A method for segmenting different strata of stratified shale and identifying their oil content

Abstract

The present invention discloses a method for segmenting different strata of layered shale and identifying their oil content, and belongs to the field of oil and gas exploration. The layer segmentation method is based on XRF mineral scanning and single polarization-fluorescence-laser confocal optical microscope joint observation, which realizes the precise identification and segmentation of micron-level stratum boundaries of layered core samples from different scales, extracts group components from the segmented independent strata, and performs chromatography-mass spectrometry analysis and FT-ICR MS analysis on the extracted saturated, aromatic, non-aromatic, bitumen and other group components. The TSF spectra, light and heavy components, biomarker compounds and non-hydrocarbon compounds obtained from the above experiments are comprehensively analyzed to achieve quantification of oil content differences and oil source comparison at the laminar scale, and clarify the micro-migration phenomenon of shale oil. The influence of heterogeneity of layered core samples on the results obtained by traditional analysis methods is overcome. This technological breakthrough provides direct evidence for the accurate prediction of shale oil sweet spots, reduces exploration risks and improves economic benefits.

Description

Technical Field

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

[0002] The core challenge facing current shale oil content detection technology lies in its methodological limitations. Traditional detection methods, such as Rock-Eval pyrolysis and nuclear magnetic resonance (NMR), assume that shale is homogenized, assessing oil content and hydrocarbon composition through bulk sampling and analysis. This approach inherently ignores the significant layered structure and heterogeneity of stratified shales. Shales are composed of multiple vertically stacked layers or strata, ranging from millimeters to centimeters in size. Different strata exhibit significant heterogeneity in key parameters such as mineralogy (varying ratios of clay minerals to brittle minerals), organic matter abundance, and pore structure (varying connectivity of micropores and mesopores).

[0003] This interlayer heterogeneity creates two technical limitations. First, existing integrated detection methods sample different layers together, ignoring the heterogeneity of layered shale. This also smooths out interlayer variations in parameters such as oil content and the ratio of light to heavy components. This makes it difficult to precisely locate localized shale oil-rich layers and quantify the differences in quality between high-quality oil layers (light oil-rich layers) and conventional layers, obscuring key geological information. Second, while existing technical systems offer high-precision detection capabilities, they lack experimental methods for layer segmentation and ignore the fundamental impact of core heterogeneity on experimental results, making it impossible to interpret the multi-factor-driven micromigration of shale oil between layers. This migration is governed by complex mechanisms, including interlayer physical property differences, hydrocarbon generation potential gradients, hydrocarbon expulsion intensity, pore space configuration, mineral conductivity, preservation stability, and the coupled relationship between migration forces and resistances. These mechanisms drive hydrocarbons to accumulate in specific layers, forming localized enrichment zones (i.e., exploration sweet spots). However, traditional methods find it difficult to capture the resulting multi-dimensional differences in composition, organic matter maturity, and other aspects, and also to identify hydrocarbon migration pathways.

[0004] Therefore, it is urgent to develop methods for segmenting different strata of layered shale and identifying their oil content, so as to fully reveal the differential hydrocarbon responses of the source-reservoir structure between strata caused by the heterogeneity of layered shale, and to clarify the differences in oil sources and the micro-migration of shale oil. Summary of the Invention

[0005] The present invention aims to provide a method for segmenting and identifying the oil content of different strata in stratified shale. This stratum demarcation method, based on combined XRF mineral scanning and single polarization-fluorescence-laser confocal optical microscopy observation, enables precise identification and segmentation of micron-level stratum boundaries in stratified core samples at different scales. Reservoir quantitative fluorescence analysis and group component extraction are then performed on the segmented independent strata. The extracted saturated, aromatic, non-aromatic, and bitumen group components are then subjected to chromatography-mass spectrometry and FT-ICRMS analysis. Comprehensive analysis of the TSF spectra, light and heavy components, biomarker compounds, and non-hydrocarbon compounds obtained from these experiments allows for quantification of laminar-scale oil content differences and oil source comparison, clarifying shale oil micromigration phenomena. This overcomes the impact of heterogeneity in stratified core samples on the results obtained by traditional analytical methods. This technological breakthrough provides direct evidence for the accurate prediction of shale oil sweet spots, reducing exploration risks and improving economic efficiency.

[0006] To achieve the above-mentioned object, the present invention provides a method for segmenting different strata of stratified shale and identifying their oil content, comprising the following steps:

[0007] Step S1, core sectioning and description: Use a diamond wire cutting machine to perform fine sectioning of the layered shale core perpendicular to the bedding direction, and record the thickness, color, and texture characteristics of the layer system through visual observation;

[0008] Step S2, core-scale XRF mineralogy scanning and stratigraphic division: Based on visual observation of the core, the core profile is scanned using an X-ray fluorescence spectrometer and a single polarized / orthogonal light microscope to identify significant differences in the elements and mineral compositions of the stratigraphic layers and highlight stratigraphic interfaces that are difficult to distinguish with the naked eye during core observation.

[0009] Step S3, optical observation of oil content: Based on the mineral-element stratification results established by combining XRF with polarizer in step S2, observations are made using a fluorescence microscope and a laser confocal microscope. Utilizing the excitation luminescence characteristics of hydrocarbon substances, the heterogeneity of hydrocarbon distribution within the layered core is directly observed, and the differences in organic matter distribution and oil content in different strata of the core section are accurately identified.

[0010] Fluorescence microscopy was used to observe the differences in luminescence intensity and color, and to label the different oil-containing components of oil, colloid, and asphaltene. Laser confocal microscopy was used to quantify the three-dimensional spatial distribution of light and heavy hydrocarbons at micron-level resolution, directly proving the significant differences in oil content and quality between strata, and to differentiate the strata of the core.

[0011] 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;

[0012] 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 micro-migration phenomenon of shale oil;

[0013] 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 of 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 micro-migration phenomenon of shale oil of the same or different sources between different strata is revealed.

[0014] Preferably, in step S3, a cryo-observation method of a laser confocal microscope is used to observe crude oil in micron-submicron pores of different layers. In the scanning results, grayish white represents reflected light from mineral rocks; green represents short-wave fluorescence signals, reflecting volatile light oil; red represents long-wave fluorescence signals, reflecting heavy components; and the results are aggregated into a volume distribution diagram of light and heavy components.

[0015] Preferably, in step S3, the reservoir quantitative fluorescence analysis technique includes QGF analysis and / or TSF analysis. TSF spectra have a certain inherent correlation with geochemical parameters and can be used to predict the composition and maturity of crude oil and inclusion hydrocarbons, establishing a link between hydrocarbon inclusions, crude oil, and oil source. The R1 and R2 values ​​of TSF reflect the ratio of tricyclic aromatic hydrocarbons to monocyclic aromatic hydrocarbons in crude oil and have a strong negative correlation with the Ts / (Ts + Tm) maturity parameter of biomarker compounds, thus being used to characterize the density and maturity of crude oil.

[0016] There is a certain intrinsic relationship between the TSF spectrum and the normal alkane curve: 1. For medium-heavy oil, R1>3.0, the maximum excitation wavelength and the maximum emission wavelength Ex / Em are around 250 / 375nm, and the carbon number of the main peak of saturated hydrocarbon gas chromatography is generally greater than C 24 , the main peak wavelength of TSF spectrum is greater than 450nm; 2. Light oil, its R1 is mainly concentrated in 2.0~3.0, Ex / Em is around 260 / 350nm, and the main peak carbon number of saturated hydrocarbon gas chromatography is C 16 ~C 23 The maximum wavelength of TSF spectrum is mainly concentrated between 420 and 450 nm; 3. Condensate oil, its R1 is less than 2.0, Ex / Em is around 250 / 340 nm, and the carbon number of the main peak of saturated hydrocarbon gas chromatography is generally less than C 14, the maximum wavelength of the TSF spectrum is less than 420nm.

