Method and system for representing shale oil sample occurrence state based on nuclear magnetic resonance

Abstract

The invention discloses a method and system for representing shale oil sample occurrence state based on nuclear magnetic resonance, and relates to the technical field of offshore shale oil exploration, and the method comprises the following steps: respectively obtaining a regular plunger shale sample and an irregular shale sample at the same sampling position in a target stratum; performing a nuclear magnetic resonance experiment on the irregular shale sample to obtain a nuclear magnetic signal of the irregular shale sample, performing inversion to obtain a T2 spectrum of the irregular shale sample, and determining an initial nuclear magnetic porosity; carrying out different equal cutting on the regular plunger shale sample, and sequentially carrying out nuclear magnetic resonance experiments to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosity; and determining a porosity correction coefficient based on the target fitting relationship and the initial nuclear magnetic porosity, and determining the porosity of the irregular shale sample to be measured based on the porosity correction coefficient. According to the method, the technical problem that the fluid occurrence state of the irregular shale sample is difficult to characterize due to scarcity of the shale oil sample on the sea in the prior art is solved.

Description

Technical Field

[0001] The present invention relates to the technical field of offshore shale oil exploration, and in particular to a method and system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance. Background Art

[0002] There are differences between marine shale and continental shale in five aspects, including pore structure, mineral composition, compressibility, storage depth and occurrence form. In terms of pore structure, the porosity of marine shale is about twice that of continental shale, and the proportion of macropores in marine shale is higher and the pore size distribution range is wider; the proportion of medium and small pores in continental shale is higher, and natural fractures and bedding are more developed. In terms of mineral composition, marine shale is mainly composed of brittle minerals such as quartz and feldspar, accounting for about 67.9%; continental shale has a high content of clay minerals, accounting for about 45.3%. The difference in compressibility is that the initiation pressure of marine shale is higher and the fracture network is relatively simple; the initiation pressure of continental shale is lower and the fracture network structure is better, but the low porosity, low permeability and high water sensitivity are not conducive to hydraulic fracturing reservoir transformation. In terms of storage depth, marine shale oil has a smaller storage depth than continental shale oil. Continental sedimentary basins are often affected by orogenic and faulting activities, and are unevenly distributed and scattered, with greater depths. Marine shale oil has a large distribution area, stable distribution, and shallow depth. From the perspective of occurrence form, marine shale is much less compacted than continental shale due to seawater pressure, and is even in a state of compacted diagenesis in some shallow sea layers. Continental shale has better compacted diagenesis, forming a more stable layered structure.

[0003] Since marine shales are mostly composed of felsic minerals, which are brittle minerals that are easier to fracture, and due to the presence of seawater pressure, their compaction degree is poorer than that of ordinary terrestrial shales. Therefore, it is usually difficult to obtain complete plunger samples during the sampling process, and most of the samples taken are broken samples from the same formation. However, traditional methods have difficulty in characterizing the fluid storage state of irregular shale samples. Summary of the invention

[0004] The purpose of the present invention is to provide a method and system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance in order to solve at least one of the above technical problems.

[0005] In a first aspect, an embodiment of the present invention provides a method for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance, comprising: respectively obtaining a regular plug shale sample and an irregular shale sample at the same sampling position in a target formation; performing a nuclear magnetic resonance experiment on the irregular shale sample to obtain a nuclear magnetic signal of the irregular shale sample and inverting it to obtain a T2 spectrum of the irregular shale sample; determining an initial nuclear magnetic porosity of the irregular shale sample based on the T2 spectrum of the irregular shale sample; cutting the regular plug shale sample into different equal parts and performing nuclear magnetic resonance experiments in sequence to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosities; determining a porosity correction coefficient based on the target fitting relationship and the initial nuclear magnetic porosity; determining the porosity of the irregular shale sample to be tested in the target formation based on the porosity correction coefficient, and characterizing the occurrence state of the target formation based on the porosity.

[0006] Furthermore, the regular plug shale sample is cut into different equal parts and nuclear magnetic resonance experiments are performed in sequence to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosities, including: performing a nuclear magnetic resonance experiment on the regular plug shale sample to obtain a nuclear magnetic signal under the initial surface area of ​​the regular plug shale sample; based on the nuclear magnetic signal under the initial surface area, determining the nuclear magnetic porosity corresponding to the initial surface area; performing an initial cutting on the regular plug shale sample to obtain an initial cutting sample; performing a nuclear magnetic resonance experiment on the initial cutting sample to obtain a nuclear magnetic signal under the initial cutting surface area, and determining the corresponding nuclear magnetic porosity; repeatedly performing cutting and nuclear magnetic resonance experiments on the regular plug shale sample to obtain nuclear magnetic porosities under different cutting surface areas in sequence; fitting different cutting surface areas and corresponding nuclear magnetic porosities based on a preset functional relationship to obtain the target fitting relationship.

[0007] Further, based on the nuclear magnetic signal under the initial surface, determining the nuclear magnetic porosity corresponding to the initial surface area includes: inverting the nuclear magnetic signal under the initial surface area to obtain the transverse relaxation time; based on the target relationship between the transverse relaxation time and the porosity, determining the nuclear magnetic porosity corresponding to the initial surface area; wherein the target relationship includes:

[0008]

[0009] Wherein, T2 is the transverse relaxation time, ρ is the transverse surface relaxation intensity, F is the geometric shape factor, and r is the pore throat radius.

