A shale oil enrichment area identification result determination method and device

Abstract

This specification provides a method and apparatus for determining the identification results of shale oil enrichment areas. Petrographic and diagenetic sequence processing is performed on vein samples to determine the host minerals corresponding to fluid inclusions at different accumulation stages; fluorescence information of fluid inclusions in the host minerals is obtained; based on the fluorescence information, the equivalent maturity and abundance parameters of fluid inclusions in the host minerals are determined; in-situ and isotopic tests are performed on the host minerals to obtain time constraint parameters and formation temperature parameters; based on the equivalent maturity, abundance, time constraint, formation temperature, and formation evolution data, the shale oil accumulation period information of the target area is determined; based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity and abundance parameters, the identification results of shale oil enrichment areas within the target area are determined, thereby significantly improving the accuracy of shale oil enrichment area identification results and effectively reducing the ambiguity of the identification results.

Description

Technical Field

[0001] This manual belongs to the field of oil and gas geological exploration technology, and in particular relates to a method and apparatus for determining the identification results of shale oil enrichment areas. Background Technology

[0002] As shale oil exploration expands into deeper and more complex areas, such as those at normal pressure, reconstructing the hydrocarbon accumulation process using fluid inclusions has become a key method for identifying shale oil-rich areas. However, existing technologies mostly focus on qualitative observation or single-parameter analysis, resulting in low accuracy and multiple interpretations in the identification of shale oil-rich areas.

[0003] There is currently no effective solution to the above problems. Summary of the Invention

[0004] This specification provides a method and apparatus for determining the identification results of shale oil enrichment areas, which solves the technical problem of high ambiguity and low identification accuracy in shale oil reservoir identification due to the lack of quantitative spatiotemporal coupling between microscopic fluid influx and macroscopic stratigraphic evolution.

[0005] This specification provides a method for determining the identification results of shale oil enrichment areas, including: Acquire vein samples and stratigraphic evolution data of the shale strata in the target area; The vein samples were subjected to petrographic and diagenetic sequence processing to determine the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages. Obtain fluorescence information of fluid inclusions in the host mineral; and determine the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information; In-situ and isotopic tests were performed on the host mineral to obtain the time constraint parameters and formation temperature parameters of the host mineral. Based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data, the shale oil accumulation period information of the target area is determined; Based on the information on the shale oil accumulation period, and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, the identification results of shale oil enrichment areas within the target region are determined.

[0006] In one embodiment, determining the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information includes: The fluorescence information is converted into corresponding chromaticity parameters; wherein, the fluorescence information includes fluorescence images and fluorescence spectral data; Using a preset fitting model, the equivalent maturity parameters of fluid inclusions in the host mineral are determined based on the chromaticity parameters; The fluorescence image is used to identify the pulse region and obtain the corresponding fluorescence area by using a preset image processing algorithm; The abundance parameters of fluid inclusions in the host mineral are determined based on the ratio between the fluorescence area and the area of ​​the vein region in the host mineral.

[0007] In one embodiment, determining the abundance parameter of fluid inclusions in the host mineral based on the ratio of the fluorescence area to the area of ​​vein regions in the host mineral includes: The abundance parameters of fluid inclusions in the host mineral are determined according to the following formula:

[0008] in, For the abundance parameter, The fluorescence area is... The area of ​​the pulse region is denoted as .

[0009] In one embodiment, determining the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data includes: Based on the equivalent maturity parameter, the initial hydrocarbon accumulation time of the target area in the time series corresponding to the stratigraphic evolution data is determined; Based on the time constraint parameters and the formation temperature parameters, the time window for hydrocarbon accumulation events and the formation temperature boundary conditions in the time series are determined, and the preliminary hydrocarbon accumulation time is corrected based on the time window for hydrocarbon accumulation events and the formation temperature boundary conditions to determine the effective hydrocarbon accumulation time window; Based on the abundance parameter, determine the intensity weight of hydrocarbon accumulation activity at different time nodes within the effective hydrocarbon accumulation time window; Based on the intensity weight of the hydrocarbon accumulation activity, the effective hydrocarbon accumulation time window is inverted and calculated using a preset numerical optimization inversion algorithm to determine the shale oil accumulation period information of the target area.

[0010] In one embodiment, determining the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information, and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, includes: Based on the information on the shale oil accumulation period, determine the effective accumulation time window for shale oil in the target area; Using the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, potential enrichment regions that meet preset conditions are identified; wherein, the preset conditions include at least two of the following conditions: the equivalent maturity parameter is greater than a set threshold, the abundance parameter is higher than the regional average, and the fluorescence color of the fluid inclusions is blue or bluish-white; By spatiotemporally coupling the effective reservoir formation time window and the potential enrichment zone, the shale oil enrichment zone identification result within the target area is determined.

[0011] In one embodiment, the petrographic and diagenetic sequence processing of the vein sample to determine the host minerals corresponding to fluid inclusions at different hydrocarbon accumulation stages includes: The vein samples were subjected to petrographic observation to obtain diagenetic evidence characteristics; wherein, the diagenetic evidence characteristics include at least one of mineral contact relationships, crystal growth characteristics, cathodoluminescence characteristics, and inclusion occurrence characteristics; Based on the diagenetic evidence characteristics, the chronological order of formation of vein minerals in different phases of the vein sample is determined to obtain diagenetic sequence parameters; Based on the diagenetic sequence parameters and the occurrence characteristics of the fluid inclusions, the host minerals corresponding to the fluid inclusions in different hydrocarbon accumulation stages are determined through spatiotemporal matching analysis.

[0012] In one embodiment, the step of performing in-situ testing and isotopic testing on the host mineral to obtain the time-constrained parameters and formation temperature parameters of the host mineral includes: The U-Pb age of the host mineral was determined by laser ablation inductively coupled plasma mass spectrometry, and the U-Pb age was used as the time constraint parameter. Cluster isotope analysis was performed on the host mineral to determine the cluster isotope characterization parameters of the host mineral. By performing temperature conversion on the cluster isotope characterization parameters, the formation temperature during the formation period of the host mineral is determined, and the formation temperature is used as the formation temperature parameter.

[0013] This specification provides a device for determining the identification results of shale oil enrichment areas, including: The data acquisition module is used to acquire vein samples and stratigraphic evolution data of the shale strata in the target area; The host mineral determination module is used to perform petrographic and diagenetic sequence processing on the vein sample to determine the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages. The first parameter determination module is used to acquire fluorescence information of fluid inclusions in the host mineral; and to determine the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information. The second parameter determination module is used to perform in-situ testing and isotope testing on the host mineral to obtain the time constraint parameter and formation temperature parameter of the host mineral, respectively. The reservoir formation period determination module is used to perform multi-parameter joint inversion of the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data to determine the shale oil reservoir formation period information of the target area; The result determination module is used to determine the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information, as well as the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter.

[0014] This specification also provides a computer-readable storage medium storing computer instructions that, when executed, implement a method for determining the identification results of shale oil enrichment areas.

[0015] Based on the method for identifying shale oil enrichment areas provided in this specification, the following steps are taken: Vein samples and stratigraphic evolution data of shale formations in the target area are obtained; petrographic and diagenetic sequence processing is performed on the vein samples to determine the host minerals corresponding to fluid inclusions at different accumulation stages; fluorescence information of fluid inclusions in the host minerals is obtained; and based on the fluorescence information, the equivalent maturity and abundance parameters of fluid inclusions in the host minerals are determined; in-situ and isotopic tests are performed on the host minerals to obtain time constraint parameters and formation temperature parameters; based on the equivalent maturity parameters, abundance parameters, time constraint parameters, formation temperature parameters, and stratigraphic evolution data, the shale oil accumulation period information of the target area is determined; and based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity and abundance parameters, the shale oil enrichment area identification result within the target area is determined. In this way, by identifying the host minerals corresponding to fluid inclusions at different hydrocarbon accumulation stages and obtaining equivalent maturity parameters, abundance parameters, time constraint parameters, and formation temperature parameters, multi-parameter joint inversion of various quantitative parameters with formation evolution data is achieved, overcoming the problem of existing technologies that focus on qualitative analysis and lack quantitative coupling. By accurately determining the information on shale oil accumulation stages and combining the spatial distribution characteristics of equivalent maturity parameters and abundance parameters, the accuracy of shale oil enrichment zone identification results can be significantly improved, and the ambiguity of identification results can be effectively reduced. Attached Figure Description

[0016] To more clearly illustrate the embodiments of this specification, the accompanying drawings used in the embodiments will be briefly introduced below. The drawings described below are only some embodiments recorded in this specification. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0017] Figure 1 This is a flowchart illustrating a method for determining the identification results of shale oil enrichment areas, provided in one embodiment of this specification. Figure 2 This is a schematic diagram of the electronic device structure provided in one embodiment of this specification; Figure 3 This is a schematic diagram of the structural composition of a device for determining the identification results of shale oil enrichment areas, provided in one embodiment of this specification. Figure 4 This is a schematic diagram of the overall process for determining the identification results of shale oil enrichment areas, provided in one embodiment of this specification. Figure 5 This is a schematic diagram illustrating an embodiment of the present specification that uses an equivalent maturity index and a burial-thermal evolution history to determine the hydrocarbon accumulation period. Detailed Implementation

[0018] To enable those skilled in the art to better understand the technical solutions in this specification, the technical solutions in the embodiments of this specification will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this specification, and not all embodiments. Based on the embodiments in this specification, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of this specification.

