Reservoir rock wettability evaluation method

Abstract

The invention discloses a reservoir rock wettability evaluation method, which utilizes two rock samples with the same physical property to spontaneously imbibition an oil phase fluid and a water phase fluid to respectively simulate the oil imbibition process and the water imbibition process. A nuclear magnetic resonance technology is combined to characterize a fluid signal change rule and a distribution rule of an unconventional tight reservoir sample in an oil phase fluid imbibition process and a water phase fluid imbibition process. Determining pore size distribution of reservoir rock pores according to the nuclear magnetic resonance data, and further calculating different imbibition characteristic data of the pores with different pore size distribution of the rock to oil and water. And finally, calculating the wetting dynamic rate coefficient of the rock under different pore size distribution conditions, and judging the rock wettability according to the wetting dynamic rate coefficient. The wettability of reservoir rocks with different pore diameters is quantitatively measured, and meanwhile, the measurement time period is greatly shortened.

Description

Technical Field

[0001] This application relates to the technical field of oil and gas field development, and particularly relates to a method for evaluating the wettability of reservoir rocks. Background Art

[0002] At present, unconventional oil and gas has gradually become the main force for increasing oil and gas production. Unconventional oil and gas reservoirs are characterized by complex pore structures and poor pore permeability. Conventional wettability measurement methods (such as the contact angle measurement method, the Amott-Harvey measurement method, and the USBM measurement method) usually take a lot of time to evaluate the wettability of unconventional reservoir rocks, resulting in a long cycle for wettability measurement experiments. In addition, due to the strong heterogeneity of unconventional reservoir rocks, the detection results of conventional measurement methods cannot represent the wettability characteristics of pores with different pore sizes in the whole rock, resulting in large errors in measurement results. Summary of the Invention

[0003] In view of this, this application provides a method for evaluating the wettability of reservoir rocks to solve the problems of long experimental cycle and large detection result errors of conventional wettability measurement methods.

[0004] According to one aspect of this application, a method for evaluating the wettability of reservoir rocks is provided, including: Generating a first rock sample and a second rock sample based on a reservoir rock sample, obtaining a first sample parameter of the first rock sample, a first initial nuclear magnetic resonance signal intensity value, a second sample parameter of the second rock sample, a second initial nuclear magnetic resonance signal intensity value, a first fluid parameter of the oil-phase fluid, and a second fluid parameter of the water-phase fluid; During the process of the first rock sample spontaneously imbibing the oil-phase fluid, performing nuclear magnetic resonance tests on the first rock sample at multiple imbibition times to obtain the first sample nuclear magnetic resonance signal intensity value under each imbibition time condition, and determining the first fluid nuclear magnetic resonance signal intensity value of the oil-phase fluid imbibed by the first rock sample under each imbibition time condition based on the first initial nuclear magnetic resonance signal intensity value and the first sample nuclear magnetic resonance signal intensity value; During the process of the second rock sample spontaneously imbibing the water-phase fluid, performing nuclear magnetic resonance tests on the second rock sample at multiple imbibition times to obtain the second sample nuclear magnetic resonance signal intensity value under each imbibition time condition, and determining the second fluid nuclear magnetic resonance signal intensity value of the water-phase fluid imbibed by the second rock sample under each imbibition time condition based on the second initial nuclear magnetic resonance signal intensity value and the second sample nuclear magnetic resonance signal intensity value; Based on the first sample parameter, the first fluid parameter, and multiple first fluid nuclear magnetic resonance signal intensity values, determining multiple oil-phase wetting kinetic rates when the first rock sample spontaneously imbibes the oil-phase fluid under multiple pore types; Based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values, determine multiple aqueous wetting kinetic rates when the second rock sample spontaneously imbibes an aqueous phase fluid under multiple pore types; Based on multiple oil wetting kinetic rates and multiple aqueous wetting kinetic rates, generate multiple wetting kinetic rate coefficients, and determine the wettability of the reservoir rock sample through the multiple wetting kinetic rate coefficients.

[0005] In the solution implemented by the above reservoir rock wettability evaluation method, two rock samples with the same physical properties are used to respectively simulate the processes of spontaneous imbibition of an oil phase fluid and an aqueous phase fluid to respectively simulate the processes of oil imbibition and water imbibition. Combining nuclear magnetic resonance technology to characterize the variation law and distribution law of fluid signals during the processes of spontaneous imbibition of an oil phase fluid and an aqueous phase fluid by unconventional tight reservoir samples. Determine the pore size distribution of the reservoir rock pores according to the nuclear magnetic resonance data, and then calculate the different imbibition characteristic data of the pores with different pore size distributions in the rock for oil and water. Finally, calculate the wetting kinetic rate coefficients of the rock under different pore size distribution conditions, and use this to judge the wettability of the rock. Through the above method, the wettability of reservoir rocks with different pore sizes can be quantitatively measured, and at the same time, the measurement time period is greatly shortened, effectively overcoming technical problems such as measurement result errors, long experimental periods, and poor applicability brought by conventional wettability measurement methods when applied to unconventional reservoir rocks.

[0006] The above description is only an overview of the technical solution of the present application. In order to be able to understand the technical means of the present application more clearly, it can be implemented according to the content of the specification. And in order to make the above and other purposes, features, and advantages of the present application more obvious and understandable, the specific embodiments of the present application are specifically exemplified below. BRIEF DESCRIPTION OF THE DRAWINGS

[0007] By reading the following detailed description of the preferred embodiments, various other advantages and benefits will become clear to those of ordinary skill in the art. The drawings are only for the purpose of showing the preferred embodiments and are not considered to be a limitation of the present application. And throughout the drawings, the same reference numerals are used to represent the same components. In the drawings: Figure 1 is a schematic flowchart of a method for evaluating the wettability of a reservoir rock in an embodiment of the present application; Figure 2 is the nuclear magnetic resonance T 2 spectrum of sample W in the initial state and under different imbibition time conditions; Figure 3 is the nuclear magnetic resonance T 2 spectrum of sample O in the initial state and under different imbibition time conditions; Figure 4It is a schematic diagram of the conversion relationship between the nuclear magnetic resonance signal amount and the mass of deionized water fitted in an embodiment of the present application; Figure 5 It is a schematic diagram of the conversion relationship between the nuclear magnetic resonance signal amount and the mass of n-dodecane fitted in an embodiment of the present application; Figure 6 It is a schematic diagram of the variation relationship of the nuclear magnetic resonance signal with the imbibition time during the full-aperture pore imbibition of deionized water in an embodiment of the present application; Figure 7 It is a schematic diagram of the variation relationship of the nuclear magnetic resonance signal with the imbibition time during the full-aperture pore imbibition of n-dodecane in an embodiment of the present application; Figure 8 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time during the imbibition of deionized water in the adsorption pores in an embodiment of the present application; Figure 9 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time during the imbibition of n-dodecane in the adsorption pores in an embodiment of the present application; Figure 10 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time during the imbibition of deionized water in the flow pores in an embodiment of the present application; Figure 11 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time during the imbibition of n-dodecane in the flow pores in an embodiment of the present application. Detailed implementation manners

[0008] Hereinafter, exemplary embodiments of the present disclosure will be described in more detail with reference to the accompanying drawings. Although the exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided so that the present disclosure can be more thoroughly understood and the scope of the present disclosure can be completely conveyed to those skilled in the art.

[0009] The reservoir rock wettability evaluation method provided by the present application can be applied to the wettability measurement scenario of unconventional tight reservoirs. At present, with the increasing difficulty of conventional oil and gas resource exploitation, unconventional oil and gas have gradually become the main force for the growth of oil and gas production. Unconventional oil and gas reservoirs, such as shale and tight sandstone, have characteristics such as complex pore structures and poor pore permeability. Rock wettability is an important parameter that controls the fluid distribution and multiphase fluid flow in porous media. Wettability refers to the fact that when there are two immiscible fluids in the rock pores, one of the fluids has a stronger affinity or spreading property for the rock pore surface relative to the other fluid. Wettability is a key factor affecting the microscopic distribution state of fluids in rock pores and the interaction between fluids and rocks. Therefore, accurately measuring the wettability of reservoir rocks has extremely important guiding significance for the selection of imbibition agents, the design of enhanced oil recovery methods, and the formulation of reasonable development plans.

[0010] At present, the most commonly used quantitative methods for measuring wettability include: contact angle measurement method, Amott-Harvey measurement method (imbibition and displacement method), and USBM (U.S. Bureau of Mines) measurement method. Among them, the contact angle measurement method is to directly observe the wetting angle of a specific limited surface on the rock surface when a liquid droplet contacts. However, due to the strong heterogeneity of unconventional reservoir rocks, the measurement results will have large errors. The USBM method and the Amott-Harvey method measure the average wettability of core samples, and the Amott-Harvey and USBM methods use the method of forced expulsion of pore fluids to measure wettability. However, due to the characteristics of low porosity and low permeability of unconventional tight reservoirs, the experimental period is long and the applicability of the measurement method is poor.

[0011] Please refer to Figure 1 as shown Figure 1 which is a schematic flow chart of the reservoir rock wettability evaluation method provided by the embodiment of the present application, including the following steps: S10: Generate a first rock sample and a second rock sample based on the reservoir rock sample, and obtain the first sample parameter of the first rock sample, the first initial nuclear magnetic resonance signal intensity value, the second sample parameter of the second rock sample, the second initial nuclear magnetic resonance signal intensity value, the first fluid parameter of the oil-phase fluid, and the second fluid parameter of the water-phase fluid.

[0012] In this step, for unconventional oil and gas reservoirs, a considerable part of the micropores are distributed in the organic matter. These pores show extremely strong oil wettability, and they may account for 40%-60% of the total pore space. A large amount of oil and gas are stored in this space. In contrast, some mesopores or macropores are distributed in inorganic minerals and show hydrophilicity. These special complex wettability characteristics determine the occurrence state of oil and gas and affect the migration behavior of oil and gas. Therefore, it is crucial to separately evaluate the oil wettability and water wettability of reservoir rocks for the development of unconventional oil and gas reservoirs. Therefore, the present application proposes to obtain a shale reservoir sample as the parent rock and divide the parent rock into two parallel test samples as the first rock sample and the second rock sample. Select the oil-phase fluid and the water-phase fluid so that the first rock sample and the second rock sample can respectively perform the oil-phase spontaneous imbibition experiment and the water-phase spontaneous imbibition experiment. After obtaining the rock samples and the imbibition fluids, measure the basic parameters of the first rock sample and the second rock sample respectively as the first sample parameter and the second sample parameter. And obtain the basic parameters of the oil-phase fluid and the water-phase fluid as the first fluid parameter and the second fluid parameter.

