A method for measuring shale pore fluid saturation, mobility, and pore wettability

Abstract

The application discloses a shale pore fluid saturation, fluidity and pore wettability measurement method, relates to the technical field of shale oil exploration, and comprises the following steps: obtaining a shale oil sample to be measured, and obtaining a pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be measured; performing a preset extraction operation on the shale oil sample to be measured to obtain an extracted shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum; determining a T1 / T2 change rate of a relaxation peak peak value based on the two nuclear magnetic resonance spectra; determining a hydrogen component of the shale oil sample before and after extraction based on the T1 / T2 change rate, determining a target saturation based on the hydrogen component and a preset saturation calculation method; and determining the fluidity and wettability of the sample based on the target saturation, the T1 / T2 change rate and a preset property measurement method. The application utilizes a theoretical relationship between the calculated T1 / T2 change rate and the saturation of the obtained sample, obtains the fluidity and pore wettability of the sample, losslessly quantitatively represents various rock physical properties of shale, and improves the comprehensiveness and accuracy of the measurement result.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of shale oil exploration, and particularly relates to a shale pore fluid saturation, fluidity and pore wettability measurement method. BACKGROUND

[0002] The content of movable oil in shale directly determines the exploration and development value of shale, and therefore the mobility evaluation of shale has been one of the key problems in shale formation evaluation. In organic shale, part of the organic matter is converted into bitumen and oil and other hydrocarbons under high temperature and high pressure conditions. Due to the influence of organic matter maturity, the fluidity of these hydrocarbons shows the characteristics of strong heterogeneous distribution, and movable oil and immovable oil coexist in shale pores. In addition, the shale pores also include water naturally existing in the mineral pores of fine-grained sedimentary rocks. The complex fluid types and highly heterogeneous fluid fluidity both bring great challenges to the mobility evaluation of shale. The existing shale mobility measurement methods mainly include multi-temperature stage rock pyrolysis, step-by-step organic solvent extraction and adsorption retention, but these experimental methods can only be used for oil fluidity evaluation and cannot be used for the fluidity evaluation of bitumen and other solid-like organic matters and water in the pores. Compared with the above methods, the nuclear magnetic resonance (NMR) technology can directly detect the relaxation behavior of the fluid in the shale pores, and therefore the technology can provide more comprehensive and accurate fluid fluidity information. However, the existing shale pore fluid fluidity evaluation methods based on the NMR technology are all qualitative methods, which cannot meet the needs of shale mobility evaluation.

[0003] Wettability refers to the tendency of a certain fluid to spread on the surface of a solid when there are multiple non-miscible fluids. In a rock-oil-water system, the wettability of the pore surface of the rock can be divided into water-wet, neutral-wet and oil-wet. For hydrophilic rock, water is more likely to enter the rock pores to displace the oil therein; on the contrary, oil is more likely to enter the pores of oleophilic rock to displace the water therein. Therefore, wettability determines the distribution and flow characteristics of fluids in the rock-fluid system and is one of the key parameters in the process of oil and gas resource development. Shale contains multiple types of pores, including organic pores, clay pores and inorganic pores. At the same time, shale also contains complex hydrogen components. These different types of pores and hydrogen components together constitute a complex rock-fluid system in shale, and therefore the wettability characteristics of the pore surface of shale have great uncertainty, which brings many difficulties to the wettability measurement of shale samples.

[0004] The existing quantitative measurement methods of wettability include the contact angle method, the Amott-Harvey index method and the USBM method. Although the three methods can all characterize the wettability characteristics of the core sample, the obtained wettability characteristics are from a certain specific surface, and thus the measurement results are the average wettability in a certain volume range of the sample, are greatly affected by the heterogeneity of the sample, and are difficult to completely characterize the wettability characteristics of the sample. The nuclear magnetic resonance measurement has a larger observation scale and is less affected by the heterogeneity of the sample. However, the existing shale wettability measurement based on the NMR technology is mostly qualitative, and the accuracy of the measurement results cannot be guaranteed.

[0005] Compared with the above methods, the nuclear magnetic resonance (NMR) technology can directly detect the relaxation behavior of the fluid in the shale pore, and thus the technology can provide more comprehensive and accurate fluid mobility information, and can also obtain the wettability characteristics of the pore according to the fluid distribution characteristics of the pore surface. However, the existing shale fluid mobility and pore wettability evaluation methods based on the NMR technology are all qualitative methods, and cannot meet the need of accurately evaluating the shale petrophysical characteristics. Therefore, it is urgent to develop a quantitative evaluation method of shale fluid characteristics and pore wettability based on the NMR technology, so as to comprehensively and accurately characterize the shale petrophysical characteristics. SUMMARY

[0006] Therefore, the purpose of the present application is to provide a shale pore fluid saturation, mobility and wettability measurement method, which can improve the comprehensiveness and accuracy of the measurement results. The specific scheme is as follows:

[0007] In a first aspect, the present application discloses a shale pore fluid saturation, mobility and wettability measurement method, comprising:

[0008] obtaining a shale oil sample to be measured, and obtaining a pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be measured;

[0009] performing a preset extraction operation on the shale oil sample to be measured to obtain a post-extraction shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum;

[0010] determining the change rate of T1 / T2 of the relaxation peak peak value based on the pre-extraction nuclear magnetic resonance spectrum and the post-extraction nuclear magnetic resonance spectrum; wherein T1 is the longitudinal relaxation time, and T2 is the transverse relaxation time;

[0011] determining the hydrogen components corresponding to the pre-extraction and post-extraction shale oil samples based on the change rate of T1 / T2, and determining a target saturation degree based on the hydrogen components and a preset saturation degree calculation method; the target saturation degree is the saturation degree of different hydrogen components in the pre-extraction and post-extraction shale oil samples;

[0012] determine the fluidity and the pore wettability of the shale oil sample based on the target saturation, the T1 / T2 change rate and a preset property measurement method.

[0013] Optionally, the extraction pre-nuclear magnetic resonance spectrum of the shale oil sample comprises:

[0014] The nuclear magnetic resonance echo data corresponding to the shale oil sample is obtained based on the nuclear magnetic resonance technology.

[0015] The nuclear magnetic resonance echo data of the shale oil sample is inverted to obtain the extraction pre-nuclear magnetic resonance spectrum of the shale oil sample.

[0016] Optionally, the preset extraction operation on the shale oil sample comprises:

[0017] The shale oil sample is extracted by using a preset dichloromethane solvent containing methanol, and the extract is transferred to obtain a corresponding core sample; the preset dichloromethane solvent containing methanol is a dichloromethane solvent containing a methanol reagent with a volume percentage content of 3% to 50%;

[0018] The core sample is dried at low temperature and the residual dichloromethane is removed to obtain a corresponding extraction post-shale oil sample; the low temperature drying is performed at an environment below 65 degrees Celsius;

[0019] The nuclear magnetic resonance echo data corresponding to the extraction post-shale oil sample is obtained based on the nuclear magnetic resonance technology.

[0020] The nuclear magnetic resonance echo data of the extraction post-shale oil sample is inverted to obtain the extraction post-nuclear magnetic resonance spectrum of the extraction post-shale oil sample.

[0021] Optionally, the hydrogen component corresponding to the extraction pre-post shale oil sample is determined based on the T1 / T2 change rate, comprising:

[0022] The current value of the T1 / T2 change rate and a preset change rate value interval are obtained.

[0023] A target interval corresponding to the current value is determined from the change rate value interval, and the hydrogen component corresponding to the extraction pre-post shale oil sample is determined based on the target interval.

[0024] Optionally, the target saturation is determined based on the hydrogen component and a preset saturation calculation method, comprising:

[0025] A target correlation time is determined based on the target interval; the target correlation time includes a surface residence time and a transverse correlation time.

[0026] obtaining a first correlation between the target correlation time corresponding to the hydrogen component and first target saturation information before extraction;

[0027] obtaining a second correlation between the target correlation time corresponding to the hydrogen component and second target saturation information after extraction;

[0028] obtaining a correlation time ratio relationship based on a preset correlation time relationship, the first correlation and the second correlation; the correlation time ratio relationship is a ratio relationship between the surface residence time and the transverse correlation time;

[0029] obtaining a target correlation formula based on the correlation time ratio relationship and a preset T1 / T2 change rate formula; the target correlation formula is a formula used to represent the correlation between the T1 / T2 change rate and the target saturation;

[0030] calculating the target saturation based on a current value of the T1 / T2 change rate and the target correlation formula.

[0031] Optionally, the target correlation time is determined based on the target interval, and the method comprises:

[0032] when the target interval is a current value of the T1 / T2 change rate less than or equal to 1, determining the target correlation time as the surface residence time;

[0033] when the target interval is a current value of the T1 / T2 change rate greater than 1 and less than 2, determining the target correlation time as the surface residence time;

[0034] when the target interval is a current value of the T1 / T2 change rate greater than 2 or equal to and less than 3, determining the target correlation time as the surface residence time;

[0035] when the target interval is a current value of the T1 / T2 change rate greater than or equal to 3 and less than 6, determining the target correlation time as the transverse correlation time;

[0036] when the target interval is a current value of the T1 / T2 change rate greater than or equal to 6, determining the target correlation time as the transverse correlation time.

