45 results about "Vitrinite reflectance" patented technology

The invention relates to a shale gas multi-layer stacked reservoir dessert evaluation and separate layer fracturing decision-making method, and belongs to the technical field of oil-gas field development, and the method comprises the following steps: calculating porosity, adsorbed gas content, organic carbon content and vitrinite reflectance geological parameters; calculating brittleness index and fracture toughness engineering parameters; carrying out normalization processing and weight distribution by adopting a CRITIC weight method, constructing a geological-engineering comprehensive evaluation model, and dividing four types of sweet spot areas; through a mixed method of main parameter priority and abnormal value verification, preferentially analyzing interlayer gradients of high-weight parameters, and performing local fine verification on abnormal abrupt change of low-weight parameters based on a 3 sigma principle; and in combination with a rigid-flexible layering model, a fracturing layering strategy is dynamically decided, and the complexity of the fracture network is optimized. According to the method, the reservoir identification precision is improved through multi-parameter fusion evaluation, the fracturing efficiency is enhanced through dynamic hierarchical decision, the development cost is finally reduced, and technical support is provided for efficient development of shale gas.

The invention relates to the technical field of unconventional oil-gas exploration, in particular to a high-clay shale oil in-situ accumulation dynamics mechanism and mode evaluation method. The method comprises the following steps: collecting fluid pressure, temperature data, displacement pressure, oiliness, brittleness index, hydrostatic pressure, vitrinite reflectivity and density value of a shale sample at each depth position point of an exploratory well of each exploration point; calculating abnormal sensitivity; further acquiring ground temperature evaluation credibility; obtaining a self-adaptive fitting weight; acquiring the actual fluid pressure of the exploratory well of each survey point at each depth; acquiring the pressure coefficient of the shale sample at each depth position point of the exploratory well of each survey point; obtaining a self-sealing reservoir forming mode and a retention reservoir forming mode of shale oil; based on the vitrinite reflectivity, the oiliness, the brittleness index and the pressure coefficient, a shale oil enrichment area evaluation comprehensive index is constructed, and the in-situ flow of the high-clay shale is evaluated. According to the method, the accuracy of in-situ self-sealing reservoir formation, retention reservoir formation and dynamic mechanism evaluation of the high-clay shale is improved.

The invention relates to a detailed classification method for coking coal, which comprises the following steps of: dividing the coking coal into gas coal, 1 / 3 coking coal, gas-fat coal, fat coal, coking coal, lean coal, meager lean coal and meager coal according to the standard of China Coal Classification; detailed classification is carried out according to coal quality parameter indexes including volatile components Vdaf, a caking index G value, a gelatinous layer maximum thickness Y and a vitrinite reflectivity histogram distribution state; wherein the gas coal is divided into gas coal 1 and gas coal 2; dividing the fat coal into fat coal 1, fat coal 2 and fat coal 3; dividing 1 / 3 coking coal into 1 / 3 coking coal 1 and 1 / 3 coking coal 2; the coking coal is divided into coking coal 1, coking coal 2 and coking coal 3; dividing the lean coal into lean coal 1 and lean coal 2; the gas-fat coal and the meager lean coal are not classified in detail. And through detailed classification of the coking coal, the interchangeability of the coking coal from different sources during coal blending is improved, and the coking quality and stability of the blended coal are ensured.

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 relates to a method for identifying a crude oil source of a continental freshwater lake basin, which comprises the following steps: (1) collecting hydrocarbon source rock samples with different buried depths, and analyzing to obtain a special biomarker compound value and vitrinite reflectivity Ro in saturated hydrocarbon of the hydrocarbon source rock samples; (2) establishing and screening a first fitting relationship between the value of the special biomarker compound in the saturated hydrocarbon and the vitrinite reflectivity Ro, wherein the screening standard is that the correlation is not less than 0.65; establishing a second fitting relationship between the vitrinite reflectivity Ro and the buried depth of the hydrocarbon source rock sample; (3) analyzing to obtain the special biomarker compound value of the crude oil sample in the target freshwater lake basin, and converting the equivalent maturity Rc of the crude oil according to the first fitting relation established in the step (2); and (4) identifying the source of the crude oil according to the equivalent maturity Rc of the crude oil obtained in the step (3) and the second fitting relation established in the step (2).

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 invention pertains to the field of petroleum, and more specifically to the areas of reservoir modelling, simulation and evaluation, and discloses a method for processing data obtained through Raman spectroscopy in order to determine the thermal maturity of organic matter in rock, based on calibration using vitrinite reflectance standards, using different excitation wavelengths.

