A method for determining shale bedding fracture porosity and an oil and gas reservoir evaluation method

Abstract

The present invention provides a method for determining shale bedding fracture porosity and an oil and gas reservoir evaluation method. The method comprises: conducting a helium porosity test on a shale sample to obtain a total porosity value; conducting a low-temperature carbon dioxide adsorption experiment on the shale sample that has undergone the helium porosity test to obtain a matrix microporosity value; encapsulating the bedding plane of the shale sample that has undergone the low-temperature carbon dioxide adsorption experiment with epoxy resin, and conducting a directional mercury injection test perpendicular to the bedding plane to obtain a matrix macropore porosity value and a matrix fracture porosity value, where matrix macropores are matrix pores greater than or equal to a preset threshold; and subtracting the matrix micropore porosity value, the matrix macropore porosity value, and the matrix fracture porosity value from the obtained total porosity value to obtain a shale bedding fracture porosity value. The present invention clarifies the shale gas bedding fracture porosity, which helps evaluate shale gas exploration potential and predict favorable areas.

Description

Technical Field

[0001] The present invention belongs to the technical field of geological exploration, and in particular relates to a method for determining the porosity of shale bedding fractures and a method for evaluating oil and gas reservoirs. Background Art

[0002] Shale gas is a type of unconventional natural gas resource with typical self-generation and self-storage characteristics. The bedding in shale is lamellae-like bedding, or simply lamellae. Bedding fractures in shale are often called lamellation fractures, which are natural cracks distributed along the lamellae during the sedimentation and diagenesis of mudstone. Lamellation is actually the bedding of mudstone, and lamellation fractures are the specific manifestation of bedding fractures in shale. Lamellation is a sedimentary structure developed in mudstone under weak hydrodynamic conditions, formed by the directional arrangement of fine-grained minerals. Horizontal bedding with a thickness of less than 1 cm is usually called bedding or lamellae-like bedding. Lamellation has the habit of rock easily cracking into thin plates or flakes along parallel planes. Lamination planes are also mechanically weak planes in shale and are the planes in the rock most prone to fracture. Therefore, bedding fractures in shale are mainly distributed along these extremely thin horizontal beddings.

[0003] Bedding fractures are one of the main fracture types found in shale. In shale cores, bedding fractures are typically parallel or nearly parallel to the bedding plane, distributed intermittently, and are relatively small in size. Thin-section micrographs and scanning electron microscopy analysis show that bedding fractures in shale occur parallel or nearly parallel to the lamination interfaces. They are prominently developed in thin, densely laminar shale intervals, indicating that their development is closely related to the lamination. Bedding fractures are important reservoirs for free gas in shale. A higher degree of bedding fracture development promotes shale gas enrichment and high yields.

[0004] Porosity is a fundamental parameter for evaluating rock reservoir properties. Shale porosity can be divided into matrix porosity and microfracture porosity based on pore type. Microfractures can originate from both bedding and matrix. Currently, there are numerous methods for porosity testing, including gas injection porosimetry (GIP), water immersion porosimetry (WIP), and nuclear magnetic resonance (NMR). Summary of the Invention

[0005] In order to enrich the shale bedding fracture porosity testing method and apply it to more application scenarios, an embodiment of the present invention provides a shale bedding fracture porosity determination method, including:

[0006] Conduct helium porosity testing on shale samples to obtain total porosity values;

[0007] Conducting a low-temperature carbon dioxide adsorption experiment on the shale sample that has completed the helium porosity test to obtain a matrix micropore porosity value, wherein the matrix micropores are matrix pores that are smaller than a preset threshold value;

[0008] The bedding planes of the shale samples that have completed the low-temperature carbon dioxide adsorption experiment are encapsulated with epoxy resin, and directional mercury injection testing is carried out in the direction perpendicular to the bedding to obtain matrix macropore porosity values ​​and matrix fracture porosity values, wherein the matrix macropores are matrix pores greater than or equal to a preset threshold value;

[0009] The shale bedding fracture porosity value is obtained by subtracting the matrix micropore porosity value, matrix macropore porosity value, and matrix fracture porosity value from the obtained total porosity value.

