A shale in-situ oil saturation determination device, method, and system

Abstract

This invention relates to the field of shale oil saturation determination, specifically to an apparatus, method, and system for in-situ shale oil saturation determination. The method includes: acquiring pressurized core samples, pore free water samples, and oil phase material samples from the target formation study area; evaluating the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of different volumes of each reference sample at different gains; obtaining the conversion coefficient of each reference sample at each gain based on the relationship between the NMR signal quantity and volume at the same gain, and determining the first optimal gain and the first optimal conversion coefficient for pore free water; determining the second optimal gain and the second optimal conversion coefficient for oil phase material samples based on the relationship between the maturity and conversion coefficient, thereby determining the oil saturation of the pressurized core sample. This invention improves the accuracy of in-situ shale oil saturation determination results.

Description

Technical Field

[0001] This invention relates to the field of shale oil saturation determination, specifically to an in-situ oil saturation determination device, method, and system for shale. Background Technology

[0002] Shale oil is an unconventional petroleum resource found in shale formations. Before shale oil extraction, it is usually necessary to determine the oil saturation of the in-situ oil in the shale formation to provide technical support for subsequent processing. Oil saturation is defined as the percentage of the oil phase volume in the pore space of a rock, that is, the ratio of the oil phase volume to the total pore volume of the rock. To accurately obtain the in-situ oil saturation index of shale formations, firstly, it is necessary to use core samples that maintain in-situ pressure in the shale formation as the research object to ensure that the obtained shale core samples can represent the oil, gas and water occurrence state of in-situ oil in the shale formation. Secondly, in the saturation calculation, it is necessary to accurately obtain the oil phase volume and the total pore volume of the rock in the shale core sample. The effective total pore volume of the shale core refers to the connected pore volume that allows fluid flow, including the oil phase volume and the pore free water volume of the shale core, but excluding the bound water volume in the shale core. Therefore, accurately obtaining the pore free water volume in the shale core sample is the key to determining the oil saturation of in-situ oil in shale formations.

[0003] Current methods for obtaining pore water volume in shale core samples typically employ core displacement, spontaneous adsorption, and water balance experiments to reduce the water content in the sample, making the water state in the sample close to the original reservoir state. Subsequently, reservoir physics (distillation extraction, dry distillation), thermal analysis (thermogravimetric analysis, differential thermal analysis), and nuclear magnetic resonance (NMR) are used to study the water content in the sample, thereby obtaining the pore water volume. However, while distillation extraction can extract water from the sample, it cannot accurately distinguish between bound water and free pore water. Dry distillation, although it can differentiate between free pore water and free pore water by analyzing the cumulative water content as temperature increases, is less effective. While bound water can be detected, it requires a large sample size and is not applicable to samples containing gypsum or montmorillonite. Thermal analysis can reflect the gradual removal of oil and water in different occurrence states as temperature increases, but shale composition is complex, and multiple thermal effects often overlap within the same temperature range, making it difficult to effectively evaluate the occurrence state of shale oil. Nuclear magnetic resonance (NMR) can distinguish the oil and water content in different pore sizes, but determining the occurrence state of oil and water depends on the resaturation of the washed and dried core. During the experiment, the pore structure of shale may change, resulting in low accuracy in obtaining the pore water volume in the shale core sample, which in turn affects the accuracy of the in-situ oil saturation measurement results. Summary of the Invention

[0004] To address the issue of low accuracy in existing methods for determining the in-situ oil saturation of shale, this invention aims to provide an apparatus, method, and system for determining the in-situ oil saturation of shale. The specific technical solution adopted is as follows:

[0005] In a first aspect, the present invention provides a method for in-situ determination of oil saturation in shale, the method comprising the following steps:

[0006] Obtain pressurized core samples and reference samples from the target stratigraphic study area. The reference samples include pore free water samples from the pressurized core samples and oil phase material samples from in-situ shale oil.

[0007] The amount of NMR signal for each reference sample at each gain is evaluated based on the NMR T2 spectra of each reference sample with different volumes at different gains.

[0008] Based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain, the conversion coefficient of each reference sample at each gain is obtained, and the first optimal gain and the first optimal conversion coefficient of pore free water are determined; based on the relationship between the maturity of oil phase material samples and the conversion coefficient, the second optimal gain and the second optimal conversion coefficient of oil phase material samples are determined.

[0009] By combining the first optimal gain, the first optimal conversion factor, the second optimal gain, the second optimal conversion factor, and the NMR signal quantity, the oil saturation of the pressure-held core sample was determined.

[0010] Preferably, after obtaining the NMR T2 spectra of each volume of reference sample, the method further includes:

[0011] The NMR T2 spectra of each volume reference sample were processed by wavelet denoising algorithm and baseline correction method based on polynomial fitting, respectively, to obtain the NMR T2 spectra of each volume reference sample after denoising and baseline correction.

[0012] Preferably, the step of evaluating the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of each reference sample of different volumes at different gains includes: using an NMR analyzer to obtain the NMR T2 spectra of each reference sample of each volume after denoising and baseline correction at each gain, and using these as the NMR signal quantity of each reference sample of each volume at each gain.

[0013] Preferably, obtaining the conversion coefficient of each reference sample at each gain based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain includes:

[0014] By combining the influence of the NMR signal of reference samples of different volumes at each gain on the correlation between the volume of the same type of reference sample and the NMR signal at the same gain, the data weight of reference samples of each volume at each gain is determined.

[0015] For any gain, a linear regression model is constructed based on the relationship between the volume of all reference samples in each reference sample and the amount of NMR signal under that any gain; based on the constructed linear model and the data weights, the conversion coefficient of each reference sample under that any gain is obtained.

[0016] Preferably, the determination of the data weight of each volume of reference sample at each gain, based on the influence of the correlation between the NMR signal quantity of reference samples of different volumes at each gain and the NMR signal quantity of the same type of reference sample volume at the same gain, includes:

[0017] For any gain, the peak position of the largest peak signal in the NMR T2 spectrum of the candidate sample after denoising and baseline correction is taken as the peak position of the NMR signal of the candidate sample under any gain; the candidate sample is any volume of any kind of reference sample.

[0018] The peak position consistency of the candidate sample under any gain is evaluated based on the distribution of the NMR signal peak positions of all reference samples of the same class under any gain.

[0019] Calculate the first Pearson correlation coefficient between the volume of all reference samples of the same class as the candidate sample and the NMR signal quantity at any given gain; calculate the second Pearson correlation coefficient between the volume of all other reference samples of the same class as the candidate sample and the NMR signal quantity at any given gain; based on the second Pearson correlation coefficient and the first Pearson correlation coefficient, obtain the degree of positive correlation enhancement of the candidate sample at any given gain; the degree of positive correlation enhancement of the candidate sample at any given gain characterizes the influence of the NMR signal quantity of the candidate sample at any given gain on the correlation between the volume of the same class of reference samples and the NMR signal quantity at any given gain;

[0020] By combining the peak position consistency and the positive correlation enhancement, the data weights of each reference sample of the same class under any given gain are determined.

[0021] Preferably, determining the data weights of each reference sample of the same class under any gain by combining the peak consistency and the positive correlation enhancement includes:

[0022] Based on the peak position consistency and the positive correlation enhancement, the data confidence of the candidate sample under any given gain is obtained;

[0023] Based on the data confidence of all reference samples of the same class under any given gain, the data weights of each reference sample of the same class under any given gain are obtained, wherein the sum of the data weights of all reference samples of the same class under any given gain is 1.

