Method for evaluating natural seepage capacity of carbonate-rich shale reservoir

Abstract

The invention relates to the field of geological engineering and oil-gas exploration, in particular to a method for evaluating the natural seepage capacity of a carbonate-rich shale reservoir. The method comprises the following steps: preparing a shale sample; effective test points are obtained, and the overburden pressure permeability of the sample is tested; cutting the tested sample, performing lithofacies identification, and determining a permeability correction coefficient a value through lithofacies; determining a permeability parameter effective range and a permeability effective coefficient; determining a pressure-permeability fitting formula within the permeability parameter validity range, and obtaining a natural permeability coefficient Fn in combination with the permeability correction parameter and the permeability effective coefficient; and evaluating the seepage capacity according to the obtained natural seepage coefficient. According to the method, the natural seepage capacity of the carbonate-rich shale reservoir can be accurately and effectively evaluated.

Description

Technical Field

[0001] The present invention relates to the fields of geological engineering and oil and gas exploration, and particularly relates to a method for evaluating the natural seepage capacity of carbonate-rich shale reservoirs. Background Art

[0002] The natural seepage capacity of shale reservoirs is of great significance for evaluating the mobility of shale oil. At the same time, the natural seepage capacity of shale reservoirs determines the economic development time of shale oil and gas wells, and is of great significance for calculating the economically recoverable resource volume of shale oil.

[0003] Currently, the relevant research on shale seepage capacity mainly includes two types of technologies: (1) directly testing the shale permeability through experiments and (2) indirectly calculating the shale seepage capacity. "A High Temperature and High Pressure Permeability Testing Device" (Patent Application No. 201610898376.8) proposes a method that uses increased confining pressure and temperature control to achieve a high-pressure environment. After adding high-pressure fluid to the core using a liquid booster pump, the permeation flow rate is calculated by measuring the mass of the liquid seeping out of the core using a precision balance. "Device and Method for Stress-Seepage-Temperature Coupling and Displacement Test of Gas-Bearing Shale" (Patent Application No. 201310172572.3) proposes an experimental method that includes operation steps such as fixing the specimen, applying confining pressure, applying axial pressure, heating, evacuating, applying upstream liquid pressure, applying upstream gas pressure, injecting multiphase mixed fluid, pre-adsorption saturation of the specimen, and fluid collection to achieve stress-seepage-temperature coupling and displacement test. "Device and Method for Determining the Seepage Law of Shale Gas in Microcracks" (Patent Application No. 201410548615.8) proposes a method for obtaining the seepage law of shale gas in different microcracks by comparing the permeability curves of shale gas in intact cores and different microcracks. "Experimental Evaluation Method for Adsorption of Shale Gas by Coal / Shale Ultra-High Pressure Gas Adsorption and Seepage" (Patent Application No. 201710267006.9) proposes a method that can simultaneously achieve high-pressure gas adsorption and seepage experiments. In this method, the core permeability is calculated by measuring the gas flow rate through the core under high-pressure conditions and combining with Darcy's law.

[0004] "A Multi-Field Coupled Seepage Multi-Functional Experimental Device and Testing Method" (Patent Application No. 201710702054.6) discloses an experimental device including a device body, a stress field control system, a temperature field control system, a fluid loading control system, and a fluid seepage measurement system, and proposes an experimental method for testing the coupled seepage of carbon dioxide and tight gas or shale gas by measuring the gas volume and gas components flowing through the core. "Shale Gas Reservoir Micro-Fracture High Temperature and High Pressure Visualization Gas-Water Two-Phase Seepage Experimental Device" (Patent Application No. 201810412794.0) discloses a method of forming a seepage plate with a sapphire glass plate and a rock plate, and introducing the displacement liquid into the seepage plate under high pressure to observe the gas-liquid two-phase flow law of the rock plate and realize the two-phase seepage experiment by measuring the discharged gas volume and the displacement liquid. "Quantitative Evaluation Method for the Contribution Rate of Different Mass Transfer and Diffusion Mechanisms in Shale Gas Reservoirs to Reservoir Seepage Capacity" (Patent Application No. 201811456867.2) proposes to test the core permeability with helium, methane, and deionized water respectively, and compare the permeability measured without deionized water and the corrected helium permeability to obtain the equivalent permeability of the Darcy seepage and slippage effect mechanisms respectively. By comparing and analyzing the corrected helium permeability and methane permeability, the equivalent permeability of the surface diffusion effect is obtained. "A Pulse Decay Permeability Testing Method for Shear Fracture Shale Core" (Patent Application No. 201910664344.5) proposes to conduct a pulse decay experiment on the shear fracture shale core, measure the pressure-time relationship curves of the upstream chamber and the downstream chamber, and combine the dual-medium physical model of the shear fracture shale core to obtain the matrix permeability and fracture permeability of the shear fracture shale core by using the curve fitting method. "A True Triaxial Fracture Seepage Continuous Testing System and Method" (Patent Application No. 201910467978.1) proposes an experimental method for continuously testing the fracture seepage of specimens by simulating the actual stress, temperature, and seepage conditions of rocks in the formation under the action of a temperature field, a seepage field, and a stress field.