[0010] Furthermore, helium porosity testing was performed on the shale samples to obtain the total porosity value, including:

[0011] The sample is placed in a gas porosimeter to remove air from the pores of the shale sample. Without applying confining pressure, helium gas at a preset pressure is applied to allow helium to enter the pores of the shale sample.

[0012] After the pressure in the pores of the shale sample reaches equilibrium, the total pore volume and total porosity are calculated using Boyle's law.

[0013] Furthermore, helium porosity testing is performed on shale samples to obtain the total porosity value, which also includes:

[0014] Before placing the sample into the gas porosimeter, the target shale is first cut using a waterless wire cutter to obtain a shale sample of the desired shape, and then the shale sample is dried.

[0015] Furthermore, the shale sample of desired shape is a cubic sample.

[0016] Furthermore, matrix pores larger than or equal to 2 nm are matrix macropores, and matrix pores smaller than 2 nm are matrix micropores.

[0017] Furthermore, a low-temperature carbon dioxide adsorption experiment was conducted on the shale samples that had completed the helium porosity test to obtain the matrix micropore porosity value, including:

[0018] The shale sample that has completed the helium porosity test is placed in a low-temperature adsorption tester and vacuumed to remove the helium remaining in the nanopores of the shale sample;

[0019] conducting a low-temperature carbon dioxide adsorption experiment and setting the carbon dioxide gas pressure so that carbon dioxide gas molecules enter the micropores of the shale sample;

[0020] The carbon dioxide adsorption capacity of the shale sample under different relative pressure conditions is obtained from the low-temperature carbon dioxide adsorption experiment. The matrix micropore volume is calculated based on the carbon dioxide adsorption capacity using the following formula:

[0021]

[0022] Among them, V sp is the matrix micropore volume, cm 3 ; V0 is the micropore filling adsorption capacity, cm 3 / g; M is the molar mass of carbon dioxide, g / mol; is the density of carbon dioxide gas under standard conditions, g / cm 3 ; V m is the standard molar volume of gas, L / mol; c is the unit conversion coefficient.

[0023] Furthermore, the micropore filling adsorption capacity is obtained by the following steps:

[0024] The relative pressure and the carbon dioxide adsorption amount are nonlinearly fitted using a preset formula using preset software to obtain the micropore filling adsorption capacity. The preset formula is as follows:

[0025]

[0026] Among them, V a is the amount of carbon dioxide adsorbed, cm 3 / g; R is the gas constant; T is the absolute temperature, K; p is the experimental pressure, MPa; p0 is the saturated vapor pressure of CO2 at 0℃, MPa; β is the characteristic constant; E0 is the adsorption characteristic energy.

[0027] Furthermore, the epoxy resin encapsulation of the bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption test includes:

[0028] The bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption test is wrapped with epoxy resin, wherein the upper and lower surfaces of the shale sample parallel to the bedding are not wrapped with epoxy resin;

[0029] The shale samples were dried until the epoxy resin on their surface was fully hardened.

[0030] Furthermore, the directional mercury injection test in the direction perpendicular to the bedding to obtain the matrix macropore porosity value and the matrix fracture porosity value includes:

[0031] Place the shale sample with the epoxy resin on the surface fully hardened into a high-pressure mercury intrusion instrument and conduct a mercury intrusion porosimetry test according to preset parameters;

[0032] After the mercury injection test, the sum of the matrix macropore porosity and matrix fracture porosity of the shale sample can be calculated based on the mercury injection volume;

[0033] On the other hand, the present invention also discloses an oil and gas reservoir evaluation method, which uses the above-mentioned shale bedding fracture porosity determination method to determine rock storage space, fluid saturation and geological reserve calculation.