[0010] Furthermore, based on the target fitting relationship and the initial nuclear magnetic porosity, a porosity correction coefficient is determined, including: fitting the surface area of ​​a regular plug-shaped structure based on the volume of the irregular shale sample, and determining the fitted nuclear magnetic porosity of the irregular shale sample based on the target fitting relationship; and determining the porosity correction coefficient based on the initial nuclear magnetic porosity and the fitted nuclear magnetic porosity.

[0011] Furthermore, the method further includes: determining the volume of the irregular shale sample based on a water displacement method.

[0012] Furthermore, based on the porosity correction coefficient, the porosity of the irregular shale sample to be tested in the target formation is determined, including: performing a nuclear magnetic resonance experiment on the irregular shale sample to be tested to obtain the experimental porosity of the irregular shale sample to be tested; and correcting the experimental porosity based on the porosity correction coefficient to obtain the porosity of the irregular shale sample to be tested.

[0013] In a second aspect, an embodiment of the present invention further provides a system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance, comprising: an acquisition module, an inversion module, a first determination module, an experimental module, a second determination module and a correction module; wherein the acquisition module is used to respectively acquire regular plunger shale samples and irregular shale samples at the same sampling position in the target formation; the inversion module is used to perform a nuclear magnetic resonance experiment on the irregular shale sample to obtain the nuclear magnetic signal of the irregular shale sample and perform inversion to obtain the T2 spectrum of the irregular shale sample; the first determination module is used to determine the irregular shale sample based on the irregular shale sample. The method comprises the following steps: first, determining the initial nuclear magnetic porosity of the irregular shale sample by using a T2 spectrum; second, determining the porosity of the irregular shale sample by using a T2 spectrum; the experimental module is used to cut the regular plug shale sample into different equal parts and perform nuclear magnetic resonance experiments in sequence to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosities; the second determination module is used to determine a porosity correction coefficient based on the target fitting relationship and the initial nuclear magnetic porosity; the correction module is used to determine the porosity of the irregular shale sample to be tested in the target formation based on the porosity correction coefficient, and characterize the occurrence state of the target formation based on the porosity.

[0014] Furthermore, the experimental module is also used to: perform a nuclear magnetic resonance experiment on the regular plug shale sample to obtain a nuclear magnetic signal under the initial surface area of ​​the regular plug shale sample; determine the nuclear magnetic porosity corresponding to the initial surface area based on the nuclear magnetic signal under the initial surface area; perform an initial cutting on the regular plug shale sample to obtain an initial cutting sample; perform a nuclear magnetic resonance experiment on the initial cutting sample to obtain a nuclear magnetic signal under the initial cutting surface area, and determine the corresponding nuclear magnetic porosity; repeat the cutting and nuclear magnetic resonance experiment on the regular plug shale sample to obtain the nuclear magnetic porosity under different cutting surface areas in turn; fit different cutting surface areas and corresponding nuclear magnetic porosities based on a preset functional relationship to obtain the target fitting relationship.

[0015] In a third aspect, an embodiment of the present invention further provides an electronic device, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided by the present invention when executing the computer program.

[0016] In a fourth aspect, an embodiment of the present invention further provides a computer-readable storage medium, wherein the computer-readable storage medium stores computer instructions, and when the computer instructions are executed by a processor, the method provided by the present invention is implemented.

[0017] The present invention provides a method and system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance. The method uses the nuclear magnetic parameters between nuclear magnetic signals of cores divided into different equal parts and a complete sample to determine a data correction coefficient, and can accurately restore the signal of the core fragments, and more accurately predict the state of the core samples under the original formation state, so as to support the exploration and development of marine shale oil and achieve accurate characterization of the occurrence state of the fluid, thereby alleviating the technical problem in the prior art that it is difficult to characterize the occurrence state of the fluid in irregular shale samples due to the scarcity of offshore shale oil samples. BRIEF DESCRIPTION OF THE DRAWINGS

[0018] In order to more clearly illustrate the implementation methods of the present application or the technical solutions in the prior art, the drawings required for use in the specific implementation methods or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are some implementation methods of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0019] Figure 1 A flow chart of a method for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance provided in an embodiment of the present invention;

[0020] Figure 2 A nuclear magnetic resonance experimental model diagram of an irregular shale sample and a plunger shale sample provided in an embodiment of the present invention;

[0021] Figure 3 A schematic diagram of a saturation recovery acquisition sequence provided by an embodiment of the present invention;

[0022] Figure 4 A schematic diagram of an inversion recovery acquisition sequence provided by an embodiment of the present invention;

[0023] Figure 5 A schematic diagram of the relationship between echo interval and signal amplitude provided by an embodiment of the present invention;

[0024] Figure 6 A schematic diagram of the relationship between the number of echoes and signal amplitude provided by an embodiment of the present invention;

[0025] Figure 7 A schematic diagram of the relationship between the number of scans and the signal-to-noise ratio provided in an embodiment of the present invention;

[0026] Figure 8 A schematic diagram of the relationship between waiting time and signal amplitude provided by an embodiment of the present invention;