[0005] Currently, the instruments and methods for studying the seepage capacity of shale reservoirs mainly have the following problems: (1) Epigenetic fractures interfere with the analysis of the natural permeability of shale. Shale is very likely to generate new fractures during the process of being taken from underground to the ground and sample processing. Shale can be divided into various types according to the mineral content characteristics, such as clay rock facies, felsic rock facies, carbonate rock facies, and mixed rock facies. The skeleton structures of different types of shale are different, and the development abilities of epigenetic fractures are significantly different. However, all existing research methods and testing techniques cannot correct the shale permeability according to the shale type. (2) Shale is extremely dense, and the permeability is extremely low under formation conditions. When some shale is pressurized to the formation pressure, the core will rupture, resulting in data invalidation. However, there is currently no technical method to judge the validity of the data. Summary of the Invention

[0006] To solve the above-mentioned problems, the present invention provides a method for evaluating the natural seepage capacity of a carbonate-rich shale reservoir. The method of the present invention can accurately and effectively evaluate the natural seepage capacity of a carbonate-rich shale reservoir.

[0007] To achieve the above object, the present invention adopts the following technical solutions:

[0008] The present invention provides a method for evaluating the natural seepage capacity of a carbonate-rich shale reservoir, and the method includes the following steps: shale sample preparation; obtaining effective test points and performing confining pressure permeability tests on the samples; cutting the tested samples and performing lithofacies identification, and determining the permeability correction coefficient a value through lithofacies; determining the effective range of permeability parameters and the permeability effective coefficient; determining the pressure-permeability fitting formula within the effective range of permeability parameters, and combining the permeability correction parameters and the permeability effective coefficient to obtain the natural seepage coefficient Fn; and performing seepage capacity evaluation according to the obtained natural seepage coefficient.

[0009] Further, the method for preparing the shale samples is as follows: cylindrical samples are prepared by wire cutting on the core samples parallel to the bedding direction.

[0010] Further, the method for obtaining effective test points is as follows: after the surface of the sample is polished smoothly, permeability tests are performed under confining pressure by setting the initial pressure point, the median pressure point, and the highest pressure point; through repeated experiments, the highest pressure point for obtaining effective data is determined.

[0011] The specific method for performing confining pressure permeability tests on the samples is as follows: at least three pressure points are selected within the obtained highest pressure point range to perform confining pressure permeability tests on the samples.

[0012] Further, after the tested samples are cut, thin section analysis is performed to statistically analyze the sedimentary structure characteristics; meanwhile, parallel samples are selected for XRD whole-rock mineral component analysis, and lithofacies identification is performed according to the obtained results; the permeability correction coefficient a value is determined according to the combination type of sedimentary component 1 and sedimentary component 2 that make up the shale sedimentary structure.

[0013] Still further, the sedimentary structure characteristics are judged according to thin section observation. The single-layer sedimentary structure thickness less than 1 mm is defined as laminar, the single-layer sedimentary structure greater than 1 mm is defined as layered, and the absence of layered sedimentary structure is defined as massive; the shale mineral component characteristics are judged through XRD whole-rock mineral analysis. When the carbonate content is greater than 50%, it is defined as carbonate-rich shale type, and when the carbonate content and the content of other minerals do not exceed 50%, it is defined as mixed shale type.

