A method for rapid evaluation of total porosity, hydrocarbon-bearing porosity and permeability of shales

Abstract

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.

Description

Technical Field

[0001] This invention belongs to the technical field of shale oil and gas exploration and development methods, and specifically relates to a method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale. Background Technology

[0002] Shale oil and gas refers to oil and gas contained in organic-rich shale, which is industrially developed using horizontal well volumetric fracturing technology. Shale oil and gas has become an important area of ​​global oil and gas exploration and development. However, exploration and development practice has proven that shale must meet certain conditions to obtain commercial oil and gas flows. The oil and gas production and ultimate recovery (EUR) of shale oil and gas wells are controlled by a variety of factors. Shale reservoir properties mainly include porosity and permeability, but the formation mechanisms, research methods, and connotations of porosity and permeability differ significantly from those of conventional oil and gas reservoirs. Total porosity (TPO) refers to the proportion of the total reservoir space volume to the total shale volume. Based on the differences in the development mechanism and existence state of TPO, TPO includes matrix porosity and fracture porosity; based on the different sources of organic and inorganic minerals, TPO includes matrix organic porosity and matrix inorganic porosity; based on the different properties of the fluids contained in the pores, TPO includes water-bearing porosity and hydrocarbon-bearing porosity. Shale permeability refers to the ability of fluids to flow within it. Depending on the development mechanism of permeability, permeability includes matrix permeability and fracture permeability. Depending on the measurement method, permeability includes effective permeability (including matrix effective permeability and fracture permeability) and matrix absolute permeability.

[0003] Shale porosity and permeability are key parameters for evaluating optimal sweet spots, predicting single-well production, and EUR (Earnings per Hour). Accurate prediction of shale porosity and permeability before drilling is crucial. Shale oil and gas production is contributed by both organic and inorganic porosity, but oil and gas production in organic-rich shale primarily originates from organic porosity, especially hydrocarbon-bearing porosity. Therefore, shale oil and gas resources are determined by hydrocarbon-bearing porosity. Under the same geological conditions, higher hydrocarbon-bearing porosity results in greater shale oil and gas resources per unit volume, potentially leading to higher initial oil and gas production and EUR. Thus, hydrocarbon-bearing porosity is also a key parameter for shale oil and gas evaluation.

[0004] Under current experimental measurement techniques and conditions, shale matrix porosity can be obtained using rock samples, but fracture porosity cannot be accurately obtained. Well logging data can be used to obtain total shale porosity and fracture porosity. However, in the absence of core samples and well logging data before drilling, there is no accurate model for predicting porosity and permeability. Previous studies have been limited to experimental measurements of total shale porosity, unable to distinguish between matrix organic porosity, matrix inorganic porosity, and hydrocarbon-bearing porosity. Previous studies have identified organic and inorganic pores through microscopic observation, but have not established quantitative evaluation models for organic and inorganic porosity. Previous studies have used pyrolysis and porosity measurement methods to obtain oil content in shale and estimate oil saturation, but have not established evaluation models for hydrocarbon-bearing porosity. Total shale porosity and organic porosity are related to the total organic carbon volume content and vitrinite reflectance (Ro) of shale. This study proposes a model to evaluate matrix porosity and matrix organic porosity by establishing a relationship model between total organic carbon (TOC) volume content, Ro, and total porosity in shale. Matrix inorganic porosity is obtained by subtracting matrix organic porosity from matrix porosity. Total shale porosity is evaluated by calculating fracture porosity under compression and tension stress conditions, utilizing matrix porosity and fracture porosity. The study found that water-bearing porosity in shale is mainly controlled by clay content. A model to evaluate water-bearing porosity is established by relating water-bearing porosity to clay content; hydrocarbon-bearing porosity is obtained by subtracting water-bearing porosity from total shale porosity. Accurate evaluation of total shale porosity, matrix organic porosity, matrix inorganic porosity, water-bearing porosity, and hydrocarbon-bearing porosity provides reliable parameter basis for evaluating shale oil and gas "sweet spots."

[0005] A search revealed six existing technologies related to the evaluation of shale's total porosity, matrix organic porosity, matrix inorganic porosity, water-bearing porosity, hydrocarbon-bearing porosity, and permeability. These include: 1) experimentally measuring the porosity and permeability of shale samples, primarily using methods such as density methods and GRI; 2) observing and statistically analyzing shale's organic and inorganic porosity using methods such as electron microscopy; 3) obtaining shale oil content through pyrolysis of Si, and then calculating oil-bearing porosity using total porosity; 4) obtaining shale oil content through nuclear magnetic resonance and laser confocal microscopy, and then evaluating oil-bearing porosity using total porosity; 5) measuring shale gas content and then evaluating gas-bearing porosity using total porosity; and 6) measuring shale's total porosity, water-bearing porosity, and hydrocarbon-bearing porosity using the GRI method. Existing technologies all conduct experimental measurements on single shale samples, failing to identify the controlling factors for porosity and permeability parameters, and lacking an evaluation model for porosity parameters. This makes it impossible to evaluate shale physical properties beyond experimental measurements. Furthermore, due to the significant and difficult-to-recover volatilization of oil and gas during the shale coring process, the measured values ​​contain substantial errors. Therefore, the measurements obtained using existing technologies are inaccurate.

[0006] Among the existing technologies, six methods for measuring total porosity, matrix organic porosity, matrix inorganic porosity, water-bearing porosity, hydrocarbon-bearing porosity, and permeability of shale all have defects and cannot meet the requirements for evaluating shale oil and gas "sweet spots," production, and EUR prediction, and the measurement results have large errors.

[0007] One method involves experimentally measuring the total porosity and matrix permeability of shale samples. These methods primarily include density methods and GRI methods. However, because shale has a relatively small total porosity and most pores are not interconnected, density methods, which are suitable for measuring porosity and permeability in conventional reservoir samples, have significant errors.

[0008] Secondly, the organic and inorganic porosity of shale can be observed and statistically analyzed using methods such as electron microscopy. Electron microscopy techniques such as SEM and FBI can accurately observe and statistically analyze the organic and inorganic porosity of shale. However, this method involves complex sample preparation and small sample size, typically 65μm×65μm×65μm. Due to the strong heterogeneity of shale, a small sample is unlikely to represent the entire shale, thus resulting in significant errors.

