29 results about "Vitrinite reflectance" patented technology

This invention provides a method, system, and computer equipment for predicting the maturity of shale and mudstone reservoirs through well logging. By analyzing the total porosity and total organic carbon content of shale and mudstone cores from different regions, this invention obtains a mathematical relationship between relative porosity and total organic carbon content. This mathematical relationship reflects the porosity-enhancing efficiency of organic matter and reveals a close relationship between this efficiency and vitrinite reflectivity, which reflects the thermal maturity of organic matter. As maturity increases, the porosity-enhancing efficiency of reservoir organic matter decreases. Therefore, the maturity of shale and mudstone reservoirs can be predicted and evaluated based on the porosity-enhancing efficiency of organic matter. Based on this, this invention establishes a "three-parameter" chart using data on total porosity, total organic carbon content, and vitrinite reflectivity of shale and mudstone from different regions. By processing the data in the area to be tested, the mathematical relationship between relative porosity and total organic carbon content of the shale and mudstone reservoir is obtained. Combined with the "three-parameter" chart, the organic matter maturity can be determined, providing a reference for reservoir evaluation and prediction.

This application provides a method and apparatus for calculating shale oil saturation. A learning dataset is established using measured shale core analysis and geochemical analysis data, well logging data, and well logging interpretation data. This learning dataset is then sent to a machine learning algorithm model to obtain data learning results. Next, vitrinite reflectance and geochemical parameters are obtained from the core analysis and geochemical analysis data. The vitrinite reflectance is used to constrain the geochemical parameters to obtain their maximum values. Based on these maximum values, the data learning results are corrected to obtain the final learning result. Finally, the final learning result is fitted using sensitive parameters to obtain the shale oil saturation, thus solving the problems of high data acquisition costs and large calculation errors in existing shale oil saturation calculation methods.

The invention belongs to the technical field of oil and gas resource exploration, particularly relates to a shale maturity evaluation method and system based on laser Raman spectrum classification, electronic equipment and a computer readable storage medium, and aims to solve the problem that the maturity of shale with complex components is difficult to accurately evaluate by an existing maturity evaluation method. The method comprises the following steps: firstly, identifying microscopic components of algae, inert plastid, vitrinite and solid asphalt in a sample; testing each component by using a laser Raman spectrometer to obtain spectral data, and calculating RBS values (displacement difference between a G peak and a D peak) and a mean value; models (a linear model for inert / vitrinite and an index model for algae / solid asphalt) are selected according to a component evolution mechanism and substituted into an RBS average value to obtain equivalent vitrinite reflectivity of different macerals, and the maturity is evaluated according to the equivalent vitrinite reflectivity. The method solves the problem of continental facies multi-component evaluation deviation, breaks through the bottleneck of no vitrinite of marine facies, is fast in test and low in data dispersion, and provides support for shale oil and gas evaluation.

The application discloses a sample preparation device and method suitable for determining vitrinite reflectivity by an image method, and the device comprises a sample table, the top of the sample table is provided with a sample groove, and the sample groove is used for carrying a sample to be measured; a plurality of standard sample grooves are uniformly arranged in the sample groove; and a plurality of standard sample tubes are inserted into the standard sample grooves, and the standard sample tubes are used for containing standard samples. The sample preparation device suitable for determining vitrinite reflectivity by the image method inserts the standard sample tubes containing the standard samples into the standard sample grooves of the sample groove, uniformly lays the sample to be tested on the sample groove except the area of the standard sample grooves, so that the sample to be tested is uniformly laid around the standard samples, uniform sample preparation of the standard samples and the sample to be tested is realized, the device is convenient to assemble and disassemble, the standard samples can be repeatedly used, the method is simple, and the test efficiency is high.