[0013] Subsequently, according to the experimental measurement specifications of rock sample nuclear magnetic resonance parameters, perform nuclear magnetic resonance tests on the first rock sample and the second rock sample respectively to obtain the nuclear magnetic resonance T of the two rock samples 2By obtaining the nuclear magnetic resonance (NMR) spectrum, the first initial NMR signal intensity value of the first rock sample in the initial state and the second initial NMR signal intensity value of the second rock sample in the initial state can be obtained.

[0014] In an embodiment of the present application, a specific initial parameter acquisition scheme is provided. In S10, that is, the task information, the location status information, and the stacker crane status information are input into the multi-objective optimization model for solution to obtain the optimal task scheduling scheme, which specifically includes the following steps S11 - S18: S11: Obtain reservoir rock samples.

[0015] S12: Cut the reservoir rock samples into a first rock sample and a second rock sample with the same mass and the same volume.

[0016] S13: Obtain the first initial mass and the first surface area of the first rock sample, and the second initial mass and the second surface area of the second rock sample.

[0017] For steps S11 - S13, drill a sample of an unconventional reservoir rock column, and cut it into two rock samples with the same mass and the same volume. Respectively perform cleaning and drying pretreatment on the two rock samples, and respectively record the initial mass and surface area of each pretreated rock sample.

[0018] In the above manner, a reservoir rock sample is divided into parallel samples to perform imbibition oil and imbibition water experiments respectively, so as to realize the measurement of the oil wettability and water wettability of the reservoir rock and ensure the accuracy of the final wettability measurement result.

[0019] S14: Respectively perform NMR tests on the first rock sample and the second rock sample to generate the first initial NMR signal intensity value of the first rock sample and the second initial NMR signal intensity value of the second rock sample.

[0020] In this step, according to the experimental measurement specification of rock sample NMR parameters, respectively perform NMR tests on the two rock samples to obtain the NMR T 2 spectrum. The NMR T 2 spectrum characterizes the change curve of the transverse relaxation time and the signal amplitude, from which the first initial NMR signal intensity value of the first rock sample and the second initial NMR signal intensity value of the second rock sample can be obtained.

[0021] S15: Obtain the first fluid density and the first fluid viscosity of the oil-phase fluid, and the second fluid density and the second fluid viscosity of the water-phase fluid.

[0022] S16: Perform nuclear magnetic resonance tests on the oil-phase fluid under multiple first preset quality conditions and perform nuclear magnetic resonance tests on the water-phase fluid under multiple second preset quality conditions to obtain multiple third initial nuclear magnetic resonance signal intensity values of the oil-phase fluid under multiple first preset quality conditions and multiple fourth initial nuclear magnetic resonance signal intensity values of the water-phase fluid under multiple second preset quality conditions.

[0023] S17: Generate a first linear equation corresponding to the oil-phase fluid based on multiple first preset masses and multiple third initial nuclear magnetic resonance signal intensity values, and determine a first conversion coefficient between the mass of the oil-phase fluid and the nuclear magnetic resonance signal based on the first slope of the first linear equation.

[0024] S18: Generate a second linear equation corresponding to the water-phase fluid based on multiple second preset masses and multiple fourth initial nuclear magnetic resonance signal intensity values, and determine a second conversion coefficient between the mass of the water-phase fluid and the nuclear magnetic resonance signal based on the second slope of the second linear equation.

[0025] For steps S15 - S18, the fluid densities and viscosities of the oil-phase fluid and the water-phase fluid are obtained respectively. Subsequently, according to the multiple preset masses set in the experiment, nuclear magnetic resonance experiments are performed on the oil-phase fluid and the water-phase fluid respectively to measure the nuclear magnetic resonance signal intensity values of the oil-phase fluid under different mass conditions and the nuclear magnetic resonance signal intensity values of the water-phase fluid under different mass conditions. Based on each preset mass and its corresponding nuclear magnetic resonance signal intensity value, it is experimentally found that there is a linear relationship between the imbibition fluid and the cumulative signal of the corresponding nuclear magnetic resonance. Therefore, a first linear equation between the third nuclear magnetic resonance signal and the oil-phase fluid and a second linear equation between the fourth nuclear magnetic resonance signal and the water-phase fluid are respectively fitted. And the slope of each linear equation is the mass of the imbibition fluid corresponding to the unit nuclear magnetic resonance signal intensity value. Therefore, through the first slope of the first linear equation, the first conversion coefficient of the oil-phase fluid can be obtained; through the second slope of the second linear equation, the second conversion coefficient of the water-phase fluid can be obtained. Through the above conversion coefficients, the measured nuclear magnetic resonance signal intensity value can be converted into the corresponding mass value.

[0026] By the above method, the nuclear magnetic resonance signals of the imbibition fluid under different mass conditions are measured, the calibration equations between the oil-phase fluid and the water-phase fluid and the cumulative signals of the corresponding nuclear magnetic resonance are respectively fitted, and the corresponding conversion coefficients are obtained according to their respective slopes to convert the nuclear magnetic resonance signal intensity value into the actual mass, which is convenient for subsequent quantitative analysis of the fluid content in the rock sample.

[0027] S20: During the process of the first rock sample spontaneously sucking in the oil-phase fluid, nuclear magnetic resonance (NMR) tests are performed on the first rock sample at multiple imbibition times to obtain the NMR signal intensity values of the first sample under each imbibition time condition. Based on the first initial NMR signal intensity value and the NMR signal intensity values of the first sample, the first fluid NMR signal intensity value of the oil-phase fluid sucked in by the first rock sample under each imbibition time condition is determined.

[0028] In this step, the oil-phase fluid is set on the surface of the first rock sample so that the first rock sample can perform an oil-phase spontaneous imbibition experiment. During the spontaneous imbibition process, NMR tests are performed on the first rock sample at multiple imbibition times designed in the experiment to obtain the NMR T 2 spectra, and thus the NMR signal intensity values of the first sample of the first rock sample under different imbibition time conditions can be obtained. Subsequently, by subtracting the first initial NMR signal intensity value from the NMR signal intensity values of the first sample, the first fluid NMR signal intensity value of the oil-phase fluid imbibed by the first rock sample under different imbibition time conditions is obtained.

[0029] In the above manner, the NMR signal intensity values of the oil-phase fluid imbibed by the first rock sample under different imbibition time conditions are obtained to characterize the distribution of the oil-phase fluid in the full pore diameter of the first rock sample under different imbibition time conditions, providing important information for subsequent analysis of the oil wettability of reservoir rocks.

[0030] In an embodiment of the present application, a specific scheme for calculating the nuclear magnetic signal of the oil-phase fluid sucked in by the first rock sample under different imbibition time conditions is provided. In S20, that is, during the process of the first rock sample spontaneously sucking in the oil-phase fluid, NMR tests are performed on the first rock sample at multiple imbibition times to obtain the NMR signal intensity values of the first sample under each imbibition time condition. Based on the first initial NMR signal intensity value and the NMR signal intensity values of the first sample, the first fluid NMR signal intensity value of the oil-phase fluid sucked in by the first rock sample under each imbibition time condition is determined, which specifically includes the following steps S21 - S23: S21: Place the first rock sample in the oil-phase fluid so that the pores of the first rock sample can spontaneously suck in the oil-phase fluid.

[0031] In this step, an oil-phase spontaneous imbibition experiment is performed on the first rock sample. The first rock sample is placed in the oil-phase fluid so that the surface of the first rock sample is in contact with the oil-phase fluid. The rock in the dry state will spontaneously imbibe the external oil-phase fluid by the capillary action existing in the pores during the imbibition process.

[0032] S22: During the process of the first rock sample spontaneously sucking in the oil-phase fluid, perform nuclear magnetic resonance (NMR) tests on the first rock sample at multiple imbibition times to determine the first sample NMR signal intensity value corresponding to the first rock sample under each imbibition time condition.

[0033] S23: Subtract the first initial NMR signal intensity value from the first sample NMR signal intensity value under each imbibition time condition to obtain the first fluid NMR signal intensity value of the oil-phase fluid sucked in by the first rock sample under each imbibition time condition.

[0034] For steps S22 - S23, during the process of spontaneous imbibition of the oil phase by the first rock sample, according to the multiple imbibition times set in the experiment, i.e., the imbibition time, perform NMR tests on the first rock sample in sequence to obtain the NMR T 2 spectrum under each imbibition time condition, and further obtain the first sample NMR signal intensity value under each imbibition time condition. Subsequently, subtract the first initial NMR signal intensity value from each first sample NMR signal intensity value to obtain the nuclear magnetic signal of the oil-phase fluid imbibed by the first rock sample under each imbibition time condition, which is the first fluid NMR signal intensity value.

[0035] S30: During the process of the second rock sample spontaneously sucking in the water-phase fluid, perform NMR tests on the second rock sample at multiple imbibition times to obtain the second sample NMR signal intensity value under each imbibition time condition. Based on the second initial NMR signal intensity value and the second sample NMR signal intensity value, determine the second fluid NMR signal intensity value of the water-phase fluid sucked in by the second rock sample under each imbibition time condition.

[0036] In this step, set the water-phase fluid on the surface of the second rock sample to enable the second rock sample to conduct a water-phase spontaneous imbibition experiment. During the spontaneous imbibition process, perform NMR tests on the second rock sample according to the multiple imbibition times designed in the experiment to obtain the NMR T 2 spectrum under different imbibition time conditions, and thus obtain the second sample NMR signal intensity value of the second rock sample under different imbibition time conditions. Subsequently, subtract the second initial NMR signal intensity value from the second sample NMR signal intensity value to obtain the second fluid NMR signal intensity value of the water-phase fluid imbibed by the second rock sample at different imbibition times.