The present invention discloses a method for correcting the nuclear magnetic resonance porosity of coal and rock considering the organic carbon content, which includes performing saturated water treatment on coal and rock samples and obtaining the saturated water nuclear magnetic resonance porosity of the coal and rock samples; selecting the same coal and rock samples to carry out the determination of total organic carbon and obtaining the total organic carbon content of the coal and rock samples; carrying out the determination of the vitrinite reflectance of coal and rock and obtaining the vitrinite reflectance of the coal and rock samples; performing correction on the saturated water nuclear magnetic resonance porosity of coal and rock according to the saturated water nuclear magnetic resonance porosity, the total organic carbon content, and the vitrinite reflectance to obtain the corrected porosity. The present invention introduces the total organic carbon content obtained from the test of basic coal and rock data and the vitrinite reflectance data representing the coal and rock evolution stage for correction to eliminate the nuclear magnetic resonance signals in the coal and rock matrix. The corrected data is more real and reliable, and the method is convenient and affordable, and can be carried out on a large scale, which has important guiding significance for the large-scale exploration and development of coal and rock gas.

The invention provides a shale oiliness and shale oil mobility grading evaluation method based on micro-migration. The method comprises the following steps: receiving the total organic carbon content, the highest pyrolysis peak temperature, the pyrolysis soluble hydrocarbon amount, the pyrolysis hydrocarbon amount and the vitrinite reflectivity of shale oil in any region sent by data acquisition equipment, so as to obtain the shale retention hydrocarbon amount, the shale oil saturation, the micro-migration hydrocarbon amount and the hydrocarbon generation potential index; the vitrinite reflectivity, the hydrocarbon generation potential index, the shale oil saturation and the micro-migration hydrocarbon amount are processed, the critical value of the shale oil saturation is determined, the critical value of the micro-migration hydrocarbon amount is determined, and the highest critical value and the lowest critical value of the shale retention hydrocarbon amount are determined; according to the critical value of the oil saturation of the shale, the critical value of the micro-migration hydrocarbon amount and the highest critical value and the lowest critical value of the retained hydrocarbon amount of the shale, the sweet spot section of the shale oil is identified, the distribution layer section of the sweet spots with high oiliness and mobility in the shale bed series can be quantitatively judged, and the error of identifying the sweet spot section is reduced.

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 present invention discloses a five-end-member three-component classification and characterization method for shale lithofacies, comprising performing X-ray diffraction analysis on shale samples to determine the shale mineral components and contents; performing vitrinite reflectance measurement on the shale samples to determine the shale maturity; performing total organic carbon analysis on the shale samples to determine the total organic carbon content percentage; calculating the content percentages of quartz and feldspar, clay minerals, and carbonate rock; determining the shale lithofacies type based on the position of the shale maturity, total organic carbon content percentage, quartz and feldspar content percentage, clay mineral content percentage, and carbonate rock content percentage of the shale sample in a five-end-member three-group classification diagram; and characterizing the lithofacies characteristics in the form of a radar chart. The present invention can classify and intuitively represent shale lithofacies, facilitate comparison of shale lithofacies of different samples, and be used to determine the most favorable shale lithofacies, guiding the selection of favorable areas for shale gas exploration and development.

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 relates to a method for identifying the burial depth of crude oil in a continental saline lake basin. According to the method, the ratio of crude oil terpene Ts oil / (Ts oil + Tm oil) is analyzed from a crude oil geochemical test of continental facies salt water lake basin; the method comprises the following steps: extracting terpane Ts rock and (Ts rock + Tm rock), testing and analyzing the hydrocarbon source rock in the area, analyzing the ratio of extracted organic matter terpane Ts rock / (Ts rock + Tm rock) and the vitrinite reflectivity Ro of the hydrocarbon source rock, establishing the correlation between the ratio of the hydrocarbon source rock terpane Ts rock / (Ts rock + Tm rock) and the vitrinite reflectivity Ro, and finally determining the depth of the hydrocarbon source rock by utilizing the relationship between the vitrinite reflectivity Ro and the depth according to the equivalent principle. And the burial depth of the crude oil can be accurately calculated. The identification method provided by the invention provides technical support for accurate positioning of the continental saline water lake basin oil source reservoir space, the probability of exploration and development failure is greatly reduced, and the development cost is greatly reduced.

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 present invention provides a method for obtaining the thermal history of ancient strata in deep sedimentary basins. The method includes: obtaining vitrinite reflectance data of mudstones in various layers of a work area to determine the highest paleo-geothermal gradient in the work area; obtaining fission track and (U-Th) / He test data of clastic rock strata samples in shallow Mesozoic and Cenozoic layers of the work area to simulate the thermal history of the clastic rock strata in the work area, and determining the burial history of the work area in combination with the highest paleo-geothermal gradient; obtaining fission track and (U-Th) / He test data of clastic rock strata samples in deep Paleozoic layers of the work area to determine the temperature evolution path of the deep clastic rock strata in the work area; obtaining cluster isotope test data and in-situ U-Pb dating data of carbonate rock strata samples in deep Paleozoic layers of the work area to determine the temperature evolution path of the deep carbonate rock strata in the work area; determining the paleo-geothermal gradient evolution of the work area based on the temperature evolution path of the deep clastic rock and carbonate rock strata in the work area in combination with the burial history of the work area, and restoring the paleo-heat flow evolution of the work area in combination with thermal conductivity data.

