Reservoir Rock Wettability Evaluation Method

Abstract

The present application discloses a method for evaluating the wettability of reservoir rocks. By using two rock samples with the same physical properties to spontaneously imbibe oil-phase fluid and water-phase fluid respectively to simulate the processes of oil imbibition and water imbibition, and combining nuclear magnetic resonance technology to characterize the variation law and distribution law of fluid signals during the processes of oil-phase fluid and water-phase fluid imbibition in 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 coefficient of the rock under different pore size distribution conditions, and use this to judge the wettability of the rock. While realizing the quantitative measurement of the wettability of reservoir rocks with different pore sizes, 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 to a method for evaluating the wettability of reservoir rocks. Background Art

[0002] At present, unconventional oil and gas have 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. Commonly used wettability measurement methods in related technologies (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:

[0005] 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 a water-phase fluid;

[0006] During the process of the first rock sample spontaneously imbibing the oil-phase fluid, performing nuclear magnetic resonance tests on the first rock sample according to 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;

[0007] During the process of the second rock sample spontaneously imbibing the water-phase fluid, performing nuclear magnetic resonance tests on the second rock sample according to 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;

[0008] 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 when the first rock sample spontaneously imbibes an oil-phase fluid under multiple pore types;

[0009] Based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values, determine multiple water-phase wetting kinetic rates when the second rock sample spontaneously imbibes a water-phase fluid under multiple pore types;

[0010] Based on multiple oil-phase wetting kinetic rates and multiple water-phase 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.

[0011] In the solution implemented by the above reservoir rock wettability evaluation method, two rock samples with the same physical properties are used to spontaneously imbibe an oil-phase fluid and a water-phase fluid respectively to 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 oil-phase fluid imbibition and water-phase fluid imbibition for unconventional tight reservoir samples. Determine the pore size distribution of the reservoir rock pores based on 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 the technical problems such as measurement result errors, long experimental period, and poor applicability brought by conventional wettability measurement methods when applied to unconventional reservoir rocks.

[0012] 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 given below. Brief Description of the Drawings

[0013] By reading the detailed description of the preferred embodiments below, 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:

[0014] Figure 1 is a schematic flowchart of a method for evaluating the wettability of reservoir rocks in an embodiment of the present application;

[0015] Figure 2It is the nuclear magnetic resonance T2 spectrum of sample W under the initial state and different imbibition time conditions in an embodiment of the present application;

[0016] Figure 3 It is the nuclear magnetic resonance T2 spectrum of sample O under the initial state and different imbibition time conditions in an embodiment of the present application;

[0017] Figure 4 It is a schematic diagram of the conversion relationship between the nuclear magnetic resonance signal quantity and the mass of deionized water fitted in an embodiment of the present application;

[0018] Figure 5 It is a schematic diagram of the conversion relationship between the nuclear magnetic resonance signal quantity and the mass of n-dodecane fitted in an embodiment of the present application;

[0019] Figure 6 It is a schematic diagram of the variation relationship of the nuclear magnetic resonance signal with the imbibition time when deionized water is imbibed in the full-aperture pores in an embodiment of the present application;

[0020] Figure 7 It is a schematic diagram of the variation relationship of the nuclear magnetic resonance signal with the imbibition time when n-dodecane is imbibed in the full-aperture pores in an embodiment of the present application;

[0021] Figure 8 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time when deionized water is imbibed in the adsorption pores in an embodiment of the present application;

[0022] Figure 9 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time when n-dodecane is imbibed in the adsorption pores in an embodiment of the present application;

[0023] Figure 10 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time when deionized water is imbibed in the flow pores in an embodiment of the present application;

[0024] Figure 11 It is a graph of the variation relationship of the nuclear magnetic resonance signal with the imbibition time when n-dodecane is imbibed in the flow pores in an embodiment of the present application. Detailed implementation manners

[0025] Hereinafter, the 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.

[0026] The reservoir rock wettability evaluation method provided by this application can be applied to the wettability measurement scenario of unconventional tight reservoirs. At present, as the difficulty of conventional oil and gas resource exploitation increases, unconventional oil and gas has gradually become the main force driving 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 stronger affinity or spreading property of one of the two immiscible fluids relative to the other fluid on the surface of rock pores when there are two immiscible fluids in the rock pores. 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.

[0027] 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 directly observes the wetting angle of the specific limited surface where the liquid droplet contacts the rock surface. 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 low porosity and low permeability characteristics of unconventional tight reservoirs, the experimental period is long and the applicability of the measurement method is poor.

[0028] 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 this application, including the following steps:

[0029] 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.

[0030] In this step, for unconventional oil and gas reservoirs, a considerable portion of micropores are distributed in organic matter. These pores exhibit strong lipophilicity and may account for 40%-60% of the total pore space. A large amount of oil and gas is stored in this space. In contrast, some mesopores or macropores are distributed in inorganic minerals and exhibit 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. Thus, this application proposes to obtain a shale reservoir sample as the parent rock and divide the parent rock into two parallel test samples, namely the first rock sample and the second rock sample. Select oil-phase fluid and water-phase fluid so that the first rock sample and the second rock sample can separately conduct oil-phase spontaneous imbibition experiments and water-phase spontaneous imbibition experiments. After obtaining the rock samples and imbibition fluids, measure the basic parameters of the first rock sample and the second rock sample respectively as the first sample parameters and the second sample parameters. And obtain the basic parameters of the oil-phase fluid and the water-phase fluid as the first fluid parameters and the second fluid parameters.

[0031] Subsequently, in accordance with the experimental measurement specifications of rock sample nuclear magnetic resonance parameters, conduct nuclear magnetic resonance tests on the first rock sample and the second rock sample respectively to obtain the nuclear magnetic resonance T2 spectra of the two rock samples, and then obtain the first initial nuclear magnetic resonance signal intensity value of the first rock sample in the initial state and the second initial nuclear magnetic resonance signal intensity value of the second rock sample in the initial state.