[0037] By the above method, obtain the nuclear magnetic resonance signal intensity value of the water-phase fluid imbibed by the second rock sample under different imbibition time conditions to characterize the degree of change and distribution law of fluid imbibition under different imbibition time conditions, providing important information for subsequent analysis of the water wettability of reservoir rocks.

[0038] In some embodiments, during the spontaneous imbibition process of the rock, the mass of the imbibed oil and the mass of the imbibed water of the rock are respectively recorded under different imbibition time conditions. Further, after measuring the nuclear magnetic resonance signal intensity values of the samples under different imbibition time conditions, the measured nuclear magnetic resonance signal intensity values are divided by the mass of the imbibed oil / mass of the imbibed water to achieve the dimensionless quality of the nuclear magnetic resonance signal, eliminating the error caused by the inability to ensure the exact same mass of two different samples during the imbibition of oil and water respectively, making the data between different samples comparable.

[0039] In an embodiment of the present application, a specific nuclear magnetic resonance signal scheme for calculating the aqueous fluid imbibed by the second rock sample under different imbibition time conditions is provided. In S30, that is, during the process of the second rock sample spontaneously imbibing the aqueous fluid, nuclear magnetic resonance tests are performed on the second rock sample according to multiple imbibition times to obtain the nuclear magnetic resonance signal intensity values of the second sample under each imbibition time condition. Based on the second initial nuclear magnetic resonance signal intensity value and the nuclear magnetic resonance signal intensity values of the second sample, the second fluid nuclear magnetic resonance signal intensity value of the aqueous fluid imbibed by the second rock sample under each imbibition time condition is determined, specifically including the following steps S31 - S33: S31: Place the second rock sample in the aqueous fluid so that the pores of the second rock sample spontaneously imbibe the aqueous fluid.

[0040] In this step, an aqueous spontaneous imbibition experiment is performed on the second rock sample. The second rock sample is placed in the aqueous fluid so that the surface of the second rock sample is in contact with the aqueous fluid. The dry rock will spontaneously imbibe the external aqueous fluid by the capillary action existing in the pores during the imbibition process.

[0041] S32: During the process of the second rock sample spontaneously imbibing the aqueous fluid, nuclear magnetic resonance tests are performed on the second rock sample according to multiple imbibition times to determine the nuclear magnetic resonance signal intensity values of the second sample of the second rock sample under each imbibition time condition.

[0042] S33: By subtracting the second initial nuclear magnetic resonance signal intensity value from the nuclear magnetic resonance signal intensity values of the second sample under each imbibition time condition, the second fluid nuclear magnetic resonance signal intensity value of the aqueous fluid imbibed by the second rock sample under each imbibition time condition is obtained.

[0043] For steps S32 - S33, during the oil-phase spontaneous imbibition process of the second rock sample, according to the multiple imbibition times set in the experiment, that is, the imbibition time, nuclear magnetic resonance tests are sequentially performed on the second rock sample to obtain the nuclear magnetic resonance T under each imbibition time condition 2Spectrum, and then obtain the second sample nuclear magnetic resonance signal intensity value under each imbibition time condition. Subsequently, by subtracting the second initial nuclear magnetic resonance signal intensity value from each second sample nuclear magnetic resonance signal intensity value, the nuclear magnetic signal of the aqueous fluid imbibed by the second rock sample under each imbibition time condition is obtained, which is the second fluid nuclear magnetic resonance signal intensity value.

[0044] S40: Based on the first sample parameters, the first fluid parameters, and multiple first fluid nuclear magnetic resonance signal intensity values, determine multiple oil-phase wetting kinetic rates of the first rock sample during spontaneous imbibition of the oil-phase fluid under multiple pore types.

[0045] In this step, the unconventional reservoir rock has strong heterogeneity, which will lead to uneven spatial distribution of wettability. Some pore structure regions may exhibit hydrophilicity, while some pore structure regions may exhibit oleophilicity. The single whole-region measurement result may not be able to represent the wettability characteristics of the entire rock. In order to obtain more comprehensive wettability distribution information, this application proposes to divide pores into different types (i.e., large pore diameter pores and small pore diameter pores) based on the size of the pore radius, and then calculate the fluid signal change law and distribution law of the rock sample under the conditions of full-aperture pores, large pore diameter pores, and small pore diameter pores respectively, to comprehensively evaluate the wettability of the reservoir rock.

[0046] Specifically, according to the size of the pore radius of the reservoir rock, the pores can be divided into large pore diameter pores (such as pore radius r > 2 nm) and small pore diameter pores (such as pore radius r ≤ 2 nm). And the nuclear magnetic resonance T 2 spectrum represents the distribution of the imbibition amount of the reservoir rock in different pores at different imbibition times. The abscissa (i.e., the transverse relaxation time) of the nuclear magnetic resonance T 2 spectrum represents the size of the pore radius of the reservoir rock. The smaller the abscissa value, the smaller the pore radius. Therefore, through the transverse relaxation time, the imbibition amounts of the reservoir rock in full-aperture pores, large pore diameter pores, and small pore diameter pores can be obtained respectively. Then, based on the first sample parameters, the first fluid parameters, and multiple first fluid nuclear magnetic resonance signal intensity values, calculate the imbibition rate of the reservoir rock for the oil-phase fluid under different pore types. As the basic data for quantitatively evaluating the wettability of unconventional tight reservoir rocks.

[0047] In an embodiment of the present application, a specific calculation scheme for the wetting kinetic rate of the full-aperture pores of the rock during spontaneous imbibition of oil is provided. In S40, that is, based on the first sample parameters, the first fluid parameters, and multiple first fluid nuclear magnetic resonance signal intensity values, determine multiple oil-phase wetting kinetic rates of the first rock sample during spontaneous imbibition of the oil-phase fluid under multiple pore types, which specifically includes the following steps S41 - S42: S41: Determine a first contact area of the oil-phase fluid in the full-aperture pores of the first rock sample based on a first conversion coefficient of the oil-phase fluid, a first fluid density of the oil-phase fluid, each first fluid nuclear magnetic resonance signal intensity value, and a transverse relaxation time corresponding to each first fluid nuclear magnetic resonance signal intensity value.

[0048] In this step, by summing the contact areas at multiple imbibition times, the diffusion and adsorption behaviors of the imbibing fluid in the rock pores can be quantitatively evaluated, which helps to understand the distribution characteristics of the imbibing fluid in the pores. Therefore, substitute the first conversion coefficient of the oil-phase fluid, the first fluid density of the oil-phase fluid, the first fluid nuclear magnetic resonance signal intensity values under different imbibition time conditions, and their corresponding transverse relaxation times into the first expression to calculate the first contact area of the oil-phase fluid in the full-aperture pores of the first rock sample, where the first expression is used to calculate the contact area between the rock pores and the imbibing fluid.

[0049] The first expression is: ; In the formula, S above is the contact area between the pores of the rock sample and the imbibing fluid; q above is the total number of multiple imbibition times; k above is the conversion coefficient between the imbibing fluid and the nuclear magnetic resonance signal; ρ 2 is the nuclear magnetic relaxation rate; ρ above is the fluid density of the imbibing fluid; n above is the range of the nuclear magnetic resonance signal region of the nuclear magnetic resonance T 2 spectrum; p i is the first fluid nuclear magnetic resonance signal intensity value of the i-th nuclear magnetic signal point; T 2i is the transverse relaxation time of the i-th nuclear magnetic signal point.

[0050] S42: Determine a first wetting kinetics rate of the full-aperture pores of the first rock sample during spontaneous imbibition of the oil-phase fluid based on a first fluid viscosity of the oil-phase fluid, a first surface area of the first rock sample, a first conversion coefficient, multiple first fluid nuclear magnetic resonance signal intensity values, a first initial mass, and the first contact area.

[0051] In this step, substitute the first fluid viscosity, the first surface area, the first conversion coefficient, multiple first fluid nuclear magnetic resonance signal intensity values, the first initial mass, and the calculated first contact area into the second expression to calculate the first wetting kinetics rate of the full-aperture pores of the first rock sample during spontaneous imbibition, where the second expression is used to calculate the wetting kinetics rate of the rock sample during spontaneous imbibition.

[0052] The second expression is: ; Wherein, α above is the wetting kinetics rate during the spontaneous imbibition of the rock sample; μ above is the fluid viscosity of the imbibing fluid; A above is the surface area of the rock sample; k above is the conversion coefficient of the imbibing fluid; ρ 2 is the nuclear magnetic relaxation rate; ρ above is the fluid density of the imbibing fluid; t above is the total imbibition time of the rock sample; n is the range of the nuclear magnetic resonance signal region of the nuclear magnetic resonance T 2 spectrum; p i is the fluid nuclear magnetic resonance signal intensity value of the i-th nuclear magnetic signal point; T 2i is the transverse relaxation time of the i-th nuclear magnetic signal point; m above is the initial mass of the rock sample.

[0053] Through the above method, the wetting kinetics rate during the spontaneous imbibition of oil in the pores of all apertures of the first rock sample is obtained, providing an important basis for the subsequent evaluation of rock wettability.

[0054] Therefore, in an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate during the spontaneous imbibition of oil in other pore types of the rock sample is provided. In S40, that is, based on the first sample parameters, the first fluid parameters, and multiple first fluid nuclear magnetic resonance signal intensity values, multiple oil-phase wetting kinetics rates of the first rock sample during the spontaneous inhalation of the oil-phase fluid under multiple pore types are determined. Specifically, it further includes the following steps S43-S45: S43: Based on a preset pore radius, the pores of the first rock sample are divided into first-aperture pores and second-aperture pores, wherein the radius of the first-aperture pores is smaller than that of the second-aperture pores.

[0055] In this step, the preset pore radius is the boundary value of the preset dividing line for classifying pores. Using the preset pore radius, the pores of the first rock sample are divided into large-aperture pores and small-aperture pores. Specifically, for any pore of the first rock sample, if the pore radius is less than or equal to the preset pore radius, it is confirmed that the pore is a small-aperture pore, that is, the first-aperture pore; if the pore radius is greater than the preset pore radius, it is confirmed that the pore is a large-aperture pore, that is, the second-aperture pore.