[0009] Third, the oil content of shale can be obtained by pyrolysis of Si, and then the oil-bearing porosity can be calculated using the total porosity. Pyrolysis can accurately obtain the residual Si in experimental shale samples, and the oil-bearing porosity can then be calculated using the total porosity. However, oil volatilizes during the shale sample collection process and is difficult to recover. Furthermore, parameters such as the density of the oil in the shale sample cannot be obtained during pyrolysis; therefore, the oil-bearing porosity of the shale sample cannot be accurately obtained.

[0010] Fourth, the oil content of shale samples is obtained through nuclear magnetic resonance (NMR) and laser confocal microscopy (Laser Confocal Microscopy), and then the oil-bearing porosity is evaluated through total porosity. Two-dimensional NMR can measure the residual oil content in shale samples, and laser confocal microscopy can also accurately measure and estimate the residual oil content in shale. The oil-bearing porosity is then obtained through total porosity. However, due to the volatilization of light hydrocarbons during sample preparation, which is difficult to recover, the measurement results can only reflect the residual oil content in the shale sample, rather than the true oil content under formation conditions.

[0011] Fifth, the gas content of shale is measured, and then the gas-bearing porosity is evaluated using total porosity. For shale gas, the gas content in shale samples is measured, and then the gas-bearing porosity of shale is calculated using total porosity. However, since the gas content of shale is obtained as an average value from large core samples, while the total porosity is obtained from small shale samples, and due to the high heterogeneity of shale, small shale samples cannot represent large shale core samples, there is a significant error.

[0012] Sixth, the GRI method can accurately measure and calculate the total porosity, matrix permeability, water-bearing porosity, oil-bearing porosity, gas-bearing porosity, and hydrocarbon-bearing porosity of shale. However, due to the complexity of sample processing and the long experimental time of the GRI method, it is impossible to conduct measurements on a large number of shale samples in a short period of time. In the field exploration and development of shale oil and gas, it is necessary to quickly obtain parameters such as total porosity and matrix permeability. Therefore, it is necessary to develop a rapid and accurate evaluation method for shale reservoir physical property parameters.

[0013] Existing technologies all involve experimental measurements on single shale samples. Previous studies have not identified the controlling factors for porosity and permeability parameters. Therefore, no evaluation model for porosity and permeability parameters has been established, making it impossible to evaluate shale physical properties beyond experimental measurements.

[0014] Through practical experience in shale oil and gas exploration and development, it has been found that existing methods for measuring shale porosity and permeability parameters either have defects or cannot be used for rapid evaluation, thus failing to meet production needs. There is an urgent need for a rapid, feasible, and highly accurate porosity-permeability parameter evaluation technology. This invention is proposed based on the current state of the technology and can solve the defects and deficiencies of existing technologies while meeting production requirements. Summary of the Invention

[0015] To address the aforementioned issues, this invention proposes a method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale. Based on the method and technology provided in this patent, a field for the large-scale and efficient development of shale oil and gas is provided, thereby improving economic benefits.

[0016] To achieve the above objectives, the present invention adopts the following technical solution:

[0017] A method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale includes the following steps:

[0018] Samples of the target shale section in the study area were collected and subjected to GRI, residual total organic carbon, vitrinite reflectance Ro, and XRD experiments to obtain the basic parameters of the shale samples. The basic parameters include initial shale matrix porosity, initial matrix inorganic porosity, initial matrix organic porosity, residual total organic carbon volume content TOC, vitrinite reflectance Ro, clay volume content Vclay, initial matrix water-bearing porosity, and initial matrix hydrocarbon-bearing porosity.

[0019] The organic and inorganic porosity of the matrix are evaluated based on basic parameters, and the corresponding shale matrix porosity is further obtained.

[0020] The porosity of cracks under extrusion conditions is evaluated based on basic parameters.

[0021] The evaluation of crack porosity and crack width near normal faults under tension is achieved based on basic parameters.

[0022] The total porosity of shale is evaluated based on the matrix porosity, fracture porosity under compression, and fracture porosity under tension.

[0023] Based on the basic parameters, the average values ​​of water-bearing porosity and clay volume content are statistically analyzed, and a water-bearing porosity evaluation model is established to evaluate the water-bearing porosity. The total porosity of shale is subtracted from the water-bearing porosity to evaluate the hydrocarbon-bearing porosity.

[0024] Based on the basic parameters, shale matrix porosity and hydrocarbon-bearing porosity, establish corresponding evaluation models for matrix effective permeability and matrix absolute permeability;

[0025] Based on basic parameters, fracture porosity and effective or absolute matrix permeability, establish permeability, vertical or horizontal permeability evaluation models, and fracture porosity evaluation models generated by bedding and lamination.

[0026] Preferably, the basic parameters are obtained using the GRI method to obtain shale matrix porosity, matrix inorganic porosity, matrix organic porosity, shale water-bearing porosity, shale hydrocarbon-bearing porosity, matrix effective permeability and matrix absolute permeability, using organic carbon analysis to obtain total organic carbon volume content (TOC), using vitrinite reflectance measurement to obtain vitrinite reflectance (Ro), and using XRD to obtain clay volume content (Vclay).

[0027] Preferably, obtaining the porosity of the shale matrix includes the following steps:

[0028] Within the same Ro interval, the average value of the corresponding analytical data is calculated at fixed numerical intervals.

[0029] Based on the statistically obtained average values, a relationship model between shale matrix porosity and TOC and Ro was established, and the relationship model conforms to a linear relationship.

[0030] The linear relationship is as follows:

[0031] In the formula, The shale matrix porosity is given by , TOC by , and a1 and a2 by empirical coefficients. Preferred values ​​are shown in the table below. Figure 2 As shown;

[0032] For the evaluated areas where systematic analysis and testing data are unavailable, the prediction model for shale matrix porosity is as follows:

[0033] In the formula, HI1 is the original hydrogen index of shale in the evaluated area, and HI2 is the original hydrogen index of shale in the model area.

