Shale sample oil-water saturation intelligent determination method based on two-dimensional nuclear magnetism technology

Abstract

The invention relates to the technical field of rock sample oil-water saturation determination based on a nuclear magnetic technology, and provides a shale sample oil-water saturation intelligent determination method based on a two-dimensional nuclear magnetic technology, and the method comprises the following steps: collecting volumes, echo signals and signal-to-noise ratios of a preset number of rock samples; marking a target rock sample and a comparison rock sample, and determining a volume influence comprehensive interference degree and a noise amplification coefficient of a target echo signal; obtaining a denoised target echo signal according to the target echo signal, the volume of the rock sample corresponding to the target echo signal and the noise amplification coefficient of the echo signal; according to experiments of rock sample two-dimensional nuclear magnetic oil-water distribution, pore attributes and the like, a two-dimensional nuclear magnetic T1-T2 map is divided into an invalid pore area and an effective pore area of a rock sample corresponding to the two-dimensional nuclear magnetic T1-T2 map and an oil-water distribution area of the effective pore area, a fluid close to reservoir oil-water distribution is adopted to recover a two-dimensional nuclear magnetic spectrum of the rock sample, and the oil-water content corresponding to a nuclear magnetic signal is extracted; and obtaining a rock sample oil-water saturation determination result based on the nuclear magnetic technology.

Description

Technical Field

[0001] The present invention relates to the technical field of rock sample oil-water saturation determination based on nuclear magnetic resonance technology, and in particular to an intelligent determination method for shale sample oil-water saturation based on two-dimensional nuclear magnetic resonance technology. Background Art

[0002] In the oil industry, nuclear magnetic resonance (NMR) is commonly used to determine oil and water saturation in rock samples during core testing. NMR technology uses the T2 spectrum of the core to determine oil and water saturation by analyzing the nuclear magnetic signals of the oil and water phases. Two-dimensional NMR technology, which combines high-frequency NMR longitudinal relaxation time (T1) and transverse relaxation time (T2), can address issues such as oil and water distribution and occurrence in shale reservoirs.

[0003] During magnetic resonance imaging (MRI), gradient fields generated by gradient coils in three orthogonal directions (x, y, and z) are used for spatial encoding, enabling the determination of signals at different locations within a rock sample, independent control, and three-dimensional positioning. To achieve clear imaging, the current in the gradient coils changes rapidly, generating a varying magnetic field. However, this rapidly changing current is also one of the largest sources of noise in MRI. Due to the small size of rock samples and the weak echo amplitude, the measured NMR signal is susceptible to noise. Furthermore, when using NMR to measure rock samples, the measured NMR signal often contains noise due to the low NMR porosity of shale oil reservoirs. This noisy NMR signal can affect the accuracy of oil and water saturation measurements in rock samples.

[0004] Two-dimensional NMR measurements of shale oil samples require noise control during signal acquisition. After the measurement is complete, the resulting NMR spectrum must be analyzed. High-frequency two-dimensional NMR shale oil sample measurement technology, which combines the longitudinal relaxation time (T1) and transverse relaxation time (T2) of the NMR signal, is a relatively new technology, and many testing techniques are still immature and under development. The combined two-dimensional NMR T1-T2 measurement of shale oil samples produces a T1-T2 NMR signal distribution spectrum containing information about the hydrogen species in the sample. Shale oil fluid saturation analysis based on this NMR technique requires not only analyzing the T1-T2 NMR signal distribution spectrum to identify the hydrogen species with different properties and characteristics represented by the NMR signals at each position within the spectrum, but also quantitatively calculating the NMR signals representing different hydrogen species within the spectrum from qualitative analysis. Shale oil reservoir rocks contain a variety of hydrogen-containing species, including structural water / crystallized water, clay-absorbed water, pore water, organic matter, and oil and gas of varying composition and occurrence. Different hydrogen-containing species have varying implications for fluid saturation. Correctly identifying and quantitatively analyzing the different fluid properties on the T1-T2 NMR spectrum directly impacts the accuracy of saturation calculations. Therefore, a suitable 2D NMR-based method for determining fluid saturation in shale oil samples, based on the physical properties of the T1-T2 map NMR signal, is lacking. Summary of the Invention

[0005] The present invention provides an intelligent method for determining oil and water saturation in shale samples based on two-dimensional nuclear magnetic resonance technology to address the problem that the collected nuclear magnetic resonance signals contain noise, which affects the accuracy of oil and water saturation determination in rock samples, and the lack of technology for quantitatively analyzing the different properties of hydrogen-containing species in the two-dimensional nuclear magnetic resonance spectrum of shale oil samples, making it difficult to accurately determine the saturation using the two-dimensional nuclear magnetic resonance method. The technical solutions adopted are specifically as follows:

[0006] One embodiment of the present invention provides a method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology, the method comprising the following steps:

[0007] Collect the volume, echo signal and signal-to-noise ratio of a preset number of rock samples;

[0008] Any rock sample is recorded as a target rock sample, and all rock samples except the target rock sample are recorded as comparison rock samples. According to the frequency values ​​of the echo signals of the target rock sample and the comparison rock sample, the value range of the target frequency is defined, and the power spectrum and power spectrum density of the target rock sample and the comparison rock sample are obtained. According to the similarity between the power spectrum density of the target rock sample and the comparison rock sample, the difference between the power spectrum density, the distribution of the peak of the power spectrum and the difference in volume, the volume effect echo interference degree of the target rock sample is determined. According to the volume effect echo interference degree of all rock samples, the comprehensive interference degree of volume effect is determined. The noise amplification factor of the target echo signal is obtained by combining the peak distribution and peak value of the echo signal and the signal-to-noise ratio of the target rock sample;

[0009] Determining an adjustment threshold of the target echo signal according to the target echo signal, the volume of the rock sample corresponding to the target echo signal, and the noise amplification factor of the echo signal; and obtaining a denoised target echo signal according to the determined adjustment threshold of the target echo signal;

[0010] The rock samples are subjected to water value calibration, oil-water content calibration, water distribution experiments, oil distribution experiments, pore property characteristic experiments of naturally lost rock samples, pore property characteristic experiments of low-temperature water removal rock samples, and pore property characteristic experiments of low-temperature oil removal rock samples. The water distribution area and oil distribution area are determined, and two-dimensional nuclear magnetic resonance spectra are obtained respectively. The invalid pore area and the effective pore partition are divided according to the two-dimensional nuclear magnetic resonance spectra. The nuclear magnetic resonance signal boundary line between the effective pore area and the invalid pore area is divided. The boundary between the water distribution area and the oil distribution area in the effective pore partition is divided, and the pore restoration of the rock sample is performed;

[0011] According to the values ​​of the nuclear magnetic signals measured in the water distribution area and the oil distribution area, the saturation calculation method of the two-dimensional nuclear magnetic method is used to obtain the oil and water saturation measurement results of the rock sample based on nuclear magnetic technology.

[0012] Furthermore, the rock sample is prepared by:

[0013] Rock samples are collected at the pressure-maintaining core position of the shale oil reservoir in the exploration area. After the rock samples are lifted to the surface and out of the barrel through drilling, they are completely frozen and preserved in a freezer at a temperature of -40°C or less using freezing technology. The rock samples need to be completely frozen and are large flaky rock samples greater than or equal to 15 mm and less than or equal to 20 mm. The cutting tools should cut in a direction perpendicular to the bedding and bedding end face of the rock sample so that the rock sample geometry meets the test requirements and is frozen again to keep the rock sample in a frozen state.

[0014] Furthermore, the method of defining the value range of the target frequency according to the frequency values ​​of the echo signals of the target rock sample and the comparison rock sample, and obtaining the power spectrum and power spectrum density of the target rock sample and the comparison rock sample includes the following specific methods:

[0015] The echo signals of the target rock sample and the comparison rock sample are converted into frequency domain signals respectively using fast Fourier transform, and the power spectrum is plotted based on the frequency domain signals to obtain the power spectrum density;

[0016] The minimum value of all frequency domain signals is recorded as the minimum frequency value, the maximum value of all frequency domain signals is recorded as the maximum frequency value, and all natural numbers greater than or equal to the minimum frequency value and less than or equal to the maximum frequency value are taken as the value range of the target frequency.

[0017] Furthermore, the volume-affected echo interference degree of the target rock sample is determined based on the similarity between the power spectrum densities of the target rock sample and the comparison rock sample, the difference between the power spectrum densities, the distribution of the peaks of the power spectrum graph, and the difference in volume, including the specific method of:

[0018] The absolute value of the Pearson correlation coefficient between the power spectrum density of the target rock sample and the comparison rock sample is recorded as the power spectrum correlation between the target rock sample and the comparison rock sample, and the average value of the power spectrum correlation between the target rock sample and all the comparison rock samples is recorded as the rock sample attribute similarity of the target rock sample;

[0019] Obtain the peak values ​​of the power spectra of the target rock sample and the comparison rock sample respectively; record the minimum value of the absolute values ​​of the differences between the target frequency and all the peak values ​​of the target rock sample as the shortest frequency difference of the target rock sample at the target frequency; record the minimum value of the absolute values ​​of the differences between the target frequency and all the peak values ​​of the comparison rock sample as the shortest frequency difference of the comparison rock sample at the target frequency; at the target frequency, record the absolute value of the difference between the shortest frequency differences of the target rock sample and the comparison rock sample as the shortest frequency difference between the target rock sample and the comparison rock sample at the target frequency; record the average of the shortest frequency differences between the target rock sample and all the comparison rock samples at the target frequency as the first difference of the target rock sample at the target frequency;

[0020] The absolute value of the difference between the power spectrum density of the target rock sample and the comparison rock sample at the target frequency is recorded as the power spectrum difference between the target rock sample and the comparison rock sample at the target frequency, and the average of the power spectrum differences between the target rock sample and all the comparison rock samples at the target frequency is recorded as the second difference of the target rock sample at the target frequency;

[0021] The mean of the volumes of all comparison rock samples is recorded as the average volume of the comparison rock samples, and the absolute value of the difference between the volume of the target rock sample and the average volume of the comparison rock samples is recorded as the volume difference of the target rock sample;

[0022] The volume effect echo interference degree of the target rock samples is determined based on the volume difference of the target rock samples, the similarity of the rock sample properties, and the first difference and the second difference of the target rock samples at the target frequency.

[0023] Furthermore, the method of determining the volume effect echo interference degree of the target rock sample based on the volume difference of the target rock sample, the rock sample attribute similarity, and the first difference and the second difference of the target rock sample at the target frequency includes the following specific methods:

[0024] The product of the first difference and the second difference of the target rock sample at the target frequency is recorded as the third difference of the target rock sample at the target frequency, and the cumulative sum of the third differences corresponding to the values ​​of the target rock sample at all target frequencies is recorded as the fourth difference of the target rock sample;

[0025] The product of the volume difference of the target rock sample and the fourth difference is recorded as the first product of the target rock sample, the difference between the number 1 and the rock sample attribute similarity of the target rock sample is recorded as the rock sample attribute difference degree of the target rock sample, and the product of the first product of the target rock sample and the rock sample attribute difference degree is recorded as the volume influence echo interference degree of the target rock sample.

[0026] Furthermore, the method for obtaining the volume impact comprehensive interference degree is:

[0027] The cumulative sum of the volume-affected echo interference of all rock samples is recorded as the volume-affected comprehensive interference.

[0028] Furthermore, the noise amplification factor of the target echo signal is obtained by combining the peak distribution and peak value of the signal-to-noise ratio of the target rock sample, including the specific method of:

[0029] The peak values ​​of the echo signal and the peak value of the signal-to-noise ratio of the target rock sample are obtained respectively, and the peak values ​​of the echo signal of the target rock sample are arranged in the order of the acquisition time of the peak values ​​to obtain an echo signal peak sequence; the peak values ​​of the signal-to-noise ratio of the target rock sample are arranged in the order of the acquisition time of the signal-to-noise ratio to obtain a signal-to-noise ratio peak sequence; the null hypothesis is set as no significant difference between the echo signal peak sequence and the signal-to-noise ratio peak sequence, and the alternative hypothesis is that there is a significant difference between the echo signal peak sequence and the signal-to-noise ratio peak sequence, and the t-test algorithm is used to calculate the p-value, and the p-value is recorded as the statistical significance of the target echo signal and the signal-to-noise ratio;

[0030] The peak values ​​of the echo signals of the target rock samples are arranged in ascending order of peak values ​​to obtain an echo signal peak arrangement sequence; the peak values ​​of the signal-to-noise ratios of the target rock samples are arranged in ascending order of peak values ​​to obtain a signal-to-noise ratio peak arrangement sequence; the DTW distance between the echo signal peak arrangement sequence and the signal-to-noise ratio peak arrangement sequence is recorded as the time variation difference between the target echo signal and the signal-to-noise ratio;

[0031] The noise amplification factor of the target echo signal is obtained based on the comprehensive interference of volume effect, the statistical significance of the target echo signal and the signal-to-noise ratio, and the time variation difference.