[0037] Optionally, the fluidity and the pore wettability of the shale oil sample to be measured are determined based on the target saturation, the T1 / T2 change rate and a preset property measurement method, and the method comprises:

[0038] obtaining a first change rate corresponding to the first shale oil sample and a second change rate corresponding to the second shale oil sample; the first change rate and the second change rate are change rates of T1 / T2;

[0039] determining a first change rate interval corresponding to the first change rate and a second change rate interval corresponding to the second change rate based on a preset change rate interval determination rule;

[0040] obtaining a first saturation corresponding to the first shale oil sample and a second saturation corresponding to the second shale oil sample; the first saturation and the second saturation are saturations of the hydrogen component;

[0041] when the first change rate interval and the second change rate interval are the same interval, and the first change rate interval is the change rate of T1 / T2 less than or equal to 1, determining whether the first change rate is equal to the second change rate;

[0042] when the first change rate is equal to the second change rate, comparing the first saturation and the second saturation, and determining that the shale oil sample with a larger saturation value of the first saturation and the second saturation has stronger fluid flowability; the first saturation and the second saturation are saturations of oil in the first shale oil sample and the second shale oil sample;

[0043] when the first change rate is not equal to the second change rate, determining that the shale oil sample with a larger change rate value of the first change rate and the second change rate has weaker fluid flowability;

[0044] when the first change rate interval and the second change rate interval are the same interval, and the first change rate interval is the change rate of T1 / T2 greater than 1 and less than 6, determining whether the first change rate is equal to the second change rate;

[0045] when the first change rate is equal to the second change rate, comparing the first saturation and the second saturation, and determining that the shale oil sample with a smaller saturation value of the first saturation and the second saturation has stronger fluid flowability; the first saturation and the second saturation are saturations of water in the first shale oil sample and the second shale oil sample;

[0046] when the first change rate is not equal to the second change rate, determining that the shale oil sample with a smaller change rate value of the first change rate and the second change rate has weaker fluid flowability;

[0047] when the first change rate interval and the second change rate interval are the same interval, and the first change rate interval is the change rate of T1 / T2 greater than or equal to 6, determining whether the first change rate is equal to the second change rate;

[0048] when the first change rate is equal to the second change rate, comparing the first saturation and the second saturation, and determining that the fluid flowability of the shale oil sample with a smaller saturation value is stronger; the first saturation and the second saturation are the saturations of the water in the first shale oil sample and the second shale oil sample;

[0049] when the first change rate is not equal to the second change rate, determining that the fluid flowability of the shale oil sample with a smaller change rate value is weaker;

[0050] when the first change rate interval and the second change rate interval are different intervals, the fluid flowability of the shale oil sample with a higher interval low boundary threshold value in the first change rate interval and the second change rate interval is stronger;

[0051] when the change rate of T1 / T2 is less than 2, determining that the pore of the shale oil sample is oil-wet;

[0052] when the change rate of T1 / T2 is greater than or equal to 6, determining that the pore of the shale oil sample is water-wet;

[0053] when the change rate of T1 / T2 is greater than or equal to 2 and less than 6, determining that the pore of the shale oil sample is mixed-wet;

[0054] when the shale oil sample is mixed-wet, determining that the pore of the shale oil sample with a higher change rate value in the first change rate and the second change rate is water-wet, and determining that the pore of the shale oil sample with a lower change rate value in the first change rate and the second change rate is oil-wet.

[0055] In a second aspect, the present application discloses a shale pore fluid saturation, flowability and pore wettability measuring device, comprising:

[0056] an extraction-before-NMR spectrum acquisition module, configured to acquire a shale oil sample to be measured, and acquire an extraction-before-NMR spectrum of the shale oil sample to be measured;

[0057] an extraction-after-NMR spectrum acquisition module, configured to perform a preset extraction operation on the shale oil sample to be measured, to obtain an extraction-after shale oil sample and a corresponding extraction-after-NMR spectrum;

[0058] a change rate determining module configured to determine a change rate of T1 / T2 of the relaxation peak based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum, wherein T1 is a longitudinal relaxation time and T2 is a transverse relaxation time;

[0059] a hydrogen component determining module configured to determine a hydrogen component of the shale oil sample based on the change rate of T1 / T2;

[0060] a saturation determining module configured to determine a target saturation based on the hydrogen component and a preset saturation calculation manner, wherein the target saturation is a saturation of different hydrogen components in the shale oil sample before and after extraction;

[0061] a sample property determining module configured to determine fluid flowability and pore wettability of the shale oil sample to be measured based on the target saturation, the change rate of T1 / T2 and a preset property measurement method.

[0062] In a third aspect, the present application discloses an electronic device, comprising:

[0063] a memory configured to save a computer program;

[0064] a processor configured to execute the computer program to implement the steps of the shale pore fluid saturation, flowability and pore wettability measurement method disclosed in the foregoing.

[0065] In a fourth aspect, the present application discloses a computer readable storage medium configured to store a computer program; wherein the computer program is executed by a processor to implement the shale pore fluid saturation, flowability and pore wettability measurement method disclosed in the foregoing.

[0066] It can be seen that the application provides a shale pore fluid saturation, fluidity and pore wettability measurement method, which comprises: obtaining a shale oil sample to be measured, and obtaining a nuclear magnetic resonance spectrum before extraction of the shale oil sample to be measured; performing a preset extraction operation on the shale oil sample to be measured to obtain a shale oil sample after extraction and a corresponding nuclear magnetic resonance spectrum after extraction; determining a change rate of T1 / T2 of a relaxation peak peak value based on the nuclear magnetic resonance spectrum before extraction and the nuclear magnetic resonance spectrum after extraction; wherein T1 is a longitudinal relaxation time, and T2 is a transverse relaxation time; determining a hydrogen component corresponding to the shale oil sample before and after extraction based on the change rate of T1 / T2, and determining a target saturation based on the hydrogen component and a preset saturation calculation method; the target saturation is the saturation of different hydrogen components in the shale oil sample before and after extraction; determining the fluid flowability and pore wettability of the shale oil sample to be measured based on the target saturation, the change rate of T1 / T2 and a preset property measurement method. It can be seen that, by extracting the shale oil sample to be measured, the application can measure the fluid flowability and pore wettability of the shale oil sample according to different characteristics of the mixed wettability fluid on the pore surface of the sample and the residual extraction reagent, so that the T1 / T2 of the nuclear magnetic resonance spectrum peak of different wettability fluids changes differently. The theoretical relationship between the calculated change rate of T1 / T2 and the saturation of the obtained sample is used to obtain the fluid flowability and pore wettability of the sample, which quantitatively characterizes the shale rock physical properties without damage, reduces the influence of the strong heterogeneity of the sample on the measurement results of the wettability of the shale, and improves the comprehensiveness and accuracy of the measurement results. BRIEF DESCRIPTION OF DRAWINGS

[0067] In order to more clearly illustrate the technical solutions in the embodiments of the present application or the prior art, the following will briefly introduce the drawings needed to be used in the embodiments or prior art description. Obviously, the drawings in the following description are only embodiments of the present application, and for those skilled in the art, other drawings can also be obtained without creative labor based on the provided drawings.

[0068] Figure 1 A shale pore fluid saturation, fluidity and pore wettability measurement method disclosed by the present application is shown in the flowchart;

[0069] Figure 2 T1 / T2-T2 spectra of two shale oil samples to be measured before and after extraction and low-temperature drying treatment disclosed by the present application are shown in the schematic diagram;

[0070] Figure 3 T1 / T2 spectra of two shale oil samples to be measured before and after extraction and low-temperature drying treatment disclosed by the present application are shown in the schematic diagram when T2≤0.4ms and T2>0.4ms;

[0071] Figure 4 A specific shale pore fluid saturation, fluidity and pore wettability measurement method flow chart disclosed by the application;

[0072] Figure 5 A T1 / T2 value and its change rate of different relaxation peak values of two shale oil samples to be measured before and after extraction and drying;

[0073] Figure 6 A shale pore fluid saturation, fluidity and pore wettability measurement device structure schematic diagram provided by the application;

[0074] Figure 7 An electronic device structure diagram provided by the application. DETAILED DESCRIPTION

[0075] The technical solutions in the embodiments of the application will be clearly and completely described below with reference to the drawings in the embodiments of the application. Obviously, the described embodiments are only part of the embodiments of the application, rather than all the embodiments of the application. Based on the embodiments in the application, all other embodiments obtained by those skilled in the art without creative labor fall within the protection scope of the application.

[0076] At present, the existing shale mobility measurement methods can only be used for oil fluidity evaluation, and cannot be used for evaluating the fluidity of bitumen and other solid organic matters and water in pores. The wettability characteristics obtained by the existing quantitative wettability measurement method are from a certain specific surface, so the measurement result is the average wettability in a certain volume range of the core, is greatly affected by the sample heterogeneity, and is difficult to completely characterize the wettability characteristics of the sample. And the existing shale pore fluid fluidity evaluation method and wettability evaluation method based on NMR technology are qualitative methods, which cannot meet the need of quantitatively evaluating shale rock physical properties. Therefore, the application provides a shale pore fluid saturation, fluidity and pore wettability measurement method, which can accurately characterize various shale rock physical properties without damage, and improve the comprehensiveness and accuracy of the measurement result.

[0077] The embodiments of the application disclose a shale pore fluid saturation, fluidity and pore wettability measurement method, referring to Figure 1 The method comprises the following steps:

[0078] Step S11: Obtain a shale oil sample to be measured, and obtain a nuclear magnetic resonance spectrum of the shale oil sample to be measured before extraction.

[0079] In this embodiment, a shale oil sample to be measured is obtained, and a pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be measured is obtained. Specifically, nuclear magnetic resonance echo data corresponding to the shale oil sample to be measured is obtained based on a nuclear magnetic resonance technology; and the nuclear magnetic resonance echo data of the shale oil sample to be measured is inverted to obtain a pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be measured. It can be understood that the nuclear magnetic resonance spectrum of the shale oil sample to be measured obtained based on the nuclear magnetic resonance technology includes but is not limited to the nuclear magnetic resonance spectrum of the shale oil sample to be measured obtained by a laboratory NMR (Nuclear Magnetic Resonance) instrument. Through the above technical solution, the nuclear magnetic resonance spectrum corresponding to the shale oil sample to be measured is obtained, so as to facilitate subsequent quantitative measurement of the wettability of the shale oil sample to be measured through data in the shale oil sample to be measured nuclear magnetic resonance spectrum. In a specific embodiment, the shale oil sample to be measured nuclear magnetic resonance spectrum includes but is not limited to T1 / T2-T2 spectrum, T1-T2 spectrum and T1 / T2 spectrum.

[0080] Step S12: performing a preset extraction operation on the shale oil sample to be measured to obtain a post-extraction shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum.

[0081] In this embodiment, after obtaining the shale oil sample to be measured and the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be measured, a preset extraction operation is performed on the shale oil sample to be measured to obtain a post-extraction shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum. Specifically, the shale oil sample to be measured is extracted by using a preset dichloromethane solvent containing methanol, and the extract is transferred to obtain a corresponding core sample; the preset dichloromethane solvent containing methanol is a dichloromethane solvent containing a methanol reagent with a volume percentage content of 3% to 50%; the core sample is dried at low temperature and residual dichloromethane is removed to obtain a corresponding post-extraction shale oil sample; the low-temperature drying is performed at an environment below 65 degrees Celsius; the nuclear magnetic resonance echo data corresponding to the post-extraction shale oil sample is obtained based on the nuclear magnetic resonance technology; and the nuclear magnetic resonance echo data of the post-extraction shale oil sample is inverted to obtain a post-extraction nuclear magnetic resonance spectrum of the post-extraction shale oil sample. It can be understood that the post-extraction shale oil sample corresponding to the shale oil sample to be measured is obtained by extracting the shale oil sample to be measured by using a preset dichloromethane solvent containing methanol, and the nuclear magnetic resonance spectrum of the post-extraction shale oil sample is obtained based on the nuclear magnetic resonance technology. Through the above technical solution, the nuclear magnetic resonance spectrum corresponding to the post-extraction shale oil sample is obtained, so as to facilitate subsequent quantitative measurement of the wettability of the shale oil sample to be measured through the post-extraction shale oil sample nuclear magnetic resonance spectrum.