[0034] Preferably, the matrix porosity is equal to the sum of the organic porosity and inorganic porosity of the shale matrix. When the TOC in the linear relationship is 0, the contribution of the organic porosity of the matrix to the matrix porosity is eliminated, and the obtained porosity is the average value of the inorganic porosity of the matrix.

[0035] Preferably, the evaluation of crack porosity under the extrusion background includes the following steps:

[0036] By determining the equivalent circle of a point in the target layer within a positive or negative tectonic development zone, and the angle between the tangent of the equivalent circle at that point and the line connecting that point to the tectonic inflection point or the near boundary of an undeformed stratum, the fracture porosity is calculated based on this angle, and a fracture porosity evaluation model for different tectonic locations under compressive stress is established.

[0037] The relation is:

[0038] In the formula, α represents the fracture porosity under compression, in %; α is the angle between the tangent of the structural equivalent circle at the calculation point and the line connecting that point to the structural inflection point or the near boundary of the undeformed stratum.

[0039] Preferably, the evaluation of crack porosity and crack width near normal faults under the tensile background includes the following steps:

[0040] Based on the basic parameters, the fault displacement L, the sum of clay and TOC volumes TV, the fracture porosity interpreted by well logging and seismic interpretation of shale core under tension background are obtained, as well as the fracture width predicted by seismic interpretation, the ratio of shale layer thickness to pure shale cumulative thickness Rss. Based on the obtained data, an evaluation model for fracture porosity and fracture zone width near normal faults under tension background is realized.

[0041] The crack porosity evaluation model under tension is as follows:

[0042]

[0043] In the formula, R represents crack porosity under tensile conditions, in %; ss , is the ratio of the thickness of the shale strata to the cumulative thickness of pure shale, dimensionless; L is the fault displacement of the normal fault, in meters. When L is greater than the thickness of the shale strata, let L be equal to the thickness of the shale strata; TV—the sum of the volume contents of clay and TOC, v%;

[0044] The evaluation model for the width of normal fault fracture zones is as follows:

[0045] F w =R ss ×(lnL) 1.2 / (TV / 100);

[0046] In the formula, F w R represents the width of the crack zone, in meters (m). ss denoted as the ratio of the shale layer thickness to the cumulative thickness of pure shale, dimensionless; L is the fault displacement, in meters (m). When L is greater than the shale layer thickness, let L equal the shale layer thickness; TV is the sum of the volumetric contents of clay and TOC, in v%.

[0047] Preferably, the total porosity of the shale is the sum of the shale matrix porosity, the fracture porosity under compression, and the fracture porosity under tension.

[0048] Preferably, the hydrocarbon-containing porosity is equal to the total porosity of the shale minus the water-bearing porosity of the shale.

[0049] Preferably, the hydrocarbon porosity of the shale matrix is ​​positively correlated with the effective permeability and absolute permeability of the matrix by a power law.

[0050] Preferably, the permeability, overburden vertical permeability, or overburden horizontal permeability is evaluated using an evaluation model established by the effective permeability or absolute permeability of the matrix, and an evaluation model for the crack porosity generated by bedding and lamination is established.

[0051] The evaluation model for the horizontal or vertical permeability of shale overburden is as follows:

[0052]

[0053] In the formula, K m The shale matrix permeability is expressed in mD and K. hv is the vertical or horizontal permeability of shale overburden, mD; h1 and h2 are empirical coefficients.

[0054] The shale permeability evaluation model is as follows:

[0055]

[0056] In the formula, K is the permeability, mD; K hv The permeability is either vertical or horizontal, expressed in mD. g1 is the crack porosity, %; g1 is an empirical coefficient.

[0057] The evaluation model for crack porosity caused by bedding and lamination is as follows:

[0058]

[0059] In the formula, The porosity of cracks caused by bedding and lamination, %; K h-v The average of the vertical and horizontal permeability of the overburden is given by mD; K mmD represents the matrix permeability; m1 is an empirical coefficient.

[0060] Preferably, the shale samples collected in the study area cover shale samples with different residual total organic carbon contents and different Ro values.

[0061] The beneficial effects of this invention are:

[0062] 1. The technical solution of this invention provides an evaluation method for shale porosity and permeability parameters, which provides parameter support for the evaluation and selection of shale "sweet spots", solves the defects and deficiencies in the current evaluation of shale porosity parameters, provides a rapid and accurate evaluation method for shale porosity and permeability parameters, improves the accuracy of shale physical property parameter evaluation, and meets the needs of shale oil and gas exploration and development.

[0063] 2. This invention proposes a method for evaluating the inorganic porosity of shale, overcoming the shortcomings of existing technologies that rely solely on experimental measurements to determine shale inorganic porosity. The invention considers the influence of total organic carbon (TOC) content in shale on inorganic porosity, resulting in a more accurate evaluation of shale inorganic porosity and filling the gap in existing technologies that lack evaluation techniques for both inorganic and organic porosity. It also discovers the mechanisms and factors that primarily control shale total porosity and organic porosity based on TOC and Ro, and invents a technique for establishing and evaluating total porosity and organic porosity based on TOC and Ro, overcoming the shortcomings of existing technologies that lack evaluation models for total porosity and organic porosity. Furthermore, it invents a method for evaluating shale fracture porosity under different compressional backgrounds, achieving accurate evaluation of total porosity in shale fracture development zones. It was discovered that the water-bearing porosity of shale is controlled by the clay volume content. A technique for establishing water-bearing porosity using clay volume content was invented, subtracting the water-bearing porosity from the total porosity to obtain the hydrocarbon-bearing porosity. This overcomes the shortcomings and deficiencies of existing technologies that lack evaluation models for water-bearing and hydrocarbon-bearing porosity, filling a gap in this research. A power-law relationship between different types of matrix porosity and matrix permeability in shale was discovered, and permeability evaluation techniques corresponding to different porosity types were established, enabling rapid and accurate evaluation of shale permeability. The relationship between fracture porosity and effective matrix permeability or absolute matrix permeability with overburden vertical permeability or overburden horizontal permeability was discovered. A comprehensive evaluation model was established, integrating fracture porosity, effective matrix permeability or absolute matrix permeability, overburden vertical permeability or overburden horizontal permeability, and fracture porosity generated by bedding and lamination. This solved the problem of the influence of shale bedding or lamination on permeability and fracture porosity.