[0027] Fig. 9 A schematic diagram of inversion signals of a plunger shale sample nuclear magnetic signal and an irregular shale sample nuclear magnetic signal provided in an embodiment of the present invention;

[0028] Fig.10 A schematic diagram of a corrected T2 spectrum provided in an embodiment of the present invention;

[0029] Fig.11 A schematic diagram of the nuclear magnetic porosity of an original plunger sample provided in an embodiment of the present invention;

[0030] Fig.12 A schematic diagram of the nuclear magnetic porosity of a two-part plunger sample provided in an embodiment of the present invention;

[0031] Fig.13 A schematic diagram of the nuclear magnetic porosity of a plunger sample divided into three equal parts provided in an embodiment of the present invention;

[0032] Fig.14 A schematic diagram of the nuclear magnetic porosity of a four-equally divided plunger sample provided in an embodiment of the present invention;

[0033] Fig.15 A schematic diagram of the nuclear magnetic porosity of an eight-part plunger sample provided in an embodiment of the present invention;

[0034] Fig.16 A schematic diagram of the nuclear magnetic porosity of a sixteen-equally divided plunger sample provided in an embodiment of the present invention;

[0035] Fig.17A schematic diagram of the fitting relationship between different cutting surface areas and corresponding nuclear magnetic porosity provided in an embodiment of the present invention;

[0036] Fig.18 A schematic diagram of a system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance provided in an embodiment of the present invention. DETAILED DESCRIPTION

[0037] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0038] First, the basic principles of nuclear magnetic resonance are introduced as follows:

[0039] (1) Principle of nuclear magnetic resonance. When a shale reservoir core containing fluid (oil or water) is placed in the static magnetic field of a nuclear magnetic resonance device, the protons in the fluid are polarized by the magnetic field. If a radio frequency pulse of a certain frequency is applied in the vertical direction of the magnetic field, a nuclear magnetic resonance signal will be generated. The collected rock fluid nuclear magnetic resonance signal is mathematically inverted to obtain the core T2 relaxation time spectrum. The horizontal axis of the T2 spectrum represents the T2 relaxation time, and the vertical axis represents the proportion of different relaxation time components in the core.

[0040] (2) Echo sequence. The most commonly used echo sequence is the CPMG sequence, that is, after the initial 90° pulse, a series of 180° pulses are repeated every 2τ to produce multiple echoes. The time required for the spin axis to return to its original state is defined as the relaxation time. According to different physical meanings, the relaxation time can be divided into longitudinal relaxation time (T1) and transverse relaxation time (T2). Since the measurement speed of the nuclear magnetic resonance experiment is fast and the test time of the longitudinal relaxation time T1 is relatively long, the transverse relaxation time T2 is often used in the test process to characterize the occurrence characteristics of the porous medium fluid.

[0041] (3) Transverse relaxation. Relaxation refers to the phenomenon that when protons resonate and are in a high-energy state under the action of a radio frequency pulse, they will quickly return to their original low-energy state after the radio frequency pulse stops. Under the action of the radio frequency pulse, all protons have the same phase. They are all arranged in the same direction and precess around the external magnetic field at the same angular velocity (or angular frequency). When the radio frequency pulse stops, protons with the same phase will gradually have a phase difference with each other, that is, they lose phase. The protons gradually disperse from the same phase and are eventually evenly distributed. The macroscopic manifestation is that the process in which the transverse magnetization intensity vector gradually decays from the maximum to 0 is called the transverse relaxation process, and the time required for this process is the transverse relaxation time.

[0042] The transverse relaxation time T2 is mainly composed of the volume relaxation time T B , diffusion relaxation time T S and surface relaxation time T D Composition, formula:

[0043]

[0044] According to the principle of nuclear magnetic resonance, the volume relaxation time T in the above formula B Much longer than the surface relaxation time and diffusion relaxation time, the volume relaxation time of free water is T B Generally, it is 3000ms, which makes the first term on the right side of the above formula much smaller than the other two terms and can be ignored. Therefore, the above formula can be simplified to:

[0045]

[0046] Generally, indoor nuclear magnetic instruments use a uniform magnetic field. At this time, the magnetic field gradient G is considered to be zero, so the second term on the right side of the above formula can be ignored. At this time, the formula is

[0047]

[0048] Where S is the total surface area of ​​rock pores, um 2 ; ρ is the transverse surface relaxation strength of the rock, um / ms; V is the pore volume, um 3 ; F is the geometric shape factor, F = 3 for spherical pores, F = 2 for cylindrical pipes; r is the pore throat radius, um, T E is the echo interval.

[0049] The transverse relaxation time T2 is negatively correlated with the specific surface area and positively correlated with the pore size: the larger the specific surface area, the smaller the T2 relaxation time; the smaller the pore size, the smaller the T2 relaxation time. The total amount of pore fluid in the sample determines the strength of the NMR signal and can reflect the porosity characteristics of the saturated rock sample; the magnitude of the force exerted by the rock surface on the pore fluid can also determine the length of the T2 relaxation time. The smaller the force, the longer the T2 relaxation time.