[0017] Preferably, in step S5, a group component separation experiment is performed on independent samples of each layer system to extract saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons and asphaltenes from the samples. The specific steps are:

[0018] (1) Sample pretreatment: After removing surface contamination, the sample was crushed to 200 mesh, 20-40 g of powder was weighed, and Soxhlet extraction was performed for 72 h. The extraction solvent was a ternary azeotropic mixture of acetone, chloroform, and methanol with a volume ratio of 38:32:30. The extract was added with excess n-hexane, ultrasonically vibrated, and allowed to stand for 24 h to allow the asphaltene to precipitate. The asphaltene was separated by centrifugation or filtration, and the filtrate containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon components was collected.

[0019] (2) Asphaltene separation: dissolve the precipitate in toluene, filter to remove insoluble impurities, evaporate the solvent, and weigh to calculate the asphaltene content;

[0020] (3) Column chromatography separation of the filtrate containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon components:

[0021] ① Column packing: Use a glass chromatographic column, filled with activated 100-200 mesh silica gel or alumina; cover the top with quartz sand or glass wool;

[0022] ② 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;

[0023] ③ Gradient elution:

[0024] Elute with 3 column volumes of n-hexane and collect the eluate containing saturated hydrocarbons;

[0025] Switch to 3 column volumes of toluene elution and collect the eluate containing aromatic hydrocarbons;

[0026] Finally, it was eluted with dichloromethane / methanol in a volume ratio of 9:1, and the eluate containing non-hydrocarbon components was collected;

[0027] ④ Solvent removal: The eluents containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbons were concentrated using a rotary evaporator. After the solvent was evaporated, the saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon components were obtained respectively. The components were weighed and the mass percentage of each component was calculated.

[0028] Preferably, saturated hydrocarbons or aromatic hydrocarbons extracted from samples from different strata are subjected to chromatography-mass spectrometry analysis, and a retention time-mass spectrometry database is established using normal alkane and polycyclic aromatic hydrocarbon standards. The total ion current and mass spectra of each component are recorded by a chromatography-mass spectrometry workstation, and the compound structure is matched using the NIST mass spectrometry library or a self-built database to clarify the differences in biomarker compound parameters in different strata, indicate the maturity of organic matter and the difference in oil source, and indicate the micro-migration phenomenon of shale oil.

[0029] Preferably, non-hydrocarbon components extracted from different strata are analyzed using Fourier transform ion cyclotron resonance mass spectrometry. Accurate mass numbers are used to calculate the likely elemental composition, double bond equivalence calculations are used to infer compound unsaturation and structural types, and generate molecular formula distribution maps. Shale oil contains a rich variety of non-hydrocarbon compounds, with strong heterogeneity in their distribution within the formation. These compounds are sensitive to the formation and evolution of shale oil and can effectively trace the generation, migration, and accumulation of shale oil within the strata. Oil source comparisons based on the similarity of non-hydrocarbon compound composition can identify hydrocarbon reservoirs, trace the direction of shale oil migration, and determine the primary crude oil-producing strata.

[0030] Preferably, in step S6, the micromigration phenomenon is determined by hydrocarbon component analysis, biomarker compounds, and non-hydrocarbon compounds.

[0031] Preferably, in the organic-rich strata, saturated hydrocarbons and aromatic hydrocarbons dominate the extracts, while in the organic-poor strata, the proportion of non-hydrocarbons and asphaltenes increases significantly; in the hydrocarbon component analysis, if the content of saturated hydrocarbons and aromatic hydrocarbons extracted in the organic-rich strata is relatively low, and the content of non-hydrocarbons and asphaltenes is relatively high, while the content of saturated hydrocarbons and aromatic hydrocarbons extracted in the organic-poor strata is high, and the content of low-carbon normal alkanes is significantly high, then it is a typical feature of hydrocarbon migration, indicating that the organic-rich strata are hydrocarbon-generating strata, the organic-poor strata are hydrocarbon-storing strata, and hydrocarbons have undergone micro-migration from the organic-rich strata to the organic-poor strata.

[0032] Preferably, if the maturity of the biomarker compounds in the hydrocarbon-generating strata and the hydrocarbon-reservoir strata are consistent and the original organic matter types are similar, the migrated hydrocarbons are homologous migration.

[0033] Preferably, if the maturity of the biomarker compounds in the hydrocarbon-generating and reservoir layers does not match, with the maturity of the hydrocarbon-generating layer lower than that of the reservoir layer, and the maturity indicators of the biomarker compounds do not match, this indicates that the migrated hydrocarbons and the local hydrocarbons may have different sources, resulting in a "split" in the maturity reflected by different biomarkers. In addition, the non-hydrocarbon compounds in the hydrocarbon-generating and reservoir layers differ in composition, such as the hydrocarbon-generating layer being rich in short-chain, highly condensed non-hydrocarbon compounds, while the reservoir layer is rich in long-chain, low-condensed non-hydrocarbon compounds. This difference is caused by fractionation during migration, indicating that they are not completely homologous, and the oil source of the migrated hydrocarbons is different.

[0034] Therefore, the present invention adopts the above-mentioned method for segmenting different strata of stratified shale and identifying oil content, which has the following beneficial effects:

[0035] (1) The present invention proposes a stratum division method based on XRF mineral scanning. By optimizing the division algorithm and setting cutting precision control protection points, the accurate identification of micron-level stratum boundaries is achieved. Compared with traditional methods, this technology significantly reduces the experimental error caused by shale heterogeneity. Specifically, the present invention combines the joint observation process of single polarization, fluorescence and laser confocal microscopy, and uses multi-dimensional optical parameter combination and data analysis to achieve accurate quantification of oil content differences at the laminar scale. This innovation overcomes the quantitative bias caused by ignoring core heterogeneity in traditional methods. This technical system has been verified in terrestrial shales (such as the Ordos Basin) and marine shales (such as the Sichuan Basin). Its high-precision stratification and oil content evaluation capabilities provide a key geological basis for sweet spot prediction.

[0036] (2) By combining FT-ICR MS with chromatography-mass spectrometry data, fluorescence observations, and laser confocal microscopy data, we were able to identify differences in oil content between strata and the phenomenon of shale oil micromigration, significantly improving the accuracy of sweet spot prediction. This technological breakthrough provides direct evidence for understanding the "source-storage-transportation" coupling mechanism and supports the development of differentiated exploration strategies.

[0037] (3) Based on precise stratum segmentation and oil-bearing identification technology, ineffective drilling sampling is reduced, significantly reducing exploration costs. Accurate prediction of shale oil sweet spots is achieved, the success rate of single-well drilling is improved, and the proportion of ineffective wells is significantly reduced. This technology combination directly reduces exploration risks and promotes the economic and efficient development of shale oil.

[0038] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] Figure 1 Schematic diagram of core section cutting;

[0040] Figure 2 This is the XRF mineral scan image;

[0041] Figure 3 This is an optical observation diagram of oil content in different layers;

[0042] Figure 4 is the volume distribution diagram of light and heavy components; wherein, a is the volume distribution diagram of light and heavy components at position 1; b is the volume distribution diagram of light and heavy components at position 2; c is the volume distribution diagram of light and heavy components at position 3;

[0043] Figure 5 For sand sheet samples;

[0044] Figure 6 The TSF analysis spectrum of sample A, a is the TSF analysis spectrum of the sand layer system, b is the TSF analysis spectrum of the sheet layer system;

[0045] Figure 7 This is the effect diagram of precise cutting of core layers;

[0046] Figure 8 The biomarker compound index change diagram for the stratified analysis of sample A;

[0047] Figure 9 This is the biomarker compound index change diagram of randomly selected points of parallel sample B;

[0048] Figure 10 This is the curve of the relative abundance of N1 compounds changing with DBE under the stratified analysis of sample A;

[0049] Figure 11 This is the curve of the relative abundance of N1 compounds at randomly selected points of parallel sample B changing with DBE. DETAILED DESCRIPTION

[0050] The technical solution of the present invention is further described below with reference to the accompanying drawings and embodiments.