[0064] 3. This invention overcomes the defects and deficiencies of existing technologies in evaluating shale porosity and permeability parameters, and provides porosity parameter evaluation technology for shale oil and gas exploration and development. It will greatly promote the progress and benefits of shale oil and gas exploration and development by improving the evaluation accuracy of shale oil and gas "sweet spots".

[0065] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures pointed out in the description, claims and drawings. Attached Figure Description

[0066] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0067] Figure 1 A flowchart illustrating the evaluation method for shale porosity and permeability parameters is shown.

[0068] Figure 2 The graph shows the relationship between total organic carbon volume content and matrix porosity in shale within different Ro ranges;

[0069] Figure 3 The diagram shows the relationship between Ro in shale and the organic and inorganic porosity of shale.

[0070] Figure 4 The deformation modes of positive and negative structures, reverse faults, and positive faults under compressive stress conditions are shown.

[0071] Figure 5 The graph shows the relationship between water porosity of shale matrix, hydrocarbon porosity of matrix, and clay volume content;

[0072] Figure 6 The graph shows the relationship between shale matrix porosity, matrix permeability, and TOC.

[0073] Figure 7 The graph shows the relationship between the effective permeability of the matrix and the vertical permeability, horizontal permeability, and absolute permeability of the matrix.

[0074] Figure 8 The graph shows the relationship between the absolute permeability of the matrix and the vertical permeability, horizontal permeability, and effective permeability of the matrix.

[0075] Figure 9 A line graph comparing the calculated and experimental values ​​of porosity parameters for a well is shown.

[0076] Figure 10 A scatter plot comparing the calculated and experimental values ​​of porosity parameters for a well is shown.

[0077] Figure 11 The graph shows the relationship between the lower limit of hydrocarbon matrix porosity and total hydrocarbon porosity when EUR is 30,000 cubic meters of oil equivalent.

[0078] Figure 12 The figure shows the lower limit of TOC corresponding to different Ro and fracture porosity when EUR is 30,000 cubic meters of oil equivalent;

[0079] Figure 13 The diagram shows the lower limit values ​​of Ro corresponding to different fracture porosity when EUR is 30,000 cubic meters of oil equivalent;

[0080] Figure 14 The diagram shows the lower limit of effective shale thickness corresponding to different Ro and fracture porosity when EUR is 30,000 cubic meters of oil equivalent.

[0081] Figure 15 The diagram shows the original formation pressure coefficient, the lower limit of the difference between the original formation fluid pressure and the hydrostatic pressure, corresponding to different fracture porosities when the EUR is 30,000 cubic meters of oil equivalent.

[0082] Figure 16 The figure shows the lower limit of clay volume content corresponding to different Ro and crack porosity when EUR is 30,000 cubic meters of oil equivalent. Detailed Implementation

[0083] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0084] A method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale, such as... Figure 1 As shown, it includes the following steps:

[0085] Samples of the target shale section in the study area were collected and subjected to GRI, residual total organic carbon, vitrinite reflectance Ro, and XRD experiments to obtain the basic parameters of the shale samples. The basic parameters include initial shale matrix porosity, initial matrix inorganic porosity, initial matrix organic porosity, residual total organic carbon volume content TOC, vitrinite reflectance Ro, clay volume content Vclay, initial matrix water porosity, and initial matrix hydrocarbon porosity.

[0086] The organic and inorganic porosity of the matrix are evaluated based on basic parameters, and the corresponding shale matrix porosity is further obtained.

[0087] The porosity of cracks under extrusion conditions is evaluated based on basic parameters.

[0088] The evaluation of crack porosity and crack width near normal faults under tension is achieved based on basic parameters.

[0089] The total porosity of shale is evaluated based on the matrix porosity, fracture porosity under compression, and fracture porosity under tension.

[0090] Based on the basic parameters, the average values ​​of water-bearing porosity and clay volume content are statistically analyzed, and a water-bearing porosity evaluation model is established to evaluate the water-bearing porosity. The total porosity of shale is subtracted from the water-bearing porosity to evaluate the hydrocarbon-bearing porosity.

[0091] Based on the basic parameters, shale matrix porosity and hydrocarbon-bearing porosity, establish corresponding evaluation models for matrix effective permeability and matrix absolute permeability;

[0092] Based on basic parameters, fracture porosity and effective or absolute matrix permeability, establish evaluation models for permeability, overburden vertical permeability or overburden horizontal permeability, and fracture porosity generated by bedding and lamination.

[0093] It should be noted that the industrial development value of shale oil and gas depends heavily on parameters such as total porosity, matrix porosity, fracture porosity, hydrocarbon-bearing porosity, and permeability. Due to the high heterogeneity of shale, limited data analysis of a small number of shale samples cannot identify the controlling factors for porosity and permeability. Shale porosity is primarily controlled by total organic carbon (TOC) volume content and Ro. By utilizing GRI measurements of numerous samples with varying TOC and Ro contents, and statistically averaging these parameters at specific intervals, the average values ​​of the relevant parameters can be represented as the average values ​​of shale matrix porosity within that range. Furthermore, research indicates a strong correlation between permeability and porosity. Extensive testing data allows for the precise identification of their mathematical relationship, enabling the establishment of a quantitative evaluation model and accurate assessment of shale permeability.

[0094] It should be noted that, in order to establish a universal porosity-permeability parameter evaluation model, shale samples collected from the study area covered shale samples with different residual total organic carbon contents and different Ro values. To establish an accurate porosity-permeability parameter evaluation model, at least three samples per Ro interval were collected for each 0.5v% interval of total organic carbon content. Each shale sample was pulverized to 40-60 mesh, and GRI measurements were performed to obtain matrix porosity, matrix water-bearing porosity, and matrix hydrocarbon-bearing porosity; organic carbon content analysis was performed to obtain the total organic carbon volume content; vitrinite reflectance measurement was performed to obtain Ro; and XRD measurements were performed to obtain the clay mineral volume content.

