Method for segmenting different strata series of stratified shale and identifying oiliness of stratified shale

Abstract

The invention discloses a method for segmenting different strata series of stratified shale and identifying oiliness, and belongs to the field of oil-gas exploration. The invention discloses a strata division method based on XRF (X-Ray Fluorescence) mineral scanning and single polarization-fluorescence-laser confocal optical lens combined observation, which realizes accurate identification and segmentation of micron-sized strata boundaries of a layered rock core sample from different scales, and performs group component extraction on segmented independent strata. And carrying out chromatography-mass spectrometry analysis and FT-ICR MS analysis on the extracted saturated, aromatic, non-aromatic, leached and other family components. The TSF spectrum, light and heavy components, biomarker compounds, non-hydrocarbon compounds and other data obtained through the experiments are comprehensively analyzed, layering scale oiliness difference quantification and oil source comparison are achieved, and the shale oil micro-migration phenomenon is determined. The influence of the heterogeneity of the layered rock core sample on a result obtained by a traditional analysis method is overcome. According to the technology, direct evidences are provided for accurate prediction of shale oil desserts, exploration risks are reduced, and economic benefits are improved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas exploration, and in particular to a method for slicing different strata of stratified shale and identifying oil-bearing properties. Background Art

[0002] The core challenge faced by current shale oil-bearing property detection technologies lies in the limitations of their methodologies. Traditional detection methods such as the Rock-Eval pyrolysis method and nuclear magnetic resonance, etc., are all based on the premise of the "shale homogenization" hypothesis, and evaluate the oil content and hydrocarbon composition through overall sampling analysis. This technical path essentially ignores the significant layered structural characteristics and heterogeneity of stratified shale. Shale is composed of millimeter-scale to centimeter-scale multi-laminations / strata vertically stacked, and different strata show significant heterogeneity in key parameters such as mineral composition (the proportion difference between clay minerals and brittle minerals), organic matter abundance, pore structure (the connectivity difference of the micropore-mesopore system), etc.

[0003] This interlayer heterogeneity has led to two technical defects: Firstly, the existing overall detection methods mix samples from different strata, ignoring the heterogeneity of stratified shale and smoothing out the differential information of parameters such as oil content and light / heavy component ratio between strata. It is neither possible to accurately locate the locally enriched shale oil strata nor to quantitatively evaluate the quality differences between high-quality oil layers (light oil-enriched layers) and conventional strata, resulting in the key geological information being blurred. Secondly, although the existing technical system has high-precision detection capabilities, due to the lack of experimental means for slicing strata, it ignores the essential impact of core heterogeneity on experimental results and cannot analyze the micro-migration phenomenon of shale oil driven by multiple factors between strata. This migration is controlled by complex mechanisms such as the physical property differences between strata, the hydrocarbon generation potential gradient, the intensity of hydrocarbon expulsion, the pore space configuration, the guiding ability of mineral components, the stability of preservation conditions, and the coupling relationship between migration driving force and resistance, which promotes the aggregation of hydrocarbons to specific horizons to form local enrichment areas (i.e., exploration sweet spots). However, traditional methods are neither able to capture the multi-dimensional difference laws such as component differentiation and organic matter maturity resulting from this, nor to identify the hydrocarbon migration paths.

[0004] Therefore, it is urgent to develop a method for slicing different strata of stratified shale and identifying oil-bearing properties to comprehensively reveal the hydrocarbon difference response of the source-reservoir structure between strata caused by the heterogeneity of stratified shale, and to clarify the oil source differences and the micro-migration phenomenon of shale oil. Summary of the Invention

[0005] The object of the present invention is to provide a method for slicing different strata and identifying oil-bearing properties of laminated shale, which is a stratum division method based on combined observation of XRF mineral scanning and optical microscopy of single polarized light-fluorescence-laser confocal microscopy, achieving precise identification and slicing of micron-scale stratum boundaries of laminated core samples from different scales, performing quantitative fluorescence analysis of reservoirs and extraction of group components on the sliced independent strata, and then performing gas chromatography-mass spectrometry analysis and FT-ICRMS analysis on the extracted group components such as saturated, aromatic, non-hydrocarbon, and asphaltene components. Comprehensive analysis of data such as TSF spectra, light and heavy components, biomarker compounds, and non-hydrocarbon compounds obtained from the above experiments is carried out to realize quantification of oil-bearing property differences at the lamina scale and oil source correlation, and clarify the phenomenon of micro-migration of shale oil. Overcome the influence of the heterogeneity of laminated core samples on the results obtained by traditional analysis methods. This technical breakthrough provides direct evidence for the precise prediction of shale oil sweet spots, reduces exploration risks, and improves economic benefits.

[0006] To achieve the above object, the present invention provides a method for slicing different strata and identifying oil-bearing properties of laminated shale, comprising the following steps: Step S1, core profile slicing and description: Use a diamond wire cutting machine to finely slice the laminated shale core in the direction perpendicular to the bedding plane, and record the stratum thickness, color, and texture characteristics by visual observation. Step S2, XRF mineral scanning and stratum division at the core scale: On the basis of visually observing the core, use an X-ray fluorescence spectrometer and a single polarized light / orthogonal light microscope to scan the core profile, clarify the significant differences between stratum elements and mineral compositions, and highlight the stratum interfaces that are difficult to distinguish by the naked eye during the core observation process. Step S3, oil-bearing optical observation: Based on the mineral-element stratum division result established by the combination of XRF and polarizing microscope in Step S2, observe by the combination of fluorescence microscope and laser confocal microscope, and utilize the excitation and luminescence characteristics of hydrocarbon substances to directly observe the heterogeneity of hydrocarbon distribution inside the laminated core, and precisely identify the differences in organic matter distribution and oil-bearing properties in different strata of the core profile: Use the observed luminescence intensity and color differences of the fluorescence microscope to mark different oil-bearing components of oil, gum, and asphaltene. The laser confocal microscope quantifies the three-dimensional spatial distribution of light and heavy hydrocarbons with micron-scale resolution, directly proving the significant differences in oil content and oil quality between strata, and dividing the stratum differences of the core. Step S4, stratum wire cutting and sample preparation: Based on the high-precision stratum positioning basis in Step S3, precisely perform wire cutting on the stratum / lamina interface of the core to obtain independent samples of each stratum. Step S5, geochemical analysis of hydrocarbon components: Extract group components from independent samples of each layer series, conduct gas chromatography-mass spectrometry analysis and Fourier transform ion cyclotron resonance mass spectrometry analysis on the extracted group components, clarify the differences in biomarker compounds and non-hydrocarbon compounds between different layer series, reflect the differences in the maturity of organic matter in different layer series, and clarify the oil source differences; Combine the hydrocarbon difference responses of the endogenous-reservoir structure in the shale layer series to clarify the micro-migration phenomenon of shale oil; Step S6, data fusion and comprehensive evaluation: Through systematic comparison of the experimental results of laser confocal and reservoir quantitative fluorescence analysis techniques, group component analysis, gas chromatography-mass spectrometry analysis, and Fourier transform ion cyclotron resonance mass spectrometry analysis on different layer series, clarify the differences in oil-bearing properties and organic matter maturity between different shale layer series, clarify the oil source differences, and through comprehensive data analysis, reveal the micro-migration phenomenon of shale oil being homologous or non-homologous between different layer series.

[0007] Preferably, in step S3, the cryo-observation method of a laser confocal microscope is used to observe the crude oil in the micron-submicron level pores of different layer series. In the scanning results, the grayish-white represents the reflected light of the mineral rock; the green represents the short-wave fluorescence signal, reflecting volatile light oil; the red represents the long-wave fluorescence signal, reflecting heavy components; and they converge into a light-heavy component volume distribution map.

[0008] Preferably, in step S3, the reservoir quantitative fluorescence analysis technique includes QGF analysis and / or TSF analysis, and there is a certain internal relationship between the TSF spectrum and geochemical parameters, which can be used to predict the composition and maturity of crude oil and hydrocarbon inclusions, and establish the connection between hydrocarbon inclusions and crude oil and oil sources. R1 and R2 of TSF can reflect the ratio of tricyclic aromatic hydrocarbons to monocyclic aromatic hydrocarbons in crude oil, and have a good negative correlation with the Ts / (Ts + Tm) maturity parameter of biomarker compounds, and can be used to characterize the density and maturity of crude oil.

[0009] There is a certain internal relationship between the TSF spectrum and the n-alkane curve: 1. For medium-heavy to heavy oil, its R1 > 3.0, the maximum excitation wavelength and maximum emission wavelength Ex / Em are around 250 / 375 nm, and the main peak carbon number of the saturated hydrocarbon gas chromatography is generally greater than C 24 , and the main peak wavelength of the TSF spectrum is greater than 450 nm; 2. For light oil, its R1 is mainly concentrated between 2.0 and 3.0, Ex / Em is around 260 / 350 nm, and the main peak carbon number of the saturated hydrocarbon gas chromatography is between C 16 ~C 23 ; 3. For condensate oil, its R1 < 2.0, Ex / Em is around 250 / 340 nm, and the main peak carbon number of the saturated hydrocarbon gas chromatography is generally less than C 14, the maximum wavelength of the TSF spectrum is less than 420 nm.