The present invention discloses a method for characterizing the maturity of organic matter based on mechanical properties, belonging to the field of characterizing the maturity of organic matter. It includes measuring the vitrinite reflectance of a source rock sample to obtain the maturity of the organic matter in the source rock sample and establishing a sequence of organic matter maturity; using an atomic force microscope to measure the Young's modulus of the source rock sample to obtain the Young's modulus of the organic matter in source rock samples with different maturities; combining the sequence of organic matter maturity and the Young's modulus, and using the regression analysis method to construct an S model of the organic matter maturity and the Young's modulus; using an atomic force microscope to measure the Young's modulus of an unknown source rock sample, and using the S model to obtain the maturity of the organic matter in the unknown source rock sample. The present invention is applied to the characterization of the maturity of organic matter, solves various limitations and problems existing in the traditional characterization method and the spectroscopic technology characterization method for characterizing the maturity of organic matter, and has the characteristics of wide application range, small limitation and accurate analysis results.

The invention relates to a method for calculating the maturity of a heavy oil reservoir, which comprises the following steps of: (1) collecting a typical coal sample, extracting asphaltene in the typical coal sample, and analyzing to obtain the air reflectivity of the asphaltene and the vitrinite reflectivity Ro of the typical coal sample; (2) establishing a fitting relation between asphaltene air reflectivity in the typical coal sample and vitrinite reflectivity Ro of the typical coal sample; (3) enabling the fitting relationship established in the step (2) to be equivalent to a corresponding relationship between the asphaltene air reflectivity of the heavy oil reservoir and the equivalent maturity of the heavy oil reservoir; and asphaltene in the heavy oil reservoir in the target area is extracted and analyzed to obtain the air reflectivity of the asphaltene, and the maturity of the heavy oil reservoir in the target area is calculated in combination with the corresponding relation. According to the method, the maturity of the target heavy oil reservoir can be accurately calculated, the required experimental technology is simple, data acquisition is easier, cost is low, practicability is high, and large-scale application and popularization are easier.

The invention belongs to the technical field of oil and gas exploration and development, and particularly relates to an equivalent calibration method for crude oil maturity, which comprises the following steps: collecting a plurality of groups of samples with different maturity from a shale oil layer series, each group of samples comprising a hydrocarbon source rock sample and a crude oil sample of the same layer series; determining the vitrinite reflectivity Ro of the hydrocarbon source rock sample; the method comprises the following steps: testing the contents of C29-alpha alpha alpha-20S-regular stane and C29-alpha alpha alpha-20R-regular stane in a crude oil sample, and calculating C29-alpha alpha alpha-20S / (20S + 20R); establishing a fitting formula according to the plurality of groups of vitrinite reflectivity Ro and the plurality of groups of C29-alpha alpha alpha-20S / (20S + 20R); and calculating the crude oil maturity according to a fitting formula. The method has the advantages of being high in accuracy and small in error, the maturity calculated through the method is closer to the real maturity of crude oil, the method is more accurate compared with an existing method, and efficient support is provided for oil-gas exploration of the petroliferous basin.

The invention discloses a method for calculating the gas mixing contribution ratio of coal rocks with different maturity degrees. The method comprises the following steps: S1, establishing a mixed source gas mixing ratio identification dynamic model; s2, taking a certain natural gas exploitation area as a research object, acquiring a plurality of coal rock gas and mudstone gas samples, and measuring methane carbon isotope, ethane carbon isotope and drying coefficient; s3, taking a plurality of unoxidized pure coal rock samples and pure mudstone samples, and measuring vitrinite reflectivity; s4, performing correlation analysis according to the data measured in the steps S2 and S3 to obtain a regression equation of each parameter; s5, substituting the regression equation into the model formula, and drawing a natural gas mixing ratio identification chart; and S6, substituting the data values of the methane carbon isotope, the ethane carbon isotope and the drying coefficient of the natural gas sample to be detected into the chart to obtain the coal-rock-gas mixing contribution ratio. According to the method disclosed by the invention, the contribution proportions of different types of hydrocarbon source rocks with different maturity degrees can be calculated through methane carbon isotope, ethane carbon isotope and a drying coefficient.

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.