[0032] In an embodiment of this application, a specific initial parameter acquisition scheme is provided. In S10, that is, based on the reservoir rock sample, generate the first rock sample and the second rock sample, and obtain the first sample parameters of the first rock sample, the first initial nuclear magnetic resonance signal intensity value, the second sample parameters of the second rock sample, the second initial nuclear magnetic resonance signal intensity value, the first fluid parameters of the oil-phase fluid, and the second fluid parameters of the water-phase fluid. The specific steps include the following steps S11-S18:

[0033] S11: Obtain the reservoir rock sample.

[0034] S12: Cut the reservoir rock sample into the first rock sample and the second rock sample with the same mass and the same volume.

[0035] 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.

[0036] For steps S11 - S13, drill a core sample of unconventional reservoir rock and cut it into two rock samples of the same mass and the same volume. Respectively perform cleaning and drying pre - treatments on the two rock samples, and record the initial mass and surface area of each pre - treated rock sample.

[0037] In the above - mentioned way, divide a reservoir rock sample into parallel samples to conduct imbibition oil and imbibition water experiments respectively, so as to test the oil wettability and water wettability of the reservoir rock, and ensure the accuracy of the final wettability measurement result.

[0038] S14: Respectively conduct nuclear magnetic resonance (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.

[0039] In this step, according to the experimental measurement specification of rock sample NMR parameters, respectively conduct NMR tests on the two rock samples to obtain the NMR T2 spectrum in the initial state. The NMR T2 spectrum characterizes the change curve of the transverse relaxation time and the signal amplitude, and 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 from it.

[0040] S15: Obtain the first fluid density and the first fluid viscosity of the oil - phase fluid, as well as the second fluid density and the second fluid viscosity of the water - phase fluid.

[0041] S16: Conduct NMR tests on the oil - phase fluid under multiple first preset mass conditions, and conduct NMR tests on the water - phase fluid under multiple second preset mass conditions, to obtain multiple third initial NMR signal intensity values of the oil - phase fluid under multiple first preset mass conditions and multiple fourth initial NMR signal intensity values of the water - phase fluid under multiple second preset mass conditions.

[0042] S17: Based on multiple first preset masses and multiple third initial NMR signal intensity values, generate a first linear equation corresponding to the oil - phase fluid, and based on the first slope of the first linear equation, determine the first conversion coefficient between the mass of the oil - phase fluid and the NMR signal.

[0043] S18: Based on multiple second preset masses and multiple fourth initial NMR signal intensity values, generate a second linear equation corresponding to the water - phase fluid, and based on the second slope of the second linear equation, determine the second conversion coefficient between the mass of the water - phase fluid and the NMR signal.

[0044] 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 multiple preset masses set in the experiment, nuclear magnetic resonance (NMR) experiments are carried out on the oil - phase fluid and the water - phase fluid respectively to measure the NMR signal intensity values of the oil - phase fluid under different mass conditions and the NMR signal intensity values of the water - phase fluid under different mass conditions. Based on each preset mass and its corresponding NMR signal intensity value, it is experimentally found that the cumulative signal of the imbibition fluid and the corresponding NMR has a linear relationship. Therefore, a first linear equation of the third NMR signal and the oil - phase fluid, and a second linear equation of the fourth NMR 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 NMR 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 - mentioned conversion coefficients, the measured NMR signal intensity value can be converted into the corresponding mass value.

[0045] By the above method, the NMR 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 NMR are respectively fitted, and the corresponding conversion coefficients are obtained according to their respective slopes to convert the NMR signal intensity value into the actual mass, which is convenient for subsequent quantitative analysis of the fluid content in the rock sample.

[0046] S20: During the process of the first rock sample spontaneously imbibing the oil - phase fluid, the first rock sample is subjected to NMR testing according to multiple imbibition times, and the first sample NMR signal intensity value under each imbibition time condition is obtained. Based on the first initial NMR signal intensity value and the first sample NMR signal intensity value, the first fluid NMR signal intensity value of the oil - phase fluid imbibed by the first rock sample under each imbibition time condition is determined.

[0047] In this step, the oil - phase fluid is set on the surface of the first rock sample, so that the first rock sample conducts an oil - phase spontaneous imbibition experiment. During the spontaneous imbibition process, according to multiple imbibition times designed in the experiment, the first rock sample is subjected to NMR testing to obtain the NMR T2 spectrum under different imbibition time conditions, and thus the first sample NMR signal intensity value of the first rock sample under different imbibition time conditions can be obtained. Subsequently, the first initial NMR signal intensity value is subtracted from the first sample NMR signal intensity value to obtain the first fluid NMR signal intensity value of the oil - phase fluid imbibed by the first rock sample under different imbibition time conditions.

[0048] In the above manner, the nuclear magnetic resonance 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 size of the first rock sample under different imbibition time conditions, providing important information for subsequent analysis of the oil wettability of reservoir rocks.

[0049] In one embodiment of the present application, a specific scheme for calculating the nuclear magnetic resonance signal of the oil-phase fluid inhaled 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 inhaling the oil-phase fluid, nuclear magnetic resonance tests are performed on the first rock sample according to multiple imbibition times, and the nuclear magnetic resonance signal intensity values of the first sample under each imbibition time condition are obtained. Based on the first initial nuclear magnetic resonance signal intensity value and the nuclear magnetic resonance signal intensity value of the first sample, the first fluid nuclear magnetic resonance signal intensity value of the oil-phase fluid inhaled by the first rock sample under each imbibition time condition is determined, specifically including the following steps S21 - S23:

[0050] S21: Place the first rock sample in the oil-phase fluid so that the pores of the first rock sample can spontaneously inhale the oil-phase fluid.

[0051] 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 dry rock will spontaneously imbibe the external oil-phase fluid by capillary action existing in the pores during the imbibition process.

[0052] S22: During the process of the first rock sample spontaneously inhaling the oil-phase fluid, nuclear magnetic resonance tests are performed on the first rock sample according to 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.

[0053] S23: Subtract the first initial nuclear magnetic resonance signal intensity value from the first sample nuclear magnetic resonance signal intensity value under each imbibition time condition to obtain the first fluid nuclear magnetic resonance signal intensity value of the oil-phase fluid inhaled by the first rock sample under each imbibition time condition.