[0024] Preferably, determining the first optimal gain and the first optimal conversion factor for pore free water includes:

[0025] Based on the conversion coefficient of each pore free water sample at different gains, the NMR volume of each pore free water sample at different gains was obtained.

[0026] The volume of all pore free water samples and the NMR signal at the same gain were used as inputs to the linear regression model. The volume of pore free water samples and the NMR volume were used as the X and Y variables of the linear regression model, respectively. The linear regression model was used to establish the linear regression model of the volume of pore free water samples and their NMR volume at each gain.

[0027] The gain corresponding to the maximum goodness of fit of the linear regression model of the volume of the pore free water sample and its NMR volume under all gains is determined as the first optimal gain for pore free water.

[0028] The conversion coefficient corresponding to the pore free water sample under the first optimal gain is taken as the first optimal conversion coefficient.

[0029] Preferably, determining the second optimal gain and second optimal conversion coefficient of the oil phase material sample based on the relationship between the maturity of the oil phase material sample and the conversion coefficient includes:

[0030] Based on the NMR signal quantity and corresponding conversion coefficient of the oil phase material sample, calculate the NMR volume of the oil phase material sample at each gain for each maturity level and each volume.

[0031] Based on the actual volume and NMR volume of all oil phase material samples under each maturity and each gain, a linear regression fitting model between the NMR volume and the actual volume of all oil phase material samples under each maturity and each gain is established, where the NMR volume and the actual volume are the X variable and the Y variable, respectively. The slope of the linear regression model constructed under each maturity and each gain is recorded as the crude oil NMR volume correction coefficient of the oil phase material sample under each maturity and each gain.

[0032] Based on the maturity of all oil phase material samples and the crude oil NMR volume correction coefficient under each gain, a linear regression model between the maturity of crude oil samples and the crude oil NMR volume correction coefficient under each gain is established. Maturity and crude oil NMR volume correction coefficient are used as X variables and Y variables, respectively. The gain corresponding to the linear regression model with the highest goodness of fit among all the established linear regression models under all gains is taken as the optimal gain of crude oil samples, denoted as the second optimal gain. The conversion coefficient of oil phase material samples under the second optimal gain is taken as the optimal conversion coefficient of oil phase material samples, denoted as the second optimal conversion coefficient.

[0033] Preferably, the step of determining the oil saturation of the pressure-held core sample by combining the first optimal gain, the first optimal conversion coefficient, the second optimal gain, the second optimal conversion coefficient, and the NMR signal quantity includes:

[0034] After the frozen and pressurized core samples were taken out of liquid nitrogen, the core samples were placed in a sealed test bottle for thawing using the optimal thawing time. The thawed core samples were then subjected to two-dimensional nuclear magnetic resonance (NMR) testing to obtain the NMR T2 spectrum before vacuum heating.

[0035] Using the NMR signal quantity of water in the NMR T2 spectrum of the pressure-maintained core sample at the first optimal gain and the first optimal gain, the actual volume of water corresponding to the NMR signal quantity of water is calculated and recorded as the first water-bearing volume.

[0036] Vacuum heating was performed on the pressurized core sample, and two-dimensional nuclear magnetic resonance (NMR) testing was conducted on the pressurized core sample after vacuum heating. The NMR signal of water in the NMR T2 spectrum after vacuum heating was extracted, and the actual volume of water corresponding to the NMR signal of water was calculated using the first optimal conversion coefficient based on the NMR signal of water after vacuum heating, and recorded as the second water-bearing volume.

[0037] Obtain the maturity of the pressurized core sample and the crude oil NMR volume correction coefficient of the oil phase material at the second optimal gain and each maturity level; calculate the oil phase volume in the pressurized core sample based on the crude oil NMR volume correction coefficient and NMR volume of the oil phase material at the second optimal gain and maturity level of the pressurized core sample after vacuum heating.

[0038] The oil saturation of the pressure-maintained core sample is determined by combining the first water-bearing volume, the second water-bearing volume, and the oil phase volume.

[0039] Preferably, determining the oil saturation of the pressurized core sample by combining the first water-bearing volume, the second water-bearing volume, and the oil phase volume includes:

[0040] The absolute value of the difference between the first water-bearing volume and the second water-bearing volume is taken as the free water volume of shale pore water in the pressurized core sample.

[0041] Calculate the sum of the free water volume in the shale pores and the oil phase volume;

[0042] The ratio between the free water volume in the shale pores and the sum value is determined as the oil saturation of the pressure-maintained core sample.

[0043] Preferably, the step of constructing a linear regression model based on the relationship between the volume of all reference samples in each reference sample and the NMR signal quantity at any given gain; and obtaining the conversion coefficient of each reference sample at any given gain based on the constructed linear model and the data weights, includes:

[0044] The volume of all reference samples in each type of reference sample and the NMR signal quantity at any given gain are used as inputs to the linear regression model. The NMR signal quantity and volume are used as the X and Y variables of the linear regression model, respectively. The parameters in the linear regression model are estimated using the weighted least squares method. The data weights of each reference sample at any given gain are used as the weights of the corresponding data points in the weighted least squares method. The slope of the output linear regression equation is used as the conversion coefficient of each reference sample at any given gain.

[0045] Preferably, evaluating the peak position consistency of the candidate sample under any gain based on the distribution of NMR signal peak positions of all reference samples of the same class under any gain includes:

[0046] The abscissa difference between the peak position of the NMR signal of the candidate sample at any gain and the peak position of the NMR signal of each other reference sample of the same class at any gain is obtained, and the mean of all the abscissa differences corresponding to the candidate sample at any gain is taken as the peak position consistency of the candidate sample at any gain.

[0047] Preferably, obtaining the degree of positive correlation enhancement of the candidate sample under any gain based on the second Pearson correlation coefficient and the first Pearson correlation coefficient includes: determining the difference between the second Pearson correlation coefficient and the first Pearson correlation coefficient as the degree of positive correlation enhancement of the candidate sample under any gain.

[0048] Preferably, obtaining the data confidence of the candidate sample under any gain based on the peak consistency and the positive correlation enhancement includes: using the product of the normalized value of the peak consistency and the normalized value of the positive correlation enhancement as the data confidence of the candidate sample under any gain.

[0049] In a second aspect, the present invention provides an in-situ oil saturation measuring device for shale, which is used to implement the method of the first aspect, the device comprising:

[0050] The sample acquisition module is used to acquire pressurized core samples and reference samples from the target stratigraphic study area. The reference samples include pore free water samples from the pressurized core samples and oil phase material samples from shale in-situ oil.

[0051] The NMR signal acquisition module is used to evaluate the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of each reference sample at different volumes in each reference sample at different gains.

[0052] The conversion coefficient determination module is used to obtain the conversion coefficient of each reference sample at each gain based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain, and to determine the first optimal gain and the first optimal conversion coefficient of pore free water; and to determine the second optimal gain and the second optimal conversion coefficient of oil phase material samples based on the relationship between the maturity of oil phase material samples and the conversion coefficient.

[0053] The saturation determination module is used to determine the oil saturation of the pressure-held core sample by combining the first optimal gain, the first optimal conversion coefficient, the second optimal gain, the second optimal conversion coefficient, and the NMR signal quantity.

[0054] Thirdly, the present invention provides a shale in-situ oil saturation measurement system for storing a computer program, the computer program causing the computer to execute the method of the first aspect.