[0032] Furthermore, the noise amplification factor of the target echo signal is obtained according to the comprehensive interference degree of volume effect, the statistical significance of the target echo signal and the signal-to-noise ratio, and the time variation difference, including the specific method of:

[0033] The normalized value of the product of the statistical significance of the target echo signal and the signal-to-noise ratio and the time variation difference is recorded as the second product of the target echo signal. The difference between the number 1 and the second product of the target echo signal is recorded as the third product of the target echo signal. The product of the comprehensive interference degree of volume influence and the third product of the target echo signal is recorded as the noise amplification factor of the target echo signal.

[0034] Furthermore, the method for determining the adjustment threshold of the target echo signal is:

[0035] The volume of the rock sample is used as the independent variable, and the noise amplification factor of the echo signal corresponding to the rock sample is used as the dependent variable. A straight line is fitted between the independent variable and the dependent variable to obtain a fitting straight line, and the slope of the fitting straight line is recorded as the regression coefficient.

[0036] Use the median absolute deviation (MAD) to obtain the noise level of the target echo signal;

[0037] According to the regression coefficient and noise level of the target echo signal, the adjustment threshold of the target echo signal is determined. The calculation formula is:

[0038]

[0039] Where T represents the adjustment threshold of the target echo signal; tanh represents the hyperbolic tangent function; β1 represents the regression coefficient of the target echo signal; σ1 represents the first parameter adjustment coefficient; and σ represents the noise level of the target echo signal.

[0040] Furthermore, the method of obtaining the denoised target echo signal based on the adjustment threshold of the target echo signal includes the following specific methods:

[0041] The adjusted threshold of the target echo signal is used as the value of the soft threshold, and the echo signal of the rock sample is denoised using wavelet transform to obtain the denoised target echo signal.

[0042] Furthermore, the method for calibrating the water value is:

[0043] All seven rock samples were selected, and the moisture in the rock samples was removed at high temperature. Deionized water was dripped into each rock sample respectively. The amount of water dripped into the seven rock samples was 0.100ml, 0.200ml, 0.300ml, 0.400ml, 0.500ml, 0.700ml and 0.900ml respectively. Nuclear magnetic resonance T2 spectrum measurement was carried out on each rock sample to obtain two-dimensional nuclear magnetic measurement results.

[0044] Furthermore, the method for calibrating the oil-water content is:

[0045] All seven rock samples were selected, and a certain amount of kerosene was added to the rock sample test cups. The amounts of kerosene in the rock sample cups were 0.500ml, 1.000ml, 1.500ml, 2.000ml, 2.500ml, 3.000ml and 3.500ml respectively. Nuclear magnetic resonance (NMR) measurements were performed on each rock sample to obtain two-dimensional NMR measurement results.

[0046] Furthermore, the method for determining the water distribution area is:

[0047] Water distribution experiments were conducted on rock samples containing no hydrogen-bearing substances and rock samples containing solid or nearly solid hydrogen-bearing substances;

[0048] The process of water distribution experiment for rock samples without hydrogen is as follows:

[0049] Select any shale sample, place it in a 700℃ retort to remove hydrogen, and perform a two-dimensional nuclear magnetic resonance experiment until all hydrogen is removed.

[0050] The rock sample is placed in a humidistat with a humidity of not less than 85% to absorb moisture. When the mass of the rock sample remains unchanged, a two-dimensional nuclear magnetic resonance experiment is carried out again to obtain the T1-T2 distribution spectrum and determine the water distribution area.

[0051] Furthermore, the process of conducting water distribution experiments on rock samples containing solid or nearly solid hydrogen-containing substances is as follows:

[0052] Select any shale sample, conduct 2D NMR measurement and obtain 2D NMR spectrum;

[0053] The rock samples were placed in alcohol-benzene solvent for deoiling, and then dehumidified at 115°C until constant weight was reached. Two-dimensional nuclear magnetic resonance experiments were then performed to obtain the T1-T2 distribution spectrum under deoiling and dehumidification conditions.

[0054] The rock sample is placed in a humidistat with a humidity of not less than 85% to absorb moisture, and after the mass is constant, it is subjected to two-dimensional nuclear magnetic resonance measurement again to obtain a two-dimensional nuclear magnetic spectrum saturated with water;

[0055] The rock sample is smashed open and allowed to absorb moisture again. After the mass becomes constant, a two-dimensional nuclear magnetic resonance (NMR) measurement is performed to obtain a two-dimensional NMR spectrum of water absorption of the rock sample under conditions where cracks are generated by external force destruction.

[0056] Furthermore, the method for determining the oil distribution area is:

[0057] Select any shale sample, deoil it with alcohol-benzene solvent, dehumidify it at 115℃, conduct a 2D NMR experiment, and obtain the 2D NMR spectrum of the sample under deoiling and dehumidification conditions;

[0058] The rock sample is placed in an environment with a humidity of not less than 85% and absorbs water, and then subjected to two-dimensional nuclear magnetic resonance measurement to obtain a two-dimensional nuclear magnetic spectrum of the rock sample under water absorption conditions;

[0059] The rock sample is immersed in kerosene and absorbs saturated kerosene. After the mass is stable, two-dimensional nuclear magnetic resonance measurement is carried out to obtain the two-dimensional nuclear magnetic spectrum of the rock sample under water and oil absorption conditions;

[0060] The oil distribution area is determined based on the two-dimensional nuclear magnetic spectrum of the rock sample under oil and moisture removal conditions, the two-dimensional nuclear magnetic spectrum of the rock sample under water absorption conditions, and the two-dimensional nuclear magnetic spectrum of the rock sample under water and oil absorption conditions.

[0061] Furthermore, the method of the pore property characteristic experiment of the naturally lost rock sample is:

[0062] Two rock samples collected from the center of the pressure-maintained core of the shale oil reservoir were selected. After two-dimensional nuclear magnetic resonance measurement before they were completely thawed, the rock samples were placed in a rock sample bottle and thawed slowly under natural conditions. After the rock samples were completely thawed, they were placed in a vacuum low-temperature condition of 60°C for 8 hours to remove pore water, and two-dimensional nuclear magnetic resonance measurement was performed to obtain the two-dimensional nuclear magnetic spectrum of the rock sample; one of the dehydrated rock samples was placed under constant humidity conditions with a humidity greater than 85%, so that the rock sample was saturated with water by self-absorption. After the mass remained unchanged, the sample was placed in kerosene, so that it was saturated with kerosene by self-absorption. After the mass remained unchanged, two-dimensional nuclear magnetic resonance measurement was performed to obtain the two-dimensional nuclear magnetic spectrum of the rock sample; the other sample after low-temperature dehydration was first placed in kerosene, and then placed in constant humidity conditions with a humidity greater than or equal to 85%, so that the sample was saturated with kerosene and water respectively. After the mass remained unchanged, two-dimensional nuclear magnetic resonance measurement was performed on each sample to obtain the two-dimensional nuclear magnetic spectrum of the rock sample.

[0063] Furthermore, the method of the low-temperature dewatering rock sample pore property characteristic experiment is:

[0064] Select any rock sample, perform 2D NMR measurement, place the rock sample in a vacuum at 60°C for 8 hours, remove pore water, and perform 2D NMR analysis on the rock sample to obtain the T1-T2 distribution spectrum under the condition of removing pore water.

[0065] The rock samples were placed under constant humidity conditions with a humidity greater than 85% to allow them to absorb saturated water. After their mass remained unchanged, two-dimensional nuclear magnetic resonance measurements were carried out to obtain the T1-T2 oil-water distribution spectrum under water absorption conditions. The two-dimensional nuclear magnetic resonance measurement data under different conditions were compared and analyzed to determine the reproducibility of pore water.

[0066] Furthermore, the method of the low-temperature deoiling rock sample pore property characteristic experiment is:

[0067] A rock sample collected from the center of a pressure-maintained core in a shale oil reservoir was subjected to two-dimensional nuclear magnetic resonance (NMR) measurement. The sample was then deoiled and dehumidified using chloroform at 60°C for a period of no less than 70 hours. A two-dimensional nuclear magnetic resonance (NMR) experiment was then performed on the rock sample to obtain a two-dimensional NMR spectrum after deoiling and dehumidification.

[0068] The rock sample is immersed in kerosene to make it absorb saturated kerosene. After the mass remains unchanged, a two-dimensional nuclear magnetic resonance experiment is carried out to obtain the two-dimensional nuclear magnetic spectrum under the saturated kerosene condition.

[0069] The rock sample is placed under constant humidity conditions with a humidity greater than 85% to allow the rock sample to absorb saturated water and its mass to remain unchanged. Then, the rock sample is subjected to two-dimensional nuclear magnetic resonance measurement again to obtain a two-dimensional nuclear magnetic spectrum under the water absorption condition again.

[0070] Furthermore, the specific method of dividing the ineffective pore area and the effective pore area according to the two-dimensional nuclear magnetic spectrum includes:

[0071] The rock samples were deoiled with alcohol-benzene solvent and dehumidified at 115°C to constant weight. Two-dimensional nuclear magnetic resonance (NMR) experiments were then performed to obtain the T1-T2 distribution spectrum of solids or near-solid hydrogen-containing substances that could not be removed after deoiling and dehumidification. The samples were then saturated with oil and water, and after the mass was constant, two-dimensional nuclear magnetic resonance (NMR) measurements were performed to obtain the pore oil-water distribution spectrum.

[0072] The area where the two-dimensional nuclear magnetic distribution spectrum of solid or nearly solid hydrogen-containing substances such as crystal water or structural water in clay minerals, organic matter and asphaltene is located is defined as the invalid pore distribution area, and the area composed of the self-absorption saturated water distribution area and the oil distribution area is recorded as the effective pore area.

[0073] Furthermore, the method for dividing the nuclear magnetic signal boundary line between the effective pore area and the invalid pore area is:

[0074] The abscissa of the weakest nuclear magnetic signal between the effective pore area and the invalid pore area in the two-dimensional nuclear magnetic spectrum is marked as a, and the straight line with the abscissa a is used as the dividing line between the effective pore area and the invalid pore area. The area less than or equal to the straight line a is the invalid pore area, and the area greater than the straight line a is the effective pore area.

[0075] Furthermore, the boundary division method between the water distribution area and the oil distribution area in the effective pore partition is as follows:

[0076] The vertical coordinate of the weakest nuclear magnetic signal between the oil distribution area and the water distribution area in the effective pore area is marked as b, and the straight line with the vertical coordinate b is used as the dividing line between the oil distribution area and the water distribution area. Between the oil distribution area and the water distribution area, the area with a vertical coordinate greater than b is recorded as the oil distribution area, and the area less than or equal to b is recorded as the water distribution area.

[0077] Furthermore, the pore restoration of the rock sample includes the following specific methods:

[0078] When the water distribution is greater than the oil distribution, place the rock sample in a rock sample bottle filled with kerosene to allow it to absorb the kerosene. After the rock sample mass remains constant, place the rock sample in a constant humidity chamber with a humidity of not less than 85% to allow the rock sample to absorb water until the mass remains constant.

[0079] When the water distribution is much smaller than the oil distribution, place the rock sample in a constant humidity chamber with a humidity of not less than 85% to allow the rock sample to absorb water by itself until the mass becomes constant. Then place the rock sample in a rock sample bottle filled with kerosene to allow the rock sample to absorb kerosene by itself until the mass becomes constant.

[0080] When the water distribution is the same as the oil distribution, place the rock sample in a rock sample bottle filled with kerosene to allow it to absorb the kerosene by itself. After the mass of the rock sample remains unchanged, place the rock sample in a constant humidity box with a humidity of not less than 85% to allow it to absorb water by itself until the mass remains unchanged.

[0081] Furthermore, the saturation calculation method of the two-dimensional nuclear magnetic resonance method is used to calculate the saturation of the water distribution area and the oil distribution area according to the values ​​of the nuclear magnetic signals measured. The calculation formula is:

[0082]

[0083]

[0084] Where S W1 Indicates water saturation determined by nuclear magnetic resonance; S W2 Indicates the oil saturation determined by nuclear magnetic resonance; k water represents the conversion coefficient between rock sample NMR signal and water signal; M1 represents the cumulative sum of all NMR signals in the water distribution area; K oil It represents the conversion coefficient between rock sample NMR signal and oil signal; M2 represents the cumulative sum of all NMR signals in the oil distribution area.