[0019] See Figure 1 As shown in the embodiments of this specification, a method for determining the identification results of shale oil enrichment areas is provided, wherein the method is specifically applied to the server side. In specific implementation, the method may include the following: S101: Obtain vein samples and stratigraphic evolution data of the shale strata in the target area; S102: Perform petrographic and diagenetic sequence processing on the vein samples to determine the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages; S103: Obtain fluorescence information of fluid inclusions in the host mineral; and determine the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information; S104: Perform in-situ and isotopic tests on the host mineral to obtain the time constraint parameters and formation temperature parameters of the host mineral; S105: Determine the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data; S106: Based on the information on the shale oil accumulation period, and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, determine the identification result of the shale oil enrichment area within the target region.

[0020] Among them, the aforementioned vein samples can refer to physical geological specimens collected from shale strata fissures and filled with mineral deposits carried by underground fluids. These samples typically appear in rocks as vein-like or banded geological bodies formed by minerals (such as calcite, barite, quartz, etc.) filling fissures. They encompass various types, including carbonate veins and siliceous veins, and are key material carriers for recording the trajectory and evolution of fluids during geological history.

[0021] The aforementioned stratigraphic evolution data can refer to macroscopic geological background data obtained through basin simulation technology, including burial history curves, thermal history curves, and hydrocarbon generation history data of the target area over geological time.

[0022] The aforementioned petrographic and diagenetic sequence processing can refer to the process of extracting mineral cutting, replacement, and zoning characteristics using methods such as microscopic observation and cathodoluminescence, and establishing a logical sequence of mineral formation based on geological principles.

[0023] The host mineral mentioned above can refer to the mineral crystal body that seals and protects the fluid inclusions (such as calcite veins, quartz veins, etc.); it is the spatial carrier of the inclusions. By dating and measuring the temperature of the host mineral, the formation age and environment of the inclusions inside can be indirectly obtained.

[0024] The fluid inclusions mentioned above can refer to trace amounts of original formation fluids (oil, gas, water) that are trapped in mineral lattice defects during the mineral crystal growth process; they are in a completely sealed state and retain the physicochemical properties at the time of capture.

[0025] The aforementioned fluorescence information can refer to the luminescence characteristics produced by fluid inclusions under ultraviolet light excitation, including fluorescence images reflecting color distribution and fluorescence spectral data reflecting luminescence intensity; as an "optical fingerprint" of hydrocarbon molecules, it is the physical basis for quantitatively evaluating the properties and content of oil and gas.

[0026] The aforementioned equivalent maturity parameter can refer to a quantitative indicator reflecting the degree of thermal evolution of oil and gas, calculated using a fitting model based on the fluorescence colorimetric characteristics of fluid inclusions (usually corresponding to vitrinite reflectance).

[0027] The aforementioned abundance parameter can refer to the area ratio or distribution density of hydrocarbon fluid inclusions in the vein relative to the host mineral vein, obtained through image processing algorithms; it quantitatively characterizes the scale and intensity of hydrocarbon inflows in geological history.

[0028] The aforementioned time constraint parameter can refer to the absolute radioactive age of the host mineral U-Pb obtained by in-situ testing methods such as laser ablation inductively coupled plasma mass spectrometry (LA-ICP-MS); it provides a high-precision absolute time anchor for hydrocarbon accumulation events.

[0029] The aforementioned formation temperature parameters can refer to the ambient temperature at which the host minerals were formed, obtained through cluster isotope analysis or inclusion thermometry. It reflects the thermodynamic background during fluid capture and is key to inferring burial depth.

[0030] The aforementioned information on the formation period of shale oil reservoirs can refer to the absolute geological time range and peak time of shale oil accumulation that have been determined through multi-parameter joint inversion and preserved to this day.

[0031] The spatial distribution characteristics of the aforementioned equivalent maturity and abundance parameters can refer to the attribute trend map that reflects the change law of oil and gas "quality" and "quantity" by interpolating the maturity and abundance data obtained from microscopic tests in geographic plane or three-dimensional space; it solves the problem of the distribution law of "where the oil is good and where the oil is plentiful".

[0032] The aforementioned shale oil enrichment zone identification results can refer to the final conclusions regarding the geographical scope and potential level of shale oil "sweet spots" obtained through spatiotemporal coupling evaluation; it guides the priority order of well location deployment in industrial exploration.

[0033] In some embodiments, acquiring vein samples and stratigraphic evolution data of the shale system in the target area may specifically include: Shale samples containing mineral veins are collected from well cores or field outcrops. The mineral veins are then sliced ​​and polished on both sides to obtain fluid inclusion thin sections with a preset thickness, which serve as the vein samples. Based on the drilling stratigraphic data and paleothermal gradient data of the target area, the burial history and thermal history of the shale system with geological age are reconstructed using basin simulation. The curve data of the burial depth, formation temperature and maturity of the shale system with geological time are obtained as the stratigraphic evolution data.

[0034] In some embodiments, obtaining the fluorescence information of fluid inclusions in the host mineral may specifically include: The target fluid inclusions in the pulse sample are excited using an ultraviolet excitation source to obtain the fluorescence signal of the target fluid inclusions in the visible light band. The fluorescence image corresponding to the fluorescence signal is acquired using a microscopic image acquisition device; The fluorescence spectrum data of the fluorescence signal within a preset wavelength range are obtained using a microscopic spectral analysis device. The fluorescence information includes the fluorescence image and the fluorescence spectral data.

[0035] In some embodiments, after determining the shale oil enrichment zone identification result within the target area, the specific implementation may further include: Based on the shale oil enrichment zone identification results, evaluation target areas with different potential levels are delineated within the target area; Based on the information on the shale oil accumulation period and the tectonic evolution characteristics of the target area, the optimal well location is selected within the evaluation target area; Based on the selected optimal well locations, a corresponding horizontal well drilling plan and segmented fracturing design parameters are formulated, and shale oil development operations are carried out according to the plan and parameters.

[0036] In some embodiments, to overcome the shortcomings of existing technologies in determining the shale oil accumulation period and identifying enriched areas, this invention proposes a method for identifying the shale oil accumulation period and enriched areas based on fluid inclusion fluorescence chromaticity parameters and multi-parameter joint inversion. Preferably, the optical characteristics of fluid inclusions are introduced to improve the accuracy of maturity and stage division. The aim is to achieve the following objectives: Quantitative constraints on the shale oil accumulation period: reducing the ambiguity and uncertainty caused by relying solely on a single burial-thermal history or single dating method under the background of multi-stage fluid activity or complex thermal evolution. Reliable identification of highly mature, lightweight shale oil enriched areas: introducing a parameter system that can directly characterize the intensity and maturity of microscale hydrocarbon activity, improving the stability and repeatability of "sweet spot" identification. Establishing a scalable and standardized data processing workflow: enabling the method to be stably implemented under different well areas, different stratigraphic sequences, and different vein mineral assemblages, providing technical support for shale oil exploration evaluation and favorable area selection.

[0037] Based on the above embodiments, through deep coupling of multi-source information, the fluorescence chromaticity parameters, equivalent maturity, and abundance indices of fluid inclusions are jointly inverted with the U-Pb age and burial-thermal history of the host minerals in a multi-dimensional manner. This effectively overcomes the limitations of multiple solutions caused by single evaluation methods and significantly improves the reliability and scientific rigor of shale oil accumulation period determination. Simultaneously, by utilizing the statistical analysis of inclusion fluorescence area at the microscale to construct a quantitative abundance index, a direct and standardized representation of the intensity of shale oil fluid activity is achieved, greatly enhancing the stability and repeatability of enrichment zone identification. Furthermore, this method can simultaneously output panoramic evaluation results covering the "time-plane-space" dimensions, providing direct scientific basis for the precise selection of shale oil sweet spots. Its standardized modular process not only demonstrates strong cross-basin applicability and scalability but also facilitates deep integration with microscopic imaging, isotope dating, and basin simulation systems, laying a solid foundation for the digital evaluation and engineering implementation of shale oil.

[0038] In some embodiments, the method for determining the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information may further include the following: S1: Convert the fluorescence information into corresponding chromaticity parameters; wherein, the fluorescence information includes fluorescence images and fluorescence spectral data; S2: Using a preset fitting model, determine the equivalent maturity parameters of fluid inclusions in the host mineral based on the chromaticity parameters; S3: Use a preset image processing algorithm to identify the pulse region of the fluorescence image to obtain the corresponding fluorescence area; S4: Determine the abundance parameters of fluid inclusions in the host mineral based on the ratio between the fluorescence area and the area of ​​the vein region in the host mineral.

[0039] Specifically, after acquiring the fluorescence image and fluorescence spectral data of the target fluid inclusion, a digital conversion is first performed. This process involves integrating the energy distribution of the original spectral curve in the visible light band and mapping it to a standard color space coordinate system. Specifically, a set of chromaticity coordinate values ​​reflecting color characteristics are calculated based on the intensity of the spectrum at different wavelengths. Simultaneously, the spectral data is corrected by combining pixel brightness information from the fluorescence image to ensure that the extracted chromaticity parameters can eliminate visual errors caused by fluctuations in the experimental equipment's light source or losses in the microscope's optical path, thereby accurately reproducing the luminescent nature of hydrocarbon substances under ultraviolet light excitation.