[0014] Further, the method for determining the effective range of permeability parameters is as follows: obtaining the shale permeability change rate Δ at the n pressure points within the effective pressure range n ; when the permeability K at the n pressure pointsn Greater than 0.1×10 -3 μm -2 , the permeability parameters at the nth point and subsequent points are invalid; when Δ n > 30%, the permeability parameters at the nth point and subsequent points are invalid.

[0015] The method for determining the permeability effective coefficient is as follows: when the stress sensitivity coefficient > 0.7, the permeability effective coefficient b is 0; when the stress sensitivity coefficient ≤ 0.7, b is 1.

[0016] Furthermore, the shale permeability change rate Δ n is expressed by the following formula:

[0017]

[0018] where K n is the permeability measured at the nth pressure point (×10 -3 μm -2 ), K n-1 is the permeability measured at the (n - 1)th point (×10 -3 μm -2 ), and Δ is the permeability change rate between the nth and (n - 1)th points.

[0019] Furthermore, the stress sensitivity coefficient S S is expressed by the following formula:

[0020]

[0021] where P n , P0 are the effective stresses (MPa) corresponding to the nth pressure point and the initial pressure point respectively, K n and K0 are the permeabilities (×10 -3 μm -2 ) corresponding to the nth pressure point and the initial pressure point respectively, and S S is the stress sensitivity coefficient.

[0022] Further, the specific method for evaluating the seepage capacity based on the obtained natural seepage coefficient is as follows:

[0023] When the natural seepage coefficient Fn > 1×10 -2 , the natural seepage capacity of the reservoir is extremely strong;

[0024] 1×10 -3 < Fn ≤ 1×10 -2 , the natural seepage capacity of the reservoir is strong;

[0025] 1×10 -4 < Fn ≤ 1×10 -3 , the natural seepage capacity of the reservoir is relatively strong;

[0026] 1×10 -5 <Fn ≤ 1×10 -4 When, the natural seepage capacity of the reservoir is medium;

[0027] 1×10 -6 <Fn ≤ 1×10 -5 When, the natural seepage capacity of the reservoir is weak;

[0028] Fn ≤ 1×10 -6 When, the natural seepage capacity of the reservoir is very weak.

[0029] Furthermore, the natural seepage coefficient Fn is expressed by the following formula:

[0030] F n = a * b * P n

[0031] Wherein, F n is the natural seepage coefficient, a is the permeability correction coefficient, b is the effective permeability coefficient, and P n is the pressure.

[0032] Compared with the prior art, the present invention has the following advantages:

[0033] The method of the present invention can accurately and effectively evaluate the natural seepage capacity of the carbonate-rich shale reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0034] Figure 1 is the specific flowchart of the method for evaluating the natural seepage capacity of the carbonate-rich shale reservoir according to the embodiment of the present invention;

[0035] Figure 2 is the pressure-permeability fitting curve in Embodiment 1 of the present invention;

[0036] Figure 3 is the pressure-permeability fitting curve in Embodiment 2 of the present invention;

[0037] Figure 4 is the pressure-permeability fitting curve in Embodiment 3 of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0038] It should be noted that the following detailed description is exemplary and is intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those of ordinary skill in the technical field to which the present invention belongs.

[0039] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and "including" are used in this specification, they indicate the presence of features, steps, operations, and their combinations.

[0040] The present invention provides a method for evaluating the natural seepage capacity of a carbonate-rich shale reservoir, and the method includes the following steps:

[0041] Step 1. Preparation of shale samples;

[0042] Step 2. Obtaining effective test points;

[0043] Step 3. Conducting confining pressure permeability tests on the samples;

[0044] Step 4. Cutting the tested samples, conducting lithofacies identification, and determining the permeability correction coefficient a value through lithofacies;

[0045] Step 5. Determining the effective range of permeability parameters and the permeability effective coefficient;

[0046] Step 6. Determining the pressure-permeability fitting formula within the effective range of permeability parameters, and combining the permeability correction parameters and the permeability effective coefficient to obtain the natural seepage coefficient Fn; evaluating the seepage capacity according to the obtained natural seepage coefficient.

[0047] As a preferred embodiment, in Step 1, cylindrical samples are obtained by cutting a rock or core sample at any angle according to requirements.