[0055] The present invention has at least the following beneficial effects:

[0056] 1. This invention analyzes the impact of noise interference and baseline drift on the NMR T2 spectra of different types of reference samples when obtaining conversion coefficients that reflect the conversion relationship between the NMR signal quantity and the actual volume of water in actual pressurized core samples. It determines the conversion coefficient for each reference sample at each gain, effectively reducing the impact of pore free water samples, which are significantly affected by noise interference and baseline drift, on the accuracy of the final calculated conversion coefficients. Based on the NMR signal quantities obtained from the conversion coefficients of pore free water samples of different volumes at different gains, the optimal conversion coefficient and optimal gain that better reflect the conversion relationship between the NMR signal quantity and the actual volume of water in actual pressurized core samples are selected. This improves the accuracy of subsequent oil-water occurrence state discrimination in samples, thus providing more accurate key parameters for subsequent in-situ shale oil saturation determination, enhancing the accuracy of shale in-situ oil saturation determination results, and providing more reliable data support for subsequent exploration and development decisions.

[0057] 2. In obtaining the conversion coefficient that reflects the conversion relationship between the NMR signal quantity of oil phase material in the actual pressurized core sample and its actual volume, this invention uses the NMR signal quantities obtained from crude oil samples of different volumes and maturity at different gains to screen out the optimal conversion coefficient and optimal gain that better reflect the conversion relationship between the NMR signal quantity of oil phase material in the actual pressurized core sample and its actual volume. This improves the accuracy of subsequent calculation results and provides more accurate key parameters for the subsequent determination of shale in-situ oil saturation, thereby obtaining more accurate results for the determination of shale in-situ oil saturation. Attached Figure Description

[0058] To more clearly illustrate the technical solutions and advantages in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0059] Figure 1 This is a flowchart of a method for determining the in-situ oil saturation of shale provided in an embodiment of the present invention;

[0060] Figure 2 This is a structural block diagram of a shale in-situ oil saturation measuring device provided in an embodiment of the present invention;

[0061] Figure 3 The image shows a two-dimensional nuclear magnetic resonance (NMR) image of a cryopreserved, pressurized shale core sample thawed at 4 minutes, as provided in an embodiment of the present invention.

[0062] Figure 4This is a two-dimensional nuclear magnetic resonance (NMR) image of a cryopreserved, pressurized shale core sample thawed for 10 minutes, as provided in an embodiment of the present invention.

[0063] Figure 5 This is a two-dimensional nuclear magnetic resonance (NMR) image of a cryopreserved, pressurized shale core sample thawed for 20 minutes, as provided in an embodiment of the present invention.

[0064] Figure 6 This is a two-dimensional NMR monitoring image of a cryopreserved, pressurized shale core sample after thawing and loss, provided in an embodiment of the present invention.

[0065] Figure 7 Scanning electron microscope (SEM) images of shale core samples with pressure retention provided in this embodiment of the invention at different temperatures;

[0066] Figure 8 A characteristic diagram of the variation of the T2 NMR spectrum of a water-bearing shale at a vacuum temperature of 40°C, provided for an embodiment of the present invention;

[0067] Figure 9 This is another characteristic diagram of the T2 NMR spectrum variation of shale water-bearing material at a vacuum temperature of 40°C provided in an embodiment of the present invention;

[0068] Figure 10 A characteristic diagram of the variation of the T2 NMR spectrum of a water-bearing shale at a vacuum temperature of 50°C, provided for an embodiment of the present invention;

[0069] Figure 11 This is another characteristic diagram of the T2 NMR spectrum variation of shale water-bearing material at a vacuum temperature of 50°C provided in an embodiment of the present invention;

[0070] Figure 12 A characteristic diagram of the variation of the T2 NMR spectrum of a water-bearing shale at a vacuum temperature of 60°C, provided for an embodiment of the present invention;

[0071] Figure 13 This is another characteristic diagram of the T2 NMR spectrum variation of shale water-bearing material at a vacuum temperature of 60°C, provided as an embodiment of the present invention. Detailed Implementation

[0072] To further illustrate the technical means and effects of the present invention in achieving its intended purpose, the following detailed description, in conjunction with the accompanying drawings and preferred embodiments, describes a shale in-situ oil saturation measuring device, method, and system proposed according to the present invention.

[0073] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0074] The following description, in conjunction with the accompanying drawings, details the specific scheme of the shale in-situ oil saturation determination device, method, and system provided by the present invention.

[0075] Example of an in-situ method for determining oil saturation in shale:

[0076] The specific scenario addressed in this embodiment is as follows: When measuring the in-situ oil saturation of shale, based on the relationship between the NMR signal quantity and gain of each reference sample at the same gain, the optimal gain and optimal conversion coefficient of pore free water, as well as the optimal gain and optimal conversion coefficient of oil phase material sample, are obtained respectively. Using these two optimal gains and two optimal conversion coefficients, the water volume of the pressurized core sample before vacuum heating and after vacuum heating, as well as the oil phase volume in the pressurized core sample, are determined, thereby realizing the measurement of in-situ oil saturation of shale.

[0077] This embodiment proposes a method for in-situ determination of oil saturation in shale, such as... Figure 1 As shown, the method for determining the in-situ oil saturation of shale in this embodiment includes the following steps:

[0078] Step S1: Obtain pressurized core samples and reference samples from the target stratigraphic study area. The reference samples include pore free water samples from the pressurized core samples and oil phase material samples from in-situ shale oil.

[0079] First, shale core samples from the target stratigraphic study area were obtained using a pressure-holding core sampling method to ensure that the oil, gas, and water in the shale core samples were not lost, thus guaranteeing that the obtained shale core samples could represent the oil, gas, and water occurrence state of the in-situ shale oil in the target stratigraphic study area. After the pressure-holding core cylinder was lifted to the surface and removed from the cylinder, it was quickly placed into an ultra-low temperature freezing device, sealed with a threaded cap, and liquid nitrogen was connected to the liquid nitrogen injection end of the ultra-low temperature freezing device of the pressure-holding core cylinder through a dedicated pipeline for ultra-low temperature freezing treatment for at least 4 hours. After steps such as inner cylinder cutting and milling, removal of sealing liquid, and sample freezing and cutting, the obtained shale core samples were cut into long sections. Width Gao Wei The block-shaped sample, with a specific size that can fit into a two-dimensional NMR test bottle, is used to prepare shale pressurized core samples. The entire process of preparing shale pressurized core samples must be carried out in a liquid nitrogen cryogenic environment to ensure that no fluid is lost from the obtained shale pressurized core samples.

[0080] Multiple parallel samples were prepared for the shale core samples with pressure retention, and the prepared shale core samples and their parallel samples were cryopreserved in a liquid nitrogen environment.

[0081] Obtain any one parallel sample from the cryopreserved pressurized shale core samples. Place the obtained parallel sample in a sealed test bottle for thawing. Perform NMR T2 spectroscopy on the thawing parallel sample to obtain two-dimensional NMR spectra at different thawing times. Monitor the changes in fluid content in the parallel sample based on the obtained two-dimensional NMR spectra. The thawing time corresponding to the parallel sample reaching its maximum fluid content is taken as the optimal thawing time for the current batch of pressurized core samples. Figures 3-6 As shown, two-dimensional NMR spectra of cryopreserved pressurized shale core samples are displayed at thawing times of 4 minutes, 10 minutes, 20 minutes, and after thawing and loss of samples.