[0054] For steps S22 - S23, during the oil-phase spontaneous imbibition process of the first 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 first rock sample to obtain the nuclear magnetic resonance T2 spectra under each imbibition time condition, and then the first sample nuclear magnetic resonance signal intensity values under each imbibition time condition are obtained. Subsequently, subtract the first initial nuclear magnetic resonance signal intensity value from each first sample nuclear magnetic resonance signal intensity value to obtain the nuclear magnetic resonance signal of the oil-phase fluid imbibed by the first rock sample under each imbibition time condition, which is the first fluid nuclear magnetic resonance signal intensity value.

[0055] S30: During the process of the second rock sample spontaneously sucking in the aqueous fluid, nuclear magnetic resonance (NMR) tests are performed on the second rock sample at multiple imbibition times to obtain the NMR signal intensity values of the second sample under each imbibition time condition. Based on the second initial NMR signal intensity value and the NMR signal intensity values of the second sample, the second fluid NMR signal intensity value of the aqueous fluid sucked in by the second rock sample under each imbibition time condition is determined.

[0056] In this step, the aqueous fluid is set on the surface of the second rock sample so that the second rock sample undergoes an aqueous spontaneous imbibition experiment. During the spontaneous imbibition process, NMR tests are performed on the second rock sample at multiple imbibition times designed in the experiment to obtain the NMR T2 spectra under different imbibition time conditions, and thus the NMR signal intensity values of the second sample of the second rock sample under different imbibition time conditions can be obtained. Subsequently, by subtracting the second initial NMR signal intensity value from the NMR signal intensity value of the second sample, the second fluid NMR signal intensity value of the aqueous fluid imbibed by the second rock sample at different imbibition times is obtained.

[0057] In the above manner, the NMR signal intensity values of the aqueous fluid imbibed by the second rock sample under different imbibition time conditions are obtained to characterize the degree of change in fluid imbibition and the distribution law under different imbibition time conditions, providing important information for subsequent analysis of the water wettability of reservoir rocks.

[0058] 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. Then, after obtaining the NMR signal intensity values of the sample under different imbibition time conditions, the measured NMR signal intensity values are divided by the mass of the imbibed oil / mass of the imbibed water to achieve the dimensionless quality of the NMR signal, eliminating the error caused by the inability to ensure that the masses of the two different samples are exactly the same when respectively performing oil and water imbibition, making the data between different samples comparable.

[0059] In an embodiment of the present application, a specific scheme for calculating the nuclear magnetic signal of the aqueous fluid sucked in 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 sucking in the aqueous fluid, NMR tests are performed on the second rock sample at multiple imbibition times to obtain the NMR signal intensity values of the second sample under each imbibition time condition. Based on the second initial NMR signal intensity value and the NMR signal intensity values of the second sample, the second fluid NMR signal intensity value of the aqueous fluid sucked in by the second rock sample under each imbibition time condition is determined, which specifically includes the following steps S31 - S33:

[0060] S31: Place the second rock sample in an aqueous fluid so that the pores of the second rock sample spontaneously imbibe the aqueous fluid.

[0061] In this step, an aqueous spontaneous imbibition experiment is conducted 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 rock in the dry state relies on the capillary action existing in the pores to spontaneously imbibe the external aqueous fluid, which is the imbibition process.

[0062] S32: During the process of the second rock sample spontaneously imbibing the aqueous fluid, perform nuclear magnetic resonance (NMR) tests on the second rock sample at multiple imbibition times to determine the NMR signal intensity value of the second sample of the second rock sample under each imbibition time condition.

[0063] S33: Subtract the second initial NMR signal intensity value from the NMR signal intensity value of the second sample under each imbibition time condition to obtain the NMR signal intensity value of the aqueous fluid imbibed by the second rock sample under each imbibition time condition.

[0064] For steps S32 - S33, during the oil-phase spontaneous imbibition process of the second rock sample, according to multiple imbibition times set in the experiment, that is, the imbibition times, perform NMR tests on the second rock sample in sequence to obtain the NMR T2 spectrum under each imbibition time condition, and then obtain the NMR signal intensity value of the second sample under each imbibition time condition. Subsequently, subtract the second initial NMR signal intensity value from each NMR signal intensity value of the second sample to obtain the nuclear magnetic signal of the aqueous fluid imbibed by the second rock sample under each imbibition time condition, which is the NMR signal intensity value of the second fluid.

[0065] S40: Based on the first sample parameters, the first fluid parameters, and multiple first fluid NMR signal intensity values, determine multiple oil-phase wetting kinetic rates of the first rock sample when spontaneously imbibing the oil-phase fluid under multiple pore types.

[0066] In this step, the rocks in unconventional reservoirs have strong heterogeneity, which leads to uneven spatial distribution of wettability. Some pore structure regions may exhibit hydrophilicity, while some pore structure regions may exhibit oleophilicity. The measurement results of the entire region alone 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 classify the pores into different types (i.e., large pore radius pores and small pore radius 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 pore diameter pores, large pore diameter pores, and small pore diameter pores respectively, to comprehensively evaluate the wettability of reservoir rocks.

[0067] Specifically, according to the size of the pore radius of the reservoir rock, the pores can be divided into large-aperture pores (such as pore radius r > 2 nm) and small-aperture pores (such as pore radius r ≤ 2 nm). The nuclear magnetic resonance T2 spectrum represents the distribution of the imbibition amount of the reservoir rock in different pores at different imbibition times. The abscissa of the nuclear magnetic resonance T2 spectrum (i.e., the transverse relaxation time) 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 full-aperture pores, large-aperture pores, and small-aperture pores of the reservoir rock can be obtained respectively. Furthermore, based on the first sample parameter, the first fluid parameter, and multiple first fluid nuclear magnetic resonance signal intensity values, the imbibition rate of the reservoir rock for the oil-phase fluid under different pore types can be calculated. This serves as the basic data for quantitatively evaluating the wettability of unconventional tight reservoir rocks.