[0056] S44: Based on multiple first sample nuclear magnetic resonance signal intensity values, the preset pore radius, and the first initial nuclear magnetic resonance signal intensity value of the first rock sample, determine multiple first target fluid nuclear magnetic resonance signal intensity values corresponding to the first-aperture pores and multiple second target fluid nuclear magnetic resonance signal intensity values corresponding to the second-aperture pores.

[0057] In this step, the transverse coordinate of the nuclear magnetic resonance T 2 spectrum reflects the pore size distribution. Based on the conversion formula between the nuclear magnetic resonance transverse relaxation time and the pore size, in the nuclear magnetic resonance T 2Determine the nuclear magnetic resonance signal intensity values corresponding to different pore types in the spectrum. Specifically, the conversion formula is: T 2 = r / C, where T 2 is the transverse relaxation time; r is the preset pore radius; C is the conversion coefficient of the rock sample. Based on the preset pore radius, in the nuclear magnetic resonance T 2 spectrum, determine the nuclear magnetic resonance transverse relaxation times corresponding to different pore types, and then determine the nuclear magnetic resonance signal intensity values of multiple samples corresponding to different pore types. Subsequently, subtract the initial nuclear magnetic resonance signal intensity value from the nuclear magnetic resonance signal intensity value of the sample of each pore type to obtain the nuclear magnetic resonance signal intensity value of the fluid during spontaneous imbibition of oil for the pores of each pore type.

[0058] S45: Based on the first sample parameter, the first fluid parameter, multiple first target fluid nuclear magnetic resonance signal intensity values, and multiple second target fluid nuclear magnetic resonance signal intensity values, determine the second wetting kinetics rate of the pores with the first pore diameter in the first rock sample during spontaneous oil phase fluid imbibition, and the third wetting kinetics rate of the pores with the second pore diameter during spontaneous oil phase fluid imbibition.

[0059] In this step, after classifying the pores with the full pore diameter of the first rock sample into pores with the first pore diameter and pores with the second pore diameter, based on the first sample parameter, the first fluid parameter, and multiple first target fluid nuclear magnetic resonance signal intensity values under the condition of the pores with the first pore diameter, determine the second wetting kinetics rate of the pores with the first pore diameter during spontaneous imbibition of oil. At the same time, based on the first sample parameter, the first fluid parameter, and multiple second target fluid nuclear magnetic resonance signal intensity values under the condition of the pores with the second pore diameter, determine the third wetting kinetics rate of the pores with the second pore diameter during spontaneous imbibition of oil.

[0060] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of the pores with the full pore diameter of the rock during spontaneous imbibition of oil is provided. In S45, that is, based on the first sample parameter, the first fluid parameter, and multiple first fluid nuclear magnetic resonance signal intensity values, determine multiple oil phase wetting kinetics rates of the first rock sample during spontaneous oil phase fluid imbibition under multiple pore types. Specifically, it includes the following steps S451 - S454: S451: Substitute the first conversion coefficient of the oil phase fluid, the first fluid density of the oil phase fluid, multiple first target sample nuclear magnetic resonance signals, and the transverse relaxation time corresponding to each first target nuclear magnetic resonance signal into the first expression to calculate the second contact area of the oil phase fluid in the pores with the first pore diameter of the first rock sample.

[0061] S452: Substitute the first fluid viscosity of the oil-phase fluid, the first surface area of the first rock sample, the preset imbibition time, the first conversion coefficient of the oil-phase fluid, multiple first target fluid nuclear magnetic resonance signal intensity values of the oil-phase fluid, the first initial mass of the first rock sample, and the second contact area into the second expression to calculate the second wetting kinetics rate of the first pore size pores of the first rock sample during spontaneous imbibition of the oil-phase fluid.

[0062] S453: Substitute the first conversion coefficient of the oil-phase fluid, the first fluid density of the oil-phase fluid, multiple second target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each second target fluid nuclear magnetic resonance signal intensity value into the first expression to calculate the third contact area of the oil-phase fluid in the second pore size pores of the first rock sample.

[0063] S454: Substitute the first fluid viscosity of the oil-phase fluid, the first surface area of the first rock sample, the preset imbibition time, the first conversion coefficient of the oil-phase fluid, multiple second target fluid nuclear magnetic resonance signal intensity values of the oil-phase fluid, the first initial mass of the first rock sample, and the third contact area into the second expression to calculate the third wetting kinetics rate of the second pore size pores of the first rock sample during spontaneous imbibition of the oil-phase fluid.

[0064] For steps S451 - S454, substitute the first conversion coefficient of the oil-phase fluid, the first fluid density of the oil-phase fluid, the first target fluid nuclear magnetic resonance signal intensity values of the first pore size pores under different imbibition time conditions and their corresponding transverse relaxation times into the first expression to calculate the second contact area of the oil-phase fluid in the first pore size pores of the first rock sample. Subsequently, substitute the first fluid viscosity, the first surface area, the first conversion coefficient, multiple first target fluid nuclear magnetic resonance signal intensity values, the first initial mass, and the calculated second contact area into the second expression to calculate the second wetting kinetics rate of the first pore size pores of the first rock sample during spontaneous imbibition of oil. At the same time, substitute the first conversion coefficient of the oil-phase fluid, the first fluid density of the oil-phase fluid, the second target fluid nuclear magnetic resonance signal intensity values of the second pore size pores under different imbibition time conditions and their corresponding transverse relaxation times into the first expression to calculate the third contact area of the oil-phase fluid in the second pore size pores of the first rock sample. Subsequently, substitute the first fluid viscosity, the first surface area, the first conversion coefficient, multiple second target fluid nuclear magnetic resonance signal intensity values, the first initial mass, and the calculated third contact area into the second expression to calculate the third wetting kinetics rate of the second pore size pores of the first rock sample during spontaneous imbibition of oil.

[0065] S50: Based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values, determine multiple aqueous wetting kinetics rates of the second rock sample during spontaneous imbibition of the aqueous-phase fluid under multiple pore types.

[0066] In this step, pores are classified based on the pore radius (i.e., full-aperture pores, large-aperture pores, and small-aperture pores), and then the variation law and distribution law of fluid signals of the rock sample under the conditions of full-aperture pores, large-aperture pores, and small-aperture pores are calculated respectively to comprehensively evaluate the wettability of reservoir rocks.

[0067] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of the full-aperture pores of a rock during spontaneous imbibition is provided. In S50, that is, based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values, multiple water-phase wetting kinetics rates of the second rock sample during spontaneous imbibition of the water-phase fluid are determined under various pore types, specifically including the following steps S51 - S52: S51: Based on the second conversion coefficient of the water-phase fluid, the second fluid density of the water-phase fluid, each second fluid nuclear magnetic resonance signal intensity value, and the transverse relaxation time corresponding to each second fluid nuclear magnetic resonance signal intensity value, determine the fourth contact area of the water-phase fluid in the full-aperture pores of the second rock sample.

[0068] In this step, by summing the contact areas at multiple imbibition times, the diffusion and adsorption behaviors of the imbibing fluid in the rock pores can be quantitatively evaluated, which helps to understand the distribution characteristics of the imbibing fluid in the pores. Therefore, substitute the second conversion coefficient of the water-phase fluid, the second fluid density of the water-phase fluid, and the second fluid nuclear magnetic resonance signal intensity values and their corresponding transverse relaxation times under different imbibition time conditions into the first expression to calculate the fourth contact area of the water-phase fluid in the full-aperture pores of the second rock sample.

[0069] S52: Based on the second fluid viscosity of the water-phase fluid, the second surface area of the second rock sample, the second conversion coefficient, multiple second fluid nuclear magnetic resonance signal intensity values, the second initial mass, and the fourth contact area, determine the fourth wetting kinetics rate of the second rock sample during spontaneous imbibition of the water-phase fluid.

[0070] In this step, substitute the second fluid viscosity, the second surface area, the second conversion coefficient, multiple second fluid nuclear magnetic resonance signal intensity values, the first initial mass, and the calculated fourth contact area into the second expression to calculate the fourth wetting kinetics rate of the full-aperture pores of the second rock sample during spontaneous imbibition.

[0071] Through the above method, the wetting kinetics rate of the full-aperture pores of the second rock sample during spontaneous imbibition is obtained, providing an important basis for subsequent rock wettability evaluation.

[0072] Therefore, in an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of other pore types of rock samples during spontaneous imbibition and water absorption is provided. In S50, that is, based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values, multiple aqueous wetting kinetics rates of the second rock sample during spontaneous imbibition of an aqueous fluid phase are determined under multiple pore types, and specifically, the following steps S53 - S55 are further included: S53: Based on a preset pore radius, the pores of the second rock sample are divided into third - aperture pores and fourth - aperture pores, where the radius of the third - aperture pores is smaller than the radius of the fourth - aperture pores.

[0073] In this step, the preset pore radius is the boundary value of a predefined dividing line for classifying pores. Using the preset pore radius, the pores of the second rock sample are divided into large - aperture pores and small - aperture pores. Specifically, for any pore of the second rock sample, if the pore radius is less than or equal to the preset pore radius, it is confirmed that the pore is a small - aperture pore, that is, a third - aperture pore; if the pore radius is greater than the preset pore radius, it is confirmed that the pore is a large - aperture pore, that is, a fourth - aperture pore.

[0074] S54: Based on multiple second - sample nuclear magnetic resonance signal intensity values of the second rock sample, the preset pore radius, and the second initial nuclear magnetic resonance signal intensity value, multiple third - target fluid nuclear magnetic resonance signal intensity values corresponding to the third - aperture pores and multiple fourth - target fluid nuclear magnetic resonance signal intensity values corresponding to the fourth - aperture pores are determined.