[0040] After obtaining the chromaticity parameters, they are input into a pre-defined fitting model. This model is pre-constructed based on a large amount of calibrated sample data with known thermal evolution levels in the region. Its core mechanism lies in capturing the color shift phenomenon of hydrocarbon molecules as maturity increases. As the degree of heating of oil and gas deepens, its fluorescence characteristics show a trend of shifting from short wavelengths to long wavelengths. Through the calculation of this fitting model, abstract chromaticity values ​​can be automatically converted into equivalent maturity parameters reflecting oil and gas quality. This process eliminates the subjectivity of traditional manual color judgment and realizes a scientific conversion from optical characteristics to the degree of geological thermal evolution.

[0041] To accurately extract abundance, this embodiment employs a pre-defined image processing algorithm for deep analysis of the fluorescence image. First, the algorithm removes background data based on brightness and color differences in the image. Then, using edge detection and region growing techniques, it automatically identifies and outlines the geometric contours of the host mineral vein. After determining the vein as the specific study area, the algorithm further scans the luminescent pixels within that area, precisely segmenting all fluorescent spots representing fluid inclusions. By counting the total number of pixels occupied by these fluorescent spots, the fluorescent area representing the hydrocarbon content is determined. This computer vision-based recognition method effectively distinguishes the vein from the surrounding shale matrix, ensuring the accuracy of the statistical range.

[0042] Finally, the abundance parameter of fluid inclusions was determined based on the ratio between the obtained fluorescence area and the total area of ​​the host mineral vein region. This parameter essentially reflects the degree of filling of oil and gas fluids into mineral fractures during a specific geological period of vein formation. A higher ratio indicates stronger oil and gas injection dynamics in the shale formation at that time, and a greater oil saturation potential of the reservoir. By comparing the abundance parameters of vein samples from different periods, it is possible to intuitively identify which period of hydrocarbon accumulation was the most intense. This quantitative abundance assessment provides the most direct physical dimensional support for subsequent screening of core areas of shale oil-rich regions.

[0043] In some embodiments, converting the fluorescence information into corresponding chromaticity parameters may specifically include: In-situ observation of hydrocarbon fluid inclusions in the host mineral was performed using fluorescence microscopy, and fluorescence images and fluorescence spectral data of the inclusions were acquired simultaneously. After background noise reduction and normalization correction of the fluorescence images and fluorescence spectral data, the corresponding standard chromaticity parameters, such as CIE1931 chromaticity parameters, were obtained through color space mapping conversion.

[0044] Among them, the preferred chromaticity parameters include CIE-x and CIE-y.

[0045] In some embodiments, the RGB values ​​of the fluorescence image can be linearized and color space transformed to obtain tristimulus values ​​X, Y, and Z, which are then calculated according to the following formula:

[0046] in, Refers to the raw pixel values ​​extracted from the fluorescence image. Refers to the normalized standard red, green, and blue components. Refers to the normalized components of the input. Refers to the linearized color components. Refers to the CIEXYZ tristimulus value. Refers to the CIE 1931 standard chromaticity coordinates.

[0047] Preferably, fluorescence image acquisition can be performed using a fluorescence microscope or a confocal laser scanning microscope; multiple fields of view can be acquired for the same sample to reduce the deviation introduced by field of view differences.

[0048] In some embodiments, an equivalent maturity parameter of the fluid inclusion is calculated to characterize the thermal maturity level of the hydrocarbon fluid represented by the inclusion. The equivalent maturity parameter is calculated according to the following formula:

[0049] Where x and y are the CIE-x and CIE-y parameters of the fluid inclusions, respectively. The calculation formulas vary by region and stratigraphic level, and can be obtained using least squares fitting, polynomial fitting, or exponential fitting. Preferably, EqHIRo can be calculated for multiple inclusions in the host mineral of the same sample and the same period, and the mean, median, or weighted statistical value can be used as the maturity characterization result for that period.

[0050] In some embodiments, image processing and region statistics are performed on the fluorescence image to obtain the fluorescence area of ​​hydrocarbon fluid inclusions, and inclusion abundance parameters are constructed to characterize the relative changes in the intensity or enrichment of oil and gas activity.

[0051] In a preferred embodiment, the inclusion abundance parameter is defined as the ratio of the fluorescence area of ​​the fluid inclusion to the area of ​​the host mineral vein in the delineated region.

[0052] Preferably, fluorescence area statistics may include one or more of the following processing steps: a. pulse region identification and boundary delineation; b. fluorescence region threshold segmentation; c. morphological denoising and connected component identification; d. summarizing and statistically analyzing results from multiple fields of view.

[0053] More preferably, multiple fields of view can be selected within the same host mineral period for repeated statistical analysis of the same sample to obtain stable abundance characterization results.

[0054] In some embodiments, the method for determining the abundance parameter of fluid inclusions in the host mineral based on the ratio between the fluorescence area and the area of ​​the vein region in the host mineral may further include the following: The abundance parameters of fluid inclusions in the host mineral are determined according to the following formula:

[0055] in, For the abundance parameter, The fluorescence area is... The area of ​​the pulse region is denoted as .

[0056] In some embodiments, the method for determining the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data may further include the following: S1: Determine the initial hydrocarbon accumulation time of the target area in the time series corresponding to the stratigraphic evolution data based on the equivalent maturity parameter; S2: Based on the time constraint parameters and the formation temperature parameters, determine the hydrocarbon accumulation event time window and formation temperature boundary conditions in the time series, and correct the preliminary hydrocarbon accumulation time based on the hydrocarbon accumulation event time window and the formation temperature boundary conditions to determine the effective hydrocarbon accumulation time window; S3: Determine the intensity weight of hydrocarbon accumulation activity at different time nodes within the effective hydrocarbon accumulation time window based on the abundance parameter; S4: Based on the intensity weight of the hydrocarbon accumulation activity, the effective hydrocarbon accumulation time window is inverted and calculated using a preset numerical optimization inversion algorithm to determine the shale oil accumulation period information of the target area.

[0057] Specifically, after obtaining the equivalent maturity parameters of the shale strata in the target area, the burial history and thermal history simulation results from the stratigraphic evolution data are first retrieved. By constructing maturity curves of the target strata as they evolve over geological time, the measured equivalent maturity values ​​of fluid inclusions are mapped onto the time axis. Since the thermal evolution of hydrocarbons is a cumulative process controlled by both temperature and time, this mapping relationship can be used to initially pinpoint the geological history interval corresponding to the fluid reaching its current evolution level, thereby obtaining the preliminary time range for shale oil charging in the target area.

[0058] To further improve identification accuracy, this embodiment introduces dual constraints of absolute time and thermodynamic temperature. First, the U-Pb age of the host mineral (a time constraint parameter) is used as a hard time boundary, requiring the preliminary hydrocarbon accumulation time to fall within the time error range of mineral crystallization. Subsequently, the formation temperature parameters calculated using cluster isotopes are used to search for matching paleotemperature intervals in the stratigraphic evolution data. By overlaying the preliminary time interval, radiometric dating interval, and paleotemperature window, and eliminating interfering periods that do not conform to physical logic, a highly confident and effective hydrocarbon accumulation time window is finally determined.

[0059] Within the effective hydrocarbon accumulation window, this embodiment utilizes fluorescence abundance parameters for intensity characterization to identify the main charging period. Based on the physical mechanism that "the more intense the charging, the higher the frequency and abundance of inclusion capture," the abundance parameters in veins of different phases are converted into weighted distribution coefficients on the time axis. Locations with higher abundance are assigned higher weights, representing stronger hydrodynamics and larger-scale charging activity at that time point. Through this intensity-weighted processing, the static hydrocarbon accumulation window is transformed into a dynamic hydrocarbon accumulation probability distribution, providing a quantitative basis for accurately identifying peak hydrocarbon generation and expulsion.

[0060] Finally, a pre-defined numerical optimization inversion algorithm (such as Bayesian evolutionary algorithm or genetic optimization algorithm) is used to globally and collaboratively solve multiple parameters within the effective hydrocarbon accumulation time window. This algorithm uses minimizing the residuals between measured maturity, temperature, and age data and simulated values ​​as the objective function, and performs tens of thousands of iterative calculations combined with hydrocarbon accumulation activity intensity weights. The final output is complete information on the shale oil accumulation period in the target area, including the start time of accumulation, the peak charging time, and the end time of accumulation. This inversion result not only provides absolute time points but also the probability density distribution of hydrocarbon accumulation evolution, greatly reducing human bias in exploration evaluation.

[0061] By introducing absolute age and isotopic temperature, the potential for multiple solutions that may arise from relying solely on thermal simulation is effectively corrected. At the same time, by constructing intensity weights using abundance parameters and performing numerical inversion, a technological leap from "qualitative time inference" to "quantitative process reconstruction" is achieved, significantly improving the scientific rigor of hydrocarbon accumulation period identification and the prediction accuracy of well location deployment.

[0062] In some embodiments, the method for determining the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data may further include the following: Using the time constraint parameters and the formation temperature parameters, a theoretical evolution period that conforms to the physical background of host mineral growth is determined in the formation evolution data; The equivalent maturity parameter is fitted to the theoretical maturity sequence within the theoretical evolution period. Based on the principle of minimizing the fitting residual, multiple candidate charging times are determined within the theoretical evolution period. The abundance parameters are mapped to the multiple candidate charging times and used as weighting factors for charging contributions at different times to calculate the probability distribution of hydrocarbon accumulation intensity. Based on the peak characteristics of the probability distribution of the reservoir formation intensity, the information on the shale oil reservoir formation period is determined.

