A capillary force reconstruction method for micro-wettability by using nuclear magnetic resonance and high-pressure mercury injection combined inversion

Abstract

The application discloses a capillary force reconstruction method for micro-wettability inversion by combining nuclear magnetic resonance and high-pressure mercury injection, and belongs to the technical field of oil and gas field development experiment analysis. The application uses nuclear magnetic resonance and mercury injection to jointly calibrate and obtain full pore size distribution, combines with imbibition nuclear magnetic experiment to invert micro-wettability index of each pore size section, obtains intrinsic contact angle through mathematical mapping, and substitutes the intrinsic contact angle into a Morrow rough surface model to map exclusive dynamic advancing angle and receding angle of each pore size section. Based on a Young-Laplace equation, bidirectional entering pressures of oil injection (displacement) and water injection (imbibition) are respectively calculated, accurate discrete data points are reconstructed by combining residual fluid truncation conditions, and finally, the Skjæveland correlation formula is substituted to fit output, so that a complete imbibition-displacement capillary force curve is obtained. The method greatly shortens the experiment period and expands the test pressure range. Real fluid combination displacement-imbibition capillary force calculation for micro-wettability control is realized, and real capillary force hysteresis characteristics are represented.

Description

Technical Field

[0001] This invention belongs to the field of experimental analysis technology for oil and gas field development, specifically relating to a capillary force reconstruction method for microscopic wettability using nuclear magnetic resonance and high-pressure mercury intrusion. Background Technology

[0002] Capillary force curves are crucial fundamental data for describing the pore structure characteristics of reservoir rocks, evaluating reservoir fluid distribution patterns, and conducting reservoir numerical simulations. Especially in unconventional oil and gas development, pore size distribution and capillary force information controlled by wettability are essential for numerical modeling studies.

[0003] Currently, traditional capillary force measurement methods mainly include the semi-permeable septum method and mercury intrusion porosimetry, but both of these methods have significant limitations when applied to the study of tight core samples.

[0004] 1. Semi-permeable partition method:

[0005] This method uses real fluid combinations (oil / water) and core samples for experiments, enabling it to reflect the true microscopic wettability characteristics of the core. However, its drawbacks include an extremely long experimental cycle and the displacement pressure being limited by the pore size of the semi-permeable septum. For dense cores with small pore sizes, this method struggles to provide sufficiently high displacement pressures, resulting in the inability to obtain effective information from the micropore size segment.

[0006] 2. Mercury porosimetry:

[0007] This method utilizes mercury and air as a fluid combination and can apply extremely high mercury ingress pressures (typically exceeding 200 MPa), meeting the testing requirements for small pore sizes in rock cores. However, because mercury is a strongly non-wetting phase, the experimental process effectively "homogenizes" the complex micro-wetting properties of the rock (i.e., forces all pore sizes to exhibit strong non-wetting). This means that mercury intrusion porosimetry can only reflect the contribution of pore size to capillary forces, completely losing the control effect of rock micro-wetting properties on capillary forces.

[0008] In summary, the semi-permeable diaphragm method is limited by pressure and cannot characterize small pore sizes, while the mercury intrusion porosimetry method is limited by fluid properties and cannot characterize wettability. Neither of these methods can independently meet the dual research requirements of "small pore size + true microscopic wettability" for unconventional tight oil and gas reservoirs.

[0009] To address the problem of characterizing capillary forces considering the influence of wettability, scholars both domestically and internationally have proposed various theoretical models and experimental methods (e.g., Skjæveland et al., 2000; Andersen et al., 2017; Zheng et al., 2021, etc.). However, most existing models and methods are based on the assumption of "single uniform wetting," which assumes that all pores in the core have a uniform wetting index and uses this as the basis for calculation. In reality, the wettability of rocks is not uniformly distributed; the wetting index obtained through macroscopic measurement is actually the average result of pores with different pore sizes and different wetting characteristics. Existing methods ignore this heterogeneous distribution of wettability with pore size, leading to deviations between the predicted capillary force curves and actual underground conditions.

[0010] The invention patent "Method for Delineating Formation Water in Tight Sandstone Gas Reservoirs Based on Mercury Intrusion Porosimetry and Online Nuclear Magnetic Resonance" (CN121090591A) utilizes the interfacial tension of mercury... and contact angle Interfacial tension converted to water and contact angle This method converts the mercury injection capillary force curve into a gas-water capillary force curve. However, this method only performs a global mathematical scaling on the mercury injection curve, ignoring the heterogeneous characteristics of rock wettability varying with pore size. Therefore, it cannot reconstruct a complete capillary force curve reflecting the true mixed wetting state. The invention patent "A Method for Calculating the Immersion Characteristic Curve of Metamorphic Rock Buried Hill Fractured Reservoirs" (CN120293812A) uses empirical formulas (Willhite model and J-function model) to characterize the curves. The parameters in the models are empirical constants obtained through mathematical fitting. These parameters simplify the complex wettability inside the core to a global average trend, masking the heterogeneity of wettability at the pore scale. Furthermore, these parameters have multiple solutions, meaning the obtained capillary force curve may not represent the true physical properties of the rock.

[0011] Therefore, this invention proposes a capillary force reconstruction method for microscopic wettability using a combination of nuclear magnetic resonance (NMR) and high-pressure mercury intrusion porosimetry (HIP). Leveraging the method's ability to test the heterogeneous distribution of wettability, it combines the "microscopic wettability distribution across different pore sizes" with the "pore size," thereby rapidly and accurately reconstructing a mixed wettability capillary force curve that conforms to the true physical state of the rock. Compared to existing technologies, this invention not only overcomes the "homogenization" distortion of wettability caused by HIP, but also solves the "blind zone" and multiple solutions of negative capillary forces in the percolation method. It is the first to achieve a mixed wettability capillary force curve reconstruction driven by the heterogeneous distribution of microscopic pore wettability. Summary of the Invention

[0012] The purpose of this invention is to overcome the shortcomings of the existing technology. Existing capillary force testing methods (mercury intrusion porosimetry, semi-permeable septum method) are difficult to simultaneously characterize the small pore size of dense rock cores and reflect the actual wettability. Existing theoretical prediction models mostly assume that the rock is uniformly wetted and do not fully consider the wetting lag phenomenon in the process of displacement and infiltration, resulting in the predicted mixed wetting capillary force curve having a negative pressure blind zone and deviating from the actual underground multiphase flow state.

[0013] To solve the above-mentioned technical problems, the present invention adopts the following technical solution:

[0014] A capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury intrusion inversion, comprising the following steps:

[0015] Step S1: Preparation and grouping of core samples; Select the full-diameter or plunger core to be tested, wash and dry it, and cut it into two parallel samples with similar physical properties: one is the main plunger sample (used for NMR and wettability testing), and the other is the end sample (used for high-pressure mercury intrusion testing).