[0010] Preferably, in step S5, a family component separation experiment is carried out on independent samples of each layer system, and saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons and asphaltenes are extracted from the samples. The specific steps are as follows: (1) Sample pretreatment: After removing the surface contamination of the sample, it is crushed to 200 mesh, 20-40 g of powder is weighed, and Soxhlet extraction is carried out for 72 h. The extraction solvent is an acetone-chloroform-methanol ternary azeotropic mixed solvent with a volume ratio of 38:32:30; Take the extract, add an excessive amount of n-hexane, ultrasonically oscillate and then stand for 24 hours to precipitate asphaltenes; Centrifuge or filter to separate asphaltenes, and collect the filtrate containing saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon components; (2) Asphaltene separation: Dissolve the precipitate in toluene, filter to remove insoluble impurities, evaporate the solvent to dryness and weigh to calculate the asphaltene content; (3) Column chromatography separation is carried out on the filtrate containing saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon components: ① Column packing: Use a glass chromatography column and fill it with silica gel or alumina with 100-200 meshes after activation; Cover the top with quartz sand or glass wool; ② Sample loading: Mix the filtrate with a small amount of silica gel, evaporate the solvent to make a uniform powder, and transfer it to the top of the chromatography column; ③ Gradient elution: Elute with 3 times the column volume of n-hexane and collect the eluate containing saturated hydrocarbons; Switch to elution with 3 times the column volume of toluene and collect the eluate containing aromatic hydrocarbons; Finally, elute with dichloromethane / methanol with a volume ratio of 9:1 and collect the eluate containing non-hydrocarbon components; ④ Solvent removal: Concentrate the eluates containing saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbons respectively with a rotary evaporator, evaporate the solvent to dryness to obtain saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon components respectively, weigh them, and calculate the mass percentage of each component.

[0011] Preferably, the saturated hydrocarbons or aromatic hydrocarbons extracted from samples of different layer systems are subjected to gas chromatography-mass spectrometry analysis. Use n-alkanes and polycyclic aromatic hydrocarbon standards to establish a retention time-mass spectrometry database. Record the total ion current chromatogram and the mass spectra of each component through a gas chromatography-mass spectrometry workstation. Match the compound structures using the NIST mass spectrometry library or a self-built database to clarify the differences in biomarker compound parameters in different layer systems, indicate the maturity of organic matter and the differences in oil sources, and indicate the micro-migration phenomenon of shale oil.

[0012] Preferably, Fourier transform ion cyclotron resonance mass spectrometry analysis is performed on the non-hydrocarbon components extracted from different strata series. The possible elemental composition is calculated using the accurate mass number, and the double bond equivalence is calculated to infer the degree of unsaturation and structural type of the compound, generating a molecular formula distribution map. The non-hydrocarbon compounds in shale oil are rich in variety, have strong heterogeneity in distribution in the strata, and are sensitive to the formation and evolution process of shale oil, and can effectively trace the generation-migration-accumulation process of shale oil in the strata series. By calculating the similarity of the non-hydrocarbon compound composition for oil source correlation, the hydrocarbon-bearing strata can be identified, the migration direction of shale oil can be traced, and the main production strata series of crude oil can be judged.

[0013] Preferably, in step S6, the micro-migration phenomenon is judged by hydrocarbon component analysis, biomarker compounds, and non-hydrocarbon compounds.

[0014] Preferably, in the organic-rich strata series, saturated hydrocarbons and aromatic hydrocarbons dominate in its extracts, while in the organic-poor strata series, the proportion of non-hydrocarbons and asphaltenes increases significantly; in hydrocarbon component analysis, if the content of saturated hydrocarbons and aromatic hydrocarbons extracted from the organic-rich strata series is relatively low, and the content of non-hydrocarbons and asphaltenes is relatively high, while the content of saturated hydrocarbons and aromatic hydrocarbons extracted from the organic-poor strata series is high, and the content of low-carbon-number n-alkanes is significantly high, it is a typical feature of hydrocarbon migration, indicating that the organic-rich strata series is the hydrocarbon-generation strata series, the organic-poor strata series is the hydrocarbon-bearing strata series, and micro-migration of hydrocarbons occurs from the organic-rich strata series to the organic-poor strata series.

[0015] Preferably, if the maturity of biomarker compounds in the hydrocarbon-generation strata series and the hydrocarbon-bearing strata series is the same and the original organic matter types are similar, the migrated hydrocarbons are of homologous migration.

[0016] Preferably, if the maturity of biomarker compounds in the hydrocarbon-generation strata series and the hydrocarbon-bearing strata series cannot be matched, and the phenomenon that the maturity of the hydrocarbon-generation strata series is lower than that of the hydrocarbon-bearing strata series occurs, and the maturity indexes of the biomarker compounds cannot be matched between the two, it indicates that the migrated hydrocarbons and the local hydrocarbons may have different sources, resulting in the "disconnection" of the maturity reflected by different biomarkers, and there are differences in the composition of non-hydrocarbon compounds in the hydrocarbon-generation strata series and the hydrocarbon-bearing strata series. For example, the hydrocarbon-generation strata series is rich in non-hydrocarbon compounds with short chains and high condensation degrees, while the hydrocarbon-bearing strata series is rich in non-hydrocarbon compounds with long chains and low condensation degrees. This difference is caused by the fractionation effect during the migration process, indicating that they are not completely homologous, and the oil sources of the migrated hydrocarbons are non-homologous.

[0017] Therefore, the present invention adopts the above-mentioned method for slicing different strata series of stratified shale and identifying oil-bearing properties, and has the following beneficial effects: (1) The present invention proposes a method for stratigraphic division based on XRF mineral scanning. By optimizing the division algorithm and setting the cutting precision control protection points, the accurate identification of micron-level stratigraphic boundaries is achieved. Compared with traditional methods, this technology significantly reduces the experimental errors caused by shale heterogeneity. Specifically, the present invention combines the joint observation process of single polarized light, fluorescence, and laser confocal microscopy, and uses multi-dimensional optical parameter combinations and data analysis to achieve the accurate quantification of the oil-bearing differences at the lamina scale. This innovation overcomes the quantification deviation caused by traditional methods ignoring core heterogeneity. This technology system has been verified in continental shale (such as the Ordos Basin) and marine shale (such as the Sichuan Basin), and its high-precision stratification and oil-bearing evaluation capabilities provide key geological basis for sweet spot prediction.

[0018] (2) Through the data fusion method of FT-ICR MS and chromatography-mass spectrometry coupling technology, combined with fluorescence observation and laser confocal data, the oil-bearing differences between stratigraphic series and the micro-migration phenomenon of shale oil are clarified, and the prediction accuracy of sweet spots is significantly improved. This technological breakthrough provides direct evidence for understanding the "source-reservoir-migration" coupling mechanism and supports the formulation of differential exploration strategies.

[0019] (3) Based on the technology of precise stratigraphic slicing and oil-bearing identification, the invalid drilling sampling is reduced, and the exploration cost is significantly reduced. The accurate prediction of shale oil sweet spots is realized, the success rate of single-well drilling is improved, and the proportion of invalid wells is significantly decreased. This technology combination directly reduces the exploration risk and promotes the economic and efficient development of shale oil.

[0020] The technical solutions of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Description of the Drawings

[0021] Figure 1 Schematic diagram of core section slicing; Figure 2 XRF mineral scanning map; Figure 3 Optical observation map of oil-bearing properties of different stratigraphic series; Figure 4 Volume distribution map of light and heavy components; among them, a is the volume distribution map of light and heavy components at position 1; b is the volume distribution map of light and heavy components at position 2; c is the volume distribution map of light and heavy components at position 3; Figure 5 Sand-shale sample; Figure 6 TSF analysis spectrogram of sample A, where a is the TSF analysis spectrogram of the sand stratigraphic series, and b is the TSF analysis spectrogram of the shale stratigraphic series; Figure 7 Effect diagram of precise cutting of core stratigraphic series; Figure 8It is a graph showing the changes in biomarker compound indicators for the hierarchical analysis of Sample A; Figure 9 It is a graph showing the changes in biomarker compound indicators for randomly selected points of parallel Sample B; Figure 10 It is a curve showing the relative abundance of N1 compounds changing with DBE under the hierarchical analysis of Sample A; Figure 11 It is a curve showing the relative abundance of N1 compounds changing with DBE for randomly selected points of parallel Sample B. Specific implementation manner

[0022] The technical solutions of the present invention will be further described below with reference to the accompanying drawings and embodiments.