[0082] Considering that 2D NMR monitoring can detect changes in moisture content in shale, but at lower temperatures, shale pore water, which relies on capillary force, weakly bound water, and free water, will lose water relatively quickly. Shale bound water, which has polar water molecules adsorbed on the surface and lattice of clay minerals in shale, is not easily lost. Furthermore, vacuum conditions can lower the boiling point of water. Therefore, this embodiment uses appropriate vacuum pressure and heating temperature to perform vacuum heating treatment on pressurized core samples. This allows only the shale pore water in the sample to be lost during vacuum heating treatment, while retaining the shale bound water and ensuring that the shale pore structure of the sample is not damaged. By monitoring the changes in moisture content in the sample during vacuum heating treatment using 2D NMR, it is possible to determine whether the oil-water state of the sample has reached a saturated oil-bound water state after vacuum heating treatment. This improves the accuracy of subsequently obtaining the volume of pore free water in the sample, thereby enabling a more accurate determination of the oil saturation of in-situ shale oil in the target stratum study area.

[0083] As a specific example, for any parallel sample of a cryopreserved, pressurized shale core, the parallel sample is placed in a sealed test bottle for thawing using the optimal thawing time. The thawed parallel sample is then analyzed using scanning electron microscopy (SEM). The region containing the marker mineral within the field of view is selected as the marker mineral region for imaging. This is used to monitor changes in the shale pore structure when the parallel sample is subsequently heated. In this embodiment, two quartz minerals within the field of view are selected as marker minerals. The parallel sample is heated at an initial temperature of 40°C, with subsequent heating at 10°C intervals for 8 hours, until reaching 80°C. The marker mineral region of the parallel sample at each heating temperature is then imaged using SEM, resulting in SEM images of the parallel sample at different heating temperatures. The mineral regions of the parallel samples can be manually marked. Figure 7 As shown in the figure, this image displays scanning electron microscope (SEM) images of shale core samples under pressure at different temperatures.

[0084] The heating temperature at which the shale pore structure in the parallel samples begins to change is obtained by analyzing scanning electron microscope (SEM) images of parallel samples at different heating temperatures. This value is recorded as the critical temperature for the current batch of pressurized core samples and is used as the critical temperature for subsequent vacuum heating treatment of the current batch of pressurized core samples to prevent changes in the shale pore structure during vacuum heating. Since significant changes in shale pore structure occur after 50°C, the critical temperature is set at 50°C in this embodiment. Other implementation methods can be determined according to specific circumstances. Whether the shale pore structure in the parallel samples begins to change is determined by a professional through observation.

[0085] Based on the critical temperature value of the current batch of pressurized core samples and the boiling point temperature of water under different vacuum pressures, the critical vacuum pressure value for vacuum heating treatment of the pressurized core samples is obtained, and the obtained critical vacuum pressure value is recorded as the critical vacuum pressure value of the current batch of pressurized core samples, so that the boiling point temperature of water under the critical vacuum pressure value does not reach the critical temperature value. In this embodiment, the critical vacuum pressure value is -90 kPa. When the pressurized core samples are vacuum heated using the critical vacuum pressure value and the boiling point temperature of water under the pressure value, the pore free water in the pressurized core samples vaporizes because the heating temperature reaches its boiling point temperature condition, while the shale bound water in the pressurized core samples is retained because the heating temperature does not reach its overflow temperature, and the pore structure of the pressurized core samples is not destroyed because the heating temperature does not reach the critical temperature value.

[0086] Using pore free water from pressurized core samples as one type of reference sample, and oil phase material from in-situ shale oil as another type of reference sample, this embodiment uses two types of reference samples. Oil phase material of different maturity levels and volumes from in-situ shale oil in the target formation study area is obtained. Different maturity levels can be 0.75%, 0.95%, 1.20%, 1.30%, 1.40%, and 1.60%, and different volumes can be 0.1 ml, 0.2 ml, 0.3 ml, 0.4 ml, and 0.5 ml. Similarly, pore free water samples of different volumes are also obtained, for example, 0.1 ml, 0.2 ml, 0.3 ml, 0.4 ml, and 0.5 ml. In specific applications, the implementer can set the reference sample volume according to specific circumstances. The oil phase material can be separated from parallel samples of pressurized core shale samples using experimental methods.

[0087] Through the above steps, pressurized core samples, pore free water samples of different volumes, oil phase material samples of different volumes and maturity levels from the target stratum study area were obtained, along with the optimal thawing time and critical temperature values, which will be used for subsequent determination of the in-situ oil saturation of shale.

[0088] Step S2: Evaluate the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of each reference sample with different volumes at different gains.

[0089] When using two-dimensional nuclear magnetic resonance (NMR) to monitor the changes in water content in pressurized core samples during vacuum heating to determine whether the oil-water state of the sample has reached saturated oil-bound water, and subsequently to calculate the volume of free water in shale pores based on the changes in water volume before and after vacuum heating, the accuracy of determining the saturated oil-bound water state and calculating the volume of free water in shale pores both depend on the accuracy of the conversion coefficient between the NMR signal of water in the actual pressurized core sample and the actual volume of water. However, the acquired NMR echo data is usually affected by noise interference and instrument baseline drift, which introduces incorrect information into the NMR signal of pure water samples of different volumes. As a result, the final conversion coefficient cannot accurately reflect the conversion relationship between the NMR signal of water in the actual pressurized core sample and the actual volume of water. Therefore, in order to improve the accuracy of the final conversion relationship, the following processing is performed in this embodiment.

[0090] The following embodiment uses a pure water sample as an example for explanation. The method provided in this embodiment can also be used to process oil phase samples.

[0091] Two-dimensional NMR spectroscopy was performed on multiple porous free water samples of different volumes. The NMR T2 spectra of each porous free water sample were obtained at different gains. In this embodiment, the echo interval was less than 0.1 ms and the number of scans was at least 8 in all the test parameters used in the two-dimensional NMR tests. The time should be no less than 30ms, ensuring that the time for each NMR test is less than five minutes, and the signal-to-noise ratio is greater than 200. This represents the relaxation time corresponding to the maximum porosity. Two-dimensional NMR testing and one-dimensional inversion are existing technologies, and the specific process will not be described in detail.

[0092] Because the echo signal generated by NMR has a relatively low amplitude, it is easily affected by noise interference, and the acquired echo data is also susceptible to instrument baseline drift. This noise interference and baseline drift also affect the NMR T2 spectra obtained after inversion. Therefore, to reduce the impact of noise interference and baseline drift on the extraction of the NMR signal intensity of the corresponding peak signals in the respective NMR T2 spectra of pure water samples of different volumes, wavelet denoising algorithm and polynomial fitting-based baseline correction method are used to process the NMR T2 spectra of each pore free water sample sequentially, obtaining the NMR T2 spectra of each pore free water sample after denoising and baseline correction. The wavelet denoising algorithm and the polynomial fitting-based baseline correction method are both well-known techniques, and their specific processes will not be elaborated further.

[0093] The following explanation uses a reference sample of any volume from any type of reference sample as an example. Other reference samples can be processed using the method provided in this embodiment.

[0094] Specifically, any volume of a reference sample from any type of reference sample is designated as a candidate sample. For gain G, a Gaussian-fit-based peak-finding algorithm is used to extract the peak position of the largest peak signal in the NMR T2 spectrum of the candidate sample after denoising and baseline correction under gain G. This peak position is recorded as the NMR signal peak position of the candidate sample under gain G. An NMR analyzer is then used to obtain the corresponding NMR signal quantity of the candidate sample after denoising and baseline correction under gain G, which is recorded as the NMR signal quantity of the candidate sample under gain G. The Gaussian-fit-based peak-finding algorithm is a well-known technique, and its specific process will not be elaborated further.