[0095] Furthermore, basic parameters were obtained, including shale matrix porosity, matrix inorganic porosity, matrix organic porosity, shale water-bearing porosity, shale hydrocarbon-bearing porosity, matrix effective permeability, and matrix absolute permeability obtained by GRI method; total organic carbon volume content (TOC) obtained by organic carbon analysis; vitrinite reflectance (Ro) obtained by vitrinite reflectance measurement; and clay volume content (Vclay) obtained by XRD.

[0096] Furthermore, obtaining the porosity of the shale matrix includes the following steps:

[0097] Within the same Ro interval, the average value of the corresponding analytical data is calculated at fixed numerical intervals.

[0098] Based on the statistically obtained average values, a relationship model between shale matrix porosity and TOC and Ro was established. The relationship model conforms to a linear relationship.

[0099] like Figure 2 As shown, the linear relationship is:

[0100] In the formula, denoted as shale matrix porosity, TOC as shale residual organic carbon volume content (v%), and a1 and a2 as empirical coefficients.

[0101] It should be noted that the preferred fixed numerical interval is 2v%.

[0102] For the evaluated areas where systematic analysis and testing data are unavailable, the prediction model for shale matrix porosity is as follows:

[0103] In the formula, HI1 is the original hydrogen index of the shale in the evaluated area, and HI2 is the original hydrogen index of the shale in the model area. Furthermore, matrix porosity is equal to the sum of the organic porosity and inorganic porosity of the shale matrix. When TOC in the linear relationship is 0, the contribution of matrix organic porosity to matrix porosity is eliminated, and the obtained porosity is the average value of the matrix inorganic porosity.

[0104] It should be noted that, as Figure 3 As shown, the study found that the organic porosity of the shale matrix... It has a very good mathematical correlation with Ro. Based on The mathematical model of TOC excludes the effect of organic matter when TOC = 0% v. The intercept of the intercept is the matrix inorganic porosity corresponding to the Ro interval, which is influenced by the effect of the intercept. The slope is the unit TOC. Right now (abbreviated as PDT).

[0105] Thus, different Ro intervals are obtained. The evaluation model is shown in the following formula:

[0106]

[0107]

[0108]

[0109] In the formula, Ro is the inorganic porosity of the shale matrix, in %; Ro is the vitrinite reflectance, in %; TOC is the volume content of residual organic carbon in the shale (v%). (or PDT) represents the matrix organic porosity per unit TOC, dimensionless; b1, b2, b3, b4, b5, b6, b7, b8, b9, b 10 b 11 For empirical coefficients, the preferred values ​​are -0.4583, 5.2154, 2.7865, 4.9846, -49.36, 134.77, -86.266, 9.0146, 0.0396, -7.982, and 20.933; for empirical coefficients c1, c2, c3, c4, c5, c6, c7, and c8, the preferred values ​​are 0.7737, -0.3368, 0.6697, -1.5001, 1.0500, -1.1421, -0.2099, and 0.8146.

[0110] For the evaluated areas where systematic analysis and testing data are unavailable, the prediction model for shale matrix porosity is as follows:

[0111] In the formula, HI1 is the original hydrogen index of shale in the evaluated area, and HI2 is the original hydrogen index of shale in the model area.

[0112] Furthermore, the evaluation of crack porosity under extrusion conditions includes the following steps:

[0113] By determining the equivalent circle of a point in the target layer within a positive or negative tectonic development zone, and the angle between the tangent of the equivalent circle at that point and the line connecting that point to the tectonic inflection point or the near boundary of an undeformed stratum, the fracture porosity is calculated based on this angle, and a fracture porosity evaluation model for different tectonic locations under compressive stress is established.

[0114] The relation is:

[0115] In the formula, α represents the fracture porosity under compression, in %; α is the angle between the tangent of the structural equivalent circle at the calculation point and the line connecting that point to the structural inflection point or the near boundary of the undeformed stratum.

[0116] It should be noted that, as Figure 4 As shown, the evaluation location for positive or negative structures can be determined using the top or bottom surface of the target layer or the mean isobath. (See attached diagram) Figure 4 The equivalent circular tangent AC of the average isobath at point A in the negative structural structure, the line AB connecting point A and point B near the boundary of the structural inflection point, and the angle α between AC and AB can be used to calculate the crack porosity under the extrusion background using the above formula based on the value of α.

[0117] It should be noted that the fracture porosity near the reverse fault under compression conditions varies with the distance from the fault. Therefore, the following relationship can be used to evaluate the fracture porosity correction coefficient near the reverse fault.

[0118] F c =[1+log(L) 0.5 )-D / L] / log(TV);

[0119] In the formula, F c This is the porosity correction factor for fractures near the reverse fault, dimensionless, when F c When <1, let F c =1; L is the reverse fault displacement, m; D is the lateral distance from the reverse fault, m; TV is the sum of the clay and TOC volume contents of the target layer, v%;

[0120] The evaluation model for fracture porosity near reverse faults is as follows:

[0121]

[0122] In the formula, The value represents the crack porosity, in %; F represents the crack porosity calculated based on positive or negative structural orientation, expressed as a percentage. c This is the porosity correction factor for fractures near the reverse fault, dimensionless, when F c When <1, let F c =1, Non-reverse fault control zone F c =1.

[0123] Furthermore, the evaluation of fracture porosity and fracture zone width near normal faults under tensional conditions includes the following steps:

[0124] Based on the basic parameters, the fault displacement L, the sum of clay and TOC volumes TV, the fracture porosity interpreted by well logging and seismic interpretation of shale core under tension background are obtained, as well as the fracture width predicted by seismic interpretation, the ratio of shale layer thickness to pure shale cumulative thickness Rss. Based on the obtained data, an evaluation model for fracture porosity and fracture zone width near normal faults under tension background is realized.