[0085] The beneficial effects of the present invention are:

[0086] This application evaluates the aggravating effect of rock sample volume change on the noise generated by gradient field switching based on the similarity between the power spectral density of the target rock sample and the difference between the power spectral density, the distribution of the peak of the power spectrum and the volume difference between the target rock sample and the comparison rock sample, and determines the comprehensive interference degree of volume influence. Furthermore, considering that the volume difference between different rock samples will amplify and interfere with the echo signal, and the intensity noise of the echo signal is directly related to the intensity, the influence effect of the echo signal on the noise is further analyzed, and the peak distribution and peak value of the echo signal and the signal-to-noise ratio of the target rock sample are combined to obtain the target echo signal. The noise amplification coefficient of the target echo signal is as follows: when the noise amplification coefficient of the target echo signal is larger, the sensitivity of the volume change of the rock sample to the noise generated by the gradient field switching is greater, that is, the volume change of the rock sample has a greater impact on the noise generated when the gradient field is switched; according to the target echo signal, the volume of the rock sample corresponding to the target echo signal, and the noise amplification coefficient of the echo signal, the target echo signal is denoised to obtain the denoised target echo signal, and the processing intensity of the wavelet transform on the signal at different frequencies is more accurately controlled, so that the denoising process can be adaptively adjusted according to the volume difference of the rock sample and the noise amplification effect, thereby suppressing the noise. The invention can suppress the noise while retaining the effective information of the signal, improve the accuracy and reliability of the nuclear magnetic resonance signal processing, and solve the problem that the collected nuclear magnetic resonance signal contains noise, which affects the accuracy of the oil and water saturation determination of the rock sample; further, the invention clarifies the oil and water distribution area of ​​the two-dimensional nuclear magnetic spectrum through the oil and water distribution experiment, and then establishes a method for dividing the boundaries between the oil and water distribution areas, avoiding the confusion of oil and water caused by unclear oil and water distribution division, which brings serious distortion consequences to the oil and water saturation determination of the two-dimensional nuclear magnetic method; the distribution of the effective pore area and the invalid pore area is clarified through the experiment, and a method for dividing the effective pore area and the invalid pore area is established. The effective pore zone method avoids the drawback of inaccurate determination of oil-water content and pore volume due to unclear distinction between the two, which leads to large deviations in oil-water saturation analysis, thereby greatly improving the accuracy of 2D NMR oil-water saturation determination. Through shale oil sample property verification experiments, it is confirmed that the pores of shale oil reservoir samples have dual wettability with oil and water. Based on this, a 2D NMR saturation experimental method is established, which enables accurate determination of water, oil, and pore volume, improving the accuracy of shale sample oil-water saturation determination. Its application in conventional coring solves the problem of shale samples being unable to correct for oil and gas loss during coring and drilling. Based on the experiment of quantitatively analyzing the oil-water distribution in the 2D NMR T1-T2 spectrum, a method for quantitative oil and water extraction and oil-water saturation calculation based on the T1-T2 oil-water distribution spectrum is established. This method is convenient, fast, simple and clear, with a short experimental cycle and high production efficiency. It is non-toxic and harmless, and conforms to the HSE safety, health and environmental protection concept. BRIEF DESCRIPTION OF THE DRAWINGS

[0087] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0088] Figure 1 A schematic flow chart of a method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to one embodiment of the present invention;

[0089] Figure 2 A schematic diagram of the relationship between water content and nuclear magnetic resonance signals provided by one embodiment of the present invention;

[0090] Figure 3 A schematic diagram showing the relationship between kerosene volume and nuclear magnetic resonance signals according to an embodiment of the present invention;

[0091] Figure 4 A schematic diagram of a two-dimensional nuclear magnetic distribution spectrum of a rock sample water distribution experiment provided by one embodiment of the present invention;

[0092] Figure 5 Two-dimensional nuclear magnetic distribution spectrum of water distribution experiment under different conditions provided by one embodiment of the present invention;

[0093] Figure 6 A two-dimensional nuclear magnetic distribution spectrum of an oil distribution experiment provided by one embodiment of the present invention;

[0094] Figure 7 A two-dimensional nuclear magnetic resonance distribution spectrum of the pore property characteristic experiment of rock sample oil under low-temperature water removal provided by one embodiment of the present invention;

[0095] Figure 8 A two-dimensional nuclear magnetic resonance distribution spectrum of the pore property characteristic experiment of low-temperature oil removal of rock sample provided by one embodiment of the present invention;

[0096] Figure 9 A diagram showing the oil-water distribution zones of a shale sample's two-dimensional nuclear magnetic resonance spectrum provided by one embodiment of the present invention;

[0097] Figure 10 This is an oil-water distribution area division diagram of oil-water data extracted from two-dimensional nuclear magnetic resonance spectroscopy of shale samples provided by one embodiment of the present invention. DETAILED DESCRIPTION

[0098] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0099] See also Figure 1 , which shows a flow chart of a method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology provided by one embodiment of the present invention. The method includes the following steps:

[0100] Step S001: Collect the volume, echo signal and signal-to-noise ratio of a preset number of rock samples.

[0101] Rock samples are collected at the pressure-maintaining core position of the shale oil reservoir in the exploration area. After the rock samples are lifted to the surface through drilling and taken out of the barrel, they are completely frozen and preserved in a freezer at a temperature of -40°C or less using freezing technology to avoid large-scale loss of fluid in the rock samples.

[0102] Among them, the rock sample needs to be completely frozen, and a core cutting tool or a special core machete should be used to make large flaky rock samples greater than or equal to 15 mm and less than or equal to 20 mm along the core bedding surface. The core cutting tool or the special core machete should cut in a direction perpendicular to the bedding and the bedding end face, and the geometric shape should meet the test requirements, and then be frozen again to keep the rock sample in a frozen state.

[0103] For each rock sample, a 3D scanner is used to collect 3D data of the rock sample, and the volume of the rock sample is obtained based on the 3D data. A nuclear magnetic analyzer is used to collect the echo signal and signal-to-noise ratio of the rock sample.

[0104] Preferably, in one embodiment of the present application, seven rock samples of varying mass are collected, each having a thickness of 15 mm or greater and 20 mm or less. When collecting echo signals and signal-to-noise ratios, the data sampling frequency in this embodiment is 21 MHz, and a total of 10 seconds of echo signals and signal-to-noise ratios are collected. In actual applications, as other implementations, implementers may determine the number of rock samples collected, the sampling frequency of echo signals and signal-to-noise ratios, and the sampling duration based on actual circumstances, and this application does not impose any specific restrictions.

[0105] At this point, the volume, echo signal and signal-to-noise ratio of different rock samples are obtained.

[0106] Step S002: any rock sample is recorded as a target rock sample, and all rock samples except the target rock sample are recorded as comparison rock samples. The value range of the target frequency is defined according to the frequency values ​​of the echo signals of the target rock sample and the comparison rock sample, and the power spectrum and power spectrum density of the target rock sample and the comparison rock sample are obtained. The volume effect echo interference degree of the target rock sample is determined according to the similarity between the power spectrum densities of the target rock sample and the comparison rock sample, the difference between the power spectrum densities, the distribution of the peak values ​​of the power spectrum, and the difference in volume. The volume effect comprehensive interference degree is determined according to the volume effect echo interference degrees of all rock samples. The noise amplification factor of the target echo signal is obtained by combining the peak distribution and peak value of the echo signal and the signal-to-noise ratio of the target rock sample.

[0107] The echo signal from a rock sample records the relaxation process of hydrogen nuclei within the sample in a magnetic field. The magnetic field generated by rapid gradient field switching is one of the largest noise sources in magnetic resonance imaging. The switching of the gradient field causes the metal wire in the coil to vibrate violently due to the Lorentz force, generating noise that interferes with the echo signal. In particular, in shale oil reservoirs with low NMR porosity, the collected fluid signal is weak and noisy. Therefore, the quality of the echo signal is directly affected by the noise generated by gradient field switching. The greater the noise, the lower the clarity and accuracy of the echo signal.

[0108] First, the echo signals were analyzed to evaluate the effect of rock sample volume changes on the noise generated by gradient field switching.

[0109] Any rock sample is designated as the target rock sample, and all samples other than the target rock sample are designated as comparison rock samples. The echo signals of the target rock sample and the comparison rock sample are converted into frequency domain signals using a fast Fourier transform. A power spectrum is plotted based on the frequency domain signals to obtain the power spectral density. The minimum value of all frequency domain signals is designated as the minimum frequency value, and the maximum value of all frequency domain signals is designated as the maximum frequency value. The target frequency is defined. Specifically, all natural numbers greater than or equal to the minimum frequency value and less than or equal to the maximum frequency value are defined as the target frequency value range.

[0110] The power spectral density shows the distribution of the echo signal's power at different frequencies. Different frequency components correspond to different pore structures within the rock sample. The pore structure of shale oil reservoirs is determined by the rock's inherent properties, such as organic matter abundance, maturity, and lithology. These inherent properties vary little within the same or similar geological environments. Furthermore, pore types within shale oil reservoirs primarily include primary pores and secondary pores, with residual intergranular pores and secondary dissolution pores being the predominant types. These pores have poor connectivity, further limiting the variability of the pore structure. Therefore, rock samples with the same inherent properties exhibit relatively consistent pore structure characteristics.

[0111] The absolute value of the Pearson correlation coefficient between the power spectrum density of the target rock sample and the comparison rock sample is recorded as the power spectrum correlation between the target rock sample and the comparison rock sample, and the mean value of the power spectrum correlation between the target rock sample and all the comparison rock samples is recorded as the rock sample attribute similarity of the target rock sample.

[0112] The greater the similarity of the target rock sample's rock properties, the greater the consistency of the pore structure characteristics between the target rock sample and the comparison rock sample.

[0113] A peak detection algorithm is used to obtain the peak values ​​of the power spectra of the target rock sample and the comparison rock sample. The minimum value among the absolute values ​​of the difference between the target frequency and all the peak values ​​of the target rock sample is recorded as the shortest frequency difference of the target rock sample at the target frequency. The minimum value among the absolute values ​​of the difference between the target frequency and all the peak values ​​of the comparison rock sample is recorded as the shortest frequency difference of the comparison rock sample at the target frequency. At the target frequency, the absolute value of the difference between the shortest frequency differences of the target rock sample and the comparison rock sample is recorded as the shortest frequency difference between the target rock sample and the comparison rock sample at the target frequency. The average of the shortest frequency differences between the target rock sample and all the comparison rock samples at the target frequency is recorded as the first difference of the target rock sample at the target frequency.

[0114] The use of a peak detection algorithm to obtain the peak value of the power spectrum is a well-known technique and will not be described in detail. It is understood that there are generally multiple peak values ​​in the power spectrum, and the horizontal axis of each peak value in the power spectrum is the frequency of the frequency domain signal.

[0115] The first difference of the target rock sample at the target frequency reflects the difference in pore structure characteristics between the target rock sample and the comparison rock sample at the target frequency. When the first difference of the target rock sample at the target frequency is larger, the difference in pore structure characteristics between the target rock sample and the comparison rock sample at the target frequency is more significant, and the possibility of interference with the echo signal of the target rock sample is greater.

[0116] The absolute value of the difference between the power spectrum density of the target rock sample and the comparison rock sample at the target frequency is recorded as the power spectrum difference between the target rock sample and the comparison rock sample at the target frequency, and the average of the power spectrum differences between the target rock sample and all comparison rock samples at the target frequency is recorded as the second difference of the target rock sample at the target frequency.

[0117] The second difference of the target rock sample at the target frequency reflects the difference between the power spectrum density of the target rock sample and the comparison rock sample at the target frequency. When the second difference of the target rock sample at the target frequency is greater, the difference between the power spectrum density of the target rock sample and the comparison rock sample at the target frequency is greater, and the possibility that the echo signal of the target rock sample is interfered is greater.

[0118] The mean of the volumes of all comparison rock samples is recorded as the average volume of the comparison rock samples, and the absolute value of the difference between the volume of the target rock sample and the average volume of the comparison rock samples is recorded as the volume difference of the target rock sample.

[0119] The volume effect echo interference degree of the target rock sample is determined based on the volume difference of the target rock sample, the similarity of the rock sample properties, and the first difference and the second difference of the target rock sample at the target frequency.