[0050] However, due to the limitation of current technology, the magnet in the nuclear magnetic instrument cannot be an ideal uniform magnetic field. There is always a certain magnetic field gradient G in the magnet. Therefore, T E The increase in will increase the relaxation contribution caused by the diffusion of fluid molecules, resulting in a decrease in the total relaxation time T2, which will cause the nuclear magnetic T2 spectrum to shift to the left to a certain extent. In addition, a larger echo interval T EThis will cause the instrument to be unable to detect hydrogen nucleus signals with very short relaxation times in the core, such as clay bound water, microcapillary bound water, etc. Because the water in small pores has a very short relaxation time, if the echo interval is set too long, the fluid signals in these small pores will have completed relaxation before the instrument has fully responded, and naturally their relaxation signals cannot be detected.

[0051] (4) Two-dimensional nuclear magnetic resonance. T1-T2 two-dimensional nuclear magnetic resonance simultaneously detects the T1 and T2 of the object being measured. When the NMR system is fixed, for a single fluid, the relaxation of hydrogen nuclei follows the BPP (Bloembergen Purcell Pound) formula, which is the effect of dipole-dipole interaction on the relaxation rate:

[0052]

[0053] Where ω is the angular frequency, γ is the gyromagnetic ratio, μ0 is the vacuum permeability, is Planck's constant, I is the spin quantum number (for hydrogen nuclei, I = 1 / 2), r is the distance between protons, τ c is the molecular spin correlation time.

[0054] The relaxation time is dependent on the magnetic field strength. As the field strength increases, the relaxation rate slows down. The transverse relaxation T2 is mainly affected by the molecular spin correlation time τ c In the field of oil and gas exploration, the observation object is a multi-component complex fluid, and the T1-T2 two-dimensional nuclear magnetic resonance spectrum can be measured by adopting different observation methods.

[0055] A relatively simple and easy-to-implement method is to collect multiple groups of CPMG (Carr-Purcell-Meiboom-Gill) echo trains with different waiting times (Tw). The attenuation of the echo signal is affected by two factors, Tw and the acquisition time t. The amplitude of the echo train attenuates with the two factors as follows:

[0056]

[0057] Among them, b is is the i-th echo after waiting time T ws The echo amplitude at time t is m, and m is the transverse relaxation time T 2j The number of, p is the longitudinal relaxation time T 1r The number of jr is about the transverse relaxation time T 2j , the longitudinal relaxation time is T 1r The two-dimensional distribution function of hydrogen nuclei at is For noise.

[0058] c is a constant coefficient related to the T1-T2 acquisition mode. For T1 dimension acquisition, when the saturation recovery method is used, c = 1; when the inversion recovery method is used, c = 2. Perform a two-dimensional inversion on the above formula to obtain f jr , we can get the T1-T2 two-dimensional distribution.

[0059] Embodiment 1

[0060] Figure 1 1 is a flow chart of a method for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance according to an embodiment of the present invention. Figure 1 As shown, the method specifically comprises the following steps:

[0061] Step S102, respectively obtaining a regular plug shale sample and an irregular shale sample at the same sampling position in the target formation.

[0062] Step S104, performing a nuclear magnetic resonance experiment on the irregular shale sample to obtain a nuclear magnetic resonance signal of the irregular shale sample and inverting the signal to obtain a T2 spectrum of the irregular shale sample.

[0063] Specifically, the irregular shale sample is placed in a fixed container without hydrogen signal and a nuclear magnetic resonance experiment is carried out.

[0064] Step S106, determining the initial nuclear magnetic porosity of the irregular shale sample based on the T2 spectrum of the irregular shale sample.

[0065] Specifically, the initial nuclear magnetic porosity is determined based on the target relationship between the transverse relaxation time and the porosity; wherein the target relationship includes:

[0066]

[0067] Where T2 is the transverse relaxation time, ρ is the transverse surface relaxation intensity, F is the geometric shape factor, and r is the pore throat radius.

[0068] Step S108, cutting the regular plug shale sample into different equal parts and performing nuclear magnetic resonance experiments in sequence to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosity.

[0069] Step S110, determining a porosity correction coefficient based on the target fitting relationship and the initial NMR porosity.

[0070] Step S112, based on the porosity correction coefficient, determine the porosity of the irregular shale sample to be tested in the target formation, and characterize the occurrence state of the target formation based on the porosity.

[0071] Figure 2 1 is a nuclear magnetic resonance experimental model diagram of an irregular shale sample and a plunger shale sample provided according to an embodiment of the present invention. Figure 2 As shown in the left figure, the offshore scarce irregular shale oil sample is placed in a plastic container without hydrogen signal, and then placed in the magnetic field generated by the nuclear magnetic resonance instrument to complete the polarization process. The radio frequency signal is transmitted to the container containing the sample to be tested, and the generated echo signal is collected for echo signal inversion. For the transverse relaxation time, the CPMG pulse sequence with optimized parameters is selected.

[0072] Figure 3 is a schematic diagram of a saturation recovery acquisition sequence provided according to an embodiment of the present invention, such as Figure 3 As shown, for the longitudinal relaxation time, in the T1 dimension, the magnetization vector range of the saturation recovery method is (0, M0). Figure 4 is a schematic diagram of an inversion recovery acquisition sequence provided according to an embodiment of the present invention, such as Figure 4 As shown, the magnetization vector range of the inversion recovery method is (-M0, M0). According to the test results, the signal-to-noise ratio of the inversion recovery method is better, and the accuracy of the measured short relaxation component information is higher. Therefore, the present invention preferably measures an inversion recovery pulse sequence with higher accuracy of short relaxation component signals. For the echo signal inversion algorithm, the penalty function method (BRD), the singular value decomposition algorithm (SVD), the joint iterative reconstruction algorithm (SIRT) and the improved methods based on these algorithms, the present invention does not make any limiting requirements.