[0051] Unless otherwise defined, technical or scientific terms used in the present invention shall have the same meaning as commonly understood by one of ordinary skill in the art to which the present invention belongs.

[0052] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the following will refer to the accompanying drawings of the embodiments of the present invention. Figures 1 to 11 The technical solutions of the present invention are clearly and completely described. Obviously, the embodiments described are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making any creative efforts are within the scope of protection of the present invention.

[0053] In the description of the present invention, it should be understood that the terms "center", "surroundings", "horizontal", "longitudinal", "length", "thickness", "angle", "up", "down", "left", "right", etc., which indicate directions or positions, are limited to simplifying the description of the present invention, rather than specific positions or directions. The above terms are not limitations of the present invention.

[0054] The present invention provides a method for segmenting different strata of stratified shale and identifying their oil content, comprising the following steps:

[0055] Step S1, core sectioning and description: Use a diamond wire cutting machine to perform fine sectioning of the layered shale core perpendicular to the bedding direction, and record the thickness, color and texture characteristics of the layer system through visual observation.

[0056] Step S2, core-scale XRF mineral scanning and stratum division: Based on visual observation of the core, the core profile is scanned using an X-ray fluorescence spectrometer and a single polarization / orthogonal light microscope to clarify the significant differences between the stratum elements and mineral compositions, and to highlight the stratum interfaces that are difficult to distinguish with the naked eye during core observation.

[0057] 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.

[0058] 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.

[0059] 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.

[0060] 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.

[0061] The specific steps are as follows:

[0062] Step S1: Core section segmentation and description:

[0063] 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.

[0064] Implementation conditions: The core needs to be pretreated to a moisture content of <5%, and the cutting speed is ≤0.5mm / s.

[0065] Step S2: XRF mineral scanning to divide the layers:

[0066] 2.1. High-resolution (10 μm) scanning of the core profile was performed using an X-ray fluorescence spectrometer (Bruker M4 Tornado). Stratigraphic and laminar segments were divided based on differences in mineral composition (quartz, clay, and pyrite).

[0067] 2.1.1 Experimental Principle:

[0068] 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 by the sample after it is excited. This is typically performed using an X-ray fluorescence spectrometer. During measurement, the sample is placed in the instrument and excited with X-rays. The elements in the sample absorb the X-rays and are excited to a high-energy state that emits X-rays. The energy of these emitted X-rays is related to the element type, and the type and content of the element in the sample can be determined by measuring the energy of these X-rays.

[0069] 2.1.2 Experimental steps:

[0070] (1) Surface polishing: The longitudinal plane of the cut rock sample is placed on a grinding machine for grinding to make the longitudinal surface of the core smoother and flatter.

[0071] (2) Ultrasonic cleaning: Pour an appropriate amount of cleaning solution (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 capacity of stains on the sample surface.

[0072] (3) Vacuum drying: Place the sample in a vacuum drying oven and set a certain temperature and pressure for drying. Principle: The vacuum drying oven is filled with inert gas, which can quickly dry the sample in a very clean environment. This is especially true for items with complex components, such as those in clean laboratories and aerospace units that are heat-sensitive, easily decomposed, and easily oxidized. The surface of the sample after treatment is smooth, dry, and free of oil stains.

[0073] (4) Sample testing: After removing dust from the bulk shale sample, secure it with plasticine in the sealed vacuum chamber of the instrument, with its smooth surface facing upward. The X-ray device is controlled to turn on and evenly scan the upper surface of the sample. The instrument reads the unique wavelength of the X-rays to qualitatively identify the elements contained in the sample.

[0074] 2.1.3 Experimental results:

[0075] Based on the naked eye observation of the core, XRF scanning can more intuitively find the significant differences in elements of different layers. Figure 2 Taking the identification of Ca in a sample as an example, the lighter-colored areas represent the Ca distribution in the sample. From this diagram, we can distinguish different strata based on elemental differences. This indicates that different strata within the same core vary in composition, necessitating separate analysis of each stratum. XRF scanning is even more helpful in distinguishing stratum boundaries, clarifying the boundaries of stratum changes beyond visual observation and facilitating subsequent precise segmentation of core strata.

[0076] 2.2. Single polarized light / orthogonal light microscope (equipment model: Olympus BX53): Identify mineral structure and organic matter distribution.

[0077] 2.2.1 Experimental Principle

[0078] Under a microscope, the morphology and cleavage direction of mineral particles can be used to determine the history of crystal growth or deformation. Organic matter is typically amorphous carbonaceous material, which appears black or dark brown under single polarized light due to its strong absorption, contrasting with transparent minerals.

[0079] Under single-polarized light, minerals may display characteristics such as color, pleochroism, and morphology, which can help identify the mineral species. Under orthogonal light, information such as the mineral's birefringence and extinction angle can be used to determine the crystal structure and orientation, thereby analyzing the fabric. For example, quartz exhibits wavy extinction under orthogonal light, which may reflect its deformation history.

[0080] Organic matter is often amorphous and may appear to have a specific color or transparency, such as black or brown, under single-polarized light. However, organic matter may not exhibit interference colors under orthogonal light because it is amorphous, and therefore may exhibit total extinction under orthogonal light. This can be used to distinguish organic matter from minerals.

[0081] 2.2.2 Experimental steps

[0082] (1) Clarify the sampling requirements. For samples with identifiable layers, slice them vertically. Use a cutting machine to cut each sample into 25mm×25mm×5mm or 25mm×5mm diameter rock samples.

[0083] (2) Glue dripping method: For densely bonded rocks, it is appropriate to use methyl α-cyanoacrylate or non-fluorescent α-cyanoacrylate instant strong adhesive for glue dripping.

[0084] (3) Diamond grinding disc surface grinding method: Grind the glued rock sample on the No. 120, No. 320, No. 500, No. 1000, No. 2000, and No. 3000 diamond grinding discs in turn by dripping water until the surface is bright.

[0085] (4) Strong adhesive method: Use a smooth or single-sided frosted slide as the slide. Use a piece of textile to clean the slide and the ground rock sample surface. Use a non-fluorescent α-cyanoacrylate instant strong adhesive to stick the slide together.

[0086] (5) Machine slicing method: Turn on the cooling water, adsorb the rock slice on the vacuum clamp of the slicer, check to make sure it is firmly adsorbed, cut the rock slice into a flat surface of 0.8mm~1.2mm, wash and dry.

[0087] (6) Automatic grinding method: Divide the rock slices into batches according to the thickness of the glass slide. Place the same batch of rock slices in the automatic grinding machine. After turning on the cooling water, set the thickness to 0.04mm~0.05mm and start the grinding. Then, use W7 diamond abrasive with water on the glass plate, or drip water on the 1000, 2000, and 3000 diamond discs to grind to 0.030mm~0.035mm. The quartz interference color is first-grade grayish white. If it is carbonate rock, the thickness is 0.040mm. The structure is clear under the polarizing microscope and the interference color is high-grade white. No particles fall off.

[0088] (7) The polarizing film should be covered with a cover glass. Place the cover glass on the glue surface and squeeze it with tweezers to remove bubbles. Soak it in alcohol and then rinse it with clean water.

[0089] (8) Polarizing microscope observation: Use a 4× or 10× objective lens to look for areas with dense distribution of minerals and organic matter.

[0090] 2.2.3 Experimental Results

[0091] After XRF scanning identifies the core layers, polarizing microscopy allows for more precise observation of the differences in mineral composition within these layers, further validating the need to study stratified shales in their respective layers. Polarizing microscopy can highlight interlayer interfaces that are difficult to distinguish with the naked eye during core observation, enabling precise demarcation of the interfaces between different layers. Fluorescence microscopy is then used to further demonstrate differences in the distribution and content of organic matter within these layers.