[0120] Preferably, as an embodiment of the present application, the product of the first difference and the second difference of the target rock sample at the target frequency is recorded as the third difference of the target rock sample at the target frequency, and the cumulative sum of the third differences corresponding to the values ​​of the target rock sample at all target frequencies is recorded as the fourth difference of the target rock sample; the product of the volume difference and the fourth difference of the target rock sample is recorded as the first product of the target rock sample, the difference between the number 1 and the rock sample attribute similarity of the target rock sample is recorded as the rock sample attribute difference degree of the target rock sample, and the product of the first product of the target rock sample and the rock sample attribute difference degree is recorded as the volume influence echo interference degree of the target rock sample.

[0121] According to the volume effect echo interference degree of all rock samples, the comprehensive interference degree of volume effect is determined.

[0122] Preferably, as an embodiment of the present application, the cumulative sum of the volume-affected echo interference degrees of all rock samples is recorded as the volume-affected comprehensive interference degree.

[0123] The volume effect comprehensive interference factor evaluates the likelihood of echo signal interference caused by differences in rock sample volume. The greater the volume difference of the target rock sample, the greater the impact of the probability of echo signal interference on the volume effect comprehensive interference factor. The greater the volume effect comprehensive interference factor, the more significant the interference effect of rock sample volume differences on the echo signal.

[0124] The volume difference between different rock samples will amplify and interfere with the echo signal, and the intensity noise of the echo signal is directly related to the intensity. The effect of the echo signal on the noise is further analyzed.

[0125] A peak detection algorithm is used to process the target rock sample's echo signal and signal-to-noise ratio (SNR) to obtain the peak values ​​of the target rock sample's echo signal and SNR. The peak values ​​of the target rock sample's echo signal are arranged in chronological order of their acquisition time to obtain an echo signal peak sequence. The peak values ​​of the target rock sample's SNR are arranged in chronological order of their acquisition time to obtain an SNR peak sequence. The null hypothesis is that there is no significant difference between the echo signal peak sequence and the SNR peak sequence, and the alternative hypothesis is that there is a significant difference between the echo signal peak sequence and the SNR peak sequence. A t-test is used to calculate the p-value. The p-value is recorded as the statistical significance of the target rock sample's echo signal and SNR.

[0126] The greater the statistical significance of the target echo signal and the signal-to-noise ratio, the greater the possibility that the echo signal of the target rock sample is interfered with.

[0127] The peak values ​​of the target rock sample's echo signals are arranged in ascending order to obtain an echo signal peak sequence. The peak values ​​of the target rock sample's signal-to-noise ratio are arranged in ascending order to obtain a signal-to-noise ratio peak sequence. The DTW distance between the echo signal peak sequence and the signal-to-noise ratio peak sequence is recorded as the temporal variation difference between the target echo signal and the signal-to-noise ratio.

[0128] The smaller the difference between the time variation of the target echo signal and the signal-to-noise ratio, the more consistent the temporal variation trend of the echo signal and the signal-to-noise ratio of the target rock sample.

[0129] The noise amplification factor of the target echo signal is obtained based on the comprehensive interference of volume effect, the statistical significance of the target echo signal and the signal-to-noise ratio, and the time variation difference.

[0130] Preferably, as an embodiment of the present application, the normalized value of the product of the statistical significance of the target echo signal and the signal-to-noise ratio and the time variation difference is recorded as the second product of the target echo signal, the difference between the number 1 and the second product of the target echo signal is recorded as the third product of the target echo signal, and the product of the volume impact comprehensive interference and the third product of the target echo signal is recorded as the noise amplification factor of the target echo signal.

[0131] It should be noted that this embodiment uses the Z-Score standard normalization method to calculate the normalized value. In actual application, the implementer can use other existing methods such as maximum and minimum value normalization method, sigmoid function, etc. to calculate the normalized value, which is not limited here.

[0132] When the statistical significance of the target echo signal and the signal-to-noise ratio and the time variation difference are smaller and the comprehensive interference of the volume effect is greater, the noise amplification factor of the target echo signal is greater. At this time, the sensitivity of the volume change of the rock sample to the noise generated by the gradient field switching is greater, that is, the impact of the volume change of the rock sample on the noise generated during the gradient field switching is greater.

[0133] At this point, the noise amplification factor of the target echo signal is obtained. The noise amplification factor of any rock sample can be obtained using the same method.

[0134] Step S003: Determine an adjustment threshold of the target echo signal according to the target echo signal, the volume of the rock sample corresponding to the target echo signal, and the noise amplification factor of the echo signal; and obtain a denoised target echo signal based on the determined adjustment threshold of the target echo signal.

[0135] The volume of the rock sample is taken as the independent variable, and the noise amplification factor of the echo signal corresponding to the rock sample is taken as the dependent variable. The least squares method is used to perform linear fitting on the independent and dependent variables to obtain a fitting straight line, and the slope of the fitting straight line is recorded as the regression coefficient.

[0136] Using the least squares method to perform straight line fitting is a well-known technology and will not be described in detail. This embodiment uses the least squares method to perform straight line fitting. In actual application, as other implementation methods, on the basis of achieving the purpose of performing straight line fitting, the implementer can use other existing methods such as polynomial fitting technology to fit the straight line. This application does not impose any special restrictions.

[0137] The regression coefficient is used to evaluate the strength of the linear relationship between the volume of the rock sample and the noise amplification factor. The stronger the linear relationship, the larger the absolute value of the regression coefficient.

[0138] The median absolute deviation (MAD) is used to obtain the noise level of the target echo signal.

[0139] Wavelet transform can be used to denoise the echo signal of the rock sample. The soft threshold in the wavelet transform determines the ability to distinguish between noise and valid signals in the echo signal.

[0140] The target echo signal adjustment threshold is determined based on the regression coefficient and noise level of the target echo signal. The target echo signal adjustment threshold is calculated as follows:

[0141]

[0142] Wherein, T represents the adjustment threshold of the target echo signal; tanh represents the hyperbolic tangent function; β1 represents the regression coefficient of the target echo signal; σ1 represents the first tuning parameter coefficient, and in this embodiment, the value of the first tuning parameter coefficient is 1; σ represents the noise level of the target echo signal.

[0143] The adjusted threshold of the target echo signal is used as the value of the soft threshold, and the echo signal of the rock sample is denoised using wavelet transform to obtain the denoised target echo signal.

[0144] The same method can be used to obtain the denoised target echo signal corresponding to the echo signal of any rock sample.

[0145] By using the adjustment threshold of the target echo signal as the value of the soft threshold, it is possible to effectively suppress noise while retaining the effective information of the signal, and more accurately control the processing intensity of the wavelet transform on the signal at different frequencies, so that the denoising process can be adaptively adjusted according to the volume difference of the rock sample and the noise amplification effect, thereby retaining the effective information of the signal while suppressing noise, and improving the accuracy and reliability of nuclear magnetic resonance signal processing.

[0146] It should be noted that, unless otherwise specified, the subsequent NMR measurements in this embodiment all use wavelet transform for denoising to ensure the accuracy of NMR signal processing.

[0147] At this point, the denoised target echo signals corresponding to the echo signals of all rock samples are obtained.

[0148] Step S004: perform water value calibration, oil-water content calibration, water distribution experiment, oil distribution experiment, natural loss rock sample pore property characteristic experiment, low-temperature water removal rock sample pore property characteristic experiment, low-temperature oil removal rock sample pore property characteristic experiment, determine the water distribution area and oil distribution area, as well as the invalid pore area and effective pore partition, provide a boundary demarcation method between the invalid pore area and the effective pore partition of the two-dimensional nuclear magnetic spectrum, and a boundary demarcation method between the water distribution area and the oil distribution area in the effective pore partition, measure the original sample, restore and test the pore volume of the rock sample, demarcate the boundary between the water distribution area and the oil distribution area of ​​the shale sample, and obtain the oil and water saturation data of the shale sample according to the oil-water distribution boundary value and the given saturation calculation method.

[0149] Shale samples cannot be prepared by hammering. To improve the success rate of sample preparation and reduce breakage, specialized cutting tools are required. This also prevents cracks in the prepared sample, which could affect the shale test results. The preparation method is as follows: Use liquid nitrogen or a -40°C freezer to freeze the full-diameter shale sample to be sampled; completely freeze the sample; use a core cutting tool or a specialized core machete to create a full-diameter flake sample along the core bedding plane, suitable for testing, and refreeze it to maintain a frozen state. The required thickness for testing is generally 15mm to 20mm. Use the core cutting tool to cut the full-diameter flake core perpendicular to the bedding and bedding end faces into block samples with a geometric shape that meets the testing requirements.

[0150] Calibrate the water content of rock samples.

[0151] Specifically, the required rock samples are selected, the moisture in the rock samples is removed at high temperature, and different amounts of deionized water or distilled water are dripped into each rock sample. The amounts of water dripped into the seven rock samples are 0.100ml, 0.200ml, 0.300ml, 0.400ml, 0.500ml, 0.700ml and 0.900ml respectively; nuclear magnetic resonance T2 spectrum measurement is carried out on each rock sample to obtain the relationship between water content and nuclear magnetic signal. The relationship between water content and nuclear magnetic signal is the two-dimensional nuclear magnetic measurement result.

[0152] The relationship between water content and nuclear magnetic signal is shown in the following diagram: Figure 2 As shown, in Figure 2In the figure, the horizontal axis is the NMR signal, and the vertical axis is the water content. Water content and the NMR signal are directly proportional and linearly related. Therefore, NMR technology has high accuracy and reliability in determining water content, and the water content in rock samples can be accurately inferred by measuring the NMR signal.

[0153] The rock samples were calibrated for oil content.

[0154] Specifically, all rock samples were selected and a certain amount of kerosene was added to the rock sample test cups respectively. The amounts of kerosene in the rock sample cups were 0.500ml, 1.000ml, 1.500ml, 2.000ml, 2.500ml, 3.000ml and 3.500ml respectively. Nuclear magnetic resonance measurement was carried out on each rock sample to obtain the relationship between the amount of kerosene and the nuclear magnetic signal. The relationship between the amount of kerosene and the nuclear magnetic signal is the two-dimensional nuclear magnetic measurement result.

[0155] The relationship between kerosene volume and nuclear magnetic signal is shown in the figure below: Figure 3 As shown, in Figure 3 In the figure, the horizontal axis represents the NMR signal, and the vertical axis represents the kerosene content. The kerosene content and the NMR signal are in a positive linear relationship. Therefore, NMR technology has high accuracy and reliability in measuring kerosene content, and the amount of kerosene in a rock sample can be accurately inferred by measuring the NMR signal.

[0156] Conduct water distribution experiments on rock samples. It is necessary to conduct water distribution experiments on rock samples that do not contain hydrogen-containing substances and rock samples that contain solid or nearly solid hydrogen-containing substances.

[0157] A water distribution experiment is conducted on shale samples that do not contain hydrogen. Specifically, for any hydrogen-containing rock sample, the rock sample is placed in a 700°C retort to remove the hydrogen-containing rock at a constant temperature, and a two-dimensional nuclear magnetic resonance experiment is performed to obtain a two-dimensional nuclear magnetic spectrum. The two-dimensional nuclear magnetic spectrum is as follows: Figure 4 As shown in (a), until the hydrogen-containing substances in the rock sample are completely removed; the rock sample is placed in a humidistat with a humidity of not less than 85% to absorb moisture. When the mass of the rock sample remains unchanged, the two-dimensional nuclear magnetic resonance experiment is carried out again to obtain the T1-T2 distribution spectrum. The T1-T2 distribution spectrum is shown in Figure 4 As shown in (b), determine the water distribution area.

[0158] Among them, the T1-T2 distribution spectrum is a two-dimensional nuclear magnetic spectrum, that is, a T1-T2 joint determination spectrum; in a two-dimensional nuclear magnetic spectrum such as the schematic diagram of the two-dimensional nuclear magnetic distribution spectrum of the rock sample water distribution experiment, as shown in Figure 4 In (a), after the rock sample is retorted at 700℃, the hydrogen-containing substances are basically removed. After water is added to the rock sample, the nuclear magnetic signals in the two-dimensional nuclear magnetic T1-T2 spectrum are distributed near the diagonal line of the T1-T2map. Figure 4 In the schematic diagram of the two-dimensional nuclear magnetic distribution spectrum of the rock sample water distribution experiment (b), relative to Figure 4In (a), the newly added NMR signal is the NMR signal of water.

[0159] Water distribution experiments were conducted on shale samples containing solid or nearly solid hydrogen-containing substances.