[0073] Figure 5 is a schematic diagram of the relationship between echo interval and signal amplitude provided according to an embodiment of the present invention, Figure 6 is a schematic diagram of the relationship between the number of echoes and the signal amplitude provided according to an embodiment of the present invention, Figure 7 is a schematic diagram of the relationship between the number of scans and the signal-to-noise ratio provided according to an embodiment of the present invention. Figure 8 FIG. 1 is a schematic diagram of the relationship between waiting time and signal amplitude according to an embodiment of the present invention. Figure 5-Figure 8 As shown, in the embodiment of the present invention, for irregular shale samples, the method for determining the acquisition parameter threshold is as follows:

[0074] ① The echo time interval TE setting range is 0.06ms~0.50ms. Inversion is performed based on the collected nuclear magnetic resonance signal echo data. Figure 5 As shown, with the echo interval T E As the short relaxation signal peak of the NMR spectrum gradually shifts to the right, and the signal amount gradually decreases, which causes the shorter relaxation components to gradually fail to be measured. Therefore, for NMR testing of low-porosity and low-permeability shale reservoir fluids, a shorter time interval T should be selected as much as possible. E The method provided in the embodiment of the present invention preferably adopts the time interval T E It is 0.06ms or 60us, thus realizing the accurate acquisition of micropore fluid signals in shale.

[0075] ② The setting range of echo number NECH is 1000~18000. Figure 6 As shown, the number of echoes can affect the attenuation degree of the spin echo train signal amplitude. When NECH is small, the CPMG spin echo train signal amplitude cannot be completely attenuated, making it difficult to effectively characterize the large-porosity fluid distribution. Since some of the samples measured belong to unconventional offshore shales, other experiments have confirmed the existence of microcracks and some large pores. At the same time, shale gas may exist in the shale plugs collected from deep layers. A larger number of echoes can ensure that the fluid in the large pores and the existing shale gas echo train signals can be completely attenuated. Therefore, the method provided in the embodiment of the present invention preferably uses an echo number NECH of 18,000.

[0076] ③ The setting range of echo group number or scanning number NS is 8 to 256. Figure 7 As shown, when the shale sample plunger is placed in a nuclear magnetic resonance instrument for testing, noise signals will be generated due to the nuclear magnetic resonance instrument when emitting signals and the instrument itself. Accurately identifying the state of occurrence of the fluid in the plunger requires that the proportion of these noise signals be minimized and the signal-to-noise ratio of the data be maximized. Therefore, the method provided in an embodiment of the present invention increases the number of scans to reduce the impact of noise signals as much as possible, thereby increasing the accuracy of signal detection. However, too many scans will reduce the efficiency of nuclear magnetic resonance detection, and at the same time, the nuclear magnetic resonance instrument will be overheated, which may cause inaccurate signals. From the perspective of improving the signal-to-noise ratio and saving time to increase efficiency, the scan number threshold is found to achieve the rapidity and accuracy of nuclear magnetic signal detection. Therefore, the method provided in an embodiment of the present invention preferably uses 64 scans.

[0077] ④ The setting range of waiting time TW is 3000~10000ms. Figure 8 As shown, in a magnetic field, the hydrogen nuclei in the shale sample are polarized to emit echo signals. For conventional sandstone reservoirs, the pores of the plunger sample are relatively large. After a short waiting time, the hydrogen nuclei in the magnetic field can be restored to the initial polarization state. For unconventional shale reservoirs, a shorter waiting time will cause the hydrogen nuclei in the magnetic field to be unable to fully restore to the initial polarization state, resulting in a decrease in signal amplitude. Therefore, the method provided in the embodiment of the present invention preferably adopts a waiting time setting of 10000ms to ensure that the hydrogen nuclei in the shale reservoir can be restored to the initial polarization state, thereby achieving the accuracy of the experimental test.

[0078] Fig. 9 1 is a schematic diagram of inversion signals of a plunger shale sample nuclear magnetic signal and an irregular shale sample nuclear magnetic signal according to an embodiment of the present invention. Fig. 9As shown in the figure, by comparing the echo inversion data of the regular plunger shale sample, it is found that the lateral echo time T2 is shifted to the left due to the enhanced surface relaxation of the irregular shale sample, the T2 cutoff value is reduced, and the echo signal of the irregular sample decays earlier. This affects the identification of fluid signals in different occurrence states. Through the following steps S1101 to S1122, the same block of samples is continuously divided into sections to correct the error caused by the increase in the surface area of ​​the broken samples.

[0079] Using the CPMG signal acquisition sequence, when t = (n + 1 / 2)TE, the phase is reversed, and the echo is collected when t = nTE. The normalized echo data can be expressed as:

[0080]

[0081] Where N2(t) is the total number of particles that are not absorbed at time t, and N2(0) is the total number of particles at the initial time.