[0092] Step S3: Optical observation and detection of oil content:

[0093] 3.1. Fluorescence microscope (equipment model: Leica DM6B): excitation wavelength 365 nm, observe the fluorescence intensity and distribution of hydrocarbons.

[0094] 3.1.1 Experimental Principle

[0095] The hydrocarbons in shale are divided into four groups based on their solubility in mixtures of solutions of varying polarity: saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons, and asphaltenes. Within the reservoir, hydrocarbons accumulate in varying proportions, and these components exhibit distinct fluorescence properties. Under certain fluorescence intensities, they exhibit different colors. Therefore, the content and distribution of different components within shale can be analyzed by zoning their fluorescence colors.

[0096] 3.1.2 Experimental steps

[0097] (1) Clarify the sampling requirements. For samples with identifiable layers, slice them vertically. Use a cutting machine to cut each sample into a rock sample of 25mm×25mm×5mm or 25mm×5mm in diameter.

[0098] (2) Glue dripping method: Use non-fluorescent α-cyanoacrylate instant strong adhesive to drip glue for solidification.

[0099] (3) Diamond grinding disc surface grinding method: Grind the glued rock sample on the No. 120, No. 320, No. 500, No. 1000, No. 2000, and No. 3000 diamond grinding discs in turn by dripping water until the surface is bright.

[0100] (4) Strong adhesive method: Use a smooth or single-sided frosted slide as the slide. Use a piece of textile to clean the slide and the ground rock sample surface. Use a non-fluorescent α-cyanoacrylate instant strong adhesive to stick the slide together.

[0101] (5) Machine slicing method: Turn on the cooling water, adsorb the rock slice on the vacuum clamp of the slicer, check to make sure it is firmly adsorbed, cut the rock slice into a flat surface of 0.8mm~1.2mm, wash and dry.

[0102] (6) Automatic grinding method: Divide the rock slices into batches according to the thickness of the glass slide. Place the same batch of rock slices in the automatic grinding machine. After turning on the cooling water, set the thickness to 0.04mm~0.05mm and start the grinding machine. Then, fine-grind with W7 diamond abrasive and water on the glass plate, or drip water on the 1000, 2000, and 3000 diamond discs to 0.030mm~0.035mm.

[0103] (7) The fluorescent slice should be covered with a cover glass. Place the cover glass on the glue surface and squeeze with tweezers to remove bubbles. After drying in a 50℃ oven, store away from light to prevent oxidation of the fluorescent substance.

[0104] (8) Microscope settings:

[0105] Excitation light source: mercury lamp or LED light source, choose ultraviolet light (365 nm) or blue light (450 nm) excitation.

[0106] Filter configuration: Excitation filter: allows light of a specific wavelength to pass (such as BP 450-490 nm).

[0107] Emission filter: intercepts the fluorescence signal (e.g. LP 515 nm).

[0108] Objective lens selection: 10×50× oil immersion objective lens to improve resolution.

[0109] 3.1.3 Experimental Results

[0110] Based on the observation of the same layer area with a polarizing microscope, the difference in the fluorescence color of the oil in different layers clearly reveals the difference in the distribution and content of organic matter in different layers. The difference in fluorescence color can preliminarily indicate the distribution of hydrocarbon components in different layers and simply indicate the oil quality of different layers. The fluorescence colors of different oils are shown in Table 1:

[0111] Table 1 Fluorescence colors of different oils

[0112] ;

[0113] Then, laser confocal microscopy was used to observe the differences in oil quality in different layers in depth.

[0114] 3.2 Laser confocal microscopy (Zeiss LSM 900): Three-dimensional reconstruction of the pore-hydrocarbon occurrence relationship.

[0115] 3.2.1 Experimental Principle

[0116] Laser scanning confocal microscopy offers advantages such as high resolution, simple sample preparation, a high degree of penetration, and the integration of laser scanning and digital image processing. It is used to study the pore structure characteristics of unconventional lithologies such as tight sandstones, providing rapid, accurate, and intuitive information on micropore structure and organic matter composition. Using a fixed-wavelength 488nm laser to excite the sample, light components in crude oil produce fluorescence signals in the 490nm to 600nm range, while heavy components produce fluorescence signals in the 600nm to 800nm ​​range.

[0117] Basic principles of light and heavy component analysis: Traditional experimental observations suggest that the fluorescence color of liquid hydrocarbons can reflect the degree of organic matter evolution. That is, as organic matter evolves from low maturity to high maturity, its fluorescence color changes from fiery red → yellow → orange → blue → bright yellow (blue shift).

[0118] 3.2.2 Experimental steps

[0119] Slice → Glue → Polish slices → Glue → Grind thin slices → Label. Do not soak in organic solvents before sectioning. Sectioning requires that oil-bearing rock samples be kept frozen during drilling and sectioning. Samples must be frozen in liquid nitrogen before sectioning. After sectioning, air-dry the sample at a temperature below 5°C and then bond it with 502 glue in a vacuum environment. When rough grinding, if loose rock particles have fallen off, re-bond it with glue and then grind again until there are no holes. Allow the sample to dry out before mounting it on a slide.

[0120] 3.2.3 Experimental Results

[0121] The cryo-observation method of laser scanning confocal microscopy was used to observe crude oil in micron-submicron pores of different layers. Figure 3 As shown in the scanning results, gray-white is used to represent the reflected light of the mineral rocks on the sample surface; green is used to represent the short-wave fluorescence signal, reflecting the volatile light oil; red is used to represent the long-wave fluorescence signal, reflecting the heavy components. The results are aggregated into Figure 4 The volume distribution of light and heavy components is shown in the figure, where positions 1, 2, and 3 are selected from different strata. The results show that position 1 is a shale stratum with fractures. The single-point fluorescence image shows yellow-green fluorescence in the fractures, while the shale stratum shows black or dark brown fluorescence reflections. The reconstruction of light and heavy components shows that the fractures are mostly light oil, while the shale is relatively more heavily distributed with heavy components. Position 2 is a carbonate stratum. The single-point fluorescence image shows mostly light yellow and yellow-green fluorescence. The laser confocal microscope light and heavy component reconstruction shows that the stratum is mainly light oil. Position 3 is a region with multiple fractures. The single-point fluorescence image shows sky blue and yellow-green fluorescence reflections. The fractures are mainly composed of nearby hydrocarbons that have migrated and accumulated in the fractures. The laser confocal microscope also shows that the green light oil is dominant.

[0122] Most shale strata are organic-rich and have stronger hydrocarbon-generating capacity than carbonate strata (organic-poor strata). Both the single-point fluorescence images and the light-heavy component reconstructions show that organic-rich strata contain more heavy components, while organic-poor strata are enriched in light oil components.

[0123] 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 existence of shale oil micro-migration between strata, verifying and supplementing the differences in oil quality in various strata observed by fluorescence microscopy.

[0124] 3.3 Reservoir Quantitative Fluorescence Analysis Technology: (Equipment Model: Varian Cary-Eclipse)

[0125] 3.3.1 Experimental Principle

[0126] Fluorescence is a type of photoluminescence, and fluorescence spectroscopy has been used in oil and gas exploration for over a century. Hydrocarbons in reservoirs, such as aromatic hydrocarbons and polar compounds, spontaneously fluoresce when excited by light of a certain wavelength. This fluorescence spectrum, generated by these hydrocarbons, can reveal a wide range of information, including the chemical composition and physical properties of crude oil and its abundance. Fluorescence spectroscopy can detect various forms of hydrocarbons, including diluted or undiluted hydrocarbons, surface coatings, and oil and gas inclusions, at concentrations of 10⁻⁶ or lower. Compared to MCI (fluid inclusion composition analysis), which can also detect the molecular composition of adsorbed and encapsulated hydrocarbons in reservoirs, quantitative particle fluorescence technology offers the advantages of low sample requirements, economical, high-volume, rapid, and highly sensitive analysis.