[0063] In some embodiments, determining the shale oil accumulation period information based on the peak characteristics of the accumulation intensity probability distribution may specifically include: Identify the primary and secondary peaks in the probability distribution of the reservoir accumulation intensity, and extract the geological time center values ​​corresponding to the primary and secondary peaks as the secondary time of the primary and secondary charging periods of the shale oil reservoir accumulation. Calculate the half-peak width of the main peak and the secondary peak, and determine the start and end times and duration of the corresponding hydrocarbon accumulation stage based on the half-peak width; The coverage areas of the main peak and the secondary peaks are integrated to determine the relative contribution ratio of each hydrocarbon accumulation stage to the total hydrocarbon accumulation scale. The shale oil accumulation period information includes a dynamic accumulation evolution profile constructed from the start and end times, duration, and relative contribution ratio.

[0064] In some embodiments, the method for determining the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter may further include the following: S1: Based on the information on the shale oil accumulation period, determine the effective accumulation time window for shale oil in the target area; S2: Using the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, determine potential enrichment areas that meet preset conditions; wherein, the preset conditions include at least two of the following conditions: the equivalent maturity parameter is greater than a set threshold, the abundance parameter is higher than the regional average, and the fluorescence color of the fluid inclusions is blue or bluish-white; S3: Couple the effective reservoir formation time window and the potential enrichment area in time and space to determine the shale oil enrichment area identification result in the target area.

[0065] The abundance parameters mentioned above are used to construct the hydrocarbon accumulation intensity weights.

[0066] Specifically, firstly, based on the shale oil accumulation period information obtained from the aforementioned multi-parameter joint inversion, the absolute age range with the highest shale oil charging probability within the target area is extracted and determined as the effective accumulation time window. In practice, this time window usually corresponds to the optimal matching period when the source rock experiences large-scale hydrocarbon generation and expulsion and reservoir fractures are well-developed. The significance of this step is that it establishes a "geological time scale," within which all subsequent microscopic parameter characteristics must be validated for effectiveness, thereby eliminating invalid sporadic charging interference from geological history.

[0067] By utilizing the spatial distribution trends of equivalent maturity and abundance parameters, combined with the optical characteristics of inclusions, potential enrichment areas are delineated within the target region. Specifically, a preset identification threshold is established: the equivalent maturity parameter EqHIRo must be within the main hydrocarbon generation window (e.g., >0.8%), and the fluorescence area ratio of inclusions in the vein must be significantly higher than the average level of the entire region (e.g., more than 20%). In particular, fluorescence color characteristics are introduced as a quality correction factor: if fluid inclusions exhibit blue or bluish-white fluorescence under ultraviolet light, it indicates the presence of a high proportion of light hydrocarbon components, suggesting better fluidity and exploitation potential. Through the intersection calculation of at least two of the above conditions, a spatially defined "high-value oil-bearing area" is initially identified.

[0068] Finally, a spatiotemporal coupling logic operation was performed between the determined effective hydrocarbon accumulation time window and the potential enrichment areas in space. Vein samples within each potential enrichment area were verified: only when the recorded capture time (determined based on the host mineral U-Pb age) of a high-abundance, high-maturity inclusion within that area precisely falls within the effective hydrocarbon accumulation time window was it classified as a definitive enrichment area (Level 1 sweet spot). If the spatial parameters met the criteria but the temporal alignment did not match (e.g., belonging to early inefficient charging or remnants after late-stage destruction), it was downgraded to a Level 2 or 3 evaluation area. This coupling mechanism ensures that the identification results not only reflect "currently abundant oil" but also prove that "these oils were injected during the main charging period and have been effectively preserved to this day," thus leading to the identification conclusion.

[0069] By aligning microscopic test parameters with macroscopic evolution data in a spatiotemporal manner, a technological evolution from "static point-like evaluation" to "four-dimensional dynamic inversion" has been achieved. This not only accurately delineates the spatial distribution of shale oil, but also effectively filters out invalid oil and gas shows through strong constraints on reservoir formation time, providing a scientific basis for precise exploration of deep shale oil.

[0070] In some embodiments, the step of spatiotemporally coupling the effective reservoir formation time window and the potential enrichment zone to determine the shale oil enrichment zone identification result within the target area may specifically include: First, the process is executed in a Geographic Information System (GIS) or 3D geological modeling platform. By spatially meshing the target area, the shale formations to be evaluated are divided into several discrete computational units with geographic coordinate attributes (X, Y, Z). Then, attribute assignment operations are performed, mapping the equivalent maturity parameter EqHIRo, abundance parameters, and fluorescence color information of fluid inclusions obtained in the previous steps to the corresponding computational units. This constructs a spatial database containing both the quality and quantity attributes of hydrocarbons, laying the foundation for subsequent multidimensional logical operations.

[0071] A pre-defined logical judgment algorithm is used to initially screen each computational unit. This algorithm focuses on resource quality and oil-bearing scale, with screening criteria including: the equivalent maturity parameter being greater than a set threshold, the abundance parameter being higher than the regional average, and the fluorescence color of the fluid inclusions being blue or bluish-white. When a computational unit simultaneously meets at least two of the above conditions, it is automatically marked and delineated as a potential enrichment candidate area. This step, from the perspective of static spatial distribution, excludes oil-poor areas with extremely poor oil-bearing indications, and initially identifies geographical areas with exploration potential.

[0072] Based on the delineation of spatial candidate regions, the effective hydrocarbon accumulation time window obtained through the aforementioned numerical optimization inversion algorithm is retrieved and defined as the "time threshold" for determining resource validity. The specific "coupling" action involves: automatically extracting the absolute U-Pb capture age of the host minerals corresponding to fluid inclusions within potential enrichment candidate regions, and comparing this physical age with the time threshold using spatiotemporal alignment logic. By executing a preset "spatiotemporal conformity function," the dynamic filling attributes of each grid cell are validated to ensure that high spatial values ​​have genuine dynamic support in the temporal dimension.

[0073] Finally, the shale oil enrichment zone identification results are output based on the spatiotemporal coupling verification results. Only when all static parameters within the computational unit meet the standards, and the capture time of its recorded high-intensity charging events (i.e., high-abundance inclusions) falls precisely within the effective reservoir accumulation time window, is the grid unit ultimately identified as a shale oil enrichment zone (sweet spot). If a computational unit meets the spatial static indicators, but its inclusion capture time falls outside the main window (e.g., belonging to early inefficient charging or residual display due to later tectonic destruction), it is marked as "invalid display" or "inefficient zone" and removed from the final results. This embodiment achieves precise positioning from "static planar distribution" to "dynamic spatiotemporal identification," significantly improving the identification accuracy of "true sweet spots" in complex shale formations.

[0074] By introducing mandatory constraints based on the time dimension, the identification accuracy of "true sweet spots" in complex shale formations is significantly improved, realizing a technological evolution from static planar distribution description to dynamic spatiotemporal four-dimensional identification. This method can effectively identify and eliminate "false high-value" signals caused by early inefficient charging or later tectonic damage, fundamentally solving the common problem in shale oil exploration of "strong oil and gas shows without industrial production." Ultimately, this precise spatiotemporal location identification provides high-confidence decision support for the selection of optimal well locations and exploration deployment, greatly reducing the evaluation risks and drilling costs of unconventional oil and gas development.

[0075] In some embodiments, the step of spatiotemporally coupling the effective reservoir formation time window and the potential enrichment zone to determine the shale oil enrichment zone identification result within the target area may further include: Obtain the capture age parameters of fluid inclusions of different phases within the potential enrichment region; The capture age parameter is compared with the effective hydrocarbon accumulation time window to determine the validity of each hydrocarbon accumulation event within the potential enrichment area; The contribution ratio of effective hydrocarbon accumulation events falling within the effective hydrocarbon accumulation time window to the abundance parameter is statistically analyzed, and the spatiotemporal matching coefficient is calculated. Based on the spatiotemporal matching coefficient, the potential enrichment area is classified to determine the shale oil enrichment area identification result.

[0076] Specifically, for potential enrichment areas, U-Pb radioisotope dating is first used to obtain the capture age parameters of fluid inclusions from different periods in the host minerals. These ages are then aligned with the effective hydrocarbon accumulation time windows obtained through inversion to determine whether a specific charging event falls within the main hydrocarbon generation and expulsion period, thereby confirming the validity of the hydrocarbon accumulation event. Next, by statistically analyzing the contribution weight of fluid inclusion abundance to the total abundance parameter within the effective hydrocarbon accumulation time window, a spatiotemporal matching coefficient is calculated. This coefficient serves as a quantitative indicator of the temporal consistency between hydrocarbon accumulation dynamics and reservoir space. Finally, based on this coefficient, potential enrichment areas are classified into potential levels, with high-matching areas identified as the final shale oil enrichment areas. This effectively eliminates "pseudo-high values" interference caused by non-main period charging in geological history, ensuring the industrial applicability of the identification results.