[0082] Specifically, first input the attenuated echo signal, use the iterative reconstruction method to invert the T2 spectrum, and normalize the spectrum peak position; determine the NMR signal quantity under the correction echo interval and echo number based on the NMR T2 spectrum correction formula, and determine the NMR signal quantity based on the normalized spectrum peak position of the corrected NMR T2 spectrum, and finally complete the correction process of irregular shale samples to obtain the correction coefficient. Among them, the echo interval TE has a greater impact on the NMR inversion signal of irregular samples, while the echo number NECH has a smaller impact. Fig.10 FIG. 1 is a schematic diagram of a corrected T2 spectrum according to an embodiment of the present invention. Fig.10 As shown in the figure, the T2 spectrum of the irregular shale sample inverted according to the correction coefficient is compared with the T2 spectrum of the standard plunger sample, and the corrected T2 spectrum is good. This correction method can effectively eliminate the influence caused by the increased relaxation of the irregular shale sample surface.

[0083] Specifically, step S108 also includes the following steps:

[0084] Step S1081, performing a nuclear magnetic resonance experiment on the regular plug shale sample to obtain a nuclear magnetic resonance signal under the initial surface area of ​​the regular plug shale sample;

[0085] Step S1082, determining the nuclear magnetic porosity corresponding to the initial surface area based on the nuclear magnetic signal under the initial surface area;

[0086] Specifically, the NMR signal under the initial surface area is inverted to obtain the transverse relaxation time;

[0087] Based on the target relationship between transverse relaxation time and porosity, the nuclear magnetic porosity corresponding to the initial surface area is determined; wherein the target relationship includes:

[0088]

[0089] Where T2 is the transverse relaxation time, ρ is the transverse surface relaxation intensity, F is the geometric shape factor, and r is the pore throat radius.

[0090] Step S1083, performing primary cutting on the regular plunger shale sample to obtain a primary cutting sample;

[0091] Step S1084, performing a nuclear magnetic resonance experiment on the primary cut sample to obtain a nuclear magnetic resonance signal under the primary cut surface area, and determining the corresponding nuclear magnetic resonance porosity;

[0092] Step S1085, repeatedly cutting and performing NMR experiments on the regular plug shale sample to obtain NMR porosities at different cutting surface areas in turn;

[0093] Step S1086, fitting different cutting surface areas and corresponding NMR porosities based on a preset functional relationship to obtain a target fitting relationship.

[0094] Fig.11 is a schematic diagram of the nuclear magnetic porosity of an original plunger sample provided in an embodiment of the present invention, Fig.12 is a schematic diagram of the nuclear magnetic porosity of a bisected plunger sample provided in an embodiment of the present invention, Fig.13 is a schematic diagram of the nuclear magnetic porosity of a plunger sample divided into three equal parts according to an embodiment of the present invention, Fig.14 is a schematic diagram of the nuclear magnetic porosity of a four-divided plunger sample provided in an embodiment of the present invention, Fig.15 is a schematic diagram of the nuclear magnetic porosity of an eight-divided plunger sample provided in an embodiment of the present invention, Fig.16 Schematic diagram of the nuclear magnetic porosity of a sixteen-equally divided plunger sample provided according to an embodiment of the present invention.

[0095] like Figure 11-Figure 16 As shown in the figure, for the same batch of samples, a complete plunger sample is selected, and it is cut by wire cutting and then subjected to NMR testing. It can be found that with the increase in the number of sample cutting times, the sample porosity decreases relatively; the sum of the NMR porosities of the complete plunger sample and the cut plunger sample is fitted, and a functional relationship can be fitted, which is the target fitting relationship. Fig.17 1 is a schematic diagram of the fitting relationship between different cutting surface areas and corresponding nuclear magnetic porosity provided according to an embodiment of the present invention. Fig.17 As shown, the target fitting relationship is a linear fitting relationship.

[0096] Specifically, the formula used to calculate the surface area of ​​the plunger sample is as follows:

[0097] S=2πr 2+πdl+2nπr 2 +2mdl

[0098] S is the plunger area after cutting, cm 2 ; r is the original plunger radius, cm; d is the original plunger diameter, cm; l is the original plunger length, cm; n is the number of transverse cuts along the plunger; m is the number of longitudinal cuts along the plunger (cutting through the center of the circle).

[0099] In an optional implementation provided by the embodiment of the present invention, Figure 11-Figure 16 As shown, the uncut complete plunger sample is 4 cm long and 2.5 cm in diameter, so its surface area is 17.6625 cm 2 The porosity was measured to be 0.683%; the surface area of ​​the sample cut once was tested to be 27.475cm 2 The porosity was measured to be 0.677%; the surface area of ​​the sample cut twice was tested to be 37.2875cm 2 The porosity was measured to be 0.667%; the surface area of ​​the sample cut three times was tested to be 47.1cm 2 The porosity was measured to be 0.655%; the surface area of ​​the sample cut four times was tested to be 67.1cm 2 The porosity was measured to be 0.641%; the surface area of ​​the sample cut five times was tested to be 87.1cm 2 , its porosity was measured to be 0.626%; Fig.17 As shown, the target fitting relationship for point casting is: y=-0.0008x+0.698.