The invention discloses a method for predicting the peak gas production rate of a deep coal bed gas fractured horizontal well, which comprises the following steps of: 1, data collection and arrangement: collecting actual drilling, well logging, fracturing and production data of the fractured horizontal well in a deep coal bed gas development target area; 2, starting from a known well, combining actual drilling, well logging, fracturing and production data, and comprehensively determining main factors influencing the peak gas production rate of the deep coal bed gas fractured horizontal well; main control factors of the peak yield of the deep coal bed gas fractured horizontal well are fully considered, the influence of the key index vitrinite reflectance on the peak yield is introduced and quantified, the method is suitable for deep coal bed gas fractured horizontal well development practice, key parameters are easy and convenient to obtain, field practicability is high, and the method is suitable for large-scale popularization and application. The method can quickly predict the peak gas production of the to-be-analyzed gas well.

The invention discloses a coal rock longitudinal wave anisotropy coefficient logging determination method, device and equipment, and the method comprises the steps: obtaining the continuous depth vitrinite reflectivity of coal rock based on a logging curve of the coal rock; and determining the continuous depth longitudinal wave anisotropy coefficient of the coal rock according to the continuous depth vitrinite reflectance of the coal rock and the incidence relation between the longitudinal wave anisotropy coefficient of the core sample of the coal rock and the vitrinite reflectance of the core sample, which is pre-constructed based on an experimental analysis method. According to the method, aiming at the problem of coal rock stratum longitudinal wave anisotropy evaluation, the function relation between the longitudinal wave anisotropy coefficient and the vitrinite reflectivity is creatively established through anisotropy cause analysis, and then logging information is used for continuous deep processing, so that the coal rock longitudinal wave anisotropy coefficient logging calculation method is formed. The method provided by the invention mainly aims at a coal rock stratum, and can provide necessary parameters for coal rock anisotropy characteristic analysis, crustal stress calculation and the like.

The present application provides a kind of effective hydrocarbon source rock prediction method, device, storage medium and electronic equipment.The effective hydrocarbon source rock prediction method comprises: determining the target layer section of potential hydrocarbon source rock development in the sequence stratigraphic framework of target area;Potential hydrocarbon source rock thickness in the target layer section is predicted;Organic carbon content and vitrinite reflectance in the target layer section are predicted;Based on the potential hydrocarbon source rock thickness, organic carbon content and vitrinite reflectance in the target layer section, the distribution area of effective hydrocarbon source rock in the target layer section is determined.The problem that effective hydrocarbon source rock cannot be accurately predicted in low exploration degree area in the prior art is solved.

The invention discloses a quantitative prediction method for a coal-rock gas favorable area. The quantitative prediction method comprises the following steps: S1, collecting coal-rock underground core samples and cover rock core samples of a coal seam which is deeper than 2000m in different areas of a coal-containing basin; s2, measuring the vitrinite reflectivity, the vitrinite content, the porosity and the permeability of the underground rock core sample; s3, measuring the porosity, the permeability, the breakthrough pressure and the diffusion coefficient of the cap rock core sample, and statistically analyzing contribution weights of five evaluation indexes of the coal seam thickness, the porosity, the permeability, the breakthrough pressure and the diffusion coefficient to the sealing capacity based on the measured data to obtain a sealing index S; s4, statistically analyzing the contribution weights of the coal seam thickness, the vitrinite reflectivity, the vitrinite content, the porosity and the permeability measured in the step S2 and the sealing index S to the sealing capacity, and establishing a quantitative calculation formula of an enrichment index E; and S5, performing coal rock gas favorable area evaluation based on the enrichment index E.