[0125] The crack porosity evaluation model under tension is as follows:

[0126]

[0127] In the formula, R represents crack porosity under tensile conditions, in %; ss , is the ratio of the thickness of the shale strata to the cumulative thickness of pure shale, dimensionless; L is the fault displacement of the normal fault, in meters. When L is greater than the thickness of the shale strata, let L be equal to the thickness of the shale strata; TV—the sum of the volume contents of clay and TOC, v%;

[0128] The evaluation model for the width of normal fault fracture zones is as follows:

[0129] F w =R ss ×(lnL) 1.2 / (TV / 100);

[0130] In the formula, F w R represents the width of the crack zone, in meters (m). ss denoted as the ratio of the shale layer thickness to the cumulative thickness of pure shale, dimensionless; L is the fault displacement, in meters (m). When L is greater than the shale layer thickness, let L equal the shale layer thickness; TV is the sum of the volumetric contents of clay and TOC, in v%.

[0131] It should be noted that under tensile stress conditions, shale formations develop a fault system composed of normal faults and derived faults. The fault displacement, the ratio of shale formation thickness to the cumulative thickness of pure shale, and the sum of clay and TOC volume contents within the normal fault system collectively control the degree of microfracture development in the shale formation. Fracture porosity varies significantly at different locations within a normal fault system. Therefore, the fracture porosity within a normal fault system reflects the average fracture porosity controlled by all faults within that system, and the fracture width is the sum of the fracture widths controlled by all normal faults. Based on fault displacement, fracture porosity interpreted from well logging and seismic interpretation of 24 core wells in a certain shale area, seismically predicted fracture width, the sum of clay and TOC volume contents from core analysis, and the ratio of shale formation thickness to the cumulative thickness of pure shale, an evaluation model for fracture porosity and fracture width near normal faults was established.

[0132] Furthermore, the total porosity of shale is the sum of the shale matrix porosity, the fracture porosity under compression, and the fracture porosity under tension.

[0133] It should be noted that the total porosity of shale is the sum of matrix porosity and fracture porosity, including fracture porosity generated by bedding and lamination. As mentioned earlier, matrix porosity is obtained from shale TOC and Ro, and fracture porosity is obtained through controlling factors such as tectonic deformation and faulting, thereby enabling the prediction of shale total porosity, as shown below:

[0134]

[0135] In the formula, The total porosity of shale is expressed as a percentage. Porosity of shale fractures caused by fracturing, %; The porosity of the shale matrix is ​​expressed as a percentage. The porosity of shale fractures caused by bedding and lamination is expressed as %, and the evaluation model is described later.

[0136] Furthermore, hydrocarbon porosity equals the total porosity of shale minus the water-bearing porosity of shale.

[0137] It should be noted that the study utilized GRI analysis of 1308 shale samples from a certain location to obtain matrix water porosity and matrix hydrocarbon porosity, and XRD analysis to obtain clay volume content. The average value of these parameters was statistically analyzed at certain intervals based on clay volume content, preferably taken as 2v%. This study investigated the influence of clay mineral volume content on matrix water porosity and matrix hydrocarbon porosity. Shale matrix porosity is the sum of matrix water porosity and matrix hydrocarbon porosity. The relationship between matrix water porosity and clay volume content (see appendix) was used to further investigate this influence. Figure 5 A matrix water content porosity evaluation model was established, as shown below:

[0138]

[0139] In the formula, V represents the water content porosity of the matrix, in %; clay d1 and d2 are empirical coefficients, preferably 0.0923 and 1.4316, respectively, representing the clay volume content (%).

[0140] The hydrocarbon-bearing porosity of shale matrix is ​​the difference between the total porosity of shale (the sum of matrix porosity and fracture porosity) and the water-bearing porosity of the matrix. Therefore, the evaluation model for hydrocarbon-bearing porosity of shale matrix is ​​as follows:

[0141]

[0142] In the formula, The percentage represents the hydrocarbon porosity of the matrix. The value represents matrix porosity, in percentages. The value represents the crack porosity, in %; The water content porosity of the matrix is ​​%.

[0143] Furthermore, the hydrocarbon porosity of the shale matrix is ​​positively correlated with both the effective permeability and the absolute permeability of the matrix by a power law.

[0144] It should be noted that for fracture-developed zones, a correction formula related to the power of fracture porosity is added to evaluate the permeability of shale in fracture-developed zones.

[0145] It should be noted that, as Figure 6 As shown, research indicates that the multiple correlation coefficients between matrix porosity and both effective and absolute matrix permeability are above 0.95. Therefore, matrix porosity can be used to establish evaluation models for effective and absolute matrix permeability. Similarly, the hydrocarbon-bearing porosity of shale matrix exhibits a strong power-law positive correlation with both effective and absolute matrix permeability, with multiple correlation coefficients also above 0.95. Therefore, hydrocarbon-bearing porosity can be used to establish evaluation models for effective and absolute matrix permeability, as shown below:

[0146]

[0147] In the formula, K m The shale matrix permeability is expressed in mD. f1 and f2 are empirical coefficients, representing matrix porosity (%). The model and empirical parameters are preferably adopted as follows: Figure 5 As shown.

[0148] Furthermore, the permeability, overburden vertical permeability, or overburden horizontal permeability mentioned above are evaluated using the effective permeability or absolute permeability of the matrix, and an evaluation model for the porosity of cracks generated by bedding and lamination is established.

[0149] The evaluation model for the horizontal or vertical permeability of shale overburden is as follows:

[0150]

[0151] In the formula, K m The shale matrix permeability is expressed in mD and K. hv is the vertical or horizontal permeability of shale overburden, mD; h1 and h2 are empirical coefficients.

[0152] It should be noted that, as Figure 7 As shown, the empirical parameters h1 and h2 for calculating the horizontal permeability of the overburden using the effective permeability of the matrix obtained from GRI are preferably 37.834 and 0.8728, respectively; the empirical parameters h1 and h2 for calculating the vertical permeability of the overburden using the effective permeability of the matrix obtained from GRI are preferably 1.6831 and 0.8457, respectively. Figure 8 As shown, the empirical parameters h1 and h2 for calculating the horizontal permeability of the overburden using the absolute permeability of the matrix obtained by GRI are preferably 1.9166 and 0.9323, respectively; the empirical parameters h1 and h2 for calculating the vertical permeability of the overburden using the effective permeability of the matrix obtained by GRI are preferably 0.0871 and 0.8938, respectively.