[0082] It should be noted that the extraction method for extracting the shale oil sample to be tested includes but is not limited to Soxhlet extraction, ultrasonic extraction, soaking extraction and soaking stirring extraction; the core sample can be dried by any method that places the sample in a drying environment below 65 degrees Celsius.

[0083] The T1 / T2 spectra of two shale oil samples to be tested before and after extraction and low-temperature drying are shown in FIG. 1, where the dashed line is the T1 / T2 spectrum of the sample before extraction and low-temperature drying, and the solid line is the T1 / T2 spectrum of the sample after extraction and low-temperature drying. The numbers 1-5 in the figure are the serial numbers of the relaxation peak. Figure 2

[0084] Step S13: determining the change rate of T1 / T2 of the relaxation peak peak value based on the pre-extraction nuclear magnetic resonance spectrum and the post-extraction nuclear magnetic resonance spectrum.

[0085] In this embodiment, after performing a preset extraction operation on the shale oil sample to be tested to obtain a post-extraction shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum, the change rate of T1 / T2 of the relaxation peak peak value is determined based on the pre-extraction nuclear magnetic resonance spectrum and the post-extraction nuclear magnetic resonance spectrum. Specifically, the T1 / T2 of the relaxation peak peak value corresponding to the shale oil sample to be tested is determined according to the nuclear magnetic resonance spectrum of the shale oil sample to be tested, and the T1 / T2 of the relaxation peak peak value corresponding to the post-extraction shale oil sample is determined according to the nuclear magnetic resonance spectrum of the post-extraction shale oil sample. The change rate of T1 / T2 of the relaxation peak peak value is determined based on the ratio of the T1 / T2 of the relaxation peak peak value corresponding to the shale oil sample to be tested and the T1 / T2 of the relaxation peak peak value corresponding to the post-extraction shale oil sample. It can be understood that by extracting the shale oil sample to be tested with a preset dichloromethane solvent containing methanol as an organic solvent, and according to the different characteristics of the mixture of the wetting phase fluid on the pore surface of the sample and the residual methanol reagent, different changes in the nuclear magnetic resonance spectrum relaxation peak peak value of different wetting phase fluids are obtained, and the corresponding change rate of T1 / T2 of the relaxation peak peak value is obtained.

[0086] It can be understood that the T1 / T2 of the relaxation peak peak value in the nuclear magnetic resonance spectrum of the shale oil sample to be tested before and after extraction and drying is counted, where the change rate of T1 / T2 of the i-th relaxation peak peak value in the nuclear magnetic resonance spectrum corresponding to the shale oil sample to be tested is:

[0087] k R_i = R AR_i / R ES_i ;

[0088] where k R_i represents the change rate of T1 / T2 of the i-th relaxation peak peak value, and R AR_i ​T1 / T2 represents the T1 / T2 of the i-th relaxation peak of the shale oil sample to be tested; ES_i T1 / T2 represents the T1 / T2 of the i-th relaxation peak of the shale oil sample after extraction.

[0089] The T1 / T2 spectra of the two shale oil samples to be tested before and after extraction and low-temperature drying treatment when T2≤0.4 ms and T2>0.4 ms are shown in FIG. 1. Figure 3 The dashed line in the figure is the T1 / T2 spectrum of the sample before extraction and low-temperature drying treatment, and the solid line is the T1 / T2 spectrum of the sample after extraction and low-temperature drying treatment. The numbers 1-5 in the figure are the serial numbers of the relaxation peak. By counting the T1 / T2 of the peak value of different relaxation peaks in the nuclear magnetic resonance spectrum, the change rate of the T1 / T2 of the peak value of the relaxation peak is determined. It should be noted that, Figure 3 is to intuitively show the change of the T1 / T2 of the peak value of the relaxation peak of the sample before and after extraction and low-temperature drying treatment, and is not a necessary process for calculating the change rate k R_i of the T1 / T2 of the peak value of the relaxation peak.

[0090] Based on the surface relaxation theory model of shale, the ratio T1 / T2 of the longitudinal relaxation time T1 and the transverse relaxation time T2 of the pore fluid can be represented as:

[0091]

[0092] where A is a function related to the shale skeleton parameters, including the surface density of magnetic ions, the density of fluid molecules, the specific surface area of paramagnetic ions, and the hydrogen nucleus-paramagnetic ion interaction distance. J is the spectral density function of the Larmor frequency ω and the correlation time τ, where I and S are the subscripts of H nuclei and paramagnetic ions, respectively, satisfying ω 1 S = 659ω I .

[0093] The T1 / T2 change rate before and after the solvent extraction experiment can be represented as:

[0094]

[0095] Since T2 hardly changes before and after the solvent extraction experiment, formula 1 can be simplified as:

[0096]

[0097] Substituting the spectral density function (J(ω,τ)) of the quasi-1D translational diffusion model and the 2D translational diffusion model, the theoretical expression of the T1 / T2 change rate before and after the solvent extraction experiment is:

[0098]

[0099] ​

[0100] where τ m is the translational correlation time, τ s is the surface residence time.

[0101] Step S14: determining the hydrogen components of the shale oil sample before and after extraction based on the change rate of T1 / T2, and determining the target saturation degree based on the hydrogen components and a preset saturation degree calculation method.

[0102] In this embodiment, after determining the change rate of T1 / T2 of the relaxation peak value based on the NMR spectrum before extraction and the NMR spectrum after extraction, the hydrogen components of the shale oil sample before and after extraction are determined based on the change rate of T1 / T2, and the target saturation degree is determined based on the hydrogen components and a preset saturation degree calculation method; the target saturation degree is the saturation degree of different hydrogen components in the shale oil sample before and after extraction. It can be understood that there is a quantitative relationship between the T1 / T2 change rate and the saturation degree of different hydrogen components on the shale pore surface. When the magnetic field frequency is constant, the T1 / T2 change rate, i.e. formula 4a, b, is only related to the translational correlation time τ m and the surface residence time τ s . Specifically, under the quasi-1D translational diffusion model, the T1 / T2 change rate is only related to the change of the surface residence time τ s ; under the 2D translational diffusion model, the T1 / T2 change rate is only related to the translational correlation time τ m . According to the different types of hydrogen components, the relationship between the T1 / T2 change rate and the saturation degree of the hydrogen components on the pore surface is determined, which can be divided into the following cases:

[0103] 1. When the T1 / T2 change rate is less than or equal to 1, the hydrogen components on the pore surface are oil with different flowabilities.

[0104] Before extraction, the surface residence time τ s of the oil can be represented as:

[0105]

[0106] where HS and HW are the subscripts of strong and weak flowability oils, respectively, and f1 and f2 are the volume fractions of the strong and weak flowability oils, respectively (the hydrogen content index of different hydrogen components in shale is similar, so the volume fraction is the saturation degree).

[0107] After extraction, the surface residence time τ s of the oil can be represented as:

[0108]

[0109] where f1' and f2' are the volume fractions of the oil with high and low flow properties, respectively, after extraction.

[0110] If τ s_HW = k·τ s_HS , then the equations 5 and 6 can be rewritten as:

[0111]

[0112]

[0113] In this case, τ s ' = k·τ s , and the ratio of the surface residence time of the oil with high flow properties to that of the oil with low flow properties can be expressed as:

[0114]

[0115] Since the viscosity of the oil with high flow properties is smaller than that of the oil with low flow properties, the ratio of their surface residence times is k > 1. At the same time, the volume fraction of the oil with high flow properties will decrease after extraction, i.e., f1' << f1. This indicates that the ratio of the surface residence time of the oil with high flow properties to that of the oil with low flow properties is τ s ' / τ s >> 1. According to the relationship between the T1 / T2 change ratio and τ s ' / τ s , the T1 / T2 change ratio of the oil on the pore surface satisfies the following rule (equation 8 is substituted into equation 4a):

[0116]

[0117] Therefore, when the T1 / T2 change ratio is less than or equal to 1, the smaller the T1 / T2 change ratio, the greater the saturation of the oil with high flow properties and the smaller the saturation of the oil with low flow properties before extraction.

[0118] 2. When the T1 / T2 change ratio is greater than 1 and less than 2, the hydrogen component on the pore surface is solid or solid-like organic matter such as bitumen.

[0119] Before extraction, the surface residence time τ s of the solid or solid-like organic matter such as bitumen can be expressed as:

[0120]

[0121] where OM is the subscript of the solid or solid-like organic matter such as bitumen.

[0122] After extraction, the surface residence time τ s ' of the hydrogen component on the pore surface can be expressed as:

[0123]

[0124] Wherein, meth is the subscript of methanol, f1' and f2' are the volume fractions of solid or solid-like organic matter such as asphalt and methanol respectively, and the unit is decimal.

[0125] If τ s_meth = k·τ s_OM , then the formula can be substituted into (formula 10) and (formula 11) respectively to obtain:

[0126]

[0127]

[0128] At this time, τ s ' / τ s can be expressed as:

[0129]

[0130] Since the viscosity of solid OM is much larger than that of methanol, the ratio k of the surface residence time of the two hydrogen components satisfies k >> 1. At the same time, since the organic solvent used in this study (a dichloromethane solvent containing methanol by default) is relatively weak in polarity, the content of solid or solid-like organic matter that can be extracted is very limited, which also makes the content of methanol remaining in the nano-organic pores very limited. Therefore, for the volume fractions f1' and f2' of the two hydrogen components, it satisfies 1 > f1' >> f2'. The relationship between the T1 / T2 change rate and τ s ' / τ s , the T1 / T2 change rate of solid or solid-like organic matter such as asphalt satisfies the following rules:

[0131]

[0132] Therefore, when the T1 / T2 change rate is greater than 1 and less than 2, the smaller the T1 / T2 change rate, the higher the saturation of solid or solid-like organic matter such as asphalt after extraction, and the smaller the saturation of methanol. Before extraction, the saturation of solid or solid-like organic matter such as asphalt is 1.