[0127] TSF spectra represent the fluorescence signature of hydrocarbons associated with reservoir particles and can be used to identify current or residual oil reservoirs during exploration and drilling evaluation. Studies have shown that TSF spectra of samples from current or residual oil reservoirs exhibit relatively high fluorescence intensity, while those from water layers exhibit very low and flat intensities, consistent with the fluorescence spectrum of dichloromethane solvent at 320-370 nm. Therefore, TSF intensity can reflect the content of hydrocarbons associated with reservoir particles. This content is positively correlated with oil saturation; higher TSF intensity indicates higher oil saturation. The maximum wavelength (λmax) of the TSF spectrum reflects the composition and density of the crude oil.

[0128] 3.3.2 Experimental steps

[0129] (1) Sample crushing: The collected original core and cuttings samples are crushed appropriately, lightly ground, and sieved to select about 2g of analytical sample particles with a particle size of 30-80 mesh. The particles are placed in small beakers with a capacity of 50ml and numbered one by one in sequence.

[0130] (2) Repeatedly rinse the sample in the beaker with distilled water until the clay on the surface of the particles is removed, leaving coarse, relatively pure, granular sand particles. Then dry it in the air or place it in a drying oven set at 40°C.

[0131] (3) Add 20 ml of dichloromethane to a fully dried beaker and place it in an ultrasonic cleaner for 10 minutes. After allowing it to stand for 40 minutes, pour out the dichloromethane solution in the beaker and allow the sample to evaporate to dryness. The purpose of this step is that dichloromethane is an organic solvent and can be used to remove hydrocarbons adsorbed on the rock surface.

[0132] (4) Add 40 ml of 10% hydrogen peroxide solution to a fully dried beaker. Shake the beaker with an ultrasonic cleaner for 10 minutes, then let it sit for 40 minutes. Shake it again for another 10 minutes, then pour out the hydrogen peroxide solution in the beaker and rinse with distilled water until the residue dissolved by the hydrogen peroxide is completely removed. The purpose of this step is to remove clay minerals and partially oxidized cement from the particle surface.

[0133] (5) After the distilled water wash is complete, add 40 ml of a 3.6% HCl solution and let it sit for 20 minutes. During this time, stir the sample in a clockwise direction with a glass rod. Some bubbles will appear in the beaker. Stir until no more bubbles appear. Then, discard the HCl solution and rinse the sample repeatedly with distilled water as in the previous step. This step is to remove carbonate cement from the particle surface.

[0134] (6) Place the small beaker containing the sample in a constant temperature box with a temperature less than 60°C for drying.

[0135] (7) Pour 20 ml of dichloromethane into each of the dried samples, shake them in an ultrasonic cleaner for 10 minutes, and then place the dichloromethane extract in the beaker into a reagent bottle and seal it for storage. The collected solution will be used for QGF-E analysis.

[0136] (8) Place the sample in the beaker in a fume hood for ventilation and drying. Weigh the dried pure particles with an electronic balance and record the specific data (accurate to 0.001g). Finally, use the sample for TSF and QGF analysis. The TSF analysis spectrum is as follows: Figure 6 shown.

[0137] 3.3.3 Experimental Results

[0138] Quantitative fluorescence analysis of reservoir samples from different strata reveals differences in oil content, mobility, and quality, highlighting the need for oil content analysis in these strata. Spectra such as TSF and QGF have a certain inherent connection with geochemical parameters, allowing them to predict the composition and thermal maturity of crude oil and inclusion hydrocarbons, establishing a link between hydrocarbon inclusions and crude oil and oil sources. Subsequent geochemical analysis of samples from different strata can further reveal differences in oil content between different strata or laminae in shale, as well as the phenomenon of shale oil micromigration.

[0139] The R1 and R2 values ​​of the TSF reflect the ratio of tricyclic aromatic hydrocarbons to monocyclic aromatic hydrocarbons in crude oil. They have a strong negative correlation with the maturity parameter Ts / (Ts + Tm) of biomarker compounds and can be used to characterize the density and maturity of crude oil. The smaller the R1 and R2 values, the lighter the oil.

[0140] Figure 5Quantitative fluorescence analysis of the reservoirs was conducted on sandstone and shale formations, examining the differences in oil quality between the different formations. The sandstone formation had an Ex / Em ratio of approximately 260 / 350 nm and an R1 of less than 3, indicating that the sandstone formation contained mostly light oil. The shale formation, on the other hand, had an R1 of 6 and maximum excitation and emission wavelengths of approximately 250 / 375 nm, indicating that the shale formation contained mostly medium-heavy, viscous oil.

[0141] Step S4: Layer Wire Cutting and Sample Preparation

[0142] Based on XRF classification and optical microscope observation, the layer / lamina interface of sample A core was precisely cut (accuracy ±0.1mm), such as Figure 7 As shown, four independent samples of the layers were obtained.

[0143] Step S5: Geochemical analysis of hydrocarbon components

[0144] 5.1. Group component separation: separate saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons and asphaltenes.

[0145] 5.1.1 Experimental Principle

[0146] Crude oil molecules are diverse and have complex chemical structures. Group composition is a commonly used parameter that generally describes the chemical composition characteristics of petroleum and reflects the quality of shale oil. Based on solubility and polarity, crude oil components are divided into saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons (colloids), and asphaltenes. Saturated hydrocarbons primarily contain the elements C and H, and are primarily alkanes and cycloalkanes, with low viscosity and good flowability. Aromatic hydrocarbons primarily consist of aromatic compounds with two or more rings and have lower fluidity. Gums and asphaltenes, on the other hand, are rich in highly polar, large-molecule non-hydrocarbon compounds, typically with high viscosity and poor flowability. Different groups of components have different polarities, and gradient solvent elution utilizes the polarity-selective adsorption of adsorbents (such as silica gel and alumina) to gradually separate the components.

[0147] 5.1.2 Experimental steps

[0148] (1) Sample pretreatment: After removing surface contamination, the sample was crushed to 200 mesh. 20-40 g of powder was weighed and subjected to Soxhlet extraction for 72 h. The extraction solvent was a ternary azeotropic mixture of acetone, chloroform, and methanol (38:32:30, volume ratio).

[0149] Take an appropriate amount of extract, add excess n-hexane (about 40 times the volume), and then ultrasonically vibrate and let it stand for 24 hours to allow the asphaltene to precipitate.

[0150] Separate the asphaltene (precipitate) by centrifugation or filtration and collect the filtrate (containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbons).

[0151] (2) Asphaltene separation: dissolve the precipitate in toluene, filter to remove insoluble impurities, evaporate the solvent and weigh it to calculate the asphaltene content.

[0152] (3) Column chromatography separation (saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons):

[0153] ① Column Packing: Use a glass column filled with activated silica gel or alumina (100-200 mesh). Avoid air bubbles when packing the column and cover the top with quartz sand or glass wool.

[0154] ② Loading: Mix the filtrate (sample after removing asphaltene) 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.

[0155] ③ Gradient elution:

[0156] Saturated hydrocarbons: elute with n-hexane (about 3 column volumes) and collect the eluate.

[0157] Aromatic hydrocarbons: switch to toluene elution (about 3 column volumes) and collect the eluate.

[0158] Non-hydrocarbons (gum): Finally, elute with dichloromethane / methanol (9:1, v / v) and collect the eluate.

[0159] ④Solvent removal: The eluates of each component were concentrated using a rotary evaporator, and the solvent was evaporated and then weighed to calculate the mass percentage of each component.

[0160] 5.1.3 Experimental Results

[0161] Extracts are obtained from precisely segmented layer samples to separate saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons (resins), and asphaltenes.