[0077] In some embodiments, the method for determining the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter may further include the following: In the specific implementation process of determining the shale oil enrichment area identification results, firstly, based on the spatial distribution characteristics of equivalent maturity parameters exceeding a set threshold, abundance parameters exceeding the regional average, and fluid inclusion fluorescence colors being blue or bluish-white, several potential enrichment candidate areas meeting the physical index criteria are initially selected on the target area planar layer. Subsequently, the effective reservoir formation time window obtained by inverting the shale oil reservoir formation period information is used as the core time dimension screening criterion. By comparing the measured absolute capture age of fluid inclusions in each candidate area one by one, a "spatiotemporal alignment" filtering operation is performed: only candidate areas whose inclusion capture age accurately falls within the effective reservoir formation time window are retained as the final shale oil enrichment area identification results. For candidate areas that show high abundance in space but whose capture time is outside the effective reservoir formation time window, their hydrocarbon shows are determined to be invalid shows of late-stage destruction residues or non-primary-stage charging and are removed. Thus, through the logical threshold of the time dimension, a secondary selection of static spatial potential areas is achieved, ensuring the accuracy of the identification results in the sense of reservoir dynamic evolution.

[0078] The core of this mechanism lies in using the determinism of the "time axis" to eliminate the ambiguity of the "spatial axis," using information on the shale oil reservoir formation period as the core logical filter for judging resource effectiveness. By establishing a dynamic coupling relationship between the reservoir formation time window and the spatial potential area, it requires that the fluid properties (such as equivalent maturity and fluorescence characteristics) in the potential enrichment area must be precisely aligned with the evolutionary stage of the main hydrocarbon generation and expulsion period. Thus, the time dimension is used as a "logical threshold" to effectively filter out the interference of "pseudo-high values" caused by early inefficient charging or later tectonic destruction in geological history. This ensures that the finally identified enrichment area not only has high-parameter physical characteristics in the present day, but also that its resource composition has a high degree of scale determinism and industrial value in the reservoir formation evolution logic.

[0079] In some embodiments, the method of performing petrographic and diagenetic sequence processing on the vein samples to determine the host minerals corresponding to fluid inclusions at different hydrocarbon accumulation stages may further include the following: S1: Perform petrographic observation on the vein sample to obtain diagenetic evidence characteristics of the vein sample; wherein, the diagenetic evidence characteristics include at least one of mineral contact relationship, crystal growth characteristics, cathodoluminescence characteristics, and inclusion occurrence characteristics; S2: Based on the diagenetic evidence characteristics, determine the chronological order of formation of vein minerals from different phases in the vein sample to obtain diagenetic sequence parameters; S3: Based on the diagenetic sequence parameters and the occurrence characteristics of the fluid inclusions, the host minerals corresponding to the fluid inclusions in different hydrocarbon accumulation stages are determined through spatiotemporal matching analysis.

[0080] Specifically, a detailed petrographic observation was first conducted on the prepared vein samples, using double-sided polished thin sections. Polarizing microscopy was used to capture the crystal growth characteristics and contact relationships of the minerals, such as observing the cutting or interpenetrating relationships between calcite and quartz veins to identify the physical pathways of fluid activity. Simultaneously, cathodoluminescence (CL) technology was introduced to extract the luminescence characteristics of the minerals. Key diagenetic evidence was obtained by examining the differences in luminescence color (e.g., the difference between orange-red and dark red light) and zoning structure among minerals from different periods. Furthermore, the occurrence characteristics of inclusions were carefully described to distinguish between primary inclusions hosted within the mineral growth zone and secondary inclusions distributed along later microfractures, providing first-hand image data for subsequent periodization.

[0081] Subsequently, based on the acquired diagenetic evidence characteristics, the geological cross-cutting law and metasomatic filling theory were applied to determine the chronological order of mineral formation in different phases within the vein samples. In practice, the crystallization stages of the minerals were numbered or sequentially processed to obtain quantitative diagenetic sequence parameters. For example, the first phase was identified as massive calcite filling during the opening of early faults, while the second phase consisted of fine-grained quartz formed by later hydrothermal superposition. Determining this parameter effectively establishes a relative temporal coordinate system for the fluid activity in the target area, ensuring that subsequent dating data can be accurately correlated with specific geological events.

[0082] Finally, based on the obtained diagenetic sequence parameters and inclusion occurrence characteristics, a rigorous spatiotemporal matching analysis was performed. By verifying the mineral phase in which the fluid inclusions are located and their distribution within the crystals, the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages were identified. For example, if oil-bearing inclusions are only found in the quartz zoning of the second stage, while only brine inclusions are found in the calcite of the first stage, then the host mineral corresponding to the hydrocarbon charging in that stage is determined to be late-stage quartz. This step eliminates the interference of mixed fluid information from different stages, achieving precise alignment between "fluid information" and "mineral carrier," providing a unique material basis for subsequently determining the shale oil accumulation period.

[0083] In some embodiments, thin interlayer vein samples such as calcite veins, barite veins, or shell limestone developed in fractures, bedding, or microfractures are selected from shale formations, and fluid inclusion thin sections, ordinary thin sections, and U-Pb dating target samples are prepared. By performing petrographic observation and diagenetic sequence analysis on the samples, the formation sequence of vein minerals in different stages is identified, and the host minerals corresponding to fluid inclusions in different stages are determined accordingly.

[0084] Preferably, the diagenetic sequence analysis is based on one or more of the following evidence: a) the cutting, filling and replacement relationships of minerals; b) the crystal growth zoning and the degree of euhedrality of minerals; c) the differences in cathodoluminescence characteristics and their spatial distribution; d) the occurrence of inclusions (primary, early secondary, late secondary) and their combination characteristics.

[0085] In some embodiments, the method involves performing in-situ testing and isotope testing on the host mineral to obtain the time constraint parameters and formation temperature parameters of the host mineral. In specific implementations, the method may further include the following: S1: The U-Pb age of the host mineral is determined by laser ablation inductively coupled plasma mass spectrometry, and the U-Pb age is used as the time constraint parameter. S2: Determine the cluster isotope characterization parameters of the host mineral by performing cluster isotope analysis on the host mineral; S3: By performing temperature conversion on the cluster isotope characterization parameters, the formation temperature during the formation period of the host mineral is determined, and the formation temperature is used as the formation temperature parameter.

[0086] Specifically, after identifying the host mineral (such as a calcite vein or quartz vein) corresponding to the target inclusion, high-precision in-situ dating is performed using laser ablation inductively coupled plasma mass spectrometry (LA-ICP-MS). In practice, the prepared dating target sample is first placed in the ablation chamber. Based on the growth zoning locations determined by petrographic observations, a clean area avoiding obvious fractures and impurities is selected as the test point. A high-energy laser pulse ablates the mineral surface, and the resulting aerosol is transported by a carrier gas to the mass spectrometer for isotope ratio determination. During the test, standard materials are introduced for real-time calibration to ensure the accuracy of key isotope ratios such as 206Pb / 238U and 207Pb / 206Pb. Finally, using the obtained isotope ratio data, the absolute formation age of the host mineral is determined through isochron fitting or congruence curve calculation, and this value is used as the time constraint parameter for subsequent time axis constraints. This process enabled precise calibration of the formation time of the fluid capture "container," providing a solid chronological basis for reconstructing the history of Tibet.

[0087] While acquiring age data, trace samples were taken from the host minerals and cluster isotope analysis was performed. The core of this test lies in determining the degree of "aggregation" of heavy isotopes (such as 13C and 18O) in the mineral lattice, the physical nature of which depends solely on the environmental temperature during mineral growth. In the laboratory, carbonate minerals were converted into carbon dioxide gas using a phosphoric acid reaction method, and the abundance of carbon dioxide molecules with a molecular weight of 47 was precisely measured using a high-resolution stable isotope ratio mass spectrometer, thereby calculating the cluster isotope characterization parameter (Δ47 parameter). Subsequently, the Δ47 parameter was converted into the absolute formation temperature of the host mineral formation period using a pre-defined temperature conversion equation (usually an empirical formula calibrated in a standard laboratory). This temperature, as a formation temperature parameter, not only reflects the geothermal background during fluid injection but also, together with the age parameter, constitutes a dual physical constraint of "temperature-time," thus greatly enhancing the uniqueness and scientific validity of subsequent hydrocarbon accumulation and evolution inversion results.

[0088] In some embodiments, the statistical analysis of the fluorescence area of ​​the fluid inclusions includes threshold segmentation, morphological denoising, and connected component identification of the fluorescence image; the threshold of the equivalent maturity index is any value between 0.5 and 1.6; the host minerals also include quartz, dolomite, or other transparent authigenic minerals; applicable to marine or continental shale oil systems; the enrichment zone identification results are output in the form of a two-dimensional planar map or a three-dimensional geological model annotation; the veins are located within shale strata or thin interlayers; the diagenetic sequence processing is based on mineral cutting relationships, growth zoning characteristics, scanning electron microscopy energy dispersive spectroscopy elemental anomalies, scanning electron microscopy Quemsccan elemental anomalies, or cathodoluminescence characteristics.