[0095] Using the above methods, we can obtain the NMR signal quantity of each reference sample in each type of reference sample at each gain.

[0096] Step S3: Based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain, obtain the conversion coefficient of each reference sample at each gain, and determine the first optimal gain and the first optimal conversion coefficient of pore free water; based on the relationship between the maturity of the oil phase sample and the conversion coefficient, determine the second optimal gain and the second optimal conversion coefficient of the oil phase sample.

[0097] Considering that denoising and baseline correction cannot completely eliminate the influence of noise and baseline drift on the NMR data of each pore free water sample at the same gain in the NMR T2 spectrum, the following processing is performed to accurately evaluate the influence of residual noise interference and baseline drift in the NMR T2 spectrum on the NMR signal of each pore free water sample in its respective NMR T2 spectrum. This is to reduce the impact of pore free water samples that are greatly affected by residual noise interference and baseline drift on the accuracy of the conversion coefficient when using the NMR signal of the peak signal to obtain the conversion coefficient of pore free water at each gain.

[0098] Under the same NMR testing environment, the same substance generally has the same peak signal position in the NMR T2 spectrum, and the NMR signal intensity of the peak signal is usually proportional to the amount of hydrogen-containing substance. However, noise interference and baseline drift in the NMR T2 spectrum can cause the peak position and NMR signal intensity of the corresponding spectral signal to deviate from their true values. This embodiment evaluates the consistency between each reference sample and other reference samples of the same class based on the peak position, volume, and NMR signal intensity of each reference sample, and assesses the impact of using the NMR signal intensity of a single reference sample to measure the correlation between the volume and NMR signal intensity of the same class of reference samples. Based on these two evaluation results, different weights are assigned to different reference samples to remove the influence of residual noise interference and baseline drift on the NMR data in the NMR T2 spectrum after denoising and baseline correction, thereby improving the accuracy of subsequent analysis results.

[0099] The following explanation uses the candidate sample as an example. Specifically, for gain G, the abscissa difference between the NMR signal peak position of the candidate sample under gain G and the NMR signal peak position of each other reference sample in the same class under gain G is obtained. The average of all abscissa differences obtained at this time is taken as the peak position consistency of the candidate sample under gain G. The peak position consistency of the candidate sample under gain G is used to characterize the consistency of the NMR signal peak position between the candidate sample and all other samples in the same class under gain G. The greater the peak position consistency, the less the NMR data in the NMR T2 spectrum of the candidate sample after denoising and baseline correction under gain G is affected by residual noise interference and baseline drift. The method for obtaining the abscissa difference between NMR signal peak positions is as follows: calculate the absolute value of the difference between the abscissas of two NMR signal peak positions, and take this absolute value as the abscissa difference between the NMR signal peak positions.

[0100] The Pearson correlation coefficient between the volume of all reference samples of the same class as the candidate sample and the NMR signal quantity at gain G is calculated, and this Pearson correlation coefficient is denoted as the first Pearson correlation coefficient. The Pearson correlation coefficient between the volume of all other reference samples of the same class as the candidate sample and the NMR signal quantity at gain G is also calculated, and this Pearson correlation coefficient is denoted as the second Pearson correlation coefficient. The first and second Pearson correlation coefficients are used to characterize the correlation between the sample volume and the NMR signal quantity at gain G. The method for calculating the Pearson correlation coefficient is existing technology and will not be elaborated further here.

[0101] The difference between the second Pearson correlation coefficient and the first Pearson correlation coefficient is taken as the positive correlation enhancement of the candidate sample under gain G. The positive correlation enhancement is used to evaluate the degree of improvement of the positive correlation result when using the NMR signal of the candidate sample under gain G to measure the positive correlation between the volume of the reference sample of the same class and the NMR signal under gain G. The greater the positive correlation enhancement, the better the NMR signal of the candidate sample under gain G can reflect the positive correlation between its volume and its NMR signal. At this time, the NMR data in the NMR T2 spectrum of the candidate sample after denoising and baseline correction under gain G is less affected by its residual noise interference and baseline drift.

[0102] The peak consistency and positive correlation enhancement of the candidate samples under gain G are normalized to obtain normalized values ​​for peak consistency and positive correlation enhancement, so as to eliminate the influence of data dimensions, and the values ​​of peak consistency and positive correlation enhancement are mapped to the range of [0, 1]. In this embodiment, the maximum and minimum value normalization method is used when normalizing peak consistency and positive correlation enhancement. The maximum and minimum value normalization method is the prior art and will not be described in detail here.

[0103] The product of the normalized value of the peak consistency of the candidate sample under gain G and the normalized value of the positive correlation enhancement is used as the data confidence of the candidate sample under gain G. The data confidence is used to evaluate whether the corresponding NMR signal quantity in the NMR T2 spectrum of the candidate sample under gain G after denoising and baseline correction is closer to its true value. The higher the data confidence, the closer it is to the true value. When using the NMR signal quantities of all samples of the same class as the candidate sample to obtain the conversion coefficient, the weight of the NMR signal quantity of the candidate sample should be greater.

[0104] Using the above method, we can obtain the data confidence level of all reference samples in each class at gain G.

[0105] Furthermore, based on the data confidence scores of all reference samples in the same class under gain G, the data weights of each reference sample in the same class under gain G are obtained. Specifically, the Softmax function is used to process the data confidence scores of all reference samples in the same class under gain G, mapping the Softmax function processing result of the data confidence scores to the range of 0-1, and ensuring that the sum of the Softmax function processing results of the data confidence scores of all reference samples in the same class under gain G is 1. Taking candidate samples as an example, the Softmax function processing result of the candidate sample's data confidence scores under gain G is used as the candidate sample's data weight under gain G. Through the above method, the data weights of each reference sample in each class under each gain can be obtained.

[0106] Since the amount of NMR signal is usually proportional to the amount of hydrogen-containing material, for gain G, the volume and NMR volume of all porous free water samples are used as inputs to a linear regression model. The volume and NMR volume are used as the X and Y variables, respectively, to establish linear regression models for the volume of porous free water samples and their NMR volumes under gain G. Through this method, linear regression models for the volume of porous free water samples and their NMR volumes under each gain can be obtained, with one corresponding linear regression model for each gain.

[0107] Since the gain in two-dimensional NMR testing also affects the accuracy of the NMR signal, and thus the accuracy of the conversion coefficient between the NMR signal of the reference sample and its actual volume, this embodiment obtains pure water samples of different volumes. It uses the NMR signal obtained by the conversion coefficient of the reference sample at each gain and the NMR signal calculated by the conversion coefficient of the NMR signal at each gain to verify the accuracy of the conversion coefficient at each gain. This allows for the selection of a conversion coefficient that better reflects the conversion relationship between the NMR signal of water and the actual volume of water in the actual pressurized core sample.

[0108] Based on the conversion coefficient of each pore free water sample at different gains, the NMR volume of each pore free water sample at different gains was obtained. The NMR volume was measured using an NMR analyzer by converting the NMR signal quantity to the volume of a standard sample.

[0109] The goodness-of-fit of the linear regression model between the volume of the pore free water sample and its NMR volume under all gains was obtained. A higher goodness-of-fit indicates a better fit of the linear regression model to the data, and a higher proportion of the variance in the dependent variable explained by the explanatory variables. Therefore, the gain corresponding to the maximum goodness-of-fit of the linear regression model between the volume of the pore free water sample and its NMR signal quantity under all gains was determined as the optimal gain for pore free water, denoted as the first optimal gain. The conversion coefficient corresponding to the pore free water sample under the first optimal gain was taken as the optimal conversion coefficient for the pore free water sample, denoted as the first optimal conversion coefficient. The linear regression model is a well-known technique, and the specific process will not be elaborated further.