[0034] Based on the above technical solution, the present invention has the following beneficial effects compared with the prior art:

[0035] The present invention establishes a shale bedding fracture porosity interpretation model. The inventors discovered that the total porosity value is equal to the sum of the matrix micropore porosity value, the matrix macropore porosity value, the matrix fracture porosity value, and the shale bedding fracture porosity value. A shale bedding fracture porosity determination method proposed in an embodiment of the present invention can measure multiple shale samples at the same layer. The shale bedding fracture porosity is obtained by subtracting the matrix micropore porosity value, the matrix macropore porosity value, and the matrix fracture porosity value from the obtained total porosity value. This helps to identify shale gas enrichment areas and effectively improve shale gas production capacity. Clarifying the bedding fracture porosity of different regions in a shale gas reservoir helps to evaluate the shale gas exploration potential and predict favorable shale gas areas. The obtained bedding fracture porosity helps to determine rock storage space, fluid saturation, and geological reserve calculations. BRIEF DESCRIPTION OF THE DRAWINGS

[0036] In order to more clearly illustrate the specific embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the specific embodiments or the description of the prior art. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0037] Figure 1 A schematic flow chart of a method for determining shale bedding fracture porosity provided in an embodiment of the present invention;

[0038] Figure 2 Schematic diagram of the process of step S110 in an embodiment of the present invention;

[0039] Figure 3 This is a diagram showing the effect of cutting a shale sample provided by an embodiment of the present invention;

[0040] Figure 4 Schematic diagram of the process of step S120 in an embodiment of the present invention;

[0041] Figure 5 A graph showing the amount of carbon dioxide adsorbed under different relative pressure conditions provided by an embodiment of the present invention;

[0042] Figure 6A schematic diagram of a process for epoxy resin encapsulation of the bedding surface of a shale sample that has completed a low-temperature carbon dioxide adsorption test provided in an embodiment of the present invention;

[0043] Figure 7 Schematic diagram of epoxy resin coating on the surface of a shale sample provided in an embodiment of the present invention;

[0044] Figure 8 This is a schematic diagram of a process for performing directional mercury injection testing perpendicular to the bedding direction to obtain matrix macropore porosity values ​​and matrix fracture porosity values, as provided in an embodiment of the present invention;

[0045] Figure 9 This is a mercury injection experiment curve provided by an embodiment of the present invention. DETAILED DESCRIPTION

[0046] In order to better understand the above technical solution, the above technical solution will be described in detail below with reference to the accompanying drawings and specific implementation methods.

[0047] The inventors found that the existing porosity testing method can only obtain the total porosity value of shale, and cannot effectively distinguish the bedding fracture porosity and matrix porosity of shale. It is impossible to clearly determine the bedding fracture porosity and its proportion in shale, which is not conducive to the calculation of rock storage space, fluid saturation and geological reserves. Therefore, the inventors made the present invention after further research and development.

[0048] Specifically, the inventors divided shale reservoir space into two categories: matrix pores and microfractures. Based on the above reservoir space division method, the inventors established a shale total porosity composition model. The total pore volume consists of three parts and can be expressed as:

[0049] V tp =V mp +V mf +V 1f (1)

[0050] Due to the differences in pore scales in different experimental tests, the inventors further divided the matrix pores into micropores smaller than 2 nm and matrix pores larger than 2 nm. Therefore, the total pore volume can be expressed as:

[0051] V tp =V sp +V bp +V mf +V 1f (2)

[0052] The porosity of shale is the ratio of the pore volume to the volume of the rock itself. Formula (2) can be rewritten as:

[0053]

[0054] Among them, V tp is the total pore volume, cm 3 ; V mp is the matrix pore volume, cm 3 ; V sp is the volume of micropores in the mineral matrix, cm 3 ; V bp is the macropore volume of the mineral matrix, cm 3 ; V mf is the matrix pore volume, cm 3 ; V lf is the pore volume of bedding fractures, cm 3 ; is the total porosity of shale, %; is the microporosity of the mineral matrix, %; is the macropore porosity of the mineral matrix, %; is the matrix slit porosity, %; is the bedding fracture porosity, %.

[0055] According to the above theoretical deduction, if the total porosity value, matrix micropore porosity value, matrix macropore porosity value, and matrix fracture porosity value can be obtained, the shale bedding fracture porosity can be calculated, which helps to clarify the shale gas enrichment area and effectively improve the shale gas production capacity.