[0089] As can be seen from the above, the method for determining the identification result of shale oil enrichment areas provided in the embodiments of this specification involves: acquiring vein samples and stratigraphic evolution data of shale strata in the target area; performing petrographic and diagenetic sequence processing on the vein samples to determine the host minerals corresponding to fluid inclusions at different accumulation stages; acquiring fluorescence information of fluid inclusions in the host minerals; determining the equivalent maturity parameter and abundance parameter of fluid inclusions in the host minerals based on the fluorescence information; performing in-situ and isotopic tests on the host minerals to obtain the time constraint parameter and formation temperature parameter of the host minerals; determining the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the stratigraphic evolution data; and determining the identification result of shale oil enrichment areas in the target area based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter. In this way, by identifying the host minerals corresponding to fluid inclusions at different hydrocarbon accumulation stages and obtaining equivalent maturity parameters, abundance parameters, time constraint parameters, and formation temperature parameters, multi-parameter joint inversion of various quantitative parameters with formation evolution data is achieved, overcoming the problem of existing technologies that focus on qualitative analysis and lack quantitative coupling. By accurately determining the information on shale oil accumulation stages and combining the spatial distribution characteristics of equivalent maturity parameters and abundance parameters, the accuracy of shale oil enrichment zone identification results can be significantly improved, and the ambiguity of identification results can be effectively reduced.

[0090] See Figure 2 As shown in the embodiments of this specification, a specific electronic device is also provided, wherein the electronic device includes a network communication port 201, a processor 202 and a memory 203, and the above structures are connected by internal cables so that the various structures can perform specific data interaction.

[0091] Specifically, the network communication port 201 can be used to acquire vein samples and stratigraphic evolution data of the shale strata in the target area.

[0092] The processor 202 can specifically be used to perform petrographic and diagenetic sequence processing on the vein sample to determine the host minerals corresponding to fluid inclusions at different hydrocarbon accumulation stages; acquire fluorescence information of fluid inclusions in the host minerals; and determine the equivalent maturity parameters and abundance parameters of fluid inclusions in the host minerals based on the fluorescence information; perform in-situ and isotopic tests on the host minerals to obtain the time constraint parameters and formation temperature parameters of the host minerals; determine the shale oil accumulation period information of the target area based on the equivalent maturity parameters, the abundance parameters, the time constraint parameters, the formation temperature parameters, and the formation evolution data; and determine the shale oil enrichment zone identification results within the target area based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity parameters and the abundance parameters.

[0093] The memory 203 can be used to store the corresponding instruction program.

[0094] Based on the above method, the relevant structural performance of electronic equipment can be effectively utilized to improve the data processing speed of electronic equipment and efficiently realize a method for determining the identification results of shale oil enrichment areas.

[0095] In this embodiment, the network communication port 201 can be a virtual port bound to different communication protocols, thereby enabling the sending or receiving of different data. For example, the network communication port can be a port responsible for web data communication, a port responsible for FTP data communication, or a port responsible for email data communication. Furthermore, the network communication port can also be a physical communication interface or communication chip. For example, it can be a wireless mobile network communication chip, such as GSM or CDMA; it can also be a Wi-Fi chip; or it can be a Bluetooth chip.

[0096] In this embodiment, the processor 202 can be implemented in any suitable manner. For example, the processor can take the form of a microprocessor or processor and a computer-readable medium storing computer-readable program code (e.g., software or firmware) executable by the (micro)processor, logic gates, switches, application-specific integrated circuits (ASICs), programmable logic controllers, and embedded microcontrollers, etc. This specification is not limiting.

[0097] In this embodiment, the memory 203 may include a hierarchy. In a digital system, anything that can store binary data can be a memory. In an integrated circuit, a circuit with storage function but no physical form is also called a memory, such as RAM, FIFO, etc. In a system, a storage device with a physical form is also called a memory, such as a memory stick, TF card, etc.

[0098] This specification also provides a computer-readable storage medium based on the above-described method for determining shale oil enrichment areas. The method involves acquiring vein samples and stratigraphic evolution data of shale formations in a target area; performing petrographic and diagenetic sequence processing on the vein samples to determine the host minerals corresponding to fluid inclusions at different accumulation stages; acquiring fluorescence information of fluid inclusions in the host minerals; determining the equivalent maturity and abundance parameters of fluid inclusions in the host minerals based on the fluorescence information; performing in-situ and isotopic testing on the host minerals to obtain time constraint parameters and formation temperature parameters; determining the shale oil accumulation period information of the target area based on the equivalent maturity parameters, abundance parameters, time constraint parameters, formation temperature parameters, and stratigraphic evolution data; and determining the shale oil enrichment area identification result within the target area based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity and abundance parameters.

[0099] In this embodiment, the storage medium includes, but is not limited to, Random Access Memory (RAM), Read-Only Memory (ROM), Cache, Hard Disk Drive (HDD), or Memory Card. The memory can be used to store computer program instructions. The network communication unit can be an interface configured according to standards specified in the communication protocol for network connection communication.

[0100] In this embodiment, the specific functions and effects implemented by the program instructions stored in the computer-readable storage medium can be explained in comparison with other embodiments, and will not be repeated here.

[0101] See Figure 3 At the software level, this specification also provides a device for determining the identification results of shale oil enrichment areas, which may specifically include the following structural modules: The data acquisition module 301 is used to acquire vein samples and stratigraphic evolution data of the shale strata in the target area; Host mineral determination module 302 is used to perform petrographic and diagenetic sequence processing on the vein sample to determine the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages. The first parameter determination module 303 is used to acquire fluorescence information of fluid inclusions in the host mineral; and to determine the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information. The second parameter determination module 304 is used to perform in-situ testing and isotope testing on the host mineral to obtain the time constraint parameter and formation temperature parameter of the host mineral, respectively. The reservoir formation period determination module 305 is used to perform multi-parameter joint inversion on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data to determine the shale oil reservoir formation period information of the target area; The result determination module 306 is used to determine the shale oil enrichment zone identification result in the target area based on the shale oil accumulation period information, as well as the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter.

[0102] In some embodiments, the first parameter determination module 303, in specific implementation, converts the fluorescence information into corresponding chromaticity parameters; wherein, the fluorescence information includes fluorescence images and fluorescence spectral data; using a preset fitting model, it determines the equivalent maturity parameter of fluid inclusions in the host mineral based on the chromaticity parameters; using a preset image processing algorithm to identify vein regions in the fluorescence image to obtain the corresponding fluorescence area; the abundance parameter determination module is used to determine the abundance parameter of fluid inclusions in the host mineral based on the ratio between the fluorescence area and the area of ​​vein regions in the host mineral.

[0103] In some embodiments, the abundance parameter determination module, in specific implementation, determines the abundance parameter of fluid inclusions in the host mineral according to the following formula:

[0104] in, For the abundance parameter, The fluorescence area is... The area of ​​the pulse region is denoted as .

[0105] In some embodiments, the above-mentioned hydrocarbon accumulation period determination module 305, in specific implementation, determines the preliminary hydrocarbon accumulation time of the target area in the time series corresponding to the stratigraphic evolution data based on the equivalent maturity parameter; determines the hydrocarbon accumulation event time window and stratigraphic temperature boundary conditions in the time series based on the time constraint parameter and the stratigraphic temperature parameter, and corrects the preliminary hydrocarbon accumulation time based on the hydrocarbon accumulation event time window and the stratigraphic temperature boundary conditions to determine the effective hydrocarbon accumulation time window; determines the hydrocarbon accumulation activity intensity weight of different time nodes within the effective hydrocarbon accumulation time window based on the abundance parameter; and performs inversion calculation on the effective hydrocarbon accumulation time window based on the hydrocarbon accumulation activity intensity weight using a preset numerical optimization inversion algorithm to determine the shale oil accumulation period information of the target area.

[0106] In some embodiments, the result determination module 306, in specific implementation, determines the effective accumulation time window of shale oil in the target area based on the shale oil accumulation period information; utilizes the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter to determine potential enrichment areas that meet preset conditions; wherein, the preset conditions include at least two of the following conditions: the equivalent maturity parameter is greater than a set threshold, the abundance parameter is higher than the regional average, and the fluorescence color of the fluid inclusions is blue or bluish-white; the effective accumulation time window and the potential enrichment areas are spatiotemporally coupled to determine the shale oil enrichment area identification result in the target area.

[0107] In some embodiments, the host mineral determination module 302, in specific implementation, performs petrographic observation on the vein sample to obtain diagenetic evidence characteristics of the vein sample; wherein, the diagenetic evidence characteristics include at least one of mineral contact relationship, crystal growth characteristics, cathodoluminescence characteristics, and inclusion occurrence characteristics; based on the diagenetic evidence characteristics, the formation sequence relationship of vein minerals of different stages in the vein sample is determined to obtain diagenetic sequence parameters; based on the diagenetic sequence parameters and the inclusion occurrence characteristics, the host minerals corresponding to fluid inclusions of different hydrocarbon accumulation stages are determined through spatiotemporal matching analysis.

[0108] In some embodiments, the second parameter determination module 304, in specific implementation, determines the U-Pb age of the host mineral by performing laser ablation inductively coupled plasma mass spectrometry (ICP-MS) on the host mineral, and uses the U-Pb age as the time constraint parameter; determines the cluster isotope characterization parameters of the host mineral by performing cluster isotope analysis on the host mineral; and determines the formation temperature during the formation period of the host mineral by performing temperature conversion on the cluster isotope characterization parameters, and uses the formation temperature as the formation temperature parameter.

