Method for characterizing shale oil reservoir space, method for constructing chart, and method for measuring

Abstract

The application discloses a shale oil reservoir space characterization method, a chart construction method and a measurement method. The characterization method comprises the following steps: performing linear cutting treatment on a shale sample to obtain a regular-shaped plunger sample; performing helium injection measurement on the regular-shaped plunger sample to determine effective porosity of the shale sample; performing nuclear magnetic porosity measurement on the plunger sample to determine total porosity of the shale sample; and characterizing shale oil reservoir space of the shale sample based on the effective porosity and the total porosity of the shale sample. The method optimizes a pretreatment step by performing linear cutting treatment on the shale sample, avoids the influence of residual oil in the sample on a test process and a result on the premise of ensuring the accuracy of experimental results, and further establishes a comprehensive characterization mode of the shale oil reservoir space based on helium injection measurement and nuclear magnetic resonance measurement.

Description

Technical Field

[0001] This invention relates to the field of petroleum exploration technology, and in particular to a method for characterizing shale oil reservoir space, a method for constructing maps, and a method for measuring it. Background Technology

[0002] Global shale oil resources are abundant, and the rapid development of unconventional oil and gas resources has shifted oil and gas exploration from primarily "external" to "internal" scale exploration and development. Porosity is one of the key parameters for oil and gas resource evaluation, playing a crucial role in determining the reservoir space, fluid saturation, and geological reserves of rocks. Shale porosity can be classified into open and closed pores based on their connectivity. Open pores are commonly characterized by effective porosity, which is an important parameter for proven reservoir reserves; total porosity is the basic parameter for calculating geological reserves, consisting of both connected open and closed pores. In actual production processes, helium, nitrogen, and other fluids are often used to inject plunger samples for porosity evaluation. However, measured porosity only reflects the characteristics of connected pores and ignores the non-connected pores in shale. Effective development of shale oil resources must rely on large-scale hydraulic fracturing technology. After fracturing, non-connected pores may be opened; furthermore, the self-absorption of water by the shale after fracturing generates numerous micro-fractures, greatly increasing the chance of connecting non-connected pores and making them exploitable.

[0003] Furthermore, the extremely low permeability and complex mineral composition of shale, especially the characteristics of micro- and nano-pores and foliation fractures, coupled with the differences in pore types characterized by different testing methods, and the different understandings of testing methods by different laboratories and the poor repeatability of test results, make it difficult to accurately characterize the porosity of shale.

[0004] Helium porosity and saturated liquid methods are selected for plunger sample testing. The porosity measured is typically the effective porosity of interconnected samples. Helium molecules have small diameters, stable chemical composition and density, and weak adsorption, making them an ideal medium for helium injection measurements. The helium injection method indirectly determines the effective porosity of shale plunger samples by filling the pores of the sample at a known pressure and measuring the pressure change. However, before using the helium injection method, pretreatment such as washing and drying under specified drying temperature and humidity conditions is required to calculate the apparent volume. However, for samples with different clay contents, the drying environment and drying time are difficult to control, and over-drying can lead to significant deviations in the measurement results. The saturated liquid method includes the WIP method (deionized water as the medium), KIP method (kerosene as the medium), and DLP method (water-kerosene). For low-porosity and low-permeability shale reservoir samples, the mineral composition and pore wettability are complex and diverse, especially when containing a large amount of easily expansive clay minerals. Furthermore, when the diameter of the liquid molecules is larger than the pore throat diameter, the liquid cannot fully fill the pore medium, leading to significant deviations in the measurement results. Meanwhile, if kerosene-saturated samples are used for saturation, cleaning with organic solvents is required after the test, which can affect the pore structure of the rock and thus the accuracy of subsequent experimental results. Plunger sample mercury intrusion testing can also characterize the effective porosity of shale, but it mostly only reflects information about macropores (>50 nm): ordinary mercury intrusion (30 MPa) reflects a theoretical lower limit of effective porosity of approximately 24.5 nm, high-pressure mercury intrusion (413 MPa) can reach 1.8 nm, and constant-rate mercury intrusion (approximately 6 MPa) can simultaneously reflect porosity and throat information. Given the low porosity and low permeability of shale, high displacement pressure is required to induce mercury intrusion into the sample, but this process easily generates artificial fractures and the overall mercury removal efficiency of shale is low, making the experiment destructive and rendering the tested samples unusable for other tests.