[0133] 3. When the T1 / T2 change rate is greater than or equal to 2 and less than 3, the hydrogen component on the pore surface is a mixture of solid or solid-like organic matter such as asphalt and water.

[0134] Before extraction, the surface residence time of the hydrogen component on the pore surface can be expressed as:

[0135]

[0136] Wherein, W is the subscript of water, f1 and f2 are the volume fractions of water respectively, and the unit is decimal.

[0137] After extraction, the surface residence time of the hydrogen component on the pore surface can be expressed as:

[0138]

[0139] (1-f3')(f1+f2)+f3'=1 (Equation 16a, b);

[0140] where f1', f2' and f3' are the volume fractions of water, Solid OM and methanol after extraction, respectively, in decimal.

[0141] If τ s_OM =k1·τ s_W and τ s_meth =k2·τ s_W , respectively, then the following can be obtained by substituting Equation 15 and Equation 16a, b:

[0142]

[0143]

[0144] At this time, τ s ’ / τ s can be expressed as:

[0145]

[0146] Since the proportion of water in the hydrogen component on the pore surface is larger before extraction, τ s ’ / τ s can be further expressed as:

[0147]

[0148] Since the viscosity of methanol is smaller than that of water, the ratio of their surface residence times k2<1, and the volume fraction of methanol also satisfies f3'<1. Therefore, τ s ’ / τ s satisfies:

[0149]

[0150] Combining the relationship between the T1 / T2 change rate and τ s ’ / τ s , the T1 / T2 change rate of the mixture of solid or solid-like organic matter such as asphalt and water satisfies the following rule:

[0151]

[0152]

[0153] where F(τ s ’ / τs ) represents the rate of change of T1 / T2 with respect to τ s ' / τ s The function is shown in formula 4a.

[0154] Therefore, when the T1 / T2 change rate is greater than or equal to 2 and less than 3, the greater the T1 / T2 change rate, the greater the saturation of the pre-extraction water, and the smaller the saturation of solid or solid-like organic matter such as asphalt.

[0155] 4. When the T1 / T2 change rate is greater than or equal to 3 and less than 6, the hydrogen component on the pore surface is a mixture of oil and water.

[0156] Pre-extraction, translational correlation time τ of hydrogen composition on pore surface m It can be represented as:

[0157]

[0158] In the formula, f1 and f2 are the volume fractions of oil and water in the region, respectively, in decimal form.

[0159] Translational correlation time τ of hydrogen composition on pore surface after extraction m 'Can be represented as:

[0160]

[0161] In the formula, f1', f2', and f3' are the volume fractions of oil, water, and methanol after extraction, respectively, in decimal form.

[0162] If τ m_HS =k1·τ m_W And τ m_meth =k2·τ m_W Substituting these values ​​into formulas 22 and 23 respectively, we can obtain:

[0163]

[0164]

[0165] At this time, τ m ' / τ m It can be represented as:

[0166]

[0167] Because the volume fraction of water f2 in the mixture is small, when the volume fraction of water f2 is reduced to 1 before extraction... - At that time, the τ of the hydrogen component in this region m ' / τ m This can be further simplified to:

[0168]

[0169] Since the viscosity of water is lower than that of oil but higher than that of methanol, the ratio of their translational correlation times satisfies: k2 < 1 << k1, and the volume fraction f1' of oil after actual extraction approaches 0. + . At this time, τ m ’ / τ m satisfies:

[0170]

[0171] Combining the change rate of T1 / T2 with the relationship of τ m ’ / τ m , the change rate of T1 / T2 of the oil and water mixture satisfies the following rule:

[0172]

[0173]

[0174] Therefore, when the change rate of T1 / T2 is greater than or equal to 3 and less than 6, the greater the change rate of T1 / T2, the greater the water saturation before extraction and the lower the oil saturation.

[0175] 5. When the change rate of T1 / T2 is greater than or equal to 6, the hydrogen component on the pore surface is water.

[0176] Before extraction, the translational correlation time τ m of the hydrogen component on the pore surface can be expressed as:

[0177]

[0178] After extraction, the translational correlation time τ m ’ of the hydrogen component on the pore surface can be expressed as:

[0179]

[0180] In the formula, f1' and f2' are the volume fractions of water and methanol respectively, with the unit of decimal.

[0181] If τ m_meth = k·τ m_W , substituting them into Formula 29 and Formula 30 respectively, we can get:

[0182]

[0183]

[0184] At this time, τ m ’ / τ m can be expressed as:

[0185]

[0186] Since the viscosity of methanol is much lower than that of water, the ratio k of the translational correlation times of these two hydrogen components is less than 1. And since methanol is miscible with water in any proportion, the absolute contents of the original water and residual methanol in this region will both affect the volume fraction f1’ of water after extraction, so 0 < f1’ < 1. At this time, τ m ’ / τ m Satisfies:

[0187]

[0188] Combining the change rate of T1 / T2 and τ m ’ / τ m The change rate of T1 / T2 satisfies the following law:

[0189]

[0190]

[0191] In the formula, G(τ m ’ / τ m ) is the function of the change rate of T1 / T2 with respect to τ m ’ / τ m , that is, formula 4b.

[0192] Therefore, when the change rate of T1 / T2 is greater than or equal to 6, the greater the change rate of T1 / T2, the smaller the saturation of water after extraction and the greater the saturation of methanol. Before extraction, the saturation of water on the pore surface is 1.

[0193] Step S15: Determine the fluid mobility and pore wettability of the shale oil sample to be measured based on the target saturation, the change rate of T1 / T2, and a preset property measurement method.

[0194] In this embodiment, after determining the target saturation based on the hydrogen composition and a preset saturation calculation method, the fluid flowability and pore wettability of the shale oil sample to be tested are determined based on the target saturation, the rate of change of T1 / T2, and a preset property measurement method. It is understood that if the rate of change of T1 / T2 of the relaxation peak is less than or equal to 1, the corresponding relaxation peak is determined to be an oil signal peak; if the rate of change of T1 / T2 of the relaxation peak is greater than 1, the corresponding relaxation peak is determined to be a non-oil signal peak. The non-oil signal peak includes signals from solid organic matter such as asphalt, mixed signals from water and solid organic matter such as asphalt, mixed signals from water and oil, signals from water, and mixed signals from water and methanol. A smaller value for the rate of change of T1 / T2 of the relaxation peak indicates stronger oil flowability. A higher T1 / T2 ratio for the relaxation peak indicates stronger fluidity of the non-oil fluid. Non-oil fluids include solid organic matter such as asphalt, mixtures of water and solid organic matter such as asphalt, mixtures of water and oil, and mixtures of water and methanol. If the T1 / T2 ratio for the relaxation peak is less than or equal to 2, the sample pore surface is determined to be oil-wetted. If the T1 / T2 ratio for the relaxation peak is greater than 2 and less than or equal to 6, the sample pore surface is determined to be mixed-wetted, and the magnitude of the T1 / T2 ratio indicates the degree of mixed wetting. If the T1 / T2 ratio for the relaxation peak is greater than 6, the sample pore surface is determined to be water-wetted. If the rate of change of the relaxation peak value T1 / T2 is greater than 2 and less than or equal to 6, and the smaller the value of the rate of change of the relaxation peak value T1 / T2, the more oleophilic the pore surface is; if the rate of change of the relaxation peak value T1 / T2 is greater than 2 and less than or equal to 6, and the larger the value of the rate of change of the relaxation peak value T1 / T2, the more hydrophilic the pore surface is.

[0195] In this application, when quantitatively measuring the wettability of shale oil pores, the NMR spectrum of the shale oil sample to be tested is obtained using nuclear magnetic resonance (NMR) technology. The shale oil sample is then extracted using a pre-prepared dichloromethane solvent containing methanol. The NMR spectrum of the extracted shale oil sample is then obtained using NMR technology. Finally, the rate of change of the relaxation peak value is obtained from the aforementioned NMR spectrum, which is used to determine the wettability of the shale oil sample pores. In the quantitative measurement of shale porosity wettability, a pre-set dichloromethane solvent containing methanol is used as the organic solvent to extract shale oil samples. Based on the different characteristics of different wetting phase fluids on the sample pore surface after mixing with residual methanol reagent, the wettability of shale oil samples can be measured by observing the different changes in the peak values ​​of the nuclear magnetic resonance (NMR) spectrum before and after the extraction of different wetting phase fluids. This reduces the influence of strong sample heterogeneity on the wettability measurement results, making the results more representative. Furthermore, it solves the problem that previous NMR-based techniques could only qualitatively evaluate shale wettability, providing comprehensive and accurate wettability measurement results.

[0196] This application, based on the shale surface relaxation theory model, determines the theoretical expression for the T1 / T2 change rate before and after solvent extraction experiments. Based on the changes in the properties of different hydrogen components in shale before and after extraction, numerical simulation analysis is conducted using the theoretical expression for the T1 / T2 change rate. This determines the quantitative relationship between the T1 / T2 change rate and the saturation of different hydrogen components on the shale pore surface under different hydrogen component types. Based on the fluid saturation on the shale pore surface, a quantitative evaluation of shale fluid flowability and pore wettability based on the T1 / T2 change rate is achieved.

[0197] As can be seen, this application provides a method for measuring the pore fluid saturation, flowability, and pore wettability of shale oil, comprising: acquiring a shale oil sample to be tested and acquiring the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested; performing a preset extraction operation on the shale oil sample to be tested to obtain an extracted shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum; determining the T1 / T2 rate of change of the relaxation peak value based on the pre-extraction nuclear magnetic resonance spectrum and the post-extraction nuclear magnetic resonance spectrum; wherein T1 is the longitudinal relaxation time and T2 is the transverse relaxation time; determining the hydrogen component corresponding to the pre-extraction shale oil sample based on the T1 / T2 rate of change, and determining a target saturation based on the hydrogen component and a preset saturation calculation method; the target saturation is the saturation of different hydrogen components in the pre-extraction shale oil sample; and determining the fluid flowability and pore wettability of the shale oil sample to be tested based on the target saturation, the T1 / T2 rate of change, and the preset property measurement method. Therefore, this application measures the fluid flowability and pore wettability of shale oil samples by extracting the sample and taking advantage of the different characteristics of the wetted phase fluid on the sample pore surface after mixing with the residual extraction reagent. This results in different changes in the T1 / T2 ratio of the peak values ​​of the nuclear magnetic resonance spectra of different wetted phase fluids. By utilizing the theoretical relationship between the calculated T1 / T2 change rate and the saturation of the sample, the fluid flowability and pore wettability of the sample can be obtained. This non-destructive and quantitative characterization of various rock physical properties of shale reduces the influence of the strong heterogeneity of the sample on the wettability measurement results of shale, and improves the comprehensiveness and accuracy of the measurement results.

