium model of rock, the fluid-solid composite medium model being a heterogeneous model; determining physical property parameters of the rock in a seismic wave propagation process according to the fluid-solid composite medium model; determining a propagation velocity of a seismic wave in the rock according to the physical property parameters; and establishing a maximum relaxation saturation model of the rock according to the propagation velocity and the physical property parameters, the maximum relaxation saturation model being used to predict fluid saturation of a target reservoir. The maximum relaxation saturation model of the present specification embodiment can accurately describe the relationship between seismic data and reservoir physical properties and reservoir fluid content. Through the maximum relaxation saturation model, the accuracy of reservoir fluid content prediction can be improved.

The invention belongs to the field of low-permeability reservoir development experiments, and discloses an integrated experiment method for core water locking, resistivity and capillary pressure. Comprising rock resistivity, rock air permeability, core pore volume, core permeability test, porosity distribution, radius and fluid saturation. According to the method, through a brand-new thought, key methods in all experiment steps are necessarily improved, the number of experiment samples is reduced, the working efficiency is improved, and the efficiency is more than two times of the original efficiency. And meanwhile, the correlation of various experiments is ensured.

The present invention provides a method for estimating fluid saturation of a hydrocarbon-bearing rock from a rock image. The image is segmented to represent either a pore space or solid material in the rock. An image pore volume is estimated from the segmented image, and a corrected pore volume is determined to account for the sub-resolution pore volume missing in the image of the rock. An image-derived wetting fluid saturation of the rock is estimated using a direct flow simulation on the rock image and corrected for the corrected pore volume. A backpropagation-enabled trained model can be used to segment the image. A backpropagation-enabled method can be used to estimate the fluid saturation using an image selected from a series of 2D projection images, 3D reconstructed images and combinations thereof.

The invention relates to an oil saturation distribution measuring method suitable for an open system, which comprises the following steps: dyeing non-wetting phase oil, keeping wetting phase water colorless, and when the dyed oil is injected into a visual seepage model of saturated water, measuring the oil saturation distribution of the open system. An oil phase greatly absorbs a spectrum which does not correspond to the color of the oil phase, a linear relation exists between the light intensity attenuation of the spectrum and the corresponding oil quantity, and a quantitative relation between the light intensity attenuation and the corresponding oil quantity is established through dynamic calibration, so that a calibration coefficient is obtained and used for calculating the oil saturation distribution in the medium. According to the fluid saturation measuring method provided by the invention, the saturation and the optical signal have a good linear relationship, and the measuring precision is high.

This application relates to the field of rock physics research, and discloses a method, apparatus, equipment, and medium for quantitatively testing the fluid saturation inside rocks. The method includes: obtaining a dry rock sample; pressurizing and saturating the dry rock sample, and performing nuclear magnetic resonance (NMR) testing to obtain the T2 spectrum of a fully saturated rock sample; centrifuging the fully saturated rock sample and performing NMR testing to obtain the T2 spectrum of the centrifuged rock sample; and determining the fluid saturation in the rock sample based on the T2 spectrum of the fully saturated rock sample and the T2 spectrum of the centrifuged rock sample. The quantitative testing method for fluid saturation inside rocks provided by this application more accurately determines the type, content, and distribution of fluids inside rocks.