[0110] To obtain conversion coefficients that better reflect the conversion relationship between the NMR signal quantity and the actual volume of oil phase material in actual pressurized core samples, further, for gain G, the maturity and conversion coefficients of all oil phase material samples under gain G are used as inputs to a linear regression model. Maturity and conversion coefficients are used as the X and Y variables of the linear regression model, respectively. Linear regression models are then established for the maturity and conversion coefficients of oil phase material samples under each gain. The gain corresponding to the linear regression model with the maximum goodness of fit across all gains is determined as the optimal gain for the oil phase material samples, denoted as the second optimal gain; the conversion coefficients corresponding to the oil phase material samples under the second optimal gain are denoted as the second optimal conversion coefficients.

[0111] Based on the NMR signal intensity and corresponding conversion coefficients of the oil phase material samples, the NMR volume of each volume at each maturity level and under each gain is calculated. Based on the actual volume and NMR volume of all oil phase material samples at each maturity level and each gain, a linear regression fitting model is established between the NMR volume and actual volume of all oil phase material samples at each maturity level and each gain, where the NMR volume and actual volume are the X and Y variables, respectively. The slope of the linear regression model constructed for each maturity level and each gain is recorded as the correction coefficient for the crude oil NMR volume of the oil phase material samples at each maturity level and each gain. For each gain, a linear regression model was established between the maturity of crude oil samples and the crude oil NMR volume correction coefficient. Maturity and the crude oil NMR volume correction coefficient were used as the X and Y variables, respectively. The gain corresponding to the linear regression model with the highest goodness of fit among all the established gain models was taken as the optimal gain for the crude oil sample, denoted as the second optimal gain. The conversion coefficient of the oil phase material sample under the second optimal gain was also taken as the optimal conversion coefficient of the oil phase material sample, denoted as the second optimal conversion coefficient. The crude oil NMR volume correction coefficients for the oil phase material sample at the second optimal gain and for each maturity level were obtained.

[0112] Thus, the first optimal gain, the first optimal conversion coefficient, the second optimal gain, and the second optimal conversion coefficient have been determined through the above methods, and these data are transmitted to the oil-water presence status discrimination unit.

[0113] Step S4: Combine the first optimal gain, the first optimal conversion coefficient, the second optimal gain, the second optimal conversion coefficient, and the NMR signal quantity to determine the oil saturation of the pressure-holding core sample.

[0114] After the cryopreserved pressurized core sample was removed from liquid nitrogen, it was placed in a sealed test bottle for thawing using the optimal thawing time. Two-dimensional nuclear magnetic resonance (NMR) testing was then performed on the thawed pressurized core sample to obtain the NMR signal of water in the T2 NMR spectrum. The actual volume of water corresponding to the NMR signal was calculated using the water NMR signal and the first optimal conversion factor. This water volume was taken as the water-bearing volume of the pressurized core sample before vacuum heating and was recorded as the first water-bearing volume. This water-bearing volume includes the volume of free water in shale pores and the volume of bound water.

[0115] Then, the core samples after two-dimensional nuclear magnetic resonance testing are placed in a vacuum oven. The vacuum pressure of the vacuum oven is set at a value not greater than the critical vacuum pressure value of the current batch of core samples. The boiling point of water at this vacuum pressure value is set as the heating temperature of the vacuum oven. The core samples are then subjected to vacuum heating treatment using the vacuum oven.

[0116] During the vacuum heating treatment of the pressurized core samples, a two-dimensional nuclear magnetic resonance (NMR) test was performed on the pressurized core samples every hour for the first 6 hours. The NMR T2 spectrum of the pressurized core samples at each vacuum heating time point and under the first optimal gain was obtained. The NMR signal of water in each extracted NMR T2 spectrum was obtained. The actual water volume corresponding to each NMR signal was calculated using the first optimal conversion coefficient. This water volume is taken as the water-bearing volume of the pressurized core samples at each vacuum heating time point. The water-bearing volume includes the volume of free water in the shale pores that is continuously lost and the volume of bound water that is not lost.

[0117] During the vacuum heating of the pressurized core sample, the water volume of the core sample was observed at each vacuum heating time point until the water volume change range was sufficiently small, at which point vacuum heating was stopped. At this point, the oil-water state of the pressurized core sample obtained after vacuum heating had reached a saturated oil-bound water state, meaning that the free water volume in the shale pores of the pressurized core sample had almost completely disappeared, while bound water and oil phase substances had not been lost. In this embodiment, a water volume change range of less than 0.01 ml every 2 hours was considered sufficiently small. Two-dimensional nuclear magnetic resonance (NMR) tests were performed on the pressurized core sample after vacuum heating. The NMR signal of water in the T2 NMR spectrum after vacuum heating was extracted, and the actual water volume corresponding to the NMR signal was calculated using the optimal conversion factor based on this NMR signal. This actual water volume was recorded as the second water volume. Figure 8-13 As shown, the variation characteristics of the T2 NMR spectrum of shale water-bearing material at different vacuum temperatures and times are illustrated, with the T2 NMR spectrum variation characteristics of shale water-bearing material at vacuum temperatures of 40℃, 50℃, and 60℃ respectively.

[0118] The maturity of the pressurized core sample is obtained. Based on the crude oil NMR volume correction coefficient and NMR volume of the pressurized core sample after vacuum heating at the second optimal gain and the maturity of the pressurized core sample, the oil phase volume in the pressurized core sample is calculated.

[0119] Thus, through the above methods, the first and second water-bearing volumes of the pressurized core samples before and after vacuum heating, as well as the oil phase volume in the pressurized core samples, have been obtained. Next, the oil saturation of the pressurized core samples will be determined based on the first water-bearing volume, the second water-bearing volume, and the oil phase volume.

[0120] Specifically, the absolute value of the difference between the first water-bearing volume and the second water-bearing volume is taken as the free water volume of shale pore water in the pressurized core sample; the sum of the free water volume of shale pore water and the oil phase volume is calculated, and the ratio between the free water volume of shale pore water and this sum is determined as the oil saturation of the pressurized core sample.

[0121] In this embodiment, a specific formula for calculating the oil saturation of pressurized core samples is given. The oil saturation of pressurized core samples can be expressed as:

[0122]

[0123] in, This indicates the oil saturation of the pressurized core sample. This represents the volume of free water in the shale pores of a pressurized core sample. This indicates the volume of the oil phase in the pressurized core sample.

[0124] The oil saturation of the obtained pressurized core samples was used as the result of the in-situ oil saturation determination of the shale in the target formation study area. The method provided in this embodiment was used to complete the in-situ oil saturation determination of the shale.

[0125] This embodiment analyzes the impact of noise interference and baseline drift on the NMR T2 spectra of different types of reference samples when obtaining the conversion coefficient that reflects the conversion relationship between the NMR signal quantity and the actual volume of water in the actual pressurized core sample. It determines the conversion coefficient for each reference sample at each gain, effectively reducing the impact of pore free water samples, which are significantly affected by noise interference and baseline drift, on the accuracy of the final calculated conversion coefficient. Based on the NMR signal quantities obtained from the conversion coefficients of pore free water samples of different volumes at different gains, it screens out the optimal conversion coefficient and optimal gain that better reflect the conversion relationship between the NMR signal quantity and the actual volume of water in the actual pressurized core sample. This improves the accuracy of subsequent oil-water occurrence state discrimination in the samples, thus providing more accurate key parameters for the subsequent in-situ oil saturation determination of shale, enhancing the accuracy of the in-situ oil saturation determination results, and providing more reliable data support for subsequent exploration and development decisions.