The application provides a shale oil-bearing property and shale oil mobility grading evaluation method based on micro-migration. The method comprises the following steps: receiving total organic carbon content, maximum pyrolysis peak temperature, pyrolysis soluble hydrocarbon amount, pyrolysis hydrocarbon amount and vitrinite reflectance of shale oil in any area sent by a data acquisition device to obtain shale residual hydrocarbon amount, shale oil-bearing saturation, micro-migration hydrocarbon amount and hydrocarbon generation potential index; processing the vitrinite reflectance, the hydrocarbon generation potential index, the shale oil-bearing saturation and the micro-migration hydrocarbon amount to determine a critical value of the shale oil-bearing saturation, a critical value of the micro-migration hydrocarbon amount and the highest critical value and the lowest critical value of the shale residual hydrocarbon amount; and identifying a sweet spot section of the shale oil according to the critical value of the shale oil-bearing saturation, the critical value of the micro-migration hydrocarbon amount and the highest critical value and the lowest critical value of the shale residual hydrocarbon amount, so that the distribution layer section of the sweet spot with high oil-bearing property and mobility in the shale series can be quantitatively distinguished, and the error in identifying the sweet spot section is reduced.

The invention relates to the field of oil-gas exploration, and discloses a method for determining an effective gas source rock exhaust threshold by using a delta13C1-Ro relationship, and the method comprises the steps: obtaining corresponding vitrinite reflectance of an effective gas source rock stratum section at different buried depths, and drawing an evolution curve of the vitrinite reflectance with respect to the buried depths; obtaining the methane stable carbon isotope composition of the found natural gas in the research area; natural gas causes and sources are judged, and natural gas from the effective gas source rock stratum section is screened out; establishing a relationship between natural gas methane stable carbon isotope composition from the gas source rock and vitrinite reflectivity, and drawing a change curve; and determining the exhaust threshold of the effective gas source rock stratum section by utilizing the screened natural gas methane stable carbon isotope composition value in combination with the evolution curve and the change curve. According to the method, the accuracy and the pertinence of determining the exhaust threshold are improved based on actual geochemical data inversion.

The invention discloses a natural gas maturity continuous detection method based on drilling rock debris tank head gas, and belongs to the field of deep sea oil-gas exploration, and the natural gas maturity continuous detection method comprises the following steps: S1, rock debris sample treatment; s2, collecting a sample; s3, storing and transporting the sample; s4, heating in a water bath; s5, testing and analyzing; and S6, data processing: fitting mudstone section light hydrocarbon maturity parameters and mud gas methane carbon isotope or kerogen vitrinite reflectivity, establishing a rock debris tank top gas light hydrocarbon maturity model, and estimating the maturity of natural gas / kerogen around an exploratory well. By optimizing the sample treatment and analysis process, continuous and low-cost detection of the natural gas maturity under the oil-based mud system is realized, and an efficient technical means is provided for deep sea oil-gas exploration. The method is verified in the practical application of the B52 well of the dolomitic sag in the Pearl Jiangkou basin, and the exploration precision requirement is met.

The present application provides a kind of coal seam gas content prediction method, it is related to coalbed gas exploration and development technical field.The present application includes the following steps: first, select coal sample, by vitrinite random reflectance automatic determination image analysis method, obtain the maximum vitrinite reflectance R o,max Then, isothermal gas adsorption experiment is carried out to each coal sample, and the Langmuir volume V L And Langmuir pressure P L According to the maximum vitrinite reflectance R o,max Sample is divided into anthracite sample group, bituminous sample group and sub-bituminous sample group according to coal rank;Finally, the calculation formula of coal seam gas content change with depth under different coal rank is established, and the actual gas emission of coal mine is used to test, realize the calculation of coal seam gas content change with depth, the present application is simple and convenient, low in cost, can obtain the coal seam gas content of different coal mines, has good application effect and wide applicability.

This invention provides a method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale. The method includes collecting shale samples from the target layer in the study area and conducting GRI, residual total organic carbon, vitrinite reflectance (Ro), and XRD experiments to obtain basic parameters of the shale samples. These basic parameters include initial shale matrix porosity, initial matrix inorganic porosity, initial matrix organic porosity, residual total organic carbon (TOC) volume content, vitrinite reflectance (Ro), clay volume content (Vclay), initial matrix water-bearing porosity, and initial matrix hydrocarbon-bearing porosity. This invention overcomes the defects and deficiencies in the evaluation of shale porosity and permeability parameters in existing technologies, providing a porosity parameter evaluation technology for shale oil and gas exploration and development. It will significantly promote the progress and benefits of shale oil and gas exploration and development by improving the accuracy of evaluating "sweet spots" in shale oil and gas.