[0198] See Figure 4 As shown, this embodiment of the invention discloses a method for measuring the saturation, flowability, and wettability of shale pore fluids. Compared with the previous embodiment, this embodiment further explains and optimizes the technical solution.

[0199] Step S21: Obtain the shale oil sample to be tested, and obtain the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested.

[0200] Step S22: Perform a preset extraction operation on the shale oil sample to be tested to obtain the extracted shale oil sample and the corresponding extracted nuclear magnetic resonance spectrum.

[0201] Step S23: Determine the rate of change of the relaxation peak value T1 / T2 based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum.

[0202] Step S24: Obtain the current value of the rate of change of T1 / T2 and the preset range of the rate of change value, determine the target range corresponding to the current value from the range of the rate of change value, and determine the hydrogen component corresponding to the shale oil sample before and after extraction based on the target range.

[0203] In this embodiment, after determining the T1 / T2 rate of change of the relaxation peak value based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum, the current value of the T1 / T2 rate of change and a preset range of rate of change values ​​are obtained. A target range corresponding to the current value is determined from the range of rate of change values, and the hydrogen composition corresponding to the shale oil sample before and after extraction is determined based on the target range. It can be understood that when the T1 / T2 rate of change is less than or equal to 1, the hydrogen composition on the pore surface is oil with different fluidity; when the T1 / T2 rate of change is greater than 1 and less than 2, the hydrogen composition on the pore surface is solid or solid-like organic matter such as asphalt; when the T1 / T2 rate of change is greater than or equal to 2 and less than 3, the hydrogen composition on the pore surface is a mixture of solid or solid-like organic matter such as asphalt and water; when the T1 / T2 rate of change is greater than or equal to 3 and less than 6, the hydrogen composition on the pore surface is a mixture of oil and water; and when the T1 / T2 rate of change is greater than or equal to 6, the hydrogen composition on the pore surface is water.

[0204] Step S25: Determine the target saturation based on the hydrogen composition and the preset saturation calculation method.

[0205] In this embodiment, after determining the hydrogen composition corresponding to the shale oil sample before and after extraction based on the target interval, the target saturation is determined based on the hydrogen composition and a preset saturation calculation method. Specifically, a target correlation time is determined based on the target interval; the target correlation time includes surface residence time and translational correlation time; a first correlation relationship is obtained between the target correlation time corresponding to the hydrogen composition before extraction and the first target saturation information; a second correlation relationship is obtained between the target correlation time corresponding to the hydrogen composition after extraction and the second target saturation information; a correlation time ratio relationship is obtained based on the preset correlation time relationship, the first correlation relationship, and the second correlation relationship; the correlation time ratio relationship is the ratio of the surface residence time to the translational correlation time (e.g., formula 8); a target correlation formula is obtained based on the correlation time ratio relationship and a preset T1 / T2 change rate formula; the target correlation formula is a formula used to characterize the correlation relationship between the T1 / T2 change rate and the target saturation; the target saturation is calculated based on the current value of the T1 / T2 change rate and the target correlation formula. It is understood that determining the target relevant time based on the target interval includes: when the target interval is the current value of the rate of change of T1 / T2 which is less than or equal to 1, determining the target relevant time as the surface dwell time; when the target interval is the current value of the rate of change of T1 / T2 which is greater than 1 and less than 2, determining the target relevant time as the surface dwell time; when the target interval is the current value of the rate of change of T1 / T2 which is greater than or equal to 2 and less than 3, determining the target relevant time as the surface dwell time; when the target interval is the current value of the rate of change of T1 / T2 which is greater than or equal to 3 and less than 6, determining the target relevant time as the translational relevant time; and when the target interval is the current value of the rate of change of T1 / T2 which is greater than or equal to 6, determining the target relevant time as the translational relevant time.

[0206] Step S26: Determine the fluid flowability of the shale oil sample to be tested based on the target saturation and the change in T1 / T2.

[0207] In this embodiment, after determining the target saturation based on the hydrogen composition and a preset saturation calculation method, the fluid flowability of the shale oil sample to be tested is determined based on the target saturation and the change in T1 / T2. Specifically, a first rate of change corresponding to the first shale oil sample to be tested and a second rate of change corresponding to the second shale oil sample to be tested are obtained; the first rate of change and the second rate of change are the rates of change of T1 / T2; a first rate of change interval corresponding to the first rate of change and a second rate of change interval corresponding to the second rate of change are determined based on a preset rate of change interval determination rule; a first saturation corresponding to the first shale oil sample to be tested and a second saturation corresponding to the second shale oil sample to be tested are obtained; the first saturation and the second saturation are the saturation of the hydrogen composition; when the first rate of change interval and the second rate of change interval are the same interval, and the first rate of change interval is the target saturation interval, the fluid flowability of the shale oil sample to be tested is determined based on the target saturation and the change in T1 / T2. When the rate of change of T1 / T2 is less than or equal to 1, it is determined whether the first rate of change is equal to the second rate of change; when the first rate of change is equal to the second rate of change, the first saturation is compared with the second saturation, and it is determined that the oil in the shale oil sample with the larger saturation value is more fluid; the first saturation and the second saturation are the saturation of the oil in the first and second shale oil samples (the oil is highly fluid); when the first rate of change is not equal to the second rate of change, it is determined that the oil with the larger saturation value is greater than the first rate of change. The oil in the shale oil sample to be tested has weaker fluidity; when the first rate of change interval and the second rate of change interval are the same interval, and the first rate of change interval is the rate of change of T1 / T2 greater than 1 and less than 6, it is determined whether the first rate of change is equal to the second rate of change; when the first rate of change is equal to the second rate of change, the first saturation and the second saturation are compared, and it is determined that the fluid in the shale oil sample to be tested with the smaller saturation value is more fluid; the first saturation and the second saturation are the water saturation in the first shale oil sample to be tested and the second shale oil sample to be tested. When the first rate of change is not equal to the second rate of change, it is determined that the fluid in the shale oil sample with the smaller value of the first rate of change and the second rate of change is less fluid; when the first rate of change interval and the second rate of change interval are the same interval, and the first rate of change interval is the rate of change of T1 / T2 greater than or equal to 6, it is determined whether the first rate of change is equal to the second rate of change; when the first rate of change is equal to the second rate of change, the first saturation and the second saturation are compared, and it is determined that the fluid in the shale oil sample with the smaller value of the first saturation and the second saturation is more fluid;The first saturation and the second saturation refer to the water saturation in the first and second shale oil samples to be tested, respectively. When the first rate of change is not equal to the second rate of change, the shale oil sample with the smaller rate of change between the first and second rates of change is determined to have weaker fluidity. When the first rate of change interval and the second rate of change interval are different intervals, the shale oil sample with the higher lower boundary threshold between the first and second rate of change intervals has stronger fluidity. The T1 / T2 values ​​and their rates of change of different relaxation peak values ​​of the two shale oil samples before and after extraction and drying are shown below. Figure 5 As shown, by Figure 5 It can be seen that according to k R_i The calculation results can effectively and intuitively compare the fluid saturation and flow characteristics in the two shale oil samples. Among them, the T1 / T2 change rate of the 1st, 3rd, 4th and 5th relaxation peaks in the two samples is greater than 1, and their values ​​are ordered from smallest to largest as 1, 3, 5 and 4, respectively, and their flowability changes from weakest to strongest. Comparing Sample 1 and Sample 2, the T1 / T2 change rate of the first relaxation peak of Sample 1 is greater than that of Sample 2, indicating that the saturation of solid or solid-like organic matter such as asphalt in Sample 1 is low, resulting in stronger fluidity. The T1 / T2 change rate of the second relaxation peak of Sample 1 is equal to that of the second relaxation peak of Sample 2, indicating that the fluidity of the oil in both samples is consistent. The T1 / T2 change rate of the third relaxation peak of Sample 1 is greater than that of the third relaxation peak of Sample 2, indicating that the saturation of solid or solid-like organic matter such as asphalt in Sample 1 is low, while the saturation of water is high, resulting in stronger fluidity. The T1 / T2 change rate of the fifth relaxation peak of Sample 1 is greater than that of the fifth relaxation peak of Sample 2, indicating that the saturation of water in Sample 1 is low, while the saturation of methanol is high, resulting in stronger fluidity.

[0208] It can be understood that Formula 14 indicates that the greater the change rate of T1 / T2, the lower the saturation of solid or quasi-solid organic matters such as bitumen, the greater the saturation of methanol, and the stronger the fluidity of the fluid; Formulas 21a and 21b indicate that the greater the change rate of T1 / T2, the lower the saturation of solid or quasi-solid organic matters such as bitumen, the greater the saturation of water, and the stronger the fluidity of the fluid; Formulas 28a and 28b indicate that the greater the change rate of T1 / T2, the lower the saturation of oil, the greater the saturation of water, and the stronger the fluidity of the fluid; Formulas 33a and 33b indicate that the greater the change rate of T1 / T2, the lower the saturation of water, the greater the saturation of methanol, and the stronger the fluidity of the fluid; because for fluids with a change rate of T1 / T2 greater than 1 in shale, their fluidity is ranked from low to high as follows: solid or quasi-solid organic matters such as bitumen, mixtures of water and solid or quasi-solid organic matters such as bitumen, mixtures of water and oil, and water. Therefore, when the change rate of T1 / T2 is greater than 1, the greater the change rate of T1 / T2, the stronger the fluidity of the fluid. Formula 9 indicates that the smaller the change rate of T1 / T2, the higher the saturation of strongly flowing oil, the lower the saturation of weakly flowing oil, and the stronger the fluidity of the fluid. Therefore, when the change rate of T1 / T2 is less than or equal to 1, the smaller the change rate of T1 / T2, the stronger the fluidity of the fluid, and the fluidity with a change rate of T1 / T2 greater than 1 is always stronger than that with a change rate of T1 / T2 less than or equal to 1. It should be noted that when the change rate of T1 / T2 is greater than 1, some interval divisions will also be carried out. For example, the part with a change rate of T1 / T2 greater than 1 is divided into the following intervals: the change rate of T1 / T2 is greater than 1 and less than 2, that is, (1 < change rate of T1 / T2 < 2); the change rate of T1 / T2 is greater than or equal to 2 and less than 3, that is, (2 ≤ change rate of T1 / T2 < 3); the change rate of T1 / T2 is greater than or equal to 3 and less than 6, that is, (3 ≤ change rate of T1 / T2 < 6); the change rate of T1 / T2 is greater than or equal to 6, that is, (6 ≤ change rate of T1 / T2). The fluidity of each interval with a larger value is stronger than that of the interval with a lower value. That is, when the first change rate interval and the second change rate interval are different intervals, the fluidity of the fluid in the test shale oil sample with a higher low boundary threshold in the first change rate interval and the second change rate interval is stronger. For example, the low boundary threshold of the interval 6 ≤ change rate of T1 / T2 is 6, the low boundary threshold of the interval 3 < change rate of T1 / T2 < 6 is 3, and 6 is greater than 3. Therefore, the fluidity of the fluid corresponding to the interval 6 ≤ change rate of T1 / T2 is stronger than that of the interval 3 < change rate of T1 / T2 < 6.