[0016] Step S2: Preparation and calibration of experimental fluids; prepare two types of experimental water with the same salinity as real formation water: ordinary simulated formation water (H2O) and heavy water formation water (D2O); at the same time, prepare representative simulated oil according to the PVT report and calibrate its hydrogen content index;

[0017] Step S3: Nuclear magnetic resonance (NMR) test of core pore structure; After saturating the main plunger sample with ordinary simulated formation water (H2O), NMR T2 spectrum test is performed to obtain the transverse relaxation time distribution of the core under pressurized saturated water conditions;

[0018] Step S4: High-pressure mercury intrusion test; Perform a high-pressure mercury intrusion test on the end sample to obtain the mercury intrusion capillary force curve and the corresponding pore throat radius distribution curve;

[0019] Step S5: Construction and conversion of the pore size distribution model; jointly calibrate the pore throat distribution of high-pressure mercury intrusion spectroscopy with the NMR T2 spectrum, determine the conversion coefficients C and n, convert the T2 spectrum into the full pore size distribution f(r), and calculate r for each pore size interval. k pore volume component V k ;

[0020] Step S6: Cut the main plunger sample into two parallel samples of equal length, saturate them with representative simulated oil and heavy water formation water (D2O) respectively, and conduct spontaneous water absorption and forced water displacement experiments in sequence. Measure the NMR T2 spectrum at each stage and calculate the Amott-Harvey wetting index I(r) based on pore size. k ).

[0021] Step S7: Utilize the microwetting index I(r) obtained in step S6 for each pore size segment k(Values ​​range from -1 to 1), calculate the intrinsic contact angle of each pore. :

[0022] cos( )=I(r k );

[0023] Step S8: Calculate the intrinsic contact angles of each aperture segment obtained in step S7. or Substituting these values ​​into Morrow's (1975) empirical model of Class III contact angle hysteresis for rough surfaces, four dynamic contact angle variables specific to each pore size distribution are mapped: water-wetting retreat angle. Water-wet advance angle Oily back angle Oil-wet advance angle ;

[0024] Step S9: Based on the Young-Laplace equation and combined with the dynamic contact angle, determine the aperture r for each level. k Calculate the capillary inlet pressure in both directions: exhaust inlet pressure Fluid overcomes recoil angle resistance; seepage into pressure. Fluid resistance at the angle of advance;

[0025] Step S10: Calculate the... and The pore component volumes were sorted and summed separately, and the water saturation under different pressures was calculated, resulting in two discrete capillary force-saturation datasets: the displacement dataset ( , ) and the osmosis dataset ( , Substituting the values ​​into the Skjæveland double asymptotic correlation equation, a regression fit is performed to obtain a continuous curve.

[0026] As a preferred embodiment of the present invention, the relative deviation of porosity and permeability of the parallel samples in step S1 should be less than 5%; if the core is highly heterogeneous, it is preferable to drill two parallel plunger samples at the same depth.

[0027] As a preferred embodiment of the present invention, the washing and drying process in step S1 includes: using petroleum ether for displacement until the effluent shows no fluorescence, and then drying at 105°C to constant weight.

[0028] As a preferred embodiment of the present invention, the heavy water formation water in step S2 is prepared using deuterium oxide (D2O) with a purity greater than 99.9% and inorganic salts to completely shield the aqueous phase hydrogen signal in subsequent NMR tests. The representative oil sample is prepared using one or more combinations of alkanes and aromatics mixtures and alkanes and dead oil mixtures. Combined with the PVT report, it is ensured that the density and viscosity of the representative oil sample are consistent with those of the live oil, and the contact angle is consistent with that of the dead oil.

[0029] As a preferred embodiment of the present invention, the method for determining the hydrogen content index of the representative oil sample in step S2 is as follows: performing nuclear magnetic resonance T2 spectrum scanning on equal amounts of the representative oil sample and deionized water, determining the hydrogen content index by the ratio of the T2 signal intensities of the two fluids, and converting the representative oil NMR signal into the actual oil volume by the hydrogen content index.

[0030] As a preferred embodiment of the present invention, in step S3, the nuclear magnetic resonance test parameters are set as follows: the echo interval (TE) is set to 0.1ms~0.2ms to capture micro / nano pore signals, and the waiting time (TW) is set to 3000ms~5000ms to ensure complete polarization. The saturation process uses a vacuum pressurization saturation device, with a vacuuming time of not less than 4 hours, a pressurization pressure of not less than 20MPa, and a pressurization time of not less than 24 hours.

[0031] As a preferred embodiment of the present invention, the specific steps of the high-pressure mercury intrusion experiment in step S4 are as follows:

[0032] Step S4.1: Load the dried sample with known mass and pore volume into the core chamber;

[0033] Step S4.2: Turn on the vacuum pump to start evacuating the sample until the required vacuum level is reached;

[0034] Step S4.3: Use a displacement pump to measure the mercury inlet capillary pressure curve by gradually increasing the pressure from low to high at the set measurement pressure points, and then decrease the pressure from high to low to measure the mercury outlet capillary pressure curve.

[0035] Step S4.4: After the capillary pressure reaches equilibrium under the set constant pressures, record the pressure value and the corresponding mercury inlet volume;

[0036] Step S4.5: After the test, remove the sample from the core chamber. If any mercury spills, clean it up promptly to avoid environmental pollution. Place the tested sample back into the core container and seal it immediately.

[0037] The maximum mercury ingress pressure was set to 200 MPa–400 MPa in the experiment to meet the characterization requirements for 3 nm–5 nm micropore throats in dense core samples. For mercury porosimetry data processing, a mercury contact angle of 140° and a surface tension of 480 mN / m were used for pore size calculation.

[0038] As a preferred embodiment of the present invention, the specific method of joint calibration in step S5 is as follows: the conversion coefficients C and n are determined by using the cumulative curve of the pore throat distribution frequency obtained by high pressure mercury intrusion test and the cumulative curve of the signal proportion of T2 spectrum, and the T2 time axis is converted into the pore diameter r axis according to formula (1).

[0039] (1)

[0040] In the formula, C and n are the conversion coefficients between T2 relaxation time and aperture.

[0041] The method for calculating the component volume of each pore is as follows:

[0042] Let the pore volume of the core be Vtotal. Based on the converted pore size distribution probability density f(r), calculate the pore component volume Vk = Vtotal × f(r) occupied by the k-th pore size interval rk.

[0043] As a preferred embodiment of the present invention, after constructing f(r), the macropore portion that cannot be measured by mercury intrusion porosimetry (due to the surface effect of the end sample) needs to be interpolated and completed using NMR signals, and the micropore portion that cannot be accurately measured by NMR (due to the diffusion effect) needs to be corrected using mercury intrusion porosimetry data.

[0044] As a preferred embodiment of the present invention, the method for establishing the mapping between the micro-wetting index and the contact angle in step S7 is as follows:

[0045] Microscopic wetting index spectrum I obtained from NMR spectroscopy (NMR) ), establish its mapping relationship with the intrinsic contact angle, where the wetting index I( The numbers are between -1 and 1, so we have formula (2):

[0046] (2)

[0047] In the formula Let be the cosine of the intrinsic contact angle of the k-th aperture segment; Let be the wetting index of the k-th aperture segment.