[0023] Unless otherwise defined, the technical terms or scientific terms used in the present invention shall have the ordinary meaning as understood by those of ordinary skill in the field to which the present invention belongs.

[0024] To make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the accompanying drawings in the embodiments of the present invention will be combined below Figures 1 to 11 to clearly and completely describe the technical solutions of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, rather than all of the embodiments. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without making creative efforts belong to the scope of protection of the present invention.

[0025] In the description of the present invention, it should be understood that the terms "center", "periphery", "lateral", "longitudinal", "length", "thickness", "angle", "upper", "lower", "left", "right", etc. indicating directions or positions are only for simplifying the description of the present invention, rather than specific positions or orientations, and the above terms do not limit the present invention.

[0026] The present invention provides a method for slicing different layers of stratified shale and identifying oil-bearing properties, including the following steps: Step S1, core profile slicing and description: Use a diamond wire cutting machine to finely slice the core of stratified shale in the direction perpendicular to the bedding plane, and record the thickness, color and texture characteristics of the layers by visual observation.

[0027] Step S2, XRF mineral scanning and layer division at the core scale: On the basis of visually observing the core, use an X-ray fluorescence spectrometer and a single polarized / orthogonal polarized light microscope to scan the core profile, clarify the significant differences between the layer elements and mineral compositions, and highlight the layer interfaces that are not easily distinguishable by the naked eye during the core observation process.

[0028] Step S3, optical observation of oil content: Based on the mineral-element stratum division results established by combining XRF with a polarizer in step S2, observations are made by combining fluorescence microscopy with laser confocal microscopy, and the excitation luminescence characteristics of hydrocarbon substances are used to directly observe the heterogeneity of hydrocarbon distribution within the layered core, and accurately identify the distribution of organic matter and the difference in oil content in different strata of the core profile: the fluorescence microscope is used to observe the luminescence intensity and color differences, and the different oil-containing components of oil, colloid and asphaltene are marked. The laser confocal microscope quantifies the three-dimensional spatial distribution of light and heavy hydrocarbons at a micron-level resolution, directly proving the significant differences in oil content and oil quality between strata, and dividing the core strata.

[0029] Step S4, stratum linear cutting and sample preparation: Based on the high-precision stratum positioning in step S3, precise linear cutting is performed on the stratum / lamina interface of the core to obtain independent samples of each stratum.

[0030] Step S5, geochemical analysis of hydrocarbon components: extract group components from independent samples of each layer, and perform chromatography-mass spectrometry analysis and Fourier transform ion cyclotron resonance mass spectrometry analysis on the extracted group components to clarify the differences in biomarker compounds and non-hydrocarbon compounds between different layers, reflect the differences in organic matter maturity in different layers, and clarify the differences in oil sources; combine the differential response of hydrocarbons in the source-reservoir structure within the shale layer to clarify the micromigration phenomenon of shale oil.

[0031] Step S6, data fusion and comprehensive evaluation: Through systematic comparison of the experimental results of laser confocal microscopy and reservoir quantitative fluorescence analysis technology, group component analysis, chromatography-mass spectrometry analysis, and Fourier transform ion cyclotron resonance mass spectrometry analysis in different strata, the differences in oil-bearing properties and organic matter maturity between different shale strata are clarified, and the differences in oil sources are clarified. Through comprehensive data analysis, the micromigration phenomenon of shale oil from the same or different sources between different strata is revealed.

[0032] The specific steps are as follows: Step S1: Core section segmentation and description: The layered shale core was cut vertically in the bedding direction using a diamond wire cutting machine (equipment model: XTL-300) to record the layer thickness, color and texture characteristics of sample A. Figure 1 As shown, the whole parallel sample B was reserved as a comparison sample. Sample A was subjected to different layer segmentation and oil content identification, while Sample B was subjected to traditional oil content identification methods.

[0033] Implementation conditions: The core needs to be pretreated to a moisture content of <5%, and the cutting speed is ≤0.5mm / s.

[0034] Step S2: XRF mineral scanning to divide the layers: 2.1. Use an X-ray fluorescence spectrometer (equipment model: Bruker M4 Tornado) to perform high-resolution (10 μm) scanning on the core profile, and divide the stratigraphic segments and laminar segments according to the differences in mineral compositions (quartz, clay, pyrite).

[0035] 2.1.1 Experimental principle: XRF is a non-destructive analytical technique that determines the chemical composition of elements in a sample by measuring the energy of X-rays emitted after the sample is excited. Usually, an X-ray fluorescence spectrometer is used for measurement. During measurement, the sample is placed in the X-ray fluorescence spectrometer, and then the sample is excited with X-rays. The elements in the sample will absorb the X-rays and be excited to a high-energy state that emits X-rays. The energy of these emitted X-rays is related to the type of element, and the type and content of elements in the sample can be determined by measuring the energy of these X-rays.

[0036] 2.1.2 Experimental steps: (1) Surface polishing: Place the longitudinal plane of the cut core sample on a grinding machine to polish it, making the surface of the core longitudinal plane smoother and flatter.

[0037] (2) Ultrasonic cleaning: Pour an appropriate amount of cleaning liquid (water) into an ultrasonic cleaning machine, and gently place the polished core in the water for cleaning. Cleaning principle: The ultrasonic energy generated by the instrument causes the bubbles in the tank to vibrate continuously, reducing the adsorption ability of stains to the sample surface.

[0038] (3) Vacuum drying: Place the sample in a vacuum drying oven, set a certain temperature and pressure, and then perform drying treatment. Principle: The inside of the vacuum drying oven is filled with inert gas, which can enable the sample to dry quickly in a very clean environment, especially for some items with complex compositions, such as drying heat-sensitive, easily decomposed, and easily oxidized substances in clean laboratories and aerospace units. The finally processed sample has a smooth and dry surface without oil stains.

[0039] (4) Sample detection: After removing dust from the block shale sample, fix it in the airtight vacuum working chamber of the instrument with plasticine, with its smooth surface facing up; control the opening of the X-ray device and evenly scan the upper surface of the sample. By reading the unique wavelength of the X-rays through the instrument, the types of elements contained in the sample can be qualitatively identified.

[0040] 2.1.3 Experimental results: Based on the visual observation of the core, through XRF scanning, significant differences in elements in different stratigraphic segments can be more intuitively found. Figure 2Taking the identification of Ca element in the sample as an example, the lighter-colored part is the distribution area of Ca element in the sample. Different strata can be divided from the figure according to the elemental differences. This shows that there are differences in the composition of different strata in the same core, and it is necessary to analyze different strata separately. XRF scanning is more helpful for distinguishing the stratum boundaries, which can more clearly define the boundaries of stratum changes based on naked-eye observation and facilitate the subsequent precise segmentation of the core strata.

[0041] 2.2. Polarized light / Orthogonal light microscope (equipment model: Olympus BX53): Identify mineral fabric and organic matter distribution.

[0042] 2.2.1. Experimental principle Under the microscope, the growth or deformation history of crystals can be judged by the morphology and cleavage direction of mineral grains. Organic matter is usually amorphous carbonaceous material, which appears black or dark brown under polarized light due to strong light absorption, forming a contrast with transparent minerals.

[0043] Minerals may show characteristics such as color, pleochroism, and morphology under polarized light, which can help identify mineral species. Under orthogonal light, information such as the birefringence and extinction angle of minerals can be used to judge the crystal structure and arrangement direction, and then analyze the fabric. For example, quartz will have undulatory extinction under orthogonal light, which may reflect the deformation history.

[0044] Organic matter is usually amorphous and may show specific colors or transparencies under polarized light, such as black or brown. However, organic matter may not show interference colors under orthogonal light because they are amorphous, so they may show total extinction under orthogonal light. This can be used to distinguish organic matter from minerals.

[0045] 2.2.2. Experimental steps (1) Define the sampling requirements. For samples with distinguishable layers, the samples should be sliced perpendicular to the layers. Use a cutting machine to cut each sample into rock samples with dimensions of 25mm×25mm×5mm or a diameter of 25mm×5mm.

[0046] (2) Drop glue and solidify method: For rocks with dense cementation, it is advisable to use α-cyanoacrylate or non-fluorescent α-cyanoacrylate instant strong adhesive to drip and infiltrate for solidification.

[0047] (3) Diamond grinding wheel grinding flat method: Grind the solidified rock samples successively on 120#, 320#, 500#, 1000#, 2000#, and 3000# diamond grinding wheels with water until the surface is bright and flat.

[0048] (4) Strong adhesive sticking method: The glass slide uses a polished slide or a single-sided frosted slide. Wipe the glass slide and the ground surface of the rock sample clean with silk, and use non-fluorescent α-cyanoacrylate instant strong adhesive to stick the sample.