[0068] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of the full-aperture pores of the rock during spontaneous oil imbibition is provided. In S40, that is, based on the first sample parameter, the first fluid parameter, and multiple first fluid nuclear magnetic resonance signal intensity values, multiple oil-phase wetting kinetics rates of the first rock sample during spontaneous inhalation of the oil-phase fluid under multiple pore types are determined. The specific steps include the following S41 - S42:

[0069] S41: 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, determine the first contact area of the oil-phase fluid in the full-aperture pores of the first rock sample.

[0070] 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, and the first 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 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.

[0071] The first expression is:

[0072] ;

[0073] Wherein, S is the contact area between the pores of the rock sample and the imbibing fluid; q is the total number of multiple imbibing times; k is the conversion coefficient between the imbibing fluid and the nuclear magnetic resonance signal; ρ2 is the nuclear magnetic relaxation rate; ρ is the fluid density of the imbibing fluid; n is the range of the nuclear magnetic resonance signal region of the nuclear magnetic resonance T2 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.

[0074] S42: Determine the first wetting kinetics rate of the full-aperture pores of the first rock sample during spontaneous imbibition of the oil-phase fluid 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.

[0075] 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 of oil, where the second expression is used to calculate the wetting kinetics rate of the rock sample during spontaneous imbibition.

[0076] The second expression is:

[0077] ;

[0078] Wherein, α is the wetting kinetics rate of the rock sample during spontaneous imbibition; μ is the fluid viscosity of the imbibing fluid; A is the surface area of the rock sample; k is the conversion coefficient of the imbibing fluid; ρ2 is the nuclear magnetic relaxation rate; ρ is the fluid density of the imbibing fluid; t 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 T2 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 is the initial mass of the rock sample.

[0079] Through the above method, the wetting kinetics rate of the full-aperture pores of the first rock sample during spontaneous imbibition of oil is obtained, providing an important basis for subsequent rock wettability evaluation.

[0080] 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 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, multiple oil-phase wetting kinetics rates of the first rock sample during spontaneous inhalation of the oil-phase fluid under multiple pore types are determined. Specifically, it further includes the following steps S43 - S45:

[0081] S43: Based on a preset pore radius, the pores of the first rock sample are divided into first-aperture pores and second-aperture pores, where the radius of the first-aperture pores is smaller than that of the second-aperture pores.

[0082] In this step, the preset pore radius is the boundary value of the pre-set 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.

[0083] 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, 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 are determined.

[0084] In this step, the horizontal coordinate of the nuclear magnetic resonance T2 spectrum reflects the pore size distribution. Based on the conversion formula between the nuclear magnetic resonance transverse relaxation time and the pore size, the nuclear magnetic resonance signal intensity values corresponding to different pore types are determined in the nuclear magnetic resonance T2 spectrum. Specifically, the conversion formula is: T2 = r / C, where T2 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 T2 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, the initial nuclear magnetic resonance signal intensity value is subtracted from the sample nuclear magnetic resonance signal intensity value of each pore type to obtain the fluid nuclear magnetic resonance signal intensity value of each pore of each pore type during spontaneous imbibition of oil.

[0085] S45: Based on the first sample parameters, the first fluid parameters, multiple first target fluid nuclear magnetic resonance signal intensity values, and multiple second target fluid nuclear magnetic resonance signal intensity values, the second wetting kinetics rate of the first-aperture pores of the first rock sample during spontaneous inhalation of the oil-phase fluid and the third wetting kinetics rate of the second-aperture pores during spontaneous inhalation of the oil-phase fluid are determined.

[0086] In this step, after classifying the full-aperture pores of the first rock sample into first-aperture pores and second-aperture pores, based on the first sample parameters, the first fluid parameters, and multiple first target fluid nuclear magnetic resonance signal intensity values under the condition of the first-aperture pores, determine the second wetting kinetic rate of the first-aperture pores during spontaneous imbibition of oil. At the same time, based on the first sample parameters, the first fluid parameters, and multiple second target fluid nuclear magnetic resonance signal intensity values under the condition of the second-aperture pores, determine the third wetting kinetic rate of the second-aperture pores during spontaneous imbibition of oil.

[0087] 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 S45, 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 inhalation of the oil-phase fluid under various pore types, specifically including the following steps S451 - S454:

[0088] 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 first-aperture pores of the first rock sample.

[0089] 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 kinetic rate of the first-aperture pores of the first rock sample during spontaneous inhalation of the oil-phase fluid.

[0090] 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-aperture pores of the first rock sample.

[0091] 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 kinetic rate of the second-aperture pores of the first rock sample during spontaneous inhalation of the oil-phase fluid.

[0092] 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.

[0093] 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 inhalation of the aqueous - phase fluid under multiple pore types.

[0094] In this step, classify the pores based on the pore radius size (i.e., full - pore - size pores, large - pore - size pores, and small - pore - size pores), and then calculate the fluid signal change law and distribution law of the rock sample under the conditions of full - pore - size pores, large - pore - size pores, and small - pore - size pores respectively to comprehensively evaluate the wettability of the reservoir rock.

[0095] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of the full - pore - size pores of the rock during spontaneous water 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, determine multiple aqueous wetting kinetics rates of the second rock sample during spontaneous inhalation of the aqueous - phase fluid under multiple pore types, which specifically includes the following steps S51 - S52:

[0096] S51: Based on the second conversion coefficient of the aqueous - phase fluid, the second fluid density of the aqueous - 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 aqueous - phase fluid in the full - pore - size pores of the second rock sample.

[0097] In this step, by summing the contact areas at multiple imbibition times, the diffusion and adsorption behaviors of the imbibition fluid in the rock pores can be quantitatively evaluated, which helps to understand the distribution characteristics of the imbibition fluid in the pores. Therefore, the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous fluid, the second fluid nuclear magnetic resonance signal intensity values and their corresponding transverse relaxation times under different imbibition time conditions are substituted into the first expression to calculate the fourth contact area of the aqueous fluid in the pores with the full pore size of the second rock sample.

[0098] S52: 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, determine the fourth wetting kinetics rate of the second rock sample when spontaneously imbibing the aqueous fluid.