[0056] In order to better understand the above technical solution, the above technical solution will be described in detail below with reference to the accompanying drawings and specific implementation methods.

[0057] This embodiment provides a method for determining the porosity of shale bedding fractures. Figure 1 As shown, it includes steps S110 to S140, specifically:

[0058] Step S110: Perform a helium porosity test on the shale sample to obtain a total porosity value.

[0059] In one embodiment, step S110 includes step S111 and step S112. Figure 2 As shown:

[0060] In step S111, the sample is placed in a gas porosimeter to remove air from the pores of the shale sample. Without applying confining pressure, helium gas of a preset pressure is applied to allow the helium gas to enter the pores of the shale sample.

[0061] Specifically, a shale sample from a bedding-rich section is taken. The bedding distribution should be clearly visible on the surface of the shale sample. The shale sample taken is a full-diameter sample, with a diameter of 10 cm and a length of 5 cm.

[0062] The shale sample was cut using a waterless wire cutter. The sample shape required for cutting was a cube. The length, width and height of the cube sample were all 2 cm. The sample cutting effect was as follows: Figure 3 As shown, the sample shape used in general experiments is cylindrical. In order to use the sample for the subsequent directional mercury injection experiment, the present invention preferably uses a cubic sample.

[0063] After drying the cubic shale sample, place it in a gas porosimeter, and then vacuum to remove the air in the pores of the shale sample. Generally, the vacuuming time is 2 hours. Without applying confining pressure, a certain pressure of helium is applied to allow it to enter the pores of the shale sample.

[0064] Generally speaking, a gas porosity meter can test samples under both confining pressure and no confining pressure. Under confining pressure, the sample is affected by external pressure and the pores are compressed. The porosity obtained by measurement is not the total porosity, while the porosity obtained without confining pressure is the total porosity value. The total porosity value is required in the present invention, so it is necessary to apply a certain pressure of helium to allow it to enter the pores of the shale sample without confining pressure.

[0065] Step S112: After the pressure in the pores of the shale sample reaches equilibrium, the total pore volume and total porosity are calculated using Boyle's law.

[0066] Specifically, while waiting for the pressure in the pores of the shale sample to reach equilibrium, it is necessary to set the equilibrium condition. Generally, the equilibrium condition is set to a pressure change of less than 1 psi within 10 minutes. After setting the equilibrium condition, the porosimeter equipment will automatically determine whether the pressure in the shale sample has reached equilibrium.

[0067] The porosity analyzer system analysis software can be used to calculate the pore volume based on Boyle's law. Under a set initial gas pressure, helium is isothermally expanded into the core chamber, and the gas continuously diffuses into the pores inside the core. The pressure change characteristics, the core chamber volume, and the gas state equation can be used to calculate the pore volume.

[0068] In one embodiment, the gas pressure is set to 600 psi and the equilibrium time is 1 hour. After the pressure reaches equilibrium, the total pore volume V is calculated using Boyle's law. tp 0.51cm 3 , total porosity It is 6.37%.

[0069] Specifically, shale pores smaller than 2 nm are generally classified as small pores, shale pores between 2 nm and 50 nm are classified as medium pores, and pores larger than 50 nm are classified as large pores. In the present invention, matrix pores larger than or equal to 2 nm are classified as matrix macropores, and matrix pores smaller than 2 nm are classified as matrix micropores.

[0070] Step S120 , performing a low-temperature carbon dioxide adsorption experiment on the shale sample that has completed the helium porosity test to obtain a matrix micropore porosity value, wherein the matrix micropores are matrix pores that are smaller than a preset threshold.

[0071] In one embodiment, step S120 includes steps S121 to S123. Figure 4 As shown:

[0072] In step S121 , the shale sample that has completed the helium porosity test is placed in a low-temperature adsorption tester for vacuum treatment to remove the helium remaining in the nanopores of the shale sample.

[0073] Specifically, during the process of vacuuming to remove helium remaining in the nanopores of the shale sample, the vacuuming time is generally set to 2 hours.