[0109] It should be noted that the units, devices, or modules described in the above embodiments can be implemented by computer chips or physical entities, or by products with certain functions. For ease of description, the above devices are described by dividing them into various modules according to their functions. Of course, in implementing this specification, the functions of each module can be implemented in the same software and / or hardware, or modules that implement the same function can be implemented by a combination of sub-modules or sub-units, etc. The device embodiments described above are merely illustrative. For example, the division of units is only a logical functional division, and there may be other division methods in actual implementation. For example, units or components can be combined or integrated into another system, or some features can be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection between the devices or units shown or discussed can be through some interfaces, and the indirect coupling or communication connection between devices or units can be electrical, mechanical, or other forms.

[0110] As can be seen from the above, based on the shale oil enrichment zone identification result determination device provided in the embodiments of this specification, the following steps are taken: 1) Obtain vein samples and stratigraphic evolution data of shale formations in the target area; 2) Perform petrographic and diagenetic sequence processing on the vein samples to determine the host minerals corresponding to fluid inclusions at different accumulation stages; 3) Obtain fluorescence information of fluid inclusions in the host minerals; 4) Determine the equivalent maturity parameter and abundance parameter of fluid inclusions in the host minerals based on the fluorescence information; 5) Perform in-situ and isotopic tests on the host minerals to obtain the time constraint parameter and formation temperature parameter of the host minerals; 6) Determine the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the stratigraphic evolution data; 7) Determine the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter.

[0111] In a specific scenario example, the method and apparatus for determining shale oil enrichment zone identification results provided in this specification can be applied. This solves the technical problem of high ambiguity and low identification accuracy in shale oil reservoir identification due to the lack of quantitative spatiotemporal coupling between microscopic fluid charging and macroscopic stratigraphic evolution. The specific implementation process may include the following:

[0112] S1: Selection of research subjects and samples.

[0113] The K2qn1 shale oil system of the first member of the Qingshankou Formation in the Qijia-Gulong Depression in the northern part of the central depression of the Songliao Basin was selected as the research object. This area is a typical continental shale oil development zone, and the shale oil exhibits the characteristics of in-source generation, in-source retention, in-source micro-scale migration, and local re-enrichment. Sixteen samples were selected from four wells, X6, X12, X138, and X3. The sample types included calcite veins, barite veins, and limestone containing ostracod shells, covering multiple sublayers of the first member of the Qingshankou Formation. Samples were prepared as 30 μm thin sections, polished thin sections, and U-Pb dating targets. S2: Diagenetic sequence analysis and host mineral determination.

[0114] Petrographic observation and diagenetic sequence analysis of samples were performed using transmitted light, ultraviolet fluorescence, and cathodoluminescence microscopy. Minerals of different formation stages were identified based on mineral cutting relationships, growth zoning, and differences in cathodoluminescence, thus determining the host mineral stages corresponding to fluid inclusions. Host minerals containing primary or early secondary hydrocarbon fluid inclusions were preferred for subsequent analysis.

[0115] S3: Fluorescence observation and chromaticity parameter extraction of fluid inclusions.

[0116] Fluorescence images and spectral data of fluid inclusions were acquired using a fluorescence microscope or a confocal laser scanning microscope. The fluorescence excitation wavelength was 365 nm or 405 nm, the emission band acquisition range was 420-720 nm, and the image resolution was no less than 2048 × 2048 pixels. Three to ten fields of view were repeatedly selected for the same sample for acquisition.

[0117] The RGB values ​​of the fluorescent image pixels are corrected and converted to linear RGB. The tristimulus values ​​X, Y, and Z are obtained through the sRGB→XYZ transformation matrix, and the chromaticity parameters are calculated according to the formula:

[0118] For each encapsulated region, the mean or median of the region's pixels is taken as the representative value for the chromaticity parameter.

[0119] S4: Calculation of equivalent maturity index.

[0120] The equivalent maturity index of fluid inclusions is calculated based on chromaticity parameters using the following formula:

[0121] The EqHIRo values ​​of multiple inclusions within the same secondary host mineral were statistically analyzed, and the mean or median was used as the maturity characterization result for that secondary stage.

[0122] S5: Construction of inclusion abundance index.

[0123] The fluorescence images were processed as follows: Regions with large hydrocarbon inclusion veins were delineated to form Regions of Interest (ROIs). Fluorescent regions within the ROIs were extracted using adaptive thresholding. Morphological opening and closing operations were employed for noise reduction, and the fluorescence area was statistically analyzed using connected component identification. The abundance index of inclusions was defined as:

[0124] S6: In-situ U-Pb dating.

[0125] In-situ U-Pb dating of host minerals containing hydrocarbon inclusions was performed using LA-ICP-MS. The preferred conditions were: laser wavelength 193 nm, spot diameter 60-120 μm, repetition frequency 5-10 Hz, and ablation time 20-30 s. The dating was then corrected using standard samples.

[0126] S7: Δ47 isotopic analysis of host mineral clusters was used to constrain formation temperature and period.

[0127] Furthermore, cluster isotope analysis is performed on the host minerals to constrain the formation temperature corresponding to their formation period. This cluster isotope analysis is based on the pairing distribution characteristics of carbon and oxygen isotopes in the mineral lattice, and the degree of pairing is mainly controlled by the formation temperature. As the formation temperature decreases, the proportion of enriched isotope pairs in the mineral lattice increases. By measuring the deviation of the isotope pairs from their random distribution (Δ47 value) and combining this with the empirical conversion relationship between Δ47 and temperature, the formation temperature corresponding to the formation period of the host minerals can be obtained. This formation temperature is introduced as a thermal evolution constraint parameter into subsequent burial-thermal evolution history and hydrocarbon generation history constraint steps to improve the accuracy of host mineral period division and fluid activity stage determination.

[0128] S8: Multi-parameter joint inversion determines the hydrocarbon accumulation period.

[0129] The equivalent maturity index, inclusion abundance index, U-Pb age, and burial-thermal evolution history of the study area were jointly inverted. The joint inversion adopted the least squares fitting or Bayesian inversion method, using U-Pb age as a time constraint and maturity and abundance as information on hydrocarbon accumulation activity, to obtain the optimal solution or probability distribution of shale oil accumulation period.

[0130] S9: Identification of enriched regions.

[0131] Based on the spatial distribution characteristics of equivalent maturity and inclusion abundance indices, a region is identified as a highly mature light shale oil enrichment area when at least two conditions are met: equivalent maturity is greater than a set threshold, inclusion abundance is higher than the regional average, and fluorescence color is blue or bluish-white. The enrichment area results are output in the form of a two-dimensional planar map or a three-dimensional model.

[0132] Alternative implementation methods: The host mineral can be a transparent mineral such as calcite, barite, shell limestone, dolomite or quartz; the fluorescence imaging equipment can be a fluorescence microscope, confocal microscope or multispectral microscopy system; the maturity model can be an empirical model based on chromaticity parameters, peak wavelength of fluorescence spectrum, Raman value of hydrocarbon inclusions or a combination thereof.

[0133] Generalized Example: In other marine or continental shale oil systems, the same process can be used to extract chromaticity parameters, calculate maturity, statistically analyze abundance, and perform joint inversion to obtain the hydrocarbon accumulation period and identify enrichment areas.

[0134] Explanation of abnormal situations: When there are no identifiable inclusions in the sample, the host mineral cannot be staged, or the inclusions have undergone significant reequilibrium, the sample will not be used as an inversion constraint.

[0135] In some embodiments, see Figure 4 As shown, a systematic identification process for highly mature, light shale oil-rich areas is provided: First, calcite veins, barite veins, carbonate interlayer veins, or transparent mineral veins such as quartz veins developed in fractures, bedding planes, or microfractures are selected from the target shale strata. Hydrocarbon fluid inclusions and their associated brine inclusions are accurately identified using fluorescence microscopy and optical microscopy. Subsequently, the microscopic properties and spectral characteristics of the inclusions are extracted through inclusion homogenization temperature testing, fluorescence and Raman spectroscopy, and fluorescence colorimetry. These are then combined with laser ablation inductively coupled plasma mass spectrometry (LA-ICP-MS) and scanning electron microscopy. Energy dispersive spectroscopy (EDS) and cathodoluminescence (CFL) tests were used to clarify the diagenetic evolution stages of the host minerals. Based on this, U-Pb dating of the host minerals and Δ47 isotope analysis of calcite clusters were used to determine the absolute age of mineral formation and the paleotemperature of the formation. In addition, data on the burial-thermal evolution history and hydrocarbon generation history of the study area, such as well location stratification, erosion amount, TOC, thermal maturity, and source rock type, were introduced to construct a high-precision hydrocarbon accumulation and evolution model. Finally, based on the fluid activity stages and time windows determined by inversion, the abundance parameters of hydrocarbon fluid inclusions and equivalent maturity indices were spatiotemporally coupled to achieve quantitative identification and spatial location prediction of highly mature, light shale oil-rich areas.