[0209] Step S27: Determine the wettability of the pores of the test shale oil sample based on the target saturation and the change rate of T1 / T2.

[0210] In this embodiment, after determining the target saturation based on the hydrogen composition and a preset saturation calculation method, the wettability of the shale oil sample porosity is determined based on the target saturation and the rate of change of T1 / T2. Specifically, when the rate of change of T1 / T2 is less than 2, the shale oil sample porosity is determined to be oil-wetted; when the rate of change of T1 / T2 is greater than or equal to 6, the shale oil sample porosity is determined to be water-wetted; when the rate of change of T1 / T2 is greater than or equal to 2 and less than 6, the shale oil sample porosity is determined to be mixed-wetted; when the shale oil sample porosity is mixed-wetted, the shale oil sample porosity with the higher value of the first rate of change and the second rate of change is determined to be predominantly water-wetted, and the shale oil sample porosity with the lower value of the first rate of change and the second rate of change is determined to be predominantly oil-wetted.

[0211] If the rate of change of the T1 / T2 of the relaxation peak value is less than 2, the corresponding relaxation peak is determined to be oil-wetted; if the rate of change of the T1 / T2 of the relaxation peak value is greater than or equal to 2 and less than 6, the corresponding relaxation peak is determined to be mixed-wetted, and the magnitude of the rate of change of the T1 / T2 of the relaxation peak value indicates the degree of mixed wetting; if the rate of change of the T1 / T2 of the relaxation peak value is greater than or equal to 6, the corresponding relaxation peak is determined to be water-wetted. Specifically, when k R_i When k is less than or equal to 2, it indicates that the wetting phase fluid corresponding to the relaxation peak in the shale oil sample is oil or asphalt-like solid organic matter, and the pore surface is oil-wetted; when k R_i Greater than or equal to 2 and k A_i When k is less than 6, it indicates that the wetting phase fluid corresponding to the relaxation peak in the shale oil sample is a mixture of water and oil or a mixture of water and asphalt or other solid organic matter, and the pore surface is mixed-wetting; when k R_i A value greater than or equal to 6 indicates that the wetting phase fluid corresponding to the relaxation peak in the tested shale oil sample is water or a mixture of water and methanol, and the pore surface is water-wetted. The T1 / T2 values ​​and their rates of change of different relaxation peak values ​​of the two tested shale oil samples before and after extraction and drying are shown in the figure. Figure 5 As shown, by Figure 5 It can be seen that according to k R_i The calculation results can effectively and intuitively characterize the wettability of the pores in the two shale oil samples. Specifically, the first and second relaxation peaks show that the local pore surfaces of the samples are oil-wetted, the third and fifth relaxation peaks show that the local pore surfaces of the samples are mixed-wetted, and the fourth relaxation peak shows that the local pore surfaces of the samples are water-wetted.

[0212] It is understandable that Formulas 9 and 14 indicate that when the T1 / T2 change rate is less than 2, the hydrogen component on the pore surface before extraction is solid or solid-like organic matter such as oil or asphalt, and their saturation is 1, therefore the pore surface is oil-wetted. Formulas 21a,b and 28a,b indicate that when the T1 / T2 change rate is greater than 2 and less than 6, the hydrogen component on the pore surface before extraction is a mixture of water and solid or solid-like organic matter such as asphalt, or a mixture of water and oil, therefore the pore surface is mixed-wetted. Since the T1 / T2 change rate is within this range, the larger the T1 / T2 change rate, the higher the water saturation, therefore the pore wettability is more inclined towards water wetting; conversely, it is more inclined towards oil wetting. Formulas 33a,b indicate that when the T1 / T2 change rate is greater than or equal to 6, the hydrogen component on the pore surface before extraction is water, and its saturation is 1, therefore the pore surface is water-wetted. The T1 / T2 values ​​and their rate of change of different relaxation peak values ​​of the two shale oil samples before and after extraction and drying are shown in the figure. Figure 5 As shown, by Figure 5 It can be seen that according to k R_i The calculation results can effectively and intuitively compare the mixed wetting degree of the pores in the two shale oil samples. The T1 / T2 change rate corresponding to the third relaxation peak of sample 1 is greater than that corresponding to the third relaxation peak of sample 2. Furthermore, the T1 / T2 change rates corresponding to both relaxation peaks are greater than 2 and less than 6. Therefore, the third relaxation peak of sample 1 is more water-wetting than the third relaxation peak of sample 2.

[0213] For details regarding steps S21 to S23, please refer to the corresponding content disclosed in the foregoing embodiments, which will not be repeated here.

[0214] As can be seen, the embodiments of this application improve the comprehensiveness and accuracy of measurement results by acquiring a shale oil sample to be tested and obtaining its pre-extraction nuclear magnetic resonance spectrum; performing a preset extraction operation on the shale oil sample to obtain an extracted shale oil sample and its corresponding post-extraction nuclear magnetic resonance spectrum; determining the T1 / T2 rate of change of the relaxation peak value based on the pre-extraction nuclear magnetic resonance spectrum and the post-extraction nuclear magnetic resonance spectrum; acquiring the current value of the T1 / T2 rate of change and a preset range of the rate of change; determining the target range corresponding to the current value from the range of the rate of change; determining the hydrogen component corresponding to the pre-extraction shale oil sample based on the target range; determining the target saturation based on the hydrogen component and a preset saturation calculation method; determining the fluid flowability of the shale oil sample to be tested based on the target saturation and the T1 / T2 rate of change; and determining the wettability of the pores of the shale oil sample to be tested based on the target saturation and the T1 / T2 rate of change.

[0215] See Figure 6As shown in the embodiments, this application also discloses a device for measuring shale pore fluid saturation, flowability, and pore wettability, including:

[0216] The pre-extraction nuclear magnetic resonance spectrum acquisition module 11 is used to acquire the shale oil sample to be tested and to acquire the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested.

[0217] The extraction nuclear magnetic resonance spectrum acquisition module 12 is used to perform a preset extraction operation on the shale oil sample to be tested, so as to obtain the extracted shale oil sample and the corresponding extraction nuclear magnetic resonance spectrum.

[0218] The rate of change determination module 13 is used to determine the rate of change of the relaxation peak value T1 / T2 based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum; wherein T1 is the longitudinal relaxation time and T2 is the transverse relaxation time.

[0219] Hydrogen composition determination module 14 is used to determine the hydrogen composition of the shale oil sample before and after extraction based on the rate of change of T1 / T2.

[0220] The saturation determination module 15 is used to determine the target saturation based on the hydrogen composition and a preset saturation calculation method; the target saturation is the saturation of different hydrogen components in the shale oil samples before and after extraction;

[0221] The sample property determination module 16 is used to determine the fluid flowability and pore wettability of the shale oil sample to be tested based on the target saturation, the rate of change of T1 / T2, and a preset property measurement method.

[0222] As can be seen, this application includes: acquiring a shale oil sample to be tested, and acquiring the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested; performing a preset extraction operation on the shale oil sample to be tested to obtain an extracted shale oil sample and a corresponding post-extraction nuclear magnetic resonance spectrum; determining the T1 / T2 rate of change of the relaxation peak value based on the pre-extraction nuclear magnetic resonance spectrum and the post-extraction nuclear magnetic resonance spectrum; wherein T1 is the longitudinal relaxation time and T2 is the transverse relaxation time; determining the hydrogen component corresponding to the pre-extraction shale oil sample based on the T1 / T2 rate of change, and determining a target saturation based on the hydrogen component and a preset saturation calculation method; the target saturation is the saturation of different hydrogen components in the pre-extraction shale oil sample; determining the fluid flowability and pore wettability of the shale oil sample to be tested based on the target saturation, the T1 / T2 rate of change, and a preset property measurement method. Therefore, this application measures the fluid flowability and pore wettability of shale oil samples by extracting the sample and taking advantage of the different characteristics of the wetted phase fluid on the sample pore surface after mixing with the residual extraction reagent. This results in different changes in the T1 / T2 ratio of the peak values ​​of the nuclear magnetic resonance spectra of different wetted phase fluids. By utilizing the theoretical relationship between the calculated T1 / T2 change rate and the saturation of the sample, the fluid flowability and pore wettability of the sample can be obtained. This non-destructive and quantitative characterization of various rock physical properties of shale reduces the influence of the strong heterogeneity of the sample on the wettability measurement results of shale, and improves the comprehensiveness and accuracy of the measurement results.

[0223] In some specific embodiments, the pre-extraction nuclear magnetic resonance spectrum acquisition module 11 specifically includes:

[0224] The first nuclear magnetic resonance echo data acquisition unit is used to acquire the nuclear magnetic resonance echo data corresponding to the shale oil sample to be tested based on nuclear magnetic resonance technology.

[0225] The pre-extraction nuclear magnetic resonance (NMR) spectrum acquisition unit is used to invert the NMR echo data of the shale oil sample to be tested, so as to obtain the pre-extraction NMR spectrum of the shale oil sample to be tested.

[0226] In some specific embodiments, the extraction nuclear magnetic resonance spectrum acquisition module 12 specifically includes:

[0227] The core sample acquisition unit is used to extract the shale oil sample to be tested using a pre-set dichloromethane solvent containing methanol and transfer the extract to obtain the corresponding core sample; the pre-set dichloromethane solvent containing methanol is a dichloromethane solvent containing methanol reagent with a volume percentage between 3% and 50%.

[0228] The extracted shale oil sample acquisition unit is used to perform low-temperature drying on the core sample and remove residual dichloromethane to obtain the corresponding extracted shale oil sample; the low-temperature drying is performed in an environment below 65 degrees Celsius.