[0048] Based on the sign of I(rk), the pores in the full pore size distribution are divided into two main categories: water-wetted pores and oil-wetted pores.

[0049] Water-wet pores (I(rk)>0), at this time <90°, which is defined as the water-wet reference angle. ;

[0050] Oil-wet pores (I(rk)<0), at this time >90°, which is defined as the oil-wet reference angle. .

[0051] As a preferred embodiment of the present invention, the method for calculating the dynamic contact angle using the Morrow rough surface contact angle hysteresis Class III empirical model in step S8 is as follows:

[0052] For water-wet pores, substitute For oil-wet pores, substitute... :

[0053] Calculate the back angle If 0° < ≤21.6°, backsliding angle =0°;

[0054] If 21.6° < ≤87.6°, backsliding angle The calculation formula is:

[0055] (3)

[0056] If 87.6° < ≤158.4°, backsliding angle The calculation formula is:

[0057] (4)

[0058] like >158.4°, =180°.

[0059] Calculate the angle of advance If 0° < ≤21.6°, =0°;

[0060] If 21.6° < ≤92.4°, advance angle The calculation formula is:

[0061] (5)

[0062] If 92.4° < ≤158.4°, advance angle The calculation formula is:

[0063] (6)

[0064] If 158.4° < ≤180° =180°.

[0065] As a preferred embodiment of the present invention, the method for calculating the pore inlet pressure in step S9 is as follows:

[0066] Based on the Young-Laplace equation, the ingress pressure of the k-th type of pore is calculated:

[0067] Calculate the exhaust inlet pressure At that time, the fluid overcomes the resistance of the recoil angle. For water-wetted orifices:

[0068] (7)

[0069] For oil-wet holes:

[0070] (8)

[0071] In formulas (7) and (8) It is the discharge inlet pressure of the k-th type of pore; It is the interfacial tension of a two-phase fluid; It is the cosine value of the receding angle of the kth type of water-wet pores; It is the cosine value of the receding angle of the k-th type of oily wet pores; It is the radius of the k-th type of pore.

[0072] Calculate the infiltration pressure At that time, the fluid overcomes the drag of the advance angle. For a water-wetted orifice:

[0073] (9)

[0074] For oil-wet holes:

[0075] (10)

[0076] In formulas (9) and (10) It is the infiltration pressure of the k-th type of pore; It is the cosine value of the advance angle of the k-th type of water-wet pores; It is the cosine of the advance angle of the k-th type of oily wet pores. Since the Morrow hysteresis model guarantees that the advance angle > the retreat angle, it must satisfy the following condition. > This is the microscopic physical origin of the macroscopic hysteresis loop.

[0077] As a preferred embodiment of the present invention, when calculating interfacial tension, the influence of curvature and adsorption effects in the micro- and nano-pores of shale on interfacial tension needs to be considered, including the reduction in effective pore size caused by the interaction between fluid molecules and pore walls, the change in critical parameters caused by confinement effects, and the pore size shrinkage caused by the adsorption layer.

[0078] (11)

[0079] In the formula r is the effective aperture, and r is the true aperture. Where is the thickness of the adsorption layer, P is the pressure, T is the temperature, and z is the compressibility factor.

[0080] For the volumetric interfacial tension of the unrestricted segment Available:

[0081] (12)

[0082] In the formula The total component fraction of a fluid mixture The density of the liquid phase is... The density is the gas phase density. Let be the mole fraction of the i-th component in the liquid phase. Let be the mole fraction of the i-th component in the gas phase; Let be the isotensile volume of the i-th component.

[0083] Introducing critical property shift relationships within nanopores to correct phase density and feeding them back to :

[0084] (13) (14)

[0085] In the formula This represents the relative offset of the critical temperature. This represents the relative offset of the critical pressure. This is the bulk critical temperature; This is the critical temperature of the pores. This is the critical pressure of the bulk phase; The critical pressure of the pores; The Lennard-Jones collision diameter.

[0086] Used for PR-EOS calculations, correcting phase density, and feeding back to... .

[0087] Furthermore, the interface tension is corrected for confined curvature using the Tolman equation to obtain the interface tension under confined conditions. :

[0088] (15)

[0089] in, The Tolman length is used. This process focuses on characterizing the significant impact of aperture size reduction on interfacial tension and phase state.

[0090] As a preferred embodiment of the present invention, in step S10, when sorting the data, for the displacement curve: Arrange the pore volumes in ascending order and sum them up to obtain the water saturation Sw,k at the current pressure.

[0091] For the absorption curve:

[0092] Will Arrange the samples in descending order and sum the pore volumes Vk to obtain the water saturation Sw,k at the current pressure.

[0093] Furthermore, the method for calculating water saturation Sw is as follows:

[0094] Define the current macroscopic capillary pressure as The corresponding wet phase saturation Sw is the value of all inlet pressures less than this. The volume proportion Vk of the pores occupied by the aqueous phase. By gradually increasing And by summing the volumes ∑Vk intruded by the aqueous phase, two discrete drainage datasets are obtained. (Sw,d) and osmosis dataset ( ,Sw,i).

[0095] As a preferred embodiment of the present invention, the method for fitting discrete capillary force-saturation data points in step S10 is as follows:

[0096] Substitute the two sets of discrete datasets into the Skjæveland bi-asymptotic correlation model:

[0097] (16)

[0098] In the formula, For capillary pressure, Water saturation; To restrict water saturation, 1 represents residual oil saturation; cw and aw are water-wet branching coefficients, which are usually positive. cw is used to scale the amplitude of the positive capillary force component, and aw controls the curvature of the positive capillary force component; co and ao are oil-wet branching coefficients, co is usually negative, and ao is usually positive. co is used to scale the amplitude of the negative capillary force component, and ao controls the curvature of the negative capillary force component.

[0099] The model parameters cw, aw, co, and ao are solved by nonlinear fitting; the final output fitting curve is the reconstructed capillary force curve applicable to this mixed-wetting core.

[0100] As a preferred embodiment of the present invention, when using the Skjæveland model for fitting, it is usually necessary to assign initial values ​​to the parameters and set parameter boundaries, because the function is discontinuous at Swr and 1-Sor. The specific operation is as follows:

[0101] Initialize:

[0102] Swr: Slightly smaller than the minimum value of Sw in the data (for example, if the data starts from 0.2, set it to 0.15).

[0103] Sor: slightly less than (1- (For example, if the maximum value of Sw is 0.8, then Sor) 0.15);

[0104] cw: Positive value, estimated to be the maximum value of the positive pressure portion;

[0105] aw: usually between 0.5 and 2;

[0106] co: negative value, estimated to be the opposite of the maximum amplitude of the negative pressure portion;

[0107] ao: usually between 0.5 and 2.

[0108] In summary, this application includes at least one of the following beneficial technical effects:

[0109] 1. The capillary force calculated in this invention not only considers the difference in pore size but also the heterogeneity of the micro-wetting properties of the pores. The micro-wetting properties (Amott-Harvey index) of different pore size segments are used as independent variables in the calculation model of inflow / outflow and percolation capillary forces.