This invention discloses a method for calculating the contribution ratio of coal-rock gas mixtures at different maturity levels. The method comprises the following steps: S1, establishing a dynamic model for identifying the mixing ratio of mixed-source gas; S2, taking a specific natural gas extraction area as the research object, obtaining several coal-rock gas and mudstone gas samples, and measuring the methane and ethane carbon isotopes, as well as the aridity coefficient; S3, taking several unoxidized pure coal-rock and pure mudstone samples, and measuring the vitrinite reflectance; S4, performing correlation analysis based on the data obtained in steps S2 and S3 to derive regression equations for each parameter; S5, substituting the regression equations into the model formula and plotting a natural gas mixing ratio identification chart; S6, inputting the methane carbon isotope, ethane carbon isotope, and aridity coefficient data of the natural gas sample to the chart to obtain the coal-rock gas mixing contribution ratio. This method can calculate the contribution ratio of different types of source rocks at different maturity levels using methane carbon isotopes, ethane carbon isotopes, and the aridity coefficient.

The invention provides a shale in-situ conversion recoverable oil and gas resource quantity and favorable area evaluation method and equipment, and belongs to the field of shale oil and gas exploration and development. The evaluation method comprises the following steps: according to thermal simulation experiment data of a shale sample, taking influence of total organic carbon content, vitrinite reflectivity, retention oil and gas quantity, crude oil density, fluid pressure and organic matter type on oil and gas ratio in produced oil and gas as control factors, and establishing a unit mass shale in-situ conversion produced oil and gas quantity prediction model; determining an oil recovery equivalent lower limit value and an oil recovery equivalent lower limit value of rock per unit mass; determining a favorable interval according to the lower limit value of the oil recovery equivalent and the oil and gas output amount of the rock per unit mass; determining the quantity abundance of recoverable oil and gas resources according to the favorable interval; and determining a favorable area according to the abundance and the lower limit value of the recoverable oil and gas resource quantity. According to the method provided by the invention, a universal evaluation basis can be provided for evaluating the quantity of exploitable oil and gas resources developed by in-situ conversion of immature-medium and low-maturity shale and selecting areas.

The application relates to the technical field of unconventional oil and gas exploration, in particular to a high-clay shale oil in-situ accumulation dynamics mechanism and mode evaluation method, which comprises the following steps: collecting fluid pressure, temperature data, displacement pressure, oiliness, brittleness index, hydrostatic pressure, vitrinite reflectance and density values of shale samples at each depth position point of a probe well of each survey point; calculating abnormal sensitivity; then obtaining ground temperature evaluation credibility; obtaining self-adaptive fitting weight; obtaining actual fluid pressure of the probe well of each survey point at each depth; obtaining pressure coefficients of shale samples at each depth position point of the probe well of each survey point; obtaining self-sealing accumulation mode and retention accumulation mode of shale oil; and constructing a shale oil enrichment area evaluation comprehensive index based on vitrinite reflectance, oiliness, brittleness index and pressure coefficient to evaluate high-clay shale in-situ flow. The application improves the accuracy of evaluation of high-clay shale in-situ self-sealing accumulation, retention accumulation and dynamics mechanism.

A dynamic analysis method for the reflectance of vitrinite in continental hydrogen-rich shale based on normally distributed activation energy is proposed for oil and gas exploration and development, solving the problem that the existing Easy%Ro model is not suitable for the evolution analysis of vitrinite in continental hydrogen-rich shale. This invention includes: S1, a calibration method for the dynamic model of reflectance of vitrinite in continental hydrogen-rich shale; including a calibration method for the reaction dynamics model of vitrinite in hydrogen-rich shale based on in-situ thermal evolution simulation experiments or a calibration method for the reflectance dynamics model of vitrinite in hydrogen-rich shale based on paleothermal evolution history; S2, a forward modeling prediction method for geothermal evolution history based on the reflectance dynamics of vitrinite in continental hydrogen-rich shale. This invention establishes the SL_Ro model by obtaining data from in-situ thermal evolution experiments, which is more suitable for describing the reflectance evolution process of vitrinite in continental hydrogen-rich shale compared to the traditional Easy%Ro analysis method based on discrete distributed activation energy chemical kinetic models and exponential conversion relationships.