[0048] As a preferred embodiment, the method for obtaining effective test points in Step 2 is: polishing and cleaning the surface of the cylindrical sample, then placing it in a confining pressure permeability measuring instrument, heating to the target temperature, and conducting a confining pressure permeability test after the temperature stabilizes. Select the lowest initial test pressure as the first pressure point, the formation pressure as the highest pressure point, and the average value of the lowest initial test pressure and the formation pressure as the median pressure point to conduct a permeability test under confining pressure conditions. Through multiple experiments, determine the highest pressure point P m .

[0049] As a preferred embodiment, the specific method for conducting confining pressure permeability tests on the samples in Step 3 is: select the lowest initial test pressure P0, the highest pressure point P m and P1, P2,..., P m between P0 and P n a number of pressure points, and conduct confining pressure permeability tests on the samples under constant temperature conditions with a total of no less than 3 test pressure points.

[0050] As a preferred embodiment, the method for determining the permeability correction coefficient a in step 4 is as follows: Cut the cylindrical sample after testing, and conduct thin section and XRD whole-rock mineral composition analysis on the cut sample. Judge the sedimentary structure characteristics according to the thin section observation. If the thickness of a single-layer sedimentary structure is less than 1 mm, it is defined as laminated; if the thickness of a single-layer sedimentary structure is greater than 1 mm, it is defined as layered; if no layered sedimentary structure is seen, it is defined as massive. Judge the shale mineral composition characteristics through XRD whole-rock mineral analysis. If the carbonate content is greater than 50%, it is defined as carbonate-rich shale, and if the carbonate content and the content of other minerals do not exceed 50%, it is defined as mixed shale. Determine the value of the permeability correction coefficient a according to the combination type of sedimentary component 1 and sedimentary component 2 that make up the shale sedimentary structure, as shown in Table 1 below.

[0051] Table 1 Assignment table of correction parameter a

[0052]

[0053] As a preferred embodiment, determine the effective range of experimental data in step 5:

[0054] Calculate the shale permeability change rate Δ and the stress sensitivity coefficient S S :

[0055]

[0056] Where K n is the permeability measured at the nth pressure point (×10 -3 μm -2 ), K n-1 is the permeability measured at the (n - 1)th point (×10 -3 μm -2 ), and Δ is the permeability change rate between the nth and (n - 1)th points.

[0057]

[0058] Where P n , P0 are the effective stresses (MPa) corresponding to the nth pressure point and the initial pressure point respectively, K n and K0 are the permeabilities (×10 -3 μm -2 ) corresponding to the nth pressure point and the initial pressure point respectively, and S S is the stress sensitivity coefficient.

[0059] When the permeability K n at the nth pressure point is greater than 0.1×10 -3 μm -2 , the permeability parameters at the nth point and points after the nth point are invalid; when Δ n > 30%, the permeability parameters at the nth point and points after the nth point are invalid; when SS When it is greater than 0.7, the permeability effective coefficient b is 0, and in other cases b is 1.

[0060] As a preferred embodiment, the method for evaluating the natural seepage capacity is as follows: according to the measured results of permeability, use the power-exponential function to fit the pressure-permeability curve, determine the pressure-permeability (P-K) fitting formula, and combine the permeability correction parameter a and the permeability effective coefficient b to calculate the natural seepage coefficient F n :

[0061] F n = a * b * P n

[0062] Among them, F n is the natural seepage coefficient, a is the permeability correction coefficient, and b is the permeability effective coefficient.

[0063] Judge the natural seepage capacity of shale according to the evaluation index:

[0064] When the natural seepage coefficient Fn > 1×10 -2 , the natural seepage capacity of the reservoir is extremely strong;

[0065] 1×10 -3 <Fn ≤ 1×10 -2 , the natural seepage capacity of the reservoir is strong;

[0066] 1×10 -4 <Fn ≤ 1×10 -3 , the natural seepage capacity of the reservoir is relatively strong;

[0067] 1×10 -5 <Fn ≤ 1×10 -4 , the natural seepage capacity of the reservoir is medium;

[0068] 1×10 -6 <Fn ≤ 1×10 -5 , the natural seepage capacity of the reservoir is weak;

[0069] Fn ≤ 1×10 -6 , the natural seepage capacity of the reservoir is weak.