[0110] 2. This invention combines the advantages of high-pressure mercury intrusion porosimetry (high pressure for mercury injection exceeding 200 MPa) in characterizing small pore sizes with the advantages of nuclear magnetic resonance (NMR) inversion of real fluid distribution. Compared to the semi-permeable septum method, which takes several months, this method significantly shortens the experimental cycle and expands the test pressure range. Compared to the uniformity of wettability achieved by conventional mercury intrusion porosimetry, this method can completely reconstruct the capillary force curves of real fluid combinations in mixed wettable media.

[0111] 3. This invention takes into account the dynamic displacement of fluids and the capillary force hysteresis effect, and introduces a dynamic contact angle using the Morrow rough surface contact angle hysteresis model. It realizes the calculation of capillary force in a realistic fluid combination for microscopic wettability control, and characterizes the true capillary force hysteresis characteristics. Attached Figure Description

[0112] Figure 1 This is a flowchart of a method for reconstructing capillary forces in mixed-wetting cores based on joint inversion using nuclear magnetic resonance and high-pressure mercury intrusion.

[0113] Figure 2 The cumulative frequency distribution diagrams of high-pressure mercury injection and nuclear magnetic resonance T2 spectra are shown.

[0114] Figure 3 The fitting curves for the T2 relaxation time-to-pore size related parameters in nuclear magnetic resonance imaging;

[0115] Figure 4 This is a frequency distribution diagram of the transition aperture during the T2 relaxation time in nuclear magnetic resonance.

[0116] Figure 5 T2 NMR spectra of self-absorbed oil and pressurized seepage oil from water-saturated cores with different pore sizes;

[0117] Figure 6 T2 NMR spectra of self-absorbed water and pressurized seepage water in oil-saturated cores with different pore sizes;

[0118] Figure 7 A distribution diagram of the wetting index of the mixing pores at various levels;

[0119] Figure 8 To reconstruct the discrete displacement and infiltration capillary force-saturation data points scatter plot;

[0120] Figure 9 The complete adsorption-expulsion capillary force curve is obtained by substituting the Skjæveland double asymptotic correlation into the nonlinear fitting. Detailed Implementation

[0121] The accompanying drawings and descriptions provided herein may have been simplified to illustrate aspects relevant to a clear understanding of the apparatus, systems, and methods described herein, while other aspects that may be found in typical similar devices, systems, and methods have been omitted for clarity. Therefore, those skilled in the art will recognize that other elements and / or operations may be desired and / or necessary for implementing the devices, systems, and methods described herein. However, because such elements and operations are known in the art and do not contribute to a better understanding of this disclosure, a discussion of such elements and operations may not be provided herein for the sake of brevity. Nevertheless, this disclosure is still intended to include all such elements, variations, and modifications to the described aspects that are known to those skilled in the art.

[0122] Implementations are provided throughout this disclosure to make it thorough and fully convey the scope of the disclosed embodiments to those skilled in the art. Numerous specific details, such as embodiments of specific components, apparatuses, and methods, are set forth to provide a thorough understanding of implementations of this disclosure. However, it will be apparent to those skilled in the art that certain specific details disclosed are not required and that implementations may be carried out in different forms. Therefore, implementations should not be construed as limiting the scope of this disclosure. As mentioned above, in some implementations, well-known processes, well-known equipment structures, and well-known technologies may not be described in detail.

[0123] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting. For example, the singular forms “a” and “described” as used herein may also be intended to include the plural forms unless the context clearly indicates otherwise. The terms “comprising,” “including,” “containing,” and “having” are inclusive and thus specify the presence of the stated features, integers, steps, operations, elements, and / or components, but do not exclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and / or groups thereof. Unless specifically determined as a preferred or desired order of execution, the steps, processes, and operations described herein should not be construed as requiring them to be performed in the particular order discussed or shown. It should also be understood that additional or alternative steps may be employed in place of or in combination with the disclosed aspects.

[0124] The technical solution of the present invention will now be clearly and completely described with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0125] To solve the technical problems described in this application, the present invention adopts the following technical solution:

[0126] A capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury intrusion inversion, comprising the following steps:

[0127] Step S1: Preparation and grouping of core samples; Select the full-diameter or plunger core to be tested, wash and dry it, and cut it into two parallel samples with similar physical properties: one is the main plunger sample (for NMR and wettability testing), and the other is the end sample (for high-pressure mercury intrusion testing); the relative deviation of porosity and permeability of the parallel samples in Step S1 should be less than 5%; if the core is highly heterogeneous, it is preferable to drill two parallel plunger samples at the same depth. The washing and drying process in Step S1 includes: using petroleum ether for displacement until the effluent shows no fluorescence, and then drying at 105℃ to constant weight.

[0128] Step S2: Preparation and calibration of experimental fluids; two types of experimental water with the same salinity as real formation water are prepared: ordinary simulated formation water (H2O) and heavy formation water (D2O); simultaneously, a representative simulated oil is prepared according to the PVT report, and its hydrogen content index is calibrated; the heavy formation water mentioned in Step S2 is prepared using deuterium oxide (D2O) with a purity greater than 99.9% and inorganic salts, used to completely shield the aqueous phase hydrogen signal in subsequent NMR tests. Representative oil samples are prepared using one or more combinations of alkane and aromatic mixtures, or alkane and dead oil mixtures. Based on the PVT report, the density and viscosity of the representative oil sample are ensured to be consistent with live oil, and the contact angle is consistent with dead oil. The method for determining the hydrogen content index of the representative oil sample in Step S2 is as follows: equal volumes of the representative oil sample and deionized water are subjected to NMR T2 spectrum scanning. The hydrogen content index is determined by the ratio of the T2 signal intensities of the two fluids, and the representative oil NMR signal is converted into the actual oil volume using the hydrogen content index.

[0129] Step S3: Nuclear magnetic resonance (NMR) testing of the core pore structure; after saturating the main plunger sample with ordinary simulated formation water (H2O), NMR T2 spectrum testing is performed to obtain the transverse relaxation time distribution of the core under pressurized saturated water conditions. In Step S3, the NMR test parameters are set as follows: echo interval (TE) is set to 0.1ms~0.2ms to capture micro / nanopore signals, and waiting time (TW) is set to 3000ms~5000ms to ensure complete polarization. The saturation process uses a vacuum pressurization saturation device, with a vacuuming time of no less than 4 hours, a pressurization pressure of no less than 20MPa, and a pressurization time of no less than 24 hours.

[0130] Step S4: High-pressure mercury intrusion test; Perform a high-pressure mercury intrusion test on the end sample to obtain the mercury intrusion capillary force curve and the corresponding pore throat radius distribution curve.

[0131] The specific steps of the high-pressure mercury intrusion test in step S4 are as follows:

[0132] Step S4.1: Load the dried sample with known mass and pore volume into the core chamber;

[0133] Step S4.2: Turn on the vacuum pump to start evacuating the sample until the required vacuum level is reached;

[0134] Step S4.3: Use a displacement pump to measure the mercury inlet capillary pressure curve by gradually increasing the pressure from low to high at the set measurement pressure points, and then decrease the pressure from high to low to measure the mercury outlet capillary pressure curve.