[0162] 5.2. Chromatography-Mass Spectrometry (Agilent 7890B-5977B): Saturated Hydrocarbons, Aromatic Hydrocarbons (Page 7H)

[0163] 5.2.1 Experimental Principle

[0164] (1) Principle of gas chromatography:

[0165] Separation principle: The difference in distribution coefficients of different compounds between the stationary phase (chromatographic column) and the mobile phase (carrier gas) leads to different retention times in the chromatographic column, thus achieving separation.

[0166] Applicability: Saturated hydrocarbons (such as normal alkanes and branched alkanes) and aromatic hydrocarbons (such as monocyclic and polycyclic aromatic hydrocarbons) can be efficiently separated by gas chromatography due to differences in boiling points and polarity.

[0167] (2) Principle of mass spectrometry:

[0168] Ionization: Compounds are ionized by electron impact (EI) or chemical ionization (CI).

[0169] Mass analysis: Ions are separated according to their mass-to-charge ratio (m / z), a mass spectrum is generated, and the compound structure is identified through characteristic fragment ion and molecular ion peaks.

[0170] Advantages of combined use: Gas chromatography separates components, mass spectrometry provides structural information, and qualitative and quantitative analysis can be achieved by combining retention time and mass spectrum.

[0171] 5.2.2 Experimental steps

[0172] (1) Sample pretreatment

[0173] Dissolution: Dissolve the separated saturated hydrocarbon or aromatic hydrocarbon components in a low-polarity solvent (such as n-hexane, dichloromethane) with the concentration controlled at 0.1-1 mg / mL.

[0174] Filtration: Pass through a 0.22 μm organic filter membrane to remove particulate matter and prevent clogging of the chromatography column.

[0175] (2) Instrument preparation

[0176] Column selection: Non-polar columns (such as HP-5MS, 5% phenylmethylpolysiloxane) are suitable for hydrocarbon analysis.

[0177] Carrier gas: high-purity helium (He), flow rate 1-2 mL / min.

[0178] Heating program: Initial temperature: 50°C (maintain for 2 minutes)

[0179] Heating rate: 5-10℃ / min to 300℃ (hold for 10 minutes)

[0180] (3) Chromatography-mass spectrometry analysis conditions

[0181] Injection mode: split / splitless injection (1 μL, split ratio 10:1).

[0182] Ion source temperature: 230 °C (EI mode, electron energy 70 eV).

[0183] Scan mode: full scan (m / z 50-550) or selected ion monitoring (SIM).

[0184] (4) Calibration of standard products

[0185] Use normal alkanes (C8-C 40 ), polycyclic aromatic hydrocarbons (such as naphthalene, phenanthrene, and pyrene) standards were used to establish a retention time-mass spectrometry database.

[0186] (5) Data collection and processing

[0187] The total ion chromatogram (TIC) and mass spectra of each component were recorded by a chromatograph-mass spectrometer workstation. Compound structures were matched using the NIST mass spectral library or a self-built database.

[0188] 5.2.3 Experimental Results

[0189] By performing gas chromatography-mass spectrometry analysis on the saturated hydrocarbons and aromatic hydrocarbons extracted from the different layer samples separated from sample A, the ∑nC 20- / ∑nC 21+ The differences in biomarker compound parameters such as β-catenin and TAR values ​​were analyzed. Figure 8 As shown. Biomarker compounds can indicate the maturity of organic matter, such as C 29 The ratios of 20S / (20S+20R) and ββ / (ββ+αα) isomers of regular steranes increase with increasing maturity; the ratio of Ts / (Ts+Tm) in hopanes increases with increasing maturity, while the ratio of C30 molanes / C30 hopanes decreases.

[0190] The naphthalene and phenanthrene series of aromatic hydrocarbons are also important biomarkers for micromigration. For shale formations, the ratios of trimethylnaphthalene to trimethylphenanthrene (∑TMN / ∑TMP), tetramethylnaphthalene to tetramethylphenanthrene (TeMN / TeMP), and the overall ratios of the naphthalene series to the phenanthrene series (∑N / ∑P) are lower in source layers than in reservoir layers. This differentiation is attributed to the greater expulsion of naphthalene compared to phenanthrene during oil migration.

[0191] In contrast, the results of gas chromatography-mass spectrometry analysis of randomly selected locations on sample B are as follows: Figure 9 As shown, no clear regular changes can be observed in the various biocompound indicators. The experimental results of both methods indicate that stratified analysis can clarify hydrocarbon migration pathways at the stratum or laminar scale and provide a detailed assessment of shale oil content, thus avoiding analytical errors caused by shale heterogeneity.

[0192] Samples from the Sample A stratum were analyzed. For example, Lamina 2 is an organic-rich stratum with high organic matter maturity, and various biochemical indicators correspond to its high maturity. Lamina 4, on the other hand, is an organic-poor stratum with a (∑N / ∑P) ratio greater than that of the organic-rich stratum, indicating micromigration of shale oil. Other biomarker compound indicators also show high maturity, confirming micromigration of shale oil through biochemical indicators.

[0193] 5.3 FT-ICR MS (Bruker solariX)

[0194] 5.3.1 Experimental Principle

[0195] (1) Technical characteristics of FT-ICR MS

[0196] Ultra-high resolution and mass accuracy: Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) achieves precise determination of the mass-to-charge ratio (m / z) by measuring the cyclotron frequency of ions in a strong magnetic field. The resolution can reach over one million levels and can distinguish compounds with extremely small mass differences (such as isotope peaks and isomers).

[0197] 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 non-hydrocarbon components of petroleum.

[0198] (2) Characteristics of non-hydrocarbon components

[0199] Non-hydrocarbons (colloids) primarily contain polar compounds, such as acidic substances (carboxylic acids, phenols), nitrogen-containing compounds (pyrroles, carbazoles), sulfur-containing compounds (thiophenes), and large polar molecules (such as asphaltene fragments). Traditional mass spectrometry makes it difficult to resolve their complex molecular composition. However, FT-ICR MS combined with soft ionization techniques (such as electrospray ionization (ESI) and atmospheric pressure chemical ionization (APCI)) preserves molecular integrity and provides molecular formula information.

[0200] (3) Selection of ionization method

[0201] ESI (electrospray ionization): Suitable for polar compounds (such as acidic and alkaline substances containing O and N), and negative ion mode is used to detect deprotonated molecules.

[0202] APCI / APPI: Suitable for weakly polar aromatic compounds (such as polycyclic sulfur-containing aromatic hydrocarbons).

[0203] 5.3.2 Experimental steps

[0204] (1) Sample pretreatment

[0205] Dissolution: Dissolve the non-hydrocarbon components in a polar solvent (such as methanol: water = 1:1, or toluene: methanol mixture) at a concentration of approximately 0.1 mg / mL.

[0206] Desalting: Use solid phase extraction (SPE) or dialysis to remove salts to avoid mass spectrometry signal suppression.

[0207] Filtration: Pass through a 0.22 μm filter to remove particulate matter.

[0208] (2) Instrument parameter setting

[0209] Ionization source: ESI negative ion mode (for acidic compounds) or positive ion mode (for basic compounds).

[0210] Spray voltage: 3-4 kV

[0211] Drying gas temperature: 200-300℃

[0212] Mass range: m / z 150-1000, covering the typical molecular weight range of non-hydrocarbons.

[0213] Accumulation time: 0.5-1 second / scan, 64-128 times accumulation to improve signal-to-noise ratio.

[0214] (3) Data collection and analysis

[0215] Molecular formula assignment: Calculate the possible elemental composition (such as C, H, O, N, S combination) using accurate mass (error <1 ppm).

[0216] Double bond equivalence (DBE) calculations are used to infer the degree of unsaturation and structural type (e.g., aromaticity, degree of condensation) of a compound.