A method of fabricating and utilizing an unconventional reservoir maturity chart is provided. A historical dataset for a Paleozoic or a pre-Paleozoic shale or sandstone unconventional reservoir is utilized to obtain carbon isotopic ratio values for δ13C1, δ13C2, and vitrinite reflectance equivalents (VRE). Such data is utilized to plot several maturity shapes based upon VRE values, where several of the maturity shapes have a maturity shape boundary defined by the relationship δ13C1=δ13C2. The method for utilizing the unconventional reservoir maturity chart may include determining a maturity level for the hydrocarbon gas sample based upon a relative position of the plotted data point versus a first maturity shape, a second maturity shape, a third maturity shape, and a fourth maturity shape. The method may also permit determining a production plan for the unconventional reservoir associated with the hydrocarbon gas sample.

This invention relates to a method for determining the main gas generation threshold of cracked oil from different types of source rocks. The method is as follows: obtaining source rock samples; conducting high-temperature and high-pressure hydrocarbon generation and expulsion thermal simulation experiments in a closed system; performing total organic carbon (TOC) content and kerogen vitrinite reflectance measurements on the thermally simulated solid slag samples from the high-temperature and high-pressure hydrocarbon generation and expulsion thermal simulation experiments; plotting a cross-plot of total organic carbon content and kerogen vitrinite reflectance to obtain the maturity threshold of the main gas generation period; plotting the TOC-... T Cross-plots were used to obtain the temperature threshold for the main gas generation period; the maturity threshold and temperature threshold for the main gas generation period were verified using thermal simulation hydrocarbon production rate curves. This invention uses a "forward modeling" approach to study the main gas generation threshold of source rocks and their derived crude oil, overcoming the application drawbacks of previous "backward modeling" research methods that primarily focused on crude oil.

The application discloses a kind of middle-high coal rank coalbed gas favorable area prediction method, belong to oil and gas exploration and development technical field.The application first finds out the corresponding Lang's volume value when the lower limit value of middle coal rank vitrinite reflectance Ro according to the relationship between Lang's volume and vitrinite reflectance;Then the relationship between coal seam thickness (D), buried depth (H), overburden thickness (G) and gas content is established respectively, with the Lang's volume value when vitrinite reflectance Ro is 0.7% as the lower limit standard, to establish the intersection between coal seam thickness (D), buried depth (H), overburden thickness (G) and the Lang's volume value when vitrinite reflectance Ro lower limit value;Finally, the intersection value between the above three elements is determined as the standard, and the coalbed gas in a region is plotted with three elements, and the three-element superposition area is the favorable development area of coalbed gas.

The invention belongs to the technical field of coal vitrinite reflectance detection, and particularly relates to a coal vitrinite reflectance identification method, which is characterized in that the initial reflectance of a coal sample measured by a reflectance detection instrument is compensated based on the evaluation result of the influence brought by the test temperature to obtain the accurate vitrinite reflectance; the method comprises the following steps: firstly, performing compensation on the coal vitrinite reflectivity, secondly, performing evaluation calculation on an accurate abnormal coefficient of the vitrinite reflectivity obtained after compensation, and finally, calculating multiple groups of vitrinite reflectivity with qualified abnormal coefficient evaluation calculation, so that in the process of detecting the vitrinite reflectivity of the coal, not only is the influence brought by test temperature considered, but also the detection accuracy is improved. The abnormal influence of the impurities locally accumulated in the coal on the detection result is more comprehensively considered, and the comprehensiveness and accuracy of the detection result can be effectively improved by effectively and organically combining the influence of the test temperature and the influence of the impurities locally accumulated in the coal on the detection result in the same evaluation system.