[0049] (5) Machine slicing method: Turn on the cooling water, adsorb the rock slice on the vacuum fixture of the slicing machine, check and confirm that the adsorption is firm, cut the rock slice into a flat surface with a thickness of 0.8 mm to 1.2 mm, wash it and dry it.

[0050] (6) Automatic grinding method: Batch the rock slices according to the thickness of the glass slides. Put the rock slices of the same batch into the automatic grinding machine. After turning on the cooling water, preset the thickness to 0.04 mm to 0.05 mm, and start the switch to grind the slices. Subsequently, finely grind with W7 emery and water on the glass plate, or sequentially drip water and finely grind on 1000#, 2000#, and 3000# diamond discs to 0.030 mm to 0.035 mm. The quartz interference color is grade I grayish white; if it is carbonate rock, the thickness is 0.040 mm, the structure is clear under the polarized light microscope, and the interference color is high-grade white. There is no particle shedding.

[0051] (7) The polarized light thin section should be covered with a cover slip. Place the cover slip on the glue plane and squeeze it with tweezers to discharge the air bubbles. Soak and clean it with alcohol and then rinse it with clean water.

[0052] (8) Polarized light microscope observation: Use a 4× or 10× objective lens to find the areas where minerals and organic matter are densely distributed.

[0053] 2.2.3. Experimental results After distinguishing the core layers by XRF scanning, the polarized light microscope can more clearly observe the differences in mineral components in different layers microscopically, further verifying the necessity of studying different layers of stratified shale; under the observation of the polarized light microscope, the layer interfaces that are difficult to distinguish with the naked eye during the core observation can be highlighted, so as to achieve the purpose of accurately dividing different layer interfaces. Subsequently, the fluorescence microscope is used to further prove the distribution and content differences of organic matter in different layers.

[0054] Step S3. Oil-bearing optical observation and detection: 3.1. Fluorescence microscope (equipment model: Leica DM6B): The excitation wavelength is 365 nm, and the fluorescence intensity and distribution of hydrocarbons are observed.

[0055] 3.1.1. Experimental principle The hydrocarbons in shale are divided into four group components: saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons, and asphaltenes according to the differences in solubility in solvents composed of different polar solutions. In the reservoir space, hydrocarbons aggregate in different mixing ratios, and different components have different fluorescence characteristics. Under a certain intensity of fluorescence, different fluorescence colors will be shown. Therefore, the content and distribution of different components in shale can be analyzed by partitioning the fluorescence colors.

[0056] 3.1.2. Experimental steps (1)Define the sampling requirements. For samples of distinguishable layers, the slices should be cut perpendicular to the layers. Use a cutting machine to cut each sample into rock samples with dimensions of 25 mm × 25 mm × 5 mm or a diameter of 25 mm × 5 mm.

[0057] (2)Epoxy resin impregnation method: Use non-fluorescent α-cyanoacrylate instant strong adhesive to infiltrate and solidify.

[0058] (3)Diamond grinding wheel for planar grinding method: Grind the solidified rock samples successively on 120#, 320#, 500#, 1000#, 2000#, and 3000# diamond grinding wheels with water until the surface is smooth and bright.

[0059] (4)Strong adhesive for slicing method: Use a polished slide or a single-sided frosted slide for the glass slide. Wipe the glass slide and the planar surface of the ground rock sample clean with silk. Use non-fluorescent α-cyanoacrylate instant strong adhesive to stick the slice.

[0060] (5)Machine slicing method: Turn on the cooling water, adsorb the rock slice on the vacuum fixture of the slicing machine, check and confirm that the adsorption is firm, and cut the rock slice into a flat and straight surface with a thickness of 0.8 mm - 1.2 mm. Wash and dry it in the air.

[0061] (6)Automatic grinding method: Batch the rock slices according to the thickness of the glass slide. Put the rock slices of the same batch into the automatic grinding machine. After turning on the cooling water, preset the thickness to 0.04 mm - 0.05 mm and start the switch to grind the slices. Subsequently, use W7 emery with water to finely grind on the glass plate, or successively use 1000#, 2000#, and 3000# diamond disks with water to finely grind until the thickness reaches 0.030 mm - 0.035 mm.

[0062] (7)For fluorescent thin sections, cover slips should be used. Place the cover slip on the epoxy surface and squeeze it with tweezers to expel air bubbles. After drying in an oven at 50 °C, store it in the dark to prevent oxidation of fluorescent substances.

[0063] (8)Microscope settings: Excitation light source: Mercury lamp or LED light source. Select ultraviolet light (365 nm) or blue light (450 nm) for excitation.

[0064] Filter configuration: Excitation filter: Allows light of a specific wavelength to pass through (such as BP 450 - 490 nm).

[0065] Emission filter: Intercepts the fluorescent signal (such as LP 515 nm).

[0066] Objective lens selection: 10×50× oil immersion objective lens to improve resolution.

[0067] 3.1.3. Experimental results Based on observing the same series area with a polarized light microscope, the differences in the distribution and content of organic matter in different series were clearly revealed by the differences in the fluorescence emission colors of different series of oil quality. The differences in fluorescence colors can preliminarily indicate the hydrocarbon component distribution in different series and simply indicate the oil-bearing properties of different series. The fluorescence emission colors of different oil qualities are shown in Table 1: Table 1 Fluorescence Emission Colors of Different Oil Qualities ; Subsequently, the differences in the oil-bearing properties of different series were further observed in depth by laser confocal microscopy.

[0068] 3.2 Laser Scanning Confocal Microscope (Equipment Model: Zeiss LSM 900): Three-dimensional Reconstruction of the Pore-Hydrocarbon Occurrence Relationship.

[0069] 3.2.1 Experimental Principle Laser scanning confocal microscopes have the advantages of high resolution, simple sample preparation, certain penetration ability, and integrating laser scanning and digital image processing. They are used to study the pore structure characteristics of unconventional lithologies such as tight sandstone, and can quickly, accurately, and intuitively provide information such as the pore structure and organic matter components of micropores. A laser with a fixed wavelength of 488 nm is used to excite the sample, and the light components in the crude oil generate fluorescence signals in the wavelength range of 490 nm to 600 nm, and the heavy components generate fluorescence signals in the wavelength range of 600 nm to 800 nm.

[0070] Basic Principles of Light and Heavy Component Analysis: Traditional experimental observation results show that the fluorescence color of liquid hydrocarbons can reflect the degree of organic matter evolution. That is, as the organic matter evolves from low maturity to high maturity, its fluorescence color changes from fiery red → yellow → orange → blue → bright yellow (blue shift).

[0071] 3.2.2 Experimental Procedures Sectioning → Sealing with Adhesive → Polishing the Section → Mounting the Section → Grinding the Thin Section → Labeling. Do not soak with organic solvents before specimen preparation. For specimen preparation requirements, when taking samples of oil-bearing rocks and sectioning, it needs to be carried out under freezing conditions. The sample is frozen and stored in liquid nitrogen before sectioning, and the sample needs to be air-dried in an environment below 5°C after sectioning, and then cemented with 502 glue in a vacuum environment. When rough grinding the plane, if there are loose rocks with falling particles, it must be re-bonded with glue and then ground until there are no holes. Mount the specimen after the moisture of the sample has dried.

[0072] 3.2.3 Experimental Results The cryogenic observation method of laser scanning confocal microscopy was used to observe the crude oil in the micron-submicron pores of different series. As Figure 3As shown, in the scanning results, the reflected light of the mineral rocks on the sample surface is represented by grayish-white; the short-wave fluorescence signal is represented by green, reflecting volatile light oil; the long-wave fluorescence signal is represented by red, reflecting heavy components, and the results are aggregated into Figure 4 the light and heavy component volume distribution map shown, where positions 1, 2, and 3 respectively select different strata. The results show that position 1 is a shale stratum with fractures. From the single-point fluorescence map, it can be seen that the fluorescence color in the fractures is yellowish-green, and the fluorescence reflection of the shale stratum is black or dark brown; from the reconstruction of light and heavy components, it can be seen that there is mostly light oil in the fractures, while the distribution of heavy components is relatively more within the shale range. Position 2 is a carbonate stratum. From the single-point fluorescence map, the fluorescence colors are mostly light yellow and yellowish-green, and it can be seen from the reconstruction of light and heavy components by laser confocal microscopy that there is mostly light oil distribution within the stratum. Position 3 selects a multi-fracture area. The fluorescence reflection in the single-point fluorescence map is sky blue and yellowish-green. In the fractures, hydrocarbons nearby migrate into the fractures and accumulate, and it also shows mainly green light oil in the laser confocal microscopy.

[0073] Most shale strata are rich in organic matter strata, and their hydrocarbon generation ability is stronger than that of carbonate strata (poor in organic matter strata). It can be found in both the single-point fluorescence map and the reconstruction of light and heavy components that the rich organic matter strata contain more heavy components, while the poor organic matter strata are enriched in light oil components.