[0074] Step S122 , conducting a low-temperature carbon dioxide adsorption experiment, and setting the carbon dioxide pressure so that carbon dioxide gas molecules enter the micropores of the shale sample.

[0075] Specifically, when conducting a low-temperature carbon dioxide adsorption experiment, it is necessary to set the temperature and the carbon dioxide pressure. Generally, the experimental temperature is set to 0°C, and the maximum carbon dioxide pressure is set to 1 atmosphere.

[0076] Step S123: The carbon dioxide adsorption volume of the shale sample under different relative pressure conditions is obtained according to the low-temperature carbon dioxide adsorption experiment, and the matrix micropore volume is obtained according to the carbon dioxide adsorption volume using the following formula:

[0077]

[0078] Among them, V sp is the matrix micropore volume, cm 3 ; V0 is the micropore filling adsorption capacity, cm 3 / g; M is the molar mass of carbon dioxide, g / mol; Under normal circumstances, the molar mass of carbon dioxide is 44g / mol; is the density of carbon dioxide gas under standard conditions, g / cm 3 ; Normally, the density of carbon dioxide gas under standard conditions is 1.072g / cm 3 ; V m is the standard molar volume of gas, L / mol; usually, the standard molar volume of gas is 22.4 L / mol; c is the unit conversion factor, usually 1000.

[0079] Specifically, the micropore filling adsorption capacity is obtained by the following steps:

[0080] The relative pressure and the carbon dioxide adsorption amount are nonlinearly fitted using a preset formula using preset software (such as Origin data processing software) to obtain the micropore filling adsorption capacity. The preset formula is as follows:

[0081]

[0082] Among them, V a is the amount of carbon dioxide adsorbed in the experiment, cm 3 / g; R is the gas constant, usually 8.314 J / mol / K; T is the absolute temperature, K; p is the experimental pressure, MPa; p0 is the saturated vapor pressure of CO2 at 0°C, usually 3.48 MPa; β is the characteristic constant; E0 is the adsorption characteristic energy.

[0083] In a specific embodiment, the amount of carbon dioxide adsorbed under different relative pressure conditions is measured, such as Figure 5 As shown in the above method, the micropore filling adsorption capacity V0 = 1.42738 cm 3 / g, further, the matrix micropore volume V can be obtained sp =1.42738×0.0018323×8×2.6=0.0544cm 3 , so the matrix micropore porosity is

[0084] Step S130 , encapsulating the bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption experiment with epoxy resin, and conducting a directional mercury injection test perpendicular to the bedding direction to obtain the matrix macropore porosity value and the matrix fracture porosity value, wherein the matrix macropore porosity is the matrix pore that is greater than or equal to a preset threshold.

[0085] Specifically, the bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption test is encapsulated with epoxy resin, including steps S131 and S132, such as Figure 6 As shown:

[0086] Step S131 , using epoxy resin to wrap the bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption test, wherein the upper and lower surfaces of the shale sample parallel to the bedding are not wrapped with epoxy resin.

[0087] Specifically, such as Figure 7 As shown in the figure, when coating the surface of shale samples with epoxy resin, attention should be paid to the uniformity, sealing and one-time nature of the coating. That is, the coating epoxy resin should be of uniform thickness, completely sealed and formed in one time, and should not be coated twice. In particular, attention should be paid to the problem of easy voids at the corners.

[0088] Step S132: Dry the shale sample until the epoxy resin on the surface is fully hardened.

[0089] Specifically, during the process of drying the shale sample until the epoxy resin on the surface thereof is fully hardened, the hardening treatment condition is drying at a temperature of 60° C. for 24 hours.

[0090] Specifically, a directional mercury injection test is carried out in the vertical bedding direction to obtain the matrix macropore porosity value and the matrix fracture porosity value, including steps S133 and S134, such as Figure 8 As shown:

[0091] In step S133 , the shale sample with the epoxy resin on the surface fully hardened is placed in a high-pressure mercury intrusion instrument, and a mercury intrusion porosimetry test is performed according to preset parameters.