[0099] In this step, 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 are substituted into the second expression to calculate the fourth wetting kinetics rate of the pores with the full pore size of the second rock sample during spontaneous imbibition of water.

[0100] Through the above method, the wetting kinetics rate of the pores with the full pore size of the second rock sample during spontaneous imbibition of water is obtained, providing an important basis for subsequent rock wettability evaluation.

[0101] Therefore, in an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of other pore types of a rock sample during spontaneous imbibition of water 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 when spontaneously imbibing the aqueous fluid under multiple pore types are determined. Specifically, it further includes the following steps S53 - S55:

[0102] S53: Based on a preset pore radius, the pores of the second rock sample are divided into third - pore - size pores and fourth - pore - size pores, where the radius of the third - pore - size pores is smaller than that of the fourth - pore - size pores.

[0103] In this step, the preset pore radius is the boundary value of the predefined dividing line for classifying pores. Using the preset pore radius, the pores of the second rock sample are divided into large - pore - size pores and small - pore - size 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 - pore - size pore, that is, a third - pore - size pore; if the pore radius is greater than the preset pore radius, it is confirmed that the pore is a large - pore - size pore, that is, a fourth - pore - size pore.

[0104] S54: Determine the multiple third target fluid nuclear magnetic resonance signal intensity values corresponding to pores with a third pore size and the multiple fourth target fluid nuclear magnetic resonance signal intensity values corresponding to pores with a fourth pore size based on the multiple second sample nuclear magnetic resonance signal intensity values of the second rock sample, a preset pore radius, and the second initial nuclear magnetic resonance signal intensity value.

[0105] In this step, the horizontal coordinate of the nuclear magnetic resonance T2 spectrum reflects the pore size distribution of the pores. 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 T2 spectrum, determine the nuclear magnetic resonance transverse relaxation times corresponding to different pore types, and then determine the multiple sample nuclear magnetic resonance signal intensity values corresponding to different pore types. Subsequently, subtract the initial nuclear magnetic resonance signal intensity value from the sample nuclear magnetic resonance signal intensity value of each pore type to obtain the fluid nuclear magnetic resonance signal intensity value of the pores of each pore type during spontaneous imbibition water absorption.

[0106] S55: Determine the fifth wetting kinetics rate of the pores with a third pore size in the second rock sample during spontaneous imbibition of an aqueous fluid phase, and the sixth wetting kinetics rate of the pores with a fourth pore size in the second rock sample during spontaneous imbibition of an oil phase fluid based on the second sample parameter, the second fluid parameter, the multiple third target fluid nuclear magnetic resonance signal intensity values, and the multiple fourth target fluid nuclear magnetic resonance signal intensity values.

[0107] In this step, after classifying the pores with all pore sizes in the second rock sample into pores with a third pore size and pores with a fourth pore size, determine the fifth wetting kinetics rate of the pores with a third pore size during spontaneous imbibition of water based on the second sample parameter, the second fluid parameter, and the multiple third target fluid nuclear magnetic resonance signal intensity values under the condition of pores with a third pore size. At the same time, determine the sixth wetting kinetics rate of the pores with a fourth pore size during spontaneous imbibition of oil based on the second sample parameter, the second fluid parameter, and the multiple fourth target fluid nuclear magnetic resonance signal intensity values under the condition of pores with a fourth pore size.

[0108] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate of the pores with all pore sizes in a rock during spontaneous imbibition of oil is provided. In S55, that is, determine the fifth wetting kinetics rate of the pores with a third pore size in the second rock sample during spontaneous imbibition of an aqueous fluid phase, and the sixth wetting kinetics rate of the pores with a fourth pore size in the second rock sample during spontaneous imbibition of an oil phase fluid based on the second sample parameter, the second fluid parameter, the multiple third target fluid nuclear magnetic resonance signal intensity values, and the multiple fourth target fluid nuclear magnetic resonance signal intensity values, which specifically includes the following steps S551 - S554:

[0109] S551: Substitute the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous fluid, the 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 fluid in the pores with the third pore size of the second rock sample.

[0110] S552: Substitute 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, the multiple third target fluid nuclear magnetic resonance signal intensity values of the aqueous fluid, the second initial mass of the second rock sample, and the fifth contact area into the second expression to calculate the fifth wetting kinetics rate when the pores with the third pore size of the second rock sample spontaneously imbibe the aqueous fluid.

[0111] S553: Substitute the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous fluid, the 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 fluid in the pores with the fourth pore size of the second rock sample.

[0112] S554: Substitute 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, the 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 into the second expression to calculate the sixth wetting kinetics rate when the pores with the fourth pore size of the second rock sample spontaneously imbibe the aqueous fluid.

[0113] For steps S551 - S554, substitute the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous fluid, and the third target fluid nuclear magnetic resonance signal intensity values and their corresponding transverse relaxation times of the third - pore - size pores under different imbibition time conditions 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, and the fourth target fluid nuclear magnetic resonance signal intensity values and their corresponding transverse relaxation times of the fourth - pore - size pores under different imbibition time conditions 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.

[0114] S60: Generate multiple wetting kinetics rate coefficients based on multiple oil - phase wetting kinetics rates and multiple water - phase wetting kinetics rates to determine the wettability of the reservoir rock sample.

[0115] In this step, calculate the wetting kinetics rate coefficients through the oil - phase wetting kinetics rates and water - phase wetting kinetics rates 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 the multiple wetting kinetics rate coefficients.

[0116] In an embodiment of the present application, a specific calculation scheme for the wetting kinetics rate coefficient is provided. In S60, that is, generate multiple wetting kinetics rate coefficients based on multiple oil - phase wetting kinetics rates and multiple water - phase wetting kinetics rates, and determine the wettability of the reservoir rock sample through the multiple wetting kinetics rate coefficients, which specifically includes the following steps S61 - S62:

[0117] 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.

[0118] S62: Determine the wettability of the reservoir rock sample based on the multiple wetting kinetics rate coefficients of multiple pore types.