[0126] In this embodiment, when obtaining the conversion coefficient that reflects the conversion relationship between the NMR signal quantity of oil phase material in the actual pressurized core sample and its actual volume, the NMR signal quantities obtained from crude oil samples of different volumes and maturity at different gains are used to screen out the optimal conversion coefficient and optimal gain that better reflect the conversion relationship between the NMR signal quantity of oil phase material in the actual pressurized core sample and its actual volume. This improves the accuracy of subsequent calculation results and provides more accurate key parameters for the subsequent determination of shale in-situ oil saturation, thereby obtaining more accurate results for the determination of shale in-situ oil saturation.

[0127] Example of an in-situ oil saturation determination device for shale:

[0128] See Figure 2The diagram shows a structural block diagram of an in-situ oil saturation determination device for shale provided in an embodiment of the present invention. The device may include a sample acquisition module, a nuclear magnetic resonance signal acquisition module, a conversion coefficient determination module, a volume determination module, and a saturation determination module.

[0129] The sample acquisition module is used to acquire pressurized core samples and reference samples from the target stratigraphic study area. The reference samples include pore free water samples from the pressurized core samples and oil phase material samples from shale in-situ oil.

[0130] The NMR signal acquisition module is used to evaluate the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of each reference sample at different volumes in each reference sample at different gains.

[0131] The conversion coefficient determination module is used to obtain the conversion coefficient of each reference sample at each gain based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain, and to determine the first optimal gain and the first optimal conversion coefficient of pore free water; and to determine the second optimal gain and the second optimal conversion coefficient of oil phase material samples based on the relationship between the maturity of oil phase material samples and the conversion coefficient.

[0132] The saturation determination module is used to determine the oil saturation of the pressure-held core sample by combining the first optimal gain, the first optimal conversion coefficient, the second optimal gain, the second optimal conversion coefficient, and the NMR signal quantity.

[0133] It should be understood that Figure 2 The structural block diagram and modules of the in-situ oil saturation determination device for shale shown can be implemented in various ways. For example, in some embodiments, the system and its modules can be implemented by hardware, software, or a combination of both. The hardware portion can be implemented using dedicated logic; the software portion can be stored in memory and executed by appropriate instructions, such as a microprocessor or dedicated hardware. Those skilled in the art will understand that the above-described methods and devices can be implemented using computer-executable instructions and / or included in processor control code, for example, on a carrier medium such as a disk, CD, or DVD-ROM, a programmable memory such as read-only memory (firmware), or a data carrier such as an optical or electronic signal carrier. The devices and modules described in this specification can be implemented not only by hardware circuits such as very large-scale integrated circuits or gate arrays, semiconductors such as logic chips, transistors, or programmable hardware devices such as field-programmable gate arrays, programmable logic devices, etc., but also by software, for example, executed by various types of processors, or by a combination of the above-described hardware circuits and software (e.g., firmware).

[0134] For more details about the above modules, please refer to other parts of this manual; they will not be repeated here.

[0135] Based on the same inventive concept as the above method, this embodiment of the invention also provides a shale in-situ oil saturation determination system. The system stores computer program code, and when the computer program code is run on a computer, the computer executes the above-mentioned related method steps to realize the shale in-situ oil saturation determination method provided in the above embodiment.

[0136] It should be noted that the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for in-situ determination of oil saturation in shale, characterized in that, The method includes the following steps: Obtain pressurized core samples and reference samples from the target stratigraphic study area. The reference samples include pore free water samples from the pressurized core samples and oil phase material samples from in-situ shale oil. The amount of NMR signal for each reference sample at each gain is evaluated based on the NMR T2 spectra of each reference sample with different volumes at different gains. Based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain, the conversion coefficient of each reference sample at each gain is obtained, and the first optimal gain and the first optimal conversion coefficient of pore free water are determined; based on the relationship between the maturity of oil phase material samples and the conversion coefficient, the second optimal gain and the second optimal conversion coefficient of oil phase material samples are determined. By combining the first optimal gain, the first optimal conversion factor, the second optimal gain, the second optimal conversion factor, and the NMR signal quantity, the oil saturation of the pressure-held core sample was determined. The determination of the first optimal gain and the first optimal conversion factor for pore free water includes: Based on the conversion coefficient of each pore free water sample at different gains, the NMR volume of each pore free water sample at different gains was obtained. The volume of all pore free water samples and the NMR signal at the same gain were used as inputs to the linear regression model. The volume of pore free water samples and the NMR volume were used as the X and Y variables of the linear regression model, respectively. The linear regression model was used to establish the linear regression model of the volume of pore free water samples and their NMR volume at each gain. The gain corresponding to the maximum goodness of fit of the linear regression model of the volume of the pore free water sample and its NMR volume under all gains is determined as the first optimal gain for pore free water. The conversion coefficient corresponding to the pore free water sample under the first optimal gain is taken as the first optimal conversion coefficient; The determination of the second optimal gain and second optimal conversion coefficient of the oil phase material sample based on the relationship between the maturity and conversion coefficient of the oil phase material sample includes: Based on the NMR signal quantity and corresponding conversion coefficient of the oil phase material sample, calculate the NMR volume of the oil phase material sample at each gain for each maturity level and each volume. Based on the actual volume and NMR volume of all oil phase material samples under each maturity and each gain, a linear regression fitting model between the NMR volume and the actual volume of all oil phase material samples under each maturity and each gain is established, where the NMR volume and the actual volume are the X variable and the Y variable, respectively. The slope of the linear regression model constructed under each maturity and each gain is recorded as the crude oil NMR volume correction coefficient of the oil phase material sample under each maturity and each gain. Based on the maturity of all oil phase material samples and the crude oil NMR volume correction coefficient under each gain, a linear regression model between the maturity of crude oil samples and the crude oil NMR volume correction coefficient under each gain is established. Maturity and crude oil NMR volume correction coefficient are used as X and Y variables, respectively. The gain corresponding to the linear regression model with the highest goodness of fit among all the established linear regression models under all gains is taken as the optimal gain of crude oil samples, denoted as the second optimal gain. The conversion coefficient of oil phase material samples under the second optimal gain is taken as the optimal conversion coefficient of oil phase material samples, denoted as the second optimal conversion coefficient. The determination of oil saturation in pressurized core samples by combining the first optimal gain, the first optimal conversion factor, the second optimal gain, the second optimal conversion factor, and the NMR signal quantity includes: After the frozen and pressurized core samples were taken out of liquid nitrogen, the core samples were placed in a sealed test bottle for thawing using the optimal thawing time. The thawed core samples were then subjected to two-dimensional nuclear magnetic resonance (NMR) testing to obtain the NMR T2 spectrum before vacuum heating. Using the NMR signal quantity of water in the NMR T2 spectrum of the pressure-maintained core sample at the first optimal gain and the first optimal gain, the actual volume of water corresponding to the NMR signal quantity of water is calculated and recorded as the first water-bearing volume. Vacuum heating was performed on the pressurized core sample, and two-dimensional nuclear magnetic resonance (NMR) testing was conducted on the pressurized core sample after vacuum heating. The NMR signal of water in the NMR T2 spectrum after vacuum heating was extracted, and the actual volume of water corresponding to the NMR signal of water was calculated using the first optimal conversion coefficient based on the NMR signal of water after vacuum heating, and recorded as the second water-bearing volume. Obtain the maturity of the pressurized core sample and the crude oil NMR volume correction coefficient of the oil phase material at the second optimal gain and each maturity level; calculate the oil phase volume in the pressurized core sample based on the crude oil NMR volume correction coefficient and NMR volume of the oil phase material at the second optimal gain and maturity level of the pressurized core sample after vacuum heating. The oil saturation of the pressure-maintained core sample is determined by combining the first water-bearing volume, the second water-bearing volume, and the oil phase volume.