[0092] Specifically, the upper and lower surfaces of the shale sample cube parallel to the bedding are not wrapped with epoxy resin, which can be used as pre-mercury injection surfaces. After the sample is placed in a high-pressure mercury injection instrument, a mercury injection porosimetry test is carried out. The maximum mercury injection pressure is set to 400 MPa, the number of pressure points is set to 30, and the equilibrium time is set to 2 hours.

[0093] Step S134: After the mercury injection test is completed, the sum of the matrix macropore porosity and the matrix fracture porosity of the shale sample can be calculated based on the mercury injection volume.

[0094] In a specific embodiment, the mercury injection test curve is as follows Figure 9 As shown, because the mercury injection direction is perpendicular to the shale bedding plane, the pore volume obtained from the mercury injection test does not include the bedding fracture volume, ignoring the possibility of mercury molecules crossing the bedding interface. Furthermore, due to their large size, mercury molecules are unable to enter micropores smaller than 2 nm even under high experimental pressures. Therefore, the sum of the matrix macropore volume and matrix fracture pore volume in the shale sample obtained from this directional high-pressure mercury injection test is 4.64%.

[0095] Step S140 , subtracting the matrix micropore porosity value, the matrix macropore porosity value, and the matrix fracture porosity value from the acquired total porosity value to obtain the shale bedding fracture porosity.

[0096] In a specific embodiment, when the total porosity, matrix micropore porosity, matrix macropore porosity and microfracture porosity of the shale sample are determined, the shale bedding fracture porosity can be calculated:

[0097]

[0098] in, is the total porosity of shale, %; is the microporosity of the mineral matrix, %; is the macropore porosity of the mineral matrix, %; is the matrix slit porosity, %; is the bedding fracture porosity, %.

[0099] The above-mentioned method for determining the porosity of shale bedding fractures can be used to determine the rock reservoir space, fluid saturation, and geological reserves.

[0100] The present invention establishes a shale bedding fracture porosity interpretation model, where the total porosity value is equal to the sum of the matrix micropore porosity value, the matrix macropore porosity value, the matrix fracture porosity value, and the shale bedding fracture porosity value. A shale bedding fracture porosity determination method proposed in an embodiment of the present invention can measure multiple shale samples at the same layer. The shale bedding fracture porosity is obtained by subtracting the matrix micropore porosity value, the matrix macropore porosity value, and the matrix fracture porosity value from the obtained total porosity value. This helps to identify shale gas enrichment areas and effectively improve shale gas production capacity. Clarifying the bedding fracture porosity of different regions in a shale gas reservoir is beneficial for evaluating shale gas exploration potential and predicting favorable shale gas areas. The obtained bedding fracture porosity helps to determine rock storage space, fluid saturation, and geological reserve calculations.

[0101] In the foregoing detailed description, various features are grouped together in a single embodiment to simplify the disclosure. This method of disclosure should not be interpreted as reflecting an intention that embodiments of the claimed subject matter require more features than are expressly recited in each claim. On the contrary, as reflected in the appended claims, the invention comprises less than all the features of any individual disclosed embodiment. The appended claims are therefore hereby expressly incorporated into the detailed description, with each claim standing on its own as a separate preferred embodiment of the invention.

[0102] The foregoing description includes examples of one or more embodiments. Of course, it is not possible to describe all possible combinations of components or methods for the purposes of describing the above embodiments, but it will be appreciated by those skilled in the art that the various embodiments may be further combined and arranged. Therefore, the embodiments described herein are intended to encompass all such changes, modifications and variations that fall within the scope of the appended claims. Furthermore, to the extent that the term "comprising" is used in the specification or claims, the term is intended to be encompassed in a manner similar to the term "including," as explained by "including," when used as a transitional word in the claims. Furthermore, any use of the term "or" in the specification of the claims is intended to mean a "non-exclusive or."