[0070] In order to enable those skilled in the art to more clearly understand the technical solution of the present invention, the technical solution of the present invention will be described in detail below with specific embodiments.

[0071] Example 1

[0072] Select the FY1, FY5, and FY19 shale samples from a certain well in the Shahejie Formation in the Jiyang Depression of the Bohai Bay Basin as the research objects:

[0073] Step 1: According to the requirements, a shale cylindrical sample with a diameter of 2.5 cm and a height of 3 cm was obtained by wire cutting on the core sample parallel to the bedding direction;

[0074] Step 2: The surface of the cylindrical sample was polished smooth with 80-mesh, 220-mesh, and 400-mesh sandpapers. After blowing off the surface dust, it was wiped clean with alcohol and placed in a confining pressure permeability measuring instrument. The temperature was raised to 60 °C, and after the temperature stabilized, the confining pressure permeability test was carried out. 3 MPa was selected as the initial pressure point, 35 MPa as the highest pressure point, and 19 MPa as the median pressure point for the permeability test under confining pressure conditions. Through repeated experiments, the highest pressure point for obtaining effective data was determined to be 6 MPa;

[0075] Step 3: Select the lowest initial test pressure of 3 MPa, the highest pressure point of 6 MPa, and a pressure point of 4 MPa, a total of 3 test pressure points, to conduct the confining pressure permeability test on the sample at 60 °C.

[0076] Step 4: The cylindrical sample after testing was cut perpendicular to the bedding. After cutting, the sample was observed under a thin section, the sedimentary structure characteristics were counted, and parallel samples were selected for XRD whole-rock mineral composition analysis. Combining the above data for lithofacies identification, the permeability correction coefficient a was assigned through lithofacies (Table 2);

[0077] Table 2 Lithofacies and correction parameter a of shale samples in Example 1

[0078]

[0079] Step 5: Determine the validity of the experimental data, calculate the shale permeability change rate Δ and the stress sensitivity coefficient S S , and assign values to the effective parameter b (Table 3). The calculation results show that the confining pressure permeability effective coefficient b of FY1 and FY19 samples is 1, while the permeability effective coefficient b of FY5 sample is 0 because the permeability change rate at the 4 MPa point is greater than 30% and the stress sensitivity coefficient is greater than 0.7%.

[0080] Table 3 Physical property parameter table of shale samples in Example 1

[0081]

[0082] Step 6: Analysis of natural seepage capacity. According to the measured results of permeability, the pressure-permeability curve was fitted using a power-law function to determine the pressure-permeability (P-K) fitting formula. Combining the permeability effective parameter a and the permeability correction parameter b, the seepage capacity under formation pressure was determined (Table 4).

[0083] Table 4 Natural seepage coefficient F of shale in Example 1 n and natural seepage capacity

[0084]

[0085] Example 2

[0086] Select the shale samples of F1-1, F1-4 and F1-10 in the Shahejie Formation of a well in the Jiyang Depression, Bohai Bay Basin as the research objects:

[0087] Step 1: According to the requirements, through wire cutting on the core sample parallel to the bedding direction, a shale cylindrical sample with a diameter of 2.5 cm and a height of 3 cm is obtained;

[0088] Step 2: Polish the surface of the cylindrical sample with 80-mesh, 220-mesh and 400-mesh sandpapers. After blowing off the surface dust, wipe it clean with alcohol and put it into the overburden permeability measuring instrument. Heat it up to 60 °C, and conduct the overburden permeability test after the temperature is stable. Select 3 MPa as the initial pressure point, 35 MPa as the highest pressure point, and 19 MPa as the median pressure point to conduct the permeability test under overburden conditions. Through repeated experiments, determine that the highest pressure point to obtain effective data is 6 MPa;

[0089] Step 3: Select the lowest initial test pressure of 3 MPa, the highest pressure point of 6 MPa and the pressure point of 4 MPa, a total of 3 test pressure points to conduct the overburden permeability test on the sample at 60 °C.