[0135] Step S4.4: After the capillary pressure reaches equilibrium under the set constant pressures, record the pressure value and the corresponding mercury inlet volume;

[0136] Step S4.5: After the test, remove the sample from the core chamber. If any mercury spills, clean it up promptly to avoid environmental pollution. Place the tested sample back into the core container and seal it immediately.

[0137] The maximum mercury ingress pressure was set to 200 MPa–400 MPa in the experiment to meet the characterization requirements for 3 nm–5 nm micropore throats in dense core samples. For mercury porosimetry data processing, a mercury contact angle of 140° and a surface tension of 480 mN / m were used for pore size calculation.

[0138] Step S5: Construction and conversion of the pore size distribution model; jointly calibrate the pore throat distribution of high-pressure mercury intrusion spectroscopy with the NMR T2 spectrum, determine the conversion coefficients C and n, convert the T2 spectrum into the full pore size distribution f(r), and calculate r for each pore size interval. k pore volume component V k .

[0139] The specific method of joint calibration in step S5 is as follows: the conversion coefficients C and n are determined by using the cumulative curve of the pore throat distribution frequency obtained by high pressure mercury intrusion test and the cumulative curve of the signal proportion of T2 spectrum, and the T2 time axis is converted into the pore diameter r axis according to formula (1).

[0140] (1)

[0141] In the formula, C and n are the conversion coefficients between T2 relaxation time and aperture.

[0142] The method for calculating the component volume of each pore is as follows:

[0143] Let the pore volume of the core be Vtotal. Based on the converted pore size distribution probability density f(r), calculate the pore component volume Vk = Vtotal × f(r) occupied by the k-th pore size interval rk. Further, after constructing f(r), interpolation is needed to complete the macropore portion that cannot be measured by mercury porosimetry (due to end-sample surface effects), and the micropore portion that cannot be accurately measured by NMR (due to diffusion effects) is corrected using mercury porosimetry data.

[0144] Step S6: Cut the main plunger sample into two parallel samples of the same length, saturate them with representative simulated oil and heavy water formation water (D2O) respectively, and conduct spontaneous water absorption and forced water displacement experiments in sequence. Measure the nuclear magnetic resonance T2 spectrum at each stage and calculate the Amott-Harvey wetting index I(rk) based on the pore size.

[0145] Step S7: Using the microwetting index I(rk) (range -1 to 1) of each pore size obtained in step S6, calculate the intrinsic contact angle of each pore. :

[0146] cos( )=I(rk )

[0147] The method for establishing the mapping between the micro-wetting index and the contact angle in step S7 is as follows:

[0148] Microscopic wetting index spectrum I obtained from NMR spectroscopy (NMR) ), establish its mapping relationship with the intrinsic contact angle, where the wetting index I( The numbers are between -1 and 1, so we have formula (2):

[0149] (2)

[0150] In the formula Let be the cosine of the intrinsic contact angle of the k-th aperture segment; Let be the wetting index of the k-th aperture segment.

[0151] Based on the sign of I(rk), the pores in the full pore size distribution are divided into two main categories: water-wetted pores and oil-wetted pores.

[0152] Water-wet pores (I(rk)>0), at this time <90°, which is defined as the water-wet reference angle. ;

[0153] Oil-wet pores (I(rk)<0), at this time >90°, which is defined as the oil-wet reference angle. .

[0154] Step S8: Calculate the intrinsic contact angles of each aperture segment obtained in step S7. or Substituting these values ​​into Morrow's (1975) empirical model of Class III contact angle hysteresis for rough surfaces, four dynamic contact angle variables specific to each pore size distribution are mapped: water-wetting retreat angle. Water-wet advance angle Oily back angle Oil-wet advance angle ;

[0155] The method for calculating the dynamic contact angle in step S8 using Morrow's (1975) Class III empirical model for rough surface contact angle hysteresis is as follows:

[0156] For water-wet pores, substitute For oil-wet pores, substitute... :

[0157] Calculate the back angle If 0° < ≤21.6°, backsliding angle =0°;

[0158] If 21.6° < ≤87.6°, backsliding angle The calculation formula is:

[0159] (3)

[0160] If 87.6° < ≤158.4°, backsliding angle The calculation formula is:

[0161] (4)

[0162] like >158.4°, =180°.

[0163] Calculate the angle of advance If 0° < ≤21.6°, =0°;

[0164] If 21.6° < ≤92.4°, advance angle The calculation formula is:

[0165] (5)

[0166] If 92.4° < ≤158.4°, advance angle The calculation formula is:

[0167] (6)

[0168] If 158.4° < ≤180° =180°.

[0169] Step s9: Based on the Young-Laplace equation and combined with the dynamic contact angle, calculate the capillary inlet pressure in two directions for each orifice diameter rk:

[0170] Exhaust drive inlet pressure Fluid overcomes recoil angle resistance; seepage into pressure. The fluid overcomes the drag of the forward angle.

[0171] The method for calculating the pore inlet pressure in step S9 is as follows:

[0172] Based on the Young-Laplace equation, the ingress pressure of the k-th type of pore is calculated:

[0173] Calculate the exhaust inlet pressure At that time, the fluid overcomes the resistance of the recoil angle. For water-wetted orifices:

[0174] (7)

[0175] For oil-wet holes:

[0176] (8)

[0177] In formulas (7) and (8) It is the discharge inlet pressure of the k-th type of pore; It is the interfacial tension of a two-phase fluid; It is the cosine value of the receding angle of the kth type of water-wet pores; It is the cosine value of the receding angle of the k-th type of oily wet pores; It is the radius of the k-th type of pore.

[0178] Calculate the infiltration pressure At that time, the fluid overcomes the drag of the forward angle. For a water-wetted orifice:

[0179] (9)

[0180] For oil-wet holes:

[0181] (10)

[0182] In formulas (9) and (10) It is the infiltration pressure of the k-th type of pore; It is the cosine value of the advance angle of the k-th type of water-wet pores; It is the cosine value of the advance angle of the k-th type of oily wet pores.

[0183] Since the Morrow lag model guarantees that the forward angle is greater than the backward angle, it must satisfy the following condition: > This is the microscopic physical origin of the macroscopic hysteresis loop.

[0184] Step s10: Calculate the and The pore component volumes were sorted and summed separately, and the water saturation under different pressures was calculated, resulting in two discrete capillary force-saturation datasets: the displacement dataset ( , ) and the osmosis dataset ( , Substituting the values ​​into the Skjæveland double asymptotic correlation equation, a regression fit is performed to obtain a continuous curve.

[0185] As a further description of the above technical solution, when calculating interfacial tension, the influence of curvature and adsorption effects in the micro- and nano-pores of shale on interfacial tension needs to be considered, as well as the reduction in effective pore size caused by the interaction between fluid molecules and pore walls, and the change in critical parameters caused by confinement effects.