[0075] In this step, the horizontal coordinate of the nuclear magnetic resonance T 2 spectrum reflects the pore size distribution. Using the conversion formula between the nuclear magnetic resonance transverse relaxation time and the pore size, based on the preset pore radius, in the nuclear magnetic resonance T 2 spectrum, the nuclear magnetic resonance transverse relaxation times corresponding to different pore types are determined, and then multiple sample nuclear magnetic resonance signal intensity values corresponding to different pore types are determined. Subsequently, by subtracting the initial nuclear magnetic resonance signal intensity value from the sample nuclear magnetic resonance signal intensity value of each pore type, the fluid nuclear magnetic resonance signal intensity value of the pores of each pore type during spontaneous imbibition and water absorption is obtained.

[0076] S55: Based on the second sample parameters, the second fluid parameters, multiple third - target fluid nuclear magnetic resonance signal intensity values, and multiple fourth - target fluid nuclear magnetic resonance signal intensity values, the fifth wetting kinetics rate of the third - aperture pores of the second rock sample during spontaneous imbibition of an aqueous fluid phase and the sixth wetting kinetics rate of the fourth - aperture pores of the second rock sample during spontaneous imbibition of an oil - phase fluid are determined.

[0077] In this step, after classifying the full-aperture pores of the second rock sample into third-aperture pores and fourth-aperture pores, based on the second sample parameters, the second fluid parameters, and multiple third-target fluid nuclear magnetic resonance signal intensity values under the condition of the third-aperture pores, determine the fifth wetting kinetic rate of the third-aperture pores during spontaneous imbibition of water. At the same time, based on the second sample parameters, the second fluid parameters, and multiple fourth-target fluid nuclear magnetic resonance signal intensity values under the condition of the fourth-aperture pores, determine the sixth wetting kinetic rate of the fourth-aperture pores during spontaneous imbibition of oil.

[0078] In an embodiment of the present application, a specific calculation scheme for the wetting kinetic rate of the full-aperture pores of a rock during spontaneous imbibition of oil is provided. In S55, that is, based on the second sample parameters, the second fluid parameters, multiple third-target fluid nuclear magnetic resonance signal intensity values, and multiple fourth-target fluid nuclear magnetic resonance signal intensity values, determine the fifth wetting kinetic rate of the third-aperture pores of the second rock sample when spontaneously sucking in the aqueous phase fluid, and the sixth wetting kinetic rate of the fourth-aperture pores when spontaneously sucking in the oil phase fluid. The specific steps include the following S551-S554: S551: Substitute the second conversion coefficient of the aqueous phase fluid, the second fluid density of the aqueous phase fluid, multiple third-target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each third-target fluid nuclear magnetic resonance signal intensity value into the first expression to calculate the fifth contact area of the aqueous phase fluid in the third-aperture pores of the second rock sample.

[0079] S552: Substitute the second fluid viscosity of the aqueous phase fluid, the second surface area of the second rock sample, the preset imbibition time, the second conversion coefficient of the aqueous phase fluid, multiple third-target fluid nuclear magnetic resonance signal intensity values of the aqueous phase fluid, the second initial mass of the second rock sample, and the fifth contact area into the second expression to calculate the fifth wetting kinetic rate of the third-aperture pores of the second rock sample when spontaneously sucking in the aqueous phase fluid.

[0080] S553: Substitute the second conversion coefficient of the aqueous phase fluid, the second fluid density of the aqueous phase fluid, multiple fourth-target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each fourth-target fluid nuclear magnetic resonance signal intensity value into the first expression to calculate the sixth contact area of the aqueous phase fluid in the fourth-aperture pores of the second rock sample.

[0081] S554: Substitute the second fluid viscosity of the aqueous phase fluid, the second surface area of the second rock sample, the preset imbibition time, the second conversion coefficient of the aqueous phase fluid, multiple fourth-target fluid nuclear magnetic resonance signal intensity values of the aqueous phase fluid, the second initial mass of the second rock sample, and the sixth contact area into the second expression to calculate the sixth wetting kinetic rate of the fourth-aperture pores of the second rock sample when spontaneously sucking in the aqueous phase fluid.

[0082] For steps S551 - S554, substitute the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous fluid, the third target fluid nuclear magnetic resonance signal intensity values of the third - pore - size pores under different imbibition time conditions, and their corresponding transverse relaxation times into the first expression to calculate the fifth contact area of the aqueous fluid in the third - pore - size pores of the second rock sample. Subsequently, substitute the second fluid viscosity, the second surface area, the second conversion coefficient, multiple fourth target fluid nuclear magnetic resonance signal intensity values, the second initial mass, and the calculated fifth contact area into the second expression to calculate the fifth wetting kinetics rate of the third - pore - size pores of the second rock sample during spontaneous imbibition of water. At the same time, substitute the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous fluid, the fourth target fluid nuclear magnetic resonance signal intensity values of the fourth - pore - size pores under different imbibition time conditions, and their corresponding transverse relaxation times into the first expression to calculate the sixth contact area of the aqueous fluid in the fourth - pore - size pores of the second rock sample. Subsequently, substitute the second fluid viscosity, the second surface area, the second conversion coefficient, multiple fourth target fluid nuclear magnetic resonance signal intensity values, the second initial mass, and the calculated sixth contact area into the second expression to calculate the sixth wetting kinetics rate of the fourth - pore - size pores of the second rock sample during spontaneous imbibition of water.

[0083] S60: Based on multiple oil - phase wetting kinetics rates and multiple water - phase wetting kinetics rates, generate multiple wetting kinetics rate coefficients to determine the wettability of the reservoir rock sample.

[0084] In this step, calculate the wetting kinetics rate coefficient through the oil - phase wetting kinetics rate and water - phase wetting kinetics rate corresponding to each pore size range. Finally, quantitatively evaluate the wettability of different pore size ranges in the unconventional tight reservoir rock according to the magnitudes of multiple wetting kinetics rate coefficients.

[0085] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate coefficient is provided. In S60, that is, based on multiple oil - phase wetting kinetics rates and multiple water - phase wetting kinetics rates, generate multiple wetting kinetics rate coefficients, and determine the wettability of the reservoir rock sample through multiple wetting kinetics rate coefficients, which specifically includes the following steps S61 - S62: S61: Substitute the oil - phase wetting kinetics rate and water - phase wetting kinetics rate of each pore type into the third expression to calculate the wetting kinetics rate coefficient of the reservoir rock under each pore type condition.

[0086] S62: Determine the wettability of the reservoir rock sample based on multiple wetting kinetics rate coefficients of multiple pore types.

[0087] For steps S61 - S62, the multiple oil - phase wetting kinetic rates represent the wetting kinetic rates of the full - aperture pores, large - aperture pores, and small - aperture pores in the reservoir rock during spontaneous imbibition of oil; the multiple water - wetting kinetic rates represent the wetting kinetic rates of the full - aperture pores, large - aperture pores, and small - aperture pores in the reservoir rock during spontaneous imbibition of water. Substitute the oil - phase wetting kinetic rate and the water - phase wetting kinetic rate under each pore type into the third expression for calculating the wetting kinetic rate coefficient in turn, and calculate the wetting kinetic rate coefficient of the pores of each pore type in the reservoir rock during spontaneous imbibition.

[0088] The third expression is: ; In the formula, the above - mentioned \(W_{kc}\) is the wetting kinetic rate coefficient; the above - mentioned \(\alpha\) o is the oil - phase wetting kinetic rate; the above - mentioned \(\alpha\) w is the water - phase wetting kinetic rate.

[0089] To facilitate the understanding of the solutions and effects of the embodiments of the present application, a specific application example is given below. Those skilled in the art should understand that this example is only for facilitating the understanding of the present application, and any specific details are not intended to limit the present application in any way.

[0090] Step 1: Select an unconventional tight reservoir core column sample and cut it into two samples with approximately the same mass and volume from the middle: sample O and sample W for imbibition rate comparison. After cleaning the two cut samples, place them in an oven and dry them at 110 °C for 24 h. After drying, wait for the samples to cool to room temperature, and then measure the initial matrix dry nuclear magnetic resonance signals of sample O and sample W at this time, and record the corresponding initial masses as \(m\) o = 21.54 g and \(m\) w = 22.19 g, and record the corresponding imbibition external surface areas as \(A\) o = 22.93 \(cm^2\) 2 and \(A\) w = 23.32 \(cm^2\) 2 . Among them, the specific process of performing the nuclear magnetic resonance test can be carried out according to the requirements of actual applications, and the present application will not elaborate here.

[0091] Step 2: Use n-dodecane simulated oil sample and deionized water simulated water sample. Place the dry sample O in a beaker containing the oil-phase fluid, and place the dry sample W in a beaker containing the water-phase fluid. The dry rock sample will spontaneously imbibe the external fluid. Record the changes in the imbibed mass of sample O and sample W over time respectively, and measure the nuclear magnetic resonance signal intensity values of the samples under different imbibition time conditions. Exemplarily, the selected test times are 5 min, 10 min, 30 min, 120 min, 240 min, 420 min, 1860 min, 2220 min, 3240 min, and 3840 min. As Figure 2 and Figure 3 shown, it is the nuclear magnetic resonance T 2 spectrum of the rock sample, where Figure 2 is the nuclear magnetic resonance T 2 spectrum of sample W in the initial state and under different imbibition time conditions; Figure 3 is the nuclear magnetic resonance T 2 spectrum of sample O in the initial state and under different imbibition time conditions.

[0092] Step 3: By measuring the nuclear magnetic resonance signal intensity values of n-dodecane and deionized water under different mass conditions, it is found that there is a linear relationship between deionized water and n-dodecane and their corresponding cumulative nuclear magnetic signals. Fit the calibration equations of the nuclear magnetic signals with n-dodecane and deionized water respectively, and the slopes are the masses of n-dodecane and deionized water corresponding to the unit signal. Determine the corresponding conversion coefficients k o and k w of n-dodecane and deionized water based on the two slopes. Exemplarily, the selected masses of n-dodecane are: 0.05 g, 0.12 g, 0.22 g, 0.34 g, 0.41 g, 0.55 g; the selected masses of deionized water are: 0.07 g, 0.16 g, 0.23 g, 0.31 g, 0.42 g, 0.53 g. As Figure 4 and Figure 5 shown, it is the schematic diagram of the conversion relationship between the mass of the imbibed fluid and the amount of nuclear magnetic resonance signal, where Figure 4 is the schematic diagram of the conversion relationship between the amount of nuclear magnetic resonance signal and the mass of deionized water obtained by fitting; Figure 5 is the schematic diagram of the conversion relationship between the amount of nuclear magnetic resonance signal and the mass of n-dodecane obtained by fitting.