The application discloses a method and device for calculating vitrinite reflectance of a hydrocarbon source rock, a medium and an electronic device. The method comprises the following steps: obtaining a vitrinite reflectance measurement value by analyzing a hydrocarbon source rock formation core; establishing a multiple regression relationship by performing depth homing, standardizing a density logging curve, and combining the vitrinite reflectance measurement value; obtaining a time horizon of a top interface of the hydrocarbon source rock and a bottom interface of the hydrocarbon source rock by performing seismic reflection interpretation; calculating an intermediate vertical depth horizon based on the time horizon; obtaining a density three-dimensional data body by standardizing a sonic time difference curve and a standardized density curve; obtaining a bulk density horizon by combining the time horizon and the density three-dimensional data body; and calculating the vitrinite reflectance corresponding to each calculation unit according to the multiple regression relationship, the intermediate vertical depth horizon and the bulk density horizon. The technical scheme provided by the application can improve the accuracy of calculating the vitrinite reflectance.

Disclosed is a method comprising: determining a computing platform for modeling source rocks, the computing platform including a database system, a data processing system, and a machine learning engine; generating, using the database system, analyzed graph data; filtering, using the data processing system, the analyzed graph data based on vitrinite reflectance data and thereby generate trainable data; resolving, using the data processing system, data discrepancies within the trainable data and thereby generate resolved data; holistically enhancing, using the data processing system, the resolved data to be compatible with a plurality of subterranean structures and thereby generate training data; applying, using the machine learning engine, the training data to train a subterranean model and thereby generate a trained subterranean model; and testing, using the machine learning engine, the trained subterranean model and thereby generate a prediction report indicating rock characteristics and classification of a source rocks.

The application discloses a method for calibrating and restoring shale oil and gas content by using hydrocarbon generation simulation components, and comprises the following steps: carrying out a hydrocarbon generation simulation experiment on immature / low mature shale samples to obtain hydrocarbon compositions and contents under different thermal evolution degrees; calculating gas oil ratio (GOR) and light / heavy hydrocarbon ratio (K) under different thermal evolution degrees; constructing a relationship curve between hydrocarbon generation simulation temperature (T) and equivalent vitrinite reflectance (Easy R); establishing the relationship between GOR, K and Easy R according to GOR and K; taking a high mature shale sample to carry out thermal desorption gas chromatography detection, obtaining heavy hydrocarbon content and combining K to obtain restored light hydrocarbon content and restored total chromatographic hydrocarbon content (M); obtaining restored gas content (M) and chromatographic oil content (M) according to GOR and M; taking the high mature shale sample to carry out rock pyrolysis detection before and after extraction, obtaining pyrolysis hydrocarbon values (S2) before extraction and pyrolysis hydrocarbon values (S2') after extraction, combining the difference between S2 and S2', and M to calculate restored oil content (M); and accurately restoring shale oil and gas content. n o n n o n 色谱 色谱 气 色谱油 色谱油 油 ​​​​​​​​​​​​

The invention relates to the technical field of longitudinal migration distance of natural gas, and discloses a method for determining longitudinal migration distance of organic thermogenic natural gas by using a delta C-Ro relationship, comprising the following steps: S1, acquiring current burial depth Dn and geochemical parameters of a target natural gas reservoir; s2, based on the geochemical parameters, determining the cause type of the natural gas A and the gas source rock of the natural gas A; s3, establishing a Ro-D evolution model L-Ro-D-of which the vitrinite reflectivity of the gas source rock changes along with the depth; s4, establishing a delta C-Ro relation model L-Ro-Pg-of the natural gas corresponding to the gas source rock; according to the invention, through fusion of multi-parameter geochemical comparison and a machine learning algorithm, probabilistic output of gas source rock attribution is realized, the risk of man-made misjudgment is significantly reduced, and the accuracy and reliability of cause type identification are improved; the thermal history dynamic model is coupled by adopting a nonlinear regression algorithm, and Bayesian inversion and MCMC sampling are introduced, so that not only is the goodness of fit of the model improved, but also the confidence interval of the Ro-D relationship is provided, and the model prediction is more scientific and robust.