[0119] For steps S61 - S62, the multiple oil - phase wetting kinetic rates represent the wetting kinetic rates of the full - pore - size pores, large - pore - size pores, and small - pore - size pores in the reservoir rock during spontaneous imbibition of oil; the multiple water - wetting kinetic rates represent the wetting kinetic rates of the full - pore - size pores, large - pore - size pores, and small - pore - size 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.

[0120] The third expression is:

[0121] ;

[0122] In the formula, the above - mentioned Wkc is the wetting kinetic rate coefficient; the above - mentioned α o is the oil - phase wetting kinetic rate; the above - mentioned α w is the water - phase wetting kinetic rate.

[0123] 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.

[0124] 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 respectively 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 surface areas as A o = 22.93 cm 2 and A w = 23.32 cm 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.

[0125] 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 T2 spectrum of the rock sample. Among them, Figure 2 is the nuclear magnetic resonance T2 spectrum of sample W in the initial state and under different imbibition time conditions; Figure 3 is the nuclear magnetic resonance T2 spectrum of sample O in the initial state and under different imbibition time conditions.

[0126] Step 3: By measuring the nuclear magnetic resonance signal intensity values of n-dodecane and deionized water under different mass conditions, it is measured 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 signal 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 . 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 nuclear magnetic resonance signal amount. Among them, Figure 4 is the schematic diagram of the conversion relationship between the nuclear magnetic resonance signal amount and the mass of deionized water obtained by fitting; Figure 5 is the schematic diagram of the conversion relationship between the nuclear magnetic resonance signal amount and the mass of n-dodecane obtained by fitting.

[0127] 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 during the imbibition process, the contact area between the imbibed fluid and the pores in the sample can be calculated using the contact area expression of the imbibed fluid and the pores. The contact area between deionized water and the pores of the sample is 4.6×105 cm 2 , and the contact area between n-dodecane and the pores of the sample is 1.1×106 cm 2 . As Figure 6 and Figure 7 shown, it is a schematic diagram of the relationship between the NMR signal and the imbibition time when the fluid spontaneously imbibes into the full pore size pores. Among them, Figure 6 is a schematic diagram of the relationship between the NMR signal and the imbibition time when deionized water imbibes into the full pore size pores; Figure 7 is a schematic diagram of the relationship between the NMR signal and the imbibition time when n-dodecane imbibes into the full pore size pores.

[0128] The contact area expression between the imbibed fluid and the pores is as follows:

[0129] ;

[0130] In the formula, the above S is the contact area between the pores of the rock sample and the imbibed fluid, cm 2 ; the above q is the total number of multiple imbibition times; the above k is the conversion coefficient between the imbibed fluid and the NMR signal, g / a.u.; the above ρ2 is the nuclear magnetic relaxation rate, nm / ms; the above ρ is the fluid density of the imbibed fluid, g / cm 3 ; the above n is the range of the NMR signal region of the nuclear magnetic resonance T2 spectrum; the above p i is the first fluid NMR signal intensity value of the i-th nuclear magnetic signal point; the above T 2i is the transverse relaxation time of the i-th nuclear magnetic signal point; the above is the sum of the ratio of the NMR signal intensity value to its corresponding transverse relaxation time, a.u. / ms.

[0131] Step 5: Analyze the 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 of imbibed deionized water is 3.9×10 7 , and the slope of the change in the NMR signal of imbibed deionized water is 3.8×10 5, the wetting kinetic rate is calculated using the expression for calculating the wetting kinetic rate of rock samples during spontaneous imbibition. Then, 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 based on 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 is considered oil-wet; when Wkc > 0, the rock is considered water-wet. Based on the wetting kinetic rate, the wetting kinetic rate coefficient Wkc = 2.40 is quantitatively characterized, indicating that the rock is water-wet.

[0132] 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 it imbibes water respectively to calculate the wetting kinetic rate of the full-aperture pores of the rock sample during spontaneous imbibition.

[0133] The expression for the wetting kinetic rate of the full-aperture pores of sample O during spontaneous oil imbibition is:

[0134] ;

[0135] 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 ρ2 is the nuclear magnetic relaxation rate, and ρ2 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 T2 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.

[0136] The expression for the wetting kinetic rate of the full-aperture pores of sample W during spontaneous water imbibition is:

[0137] ;

[0138] In the formula, the above-mentioned α w is the wetting kinetic rate during 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 nuclear magnetic resonance signal; the above-mentioned ρ2 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 nuclear magnetic resonance signal region of nuclear magnetic resonance T2 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.

[0139] Subsequently, according to 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 using the third expression.

[0140] The third expression is:

[0141] .

[0142] Step 6: Define the small-pore-size pores with pore radius r ≤ 2 nm as adsorption pores, and the large-pore-size pores with pore radius r > 2 nm as seepage pores. According to the nuclear magnetic resonance transverse relaxation time - pore size conversion formula T2 = r / C, where the shale conversion coefficient C is approximately 10 nm / ms, the pore radius is converted by nuclear magnetic resonance. In the nuclear magnetic resonance T2 spectrum, the pores are classified as adsorption pores with T2 ≤ 2 / C and seepage pores with T2 > 2 / C. In the nuclear magnetic resonance T2 spectrum, the pores are classified as adsorption pores with T2 ≤ 0.2 ms and seepage pores with T2 > 0.2 ms. The nuclear magnetic resonance signal intensity values of the sample in the two ranges of T2 ≤ 0.2 ms and T2 > 0.2 ms in the nuclear magnetic resonance T2 spectrum under different imbibition time conditions are obtained respectively. Subsequently, by subtracting the initial nuclear magnetic resonance signal intensity values in the corresponding ranges in the initial state from the nuclear magnetic resonance signal intensity values of the sample in different pore size distribution ranges, the nuclear magnetic resonance signal intensity values of the n-dodecane adsorbed by the adsorption pores and seepage pores in sample O, and the nuclear magnetic resonance signal intensity values of the deionized water adsorbed by the adsorption pores and seepage pores in sample W at different imbibition times are obtained.