[0217] Visualization: Generate molecular formula distribution plots (e.g., DBE vs. carbon number plots, heteroatom class abundance plots).

[0218] 5.3.3 Experimental Results

[0219] 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 changing trends of the composition characteristics of non-hydrocarbon compounds such as N1 and N2 in different layers were analyzed. In the core hydrocarbon-generating layer samples, N1 compounds with high condensation degree and large parent core structure are relatively enriched. The distribution of neutral N1 compounds DBE in shale oil varies greatly among different rock types, reflecting the differences in the oil generation, migration and accumulation processes in different layers. The curve of the relative abundance of N1 compounds in the four layers of sample A as a function of DBE is shown in the figure below. Figure 10 As shown in the figure, the DBE distribution characteristics of N1 type compounds are obvious, among which layer 2 is an organic-rich layer, layers 1 and 4 are organic-poor layers but have received hydrocarbon migration, and layer 3 is an organic-poor layer that has not received hydrocarbon migration. The results show that in the organic-rich series samples, N1 type compounds with higher condensation degree and larger parent core structure are relatively enriched.

[0220] In contrast, the results of FT-ICR MS performed on randomly selected locations on sample B are as follows: Figure 11 As shown in the figure, the DBE distribution characteristics of N1 compounds are broadly distributed without a significant peak. The heterogeneity of the sample causes the high condensation N1 signal to be diluted by the low condensation molecules.

[0221] Step S6: Data fusion and comprehensive evaluation (comparison of overall advantages and disadvantages)

[0222] 6.1 Demonstrating the advantages of separation layer systems

[0223] Independent layer samples obtained through precise separation technology can clarify the following key geological understandings:

[0224] ① Analysis of oil quality differences at the stratum level: Separation stratum technology enables detailed characterization of the hydrocarbon composition (light-heavy component ratio) and oil quality across different strata. Analysis of independent stratum samples allows for the precise identification and quantification of significant differences in light-heavy component distribution between strata. These differences are not only a direct indicator of stratum oil quality but also key evidence for the existence of shale oil micro-migration between strata.

[0225] ② Geochemical multi-parameter coupled characterization: Based on independent samples obtained from separated layers, saturated hydrocarbon-aromatic hydrocarbon-non-hydrocarbon-asphaltenes composition analysis quantifies hydrocarbon phase differences. Combined with chromatography-mass spectrometry and Fourier transform ion cyclotron resonance mass spectrometry, it is possible to clearly distinguish between biomarker compounds (such as terpanes and steranes) and non-hydrocarbon compounds (such as nitrogen- and oxygen-containing compounds) in samples from different layers. These layer-specific geochemical differences reflect differences in organic matter maturity (such as variations in the isomerization ratio of C29 steranes), providing evidence for oil source correlation and micromigration between layers.

[0226] ③ "Source-reservoir" structural coupling mechanism: Within the context of shale reservoirs, separate stratum studies are key to elucidating how inter-stratum micromigration leads to localized abnormal shale oil enrichment. Only by accurately separating and independently analyzing different strata can the specific migration pathways of shale oil between strata be effectively tracked and clarified. This technical system establishes a complete chain of evidence for shale oil "sweet spot" prediction, from characterizing stratum heterogeneity to differential hydrocarbon responses to source-reservoir structures, clarifying oil source differences and shale oil micromigration.

[0227] For example, in a study of a shale oil formation, it was found that the uncut core showed general oil content as a whole, but 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. The comprehensive analysis results of the oil quality of each layer were compared with the test results of the uncut core. This highlighted that after the formation division and separation, the oil quality characteristics of each layer can be evaluated more accurately, fully reflecting the advantages of separated layers in the fine evaluation of oil quality, avoiding the inter-layer differences that may be covered up by the overall evaluation when not cut, and providing more targeted and accurate formation oil quality information for subsequent exploration and development, thereby guiding the rational selection of development layers, optimizing mining plans, and improving the exploration and development efficiency and benefits of shale oil and gas resources.

[0228] 6.2 Comparing Geochemical Parameters of Separated Strata: Evidence of Homologous and Dissimilar Oil Sources – Guiding Exploration and Development

[0229] Organic geochemical analysis of the separated layers can provide rich oil-source correlation information. Hydrocarbon component analysis shows that the organic-rich layers have relatively low saturated hydrocarbon and aromatic hydrocarbon contents, while non-hydrocarbon and asphaltene contents are high. On the contrary, the organic-poor layers have high saturated hydrocarbon and aromatic hydrocarbon contents, especially the low-carbon normal alkanes, which are typical characteristics of migrating hydrocarbons and indicate that hydrocarbons have undergone micro-migration from the organic-rich layers to the organic-poor layers. Biomarker compound analysis can further provide evidence for oil-source correlation. For example, ∑nC 20- / ∑nC 21+ Differences in biomarker parameters such as α and TAR values ​​across different strata reflect the distribution of light and heavy hydrocarbons and the maturity of organic matter. Abnormal biomarker maturity indicators in organic-poor strata, such as significantly different 20S / (20S+20R) and ββ / (ββ+αα) ratios of C29 regular steranes compared to organic-rich strata, may be due to the influence of migrating hydrocarbons, indicating the presence of either homologous or divergent oil sources. By systematically comparing geochemical parameters across separate strata, the oil source characteristics of different strata can be clarified, allowing accurate identification of micromigration within shale formations. This provides key insights for shale oil exploration and development, guiding the rational selection of development strata, optimizing production plans, and improving the efficiency and benefits of shale oil and gas exploration and development.

[0230] 6.2.1 Evidence of a common oil source:

[0231] The connection between hydrocarbon-generating strata and reservoir strata: Hydrocarbon-generating strata generate large amounts of hydrocarbons, which are then expelled and migrate to the reservoir strata, forming "intra-source sweet spots." This suggests a genetic connection between "intra-source sweet spots" and hydrocarbon-generating strata, suggesting similarities in the original organic matter type and maturity of the two.

[0232] Maturity consistency: The maturity of biomarkers (such as C29 sterane 20S / (20S+20R), Ts / (Ts+Tm)) in hydrocarbon-generating and reservoir layers should be consistent, indicating homologous migration.

[0233] Target area selection: frequent sand-shale interbeds: areas with high vertical migration efficiency, such as interbeds of thin sandstone and organic-rich shale.

[0234] 6.2.2 Evidence of oil sources from different sources:

[0235] Differences in maturity parameters: For example, the sterane maturity index 20S / (20S+20R) indicates high maturity, while the hopane index Ts / (Ts+Tm) indicates low maturity. This mismatch indicates that the migrating hydrocarbons and local hydrocarbons may have different sources (e.g., steranes originate from deep, highly mature sources, while hopanes originate from shallow, less mature sources). This leads to a "discrepancy" in the maturity profiles of the different biomarkers, suggesting that the migrating hydrocarbons originate from different oil sources.

[0236] Differences in the fractionation characteristics of non-hydrocarbon compounds: The composition of non-hydrocarbon compounds retained in hydrocarbon-generating strata differs from that of non-hydrocarbon compounds that migrate to hydrocarbon-reservoir strata. For example, hydrocarbon-generating strata are rich in short-chain, highly condensed non-hydrocarbon compounds, while hydrocarbon-reservoir strata are rich in long-chain, less condensed non-hydrocarbon compounds. This difference is due to fractionation during migration, indicating that they are not completely homologous.

[0237] Preferred target areas: areas with thick sandstone development, massive sandstone with strong lateral conductivity, especially in slope zones adjacent to highly mature source rocks.