Claims

1. A method for determining shale bedding fracture porosity, characterized in that: The following steps are involved: Conduct helium porosity testing on shale samples to obtain total porosity values; Conducting a low-temperature carbon dioxide adsorption experiment on the shale sample that has completed the helium porosity test to obtain a matrix micropore porosity value, wherein the matrix micropores are matrix pores that are smaller than a preset threshold value; The bedding planes of the shale samples that have completed the low-temperature carbon dioxide adsorption experiment are encapsulated with epoxy resin, and directional mercury injection testing is carried out in the direction perpendicular to the bedding to obtain matrix macropore porosity values ​​and matrix fracture porosity values, wherein the matrix macropores are matrix pores greater than or equal to a preset threshold value; The shale bedding fracture porosity value is obtained by subtracting the matrix micropore porosity value, matrix macropore porosity value, and matrix fracture porosity value from the obtained total porosity value.

2. The method according to claim 1, wherein The helium porosity test is performed on the shale sample to obtain the total porosity value, including: The sample is placed in a gas porosimeter to remove air from the pores of the shale sample. Without applying confining pressure, helium gas at a preset pressure is applied to allow helium to enter the pores of the shale sample. After the pressure in the pores of the shale sample reaches equilibrium, the total pore volume and total porosity are calculated using Boyle's law.

3. The method according to claim 1, wherein The helium porosity test on the shale sample to obtain the total porosity value also includes: Before placing the sample into the gas porosimeter, the target shale is first cut using a waterless wire cutter to obtain a shale sample of the desired shape, and then the shale sample is dried.

4. The method according to claim 3, wherein The shale sample of desired shape is a cubic sample.

5. The method according to claim 1, wherein The matrix pore size of the preset threshold is 2 nm.

6. The method according to claim 1, wherein The low-temperature carbon dioxide adsorption experiment is performed on the shale sample that has completed the helium porosity test to obtain the matrix micropore porosity value, including: The shale sample that has completed the helium porosity test is placed in a low-temperature adsorption tester and vacuumed to remove the helium remaining in the nanopores of the shale sample; conducting a low-temperature carbon dioxide adsorption experiment and setting the carbon dioxide gas pressure so that carbon dioxide gas molecules enter the micropores of the shale sample; The carbon dioxide adsorption capacity of the shale sample under different relative pressure conditions is obtained from the low-temperature carbon dioxide adsorption experiment. The matrix micropore volume is calculated based on the carbon dioxide adsorption capacity using the following formula: Among them, V sp is the matrix micropore volume, cm 3 ; V0 is the micropore filling adsorption capacity, cm 3 / g; M is the molar mass of carbon dioxide, g / mol; is the density of carbon dioxide gas under standard conditions, g / cm 3 ; V m is the standard molar volume of gas, L / mol; c is the unit conversion coefficient.

7. The method according to claim 6, wherein The micropore filling adsorption capacity is obtained by the following steps: The relative pressure and the carbon dioxide adsorption amount are nonlinearly fitted using a preset formula using preset software to obtain the micropore filling adsorption capacity. The preset formula is as follows: Among them, V a is the amount of carbon dioxide adsorbed, cm 3 / g; R is the gas constant; T is the absolute temperature, K; p is the experimental pressure, MPa; p0 is the saturated vapor pressure of CO2 at 0℃, MPa; β is the characteristic constant; E0 is the adsorption characteristic energy.

8. The method according to claim 4, wherein The epoxy resin encapsulation of the bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption test comprises: The bedding surface of the shale sample that has completed the low-temperature carbon dioxide adsorption test is wrapped with epoxy resin, wherein the upper and lower surfaces of the shale sample parallel to the bedding are not wrapped with epoxy resin; The shale samples were dried until the epoxy resin on their surface was fully hardened.

9. The method according to claim 1, wherein The directional mercury injection test conducted in the direction perpendicular to the bedding to obtain the matrix macropore porosity value and matrix fracture porosity value includes: Place the shale sample with the epoxy resin on the surface fully hardened into a high-pressure mercury intrusion instrument and conduct a mercury intrusion porosimetry test according to preset parameters; After the mercury injection test, the sum of the matrix macropore porosity and matrix fracture porosity of the shale sample can be calculated based on the mercury injection volume.

10. A method for evaluating an oil and gas reservoir, characterized in that: The method comprises the shale bedding fracture porosity determination method according to any one of claims 1 to 9.

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