[0074] It reveals the differences in hydrocarbon occurrence in different strata, more intuitively reflects the significant differences in light oil and heavy components in different strata, can accurately locate and quantify the distribution of light and heavy components in different strata, and can also prove the phenomenon of micro-migration of shale oil between strata, verifying and supplementing the differences in oil-bearing properties of each stratum observed by fluorescence microscopy.

[0075] 3.3 Quantitative fluorescence analysis technology for reservoirs: (Equipment model: Varian Cary-Eclipse) 3.3.1 Experimental principle Fluorescence belongs to a kind of photoluminescence. The application of fluorescence spectroscopy technology to oil and gas exploration has a history of more than one hundred years. Hydrocarbon substances in the reservoir, such as aromatic hydrocarbons and polar compounds, will spontaneously generate fluorescence when excited by light of a certain wavelength. The fluorescence spectrum formed by hydrocarbon substances in the reservoir can reflect various information such as the chemical composition, physical properties of crude oil, and oil-bearing abundance in the reservoir. The method of using fluorescence spectroscopy to detect various forms of hydrocarbons can detect diluted or undiluted, surface-coated hydrocarbons, as well as oil and gas inclusions, and the detection concentration of hydrocarbons is 10-6 or lower. Compared with MCI (fluid inclusion composition analysis technology) which can also detect the molecular composition information of adsorbed hydrocarbons and included hydrocarbons in the reservoir, the quantitative particle fluorescence technology has the advantages of small sample requirement, economy, large batch, rapidity, and high sensitivity.

[0076] The TSF spectrum represents the fluorescence characteristics of hydrocarbons associated with the reservoir particle surface and can be used to determine the current oil layer or residual oil layer in exploration and drilling evaluation. Research shows that the TSF spectra of samples from the current oil layer or residual oil layer have relatively high fluorescence intensities, while the TSF spectra of water layer samples have very low and flat intensities, which are consistent with the fluorescence spectra of dichloromethane solvent in the range of 320 - 370 nm. Therefore, the TSF intensity can reflect the content of hydrocarbons associated with reservoir particles. The content of associated hydrocarbons is positively correlated with the oil saturation. The greater the TSF intensity, the higher the oil saturation. The maximum wavelength (λmax) of the TSF spectrum reflects the composition and density of the crude oil.

[0077] 3.3.2 Experimental Procedures (1)Crush the samples. Appropriately crush, slightly grind, and sieve the collected original core and cuttings samples, and screen out about 2 g of analytical sample particles with particle sizes ranging from 30 mesh to 80 mesh. Place them separately into small beakers with a capacity of 50 ml and number them one by one in sequence.

[0078] (2)Wash the samples in the beaker repeatedly with distilled water until the clay on the particle surface is removed, leaving behind coarser-grained, relatively pure, granular sand grains. Then air-dry them or dry them in an oven with a temperature set at 40 °C.

[0079] (3)Add 20 ml of dichloromethane to the already thoroughly dried small beaker, place it in an ultrasonic cleaner and shake for 10 minutes, then let it stand for 40 minutes. After that, pour out the dichloromethane solution in the small beaker and let the samples stand until they evaporate to a dry state. The purpose of this step is that dichloromethane is an organic solvent, used to remove the hydrocarbons adsorbed on the rock surface.

[0080] (4)Add 40 ml of 10% hydrogen peroxide solution to the already thoroughly dried small beaker, shake it in an ultrasonic cleaner for 10 minutes, then let it stand for 40 minutes, shake it for another 10 minutes, and then pour out the hydrogen peroxide solution in the beaker. Wash it with distilled water until the residue dissolved by hydrogen peroxide is washed clean. The purpose of this step is to remove the clay minerals and partially oxidized cements on the particle surface.

[0081] (5)After the distilled water washing is completed, add 40 ml of 3.6% HCl solution and let it stand for 20 minutes. During the standing process, stir clockwise with a glass rod. Bubbles will appear in some beakers. Stir until no more bubbles appear. Then pour out the HCl solution and wash the samples repeatedly with distilled water as in the above steps. This step is to remove the carbonate cements on the particle surface.

[0082] (6)Put the small beakers containing the samples into an incubator with a temperature less than 60 °C to dry.

[0083] (7) Pour 20 ml of dichloromethane into the dried samples respectively, shake them with an ultrasonic cleaner for 10 minutes, then place the dichloromethane extraction solution in the beaker after shaking into a reagent bottle for sealed storage, and use the collected solution for QGF-E analysis.

[0084] (8) Place the samples in the beaker in the fume hood to air dry. Weigh the dried pure particles with an electronic balance and record the specific data (accurate to 0.001 g). Finally, use the samples for TSF and QGF analysis. The TSF analysis spectrum is as Figure 6 shown.

[0085] 3.3.3 Experimental Results Select samples from different strata for reservoir quantitative fluorescence analysis, and the differences in oil content, mobility, and oil quality of different strata can be obtained, indicating the necessity of oil-bearing analysis for different strata. There is a certain internal relationship between spectra such as TSF and QGF and geochemical parameters, which can be used to predict the composition and thermal maturity of crude oil and inclusion hydrocarbons, establish the connection between hydrocarbon inclusions and crude oil, and oil sources. Subsequently, geochemical analysis is carried out on samples from different strata to further reveal the oil-bearing differences and shale oil micro-migration phenomena between different strata or different laminations of shale.

[0086] R1 and R2 of TSF can reflect the ratio of tricyclic aromatic hydrocarbons to monocyclic aromatic hydrocarbons in crude oil, and have a good negative correlation with the maturity parameter Ts / (Ts + Tm) of biomarker compounds, which can be used to characterize the density and maturity of crude oil. The smaller R1 and R2 are, the lighter the oil quality is.

[0087] Figure 5 Select two parts, the sandstone stratum and the shale stratum, for reservoir quantitative fluorescence analysis to study the differences in oil-bearing quality of different strata. Among them, the Ex / Em of the sandstone stratum is about 260 / 350 nm, and R1 is less than 3, indicating that most of the oil in the sandstone stratum is light oil; while for the shale stratum, R1 is 6, and the maximum excitation wavelength and maximum emission wavelength Ex / Em are about 250 / 375 nm, indicating that most of the oil in the shale stratum is medium and heavy viscous oil.

[0088] Step S4: Stratum wire cutting and sample preparation Based on XRF division and optical microscope observation, precisely perform wire cutting (accuracy ±0.1 mm) on the stratum / lamination interface of core sample A, as Figure 7 shown, to obtain 4 independent stratum samples.

[0089] Step S5: Geochemical analysis of hydrocarbon components 5.1. Separation of group components: Separate saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons, and asphaltenes.

[0090] 5.1.1. Experimental principle Crude oil molecules are diverse and have complex chemical structures. Group composition is a common parameter used to generally describe the chemical composition characteristics of petroleum and reflect the quality of shale oil. According to solubility and polarity, crude oil components are divided into saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons (resins), and asphaltenes. Among them, the saturated fraction mainly contains two elements, C and H, mainly consisting of alkanes and cycloalkanes, with low viscosity and good fluidity; the aromatic fraction is mainly aromatic compounds with more than two rings, and the fluidity is second; while resins and asphaltenes are rich in non-hydrocarbon compounds with strong polar macromolecules, usually with high viscosity and poor fluidity. The polarities of different group components are different. Through gradient solvent elution method, using the selective adsorption of adsorbents (such as silica gel, alumina) for polarity, each component is gradually separated.

[0091] 5.1.2. Experimental Procedures (1) Sample pretreatment: After removing the surface contamination, the sample is crushed to 200 mesh, and 20 - 40 g of the powder is weighed and subjected to Soxhlet extraction for 72 h. The extraction solvent is a ternary azeotropic mixed solvent of acetone - chloroform - methanol (38∶32∶30, volume ratio).

[0092] An appropriate amount of the extract is taken, and an excessive amount of n - hexane (about 40 times the volume) is added. After ultrasonic oscillation, it is left standing for 24 hours to precipitate the asphaltenes.

[0093] The asphaltenes (precipitates) are separated by centrifugation or filtration, and the filtrate (containing saturated hydrocarbons, aromatic hydrocarbons, and non - hydrocarbons) is collected.

[0094] (2) Asphaltene separation: The precipitate is dissolved in toluene, the insoluble impurities are removed by filtration, the solvent is evaporated to dryness and weighed to calculate the asphaltene content.

[0095] (3) Column chromatography separation (saturated hydrocarbons, aromatic hydrocarbons, non - hydrocarbons): ① Column packing: Use a glass chromatography column and pack it with activated silica gel or alumina (100 - 200 mesh). Avoid air bubbles during column packing, and cover the top with quartz sand or glass wool.