[0143] Step 7: Calculate the contact areas of deionized water and n-dodecane in the adsorption pores during imbibition. The contact area between deionized water and pores in the adsorption pores is 2.8×105 cm 2 , and the contact area between deionized water and pores in the adsorption pores is 1.1×106 cm 2 . As shown in Figure 8 and Figure 9 , 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 adsorption pores. Among them, Figure 8 is the relationship diagram between the nuclear magnetic resonance signal and the imbibition time when deionized water imbibes in the adsorption pores; Figure 9 is the relationship diagram between the nuclear magnetic resonance signal and the imbibition time when n-dodecane imbibes 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 imbibing in the adsorption pores is 6.7×10 3 , and the slope of the change in the nuclear magnetic resonance signal of n-dodecane imbibing is 3.0×10 5 . Calculate the wetting kinetics rate α mi-w = 25.87, α mi-w = 7.60. And finally, quantitatively characterize the wetting kinetics rate coefficient Wkc in the adsorption pores according to the wetting kinetics rate mi = -0.59, showing oleophilicity.

[0144] The calculation process expression is as follows:

[0145] ;

[0146] 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 of reservoir rocks; 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 to the corresponding transverse relaxation times within the range of the adsorption pores.

[0147] ;

[0148] In the formula, the above α mi-w is the wetting kinetics rate of deionized water imbibing 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 k w 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.

[0149] ;

[0150] In the formula, the above-mentioned α mi-o为 is the wetting kinetic rate of the adsorbed pores in sample O for the imbibition of n-dodecane; 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.

[0151] ;

[0152] In the formula, the above-mentioned Wkc mi is the wetting kinetic rate coefficient of the adsorbed pores; the above-mentioned α mi-o is the wetting kinetic rate of the adsorbed pores in sample O for the imbibition of n-dodecane; the above-mentioned α mi-w is the wetting kinetic rate of the adsorbed pores in sample W for the imbibition of deionized water.

[0153] 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.

[0154] The calculation process expression is as follows:

[0155] ;

[0156] 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 ratios of the nuclear magnetic resonance signal intensity value within the range of the seepage pores to the corresponding transverse relaxation time.

[0157] ;

[0158] In the formula, the above-mentioned α me-w is the wetting kinetics rate of the seepage pores in sample W for imbibing deionized water; 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.

[0159] ;

[0160] In the formula, the above-mentioned α me-o is the wetting kinetics rate of the seepage pores in sample O for imbibing n-dodecane; 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.

[0161] ;

[0162] In the formula, the above-mentioned Wkc me is the wetting kinetics rate coefficient of the seepage pores; the above-mentioned α me-o is the wetting kinetics rate of the seepage pores in sample O for imbibing n-dodecane; the above-mentioned α me-w is the wetting kinetics rate of the seepage pores in sample W for imbibing deionized water.

[0163] 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 applying conventional wettability measurement methods to unconventional reservoir rocks.

[0164] 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 method for evaluating the wettability of reservoir rocks, characterized in that, 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 an oil-phase fluid, and a second fluid parameter of an aqueous-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 a first sample nuclear magnetic resonance signal intensity value under each imbibition time condition, and based on the first initial nuclear magnetic resonance signal intensity value and the first sample nuclear magnetic resonance signal intensity value, determining a first fluid nuclear magnetic resonance signal intensity value of the oil-phase fluid imbibed by the first rock sample under each imbibition time condition; During the process of the second rock sample spontaneously imbibing the aqueous-phase fluid, performing nuclear magnetic resonance tests on the second rock sample at the multiple imbibition times to obtain a second sample nuclear magnetic resonance signal intensity value under each imbibition time condition, and based on the second initial nuclear magnetic resonance signal intensity value and the second sample nuclear magnetic resonance signal intensity value, determining a second fluid nuclear magnetic resonance signal intensity value of the aqueous-phase fluid imbibed by the second rock sample under each imbibition time condition; 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 parameter, the second fluid parameter, and multiple second fluid nuclear magnetic resonance signal intensity values, determining multiple aqueous-phase wetting kinetic rates when the second rock sample spontaneously imbibes the aqueous-phase fluid under the multiple pore types; Based on the multiple oil-phase wetting kinetic rates and the multiple aqueous-phase wetting kinetic rates, generating multiple wetting kinetic rate coefficients, and determining the wettability of the reservoir rock sample through the multiple wetting kinetic rate coefficients.

2. The method according to claim 1, wherein The step of generating the first rock sample and the second rock sample based on the reservoir rock sample, and obtaining 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 aqueous-phase fluid specifically includes: Obtaining a reservoir rock sample; Cutting the reservoir rock sample into the first rock sample and the second rock sample with 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 tests 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; Obtaining 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 aqueous-phase fluid. Perform nuclear magnetic resonance (NMR) tests on the oil-phase fluid under multiple first preset quality conditions, and perform NMR tests on the water-phase fluid under multiple second preset quality conditions, to obtain multiple third initial NMR signal intensity values of the oil-phase fluid under the multiple first preset quality conditions and multiple fourth initial NMR signal intensity values of the water-phase fluid under the multiple second preset quality conditions; Based on the multiple first preset qualities and the multiple third initial NMR signal intensity values, generate a first linear equation corresponding to the oil-phase fluid, and based on the first slope of the first linear equation, determine a first conversion coefficient between the mass of the oil-phase fluid and the NMR signal; Based on the multiple second preset qualities and the multiple fourth initial NMR signal intensity values, generate a second linear equation corresponding to the water-phase fluid, and based on the second slope of the second linear equation, determine a second conversion coefficient between the mass of the water-phase fluid and the NMR signal.