[0160] Specifically, any shale rock sample is selected, two-dimensional nuclear magnetic resonance measurement is carried out and a two-dimensional nuclear magnetic spectrum is obtained. The rock sample is placed in an alcohol-benzene solvent for deoiling, and dehumidified at 115°C to constant weight. A two-dimensional nuclear magnetic experiment is carried out to obtain the T1-T2 distribution spectrum under the deoiling and dehumidification conditions; the rock sample is placed in a humidistat with a humidity of not less than 85% to absorb moisture, and after the mass is weighed to be constant, a two-dimensional nuclear magnetic resonance measurement is carried out again to obtain a two-dimensional nuclear magnetic spectrum saturated with water; the rock sample is smashed open and moisture is absorbed again. After the mass is constant, a two-dimensional nuclear magnetic resonance measurement is carried out to obtain a two-dimensional nuclear magnetic spectrum of water absorption when the rock sample contains cracks under external force destruction conditions; the two-dimensional nuclear magnetic resonance measurement results under different conditions are compared to determine the water distribution location. In this process, the two-dimensional nuclear magnetic distribution spectra of the water distribution experiment under different conditions are as follows: Figure 5 shown.

[0161] exist Figure 5 (a) is the two-dimensional nuclear magnetic spectrum measured from the original rock sample. The oil-water distribution area of ​​the two-dimensional nuclear magnetic T1-T2map spectrum has a strong nuclear magnetic signal, indicating that the sample has a good oil-water distribution; Figure 5 In (b), the NMR signal belongs to hydrogen-containing substances that cannot be removed by solvent degreasing and 115°C dehumidification. These hydrogen-containing substances that cannot be removed are mainly crystal water or structural water in clay minerals, organic matter and asphaltene, which are solid or nearly solid hydrogen-containing substances. Figure 5 In (c), the rock sample absorbs water and there are new nuclear magnetic signals. The basic distribution of the new nuclear magnetic signals is similar to that of Figure 4 The same as (b), in the area near the diagonal of the two-dimensional nuclear magnetic spectrum, that is, in the area of ​​T1 / T2=10-1, the signal that appears belongs to water signal; Figure 5 In (d), after the rock sample is cracked under the action of external force, it is saturated with water again, and a new two-dimensional nuclear magnetic spectrum is obtained. There is a new nuclear magnetic signal. The new nuclear magnetic signal is the re-saturated water, and its two-dimensional nuclear magnetic signal is basically distributed along the T1 / T2=10-1 area.

[0162] Through the above experimental process, it can be seen that in the two-dimensional nuclear magnetic distribution spectrum of the rock sample, water is distributed along the diagonal of the T1-T2 two-dimensional spectrum, that is, the two-dimensional nuclear magnetic distribution area of ​​water is basically in the range of T1 / T2=10-1.

[0163] Carry out oil distribution experiments on rock samples.

[0164] Specifically, any rock sample was selected, deoiled with alcohol-benzene solvent, dehumidified at 115°C, and a two-dimensional nuclear magnetic resonance experiment was performed to obtain the two-dimensional nuclear magnetic spectrum of the rock sample under the deoiling and dehumidification conditions. The two-dimensional nuclear magnetic spectrum of the two-dimensional nuclear magnetic experiment is shown as follows: Figure 6As shown in (a); after the rock sample is placed in an environment with a humidity of not less than 85% and absorbs water, a two-dimensional nuclear magnetic resonance measurement is carried out to obtain a two-dimensional nuclear magnetic spectrum of the rock sample under water absorption conditions. The two-dimensional nuclear magnetic spectrum of the rock sample under water absorption conditions is shown as follows Figure 6 As shown in (b); the rock sample is immersed in kerosene to absorb saturated kerosene. After the quality is stable, a two-dimensional nuclear magnetic resonance measurement is carried out to obtain the two-dimensional nuclear magnetic spectrum of the rock sample under water and oil absorption conditions. The two-dimensional nuclear magnetic spectrum of the rock sample under water and oil absorption conditions is as shown in the two-dimensional nuclear magnetic spectrum of the two-dimensional nuclear magnetic experiment. Figure 6 As shown in (c).

[0165] The two-dimensional NMR distribution spectrum of the oil distribution experiment is as follows Figure 6 As shown, Figure 6 In (a), only the nuclear magnetic field signal at the left edge exists, which belongs to the hydrogen-containing species that cannot be removed by oil removal and dehumidification, while the pore fluid has been removed; Figure 6 In (b), a new signal is detected on the right side of the original NMR signal that cannot be removed. The new signal is the NMR signal of absorbed water. Its distribution range is consistent with the previous water distribution experiment, and is basically distributed in the T1 / T2=10-1 area. The NMR signal belongs to absorbed water. Figure 6 The new signal detected in (c) is the 2D NMR signal of absorbed oil, distributed in a region with high T1 values, above the water signal, and with a slightly increased T2 value (i.e., T1 / T2 > 10), indicating a stratification with the water. This oil distribution experiment shows that when shale pores are in a two-phase medium containing both water and oil, the 2D NMR spectrum of the shale sample exhibits oil-water stratification, with oil distributed in the region with T1 / T2 > 10, and water similarly distributed in the T1 / T2 = 10-1 range.

[0166] Conduct pore property characteristic experiments on naturally lost rock samples.

[0167] Specifically, two shale samples collected from the center of the pressure-maintained core of the shale oil reservoir were selected. After two-dimensional nuclear magnetic resonance measurement was performed on the samples before they were completely thawed, the samples were placed in a sample bottle and thawed slowly under natural conditions. After the samples were completely thawed, they were placed in a vacuum low-temperature condition of 60°C for 8 hours to remove pore water, and two-dimensional nuclear magnetic resonance measurement was performed to obtain a two-dimensional nuclear magnetic spectrum of the rock sample; one of the dehydrated rock samples was placed under constant humidity conditions with a humidity greater than 85%, so that the rock sample was saturated with water by self-absorption. After the mass remained unchanged, the sample was placed in kerosene, so that it was saturated with kerosene by self-absorption. After the mass remained unchanged, a two-dimensional nuclear magnetic resonance measurement was performed to obtain a two-dimensional nuclear magnetic spectrum of the rock sample; the other sample after low-temperature dehydration was first placed in kerosene, and then placed under constant humidity conditions with a humidity greater than or equal to 85%, so that the sample was saturated with kerosene and water, respectively. After the mass remained unchanged, two-dimensional nuclear magnetic resonance measurement was performed on each sample.

[0168] Table 1 is the NMR analysis data of rock samples that absorbed water and then absorbed oil.

[0169] Table 1 Nuclear magnetic analysis data of rock samples absorbing water and then absorbing oil

[0170]

[0171]

[0172] As shown in Table 1, after rock sample 1 was saturated with water, the water content increased by 0.045 ml, and the oil and gas content had basically no obvious change. After saturated with oil, the oil and gas content increased by 0.027 ml, and the water content had no change. For rock sample 2, after saturated with oil, the oil content increased by 0.034 ml, and the pore water content had basically no obvious change. After saturated with water, the pore water content increased by 0.047 ml, and the oil and gas content had no obvious change. The oil and water content measured after the rock sample self-absorbed oil and water was slightly greater than the oil and water content measured during pressure-maintaining freezing.

[0173] Therefore, when a rock sample with pores containing oil and water is saturated with oil and water during self-absorption, water can only enter the pore space where water is stored, that is, the water-wetted pores, under the action of the capillary force of the pores, while the pores where oil is stored are oil-wet and have a repulsive force on water, and water cannot enter the pores where oil is stored; similarly, oil can be self-absorbed into the pores where oil is stored under the action of capillary force, while the pores where water is stored are water-wet because there is water in the capillaries and water is adsorbed on the pore surface, and have a repulsive force on oil, and oil cannot enter the pore space where water is stored. Therefore, the pores of rock samples containing some oil and water are selective for the absorbed oil and water, that is, the pores of shale rock samples from which some oil and water have been lost are selective for the absorbed oil and water, and oil can only enter the pores where oil is stored, and water can only enter the pores where water is stored. Moreover, the pores of naturally lost rock samples can be filled with oil and water through self-imbibition saturation, that is, rock samples that have lost oil and water can be restored to have an oil and water distribution close to reservoir conditions through self-imbibition saturation with oil and water.

[0174] The pore property characteristic experiment of rock samples was carried out by low temperature dehydration.

[0175] Select any rock sample and perform two-dimensional nuclear magnetic resonance measurement. Place the rock sample in a vacuum at a low temperature of 60°C for 8 hours to remove pore water, and conduct two-dimensional nuclear magnetic resonance analysis of the rock sample to obtain the T1-T2 distribution spectrum under the condition of removing pore water; place the rock sample under constant humidity conditions with a humidity greater than 85% to allow the rock sample to self-absorb saturated water. After the mass remains unchanged, perform two-dimensional nuclear magnetic resonance measurement to obtain the T1-T2 oil-water distribution spectrum under the condition of re-absorption of water; compare and analyze the two-dimensional nuclear magnetic resonance measurement data under different conditions to determine the reproducibility of pore water.

[0176] Specifically, a rock sample collected from the pressure-maintaining core of a shale oil reservoir was selected and subjected to two-dimensional nuclear magnetic resonance measurement before it was completely thawed. The two-dimensional nuclear magnetic spectrum is shown in FIG. Figure 7(a) As shown; Then, the rock sample was placed in a rock sample bottle and thawed slowly under natural conditions for 4 hours to completely thaw the rock sample. The rock sample was placed in a vacuum low temperature condition of 60℃ for 8 hours to remove the pore water, and the two-dimensional nuclear magnetic resonance analysis of the rock sample after water removal was carried out. The two-dimensional nuclear magnetic resonance spectrum is shown as follows Figure 7 (b) The rock sample after dehydration was placed under constant humidity conditions with a humidity greater than 85% to allow the rock sample to absorb saturated water. After the mass remained unchanged, the rock sample was subjected to two-dimensional nuclear magnetic resonance measurement again. The two-dimensional nuclear magnetic spectrum is shown in Figure 7 (c) shown.

[0177] The two-dimensional nuclear magnetic distribution spectrum of the rock sample low-temperature dehydration pore property characteristics experiment is as follows Figure 7 As shown. Figure 7 In the figure, (a) indicates that the selected rock sample contains a good distribution of oil and water, (b) indicates that the pore water is basically removed and some oil is also removed, and (c) indicates that the rock sample is resaturated with moisture and can absorb water back into the pores from which the pore water has been removed, while water cannot enter the pores where oil is stored.

[0178] That is, the rock samples collected from the pressure-maintaining core area of ​​the shale oil reservoir contain a good distribution of oil and water. After the rock samples are placed in a vacuum at a low temperature of 60°C for 8 hours, the pore water is basically removed and part of the oil is also removed. After moisture absorption and saturation, the rock samples can reabsorb water into the pores from which the pore water has been removed, while water cannot enter the pores where oil is stored.

[0179] Therefore, pore water has reproducibility, that is, under the action of capillary force, pore water can enter the pores occupied by the original pore water, but water does not enter the pores where oil is stored.

[0180] A low-temperature deoiling rock sample pore property characteristic experiment was conducted on the rock sample.

[0181] Specifically, rock samples collected from the pressure-maintaining core of the shale oil reservoir were selected for two-dimensional nuclear magnetic resonance measurement. The two-dimensional nuclear magnetic spectrum is as follows: Figure 8 As shown in (a); chloroform is used to remove oil and moisture at a low temperature of 60℃, and the deoiling time is generally not less than 70h. A two-dimensional nuclear magnetic resonance experiment is carried out on the rock sample to obtain a two-dimensional nuclear magnetic spectrum after deoiling and dehumidification. The two-dimensional nuclear magnetic spectrum is shown in Figure 8 (b) As shown; the rock sample is immersed in kerosene to make the rock sample self-absorb saturated with kerosene. After the mass remains unchanged, a two-dimensional nuclear magnetic resonance experiment is carried out to obtain a two-dimensional nuclear magnetic spectrum under the condition of no pore water. The two-dimensional nuclear magnetic spectrum is shown as follows Figure 8 (c) shows that the rock sample is placed under a constant humidity condition with a humidity greater than 85% to allow the rock sample to absorb saturated water and maintain its mass. The rock sample is then subjected to a two-dimensional nuclear magnetic resonance (NMR) measurement to obtain a two-dimensional NMR spectrum under the water absorption condition. The two-dimensional NMR spectrum is shown in FIG. Figure 8 (d) shown.

[0182] Among them, it is necessary to understand that the two-dimensional nuclear magnetic spectrum is a T1-T2 combined measurement spectrum.