[0093] Step 4: Subtract the initial nuclear magnetic resonance (NMR) signal intensity value from the NMR signal intensity values of Sample O and Sample W under different imbibition time conditions to obtain the variation law of the fluid NMR signal intensity value of n - dodecane imbibed by Sample O and the fluid NMR signal intensity value of deionized water imbibed by Sample W under different imbibition time conditions. Since the NMR signal characterizes the full - pore - size distribution of the imbibed fluid, the contact area between the imbibed fluid and the pores in the sample can be calculated using the expression for the contact area between the imbibed fluid and the pores. The contact area between deionized water and the sample pores is 4.6×10⁵ cm 2 , and the contact area between n - dodecane and the sample pores is 1.1×10⁶ cm 2 . As shown in Figure 6 and Figure 7 , it is a schematic diagram of the variation relationship between the NMR signal and the imbibition time when the full - pore - size pores spontaneously imbibe the fluid. Among them, Figure 6 is a schematic diagram of the variation relationship between the NMR signal and the imbibition time when the full - pore - size pores imbibe deionized water; Figure 7 is a schematic diagram of the variation relationship between the NMR signal and the imbibition time when the full - pore - size pores imbibe n - dodecane.

[0094] The expression for the contact area between the imbibed fluid and the pores is as follows: ; In the formula, the above - mentioned S is the contact area between the pores of the rock sample and the imbibed fluid, cm 2 ; the above - mentioned q is the total number of multiple imbibition times; the above - mentioned k is the conversion coefficient between the imbibed fluid and the NMR signal, g / a.u.; the above - mentioned ρ 2 is the nuclear magnetic relaxation rate, nm / ms; the above - mentioned ρ is the fluid density of the imbibed fluid, g / cm 3 ; the above - mentioned n is the range of the NMR signal region of the nuclear magnetic resonance T 2 spectrum; the above - mentioned p i is the first fluid NMR signal intensity value of the i - th NMR signal point; the above - mentioned T 2i is the transverse relaxation time of the i - th NMR signal point; the above - mentioned is the sum of the ratios of the NMR signal intensity value to its corresponding transverse relaxation time, a.u. / ms.

[0095] Step 5: Analyze the variation relationship between the NMR signal and the imbibition time during the different imbibition processes of spontaneous oil imbibition and spontaneous water imbibition in the rock. Among them, the slope of the change in the NMR signal during deionized water imbibition is 3.9×10 7 , and the slope of the change in the NMR signal during deionized water imbibition is 3.8×10 5, the wetting kinetic rate is calculated by using the expression for calculating the wetting kinetic rate of a rock sample during spontaneous imbibition. Furthermore, based on the wetting kinetic rate of the oil phase and the wetting kinetic rate of the water phase, the wetting kinetic rate coefficient of the reservoir rock is calculated. Finally, the overall wettability of the reservoir rock is quantitatively evaluated by the magnitude of the wetting kinetic rate coefficient. Specifically, α o is defined as the wetting kinetic rate when the sample imbibes oil, and α w is defined as the wetting kinetic rate when the sample imbibes water. The calculation result of α w is 25.87, and the calculation result of α o is 7.60. Define Wkc as the wetting kinetic rate coefficient. When Wkc ≤ 0, the rock shows oleophilicity; when Wkc > 0, the rock shows hydrophilicity. According to the wetting kinetic rate, the wetting kinetic rate coefficient Wkc = 2.40 is quantitatively characterized, indicating hydrophilicity.

[0096] Specifically, the calculation process of the wetting kinetic rate is as follows. Substitute the fluid viscosity of the imbibing fluid, the surface area of the rock sample, the conversion coefficient of the imbibing fluid, the fluid nuclear magnetic resonance signal intensity value, the initial mass of the rock sample, and the contact area into the expression when the rock imbibes oil and when the rock imbibes water respectively to calculate the wetting kinetic rate of the full-aperture pores of the rock sample during spontaneous imbibition.

[0097] The expression for the wetting kinetic rate of the full-aperture pores of sample O during spontaneous oil imbibition is: ; In the formula, the above-mentioned α o is the wetting kinetic rate of sample O during spontaneous oil imbibition; the above-mentioned μ o is the viscosity of n-dodecane, with the unit of cP; the above-mentioned A o is the surface area of sample O, with the unit of cm 2 ; the above-mentioned k o is the conversion coefficient between n-dodecane and the nuclear magnetic signal; the above-mentioned ρ 2 is the nuclear magnetic relaxation rate, ρ 2 is a constant; the above-mentioned ρ o is the density of n-dodecane, with the unit of cm 3 ; the above-mentioned n is the range of the nuclear magnetic resonance signal region of the nuclear magnetic resonance T 2 spectrum; the above-mentioned t is the imbibition time, with the unit of min; the above-mentioned p i is the n-dodecane nuclear magnetic resonance signal intensity value at the i-th nuclear magnetic signal point; the above-mentioned T 2i is the transverse relaxation time at the i-th nuclear magnetic signal point; the above-mentioned m o is the initial mass of sample O, with the unit of g.

[0098] The expression for the wetting kinetic rate of the full-aperture pores of sample W during spontaneous water imbibition is: ; In the formula, the above-mentioned α w is the wetting kinetic rate during the spontaneous imbibition of sample W; the above-mentioned μ w is the viscosity of deionized water, with the unit of cP; the above-mentioned A w is the surface area of sample W, with the unit of cm 2 ; the above-mentioned k w is the conversion coefficient between deionized water and the nuclear magnetic signal; the above-mentioned ρ 2 is the nuclear magnetic relaxation rate; the above-mentioned ρ w is the density of deionized water, with the unit of cm 3 ; the above-mentioned n is the range of the nuclear magnetic resonance signal region of the nuclear magnetic resonance T 2 spectrum; the above-mentioned t is the imbibition time, with the unit of min; the above-mentioned p i is the nuclear magnetic resonance signal intensity value of deionized water at the i-th nuclear magnetic signal point; the above-mentioned T 2i is the transverse relaxation time at the i-th nuclear magnetic signal point; the above-mentioned m w is the initial mass of sample W, with the unit of g.

[0099] Subsequently, according to the oil-phase wetting kinetic rate and the water-phase wetting kinetic rate, the wetting kinetic rate coefficient of the reservoir rock is calculated using the third expression.

[0100] The third expression is: .

[0101] Step 6: Define the small-aperture pores with pore radius r ≤ 2 nm as adsorption pores, and the large-aperture pores with pore radius r > 2 nm as seepage pores. According to the nuclear magnetic resonance transverse relaxation time - pore aperture conversion formula T 2 = r / C, where the shale conversion coefficient C is approximately 10 nm / ms, perform nuclear magnetic conversion on the pore radius. In the nuclear magnetic resonance T 2 spectrum, classify the pores as adsorption pores with T 2 ≤ 2 / C and seepage pores with T 2 > 2 / C. In the nuclear magnetic resonance T 2 spectrum, classify the pores as adsorption pores with T 2 ≤ 0.2 ms and seepage pores with T 2 > 0.2 ms. Obtain the nuclear magnetic resonance T 2 spectra at different imbibition time conditions, where T 2 ≤ 0.2 ms and T 2The nuclear magnetic resonance signal intensity values of the samples within two ranges greater than 0.2 ms. Subsequently, by subtracting the initial nuclear magnetic resonance signal intensity values within the corresponding ranges in the initial state from the nuclear magnetic resonance signal intensity values of the samples with different pore size distribution ranges, the nuclear magnetic resonance signal intensity values of n-dodecane adsorbed and seeped by the adsorption pores and seepage pores in sample O, and the nuclear magnetic resonance signal intensity values of deionized water adsorbed and seeped by the adsorption pores and seepage pores in sample W at different imbibition times are obtained.

[0102] Step 7: Calculate the contact area of deionized water and n-dodecane in the adsorption pores respectively during the imbibition process of the reservoir rock. The contact area between deionized water and the pores in the adsorption pores is 2.8×105 cm 2 , and the contact area between deionized water and the pores in the adsorption pores is 1.1×106 cm 2 . As Figure 8 and Figure 9 shown, it is a schematic diagram of the relationship between the nuclear magnetic resonance signal and the imbibition time during the spontaneous imbibition of fluid in the adsorption pores. Among them, Figure 8 is the relationship diagram of the nuclear magnetic resonance signal with the imbibition time during the imbibition of deionized water in the adsorption pores; Figure 9 is the relationship diagram of the nuclear magnetic resonance signal with the imbibition time during the imbibition of n-dodecane in the adsorption pores. According to the changes in the nuclear magnetic resonance signals of the imbibed fluids in the adsorption pores during different imbibition processes, the slope of the change in the nuclear magnetic resonance signal of deionized water imbibed in the adsorption pores is 6.7×10 3 , and the slope of the change in the nuclear magnetic resonance signal of n-dodecane imbibed is 3.0×10 5 . Calculate the wetting kinetic rate α mi-w =25.87, α mi-w =7.60. And finally, quantitatively characterize the wetting kinetic rate coefficient Wkc in the adsorption pores according to the wetting kinetic rate mi =-0.59, showing oleophilicity.

[0103] The calculation process expression is as follows: ; In the formula, the above S mi is the contact area between the imbibed fluid and the pores in the adsorption pores during the imbibition process of the reservoir rock; the above u is the transverse relaxation time region of the adsorption pores; the above is the sum of the ratios of the nuclear magnetic resonance signal intensity values within the range of the adsorption pores to the corresponding transverse relaxation times.

[0104] ; In the formula, the above α mi-w is the wetting kinetic rate of deionized water imbibed in the adsorption pores of sample W; the above μ w is the viscosity of deionized water; the above A w is the surface area of sample W; the above kw is the conversion coefficient between deionized water and the nuclear magnetic resonance signal; the above ρ w is the density of deionized water; the above m w is the initial mass of sample W.