[0100] Specifically, step S110 also includes the following steps:

[0101] Step S1101, fitting the surface area of ​​a regular plug-shaped structure based on the volume of the irregular shale sample, and determining the fitting nuclear magnetic porosity of the irregular shale sample based on the target fitting relationship

[0102] Optionally, in an embodiment of the present invention, the volume of the irregular shale sample is determined based on the drainage method. After the volume of the irregular shale sample is determined, the surface area of ​​a regular plug sample with the same volume is fitted, wherein the bottom area of ​​the fitted regular plug sample is the same as the bottom area of ​​the plug shale sample used to determine the target fitting relationship. The fitted surface area is brought into the target fitting relationship to obtain the fitted nuclear magnetic porosity of the irregular shale sample.

[0103] Step S1102, determining a porosity correction coefficient based on the initial NMR porosity and the fitted NMR porosity.

[0104] Specifically, step S112 also includes the following steps:

[0105] Step S1121, performing a nuclear magnetic resonance experiment on the irregular shale sample to be tested to obtain the experimental porosity of the irregular shale sample to be tested;

[0106] Step S1122, correcting the experimental porosity based on the porosity correction coefficient to obtain the porosity of the irregular shale sample to be tested.

[0107] From the above description, it can be seen that the present invention provides a method for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance. The data correction coefficient is determined by using the nuclear magnetic parameters between the nuclear magnetic signals of cores divided into different equal parts and the complete sample. The signal of the core fragments can be accurately restored, and the state of the core samples under the original formation state can be more accurately predicted to support the exploration and development of marine shale oil, and to achieve accurate characterization of the occurrence state of the fluid. This alleviates the technical problem in the prior art that it is difficult to characterize the occurrence state of the fluid in irregular shale samples due to the scarcity of offshore shale oil samples.

[0108] Embodiment 2

[0109] Fig.18 Schematic diagram of a system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance according to an embodiment of the present invention. Fig.18 As shown, the system includes: an acquisition module 10, an inversion module 20, a first determination module 30, an experimental module 40, a second determination module 50 and a correction module 60.

[0110] Specifically, the acquisition module 10 is used to respectively acquire a regular plug shale sample and an irregular shale sample at the same sampling position in the target formation;

[0111] The inversion module 20 is used to perform a nuclear magnetic resonance experiment on the irregular shale sample, obtain the nuclear magnetic resonance signal of the irregular shale sample and perform inversion to obtain the T2 spectrum of the irregular shale sample;

[0112] A first determination module 30 is used to determine the initial nuclear magnetic porosity of the irregular shale sample based on the T2 spectrum of the irregular shale sample;

[0113] Experimental module 40, for cutting the regular plug shale sample into different equal parts and performing nuclear magnetic resonance experiments in sequence, to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosity;

[0114] A second determination module 50 is used to determine a porosity correction coefficient based on the target fitting relationship and the initial nuclear magnetic porosity;

[0115] The correction module 60 is used to determine the porosity of the irregular shale sample to be tested in the target formation based on the porosity correction coefficient, and to characterize the occurrence state of the target formation based on the porosity.

[0116] Specifically, the experimental module 40 is also used for:

[0117] A nuclear magnetic resonance experiment is conducted on the regular plug shale sample to obtain the nuclear magnetic signal under the initial surface area of ​​the regular plug shale sample;

[0118] Based on the nuclear magnetic signal under the initial surface area, the nuclear magnetic porosity corresponding to the initial surface area is determined;

[0119] Performing primary cutting on the regular plunger shale sample to obtain a primary cutting sample;

[0120] Performing NMR experiments on the primary cut samples to obtain NMR signals under the primary cut surface area and determine the corresponding NMR porosity;

[0121] Cutting and NMR experiments were repeated on regular plug shale samples to obtain NMR porosity at different cutting surface areas.

[0122] Based on the preset functional relationship, different cutting surface areas and corresponding NMR porosities are fitted to obtain the target fitting relationship.

[0123] The present invention further provides an electronic device, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided in the embodiment of the present invention when executing the computer program.

[0124] The present invention also provides a computer-readable storage medium, which stores computer instructions. When the computer instructions are executed by a processor, the method provided in the embodiment of the present invention is implemented.

[0125] It will be apparent to those skilled in the art that the invention is not limited to the details of the exemplary embodiments described above and that the invention can be implemented in other specific forms without departing from the spirit or essential features of the invention. Therefore, the embodiments should be considered exemplary and non-limiting in all respects, and the scope of the invention is defined by the appended claims rather than the foregoing description, and it is intended that all variations falling within the meaning and scope of the equivalent elements of the claims be included in the invention. Any reference numeral in a claim should not be considered as limiting the claim to which it relates.

[0126] In addition, it should be understood that although the present specification is described according to implementation modes, not every implementation mode contains only one independent technical solution. This description of the specification is only for the sake of clarity. Those skilled in the art should regard the specification as a whole. The technical solutions in each embodiment may also be appropriately combined to form other implementation modes that can be understood by those skilled in the art.