[0090] Step 4: Cut the cylindrical sample after testing perpendicular to the bedding. After cutting, observe the thin section of the sample, count the sedimentary structure characteristics and select parallel samples for XRD whole-rock mineral component analysis. Combine the above data for lithofacies identification, and assign the permeability correction coefficient a through lithofacies (Table 5);

[0091] Table 5 Lithofacies and correction parameter a of shale samples in Example 2

[0092]

[0093] Step 5: Determine the validity of the experimental data, calculate the shale permeability change rate Δ and the stress sensitivity coefficient S S , and assign values to the effective parameter b (Table 6). The calculation results show that the initial permeability of the F1-1 sample is greater than 0.1×10 -3 μm -2 , and the permeability change rate at 4 MPa is greater than 30%, and the stress sensitivity coefficient is greater than S S greater than 0.7. And the initial permeability of the F1-10 sample is greater than 0.1×10 -3 μm -2 , so it is determined that the permeability effective coefficient b of F1-1 and F1-10 is 0, and only the permeability effective coefficient of F1-4 is 1.

[0094] Table 6 Physical property parameter table of shale samples in Example 2

[0095]

[0096] Step 6: Natural seepage capacity analysis. According to the measured results of permeability, use the power-exponential function to fit the pressure-permeability curve, determine the pressure-permeability (P-K) fitting formula, and combine the effective parameter a of permeability and the permeability correction parameter b to determine the seepage capacity under formation pressure (Table 7).

[0097] Table 7 Shale natural seepage coefficient F in Example 2 n and natural seepage capacity

[0098]

[0099] Example 3

[0100] Select the shale samples of N5-2, N5-10, and N5-11 in the Shahejie Formation of a well in the Jiyang Depression, Bohai Bay Basin as the research objects:

[0101] Step 1: According to the requirements, use wire cutting on the core sample parallel to the bedding direction to obtain a shale cylindrical sample with a diameter of 2.5 cm and a height of 3 cm;

[0102] Step 2: Polish the surface of the cylindrical sample with 80-mesh, 220-mesh, and 400-mesh sandpapers. After blowing off the surface dust, wipe it clean with alcohol and put it into the confining pressure permeability measuring instrument. Heat it up to 60 °C, and after the temperature stabilizes, conduct the confining pressure permeability test. Select 3 MPa as the initial pressure point, 35 MPa as the highest pressure point, and 19 MPa as the median pressure point to conduct the permeability test under confining pressure conditions. Through repeated experiments, determine that the highest pressure point for obtaining effective data is 6 MPa;

[0103] Step 3: Select three test pressure points, namely the lowest initial test pressure of 3 MPa, the highest pressure point of 6 MPa, and the pressure point of 4 MPa, to conduct the confining pressure permeability test on the sample at 60 °C.

[0104] Step 4: Cut the tested cylindrical sample perpendicular to the bedding. After cutting, observe the thin section of the sample, count the sedimentary structure characteristics, select parallel samples for XRD whole-rock mineral composition analysis, and conduct lithofacies identification in combination with the above data. Assign the permeability correction coefficient a through lithofacies (Table 8);

[0105] Table 8 Lithofacies and correction parameter a of shale samples in Example 3

[0106]

[0107] Step 5: Determine the validity of the experimental data, and calculate the shale permeability change rate Δ and the stress sensitivity coefficient S S, and assign a value to the effective parameter b (Table 9). The calculation results show that the permeability effective coefficients of the N5-2, N5-10, and N5-11 samples are all 1.

[0108] Table 9 Physical property parameters of shale samples in Example 3

[0109]

[0110] Step 6: Natural seepage capacity analysis. According to the measured permeability results, use the power-exponential function to fit the pressure-permeability curve, determine the pressure-permeability (P-K) fitting formula, and combine the permeability effective parameter a and the permeability correction parameter b to determine the seepage capacity under the formation pressure (Table 10).

[0111] Table 10 Natural seepage coefficient Fn and natural seepage capacity of shale in Example 3

[0112]

[0113] The above embodiments are preferred embodiments of the present invention, but the embodiments of the present invention are not limited to the above embodiments. Any other changes, modifications, substitutions, combinations, and simplifications made without departing from the spirit and principle of the present invention shall be equivalent replacement methods and are all included in the protection scope of the present invention.

Claims

1. A method for evaluating the natural seepage capacity of a carbonate-rich shale reservoir, characterized in that, The method includes the following steps: shale sample preparation; obtaining effective test points and conducting confining pressure permeability tests on the samples; cutting the tested samples and conducting petrographic identification to determine the permeability correction coefficient a value through petrography; determining the effective range of permeability parameters and the permeability effective coefficient; determining the pressure-permeability fitting formula within the effective range of permeability parameters, and combining the permeability correction parameter and the permeability effective coefficient to obtain the natural seepage coefficient Fn; and evaluating the seepage capacity based on the obtained natural seepage coefficient.