[0105] ; In the formula, the above α mi-o为 is the wetting kinetic rate of the adsorption pores in sample O for imbibing n - dodecane; the above μ o is the viscosity of n - dodecane; the above A o is the surface area of sample O; the above k o is the conversion coefficient between n - dodecane and the nuclear magnetic resonance signal; the above ρ o is the density of n - dodecane; the above m o represents the initial mass of sample O.

[0106] ; In the formula, the above Wkc mi is the wetting kinetic rate coefficient of the adsorption pores; the above α mi-o is the wetting kinetic rate of the adsorption pores in sample O for imbibing n - dodecane; the above α mi-w is the wetting kinetic rate of the adsorption pores in sample W for imbibing deionized water.

[0107] Step 8: Calculate the contact area of deionized water and n - dodecane in the flow pores during the imbibition process of the reservoir rock. The contact area of deionized water and the pores in the flow pores is 1.7×105 cm 2 , and the contact area of deionized water and the pores in the flow pores is 5.2×104 cm 2 . As Figure 10 and Figure 11 shown, it is a schematic diagram of the relationship between the nuclear magnetic resonance signal and the imbibition time when the fluid spontaneously imbibes in the flow pores. Among them, Figure 10 is the relationship diagram of the nuclear magnetic resonance signal and the imbibition time when deionized water imbibes in the flow pores; Figure 11 is the relationship diagram of the nuclear magnetic resonance signal and the imbibition time when n - dodecane imbibes in the flow pores. According to the relationship between the nuclear magnetic resonance signal of the imbibed fluid in the flow pores and the imbibition time during different imbibition processes, the slope of the change in the nuclear magnetic resonance signal of deionized water imbibed in the flow pores is 2.4×10 7 , and the slope of the change in the nuclear magnetic resonance signal of n - dodecane imbibed is 1.9×10 4 . Calculate the wetting kinetic rate α me-w = 25.87, α me-o = 3.95. And finally, quantitatively characterize the wetting kinetic rate coefficient Wkc in the flow pores according to the wetting kinetic rate me= 5.38, showing hydrophilicity.

[0108] The calculation process expression is as follows: ; In the formula, the above-mentioned S me is the contact area between the imbibition fluid in the seepage pores and the pores during the imbibition process; the above-mentioned is the sum of the ratio of the nuclear magnetic resonance signal intensity value within the range of the seepage pores to the corresponding transverse relaxation time.

[0109] ; In the formula, the above-mentioned α me-w is the wetting kinetic rate of the imbibition of deionized water in the seepage pores of sample W; the above-mentioned μ w is the viscosity of deionized water; the above-mentioned A w is the surface area of sample W; the above-mentioned k w is the conversion coefficient between deionized water and the nuclear magnetic resonance signal; the above-mentioned ρ w is the density of deionized water; the above-mentioned m w is the initial mass of sample W.

[0110] ; In the formula, the above-mentioned α me-o is the wetting kinetic rate of the imbibition of n-dodecane in the seepage pores of sample O; the above-mentioned μ o is the viscosity of n-dodecane; the above-mentioned A o is the surface area of sample O; the above-mentioned k o is the conversion coefficient between n-dodecane and the nuclear magnetic resonance signal; the above-mentioned ρ o is the density of n-dodecane; the above-mentioned m o represents the initial mass of sample O.

[0111] ; In the formula, the above-mentioned Wkc me is the wetting kinetic rate coefficient of the seepage pores; the above-mentioned α me-o is the wetting kinetic rate of the imbibition of n-dodecane in the seepage pores of sample O; the above-mentioned α me-w is the wetting kinetic rate of the imbibition of deionized water in the seepage pores of sample W.

[0112] It can be seen that in the above solution, two rock samples with the same physical properties are used to spontaneously imbibe oil-phase fluid and water-phase fluid respectively to simulate the processes of oil imbibition and water imbibition. Combining with nuclear magnetic resonance technology, the variation law and distribution law of fluid signals during the processes of oil-phase fluid imbibition and water-phase fluid imbibition in unconventional tight reservoir samples are characterized. The pore size distribution of the reservoir rock pores is determined according to the nuclear magnetic resonance data, and then the different imbibition characteristic data of the pores with different pore size distributions in the rock for oil and water are calculated. Finally, the wetting kinetic rate coefficient of the rock under different pore size distribution conditions is calculated, and this is used to judge the wettability of the rock. Through the above method, the wettability of reservoir rocks with different pore sizes can be quantitatively measured, while greatly shortening the measurement time period, and effectively overcoming the technical problems such as measurement result errors, long experimental period and poor applicability brought by the application of conventional wettability measurement methods to unconventional reservoir rocks.

[0113] The above-described embodiments are only used to illustrate the technical solutions of the present application, rather than to limit them; although the present application has been described in detail with reference to the foregoing embodiments, those of ordinary skill in the art should understand that they can still modify the technical solutions recorded in the foregoing embodiments, or perform equivalent replacements on some of the technical features; and these modifications or replacements do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the various embodiments of the present application, and should all be included in the protection scope of the present application.

Claims

1. A reservoir rock wettability evaluation method, characterized in that: include: Generate a first rock sample and a second rock sample based on the reservoir rock sample, and obtain a first sample parameter of the first rock sample, a first initial nuclear magnetic resonance signal intensity value, a second sample parameter of the second rock sample, a second initial nuclear magnetic resonance signal intensity value, a first fluid parameter of the oil phase fluid, and a second fluid parameter of the water phase fluid; During the process of the first rock sample spontaneously absorbing the oil phase fluid, performing a nuclear magnetic resonance test on the first rock sample according to multiple imbibition times to obtain a nuclear magnetic resonance signal intensity value of the first sample under each imbibition time condition, and determining a first fluid nuclear magnetic resonance signal intensity value of the oil phase fluid absorbed by the first rock sample under each imbibition time condition based on the first initial nuclear magnetic resonance signal intensity value and the first sample nuclear magnetic resonance signal intensity value; During the process of the second rock sample spontaneously absorbing the aqueous phase fluid, performing a nuclear magnetic resonance test on the second rock sample according to the multiple imbibition times to obtain a nuclear magnetic resonance signal intensity value of the second sample under the condition of each imbibition time, and determining a second fluid nuclear magnetic resonance signal intensity value of the aqueous phase fluid absorbed by the second rock sample under the condition of each imbibition time based on the second initial nuclear magnetic resonance signal intensity value and the second sample nuclear magnetic resonance signal intensity value; Determine, based on the first sample parameter, the first fluid parameter and a plurality of first fluid nuclear magnetic resonance signal intensity values, a plurality of oil phase wetting kinetic rates when the first rock sample spontaneously absorbs the oil phase fluid under a plurality of pore types; Determine multiple water-phase wetting kinetic rates when the second rock sample spontaneously absorbs water-phase fluid under the multiple pore types based on the second sample parameter, the second fluid parameter and multiple second fluid nuclear magnetic resonance signal intensity values; Based on the multiple oil phase wetting kinetic rates and the multiple water phase wetting kinetic rates, a plurality of wetting kinetic rate coefficients are generated, and the wettability of the reservoir rock sample is determined by the multiple wetting kinetic rate coefficients.

2. The method according to claim 1, characterized in that: The step of generating a first rock sample and a second rock sample based on a reservoir rock sample, and obtaining a first sample parameter of the first rock sample, a first initial nuclear magnetic resonance signal intensity value, a second sample parameter of the second rock sample, a second initial nuclear magnetic resonance signal intensity value, a first fluid parameter of an oil phase fluid, and a second fluid parameter of an aqueous phase fluid specifically includes: Obtaining reservoir rock samples; cutting the reservoir rock sample into the first rock sample and the second rock sample of the same mass and the same volume; Obtaining a first initial mass and a first surface area of ​​the first rock sample, and a second initial mass and a second surface area of ​​the second rock sample; Performing nuclear magnetic resonance testing on the first rock sample and the second rock sample respectively to generate a first initial nuclear magnetic resonance signal intensity value of the first rock sample and a second initial nuclear magnetic resonance signal intensity value of the second rock sample; Acquire a first fluid density and a first fluid viscosity of the oil phase fluid, and a second fluid density and a second fluid viscosity of the water phase fluid; Performing a nuclear magnetic resonance test on the oil phase fluid under a plurality of first preset mass conditions, and performing a nuclear magnetic resonance test on the water phase fluid under a plurality of second preset mass conditions, to obtain a plurality of third initial nuclear magnetic resonance signal intensity values ​​of the oil phase fluid under a plurality of first preset mass conditions, and a plurality of fourth initial nuclear magnetic resonance signal intensity values ​​of the water phase fluid under a plurality of second preset mass conditions; Based on the multiple first preset masses and the multiple third initial nuclear magnetic resonance signal intensity values, a first linear equation corresponding to the oil phase fluid is generated, and based on a first slope of the first linear equation, a first conversion coefficient between the mass of the oil phase fluid and the nuclear magnetic resonance signal is determined; Based on the multiple second preset masses and the multiple fourth initial nuclear magnetic resonance signal intensity values, a second linear equation corresponding to the aqueous fluid is generated, and based on the second slope of the second linear equation, a second conversion coefficient between the mass of the aqueous fluid and the nuclear magnetic resonance signal is determined.

3. The method according to claim 1, characterized in that: The step of performing a nuclear magnetic resonance test on the first rock sample according to a plurality of imbibition times during the process of the first rock sample spontaneously absorbing the oil phase fluid to obtain a nuclear magnetic resonance signal intensity value of the first sample under each imbibition time condition, and determining the first fluid nuclear magnetic resonance signal intensity value of the oil phase fluid absorbed by the first rock sample under each imbibition time condition based on the first initial nuclear magnetic resonance signal intensity value and the first sample nuclear magnetic resonance signal intensity value specifically comprises: placing the first rock sample in the oil-phase fluid, so that the pores of the first rock sample can spontaneously absorb the oil-phase fluid; During the process of the first rock sample spontaneously absorbing the oil phase fluid, performing a nuclear magnetic resonance test on the first rock sample according to the multiple imbibition times to determine the first sample nuclear magnetic resonance signal intensity value corresponding to the first rock sample under each imbibition time condition; By subtracting the first initial nuclear magnetic resonance signal intensity value from the first sample nuclear magnetic resonance signal intensity value under the said imbibition time condition, the first fluid nuclear magnetic resonance signal intensity value of the oil phase fluid absorbed by the first rock sample under the said imbibition time condition is obtained.