[0005] In addition, North America has proposed using pulverized samples for total porosity determination. The GRI (Gas Research Institute) method measures the total porosity of shale, which also uses helium injection, but requires pulverizing the rock. Although this reduces the gas injection pressure during measurement, increases the contact area between the gas and rock pores, and shortens the test time, the degree of pulverization affects the range of released pores and alters the original water saturation or water absorption of the core, causing changes in the core density and leading to differences in measurement results. The CO2 / N2 adsorption method can quantitatively characterize powdered samples, but it mainly reflects the pore size distribution of shale in the micropore (<2nm) and mesopore (2-50nm) range, which is mainly controlled by the relationship between molecular diameter and pore diameter. However, the gas adsorption effect of shale pores is difficult to quantify.

[0006] Nuclear magnetic resonance (NMR) can obtain information on the effective porosity, total porosity, pore size distribution, pore connectivity, and mobile fluids of shale without damaging the sample. However, it is affected by many factors, including the testing environment, instrument parameters, sample micropores, paramagnetic materials, and fluid type. Furthermore, the porosity, permeability, and pore size in shale are typically smaller than those in conventional reservoirs, resulting in a low signal-to-noise ratio in NMR experiments and longer data acquisition times. Nanoscale pores have very short relaxation times, potentially falling below the instrument's detection limit and becoming undetectable. Additionally, the presence of numerous organic matter pores in shale makes water and organic matter in the pores homonuclear and difficult to distinguish, increasing the difficulty of data interpretation.

[0007] In addition, imaging methods such as optical microscopy, scanning electron microscopy, FIB-SEM, and micro-nano CT can be used for qualitative analysis of shale reservoirs. Combined with statistical methods, quantitative information such as shale porosity and pore size distribution can be obtained. However, the reliability and accuracy of imaging analysis are limited by factors such as the influence of sample characteristics on image quality and instrument resolution. Furthermore, whether the sample pretreatment correctly preserves the original information and whether the micro-area analysis is sufficiently representative are also important issues. Summary of the Invention

[0008] To accurately establish a characterization system for shale oil reservoir space, avoid the influence of permeability and complex mineral composition, and solve the defects of harsh drying conditions, low efficiency of high-pressure pumps, and easy sample damage when measuring apparent volume, thereby enriching technical routes and increasing the selection space, this invention provides a characterization method, a chart construction method, and a measurement method for shale oil reservoir space.

[0009] In a first aspect, embodiments of the present invention provide a method for characterizing shale oil reservoir space, which may include:

[0010] The shale samples were wire-cut to obtain plunger samples with regular shapes;

[0011] Helium injection measurements were performed on regularly shaped plunger samples to determine the effective porosity of the shale samples;

[0012] The plunger sample was subjected to nuclear magnetic resonance porosity measurement to determine the total porosity of the shale sample;

[0013] Based on the effective porosity and total porosity of the shale sample, the shale oil reservoir space of the shale sample is characterized.

[0014] Optionally, performing nuclear magnetic resonance porosity measurement on the plunger sample to determine the total porosity of the shale sample may include:

[0015] The total porosity of the shale sample was determined by performing two-dimensional nuclear magnetic resonance porosity measurements under ambient temperature, drying, saturated water, and centrifugation conditions.

[0016] The drying conditions are as follows: drying at 70°C for no less than 48 hours;

[0017] The saturated water condition is 15 MPa saturated water for no less than 15 hours.