[0183] The two-dimensional nuclear magnetic distribution spectrum of the rock sample low-temperature oil removal pore property characteristics experiment is as follows Figure 8 As shown, by comparison Figure 8 It can be seen that (a) indicates that the selected rock sample contains a certain amount of oil and water, the water is distributed along T1 / t2 = 1--10, and the oil is basically distributed in T1 / T2>10; (b) indicates that after the rock sample is deoiled and dehumidified at low temperature, the oil and water are basically removed, and after the rock sample is immersed in kerosene and saturated by self-absorption, the original water distribution area has a strong nuclear magnetic signal; (c) shows that under the condition of no pore water, oil can not only enter the pore space where the original rock sample is oil-bearing, but also enter the pore space occupied by the original rock sample pore water. (d) indicates that after the rock sample is saturated with water by self-absorption and its mass remains unchanged, the 2D NMR oil-water distribution is the same as the original 2D NMR distribution of the selected rock sample, indicating that the rock sample is saturated with water and the oil is displaced at the same time, that is, the water displaces the self-absorbed saturated oil occupying the water distribution area of ​​the original rock sample, that is, the water reoccupies the pore space that belongs to it, while the water cannot displace the oil in the pore space where the oil of the original rock sample is stored.

[0184] Water can displace oil in the water distribution area because the capillary surface tension of the water distribution area on water is greater than the surface tension of oil, that is, the capillary force of the water distribution area on water is greater than the capillary force on oil, and the capillary pores are hydrophilic. Water cannot displace oil in the oil distribution area because the capillary force of the oil distribution area on oil is greater than the capillary force on water, and the capillary pores are lipophilic. Such lipophilic and hydrophilic pores are called organic pores and inorganic pores, respectively. The lipophilic organic pores and hydrophilic inorganic pores can utilize the difference in their surface tension on oil and water, and recover by absorbing oil and water, thereby obtaining the pore size and distribution of organic pores and inorganic pores.

[0185] Combined with the conclusions from the oil-water distribution experiment, after removing pore water and oil from a rock sample, even if it is first saturated with water, water will not enter the pore spaces occupied by oil. This indicates that the rock sample can self-absorb saturated oil and water, with water only entering the pore spaces occupied by water and not the pores containing oil. In the absence of pore water in the rock sample, oil can enter both the pores occupied by the original rock sample's pore water and the pores containing oil, but water can displace oil from the pore spaces occupied by the original rock sample's pore water and not the pores containing oil. In the presence of pore water, oil can only enter the pores containing oil and cannot displace pores already occupied by water, meaning water can only enter the pores occupied by pore water. Therefore, pore properties can be used to restore the pore spaces occupied by oil and water in rock samples, enabling the determination of different pore properties and oil content.

[0186] Therefore, oil also has reproducibility, that is, oil can enter the pore space where oil is stored under the action of capillary forces.

[0187] Experiment to determine the distribution position of effective pore area and invalid pore area.

[0188] The rock samples were deoiled with alcohol-benzene solvent and dehumidified at 115℃ to constant weight. Two-dimensional nuclear magnetic resonance experiments were performed to obtain the T1-T2 distribution spectrum of solid or nearly solid hydrogen-containing substances such as crystal water or structural water, organic matter and asphaltene in clay minerals under deoiling and dehumidification conditions. Figure 6 Middle (a) has no reservoir properties and has no effect on the oil and water distribution in the reservoir. The pores it contains have no practical significance for oil and gas storage. It can locate the crystal water or structural water in clay minerals, organic matter, asphaltene and other solid or nearly solid hydrogen-containing substances. The area where the nuclear magnetic resonance signal is located in the T1-T2 two-dimensional nuclear magnetic resonance test spectrum is the invalid pore area.

[0189] The rock samples were deoiled with alcohol-benzene solvent and dehumidified to constant weight at 115℃. Then, the rock samples were saturated with oil and water and subjected to two-dimensional nuclear magnetic resonance T1-T2 combined determination. The nuclear magnetic resonance T1-T2 oil-water distribution spectrum was obtained as follows: Figure 6 (b) Figure 6 In (c), Figure 6 (b) Figure 6 (c) and Figure 6 Compared with (a), the newly appeared nuclear magnetic signals are oil and water. Oil, water and the pores in which they are stored are the main research objects of this application. The pores occupied by oil and water are the oil, gas and water storage spaces in the shale reservoir, and belong to the effective pore area.

[0190] Therefore, the T1-T2 distribution spectrum area of ​​solid or nearly solid hydrogen-containing substances such as crystal water or structural water in clay minerals, organic matter and asphaltene is determined to be the invalid pore distribution area, and the area where saturated oil and water are distributed is the effective pore distribution area.

[0191] The boundary between the invalid pore area and the valid pore area is divided in the T1-T2 combined measurement spectrum.

[0192] Specifically, in addition to the mobile pore water and nearly solid crystalline water, shale oil samples also contain clay-adsorbed water adsorbed on the surface of the clay layer. The mixing of different types of water will lead to a complex distribution of effective pore areas and invalid pore areas. The boundary between the effective pore area and the invalid pore area of ​​many samples is difficult to distinguish. In order to achieve the saturation calculation of the two-dimensional nuclear magnetic resonance method and accurately extract the data of the pore water corresponding to the spectrum, it is necessary to clarify the boundary between the effective pore area and the invalid pore area. Therefore, it is necessary to establish a set of applicable methods for dividing the effective pore area and the invalid pore area. The nuclear magnetic resonance T2 relaxation time has a corresponding relationship with the pore diameter of the sample, and the T2 relaxation time value can be used for division. The specific methods include:

[0193] On the basis of determining the distribution positions of the effective pore area and the invalid pore area, the abscissa of the weakest nuclear magnetic signal between the effective pore area and the invalid pore area in the two-dimensional nuclear magnetic spectrum is marked as a, and the straight line with the abscissa a is used as the dividing line between the effective pore area and the invalid pore area. The area less than or equal to the straight line a is the invalid pore area, and the area greater than the straight line a is the effective pore area.

[0194] There is no obvious weakest point of the nuclear magnetic signal between the effective pore area and the invalid pore area. In the T1-T2 rectangular coordinate system, T2≤0.2ms is selected as the invalid pore area, and T2>0.2ms is selected as the effective pore area. The oil and water distribution area division diagram of the shale sample two-dimensional nuclear magnetic test spectrum is shown in the figure below. Figure 9 As shown in (b), straight line A is the boundary between the ineffective pore area and the effective pore area.

[0195] When the spectrum NMR signals between the effective pore area and the invalid pore area are continuously free of NMR signals, that is, the NMR signals are all in the spectrum background area, the value of a is a=(a1+a2) / 2, where a1 is the T2 value of the left boundary of the continuous absence of NMR signals, and a2 is the T2 value of the right boundary of the continuous absence of NMR signals. Similarly, the straight line T2≤a ms is the invalid pore area, and T2>a ms is the effective pore area.

[0196] A large number of experiments have shown that under natural conditions, the areas corresponding to the two-dimensional nuclear magnetic resonance signals of solid or near-solid hydrogen-containing substances such as crystalline water or structural water, organic matter and asphaltene are mostly before T2=0.1ms, while the nuclear magnetic resonance signals of pore water are basically after T2=0.2ms. The boundary between the invalid pore area and the effective pore area is generally between T2=0.1ms and T2=0.2ms. The invalid pore area and the effective pore area of ​​the two-dimensional nuclear magnetic T1-T2 oil-water distribution spectrum of shale oil rock samples measured by equipment can be divided according to this method.

[0197] Boundary demarcation between water distribution and oil distribution.

[0198] Specifically, saturation calculation requires specific and accurate oil-water data. Reservoir oil and gas are very complex mixtures. The different properties of oil, gas and water compositions and the different occurrence states of oil and gas all affect the oil-water distribution in the two-dimensional nuclear magnetic resonance spectrum, resulting in unclear boundaries between water distribution and oil distribution. It is also necessary to establish an appropriate method for dividing water distribution areas and oil distribution areas. The interaction between different substances mainly affects the relaxation time T1 value, which can be used to divide the water distribution areas. The specific methods include:

[0199] Specifically, the vertical coordinate of the weakest nuclear magnetic signal between pore water and oil distribution is marked as b, and the straight line with the vertical coordinate b is used as the dividing line between the water distribution area and the oil distribution area in the effective pore area. Between the oil distribution area and the water distribution area, the area with a vertical coordinate greater than b is recorded as the oil distribution area, and the area with a vertical coordinate less than or equal to b is recorded as the water distribution area. The oil and water distribution area division diagram of the 2D nuclear magnetic spectrum of the shale sample is shown as follows Figure 9 As shown in (a), straight line B is the oil-water boundary.

[0200] When there is no obvious weakest point in the nuclear magnetic signal between pore water and oil, the area between the oil distribution area and the water distribution area with a vertical coordinate greater than 10ms is recorded as the oil distribution area, and the area with a vertical coordinate less than or equal to 10ms is recorded as the water distribution area. Figure 9 As shown in (c), straight line B is the oil-water boundary.

[0201] When there are continuous NMR signal-free areas between the pore water and oil distribution areas, the midline of the continuous NMR signal-free area is used as the dividing line of the oil-water partition, and the b value is b = (b1 + b2) / 2, where b1 is the lower boundary T1 value of the continuous NMR signal-free area and b2 is the upper boundary T1 value of the continuous NMR signal-free area. Similarly, between the oil distribution area and the water distribution area, the area with a vertical coordinate greater than b is recorded as the oil distribution area, and the area with a vertical coordinate less than or equal to b is recorded as the water distribution area. The oil-water distribution area division diagram of the 2D NMR test spectrum of shale samples is shown in the figure below. Figure 9 As shown in (b), straight line B is the oil-water boundary.

[0202] exist Figure 9 In the figure, a is the data boundary division diagram of the sample with obvious boundaries between effective pores and invalid pores and between oil and water distribution; b is the data boundary division diagram of the sample with unclear boundaries between effective pores and invalid pores and continuous no-signal between oil and water distribution; c is the data boundary division diagram with obvious boundaries between effective pores and invalid pores and unclear boundaries between oil and water distribution; 1 is the invalid pore area; 2 is the oil and water effective pore area; 3 is the pore water distribution area; 4 is the oil and gas distribution area; A is the boundary between invalid pores and effective pores; B is the oil and water distribution boundary.

[0203] At this point, the water distribution area and the oil distribution area are obtained.

[0204] Finally, the pore restoration of the rock samples was performed.

[0205] Since the saturation calculation requires not only the oil and water content data in the rock sample, but also the pore volume data of the rock sample, nuclear magnetic resonance measures the fluid in the pores and cannot measure the empty pores of the rock sample. Therefore, based on the pore property experiment, the pores of the rock sample need to be restored.

[0206] Specifically, based on the two-dimensional determination spectrum of residual oil and water in the rock sample, a qualitative analysis shows that when the water distribution is greater than the oil distribution, the rock sample is placed in a rock sample bottle filled with kerosene, so that it absorbs kerosene by itself. After the mass of the rock sample remains unchanged, the rock sample is placed in a constant humidity box with a humidity of not less than 85%, so that the rock sample absorbs water until the mass remains constant; when the water distribution is much smaller than the oil distribution, the rock sample is placed in a constant humidity box with a humidity of not less than 85%, so that the rock sample absorbs water by itself. After the mass remains constant, the rock sample is placed in a rock sample bottle filled with kerosene, so that the rock sample absorbs kerosene by itself until the mass remains unchanged; when the water distribution is the same as the oil distribution, the rock sample is placed in a rock sample bottle filled with kerosene, so that it absorbs kerosene by itself. After the mass of the rock sample remains unchanged, the rock sample is placed in a rock sample bottle filled with water, so that the rock sample absorbs water by itself until the mass remains unchanged.

[0207] It can be understood that the use of such a self-imbibition saturation method can shorten the self-imbibition saturation time of the rock sample.

[0208] The pore volume of rock samples was measured.

[0209] Two-dimensional nuclear magnetic resonance equipment is used to carry out T1-T2 joint measurement on rock samples that have been saturated with oil and water after self-imbibition, and two-dimensional nuclear magnetic resonance test data and maps are obtained.

[0210] According to the rock sample pore property experiment, after the rock sample is saturated with oil and water by self-absorption, water can only enter the pores where the original pore water is stored, that is, water can only enter the water-wet pores, and oil can only enter the pores of the oil-wet phase. When the self-absorption saturation mass is constant, the rock sample pores are completely saturated, and the sum of the measured oil and water volumes is the pore volume of the rock sample.