4. The method according to claim 1, characterized in that: The step of performing a nuclear magnetic resonance test on the second rock sample according to the plurality of imbibition times during the process of the second rock sample spontaneously absorbing the aqueous phase fluid to obtain a nuclear magnetic resonance signal intensity value of the second sample under each imbibition time condition, and determining a second fluid nuclear magnetic resonance signal intensity value of the aqueous phase fluid absorbed by the second rock sample under each imbibition time condition based on the second initial nuclear magnetic resonance signal intensity value and the second sample nuclear magnetic resonance signal intensity value specifically comprises: placing the second rock sample in the water phase fluid, so that the pores of the second rock sample spontaneously absorb the water phase fluid; During the process of the second rock sample spontaneously absorbing the aqueous phase fluid, performing a nuclear magnetic resonance test on the second rock sample according to the multiple imbibition times to determine a second sample nuclear magnetic resonance signal intensity value of the second rock sample under each imbibition time condition; By subtracting the second initial nuclear magnetic resonance signal intensity value from the second sample nuclear magnetic resonance signal intensity value under the said infiltration time condition, the second fluid nuclear magnetic resonance signal intensity value of the aqueous phase fluid absorbed by the second rock sample under the said infiltration time condition is obtained.

5. The method according to claim 3, characterized in that: The step of determining a plurality of oil phase wetting kinetic rates when the first rock sample spontaneously absorbs the oil phase fluid under a plurality of pore types based on the first sample parameter, the first fluid parameter and a plurality of first fluid nuclear magnetic resonance signal intensity values ​​specifically comprises: Determine a first contact area of ​​the oil-phase fluid in the full-aperture pores of the first rock sample based on the first conversion coefficient of the oil-phase fluid, the first fluid density of the oil-phase fluid, each first fluid nuclear magnetic resonance signal intensity value, and the transverse relaxation time corresponding to each first fluid nuclear magnetic resonance signal intensity value; Based on the first fluid viscosity of the oil phase fluid, the first surface area of ​​the first rock sample, the first conversion coefficient, multiple first fluid nuclear magnetic resonance signal intensity values, the first initial mass and the first contact area, determine the first wetting kinetic rate when the first rock sample spontaneously absorbs the oil phase fluid.

6. The method according to claim 5, characterized in that The step of determining a plurality of oil phase wetting kinetic rates when the first rock sample spontaneously absorbs the oil phase fluid under a plurality of pore types based on the first sample parameter, the first fluid parameter and a plurality of first fluid nuclear magnetic resonance signal intensity values ​​specifically includes: Based on a preset pore radius, the pores of the first rock sample are divided into pores of a first pore size and pores of a second pore size, wherein the radius of the pores of the first pore size is smaller than the radius of the pores of the second pore size; Based on the multiple first sample nuclear magnetic resonance signal intensity values ​​of the first rock sample, the preset pore radius and the first initial nuclear magnetic resonance signal intensity value, determine the multiple first target fluid nuclear magnetic resonance signal intensity values ​​corresponding to the first pore size and the multiple second target fluid nuclear magnetic resonance signal intensity values ​​corresponding to the second pore size; Based on the first sample parameter, the first fluid parameter, the multiple first target fluid nuclear magnetic resonance signal intensity values ​​and the multiple second target fluid nuclear magnetic resonance signal intensity values, determine the second wetting kinetic rate when the first pore size pores of the first rock sample spontaneously absorb oil phase fluid, and the third wetting kinetic rate when the second pore size pores spontaneously absorb oil phase fluid.

7. The method according to claim 6, characterized in that The step of determining the second wetting kinetic rate when the first pore size pores of the first rock sample spontaneously absorb the oil phase fluid and the third wetting kinetic rate when the second pore size pores spontaneously absorb the oil phase fluid based on the first sample parameter, the first fluid parameter, the multiple first target fluid nuclear magnetic resonance signal intensity values ​​and the multiple second target fluid nuclear magnetic resonance signal intensity values ​​specifically includes: Substituting the first conversion coefficient of the oil phase fluid, the first fluid density of the oil phase fluid, a plurality of first target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each first target fluid nuclear magnetic resonance signal intensity value into a first expression, calculating the second contact area of ​​the oil phase fluid in the first aperture pore of the first rock sample; Substituting the first fluid viscosity of the oil phase fluid, the first surface area of ​​the first rock sample, the preset imbibition time, the first conversion coefficient of the oil phase fluid, the multiple first target fluid nuclear magnetic resonance signal intensity values ​​of the oil phase fluid, the first initial mass of the first rock sample and the second contact area into a second expression, calculates the second wetting kinetic rate when the first pore size pores of the first rock sample spontaneously absorb the oil phase fluid; Substituting the first conversion coefficient of the oil phase fluid, the first fluid density of the oil phase fluid, a plurality of second target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each second target fluid nuclear magnetic resonance signal intensity value into the first expression, calculating the third contact area of ​​the oil phase fluid in the pores of the second pore size of the first rock sample; The first fluid viscosity of the oil phase fluid, the first surface area of ​​the first rock sample, the preset imbibition time, the first conversion coefficient of the oil phase fluid, the multiple second target fluid nuclear magnetic resonance signal intensity values ​​of the oil phase fluid, the first initial mass of the first rock sample and the third contact area are substituted into the second expression to calculate the third wetting kinetic rate when the second aperture pores of the first rock sample spontaneously absorb the oil phase fluid.

8. The method according to claim 4, characterized in that The step of determining multiple water-phase wetting kinetic rates when the second rock sample spontaneously absorbs the water-phase fluid under the multiple pore types based on the second sample parameter, the second fluid parameter and multiple second fluid nuclear magnetic resonance signal intensity values ​​specifically includes: Determine a fourth contact area of ​​the water-phase fluid in the full-aperture pores of the second rock sample based on a second conversion coefficient of the water-phase fluid, a second fluid density of the water-phase fluid, each second fluid nuclear magnetic resonance signal intensity value, and a transverse relaxation time corresponding to each second fluid nuclear magnetic resonance signal intensity value; Based on the second fluid viscosity of the aqueous fluid, the second surface area of ​​the second rock sample, the second conversion coefficient, multiple second fluid nuclear magnetic resonance signal intensity values, the second initial mass and the fourth contact area, the fourth wetting kinetic rate when the second rock sample spontaneously absorbs the aqueous fluid is determined.

9. The method according to claim 8, characterized in that The step of determining multiple water-phase wetting kinetic rates when the second rock sample spontaneously absorbs the water-phase fluid under the multiple pore types based on the second sample parameter, the second fluid parameter and multiple second fluid nuclear magnetic resonance signal intensity values ​​specifically includes: Based on a preset pore radius, the pores of the second rock sample are divided into pores of a third pore size and pores of a fourth pore size, wherein the radius of the pores of the third pore size is smaller than the radius of the pores of the fourth pore size; Based on the multiple second sample nuclear magnetic resonance signal intensity values ​​of the second rock sample, the preset pore radius and the second initial nuclear magnetic resonance signal intensity value, determine the multiple third target fluid nuclear magnetic resonance signal intensity values ​​corresponding to the third pore size and the multiple fourth target fluid nuclear magnetic resonance signal intensity values ​​corresponding to the fourth pore size; Based on the second sample parameters, the second fluid parameters, the multiple third target fluid nuclear magnetic resonance signal intensity values ​​and the multiple fourth target fluid nuclear magnetic resonance signal intensity values, the fifth wetting kinetic rate of the third pore size of the second rock sample when the water phase fluid is spontaneously absorbed, and the sixth wetting kinetic rate of the fourth pore size when the oil phase fluid is spontaneously absorbed.

10. The method according to claim 9, characterized in that The step of determining the fifth wetting kinetic rate when the third pore size pores of the second rock sample spontaneously absorb water phase fluid and the sixth wetting kinetic rate when the fourth pore size pores spontaneously absorb oil phase fluid based on the second sample parameter, the second fluid parameter, the plurality of third target fluid nuclear magnetic resonance signal intensity values ​​and the plurality of fourth target fluid nuclear magnetic resonance signal intensity values ​​specifically comprises: Substituting the second conversion coefficient of the water phase fluid, the second fluid density of the water phase fluid, a plurality of third target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each third target fluid nuclear magnetic resonance signal intensity value into the first expression, calculate the fifth contact area of ​​the water phase fluid in the pores of the third pore size of the second rock sample; Substituting the second fluid viscosity of the water phase fluid, the second surface area of ​​the second rock sample, the preset imbibition time, the second conversion coefficient of the water phase fluid, a plurality of third target fluid nuclear magnetic resonance signal intensity values ​​of the water phase fluid, the second initial mass of the second rock sample and the fifth contact area into a second expression, calculates the fifth wetting kinetic rate when the third pore size pores of the second rock sample spontaneously absorb the water phase fluid; Substituting the second conversion coefficient of the water phase fluid, the second fluid density of the water phase fluid, a plurality of fourth target fluid nuclear magnetic resonance signal intensity values, and the transverse relaxation time corresponding to each fourth target fluid nuclear magnetic resonance signal intensity value into the first expression, calculate the sixth contact area of ​​the water phase fluid in the pores of the fourth pore size of the second rock sample; The second fluid viscosity of the aqueous fluid, the second surface area of ​​the second rock sample, the preset imbibition time, the second conversion coefficient of the aqueous fluid, multiple fourth target fluid nuclear magnetic resonance signal intensity values ​​of the aqueous fluid, the second initial mass of the second rock sample and the sixth contact area are substituted into the second expression to calculate the sixth wetting kinetic rate when the fourth pore size of the second rock sample spontaneously absorbs the aqueous fluid.

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