[0229] The second nuclear magnetic resonance echo data acquisition unit is used to acquire the nuclear magnetic resonance echo data corresponding to the extracted shale oil sample based on the nuclear magnetic resonance technology.

[0230] The extraction nuclear magnetic resonance spectrum acquisition unit is used to invert the nuclear magnetic resonance echo data of the extracted shale oil sample to obtain the extraction nuclear magnetic resonance spectrum of the extracted shale oil sample.

[0231] In some specific embodiments, the rate of change determination module 13 specifically includes:

[0232] The T1 / T2 rate of change determination unit is used to determine the T1 / T2 rate of change of the relaxation peak value based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum; wherein T1 is the longitudinal relaxation time and T2 is the transverse relaxation time.

[0233] In some specific embodiments, the hydrogen composition determination module 14 specifically includes:

[0234] The rate of change range acquisition unit is used to acquire the current value of the rate of change of T1 / T2 and the preset rate of change range.

[0235] The hydrogen composition determination unit is used to determine the target interval corresponding to the current value from the range of change rate values, and to determine the hydrogen composition corresponding to the shale oil sample before and after extraction based on the target interval.

[0236] In some specific embodiments, the saturation determination module 15 specifically includes:

[0237] The first target correlation time determination unit is used to determine the target correlation time as the surface dwell time when the current value of the rate of change of the target interval T1 / T2 is less than or equal to 1; the target correlation time includes the surface dwell time and the translational correlation time;

[0238] The second target-related time determination unit is used to determine the target-related time as the surface dwell time when the current value of the rate of change of the target interval T1 / T2 is greater than 1 and less than 2.

[0239] The third target-related time determination unit is used to determine the target-related time as the surface dwell time when the current value of the rate of change of the target interval T1 / T2 is greater than 2 or equal to and less than 3.

[0240] The fourth target correlation time determination unit is used to determine the target correlation time as the translational correlation time when the current value of the rate of change of the target interval T1 / T2 is greater than or equal to 3 and less than 6.

[0241] The fifth target correlation time determination unit is used to determine the target correlation time as the translational correlation time when the current value of the rate of change of the target interval T1 / T2 is greater than or equal to 6.

[0242] The first correlation acquisition unit is used to acquire the first correlation between the target related time corresponding to the hydrogen component before extraction and the first target saturation information.

[0243] The second correlation acquisition unit is used to acquire the second correlation between the target correlation time and the second target saturation information corresponding to the extracted hydrogen component;

[0244] The relevant time ratio acquisition unit is used to acquire a relevant time ratio based on a preset relevant time correlation relationship, the first correlation relationship, and the second correlation relationship; the relevant time ratio relationship is the ratio of the surface dwell time to the translational correlation time;

[0245] The target correlation formula acquisition unit is used to acquire a target correlation formula based on the relevant time ratio relationship and a preset T1 / T2 change rate formula; the target correlation formula is a formula used to characterize the correlation between the T1 / T2 change rate and the target saturation.

[0246] The target saturation calculation unit is used to calculate the target saturation based on the current value of the rate of change of T1 / T2 and the target correlation formula.

[0247] In some specific embodiments, the sample property determination module 16 specifically includes:

[0248] The rate of change acquisition unit is used to acquire a first rate of change corresponding to a first shale oil sample to be tested and a second rate of change corresponding to a second shale oil sample to be tested; the first rate of change and the second rate of change are the rate of change of T1 / T2.

[0249] The rate of change interval determination unit is used to determine, based on a preset rate of change interval determination rule, a first rate of change interval corresponding to the first rate of change and a second rate of change interval corresponding to the second rate of change.

[0250] A saturation acquisition unit is used to acquire a first saturation corresponding to the first shale oil sample to be tested and a second saturation corresponding to the second shale oil sample to be tested; the first saturation and the second saturation are the saturation of the hydrogen component;

[0251] The first rate of change equality determination unit is used to determine whether the first rate of change is equal to the second rate of change when the first rate of change interval and the second rate of change interval are the same interval, and the rate of change of the first rate of change interval is less than or equal to 1 for T1 / T2.

[0252] The first saturation comparison unit is used to compare the first saturation with the second saturation when the first rate of change is equal to the second rate of change.

[0253] The first fluidity determination unit is used to determine that the shale oil sample fluid with the larger saturation value between the first saturation and the second saturation is more fluid; the first saturation and the second saturation are the oil saturation in the first shale oil sample and the second shale oil sample, respectively.

[0254] The second fluidity determination unit is used to determine that the fluid of the shale oil sample with the larger change rate value between the first change rate and the second change rate is less fluid when the first change rate is not equal to the second change rate.

[0255] The second rate of change equality judgment unit is used to determine whether the first rate of change is equal to the second rate of change when the first rate of change interval and the second rate of change interval are the same interval, and the rate of change of the first rate of change interval is greater than 1 and less than 6 for T1 / T2.

[0256] The second saturation comparison unit is used to compare the first saturation with the second saturation when the first rate of change is equal to the second rate of change.

[0257] The third fluidity determination unit is used to determine that the fluid of the shale oil sample to be tested with the smaller saturation value between the first saturation and the second saturation is more fluid; the first saturation and the second saturation are the water saturation in the first shale oil sample to be tested and the second shale oil sample to be tested.

[0258] The fourth fluidity determination unit is used to determine that the fluid of the shale oil sample to be tested, which has a smaller value between the first rate of change and the second rate of change, is less fluid when the first rate of change is not equal to the second rate of change.

[0259] The third rate of change equality judgment unit is used to determine whether the first rate of change is equal to the second rate of change when the first rate of change interval and the second rate of change interval are the same interval, and the rate of change of the first rate of change interval is greater than or equal to 6 for T1 / T2.

[0260] The fifth fluidity determination unit is used to compare the first saturation with the second saturation when the first rate of change is equal to the second rate of change, and determine that the shale oil sample to be tested with the smaller saturation value between the first saturation and the second saturation has stronger fluidity; the first saturation and the second saturation are the water saturation in the first shale oil sample to be tested and the second shale oil sample to be tested, respectively.

[0261] The sixth fluidity determination unit is used to determine that the shale oil sample to be tested with the smaller value of the first change rate and the second change rate has weaker fluidity when the first change rate is not equal to the second change rate.

[0262] The seventh fluidity determination unit is used to determine that when the first rate of change interval and the second rate of change interval are different intervals, the fluidity of the shale oil sample fluid with a higher lower boundary threshold between the first rate of change interval and the second rate of change interval is stronger.

[0263] The oil wetting determination unit is used to determine that the pores of the shale oil sample to be tested are oil-wetted when the rate of change of T1 / T2 is less than 2.

[0264] A water wetting determination unit is used to determine that the pores of the shale oil sample to be tested are water-wetted when the rate of change of T1 / T2 is greater than or equal to 6.

[0265] The mixed wetting determination unit is used to determine that the pores of the shale oil sample to be tested are mixed-wetting when the rate of change of T1 / T2 is greater than or equal to 2 and less than 6.

[0266] A water-biased wetting determination unit is used to determine the shale oil sample to be tested as water-biased when the shale oil sample to be tested is mixed-wetting, based on the higher value of the first change rate and the second change rate.

[0267] The biased oil wetting determination unit is used to determine the shale oil sample to be tested as biased oil wetting when the shale oil sample to be tested is mixed-wetting, based on the lower value of the first change rate and the second change rate.

[0268] Furthermore, embodiments of this application also provide an electronic device. Figure 7 This is a structural diagram of an electronic device 20 according to an exemplary embodiment. The content of the diagram should not be construed as limiting the scope of this application.

[0269] Figure 7This is a schematic diagram of the structure of an electronic device 20 provided in an embodiment of this application. Specifically, the electronic device 20 may include: at least one processor 21, at least one memory 22, a power supply 23, a communication interface 24, an input / output interface 25, and a communication bus 26. The memory 22 stores a computer program, which is loaded and executed by the processor 21 to implement the relevant steps in the shale pore fluid saturation, flowability, and pore wettability measurement methods disclosed in any of the foregoing embodiments. Alternatively, the electronic device 20 in this embodiment may specifically be a computer.

[0270] In this embodiment, the power supply 23 is used to provide operating voltage for each hardware device on the electronic device 20; the communication interface 24 can create a data transmission channel between the electronic device 20 and external devices, and the communication protocol it follows can be any communication protocol applicable to the technical solution of this application, and is not specifically limited here; the input / output interface 25 is used to acquire external input data or output data to the outside world, and its specific interface type can be selected according to specific application needs, and is not specifically limited here.

[0271] In addition, the memory 22, as a carrier for resource storage, can be a read-only memory, random access memory, disk or optical disk, etc. The resources stored thereon can include operating system 221, computer program 222, etc., and the storage method can be temporary storage or permanent storage.

[0272] The operating system 221 is used to manage and control the various hardware devices on the electronic device 20 and the computer program 222, which may be Windows Server, Netware, Unix, Linux, etc. In addition to including a computer program capable of performing the shale pore fluid saturation, flowability, and pore wettability measurement methods disclosed in any of the foregoing embodiments, the computer program 222 may further include computer programs capable of performing other specific tasks.

[0273] Furthermore, this application also discloses a storage medium storing a computer program. When the computer program is loaded and executed by a processor, it implements the steps of the shale pore fluid saturation, flowability, and pore wettability measurement method disclosed in any of the foregoing embodiments.

[0274] The various embodiments in this specification are described in a progressive manner, with each embodiment focusing on its differences from other embodiments. Similar or identical parts between embodiments can be referred to interchangeably. For the apparatus disclosed in the embodiments, since it corresponds to the method disclosed in the embodiments, the description is relatively simple; relevant parts can be referred to in the method section.

[0275] Finally, it should be noted that in this document, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

[0276] The above provides a detailed description of a method for measuring shale pore fluid saturation, flowability, and pore wettability provided by the present invention. Specific examples have been used to illustrate the principle and implementation of the present invention. The description of the above embodiments is only for the purpose of helping to understand the method and core idea of ​​the present invention. At the same time, for those skilled in the art, there will be changes in the specific implementation and application scope based on the idea of ​​the present invention. Therefore, the content of this specification should not be construed as a limitation of the present invention.