[0136] In some embodiments, see Figure 5As shown, by deeply coupling the vertical stratigraphic sequence with microscopic identification indicators, the evolution of shale oil-rich areas in the target region is intuitively displayed at the stratigraphic level. Based on the comprehensive stratigraphic columnar section of the first member (K2qn1) and the second member (K2qn2) of the Qingshankou Formation, the strata are finely divided into sub-layers Q1 to Q9, and the lithological assemblage characteristics of each layer are shown in detail. The star symbols in the figure indicate the depth points of the actual collected vein samples, such as the key evaluation samples selected in sub-layers Q1, Q4, and Q5; while the "IHI-AI-EqHIRo" column on the far right uses the size of the dots to quantitatively characterize the comprehensive evaluation results of the abundance and equivalent maturity of hydrocarbon fluid inclusions in each layer. Vertical comparison clearly shows that the diameter of the dot corresponding to the Q5 sublayer is significantly larger than that of other layers, indicating that this sublayer is in the optimal state in terms of hydrocarbon charging intensity, thermal evolution degree, and hydrocarbon accumulation time matching degree, and is ultimately identified as the core enrichment area (sweet spot layer) of shale oil in this well section. This visualization output of the vertical profile not only verifies the effectiveness of the aforementioned spatiotemporal coupling algorithm, but also provides direct technical support for the accurate selection of subsequent horizontal well traversal layers. Wherein, Formation: strata (usually referring to a "group"); Member: member (usually referring to a "section" or sublayer, such as Q1-Q9); Lithology: lithology; showing the material composition in the stratigraphic sequence (such as shale, sandstone, etc.); Sample: sampling point, marked with a pentagram in the figure; IHI-AI-EqHIRo: the core comprehensive identification index of this invention: IHI: Hydrocarbon Inclusion; AI (Abundance Index): abundance index. Corresponding to the quantitative value calculated by fluorescence area in your embodiment. EqHIRo: Equivalent vitrinite reflectance, which is the thermal maturity of inclusions obtained through fluorescence colorimetric inversion.

[0137] While this specification provides the steps of operation for the methods described in the embodiments or flowcharts, more or fewer steps may be included based on conventional or non-inventive means. The order of steps listed in the embodiments is merely one possible order of execution among many steps and does not represent the only possible order. In actual device or client product execution, the methods shown in the embodiments or drawings may be executed sequentially or in parallel (e.g., in a parallel processor or multi-threaded processing environment, or even a distributed data processing environment). The terms "comprising," "including," or any other variations thereof are intended to cover a non-exclusive inclusion, such that a process, method, product, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, product, or apparatus. Without further limitations, the presence of other identical or equivalent elements in a process, method, product, or apparatus that includes said elements is not excluded. The terms "first," "second," etc., are used to denote names and do not indicate any particular order.

[0138] Those skilled in the art will also know that, besides implementing the controller using purely computer-readable program code, the same functions can be achieved by logically programming the method steps, making the controller function as logic gates, switches, application-specific integrated circuits (ASICs), programmable logic controllers (PLCs), and embedded microcontrollers. Therefore, such a controller can be considered a hardware component, and the devices within it used to implement various functions can also be considered structures within that hardware component. Alternatively, the devices used to implement various functions can be considered as both software modules implementing the method and structures within a hardware component.

[0139] As can be seen from the above description of the embodiments, those skilled in the art can clearly understand that this specification can be implemented by means of software plus necessary general-purpose hardware platforms. Based on this understanding, the technical solutions of this specification can essentially be embodied in the form of a software product. This computer software product can be stored in a storage medium, such as ROM / RAM, magnetic disk, optical disk, etc., and includes several instructions to cause a computer device (which may be a personal computer, mobile terminal, server, or network device, etc.) to execute the methods described in the various embodiments or some parts of the embodiments of this specification.

[0140] Although this specification has been described by way of examples, those skilled in the art will recognize that many variations and modifications are possible without departing from the spirit of this specification, and it is intended that the appended claims cover such variations and modifications without departing from the spirit of this specification.

Claims

1. A method for determining the identification results of shale oil enrichment areas, characterized in that, include: Acquire vein samples and stratigraphic evolution data of the shale strata in the target area; The vein samples were subjected to petrographic and diagenetic sequence processing to determine the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages. Obtain fluorescence information of fluid inclusions in the host mineral; and determine the equivalent maturity parameter and abundance parameter of fluid inclusions in the host mineral based on the fluorescence information; In-situ and isotopic tests were performed on the host mineral to obtain the time constraint parameters and formation temperature parameters of the host mineral. Based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data, the shale oil accumulation period information of the target area is determined; Based on the information on the shale oil accumulation period, and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, the identification results of shale oil enrichment areas within the target region are determined.

2. The method according to claim 1, characterized in that, The step of determining the equivalent maturity and abundance parameters of fluid inclusions in the host mineral based on the fluorescence information includes: The fluorescence information is converted into corresponding chromaticity parameters; wherein, the fluorescence information includes fluorescence images and fluorescence spectral data; Using a preset fitting model, the equivalent maturity parameters of fluid inclusions in the host mineral are determined based on the chromaticity parameters; The fluorescence image is used to identify the pulse region and obtain the corresponding fluorescence area by using a preset image processing algorithm; The abundance parameters of fluid inclusions in the host mineral are determined based on the ratio between the fluorescence area and the area of ​​the vein region in the host mineral.

3. The method according to claim 2, characterized in that, The step of determining the abundance parameter of fluid inclusions in the host mineral based on the ratio between the fluorescence area and the vein region area in the host mineral includes: The abundance parameters of fluid inclusions in the host mineral are determined according to the following formula: in, For the abundance parameter, The fluorescence area is... The area of ​​the pulse region is denoted as .

4. The method according to claim 1, characterized in that, The step of determining the shale oil accumulation period information of the target area based on the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data includes: Based on the equivalent maturity parameter, the initial hydrocarbon accumulation time of the target area in the time series corresponding to the stratigraphic evolution data is determined; Based on the time constraint parameters and the formation temperature parameters, the time window for hydrocarbon accumulation events and the formation temperature boundary conditions in the time series are determined, and the preliminary hydrocarbon accumulation time is corrected based on the time window for hydrocarbon accumulation events and the formation temperature boundary conditions to determine the effective hydrocarbon accumulation time window; Based on the abundance parameter, determine the intensity weight of hydrocarbon accumulation activity at different time nodes within the effective hydrocarbon accumulation time window; Based on the intensity weight of the hydrocarbon accumulation activity, the effective hydrocarbon accumulation time window is inverted and calculated using a preset numerical optimization inversion algorithm to determine the shale oil accumulation period information of the target area.

5. The method according to claim 4, characterized in that, The step of determining the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information, and the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, includes: Based on the information on the shale oil accumulation period, determine the effective accumulation time window for shale oil in the target area; Using the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter, potential enrichment regions that meet preset conditions are identified; wherein, the preset conditions include at least two of the following conditions: the equivalent maturity parameter is greater than a set threshold, the abundance parameter is higher than the regional average, and the fluorescence color of the fluid inclusions is blue or bluish-white; By spatiotemporally coupling the effective reservoir formation time window and the potential enrichment zone, the shale oil enrichment zone identification result within the target area is determined.

6. The method according to claim 1, characterized in that, The petrographic and diagenetic sequence processing of the vein samples to determine the host minerals corresponding to fluid inclusions at different hydrocarbon accumulation stages includes: The vein samples were subjected to petrographic observation to obtain diagenetic evidence characteristics; wherein, the diagenetic evidence characteristics include at least one of mineral contact relationships, crystal growth characteristics, cathodoluminescence characteristics, and inclusion occurrence characteristics; Based on the diagenetic evidence characteristics, the chronological order of formation of vein minerals in different phases of the vein sample is determined to obtain diagenetic sequence parameters; Based on the diagenetic sequence parameters and the occurrence characteristics of the fluid inclusions, the host minerals corresponding to the fluid inclusions in different hydrocarbon accumulation stages are determined through spatiotemporal matching analysis.

7. The method according to claim 1, characterized in that, The process of performing in-situ and isotopic tests on the host mineral to obtain its time-constrained parameters and formation temperature parameters includes: The U-Pb age of the host mineral was determined by laser ablation inductively coupled plasma mass spectrometry, and the U-Pb age was used as the time constraint parameter. Cluster isotope analysis was performed on the host mineral to determine the cluster isotope characterization parameters of the host mineral. By performing temperature conversion on the cluster isotope characterization parameters, the formation temperature during the formation period of the host mineral is determined, and the formation temperature is used as the formation temperature parameter.

8. A device for determining the identification results of shale oil enrichment areas, characterized in that, include: The data acquisition module is used to acquire vein samples and stratigraphic evolution data of the shale strata in the target area; The host mineral determination module is used to perform petrographic and diagenetic sequence processing on the vein sample to determine the host minerals corresponding to fluid inclusions in different hydrocarbon accumulation stages. The first parameter determination module is used to obtain the fluorescence information of fluid inclusions in the host mineral; Based on the fluorescence information, the equivalent maturity parameters and abundance parameters of fluid inclusions in the host mineral are determined; The second parameter determination module is used to perform in-situ testing and isotope testing on the host mineral to obtain the time constraint parameter and formation temperature parameter of the host mineral, respectively. The reservoir formation period determination module is used to perform multi-parameter joint inversion of the equivalent maturity parameter, the abundance parameter, the time constraint parameter, the formation temperature parameter, and the formation evolution data to determine the shale oil reservoir formation period information of the target area; The result determination module is used to determine the shale oil enrichment zone identification result within the target area based on the shale oil accumulation period information, as well as the spatial distribution characteristics of the equivalent maturity parameter and the abundance parameter.

9. An electronic device, characterized in that, It includes a processor and a memory for storing processor-executable instructions, wherein the processor, when executing the instructions, implements the steps of the method according to any one of claims 1 to 7.

10. A computer-readable storage medium, characterized in that, It stores computer instructions that, when executed by a processor, implement the steps of the method according to any one of claims 1 to 7.

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