Claims

1. A method for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance, characterized in that: include: Obtaining regular plug shale samples and irregular shale samples at the same sampling position in the target formation respectively; Performing a nuclear magnetic resonance experiment on the irregular shale sample to obtain a nuclear magnetic resonance signal of the irregular shale sample and inverting the signal to obtain a T2 spectrum of the irregular shale sample; Determining the initial nuclear magnetic porosity of the irregular shale sample based on the T2 spectrum of the irregular shale sample; The regular plug shale sample is cut into different equal parts and subjected to nuclear magnetic resonance experiments in sequence to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosity; Determining a porosity correction coefficient based on the target fitting relationship and the initial nuclear magnetic porosity; Based on the porosity correction coefficient, the porosity of the irregular shale sample to be tested in the target formation is determined, and the occurrence state of the target formation is characterized based on the porosity.

2. The method according to claim 1, characterized in that: The regular plug shale samples are cut into different equal parts and subjected to nuclear magnetic resonance experiments in sequence to obtain target fitting relationships between different core surface areas and nuclear magnetic porosity, including: Performing a nuclear magnetic resonance experiment on the regular plug shale sample to obtain a nuclear magnetic resonance signal under the initial surface area of ​​the regular plug shale sample; Determining the nuclear magnetic porosity corresponding to the initial surface area based on the nuclear magnetic signal under the initial surface area; Performing a primary cutting on the regular plunger shale sample to obtain a primary cutting sample; Performing a nuclear magnetic resonance experiment on the primary cut sample to obtain a nuclear magnetic resonance signal under the primary cut surface area, and determining the corresponding nuclear magnetic resonance porosity; Repeat cutting and NMR experiments on the regular plug shale sample to obtain NMR porosities at different cutting surface areas; Different cut surface areas and corresponding nuclear magnetic porosities are fitted based on a preset functional relationship to obtain the target fitting relationship.

3. The method according to claim 2, characterized in that: Determining the nuclear magnetic porosity corresponding to the initial surface area based on the nuclear magnetic signal under the initial surface includes: Inverting the nuclear magnetic signal under the initial surface area to obtain the transverse relaxation time; Based on the target relationship between transverse relaxation time and porosity, the nuclear magnetic porosity corresponding to the initial surface area is determined; wherein the target relationship includes: Wherein, T2 is the transverse relaxation time, ρ is the transverse surface relaxation intensity, F is the geometric shape factor, and r is the pore throat radius.

4. The method according to claim 1, characterized in that: Based on the target fitting relationship and the initial nuclear magnetic porosity, a porosity correction coefficient is determined, including: Fitting the surface area of ​​a regular plug-shaped structure based on the volume of the irregular shale sample, and determining the fitted nuclear magnetic porosity of the irregular shale sample based on the target fitting relationship; A porosity correction coefficient is determined based on the initial nuclear magnetic porosity and the fitted nuclear magnetic porosity.

5. The method according to claim 4, characterized in that: The method further includes determining a volume of the irregular shale sample based on a water displacement method.

6. The method according to claim 1, characterized in that: Determining the porosity of the irregular shale sample to be tested in the target formation based on the porosity correction coefficient includes: Performing a nuclear magnetic resonance experiment on the irregular shale sample to be tested to obtain the experimental porosity of the irregular shale sample to be tested; The experimental porosity is corrected based on the porosity correction coefficient to obtain the porosity of the irregular shale sample to be tested.

7. A system for characterizing the occurrence state of shale oil samples based on nuclear magnetic resonance, characterized in that: include: An acquisition module, an inversion module, a first determination module, an experimental module, a second determination module and a correction module; wherein, The acquisition module is used to respectively acquire a regular plug shale sample and an irregular shale sample at the same sampling position in the target formation; The inversion module is used to perform a nuclear magnetic resonance experiment on the irregular shale sample to obtain the nuclear magnetic resonance signal of the irregular shale sample and perform inversion to obtain the T2 spectrum of the irregular shale sample; The first determination module is used to determine the initial nuclear magnetic porosity of the irregular shale sample based on the T2 spectrum of the irregular shale sample; The experimental module is used to cut the regular plug shale sample into different equal parts and perform nuclear magnetic resonance experiments in sequence to obtain a target fitting relationship between different core surface areas and nuclear magnetic porosity; The second determination module is used to determine a porosity correction coefficient based on the target fitting relationship and the initial nuclear magnetic porosity; The correction module is used to determine the porosity of the irregular shale sample to be tested in the target formation based on the porosity correction coefficient, and to characterize the occurrence state of the target formation based on the porosity.

8. The system according to claim 7, characterized in that: The experimental module is also used for: Performing a nuclear magnetic resonance experiment on the regular plug shale sample to obtain a nuclear magnetic resonance signal under the initial surface area of ​​the regular plug shale sample; Determining the nuclear magnetic porosity corresponding to the initial surface area based on the nuclear magnetic signal under the initial surface area; Performing a primary cutting on the regular plunger shale sample to obtain a primary cutting sample; Performing a nuclear magnetic resonance experiment on the primary cut sample to obtain a nuclear magnetic resonance signal under the primary cut surface area, and determining the corresponding nuclear magnetic resonance porosity; Repeat cutting and NMR experiments on the regular plug shale sample to obtain NMR porosities at different cutting surface areas; Different cut surface areas and corresponding nuclear magnetic porosities are fitted based on a preset functional relationship to obtain the target fitting relationship.

9. An electronic device, characterized in that: include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method according to any one of claims 1 to 6 when executing the computer program.

10. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores computer instructions, and when the computer instructions are executed by a processor, the method according to any one of claims 1 to 6 is implemented.

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