[0186] Pore ​​size reduction caused by adsorption layer:

[0187] (11)

[0188] In the formula r is the effective aperture, and r is the true aperture. Where is the thickness of the adsorption layer, P is the pressure, T is the temperature, and z is the compressibility factor.

[0189] For the volumetric interfacial tension of the unrestricted segment Available:

[0190] (12)

[0191] In the formula The total component fraction of a fluid mixture The density of the liquid phase is... The density is the gas phase density. Let be the mole fraction of the i-th component in the liquid phase. Let be the mole fraction of the i-th component in the gas phase; Let be the isotensile volume of the i-th component.

[0192] Introducing critical property shift relationships within nanopores to correct phase density and feeding them back to :

[0193] (13) (14)

[0194] In the formula This represents the relative offset of the critical temperature. This represents the relative offset of the critical pressure. This is the bulk critical temperature; This is the critical temperature of the pores. This is the critical pressure of the bulk phase; The critical pressure of the pores; The Lennard-Jones collision diameter.

[0195] Used for PR-EOS calculations, correcting phase density, and feeding back to... .

[0196] Furthermore, the interface tension is corrected for confined curvature using the Tolman equation to obtain the interface tension under confined conditions. :

[0197] (15)

[0198] in, The Tolman length is used. This process focuses on characterizing the significant impact of aperture size reduction on interfacial tension and phase state.

[0199] As a further description of the above technical solution, in step S10, when sorting the data, for the displacement curve:

[0200] Will Arrange the pore volumes in ascending order and sum them up to obtain the water saturation Sw,k at the current pressure.

[0201] For the absorption curve:

[0202] Will Arrange the samples in descending order and sum the pore volumes Vk to obtain the water saturation Sw,k at the current pressure.

[0203] Furthermore, the method for calculating water saturation Sw is as follows:

[0204] Define the current macroscopic capillary pressure as The corresponding wet phase saturation Sw is the value of all inlet pressures less than this. The volume proportion Vk of the pores occupied by the aqueous phase. By gradually increasing And by summing the volumes ∑Vk intruded by the aqueous phase, two discrete drainage datasets are obtained. (Sw,d) and osmosis dataset ( ,Sw,i).

[0205] As a further description of the above technical solution, the method for fitting discrete capillary force-saturation data points in step S10 is as follows:

[0206] Substitute the two sets of discrete datasets into the Skjæveland bi-asymptotic correlation model:

[0207] (16)

[0208] In the formula, For capillary pressure, Water saturation; To restrict water saturation, 1 represents residual oil saturation; cw and aw are water-wet branching coefficients, usually positive. cw is used to scale the amplitude of the positive capillary force component, and aw controls the curvature of the positive capillary force component; co and ao are oil-wet branching coefficients, co is usually negative, and ao is usually positive. co is used to scale the amplitude of the negative capillary force component, and ao controls the curvature of the negative capillary force component.

[0209] The model parameters cw, aw, co, and ao are solved using nonlinear fitting; the final output fitting curve is the reconstructed capillary force curve applicable to this mixed-wetting core.

[0210] Furthermore, when fitting the Skjæveland model, it is usually necessary to initialize the parameters and set parameter boundaries because the function is discontinuous at Swr and 1-Sor. The specific steps are as follows:

[0211] Initialize:

[0212] Swr: Slightly smaller than the minimum value of Sw in the data (for example, if the data starts from 0.2, set it to 0.15).

[0213] Sor: slightly less than (1- (For example, if the maximum value of Sw is 0.8, then Sor) 0.15);

[0214] cw: Positive value, estimated to be the maximum value of the positive pressure portion;

[0215] aw: usually between 0.5 and 2;

[0216] co: negative value, estimated to be the opposite of the maximum amplitude of the negative pressure portion;

[0217] ao: usually between 0.5 and 2.

[0218] Example:

[0219] This embodiment uses a shale core sample from an oilfield block as an example. The core sample is 7.00 cm long and 2.43 cm in diameter. The gas permeability of the shale core is 0.08 mD, and the porosity is 8.2%. In this embodiment, the oil sample density under surface conditions is 0.861 g / mL. The field PVT report shows a live oil density of 0.789 g / mL, a live oil viscosity of 2.5 mPa·s, and a formation water salinity of 9561 mg / L. The specific implementation method is as follows:

[0220] 1. A representative simulated oil with a viscosity of 2.5 mPa·s was prepared by mixing alkane and dead oil in a 1:9 ratio. The density of the representative simulated oil was 0.781 g / mL and the viscosity was 2.5 mPa·s. Heavy formation water (prepared with D2O, salinity 9561 mg / L) and ordinary simulated formation water (prepared with H2O) were also prepared.

[0221] 2. The core sample to be tested is cut into two parallel samples with similar physical properties along the axial direction: Sample A (end sample, about 2 cm long) is used for high pressure mercury intrusion test, and Sample B (main sample, about 5 cm long) is used for nuclear magnetic resonance and wettability test.

[0222] 3. Sample B was evacuated and saturated with ordinary simulated formation water, and its nuclear magnetic resonance T2 spectrum was measured under 100% water saturation. Simultaneously, sample A was subjected to high-pressure mercury intrusion testing at a maximum pressure of 200 MPa.

[0223] 4. Based on Figure 2 The cumulative frequency distributions of the high-pressure mercury intrusion and nuclear magnetic resonance T2 spectra shown are calculated using interpolation. The conversion coefficient C in the formula is 0.0134, and n is 1.5748. Substituting these values ​​into the formula below yields:

[0224]

[0225] Based on this, the full pore size distribution f(r) can be constructed, such as Figure 4 As shown;

[0226] 5. Cut the main sample B into two plunger samples with a diameter of 2.5 cm and a length of 2.5 cm, namely core a and core b, and dry the cores until the core T2 spectra remain unchanged;

[0227] 6. Core a was saturated with heavy water formation water, and core b was saturated with a representative oil sample. After saturation, the T2 spectrum was scanned and the samples were weighed. The signal peak area corresponding to the heavy water formation water saturation of core a was 1230.87, and the signal peak area corresponding to the representative oil saturation of core b was 3182.57.

[0228] 7. A representative oil sample from saturated core a was subjected to spontaneous oil aspiration. After reaching maximum spontaneous oil aspiration, the T2 spectrum was scanned. The signal peak area corresponding to the spontaneously aspirated oil in core a was 2158.47. Subsequently, a representative oil sample was subjected to pressurized aspiration. After the T2 spectrum stabilized, the T2 spectrum was scanned. The signal peak area corresponding to the pressurized aspiration oil in core a was 2628.37. The NMR T2 spectra of the spontaneously aspirated oil and the pressurized aspiration oil from the saturated core are shown below. Figure 5 As shown;

[0229] 8. Heavy water formation water was spontaneously absorbed from oil-saturated core b. After reaching maximum spontaneous absorption, the T2 spectrum was scanned. The signal peak area corresponding to spontaneous water absorption in core b was 2737.62. Subsequently, pressurized formation water absorption was performed. After the T2 spectrum stabilized, the T2 spectrum was scanned again. The signal peak area corresponding to pressurized water absorption in core b was 2670.52. The T2 NMR spectra of spontaneous and pressurized water absorption from the oil-saturated core are shown below. Figure 6 As shown;

[0230] 9. Microwetting indices corresponding to different relaxation times (pore sizes) are as follows: Figure 7 As shown in the figure, this shale exhibits significant heterogeneous wetting characteristics: the small pore size (approximately 0.005 μm, relaxation time less than 0.2 ms) shows a wetting index I > 0, indicating hydrophilic characteristics (mainly controlled by inorganic minerals). Conversely, the large pore size (0.005-0.5 μm) shows a wetting index I < 0, indicating oleophilic characteristics. The wetting index for each pore size range is converted into the effective contact angle between water and oil in that range.