[0096] ② Sample loading: Mix the filtrate (sample without asphaltenes) with a small amount of silica gel, evaporate the solvent to form a uniform powder, and transfer it to the top of the chromatography column.

[0097] ③ Gradient elution: Saturated hydrocarbons: Elute with n - hexane (about 3 times the column volume) and collect the eluate.

[0098] Aromatic hydrocarbons: Switch to toluene elution (about 3 times the column volume) and collect the eluate.

[0099] Non - hydrocarbons (resins): Finally, elute with dichloromethane / methanol (9:1, v / v) and collect the eluate.

[0100] ④ Solvent removal: The eluates of each component are concentrated separately using a rotary evaporator, the solvent is evaporated to dryness and weighed to calculate the mass percentage of each component.

[0101] 5.1.3 Experimental Results Extracts were obtained from the precisely segmented hierarchical samples, and saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons (gums), and asphaltenes were separated.

[0102] 5.2 Gas Chromatography-Mass Spectrometer (Equipment Model: Agilent 7890B-5977B): Saturated Hydrocarbons, Aromatic Hydrocarbons (Qiye 7H) 5.2.1 Experimental Principle (1) Principle of Gas Chromatography: Separation Principle: Different compounds have different distribution coefficients between the stationary phase (chromatographic column) and the mobile phase (carrier gas), resulting in different retention times in the chromatographic column, thus achieving separation.

[0103] Applicability: Saturated hydrocarbons (such as n-alkanes, branched alkanes) and aromatic hydrocarbons (such as monocyclic, polycyclic aromatic hydrocarbons) can be efficiently separated by gas chromatography due to differences in boiling points and polarities.

[0104] (2) Principle of Mass Spectrometry: Ionization: Compounds are ionized by electron bombardment (EI) or chemical ionization (CI) to form ions.

[0105] Mass Analysis: Ions are separated according to the mass-to-charge ratio (m / z) to generate a mass spectrum, and the compound structure is identified through characteristic fragment ions and molecular ion peaks.

[0106] Advantage of Coupling: Gas chromatography achieves component separation, and mass spectrometry provides structural information. Qualitative and quantitative analysis are achieved by combining the retention time and the mass spectrum.

[0107] 5.2.2 Experimental Procedures (1) Sample Pretreatment Dissolution: The separated saturated hydrocarbon or aromatic hydrocarbon components are dissolved in a low-polarity solvent (such as n-hexane, dichloromethane), and the concentration is controlled at 0.1 - 1 mg / mL.

[0108] Filtration: Particulates are removed through a 0.22 μm organic filter membrane to prevent clogging of the chromatographic column.

[0109] (2) Instrument Preparation Selection of Chromatographic Column: A non-polar column (such as HP-5MS, 5% phenylmethyl polysiloxane) is suitable for hydrocarbon analysis.

[0110] Carrier Gas: High-purity helium (He), flow rate 1 - 2 mL / min.

[0111] Temperature Program: Initial Temperature: 50°C (held for 2 minutes) Heating Rate: 5 - 10°C / min to 300°C (held for 10 minutes) (3) Chromatography-Mass Spectrometry Analysis Conditions Injection mode: Split / splitless injection (1 μL, split ratio 10:1).

[0112] Ion source temperature: 230 °C (EI mode, electron energy 70 eV).

[0113] Scanning mode: Full scan (m / z 50 - 550) or selected ion monitoring (SIM).

[0114] (4) Standard Calibration Use n-alkanes (C8 - C 40 ) and polycyclic aromatic hydrocarbon standards (such as naphthalene, phenanthrene, pyrene) to establish a retention time - mass spectrometry database.

[0115] (5) Data Acquisition and Processing Record the total ion chromatogram (TIC) and the mass spectra of each component through a chromatography - mass spectrometry workstation. Use the NIST mass spectrometry library or a self - built database to match the compound structures.

[0116] 5.2.3 Experimental Results By performing gas chromatography - mass spectrometry analysis on the saturated hydrocarbons and aromatic hydrocarbons extracted from different layer samples separated from Sample A, the differences in biomarker compound parameters such as the ∑n - C 20- / ∑n - C 21+ value and the TAR value in the four layer systems can be determined. The results are as Figure 8 shown. Biomarker compounds can indicate the maturity of organic matter. For example, the ratios of the isomers 20S / (20S + 20R) and ββ / (ββ + αα) of regular steranes in steranes increase with increasing maturity; the ratio of Ts / (Ts + Tm) in hopanes increases with increasing maturity, while the C30 homohopane / C30 hopane shows a decreasing trend. 29 In the aromatic hydrocarbons, the naphthalene series and phenanthrene series are also important biomarker compounds for characterizing micro - migration. For shale layer systems, the overall ratios of trimethylnaphthalene to trimethylphenanthrene (∑TMN / ∑TMP), tetramethylnaphthalene to tetramethylphenanthrene (TeMN / TeMP), and the naphthalene series to the phenanthrene series (∑N / ∑P) are lower in the oil - generating layer system than in the oil - storing layer system. This differentiation is attributed to the fact that naphthalene is more easily expelled than phenanthrene during petroleum migration.

[0117] When performing gas chromatography - mass spectrometry analysis on randomly selected positions of Sample B, the results are as

[0118] shown, and Figure 9As shown, no clear regular changes can be seen in the indicators of various biological compounds. From the experimental results of both, it can be seen that hierarchical analysis can clarify the hydrocarbon migration paths at the hierarchical scale or the laminar scale and the fine evaluation of shale oil content, avoiding errors in analysis caused by shale heterogeneity.

[0119] Samples of sample A were selected for analysis by layer system. For example, laminar layer 2 is a layer system rich in organic matter with a high degree of organic matter maturity, and all the indicators of various biological compounds correspond to its high maturity phenomenon. And laminar layer 4 is a layer system poor in organic matter, with (∑N / ∑P) greater than that of the layer system rich in organic matter, indicating the micro-migration phenomenon of shale oil. The indicators of other biomarker compounds also show a relatively high maturity, proving the micro-migration phenomenon of shale oil in terms of biochemical indicators.

[0120] 5.3 FT-ICR MS (Equipment model: Bruker solariX) 5.3.1 Experimental principle (1) Technical characteristics of FT-ICR MS Ultra-high resolution and mass accuracy: Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) measures the cyclotron frequency of ions in a strong magnetic field to achieve accurate determination of the mass-to-charge ratio (m / z), with a resolution of over one million, capable of distinguishing compounds with extremely small mass differences (such as isotope peaks, isomers).

[0121] Wide dynamic range: Suitable for the detection of trace compounds in complex mixtures, such as heteroatom compounds containing oxygen (O), nitrogen (N), sulfur (S), etc. in petroleum non-hydrocarbon components.

[0122] (2) Characteristics of non-hydrocarbon components Non-hydrocarbons (resins) mainly contain polar compounds, such as acidic substances (carboxylic acids, phenols), nitrogen-containing compounds (pyrroles, carbazoles), sulfur-containing compounds (thiophenes), and large molecular polar substances (such as asphaltene fragments). Traditional mass spectrometry is difficult to analyze their complex molecular compositions, while FT-ICR MS combined with soft ionization techniques (such as electrospray ionization ESI, atmospheric pressure chemical ionization APCI) can retain the molecular integrity and provide molecular formula information.

[0123] (3) Selection of ionization mode ESI (electrospray ionization): Suitable for polar compounds (such as acidic and basic substances containing O and N), and deprotonated molecules are detected in the negative ion mode.

[0124] APCI / APPI: Suitable for weakly polar aromatic compounds (such as polycyclic sulfur-containing aromatic hydrocarbons).

[0125] 5.3.2 Experimental steps (1) Sample pretreatment Dissolution: Dissolve the non-hydrocarbon components in a polar solvent (such as methanol: water = 1:1, or toluene: methanol mixture) at a concentration of about 0.1 mg / mL.

[0126] Desalting: Use solid-phase extraction (SPE) or dialysis to remove salts to avoid mass spectrometry signal suppression.

[0127] Filtration: Remove particulate matter through a 0.22 μm filter membrane.

[0128] (2) Instrument parameter settings Ionization source: ESI negative ion mode (for acidic compounds) or positive ion mode (for basic compounds).

[0129] Spray voltage: 3 - 4 kV Dry gas temperature: 200 - 300 °C Mass range: m / z 150 - 1000, covering the typical molecular weight range of non-hydrocarbons.

[0130] Accumulation time: 0.5 - 1 s / scanning, accumulate 64 - 128 times to improve the signal-to-noise ratio.

[0131] (3) Data acquisition and analysis Molecular formula attribution: Calculate the possible elemental compositions (such as combinations of C, H, O, N, S) using the exact mass number (error < 1 ppm).

[0132] Calculation of double bond equivalence (DBE) for inferring the degree of unsaturation and structural types of compounds (such as aromaticity, condensation degree).