[0153] The shale permeability evaluation model is as follows:

[0154]

[0155] In the formula, K is the permeability, mD; K hv The permeability is either vertical or horizontal, expressed in mD. g1 is the crack porosity, %; g1 is an empirical coefficient.

[0156] It should be noted that the contribution of tectonic fractures to shale permeability is a volumetric concept, encompassing both horizontal and vertical permeability contributions, which can be unified as a single contribution to shale permeability. However, bedding or lamination contributes differently to overburden vertical and horizontal permeability and should be considered separately, not uniformly as a contribution along with shale permeability. When fractures are well-developed, oil and gas flow follows Darcy's law; therefore, shale permeability is related to... They exhibit a strong linear positive correlation. Shale permeability is the sum of matrix permeability and fracture permeability. Fracture permeability includes fractures generated by bedding or lamination. Therefore, a permeability evaluation model for shale with fractures is established, as shown in the above formula, where g1 is preferably 0.7595.

[0157] It should be noted that K hv This considers the contribution of bedding and lamination to overburden horizontal and vertical permeability. Overburden vertical and horizontal permeability are obtained by measuring temperature, static rock pressure, and fluid pressure under simulated formation conditions. These permeability values ​​are then compared with the effective or absolute matrix permeability obtained through GRI to establish an evaluation model for overburden vertical and horizontal permeability considering the presence of bedding and lamination. Figure 7 , Figure 8 The relationship between the vertical permeability and horizontal permeability of the overburden and the corresponding effective permeability and absolute permeability of the matrix obtained by GRI was established using 20 shale samples from 17 core wells of the Yingtan Formation under the temperature, static pressure and fluid pressure conditions of the shale sample formation.

[0158] The evaluation model for crack porosity caused by bedding and lamination is as follows:

[0159]

[0160] In the formula, The porosity of cracks caused by bedding and lamination, %; K h-v The average of the vertical and horizontal permeability of the overburden is given by mD; K m mD represents the matrix permeability; m1 is an empirical coefficient.

[0161] It should be noted that the contribution of shale bedding and lamination to fracture porosity can be calculated by the average of the overburden vertical permeability and the overburden horizontal permeability, as shown in the above formula, where m1 is preferably 0.795.

[0162] Furthermore, shale samples collected from the study area included shale samples with different residual total organic carbon contents and different Ro values.

[0163] It should be noted that, as Figure 9 As shown, by obtaining the total organic carbon volume content, Ro, and clay volume content of the shale sample to be evaluated, the porosity parameters of the shale sample can be assessed. Figure 10 As shown, the measurement techniques for total organic carbon volume content, Ro, and clay volume content are mature, highly accurate, and simple to operate, greatly accelerating the acquisition of shale porosity parameters. Figure 11 As shown, based on different EUR lower limits, the lower limits of hydrocarbon-bearing matrix porosity and total hydrocarbon-bearing porosity can be predicted, providing a basis for the selection of sweet spots in shale oil and gas. This invention provides a method and technology for evaluating and selecting porosity and permeability parameters for "sweet spots" in shale oil and gas exploration and development, which will greatly improve the accuracy of shale oil and gas "sweet spot" evaluation and support shale oil and gas exploration and development.

[0164] When fractures exist in the target shale oil and gas layer, fracture porosity plays a crucial role in controlling the lower limit of the sweet spot parameter (EUR) of shale oil and gas. The lower limit values ​​of the EUR corresponding to different degrees of fracture porosity can be determined based on the contribution of fracture porosity to the EUR, as shown below:

[0165]

[0166] In the formula, EUR crack The final recovered oil equivalent (in ten thousand cubic meters) of shale oil and gas in the presence of fractures; EUR No-crack The final extracted oil equivalent of shale oil and gas without fractures, in 10,000 cubic meters; denoted as crack porosity, %; x1 and x2 are empirical parameters, preferably 0.7595 and 0.9963, respectively.

[0167] Figure 12 The graph shows the lower limit of TOC for different Ro and fracture porosity when other parameters meet the requirement of EUR = 30,000 cubic meters of oil equivalent. It can be seen that fracture porosity has a significant impact on the lower limit of TOC. Figure 13 The graph shows the lower limit of Ro corresponding to different fracture porosities when other parameters meet the requirement of EUR = 30,000 cubic meters of oil equivalent. It can be seen that fracture porosity has a significant impact on the lower limit of Ro. Figure 14The graph shows the lower limit of effective shale thickness for different Ro values ​​and fracture porosity when other parameters meet the requirement of EUR = 30,000 cubic meters of oil equivalent. It can be seen that fracture porosity has a significant impact on the lower limit of effective shale thickness. Figure 15 The figure shows the original formation pressure coefficient, the lower limit of the original formation fluid pressure and the hydrostatic pressure difference corresponding to different fracture porosities when EUR and other parameters meet the requirement of 30,000 cubic meters of oil equivalent. It can be seen that fracture porosity has an important influence on the original formation pressure coefficient, the lower limit of the original formation fluid pressure and the hydrostatic pressure difference. Figure 16 The graph shows the lower limit values ​​of clay volume content for different Ro values ​​and crack porosity when other parameters meet the requirement of EUR = 30,000 cubic meters of oil equivalent. It can be seen that crack porosity has an important influence on the lower limit value of clay volume content.