[0231] Four dynamic contact angles were calculated using Morrow's (1975) rough surface contact angle hysteresis model: water-wetted retreat angle. Water-wet advance angle Oily back angle Oil-wet advance angle .

[0232] 10. Considering the influence of curvature and adsorption effects on interfacial tension in shale micro- and nano-pores, it is necessary to consider the reduction in effective pore size caused by the interaction between fluid molecules and pore walls, as well as the change in critical parameters caused by confinement effects.

[0233] Calculate the interfacial tension under confined conditions.

[0234] A set of pore sizes (r=0.05135μm) was selected for calculation, and other fluid parameters are as follows:

[0235] Temperature T = 353.15 K;

[0236] Pressure P = 20 MPa;

[0237] Bulk interfacial tension =30mN / m

[0238] Adsorption layer thickness =0.5nm (depending on P, T, and z);

[0239] Molecular collision volume =0.38nm;

[0240] Tolman length =0.1nm

[0241] Considering the pore size shrinkage caused by the adsorption layer:

[0242]

[0243] Calculate the changes in critical fluid parameters caused by nanoconfining:

[0244]

[0245] Substitution

[0246]

[0247] The critical properties after offset are introduced for equation of state (PR-EOS) calculation, correcting for the phase density difference. Due to the smaller offset at this aperture, the bulk tension after density correction decreases slightly: Let .

[0248] Curvature correction using the Tolman equation:

[0249]

[0250] Substitute parameters , Finally, the confined interfacial tension was calculated:

[0251]

[0252] Based on interfacial tension, the infiltration pressure for each pore size segment is calculated using the Young-Laplace equation. and exhaust pressure .

[0253] Because the contact angle varies with the aperture, The calculation results cover both positive values ​​(corresponding to hydrophilic micropores) and negative values ​​(corresponding to oleophilic macropores). For the displacement curves, all... Arrange them in ascending order and sum the corresponding pore volume components to calculate the wet phase saturation Sw; for the displacement curves, all... Arrange the samples in descending order and sum the corresponding pore volume components to calculate the wet phase saturation Sw.

[0254] like Figure 8 The image shows a scatter plot of the reconstructed discrete displacement and adsorption capillary force-saturation data points. Figure 8 The discrete data were substituted into the Skjæveland double asymptotic correlation for nonlinear fitting. The complete adsorption-displacement process curve is shown below. Figure 9 As shown in the figure, this curve fully describes the entire process from infiltration to displacement, verifying the accuracy and effectiveness of the method of the present invention in characterizing mixed-wetting cores.

[0255] The above description is not intended to limit the present invention in any way. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some changes or modifications to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall fall within the scope of the present invention.

Claims

1. A capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury intrusion inversion, characterized in that, Includes the following steps: Step S1: Preparation and grouping of core samples; Select the full-diameter or plunger core to be tested, wash and dry it, and cut it into two parallel samples with similar physical properties: one is the main plunger sample used for NMR and wettability testing, and the other is the end sample used for high-pressure mercury intrusion testing. Step S2: Preparation and calibration of experimental fluids; prepare two types of experimental water with the same salinity as real formation water: ordinary simulated formation water H2O and heavy formation water D2O; prepare representative simulated oil according to the PVT report and calibrate its hydrogen content index; Step S3: Nuclear magnetic resonance (NMR) test of core pore structure; After saturating the main plunger sample with ordinary simulated formation water (H2O), NMR T2 spectrum test is performed to obtain the transverse relaxation time distribution of the core under pressurized saturated water conditions; Step S4: High-pressure mercury intrusion test; Perform a high-pressure mercury intrusion test on the end sample to obtain the mercury intrusion capillary force curve and the corresponding pore throat radius distribution curve; Step S5: Construction and conversion of the pore size distribution model; jointly calibrate the pore throat distribution of high-pressure mercury intrusion spectroscopy with the NMR T2 spectrum, determine the conversion coefficients C and n, convert the T2 spectrum into the full pore size distribution f(r), and calculate r for each pore size interval. k pore volume component V k ; Step S6: Cut the main plunger sample into two parallel samples of equal length, saturate them with representative simulated oil and heavy water formation water D2O respectively, and conduct spontaneous water absorption and forced water displacement experiments in sequence. Measure the NMR T2 spectrum at each stage and calculate the Amott-Harvey wetting index by pore size. ; Step S7: Utilize the micro wettability index of each pore size segment obtained in step S6. Calculate the intrinsic contact angle of each pore. ; Step S8: Calculate the intrinsic contact angles of each aperture segment obtained in step S7. or Substituting these values ​​into the Morrow rough surface contact angle hysteresis Class III empirical model, four dynamic contact angle variables specific to each pore size distribution are mapped: water-wetting retreat angle. Water-wet advance angle Oily back angle Oil-wet advance angle ; Step S9: Combine the dynamic contact angle to determine the aperture for each level. Calculate the capillary inlet pressure in both directions; these are the discharge inlet pressures required to overcome the backlash resistance of the fluid. and the suction pressure of fluid overcoming the resistance of the advance angle ; Step S10: Calculate the exhaust pressure. and osmotic pressure By sorting and summing the pore component volumes separately, the water saturation under different pressures is calculated, resulting in two discrete capillary force-saturation datasets: the displacement dataset and the exhaust dataset. and osmotic dataset Substituting the values ​​into the Skjæveland double asymptotic correlation equation, regression fitting is performed to obtain a continuous curve.

2. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury injection as described in claim 1, characterized in that, In step S1, the relative deviation of porosity and permeability of parallel samples should be less than 5%; if the core is highly heterogeneous, it is preferable to drill two parallel plunger samples at the same depth.

3. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury intrusion as described in claim 1, characterized in that, In step S3, the echo interval TE in the nuclear magnetic resonance test is set to 0.1ms~0.2ms, the waiting time TW is set to 3000ms~5000ms, the saturation process adopts a vacuum pressurization saturation device, the vacuuming time is not less than 4 hours, the pressurization pressure is not less than 20MPa, and the pressurization time is not less than 24 hours.

4. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury intrusion as described in claim 1, characterized in that, The specific steps of the high-pressure mercury intrusion experiment in step S4 are as follows: Step S4.1: Load the dried sample with known mass and pore volume into the core chamber; Step S4.2: Turn on the vacuum pump to start evacuating the sample until the required vacuum level is reached; Step S4.3: Use a displacement pump to measure the mercury inlet capillary pressure curve by gradually increasing the pressure from low to high at the set measurement pressure points, and then decrease the pressure from high to low to measure the mercury outlet capillary pressure curve. Step S4.4: After the capillary pressure reaches equilibrium under the set constant pressures, record the pressure value and the corresponding mercury inlet volume; Step S4.5: After the test, remove the sample from the core chamber. If any mercury spills, clean it up promptly to avoid environmental pollution. Put the tested sample back into the core container and seal it. The maximum mercury ingress pressure in the experiment is set to 200MPa~400MPa to meet the characterization requirements of 3nm~5nm micropore throats in dense cores. When processing mercury intrusion porosimetry data, the contact angle of mercury is taken as 140° and the surface tension is taken as 480mN / m for pore size calculation.

5. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury injection as described in claim 1, characterized in that, The specific steps of the joint calibration in step S5 are as follows: Step S5.1: Determine the conversion coefficients C and n using the cumulative curve of the pore throat distribution frequency obtained from the high-pressure mercury intrusion test and the cumulative curve of the signal proportion of the T2 spectrum. Convert the T2 time axis to the pore diameter r axis according to formula (1): ； In the formula, C and n are the conversion coefficients between T2 relaxation time and aperture; Step S5.2: Calculation of pore volume components; Let the pore volume of the core be Vtotal. Based on the converted pore size distribution probability density f(r), calculate the k-th pore size interval. The volume of the pore component occupied is Vk = Vtotal × f(r); Step S5.3: After constructing f(r), interpolation is performed using NMR signals to complete the macropores that cannot be measured by mercury porosimetry due to the surface effect of the end sample, and the micropores that cannot be measured by NMR due to the diffusion effect are corrected using mercury porosimetry data.

6. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury injection as described in claim 1, characterized in that, The specific steps for establishing the mapping method between the micro-wetting index and the contact angle in step S7 are as follows: Step S7.1: Microscopic wetting index spectrum obtained from NMR spectroscopy Establish its mapping relationship with the intrinsic contact angle, where the wetting index Numbers from -1 to 1: ； In the formula Let be the cosine of the intrinsic contact angle of the k-th aperture segment; Let be the wetting index of the k-th aperture segment; Step S7.2: According to The sign of the pores determines whether the pores in the full pore size distribution are classified into two main categories: water-wetted pores and oil-wetted pores. Water-wet pores ( >0), at this time <90° is defined as the water-wet reference angle. ; Oily wet pores ( <0), at this time >90° is defined as the oil-wet reference angle. .

7. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury injection as described in claim 1, characterized in that, The specific steps for calculating the dynamic contact angle using the Morrow rough surface contact angle hysteresis Class III empirical model in step S8 are as follows: Step S8.1: For water-wet pores, substitute... For oil-wet pores, substitute Calculate the back angle If 0° < ≤21.6°, backsliding angle =0°; if 21.6° < ≤87.6°, backsliding angle The calculation formula is: ； If 87.6° < ≤158.4°, backsliding angle The calculation formula is: ； like >158.4°, =180°; Step S8.2: Calculate the advance angle If 0° < ≤21.6°, =0°; If 21.6° < ≤92.4°, advance angle The calculation formula is: ; If 92.4° < ≤158.4°, advance angle The calculation formula is: ; If 158.4° < ≤180° =180°.

8. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury injection as described in claim 1, characterized in that, The specific steps for calculating the pore inlet pressure in step S9 are as follows: Step S9.1: Based on the Young-Laplace equation, calculate the inlet pressure of the k-th type of pore and the exhaust inlet pressure. At that time, the fluid overcomes the resistance of the recoil angle. For water-wetted holes: ; For oil-wet holes: ; In formulas (7) and (8) It is the discharge inlet pressure of the k-th type of pore; It is the interfacial tension of a two-phase fluid; It is the cosine value of the receding angle of the kth type of water-wet pores; It is the cosine value of the receding angle of the k-th type of oily wet pores; It is the radius of the k-th type of pore; Step S9.2: Calculate the infiltration pressure For water-wetted orifices, the fluid overcomes the resistance of the advance angle. ; For oil-wet holes: ; In formulas (9) and (10) It is the infiltration pressure of the k-th type of pore; It is the cosine value of the advance angle of the k-th type of water-wet pores; It is the cosine value of the advance angle of the k-th type of oily wet pores; Step S9.3: Considering the reduction in effective pore size due to the interaction between fluid molecules and the pore wall, the change in critical parameters due to the confinement effect, and the pore size shrinkage caused by the adsorption layer, perform interfacial tension calculation: ; In the formula r is the effective aperture, and r is the true aperture. Where P is the thickness of the adsorption layer, T is the pressure, and z is the temperature; For the volumetric interfacial tension of the unrestricted segment : ; In the formula The total number of components in a fluid mixture. The density of the liquid phase is... The density is the gas phase density. Let be the mole fraction of the i-th component in the liquid phase. Let be the mole fraction of the i-th component in the gas phase; Let be the isotensile volume of the i-th component; Step S9.4: Introduce the critical property shift relationship within the nanopores to correct the phase density and feed it back to... : ; In the formula This represents the relative offset of the critical temperature. This represents the relative offset of the critical pressure. This is the bulk critical temperature; This is the critical temperature of the pores. This is the critical pressure of the bulk phase; The critical pressure of the pores; The Lennard-Jones collision diameter; Step S9.5: Use the Tolman equation to perform confined curvature correction on the interfacial tension to obtain the interfacial tension under confined conditions. : ; in, For the Tolman length, this process focuses on characterizing the significant impact of aperture size reduction on interfacial tension and phase state.

9. The capillary force reconstruction method for microscopic wettability using combined nuclear magnetic resonance and high-pressure mercury injection as described in claim 1, characterized in that, In step S10, when sorting the data, for the displacement curve: Arrange in ascending order and sum the pore volumes Vk to obtain the water saturation Sw,k at the current pressure; for the percolation curve: Arrange the samples in descending order and sum the pore volumes Vk to obtain the water saturation Sw,k at the current pressure.

10. The capillary force reconstruction method for microscopic wettability using joint inversion of nuclear magnetic resonance and high-pressure mercury injection as described in claim 9, characterized in that, The specific steps for fitting discrete capillary force-saturation data points in step S10 are as follows: Step S10.1: Substitute the two sets of discrete datasets into the Skjæveland bi-asymptotic correlation model: ; In the formula, For capillary pressure, Water saturation; To restrict water saturation, 1 represents residual oil saturation; cw and aw are water-wet branching coefficients, usually positive. cw is used to scale the amplitude of the positive capillary force component, and aw controls the curvature of the positive capillary force component; co and ao are oil-wet branching coefficients, co is usually negative, and ao is usually positive. co is used to scale the amplitude of the negative capillary force component, and ao controls the curvature of the negative capillary force component. Step S10.2: Solve the model parameters cw, aw, co, ao using nonlinear fitting; the output fitting curve is the reconstructed capillary force curve applicable to mixed-wetting cores.

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