[0211] The two-dimensional nuclear magnetic resonance measurement after self-imbibition of oil and water can measure a water volume close to the water volume of the rock sample reservoir, and the measured oil volume is close to the oil and gas volume of the rock sample reservoir. Therefore, the oil and water saturation of the rock sample calculated by the oil and water volume after self-imbibition saturation is more accurate than the saturation calculated by using the oil and water volume before self-imbibition saturation, that is, higher than the residual oil and water saturation of the rock sample measured by two-dimensional nuclear magnetic resonance. This method is used for conventional coring to solve the problem of being unable to correct the rock sample after oil and gas are lost during the coring and drilling process.

[0212] Boundary division of oil and water distribution areas of measured shale samples:

[0213] The purpose of dividing the oil-water boundary of the measured sample is to accurately extract the oil-water data of the two-dimensional nuclear magnetic resonance spectrum for calculating the saturation. The specific method is:

[0214] The abscissa of the weakest nuclear magnetic signal between the effective pore area and the invalid pore area in the two-dimensional nuclear magnetic spectrum of the measured shale sample after oil and water absorption is marked as a, and the straight line with the abscissa a is used as the dividing line between the effective pore area and the invalid pore area. The straight line A with the abscissa a is the left boundary line of the water distribution area, and the straight line A is also the left boundary line of the oil distribution area.

[0215] The vertical coordinate of the weakest nuclear magnetic signal of the water distribution area and the oil distribution area in the two-dimensional nuclear magnetic spectrum of the rock sample after oil and water absorption is marked as b, and the straight line with the vertical coordinate b is used as the dividing line between the water distribution area and the oil distribution area. The upper side of the straight line B with the vertical coordinate b is the lower boundary line of the oil distribution area; the lower side of the straight line B is the upper boundary line of the water distribution area.

[0216] Other boundary lines for oil and water divisions, such as Figure 10 As shown, the lower boundary of the water data zone is defined as: A line perpendicular to the T1 axis, such as line C, is drawn outside the lower boundary of the water data zone (i.e., in the region without NMR signals). The T1 coordinate value is c. The right boundary of the water data zone is defined as: A line perpendicular to the T2 axis, such as line N, is drawn outside the right boundary of the water data zone. The T1 coordinate value is n. The right boundary of the oil data zone is defined as: A line perpendicular to the T2 axis, such as line M, is drawn outside the right boundary of the oil data zone. The T1 coordinate value is m. The upper boundary of the oil data zone is defined as: A line perpendicular to the T1 axis, such as line D, is drawn outside the upper boundary of the oil data zone. The T1 coordinate value is d.

[0217] The oil and water distribution area division diagram of the oil and water data extracted from the two-dimensional nuclear magnetic spectrum of shale samples is shown in Figure 10 As shown in the figure, Figure 10 In the figure, 1 is the invalid pore area; 2 is the effective oil-water pore area; 3 is the pore water distribution area; 4 is the oil and gas distribution area; A is the boundary between invalid pores and effective pores; B is the oil-water distribution boundary; C is an arbitrary perpendicular line from the lower edge of the water distribution area to the T1 axis; N is an arbitrary perpendicular line from the right edge of the water distribution area to the T2 axis; D is an arbitrary perpendicular line from the upper edge of the oil distribution area to the T1 axis; M is an arbitrary perpendicular line from the right edge of the oil distribution area to the T2 axis.

[0218] At this point, the effective pore area, ineffective pore area, water distribution area and oil distribution area are obtained.

[0219] Step S005: According to the values ​​of the nuclear magnetic signals measured in the water distribution area and the oil distribution area, the saturation calculation method of the two-dimensional nuclear magnetic method is used to obtain the oil and water saturation measurement result of the rock sample based on the nuclear magnetic technology.

[0220] Based on the values ​​of all NMR signals in the water distribution area and the oil distribution area, the water saturation determined by NMR and the oil saturation determined by NMR are calculated respectively.

[0221]

[0222]

[0223] Where S W1 Indicates water saturation determined by nuclear magnetic resonance; S W2 Indicates the oil saturation determined by nuclear magnetic resonance; k waterrepresents the conversion coefficient between the rock sample NMR signal and the water signal, and the value in this embodiment is 0.9213; M1 represents the cumulative sum of all NMR signals in the water distribution area; K oil represents the conversion coefficient between the rock sample NMR signal and the oil signal, and in this embodiment, the value is 1.2246; M2 represents the cumulative sum of all NMR signals in the oil distribution area.

[0224] The data table of water saturation measured by nuclear magnetic resonance and oil saturation measured by nuclear magnetic resonance corresponding to the seven rock samples in this application is shown in Table 2.

[0225] Table 2 Data of water saturation and oil saturation measured by nuclear magnetic resonance

[0226]

[0227] Table 2 shows the oil-water saturation data obtained using two-dimensional nuclear magnetic resonance (NMR) technology. These data are for seven samples measured using the method provided in this patent application. High-frequency two-dimensional NMR provides visualization of pore water and oil in shale oil rock samples. Analysis of the two-dimensional NMR T1-T2 oil-water distribution spectrum clearly reveals the distribution and properties of the measured oil and water, enabling the determination of pore conditions. Its accuracy surpasses that of other methods for determining oil-water saturation, achieving excellent results in practical applications and serving as essential data for studying the oil-water distribution characteristics of shale oil reservoirs.

[0228] At this point, the oil and water saturation determination results of the rock samples based on nuclear magnetic resonance technology are obtained.

[0229] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent replacements, improvements, etc. made within the principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology, characterized in that: The method comprises the following steps: Collect the volume, echo signal and signal-to-noise ratio of a preset number of rock samples; Any rock sample is recorded as a target rock sample, and all rock samples except the target rock sample are recorded as comparison rock samples. According to the frequency values ​​of the echo signals of the target rock sample and the comparison rock sample, the value range of the target frequency is defined, and the power spectrum and power spectrum density of the target rock sample and the comparison rock sample are obtained. According to the similarity between the power spectrum density of the target rock sample and the comparison rock sample, the difference between the power spectrum density, the distribution of the peak of the power spectrum and the difference in volume, the volume effect echo interference degree of the target rock sample is determined. According to the volume effect echo interference degree of all rock samples, the comprehensive interference degree of volume effect is determined. The noise amplification factor of the target echo signal is obtained by combining the peak distribution and peak value of the echo signal and the signal-to-noise ratio of the target rock sample; Determining an adjustment threshold of the target echo signal according to the target echo signal, the volume of the rock sample corresponding to the target echo signal, and the noise amplification factor of the echo signal; and obtaining a denoised target echo signal according to the determined adjustment threshold of the target echo signal; The rock samples are subjected to water value calibration, oil-water content calibration, water distribution experiments, oil distribution experiments, pore property characteristic experiments of naturally lost rock samples, pore property characteristic experiments of low-temperature water removal rock samples, and pore property characteristic experiments of low-temperature oil removal rock samples. The water distribution area and oil distribution area are determined, and two-dimensional nuclear magnetic resonance spectra are obtained respectively. The invalid pore area and the effective pore partition are divided according to the two-dimensional nuclear magnetic resonance spectra. The nuclear magnetic resonance signal boundary line between the effective pore area and the invalid pore area is divided. The boundary between the water distribution area and the oil distribution area in the effective pore partition is divided, and the pore restoration of the rock sample is performed; According to the values ​​of the nuclear magnetic signals measured in the water distribution area and the oil distribution area, the saturation calculation method of the two-dimensional nuclear magnetic method is used to obtain the oil and water saturation measurement results of the rock sample based on nuclear magnetic technology.

2. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The rock sample preparation method is as follows: Rock samples are collected at the pressure-maintaining core position of the shale oil reservoir in the exploration area. After the rock samples are lifted to the surface and out of the barrel through drilling, they are completely frozen and preserved in a freezer at a temperature of -40°C or less using freezing technology. The rock samples need to be completely frozen and are large flaky rock samples greater than or equal to 15 mm and less than or equal to 20 mm. The cutting tools should cut in a direction perpendicular to the bedding and bedding end face of the rock sample so that the rock sample geometry meets the test requirements and is frozen again to keep the rock sample in a frozen state.

3. The intelligent method for determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of defining the value range of the target frequency according to the frequency values ​​of the echo signals of the target rock sample and the comparison rock sample, and obtaining the power spectrum and power spectrum density of the target rock sample and the comparison rock sample includes the following specific methods: The echo signals of the target rock sample and the comparison rock sample are converted into frequency domain signals respectively using fast Fourier transform, and the power spectrum is plotted based on the frequency domain signals to obtain the power spectrum density; The minimum value of all frequency domain signals is recorded as the minimum frequency value, the maximum value of all frequency domain signals is recorded as the maximum frequency value, and all natural numbers greater than or equal to the minimum frequency value and less than or equal to the maximum frequency value are taken as the value range of the target frequency.

4. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of determining the volume effect echo interference degree of the target rock sample based on the similarity between the power spectrum density of the target rock sample and the comparison rock sample, the difference between the power spectrum density, the distribution of the peak value of the power spectrum graph, and the difference in volume includes the following specific methods: The absolute value of the Pearson correlation coefficient between the power spectrum density of the target rock sample and the comparison rock sample is recorded as the power spectrum correlation between the target rock sample and the comparison rock sample, and the average value of the power spectrum correlation between the target rock sample and all the comparison rock samples is recorded as the rock sample attribute similarity of the target rock sample; Obtain the peak values ​​of the power spectra of the target rock sample and the comparison rock sample respectively; record the minimum value of the absolute values ​​of the differences between the target frequency and all the peak values ​​of the target rock sample as the shortest frequency difference of the target rock sample at the target frequency; record the minimum value of the absolute values ​​of the differences between the target frequency and all the peak values ​​of the comparison rock sample as the shortest frequency difference of the comparison rock sample at the target frequency; at the target frequency, record the absolute value of the difference between the shortest frequency differences of the target rock sample and the comparison rock sample as the shortest frequency difference between the target rock sample and the comparison rock sample at the target frequency; record the average of the shortest frequency differences between the target rock sample and all the comparison rock samples at the target frequency as the first difference of the target rock sample at the target frequency; The absolute value of the difference between the power spectrum density of the target rock sample and the comparison rock sample at the target frequency is recorded as the power spectrum difference between the target rock sample and the comparison rock sample at the target frequency, and the average of the power spectrum differences between the target rock sample and all the comparison rock samples at the target frequency is recorded as the second difference of the target rock sample at the target frequency; The mean of the volumes of all comparison rock samples is recorded as the average volume of the comparison rock samples, and the absolute value of the difference between the volume of the target rock sample and the average volume of the comparison rock samples is recorded as the volume difference of the target rock sample; The volume effect echo interference degree of the target rock samples is determined based on the volume difference of the target rock samples, the similarity of the rock sample properties, and the first difference and the second difference of the target rock samples at the target frequency.

5. The intelligent method for determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 4, characterized in that: The method of determining the volume effect echo interference degree of the target rock sample based on the volume difference of the target rock sample, the similarity of the rock sample attributes, and the first difference and the second difference of the target rock sample at the target frequency includes the following specific methods: The product of the first difference and the second difference of the target rock sample at the target frequency is recorded as the third difference of the target rock sample at the target frequency, and the cumulative sum of the third differences corresponding to the values ​​of the target rock sample at all target frequencies is recorded as the fourth difference of the target rock sample; The product of the volume difference of the target rock sample and the fourth difference is recorded as the first product of the target rock sample, the difference between the number 1 and the rock sample attribute similarity of the target rock sample is recorded as the rock sample attribute difference degree of the target rock sample, and the product of the first product of the target rock sample and the rock sample attribute difference degree is recorded as the volume influence echo interference degree of the target rock sample.

6. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for obtaining the volume impact comprehensive interference degree is as follows: The cumulative sum of the volume-affected echo interference of all rock samples is recorded as the volume-affected comprehensive interference.

7. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of combining the peak distribution and peak value of the echo signal and the signal-to-noise ratio of the target rock sample to obtain the noise amplification factor of the target echo signal includes the following specific methods: The peak values ​​of the echo signal and the peak value of the signal-to-noise ratio of the target rock sample are obtained respectively, and the peak values ​​of the echo signal of the target rock sample are arranged in the order of the acquisition time of the peak values ​​to obtain an echo signal peak sequence; the peak values ​​of the signal-to-noise ratio of the target rock sample are arranged in the order of the acquisition time of the signal-to-noise ratio to obtain a signal-to-noise ratio peak sequence; the null hypothesis is set as no significant difference between the echo signal peak sequence and the signal-to-noise ratio peak sequence, and the alternative hypothesis is that there is a significant difference between the echo signal peak sequence and the signal-to-noise ratio peak sequence, and the t-test algorithm is used to calculate the p-value, and the p-value is recorded as the statistical significance of the target echo signal and the signal-to-noise ratio; The peak values ​​of the echo signals of the target rock samples are arranged in ascending order of peak values ​​to obtain an echo signal peak arrangement sequence; the peak values ​​of the signal-to-noise ratios of the target rock samples are arranged in ascending order of peak values ​​to obtain a signal-to-noise ratio peak arrangement sequence; the DTW distance between the echo signal peak arrangement sequence and the signal-to-noise ratio peak arrangement sequence is recorded as the time variation difference between the target echo signal and the signal-to-noise ratio; The noise amplification factor of the target echo signal is obtained based on the comprehensive interference of volume effect, the statistical significance of the target echo signal and the signal-to-noise ratio, and the time variation difference.