Claims

1. A method for measuring pore fluid saturation, flowability, and pore wettability in shale, characterized in that, include: Obtain a shale oil sample to be tested, and obtain the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested; A preset extraction operation is performed on the shale oil sample to be tested to obtain the extracted shale oil sample and the corresponding extracted nuclear magnetic resonance spectrum. The rate of change of the relaxation peak value T1 / T2 is determined based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum; where T1 is the longitudinal relaxation time and T2 is the transverse relaxation time. The hydrogen composition of the shale oil sample before and after extraction is determined based on the rate of change of T1 / T2, and the target saturation is determined based on the hydrogen composition and a preset saturation calculation method; the target saturation is the saturation of different hydrogen compositions in the shale oil sample before and after extraction. The fluid flowability and pore wettability of the shale oil sample to be tested are determined based on the target saturation, the rate of change of T1 / T2, and a preset property measurement method. The step of determining the hydrogen composition of the shale oil sample before and after extraction based on the rate of change of T1 / T2 includes: Obtain the current value of the rate of change of T1 / T2 and the preset range of the rate of change; Determine the target range corresponding to the current value from the range of the rate of change values, and determine the hydrogen composition corresponding to the shale oil sample before and after extraction based on the target range; The step of determining the target saturation based on the hydrogen composition and a preset saturation calculation method includes: The target-related time is determined based on the target interval; the target-related time includes surface dwell time and translational correlation time. Obtain a first correlation relationship between the target relevant time corresponding to the hydrogen component before extraction and the first target saturation information; Obtain a second correlation between the target-related time and the second target saturation information corresponding to the extracted hydrogen component; The relevant time ratio is obtained based on the preset relevant time correlation relationship, the first correlation relationship, and the second correlation relationship; the relevant time ratio relationship is the ratio of the surface dwell time to the translational correlation time; The target correlation formula is obtained based on the relevant time ratio relationship and the preset T1 / T2 change rate formula; the target correlation formula is a formula used to characterize the correlation between the T1 / T2 change rate and the target saturation. The target saturation is calculated based on the current value of the rate of change of T1 / T2 and the target correlation formula.

2. The method for measuring shale pore fluid saturation, flowability, and pore wettability according to claim 1, characterized in that, The process of obtaining the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested includes: Nuclear magnetic resonance (NMR) echo data of the shale oil sample to be tested were obtained using NMR technology. The nuclear magnetic resonance echo data of the shale oil sample to be tested are inverted to obtain the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested.

3. The method for measuring shale pore fluid saturation, flowability, and pore wettability according to claim 2, characterized in that, The step of performing a preset extraction operation on the shale oil sample to be tested to obtain the extracted shale oil sample and the corresponding extracted nuclear magnetic resonance spectrum includes: The shale oil sample to be tested was extracted using a pre-prepared dichloromethane solvent containing methanol, and the extract was transferred to obtain the corresponding core sample; the pre-prepared dichloromethane solvent containing methanol reagent with a volume percentage between 3% and 50% was a dichloromethane solvent. The core samples were dried at low temperature to remove residual dichloromethane, in order to obtain the corresponding extracted shale oil samples; the low temperature drying was carried out at an environment below 65 degrees Celsius. The nuclear magnetic resonance echo data corresponding to the extracted shale oil sample were obtained based on the nuclear magnetic resonance technology. The nuclear magnetic resonance echo data of the extracted shale oil sample are inverted to obtain the extracted nuclear magnetic resonance spectrum of the extracted shale oil sample.

4. The method for measuring shale pore fluid saturation, flowability, and pore wettability according to claim 1, characterized in that, Determining the target-related time based on the target interval includes: When the current value of the rate of change of T1 / T2 in the target interval is less than or equal to 1, the target related time is determined to be the surface dwell time. When the target interval is the current value of the rate of change of T1 / T2, which is greater than 1 and less than 2, the target related time is determined to be the surface dwell time. When the target interval is the current value of the rate of change of T1 / T2, which is greater than or equal to 2 and less than 3, the target related time is determined to be the surface dwell time. When the target interval is the current value of the rate of change of T1 / T2, which is greater than or equal to 3 and less than 6, the target correlation time is determined to be the translational correlation time. When the target interval is the current value of the rate of change of T1 / T2, which is greater than or equal to 6, the target correlation time is determined to be the translational correlation time.

5. The method for measuring shale pore fluid saturation, flowability, and pore wettability according to any one of claims 1 to 4, characterized in that, The determination of the fluid flowability and pore wettability of the shale oil sample based on the target saturation, the rate of change of T1 / T2, and a preset property measurement method includes: Obtain the first rate of change corresponding to the first shale oil sample to be tested and the second rate of change corresponding to the second shale oil sample to be tested; the first rate of change and the second rate of change are the rates of change of T1 / T2. The first rate of change interval corresponding to the first rate of change and the second rate of change interval corresponding to the second rate of change are determined based on the preset rate of change interval determination rules. Obtain the first saturation degree corresponding to the first shale oil sample to be tested and the second saturation degree corresponding to the second shale oil sample to be tested; the first saturation degree and the second saturation degree are the saturation degree of the hydrogen component; When the first rate of change interval and the second rate of change interval are the same interval, and the first rate of change interval is the rate of change of T1 / T2 less than or equal to 1, determine whether the first rate of change is equal to the second rate of change. When the first rate of change equals the second rate of change, the first saturation is compared with the second saturation, and it is determined that the shale oil sample with the larger saturation value between the first saturation and the second saturation has stronger fluidity; the first saturation and the second saturation are the oil saturation in the first shale oil sample and the second shale oil sample to be tested. When the first rate of change is not equal to the second rate of change, the shale oil sample to be tested with the larger change rate value between the first rate of change and the second rate of change is determined to have weaker fluidity. When the first rate of change interval and the second rate of change interval are the same interval, and the first rate of change interval is the rate of change of T1 / T2 greater than 1 and less than 6, determine whether the first rate of change is equal to the second rate of change. When the first rate of change equals the second rate of change, the first saturation is compared with the second saturation, and it is determined that the shale oil sample to be tested with the smaller saturation value between the first saturation and the second saturation has stronger fluidity; the first saturation and the second saturation are the water saturation in the first shale oil sample to be tested and the second shale oil sample to be tested mentioned above. When the first rate of change is not equal to the second rate of change, the shale oil sample to be tested with the smaller value of the first rate of change and the second rate of change is determined to have weaker fluidity. When the first rate of change interval and the second rate of change interval are the same interval, and the first rate of change interval is the rate of change of T1 / T2 greater than or equal to 6, determine whether the first rate of change is equal to the second rate of change. When the first rate of change equals the second rate of change, the first saturation is compared with the second saturation, and it is determined that the shale oil sample with the smaller saturation value between the first and second saturations has stronger fluidity; the first saturation and the second saturation are the water saturation in the first and second shale oil samples respectively. When the first rate of change is not equal to the second rate of change, the shale oil sample to be tested with the smaller value of the first rate of change and the second rate of change is determined to have weaker fluidity. When the first rate of change interval and the second rate of change interval are different intervals, the shale oil sample to be tested with a higher low boundary threshold in the first rate of change interval and the second rate of change interval has stronger fluidity. When the rate of change of T1 / T2 is less than 2, the pores of the shale oil sample to be tested are determined to be oil-wetted. When the rate of change of T1 / T2 is greater than or equal to 6, the pores of the shale oil sample to be tested are determined to be water-wetted. When the rate of change of T1 / T2 is greater than or equal to 2 and less than 6, the pores of the shale oil sample to be tested are determined to be mixed-wetting. When the shale oil sample to be tested is mixed-wetted, the pores of the shale oil sample to be tested with the higher value of the first change rate and the second change rate are determined to be water-wetted, and the pores of the shale oil sample to be tested with the lower value of the first change rate and the second change rate are determined to be oil-wetted.

6. A device for measuring the saturation, flowability, and wettability of shale pore fluids, characterized in that, include: The pre-extraction nuclear magnetic resonance spectrum acquisition module is used to acquire the shale oil sample to be tested and to acquire the pre-extraction nuclear magnetic resonance spectrum of the shale oil sample to be tested. The extraction nuclear magnetic resonance spectrum acquisition module is used to perform a preset extraction operation on the shale oil sample to be tested, so as to obtain the extracted shale oil sample and the corresponding extraction nuclear magnetic resonance spectrum. The rate of change determination module is used to determine the rate of change of the relaxation peak value T1 / T2 based on the pre-extraction NMR spectrum and the post-extraction NMR spectrum; where T1 is the longitudinal relaxation time and T2 is the transverse relaxation time. The hydrogen composition determination module is used to determine the hydrogen composition of the shale oil sample before and after extraction based on the rate of change of T1 / T2. The saturation determination module is used to determine the target saturation based on the hydrogen composition and a preset saturation calculation method; the target saturation is the saturation of different hydrogen components in the shale oil samples before and after extraction; The sample property determination module is used to determine the fluid flowability and pore wettability of the shale oil sample to be tested based on the target saturation, the rate of change of T1 / T2 and a preset property measurement method. The process of determining the hydrogen composition of the shale oil sample before and after extraction by the hydrogen composition determination module includes: obtaining the current value of the change rate of T1 / T2 and a preset change rate value range; determining the target range corresponding to the current value from the change rate value range; and determining the hydrogen composition of the shale oil sample before and after extraction based on the target range. The process of determining the target saturation through the saturation determination module includes: determining a target relevant time based on the target interval; the target relevant time includes surface dwell time and translational relevant time; obtaining a first correlation between the target relevant time corresponding to the hydrogen component before extraction and the first target saturation information; obtaining a second correlation between the target relevant time corresponding to the hydrogen component after extraction and the second target saturation information; obtaining a relevant time ratio relationship based on a preset relevant time correlation relationship, the first correlation relationship, and the second correlation relationship; the relevant time ratio relationship is the ratio of the surface dwell time to the translational relevant time; obtaining a target correlation formula based on the relevant time ratio relationship and a preset T1 / T2 change rate formula; the target correlation formula is a formula used to characterize the correlation between the T1 / T2 change rate and the target saturation; and calculating the target saturation based on the current value of the T1 / T2 change rate and the target correlation formula.

7. An electronic device, characterized in that, include: Memory, used to store computer programs; A processor is configured to execute the computer program to implement the steps of the method for measuring shale pore fluid saturation, flowability, and pore wettability as described in any one of claims 1 to 5.

8. A computer-readable storage medium, characterized in that, Used to store computer programs; wherein, when the computer programs are executed by a processor, they implement the method for measuring shale pore fluid saturation, flowability and pore wettability as described in any one of claims 1 to 5.

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