2. The method according to claim 1, wherein The method for preparing shale samples is as follows: cutting on a rock or core sample at any angle according to requirements to obtain cylindrical samples.

3. The method according to claim 1, wherein The method for obtaining effective test points is as follows: after polishing the surface of the sample smoothly, conducting permeability tests under confining pressure by setting the initial pressure point, median pressure point, and maximum pressure point; and determining the maximum pressure point for obtaining effective data through repeated experiments. The specific method for conducting confining pressure permeability tests on the samples is as follows: selecting at least three pressure points within the obtained maximum pressure point range to conduct confining pressure permeability tests on the samples.

4. The method according to claim 1, wherein After cutting the tested samples, conducting thin section analysis and counting the sedimentary structure characteristics; meanwhile, selecting parallel samples for XRD whole-rock mineral component analysis, and conducting petrographic identification based on the obtained results; and determining the permeability correction coefficient a value according to the combination type of sedimentary component 1 and sedimentary component 2 that make up the shale sedimentary structure.

5. The method according to claim 4, characterized in that, Judging the sedimentary structure characteristics based on thin section observation, defining the single-layer sedimentary structure with a thickness less than 1 mm as laminated, the single-layer sedimentary structure with a thickness greater than 1 mm as layered, and the absence of layered sedimentary structure as massive; judging the shale mineral component characteristics through XRD whole-rock mineral analysis, defining the shale with a carbonate content greater than 50% as carbonate-rich shale type, and the shale with a carbonate content and other mineral contents both not exceeding 50% as mixed shale type.

6. The method according to claim 1, wherein The method for determining the effective range of permeability parameters is as follows: Obtain the change rate Δ of shale permeability at n pressure points within the effective pressure range n ; When the permeability K at the n pressure points n is greater than 0.1×10 -3 μm -2 , the permeability parameters at the nth point and subsequent points are invalid; When Δ n > 30%, the permeability parameters at the nth point and subsequent points are invalid; The method for determining the permeability effective coefficient is as follows: when the stress sensitivity coefficient > 0.7, the permeability effective coefficient b is 0; when the stress sensitivity coefficient ≤ 0.7, b is 1.

7. The method according to claim 6, characterized in that Shale permeability change rate Δ n is expressed by the following formula: Among them, K n is the measured permeability at the nth pressure point (×10 -3 μm -2 ), K n-1 is the measured permeability at the (n - 1)th point (×10 -3 μm -2 ), and Δ is the change rate of permeability between the nth and (n - 1)th points.

8. The method according to claim 6, wherein Stress sensitivity coefficient S S is expressed by the following formula: Among them, P n , P0 are the effective stresses corresponding to the n pressure point and the initial pressure point, respectively, in MPa, K n and K0 are the permeabilities corresponding to the n pressure point and the initial pressure point, respectively, in ×10 -3 μm -2 , S S is the stress sensitivity coefficient.

9. The method according to claim 1, characterized in that The specific method for evaluating the seepage capacity based on the obtained natural seepage coefficient is as follows: When the natural seepage coefficient Fn > 1×10 -2 , the natural seepage capacity of the reservoir is extremely strong; 1×10 -3 When <Fn ≤ 1×10 -2 , the natural seepage capacity of the reservoir is strong; 1×10 -4 When <Fn ≤ 1×10 -3 , the natural seepage capacity of the reservoir is relatively strong; 1×10 -5 When -5 < Fn ≤ 1×10 -4 the natural seepage capacity of the reservoir is medium; 1×10 -6 When <Fn ≤ 1×10 -5 , the natural seepage capacity of the reservoir is weak; Fn ≤ 1×10 -6 When this occurs, the natural seepage capacity of the reservoir is weak.

10. The method according to claim 1 or 9, characterized in that, The natural seepage coefficient Fn is expressed by the following formula: F n = a * b * P n Among them, F n is the natural seepage coefficient, a is the permeability correction coefficient, b is the effective permeability coefficient, and P n is the pressure.

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