[0133] Visualization: Generate molecular formula distribution diagrams (such as DBE vs. carbon number diagram, heteroatom class abundance diagram).

[0134] 5.3.3 Experimental results The composition characteristics of non-hydrocarbon compounds in different layers of sample A were determined by FT-ICR MS in the negative mode of electrospray ionization source (ESI), and the variation trends of the composition characteristics of non-hydrocarbon compounds such as N1 and N2 in different layers were analyzed. In the samples of the core hydrocarbon generation layer system, N1 compounds with higher condensation degree and larger parent nucleus structure are relatively enriched. The DBE distribution of neutral N1 compounds in shale oil varies greatly among different rock types, reflecting the differences in the processes of oil generation, migration, and accumulation in different layers. The curve of the relative abundance of N1 compounds in the 4 laminations of sample A changing with DBE is as Figure 10As shown, the DBE distribution characteristics of N1 compounds are significantly distinct. Among them, lamina 2 is a hydrocarbon-rich organic matter layer series, laminae 1 and 4 are hydrocarbon-lean organic matter layer series that have received hydrocarbon migration, and lamina 3 is a hydrocarbon-lean organic matter layer series that has not received hydrocarbon migration. The results show that in the hydrocarbon-rich organic matter series samples, N1 compounds with relatively higher condensation degrees and larger parent nuclear structures are relatively enriched.

[0135] When FT-ICR MS is performed at randomly selected positions on sample B, the results are as Figure 11 shown. The DBE distribution characteristics of N1 compounds show a broad distribution without significant peaks. The heterogeneity of the sample results in the dilution of high-condensation N1 signals by low-condensation molecules.

[0136] Step S6, Data Fusion and Comprehensive Evaluation (Comparing Overall Advantages and Disadvantages) 6.1 Reflects the Advantages of the Separated Layer Series Independent layer series samples obtained through precise separation technology can clarify the following key geological understandings: ①Analysis of the differences in hydrocarbon properties at the layer series scale: The separated layer series technology makes it possible to finely characterize the hydrocarbon component compositions (light and heavy component ratios) and hydrocarbon properties of different layer series. It is precisely through the analysis of independent layer series samples that the significant differences in the distribution of light and heavy components existing between different layer series can be accurately revealed and quantified. Such differences are not only direct indicators of the quality of hydrocarbon-bearing properties of the layer series but also key evidence for the existence of shale oil micro-migration phenomena between layer series.

[0137] ②Coupled characterization of multiple geochemical parameters: Based on the independent samples obtained from the separated layer series, the differences in hydrocarbon phases can be quantified through the analysis of saturated hydrocarbon - aromatic hydrocarbon - non-hydrocarbon - asphaltene components. Combining chromatography - mass spectrometry and Fourier transform ion cyclotron resonance mass spectrometry techniques, the differences in biomarker compounds (such as terpanes, steranes) and non-hydrocarbon compounds (such as nitrogen / oxygen-containing compounds) in samples of different layer series can be clarified. These layer series-specific geochemical differences reflect the differences in organic matter maturity (such as changes in the C29 sterane isomerization ratio), providing evidence for oil source correlation and micro-migration between layer series.

[0138] ③"Source - reservoir" structure coupling mechanism: In the "source - reservoir" context of shale layer series, the study of separated layer series is the key to clarifying the mechanism of how micro-migration between layer series leads to the local abnormal enrichment of shale oil. Only by precisely separating and independently analyzing different layer series can the specific migration paths of shale oil between layer series be effectively traced and clarified. This technical system establishes a complete evidence chain from the characterization of layer series heterogeneity to the hydrocarbon difference response of the source - reservoir structure for the prediction of shale oil "sweet spots", clarifying oil source differences and shale oil micro-migration phenomena.

[0139] For example, in the study of a shale oil formation, it was found that the whole uncut core generally showed average oiliness. However, after separating the organic-rich layer and the organic-poor layer, it was found that the organic-rich layer contained more heavy components, while the organic-poor layer was enriched in light oil components. Comparing the comprehensive analysis results of the oil-bearing quality of each formation with the test results of the uncut core highlighted that after formation division and separation, the oil-bearing quality characteristics of each formation could be more accurately evaluated, fully demonstrating the advantages of separated formations in the fine evaluation of oil-bearing properties, avoiding interlayer differences that might be masked by the overall evaluation when uncut, providing more targeted and accurate formation oil-bearing quality information for subsequent exploration and development, and thus guiding the rational selection of development formations and optimizing production plans to improve the exploration and development efficiency and benefits of shale oil and gas resources.

[0140] 6.2 Comparison of geochemical parameters of separated formations: Oil source evidence of the same origin and different origins - Guiding exploration and development Organic geochemical analysis of each separated formation can obtain rich oil source correlation information. Hydrocarbon component analysis shows that the saturated hydrocarbon and aromatic hydrocarbon contents in the organic-rich layer are relatively low, while the non-hydrocarbon and asphaltene contents are relatively high; on the contrary, in the organic-poor layer, the saturated hydrocarbon and aromatic hydrocarbon contents are relatively high, especially the content of low-carbon number n-alkanes is significantly higher, which is a typical characteristic of migrated hydrocarbons, indicating that micro-migration of hydrocarbons has occurred from the organic-rich layer to the organic-poor layer. Biomarker compound analysis can further provide oil source correlation evidence. For example, differences in biomarker compound parameters such as the ∑n-C 20- / ∑n-C 21+ value and TAR value in different formations can reflect the distribution of light and heavy hydrocarbon contents and the differences in organic matter maturity. If the biomarker compound maturity index in the organic-poor layer shows abnormalities, such as the ratios of 20S / (20S + 20R) and ββ / (ββ + αα) of C29 regular steranes being significantly different from those in the organic-rich layer, it may be due to the influence of migrated hydrocarbons, indicating the existence of oil sources of the same origin or different origins. By systematically comparing the geochemical parameters of separated formations and clarifying the oil source characteristics of different formations, micro-migration phenomena within the shale formation can be accurately identified, providing a key basis for the exploration and development of shale oil, guiding the rational selection of development formations and optimizing production plans to improve the exploration and development efficiency and benefits of shale oil and gas resources.

[0141] 6.2.1 Oil source evidence of the same origin: The connection between the hydrocarbon generation formation and the hydrocarbon storage formation: The hydrocarbon generation formation has a large amount of hydrocarbon generation. After a large amount of hydrocarbon generation, the hydrocarbons are expelled outward and migrate to the hydrocarbon storage formation to form "sweet spots within the source". This indicates that there is a genetic connection between the "sweet spots within the source" and the hydrocarbon generation formation, and they should have similarities in the original organic matter type and maturity.

[0142] Maturity consistency: The biomarker maturities of the hydrocarbon-generating series and the hydrocarbon-storing series (such as C29 sterane 20S / (20S + 20R), Ts / (Ts + Tm)) should be consistent, indicating homologous migration.

[0143] Target area optimization: Sand-shale interbedded frequent zone: Areas with high vertical migration efficiency, such as interbeds of thin sandstones and organic-rich shales.

[0144] 6.2.2 Evidence of oil sources from different origins: Differences in maturity parameters: For example, the sterane maturity index 20S / (20S + 20R) shows high maturity, but the hopane index Ts / (Ts + Tm) shows low maturity, and the two cannot be matched. This indicates that the migrated hydrocarbons and the native hydrocarbons may have different sources (such as steranes from a deep high-maturity source and hopanes from a shallow low-maturity source), resulting in a "split" in the maturity reflected by different biomarkers. It shows that the migrated hydrocarbons are from oil sources with different origins.

[0145] Differences in the fractionation characteristics of non-hydrocarbon compounds: There are differences in the composition of non-hydrocarbon compounds retained in the hydrocarbon-generating series and those migrated to the hydrocarbon-storing series. For example, the hydrocarbon-generating series is rich in non-hydrocarbon compounds with short chains and high condensation degrees, while the hydrocarbon-storing series is rich in non-hydrocarbon compounds with long chains and low condensation degrees. This difference is caused by the fractionation during migration, indicating that they are not completely homologous.

[0146] Target area optimization: Areas with thick sandstone development. Massive sandstones with strong lateral conduction ability, especially the slope zones adjacent to high-maturity hydrocarbon source rocks.

[0147] Therefore, the layer division method of the present invention based on XRF mineral scanning and combined optical microscopy observations of plane-polarized light-fluorescence-laser confocal microscopy can accurately identify and cut the micron-level layer boundaries of laminated core samples at different scales. Perform quantitative fluorescence analysis of the reservoir and extraction of group components on the separated independent layers, and then perform chromatographic-mass spectrometry analysis and FT-ICR MS analysis on the extracted saturated, aromatic, non-hydrocarbon, and asphaltene group components. Comprehensive analysis of the data such as TSF spectra, light and heavy components, biomarker compounds, and non-hydrocarbon compounds obtained from the above experiments realizes the quantification of oiliness differences at the lamina scale and oil source correlation, and clarifies the micro-migration phenomenon of shale oil. Overcome the influence of the heterogeneity of laminated core samples on the results obtained by traditional analysis methods. This technical breakthrough provides direct evidence for the accurate prediction of shale oil sweet spots, reduces exploration risks, and improves economic benefits.