[0168] Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for rapid evaluation of total porosity, hydrocarbon-bearing porosity, and permeability of shales, characterized in that, Includes the following steps: Samples of the target shale section in the study area were collected and subjected to GRI, residual total organic carbon, vitrinite reflectance Ro, and XRD experiments to obtain the basic parameters of the shale samples. The basic parameters include initial shale matrix porosity, initial matrix inorganic porosity, initial matrix organic porosity, residual total organic carbon volume content TOC, vitrinite reflectance Ro, clay volume content Vclay, initial matrix water porosity, initial matrix hydrocarbon porosity, effective matrix permeability, and absolute matrix permeability. The organic and inorganic porosity of the matrix are evaluated based on basic parameters, and the corresponding shale matrix porosity is further obtained. The average value of the corresponding analytical data is statistically calculated at fixed intervals within the same Ro range. Based on the statistically obtained average value, a relationship model between shale matrix porosity and TOC and Ro is established, and the relationship model conforms to a linear relationship. The fracture porosity under the extrusion background is evaluated based on basic parameters. The evaluation of crack porosity under the extrusion background includes the following steps: By determining the equivalent circle of a point in the target layer within a positive or negative tectonic development zone, and the angle between the tangent of the equivalent circle at that point and the line connecting that point to the tectonic inflection point or the near boundary of an undeformed stratum, the fracture porosity is calculated based on this angle, and a fracture porosity evaluation model for different tectonic locations under compressive stress is established. The relationship is: ; In the formula, The crack porosity under extrusion conditions is %; The angle between the tangent of the structural equivalent circle at the calculation point and the line connecting that point to the structural inflection point or the near boundary of the undeformed stratum. The evaluation of crack porosity and crack width near normal faults under tension is achieved based on basic parameters. The evaluation of fracture porosity and fracture zone width near normal faults under the tensile background includes the following steps: Based on the basic parameters, the fault displacement L, the sum of clay and TOC volumes TV, the fracture porosity interpreted by well logging and seismic interpretation of shale core under tension background are obtained, as well as the fracture width predicted by seismic interpretation, the ratio of shale layer thickness to pure shale cumulative thickness Rss. Based on the obtained data, an evaluation model for fracture porosity and fracture zone width near normal faults under tension background is realized. The crack porosity evaluation model under tension is as follows: ； In the formula, The crack porosity under tension is %; This is the ratio of the thickness of the shale strata to the cumulative thickness of the pure shale, and is dimensionless. The fault displacement is m. When the thickness is greater than that of the shale layer, let Equal to the thickness of the shale layer; —The sum of the volumetric contents of clay and TOC, v% The evaluation model for the width of normal fault fracture zones is as follows: ； In the formula, The width of the crack zone is in meters (m). This is the ratio of the thickness of the shale strata to the cumulative thickness of the pure shale, and is dimensionless. Let f be the fault displacement, in meters. When the thickness is greater than that of the shale layer, let Equal to the thickness of the shale layer; The sum of the volume contents of clay and TOC, v% The total porosity of shale is evaluated based on the matrix porosity, fracture porosity under compression, and fracture porosity under tension. Based on the basic parameters, the average values ​​of initial matrix water porosity and clay volume content were statistically analyzed, and a water porosity evaluation model was established to evaluate water porosity. The total porosity of shale was subtracted from the water porosity to evaluate the hydrocarbon porosity. Based on the basic parameters, shale matrix porosity and hydrocarbon-bearing porosity, establish corresponding evaluation models for matrix effective permeability and matrix absolute permeability; Based on basic parameters, fracture porosity and effective or absolute matrix permeability, establish evaluation models for permeability, overburden vertical permeability or overburden horizontal permeability, and fracture porosity generated by bedding and lamination.

2. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 1, characterized in that, The basic parameters were obtained as follows: initial shale matrix porosity, initial matrix inorganic porosity, initial matrix organic porosity, initial matrix water-bearing porosity, initial matrix hydrocarbon-bearing porosity, matrix effective permeability, and matrix absolute permeability were obtained using the GRI method; residual total organic carbon volume content (TOC) was obtained using organic carbon analysis; vitrinite reflectance (Ro) was obtained using vitrinite reflectance measurement; and clay volume content (Vclay) was obtained using XRD.

3. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 1, characterized in that, Obtaining the porosity of the shale matrix includes the following steps: The linear relationship is as follows: ; In the formula, denoted as shale matrix porosity, TOC as shale residual organic carbon volume content (v%), and a1 and a2 as empirical coefficients; For the evaluated areas where systematic analysis and testing data are unavailable, the prediction model for shale matrix porosity is as follows: ; In the formula, HI1 is the original hydrogen index of shale in the evaluated area, and HI2 is the original hydrogen index of shale in the model area.

4. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 3, characterized in that, The matrix porosity is equal to the sum of the organic porosity and inorganic porosity of the shale matrix. When the TOC in the linear relationship is 0, the contribution of the organic porosity of the matrix to the matrix porosity is eliminated, and the obtained porosity is the average value of the inorganic porosity of the matrix.

5. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 1, characterized in that, The total porosity of the shale is the sum of the shale matrix porosity, the fracture porosity under compression, and the fracture porosity under tension.

6. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 1, characterized in that, The hydrocarbon-bearing porosity is equal to the total porosity of shale minus the water-bearing porosity of shale.

7. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 1, characterized in that, The hydrocarbon-bearing porosity of the shale matrix is ​​positively correlated with the effective permeability and absolute permeability of the matrix by a power law.

8. The method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to claim 1, characterized in that, The permeability, overburden vertical permeability, or overburden horizontal permeability mentioned above are evaluated using the effective permeability or absolute permeability of the matrix to establish an evaluation model for the porosity of cracks caused by bedding and lamination. The evaluation model for the horizontal or vertical permeability of shale overburden is as follows: ； In the formula, The shale matrix permeability is expressed in mD. , representing the vertical permeability or horizontal permeability of shale overburden, in mD; , This is an empirical coefficient; The shale permeability evaluation model is as follows: ； In the formula, Permeability, mD; The permeability is either vertical or horizontal, expressed in mD. The value represents the crack porosity, %; This is an empirical coefficient; The evaluation model for crack porosity caused by bedding and lamination is as follows: ； In the formula, The porosity of cracks caused by bedding and lamination, % The average of the vertical and horizontal permeability of the overburden is given in mD. The shale matrix permeability is expressed in mD. This is an empirical coefficient.

9. A method for rapidly evaluating the total porosity, hydrocarbon-bearing porosity, and permeability of shale according to any one of claims 1-8, characterized in that, The shale samples collected in the study area included shale samples with different residual total organic carbon contents and different Ro values.

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