3. The method according to claim 1, wherein The step of, during the process of the first rock sample spontaneously imbibing the oil-phase fluid, performing NMR tests on the first rock sample according to multiple imbibition times, to obtain first sample NMR signal intensity values under each imbibition time condition, and based on the first initial NMR signal intensity value and the first sample NMR signal intensity values, determining first fluid NMR signal intensity values of the oil-phase fluid imbibed by the first rock sample under each imbibition time condition, specifically includes: Place the first rock sample in the oil-phase fluid so that the pores of the first rock sample can spontaneously imbibe the oil-phase fluid; During the process of the first rock sample spontaneously imbibing the oil-phase fluid, perform NMR tests on the first rock sample according to the multiple imbibition times, and determine first sample NMR signal intensity values corresponding to the first rock sample under each imbibition time condition; Subtract the first initial NMR signal intensity value from the first sample NMR signal intensity values under each imbibition time condition to obtain first fluid NMR signal intensity values of the oil-phase fluid imbibed by the first rock sample under each imbibition time condition.

4. The method according to claim 1, characterized in that The step of, during the process of the second rock sample spontaneously imbibing the water-phase fluid, performing NMR tests on the second rock sample according to the multiple imbibition times, to obtain second sample NMR signal intensity values under each imbibition time condition, and based on the second initial NMR signal intensity value and the second sample NMR signal intensity values, determining second fluid NMR signal intensity values of the water-phase fluid imbibed by the second rock sample under each imbibition time condition, specifically includes: Place the second rock sample in the water-phase fluid so that the pores of the second rock sample spontaneously imbibe the water-phase fluid; During the process of the second rock sample spontaneously imbibing the water-phase fluid, perform NMR tests on the second rock sample according to the multiple imbibition times, and determine second sample NMR signal intensity values of the second rock sample under each imbibition time condition; By subtracting the second initial nuclear magnetic resonance signal intensity value from the nuclear magnetic resonance signal intensity value of the second sample under each imbibition time condition, the second fluid nuclear magnetic resonance signal intensity value of the aqueous fluid inhaled by the second rock sample under each imbibition time condition is obtained.

5. The method according to claim 2, wherein The step of determining multiple oil-phase wetting kinetic rates when the first rock sample spontaneously inhales an oil-phase fluid under multiple pore types based on the first sample parameter, the first fluid parameter, and multiple first fluid nuclear magnetic resonance signal intensity values specifically includes: Determining the 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; Determining the first wetting kinetic rate when the first rock sample spontaneously inhales an oil-phase fluid 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.

6. The method according to claim 5, wherein The step of determining multiple oil-phase wetting kinetic rates when the first rock sample spontaneously inhales an oil-phase fluid under multiple pore types based on the first sample parameter, the first fluid parameter, and multiple first fluid nuclear magnetic resonance signal intensity values specifically further includes: Dividing the pores of the first rock sample into first-aperture pores and second-aperture pores based on a preset pore radius, where the radius of the first-aperture pores is less than the radius of the second-aperture pores; Determining 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 based on 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; Determining the second wetting kinetic rate when the first-aperture pores of the first rock sample spontaneously inhale an oil-phase fluid and the third wetting kinetic rate when the second-aperture pores of the first rock sample spontaneously inhale an 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.

7. The method according to claim 6, characterized in that The step of determining the second wetting kinetic rate when the first-aperture pores of the first rock sample spontaneously inhale an oil-phase fluid and the third wetting kinetic rate when the second-aperture pores of the first rock sample spontaneously inhale an 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: Substitute the first conversion coefficient of the oil-phase fluid, the first fluid density of the oil-phase fluid, multiple 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 the first expression to calculate the second contact area of the oil-phase fluid in the pores with the first pore size of the first rock sample; 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 when the pores with the first pore size of the first rock sample spontaneously imbibe the oil-phase fluid; 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 pores with the second pore size of the first rock sample; 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 when the pores with the second pore size of the first rock sample spontaneously imbibe the oil-phase fluid.

8. The method according to claim 4, characterized in that, The step of determining multiple aqueous wetting kinetics rates when the second rock sample spontaneously imbibes the aqueous fluid under the multiple pore types based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values specifically includes: Based on the second conversion coefficient of the aqueous fluid, the second fluid density of the aqueous 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 aqueous fluid in the pores with the full pore size of the second rock sample; 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, determine the fourth wetting kinetics rate when the second rock sample spontaneously imbibes the aqueous fluid.

9. The method according to claim 8, wherein The step of determining multiple aqueous wetting kinetics rates when the second rock sample spontaneously imbibes the aqueous fluid under the multiple pore types based on the second sample parameters, the second fluid parameters, and multiple second fluid nuclear magnetic resonance signal intensity values specifically further includes: Based on the preset pore radius, divide the pores of the second rock sample into pores with the third pore size and pores with the fourth pore size, where the radius of the pores with the third pore size is smaller than the radius of the pores with the fourth pore size; Determine a plurality of third target fluid nuclear magnetic resonance signal intensity values corresponding to the pores with the third pore size and a plurality of fourth target fluid nuclear magnetic resonance signal intensity values corresponding to the pores with the fourth pore size based on the plurality of 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 a fifth wetting kinetics rate when the second rock sample spontaneously imbibes the aqueous phase fluid in the pores with the third pore size and a sixth wetting kinetics rate when the second rock sample spontaneously imbibes the oil phase fluid in the pores with the fourth pore size based on the second sample parameters, the second fluid parameters, 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.

10. The method according to claim 9, wherein The step of determining a fifth wetting kinetics rate when the second rock sample spontaneously imbibes the aqueous phase fluid in the pores with the third pore size and a sixth wetting kinetics rate when the second rock sample spontaneously imbibes the oil phase fluid in the pores with the fourth pore size based on the second sample parameters, the second fluid parameters, 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 includes: Substitute the second conversion coefficient of the aqueous phase fluid, the second fluid density of the aqueous phase fluid, the 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 to calculate the fifth contact area of the aqueous phase fluid in the pores with the third pore size of the second rock sample; 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, the plurality of 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 kinetics rate when the second rock sample spontaneously imbibes the aqueous phase fluid in the pores with the third pore size; Substitute the second conversion coefficient of the aqueous phase fluid, the second fluid density of the aqueous phase fluid, the 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 to calculate the sixth contact area of the aqueous phase fluid in the pores with the fourth pore size of the second rock sample; 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, the plurality of 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 kinetics rate when the second rock sample spontaneously imbibes the aqueous phase fluid in the pores with the fourth pore size.

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