[0238] Therefore, the present invention uses a stratum demarcation method based on XRF mineral scanning and combined observation using single polarization-fluorescence-laser confocal microscopy to accurately identify and segment micron-level stratum boundaries in layered core samples at different scales. The segmented independent strata undergo quantitative reservoir fluorescence analysis and group component extraction, followed by chromatography-mass spectrometry and FT-ICR MS analysis of the extracted saturated, aromatic, non-aromatic, and bitumen group components. A comprehensive analysis of the TSF spectra, light and heavy components, biomarker compounds, and non-hydrocarbon compounds obtained from the above experiments allows for quantification of laminar-scale oil content differences and oil source comparison, clarifying the phenomenon of shale oil micromigration. This overcomes the impact of heterogeneity in layered core samples on the results obtained by traditional analytical methods. This technological breakthrough provides direct evidence for the accurate prediction of shale oil sweet spots, reduces exploration risks, and improves economic efficiency.

[0239] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention rather than to limit the same. Although the present invention has been described in detail with reference to the preferred embodiments, those skilled in the art should understand that they can still modify or replace the technical solutions of the present invention with equivalents, and these modifications or equivalent replacements cannot cause the modified technical solutions to deviate from the spirit and scope of the technical solutions of the present invention.

Claims

1. A method for segmenting different strata of stratified shale and identifying their oil content, characterized in that: The following steps are involved: Step S1, core sectioning and description: Use a diamond wire cutting machine to perform fine sectioning of the layered shale core perpendicular to the bedding direction, and record the thickness, color, and texture characteristics of the layer system through visual observation; Step S2, core-scale XRF mineralogy scanning and stratigraphic division: Based on visual observation of the core, the core profile is scanned using an X-ray fluorescence spectrometer and a single polarized / orthogonal light microscope to identify significant differences in the elements and mineral compositions of the stratigraphic layers and highlight stratigraphic interfaces that are difficult to distinguish with the naked eye during core observation. Step S3, optical observation and detection of oil content: Based on the element-mineral stratum division results established by combining XRF with polarizing microscope in step S2, observations are made by combining fluorescence microscopy with laser confocal microscopy, and the excitation luminescence characteristics of hydrocarbon substances are utilized to directly observe the differential distribution of hydrocarbons within the layered core. The distribution of organic matter and the difference in oil content in different strata of the core section are accurately identified. Based on the reservoir quantitative fluorescence analysis technology, the differences in oil content, mobility, and oil quality between different strata are obtained, and the differential response of hydrocarbons in the source-reservoir structure of the shale stratum is clarified: Fluorescence microscopy was used to observe the differences in luminescence intensity and color, and to observe the different oil-bearing components of oil, colloid, and asphaltene. Laser confocal microscopy quantified the three-dimensional spatial distribution of light oil and heavy components at micron-level resolution, directly proving the significant differences in oil quality between strata and differentiating the strata of the core. In step S3, a cryo-observation method using a laser confocal microscope is used to observe the crude oil in the micron-submicron pores of different layers. In the scanning results, gray-white represents the reflected light of the mineral rock; green represents the short-wave fluorescence signal, reflecting the volatile light oil; and red represents the long-wave fluorescence signal, reflecting the heavy component. The light and heavy components are aggregated into a volume distribution map; Step S4, stratum linear cutting and sample preparation: Based on the high-precision stratum demarcation results in step S3, precise linear cutting is performed 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, 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 micro-migration phenomenon of shale oil; Step S6, data fusion and comprehensive evaluation: By systematically comparing 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 micro-migration phenomenon of shale oil from the same or different sources between different strata is revealed; In step S6, the micromigration phenomenon is determined by hydrocarbon component analysis, biomarker compounds, and non-hydrocarbon compounds; The proportion of saturated hydrocarbons and aromatic hydrocarbons, non-hydrocarbons and asphaltene in the extracts is used to determine whether the layer is organic-rich or organic-poor. In the hydrocarbon component analysis, if the contents of saturated hydrocarbons and aromatic hydrocarbons extracted from the organic-rich layer are relatively low, and the contents of non-hydrocarbons and asphaltene are relatively high, while the contents of saturated hydrocarbons and aromatic hydrocarbons extracted from the organic-poor layer are high, and the content of low-carbon normal alkanes is significantly higher, it indicates that the organic-rich layer is a hydrocarbon-generating layer, the organic-poor layer is a hydrocarbon-storage layer, and hydrocarbons have undergone micro-migration from the organic-rich layer to the organic-poor layer.

2. The method for segmenting different strata of stratified shale and identifying oil content according to claim 1, characterized in that: In step S3, the reservoir quantitative fluorescence analysis technology includes QGF analysis and / or TSF analysis. The TSF analysis results reflect the ratio of tricyclic aromatic hydrocarbons to monocyclic aromatic hydrocarbons in the crude oil, characterizing the density and maturity of the crude oil. The TSF spectrum and the normal alkane curve are combined to determine whether the oil quality is medium-heavy oil, light oil or condensate oil.

3. The method for segmenting different strata of stratified shale and identifying oil content according to claim 1, characterized in that: In step S5, a group component separation experiment is performed on independent samples of each layer system to extract saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons and asphaltenes from the samples. The specific steps are as follows: (1) Sample pretreatment: After removing surface contamination, the sample was crushed to 200 mesh, 20-40 g of powder was weighed, and Soxhlet extraction was performed for 72 h. The extraction solvent was a ternary azeotropic mixture of acetone, chloroform, and methanol with a volume ratio of 38:32:

30. The extract was added with excess n-hexane, ultrasonically vibrated, and allowed to stand for 24 h to allow the asphaltene to precipitate. The asphaltene was separated by centrifugation or filtration, and the filtrate containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon components was collected. (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 of the filtrate containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon components: ① Column packing: Use a glass chromatographic column, filled with activated 100-200 mesh silica gel or alumina; cover the top with quartz sand or glass wool; ② 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 column volumes of n-hexane and collect the eluate containing saturated hydrocarbons; Switch to 3 column volumes of toluene elution and collect the eluate containing aromatic hydrocarbons; Finally, it was eluted with dichloromethane / methanol in a volume ratio of 9:1, and the eluate containing non-hydrocarbon components was collected; ④ Solvent removal: The eluents containing saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbons were concentrated using a rotary evaporator. After the solvent was evaporated, the saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon components were obtained respectively. The components were weighed and the mass percentage of each component was calculated.

4. The method for segmenting different strata of stratified shale and identifying oil content according to claim 3, characterized in that: The saturated hydrocarbons or aromatic hydrocarbons extracted from samples from different strata are subjected to chromatography-mass spectrometry analysis. Standards of normal alkanes and polycyclic aromatic hydrocarbons are used to establish a retention time-mass spectrometry database. The total ion current and mass spectra of each component are recorded by a chromatography-mass spectrometry workstation. The compound structures are matched using the NIST mass spectral library or a self-built database to clarify the differences in biomarker compound parameters in different strata, indicate differences in organic matter maturity and oil source, and indicate the micro-migration phenomenon of shale oil.

5. The method for segmenting different strata of stratified shale and identifying oil content according to claim 3, characterized in that: The non-hydrocarbon components extracted from different layers were analyzed by Fourier transform ion cyclotron resonance mass spectrometry. The possible elemental composition was calculated using accurate mass numbers, and the double bond equivalence was calculated to infer the unsaturation and structural type of the compounds and generate a molecular formula distribution map.

6. The method for segmenting different strata of stratified shale and identifying oil content according to claim 1, characterized in that: If the maturity of biomarker compounds in the hydrocarbon-generating and reservoir strata is consistent and the original organic matter types are similar, then migration is from the same source.

7. The method for segmenting different strata of stratified shale and identifying oil content according to claim 1, characterized in that: If the maturity of the biomarker compounds in the hydrocarbon-generating and hydrocarbon-reservoir layers does not match, and there are differences in the composition of non-hydrocarbon compounds in the hydrocarbon-generating and hydrocarbon-reservoir layers, it indicates that the shale oil in the hydrocarbon-generating and hydrocarbon-reservoir layers is not completely homologous, and the oil sources of the migrated hydrocarbons are different.

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