2. The method for determining the in-situ oil saturation of shale according to claim 1, characterized in that, After obtaining the NMR T2 spectra of each volume of reference sample, the following steps are also included: The NMR T2 spectra of each volume reference sample were processed by wavelet denoising algorithm and baseline correction method based on polynomial fitting, respectively, to obtain the NMR T2 spectra of each volume reference sample after denoising and baseline correction.

3. The method for determining the in-situ oil saturation of shale according to claim 2, characterized in that, The step of evaluating the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of each reference sample of different volumes at different gains includes: using an NMR analyzer to obtain the NMR T2 spectra of each reference sample of each volume after denoising and baseline correction at each gain, and using these as the NMR signal quantity of each reference sample of each volume at each gain.

4. The method for determining the in-situ oil saturation of shale according to claim 3, characterized in that, The step of obtaining the conversion coefficient of each reference sample at each gain based on the relationship between the NMR signal quantity and volume at the same gain includes: By combining the influence of the NMR signal of reference samples of different volumes at each gain on the correlation between the volume of the same type of reference sample and the NMR signal at the same gain, the data weight of reference samples of each volume at each gain is determined. For any gain, a linear regression model is constructed based on the relationship between the volume of all reference samples in each reference sample and the amount of NMR signal under that any gain; based on the constructed linear model and the data weights, the conversion coefficient of each reference sample under that any gain is obtained.

5. The method for determining the in-situ oil saturation of shale according to claim 4, characterized in that, The method involves considering the influence of NMR signal quantities of reference samples of different volumes at each gain on the correlation between the NMR signal quantities of the same type of reference sample volume and the NMR signal quantities at the same gain, and determining the data weight of each volume of reference sample at each gain, including: For any gain, the peak position of the largest peak signal in the NMR T2 spectrum of the candidate sample after denoising and baseline correction is taken as the peak position of the NMR signal of the candidate sample under any gain; the candidate sample is any volume of any kind of reference sample. The peak position consistency of the candidate sample under any gain is evaluated based on the distribution of the NMR signal peak positions of all reference samples of the same class under any gain. Calculate the first Pearson correlation coefficient between the volume of all reference samples of the same class as the candidate sample and the NMR signal quantity at any given gain; calculate the second Pearson correlation coefficient between the volume of all other reference samples of the same class as the candidate sample and the NMR signal quantity at any given gain; based on the second Pearson correlation coefficient and the first Pearson correlation coefficient, obtain the degree of positive correlation enhancement of the candidate sample at any given gain; the degree of positive correlation enhancement of the candidate sample at any given gain characterizes the influence of the NMR signal quantity of the candidate sample at any given gain on the correlation between the volume of the same class of reference samples and the NMR signal quantity at any given gain; By combining the peak position consistency and the positive correlation enhancement, the data weights of each reference sample of the same class under any given gain are determined.

6. The method for determining the in-situ oil saturation of shale according to claim 5, characterized in that, The determination of the data weights for each reference sample of the same class under any given gain, by combining the peak consistency and the positive correlation enhancement, includes: Based on the peak consistency and the positive correlation enhancement, the data confidence of the candidate sample under any given gain is obtained; Based on the data confidence of all reference samples of the same class under any given gain, the data weights of each reference sample of the same class under any given gain are obtained, wherein the sum of the data weights of all reference samples of the same class under any given gain is 1.

7. The method for determining the in-situ oil saturation of shale according to claim 1, characterized in that, The determination of the oil saturation of the pressurized core sample by combining the first water-bearing volume, the second water-bearing volume, and the oil phase volume includes: The absolute value of the difference between the first water-bearing volume and the second water-bearing volume is taken as the free water volume of shale pore water in the pressurized core sample. Calculate the sum of the free water volume in the shale pores and the oil phase volume; The ratio between the free water volume in the shale pores and the sum value is determined as the oil saturation of the pressure-maintained core sample.

8. The method for determining the in-situ oil saturation of shale according to claim 4, characterized in that, A linear regression model is constructed based on the relationship between the volume of all reference samples in each reference sample and the amount of NMR signal at any given gain. Based on the constructed linear model and the data weights, the conversion coefficients of each reference sample under any given gain are obtained, including: The volume of all reference samples in each type of reference sample and the NMR signal quantity at any given gain are used as inputs to the linear regression model. The NMR signal quantity and volume are used as the X and Y variables of the linear regression model, respectively. The parameters in the linear regression model are estimated using the weighted least squares method. The data weights of each reference sample at any given gain are used as the weights of the corresponding data points in the weighted least squares method. The slope of the output linear regression equation is used as the conversion coefficient of each reference sample at any given gain.

9. The method for determining the in-situ oil saturation of shale according to claim 5, characterized in that, The evaluation of the peak position consistency of candidate samples under any gain, based on the distribution of NMR signal peak positions of all reference samples of the same class under any gain, includes: The abscissa difference between the peak position of the NMR signal of the candidate sample at any gain and the peak position of the NMR signal of each other reference sample of the same class at any gain is obtained, and the mean of all the abscissa differences corresponding to the candidate sample at any gain is taken as the peak position consistency of the candidate sample at any gain.

10. The method for determining the in-situ oil saturation of shale according to claim 5, characterized in that, The step of obtaining the degree of positive correlation enhancement of the candidate sample under any gain based on the second Pearson correlation coefficient and the first Pearson correlation coefficient includes: determining the difference between the second Pearson correlation coefficient and the first Pearson correlation coefficient as the degree of positive correlation enhancement of the candidate sample under any gain.

11. The method for determining the in-situ oil saturation of shale according to claim 6, characterized in that, The step of obtaining the data confidence of the candidate sample under any gain based on the peak consistency and the positive correlation enhancement includes: using the product of the normalized value of the peak consistency and the normalized value of the positive correlation enhancement as the data confidence of the candidate sample under any gain.

12. A device for determining the in-situ oil saturation of shale, characterized in that, The apparatus is used to implement the method of claim 1, the apparatus comprising: The sample acquisition module is used to acquire pressurized core samples and reference samples from the target stratigraphic study area. The reference samples include pore free water samples from the pressurized core samples and oil phase material samples from shale in-situ oil. The NMR signal acquisition module is used to evaluate the NMR signal quantity of each reference sample at each gain based on the NMR T2 spectra of each reference sample at different volumes at different gains. The conversion coefficient determination module is used to obtain the conversion coefficient of each reference sample at each gain based on the relationship between the NMR signal quantity and volume of each reference sample at the same gain, and to determine the first optimal gain and the first optimal conversion coefficient of pore free water; and to determine the second optimal gain and the second optimal conversion coefficient of oil phase material samples based on the relationship between the maturity of oil phase material samples and the conversion coefficient. The saturation determination module is used to determine the oil saturation of the pressure-held core sample by combining the first optimal gain, the first optimal conversion coefficient, the second optimal gain, the second optimal conversion coefficient, and the NMR signal quantity.

13. A system for determining the in-situ oil saturation of shale, characterized in that, Used to store a computer program that causes a computer to perform the method as described in claim 1.

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