The embodiment of the present application provides a shale source-reservoir evaluation method and device, solves the problem that the existing evaluation method cannot effectively and intuitively reflect the source-reservoir configuration of over-mature shale samples. The shale source-reservoir evaluation method provided by the embodiment of the present application comprises the following steps: obtaining parameter information of first shale samples; obtaining original source-reservoir coupling coefficients of all the first shale samples based on the parameter information of the first shale samples; obtaining second shale samples based on the source-reservoir coefficients of the first shale samples; obtaining the average value of vitrinite reflectivity of all the second shale samples; obtaining the source-reservoir coefficients of all the first shale samples based on the average value of vitrinite reflectivity of the second shale samples and the source-reservoir coefficients of the first shale samples; and performing source-reservoir evaluation on shale based on the source-reservoir coefficients of all the first shale samples.

A computer receives a measured wetness of and a measured δ2H value associated with a test gas sample from a hydrocarbon formation. The measured wetness is a molar ratio of heavy gas compounds over a total gas within the measured sample. The computer receives calculated wetnesses calculated δ2H values associated with a gas samples taken from one or more analogous hydrocarbon reservoirs. The measured wetness received for the test gas sample is identified from among the plurality of calculated wetnesses. The computer determines a corresponding δ2H value from among the calculated δ2H values that corresponds to the measured wetness of the test gas sample. The computer determines a predicted sample VRo (vitrinite reflectance equivalent) for the test gas sample based on the corresponding δ2H value and a correlation of δ2H values to VRo values. Hydrocarbons are produced from the hydrocarbon formation based on the predicted sample VRo.

The present application belongs to the field of oil and gas exploration and development, and particularly relates to a method for judging organic matter maturity. The method uses Raman spectrum characteristics of organic matter to calculate vitrinite reflectance in different cases. First, relevant characteristic parameters with strong correlation are selected to be fitted with vitrinite reflectance. Then, according to the inflection point between the characteristic parameters and vitrinite reflectance at different thermal evolution stages, i.e. the critical point of vitrinite reflectance, different fitting regions are divided, and the relationship formula with high fitting correlation coefficient in the region is taken as a discrimination formula. Therefore, the more relevant judgment formula can be directly applied in different intervals according to the characteristic parameter values obtained in the target area and the critical point, so as to calculate the vitrinite reflectance which is more consistent with the actual value, and make the judgment of the organic matter maturity in the target area more accurate. Therefore, the method can be widely applied in high thermal evolution basins, thereby overcoming the influence of high thermal evolution test inaccuracy and no vitrinite and other elements.

The present invention relates to a method for evaluating sweet spots in multi-layered shale gas reservoirs and making decisions on layered fracturing, belonging to the technical field of oil and gas field development. The method comprises the following steps: calculating geological parameters such as porosity, adsorbed gas content, organic carbon content, and vitrinite reflectance; calculating engineering parameters such as brittleness index and fracture toughness; employing the CRITIC weight method for normalization and weight distribution, constructing a comprehensive geological-engineering evaluation model, and dividing sweet spots into four categories; employing a hybrid method of "main parameter priority + outlier verification" to prioritize the analysis of interlayer gradients of high-weight parameters, and performing local fine verification of abnormal mutations of low-weight parameters based on the 3σ principle; and combining a rigid-flexible layered model to dynamically determine the fracturing layering strategy and optimize the complexity of the fracture network. The present invention improves reservoir identification accuracy through multi-parameter fusion evaluation, enhances fracturing efficiency through dynamic layered decision-making, and ultimately reduces development costs, providing technical support for the efficient development of shale gas.