8. The intelligent method for determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 7, characterized in that: The noise amplification factor of the target echo signal is obtained according to the comprehensive interference degree of volume influence, the statistical significance of the target echo signal and the signal-to-noise ratio, and the time variation difference, including the specific method of: The normalized value of the product of the statistical significance of the target echo signal and the signal-to-noise ratio and the time variation difference is recorded as the second product of the target echo signal. The difference between the number 1 and the second product of the target echo signal is recorded as the third product of the target echo signal. The product of the volume impact comprehensive interference and the third product of the target echo signal is recorded as the noise amplification factor of the target echo signal.

9. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for determining the adjustment threshold of the target echo signal is: The volume of the rock sample is used as the independent variable, and the noise amplification factor of the echo signal corresponding to the rock sample is used as the dependent variable. A straight line is fitted between the independent variable and the dependent variable to obtain a fitting straight line, and the slope of the fitting straight line is recorded as the regression coefficient. Use the median absolute deviation (MAD) to obtain the noise level of the target echo signal; According to the regression coefficient and noise level of the target echo signal, the adjustment threshold of the target echo signal is determined. The calculation formula is: Where T represents the adjustment threshold of the target echo signal; tanh represents the hyperbolic tangent function; β1 represents the regression coefficient of the target echo signal; σ1 represents the first parameter adjustment coefficient; and σ represents the noise level of the target echo signal.

10. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of obtaining the denoised target echo signal based on the adjustment threshold of the target echo signal includes the following specific methods: The adjustment threshold of the target echo signal is used as the value of the soft threshold, and the echo signal of the rock sample is denoised using wavelet transform to obtain the denoised target echo signal.

11. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for calibrating the water value is: All seven rock samples were selected, and the moisture in the rock samples was removed at high temperature. Deionized water was dripped into each rock sample respectively. The amount of water dripped into the seven rock samples was 0.100ml, 0.200ml, 0.300ml, 0.400ml, 0.500ml, 0.700ml and 0.900ml respectively. Nuclear magnetic resonance T2 spectrum measurement was carried out on each rock sample to obtain two-dimensional nuclear magnetic measurement results.

12. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for calibrating the oil and water content is: All seven rock samples were selected, and a certain amount of kerosene was added to the rock sample test cups. The amounts of kerosene in the rock sample cups were 0.500ml, 1.000ml, 1.500ml, 2.000ml, 2.500ml, 3.000ml and 3.500ml respectively. Nuclear magnetic resonance (NMR) measurements were performed on each rock sample to obtain two-dimensional NMR measurement results.

13. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for determining the water distribution area is: Water distribution experiments were conducted on rock samples containing no hydrogen-bearing substances and rock samples containing solid or nearly solid hydrogen-bearing substances; The process of water distribution experiment for rock samples without hydrogen is as follows: Select any shale sample, place it in a 700℃ retort to remove hydrogen, and perform a two-dimensional nuclear magnetic resonance experiment until all hydrogen is removed. The rock sample is placed in a humidistat with a humidity of not less than 85% to absorb moisture. When the mass of the rock sample remains unchanged, a two-dimensional nuclear magnetic resonance experiment is carried out again to obtain the T1-T2 distribution spectrum and determine the water distribution area.

14. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The process of conducting water distribution experiments on rock samples containing solid or nearly solid hydrogen-containing substances is as follows: Select any shale sample, conduct 2D NMR measurement and obtain 2D NMR spectrum; The rock samples were placed in alcohol-benzene solvent for deoiling, and then dehumidified at 115°C until constant weight was reached. Two-dimensional nuclear magnetic resonance experiments were then performed to obtain the T1-T2 distribution spectrum under deoiling and dehumidification conditions. The rock sample is placed in a humidistat with a humidity of not less than 85% to absorb moisture, and after the mass is constant, it is subjected to two-dimensional nuclear magnetic resonance measurement again to obtain a two-dimensional nuclear magnetic spectrum saturated with water; The rock sample is smashed open and allowed to absorb moisture again. After the mass becomes constant, a two-dimensional nuclear magnetic resonance (NMR) measurement is performed to obtain a two-dimensional NMR spectrum of water absorption of the rock sample under conditions where cracks are generated by external force destruction.

15. The method for intelligently measuring oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for determining the oil distribution area is: Select any shale sample, deoil it with alcohol-benzene solvent, dehumidify it at 115℃, conduct a 2D NMR experiment, and obtain the 2D NMR spectrum of the sample under deoiling and dehumidification conditions; The rock sample is placed in an environment with a humidity of not less than 85% and absorbs water, and then subjected to two-dimensional nuclear magnetic resonance measurement to obtain a two-dimensional nuclear magnetic spectrum of the rock sample under water absorption conditions; The rock sample is immersed in kerosene and absorbs saturated kerosene. After the quality is stable, two-dimensional nuclear magnetic resonance measurement is carried out to obtain the two-dimensional nuclear magnetic spectrum of the rock sample under water and oil absorption conditions; The oil distribution area is determined based on the two-dimensional nuclear magnetic spectrum of the rock sample under oil and moisture removal conditions, the two-dimensional nuclear magnetic spectrum of the rock sample under water absorption conditions, and the two-dimensional nuclear magnetic spectrum of the rock sample under water and oil absorption conditions.

16. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of the pore property characteristic experiment of the naturally lost rock sample is: Two rock samples collected from the center of the pressure-maintained core of the shale oil reservoir were selected. After two-dimensional nuclear magnetic resonance measurement before they were completely thawed, the rock samples were placed in a rock sample bottle and thawed slowly under natural conditions. After the rock samples were completely thawed, they were placed in a vacuum low-temperature condition of 60°C for 8 hours to remove pore water, and two-dimensional nuclear magnetic resonance measurement was performed to obtain the two-dimensional nuclear magnetic spectrum of the rock sample; one of the dehydrated rock samples was placed under constant humidity conditions with a humidity greater than 85%, so that the rock sample was saturated with water by self-absorption. After the mass remained unchanged, the sample was placed in kerosene, so that it was saturated with kerosene by self-absorption. After the mass remained unchanged, two-dimensional nuclear magnetic resonance measurement was performed to obtain the two-dimensional nuclear magnetic spectrum of the rock sample; the other sample after low-temperature dehydration was first placed in kerosene, and then placed in constant humidity conditions with a humidity greater than or equal to 85%, so that the sample was saturated with kerosene and water respectively. After the mass remained unchanged, two-dimensional nuclear magnetic resonance measurement was performed on each sample to obtain the two-dimensional nuclear magnetic spectrum of the rock sample.

17. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of the low-temperature dewatering rock sample pore property characteristic experiment is: Select any rock sample, perform 2D NMR measurement, place the rock sample in a vacuum at 60°C for 8 hours, remove pore water, and perform 2D NMR analysis on the rock sample to obtain the T1-T2 distribution spectrum under the condition of removing pore water. The rock samples were placed under constant humidity conditions with a humidity greater than 85% to allow them to absorb saturated water. After their mass remained unchanged, two-dimensional nuclear magnetic resonance measurements were carried out to obtain the T1-T2 oil-water distribution spectrum under water absorption conditions. The two-dimensional nuclear magnetic resonance measurement data under different conditions were compared and analyzed to determine the reproducibility of pore water.

18. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method of the low-temperature deoiling rock sample pore property characteristic experiment is: A rock sample collected from the center of a pressure-maintained core in a shale oil reservoir was subjected to two-dimensional nuclear magnetic resonance (NMR) measurement. The sample was then deoiled and dehumidified using chloroform at 60°C for a period of no less than 70 hours. A two-dimensional nuclear magnetic resonance (NMR) experiment was then performed on the rock sample to obtain a two-dimensional NMR spectrum after deoiling and dehumidification. The rock sample is immersed in kerosene to make it absorb saturated kerosene. After the mass remains unchanged, a two-dimensional nuclear magnetic resonance experiment is carried out to obtain the two-dimensional nuclear magnetic spectrum under the saturated kerosene condition. The rock sample is placed under constant humidity conditions with a humidity greater than 85% to allow the rock sample to absorb saturated water and its mass to remain unchanged. Then, the rock sample is subjected to two-dimensional nuclear magnetic resonance measurement again to obtain a two-dimensional nuclear magnetic spectrum under the water absorption condition again.

19. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The specific method of dividing the ineffective pore area and the effective pore area according to the two-dimensional nuclear magnetic spectrum includes: The rock samples were deoiled with alcohol-benzene solvent and dehumidified at 115°C to constant weight. Two-dimensional nuclear magnetic resonance (NMR) experiments were then performed to obtain the T1-T2 distribution spectrum of solids or near-solid hydrogen-containing substances that could not be removed after deoiling and dehumidification. The samples were then saturated with oil and water, and after the mass was constant, two-dimensional nuclear magnetic resonance (NMR) measurements were performed to obtain the pore oil-water distribution spectrum. The area where the two-dimensional nuclear magnetic distribution spectrum of solid or nearly solid hydrogen-containing substances such as crystal water or structural water in clay minerals, organic matter and asphaltene is located is defined as the invalid pore distribution area, and the area composed of the self-absorption saturated water distribution area and the oil distribution area is recorded as the effective pore area.

20. The method for intelligently measuring oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The method for dividing the nuclear magnetic signal boundary line between the effective pore area and the invalid pore area is: The abscissa of the weakest nuclear magnetic signal between the effective pore area and the invalid pore area in the two-dimensional nuclear magnetic spectrum is marked as a, and the straight line with the abscissa a is used as the dividing line between the effective pore area and the invalid pore area. The area less than or equal to the straight line a is the invalid pore area, and the area greater than the straight line a is the effective pore area.

21. The method for intelligently measuring oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The boundary division method between the water distribution area and the oil distribution area in the effective pore partition is: The vertical coordinate of the weakest nuclear magnetic signal between the oil distribution area and the water distribution area in the effective pore area is marked as b, and the straight line with the vertical coordinate b is used as the dividing line between the oil distribution area and the water distribution area. Between the oil distribution area and the water distribution area, the area with a vertical coordinate greater than b is recorded as the oil distribution area, and the area less than or equal to b is recorded as the water distribution area.

22. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The specific method of restoring the pores of the rock sample includes: When the water distribution is greater than the oil distribution, place the rock sample in a rock sample bottle filled with kerosene to allow it to absorb the kerosene. After the rock sample mass remains constant, place the rock sample in a constant humidity chamber with a humidity of not less than 85% to allow the rock sample to absorb water until the mass remains constant. When the water distribution is much smaller than the oil distribution, place the rock sample in a constant humidity chamber with a humidity of not less than 85% to allow the rock sample to absorb water by itself until the mass becomes constant. Then place the rock sample in a rock sample bottle filled with kerosene to allow the rock sample to absorb kerosene by itself until the mass becomes constant. When the water distribution is the same as the oil distribution, place the rock sample in a rock sample bottle filled with kerosene to allow it to absorb the kerosene by itself. After the mass of the rock sample remains unchanged, place the rock sample in a constant humidity box with a humidity of not less than 85% to allow it to absorb water by itself until the mass remains unchanged.

23. The method for intelligently determining oil and water saturation of shale samples based on two-dimensional nuclear magnetic resonance technology according to claim 1, characterized in that: The saturation calculation method of the two-dimensional nuclear magnetic resonance method is used to calculate the value of the nuclear magnetic signal measured in the water distribution area and the oil distribution area. The calculation formula is: Where S W1 Indicates water saturation determined by nuclear magnetic resonance; S W2 Indicates the oil saturation determined by nuclear magnetic resonance; k water represents the conversion coefficient between rock sample NMR signal and water signal; M1 represents the cumulative sum of all NMR signals in the water distribution area; K oil It represents the conversion coefficient between rock sample NMR signal and oil signal; M2 represents the cumulative sum of all NMR signals in the oil distribution area.

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