[0148] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit them. Although the present invention has been described in detail with reference to the preferred embodiments, those of ordinary skill in the art should understand that they can still modify or equivalently replace the technical solutions of the present invention, and such modifications or equivalent replacements do not make the modified technical solutions deviate from the spirit and scope of the technical solutions of the present invention.

Claims

1. A method for slicing different strata of laminated shale and identifying and recognizing oil-bearing properties, characterized in that It includes the following steps: Step S1, core profile slicing and description: Use a diamond wire saw to finely slice the stratified shale core in the direction perpendicular to the bedding plane, and record the formation thickness, color, and texture characteristics through visual observation. Step S2, XRF mineral scanning and formation division at the core scale: On the basis of visually observing the core, use an X-ray fluorescence spectrometer and a single-polarized / orthogonal-polarized light microscope to scan the core profile, clarify the significant differences between formation elements and mineral compositions, and highlight the formation interfaces that are difficult to distinguish by the naked eye during the core observation process. Step S3, oily optical observation and detection: Based on the element-mineral formation division results established by the combination of XRF and polarizing microscope in Step S2, observe through the combination of a fluorescence microscope and a laser confocal microscope. Utilize the excitation and luminescence characteristics of hydrocarbon substances to directly observe the differential distribution of hydrocarbons inside the stratified core, accurately identify the differences in organic matter distribution and oil properties in different formations of the core profile, and obtain the differences in oil content, mobility, and oil quality between different formations according to the reservoir quantitative fluorescence analysis technology, and clarify the hydrocarbon differential response under the background of the endogenous-reservoir structure of the shale formation. Use the observed luminescence intensity and color differences of the fluorescence microscope to observe different oil components such as oil, gum, and asphaltene. The laser confocal microscope quantifies the three-dimensional spatial distribution of light oil and heavy components with a micron-level resolution, directly proving the significant differences in oil properties between formations and dividing the formation differences of the core. Step S4, formation wire cutting and sample preparation: Through the high-precision formation division results in Step S3, precisely wire cut the formation / lamina interfaces of the core to obtain independent samples for each formation. Step S5, geochemical analysis of hydrocarbon components: Extract the group components of each independent formation sample, and conduct gas chromatography-mass spectrometry analysis and Fourier transform ion cyclotron resonance mass spectrometry analysis on the extracted group components to clarify the differences in biomarker compounds and non-hydrocarbon compounds between different formations, reflect the differences in organic matter maturity in different formations, and clarify the oil source differences; combine the hydrocarbon differential response of the endogenous-reservoir structure of the shale formation to clarify the micro-migration phenomenon of shale oil. Step S6, data fusion and comprehensive evaluation: Through systematic comparison of the experimental results of laser confocal and reservoir quantitative fluorescence analysis technology, group component analysis, gas chromatography-mass spectrometry analysis, and Fourier transform ion cyclotron resonance mass spectrometry analysis on different formations, clarify the differences in oil properties and organic matter maturity between different shale formations, clarify the oil source differences, and reveal the micro-migration phenomenon of shale oil being homologous or non-homologous between different formations through comprehensive data analysis.

2. The method for slicing different strata of laminated shale and identifying and recognizing oil-bearing property according to claim 1, wherein In Step S3, the cryogenic observation method of a laser confocal microscope is used to observe the crude oil in the micron-submicron level pores of different formations. In the scanning result, the off-white color represents the reflected light of mineral rock; the green color represents the short-wave fluorescence signal, reflecting volatile light oil; the red color represents the long-wave fluorescence signal, reflecting heavy components; and they converge into a light and heavy component volume distribution map.

3. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 1, characterized in that In step S3, the reservoir quantitative fluorescence analysis technology includes QGF analysis and / or TSF analysis. The ratio of tricyclic aromatic hydrocarbons to monocyclic aromatic hydrocarbons in crude oil is reflected by the TSF analysis results, which characterizes the density and maturity of crude oil. The oil quality is judged as medium-heavy oil, light oil or condensate oil by combining the TSF spectrum and the n-alkane curve.

4. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 1, characterized in that, In step S5, a family component separation experiment is carried out on independent samples of each layer system. Saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons and asphaltenes are extracted from the samples. The specific steps are as follows: (1) Sample pretreatment: After removing the surface contamination, the sample is crushed to 200 mesh, 20-40 g of powder is weighed, and Soxhlet extraction is carried out for 72 h. The extraction solvent is a ternary azeotropic mixed solvent of acetone-chloroform-methanol with a volume ratio of 38:32:30; Take the extract, add an excessive amount of n-hexane, ultrasonic oscillate and then stand for 24 hours to precipitate asphaltenes; Centrifuge or filter to separate asphaltenes, and collect the filtrate containing saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon components; (2) Asphaltene separation: Dissolve the precipitate in toluene, filter to remove insoluble impurities, evaporate the solvent and weigh to calculate the asphaltene content; (3) Column chromatography separation is carried out on the filtrate containing saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon components: ① Column packing: Use a glass chromatographic column and fill it with activated silica gel or alumina with a mesh size of 100-200; Cover the top with quartz sand or glass wool; ② Sample loading: Mix the filtrate with a small amount of silica gel, evaporate the solvent to make a uniform powder, and transfer it to the top of the chromatographic column; ③ Gradient elution: Elute with 3 times the column volume of n-hexane and collect the eluate containing saturated hydrocarbons; Switch to elution with 3 times the column volume of toluene and collect the eluate containing aromatic hydrocarbons; Finally, elute with dichloromethane / methanol with a volume ratio of 9:1 and collect the eluate containing non-hydrocarbon components; ④ Solvent removal: Concentrate the eluates containing saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbons respectively with a rotary evaporator, evaporate the solvent to obtain saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon components respectively, weigh, and calculate the mass percentage of each component.

5. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 4, characterized in that, Chromatography-mass spectrometry analysis is carried out on the saturated hydrocarbons or aromatic hydrocarbons extracted from samples of different layer systems. A retention time-mass spectrometry database is established using n-alkane and polycyclic aromatic hydrocarbon standards. The total ion current chromatogram and the mass spectra of each component are recorded through a chromatography-mass spectrometry workstation. The NIST mass spectrometry library or a self-built database is used to match the compound structures to clarify the differences in biomarker compound parameters in different layer systems, indicating the maturity of organic matter and oil source differences, and indicating the micro-migration phenomenon of shale oil.

6. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 4, characterized in that Fourier transform ion cyclotron resonance mass spectrometry analysis is carried out on the non-hydrocarbon components extracted from different layer systems. The possible elemental composition is calculated using the accurate mass number, and the double bond equivalence is calculated to infer the degree of unsaturation and structural type of the compound, and a molecular formula distribution map is generated.

7. A method for slicing different strata of laminated shale and identifying and recognizing oil-bearing properties according to claim 1, characterized in that, In step S6, the micro-migration phenomenon is judged by hydrocarbon component analysis, biomarker compounds and non-hydrocarbon compounds.

8. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 7, characterized in that, The layer system is judged as a rich organic matter layer or a poor organic matter layer by the proportion of saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons and asphaltenes in the extract; In hydrocarbon component analysis, if the contents of saturated hydrocarbons and aromatic hydrocarbons extracted from the organic-rich strata are relatively low, while the contents of non-hydrocarbons and asphaltenes are relatively high, and the contents of saturated hydrocarbons and aromatic hydrocarbons extracted from the organic-poor strata are high, and the content of normal paraffins with low carbon numbers is significantly high, it indicates that the organic-rich strata are the hydrocarbon-generating strata, the organic-poor strata are the hydrocarbon-storing strata, and micro-migration of hydrocarbons has occurred from the organic-rich strata to the organic-poor strata.

9. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 8, characterized in that, If the maturity of biomarker compounds in the hydrocarbon-generating strata and the hydrocarbon-storing strata is consistent and the types of original organic matter are similar, it is homologous migration.

10. A method for slicing different strata of laminated shale and identifying oil-bearing properties according to claim 8, characterized in that, If the maturity of biomarker compounds in the hydrocarbon-generating strata and the hydrocarbon-storing strata cannot be matched, and there are differences in the composition of non-hydrocarbon compounds between the hydrocarbon-generating strata and the hydrocarbon-storing strata, indicating that the shale oils in the hydrocarbon-generating strata and the hydrocarbon-storing strata are not completely homologous, then the oil sources of the migrated hydrocarbons are not homologous.

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