[0018] Optionally, the nuclear magnetic resonance porosity measurement uses the SR-CPMG sequence, with a TE echo time of 0.06 ms, a NECH value of 18000, an NTI value of 31, an end time of 3000 ms, and NS repeated scans 32 times.

[0019] Optionally, the step of performing helium injection measurements on regularly shaped plunger samples to determine the effective porosity of the shale samples may include:

[0020] Helium injection measurements were performed on the regularly shaped plunger sample using an injection pressure of 100 psi, and pressure monitoring was performed using a high-precision pressure sensor to determine the effective porosity of the shale sample.

[0021] Optionally, determining the effective porosity of the shale sample may include:

[0022] The effective porosity and pressure of the shale sample over a preset time period were obtained.

[0023] Based on the power function approximation method, the effective porosity of the shale sample is determined by fitting the pre-established correlation between porosity and time using the effective porosity change over time and the pressure change over time.

[0024] Optionally, the ambient temperature for conducting helium injection measurements on the regularly shaped plunger sample is 24±0.5℃.

[0025] Optionally, before performing helium injection measurements on regularly shaped plunger samples, the following may also be included:

[0026] The apparent volume of a regularly shaped plunger sample was determined using an electronic vernier caliper measurement method.

[0027] Optionally, the method may further include: performing electron microscopy and nano-CT scanning on the plunger sample to determine the crack porosity of the plunger sample.

[0028] Secondly, embodiments of the present invention provide a method for constructing a shale porosity identification chart, which may include:

[0029] Different types of shale samples were obtained, and the organic matter abundance of the different types of shale samples was measured;

[0030] The effective porosity and total porosity of the shale samples of different types are measured, wherein the effective porosity and total porosity of the shale samples are measured according to the characterization method of shale oil reservoir space described in the first aspect;

[0031] Based on the organic matter abundance, effective porosity, and total porosity of different types of shale samples, a shale porosity identification chart was constructed.

[0032] Thirdly, embodiments of the present invention provide a rapid method for measuring the effective porosity of shale, which may include:

[0033] The organic matter abundance of shale samples from the study block was measured.

[0034] Based on a pre-constructed shale porosity identification chart and the organic matter abundance, the effective porosity and measurement equilibrium time of the shale sample are quickly determined.

[0035] The shale porosity identification chart is pre-constructed according to the shale porosity identification chart construction method described in the second aspect.

[0036] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0037] This invention provides a method for characterizing shale oil reservoir space, a method for constructing maps, and a method for measurement. This characterization method optimizes the pretreatment steps by performing wire cutting on shale samples. While ensuring the accuracy of experimental results, it avoids the influence of residual oil in the sample on the testing process and results. Based on this, the effective porosity and total porosity of the shale sample are determined by helium injection measurement and nuclear magnetic resonance measurement, thereby establishing a comprehensive characterization method for shale oil reservoir space, laying the foundation for actual production and resource evaluation.

[0038] Other features and advantages of the invention will be set forth in the following description, 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 particularly pointed out in the written description and the accompanying drawings.

[0039] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0040] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0041] Figure 1 This is a flowchart of the shale oil reservoir characterization method provided in Embodiment 1 of the present invention;

[0042] Figure 2 This is a flowchart of a detailed method for characterizing shale oil reservoir space provided in Embodiment 1 of the present invention;

[0043] Figure 3 The image shown is a CT scan of sample S-1 provided in Embodiment 1 of the present invention.

[0044] Figure 4 The image shown is a CT scan of sample S-2 provided in Embodiment 1 of the present invention.

[0045] Figure 5 This is a schematic diagram of the helium (effective) porosity measurement results of the S-1 sample provided in Embodiment 1 of the present invention;

[0046] Figure 6 This is a schematic diagram of the helium (effective) porosity measurement results of the S-2 sample provided in Embodiment 1 of the present invention;

[0047] Figure 7 This is a schematic diagram of the closed porosity measurement results of sample S-1 provided in Embodiment 1 of the present invention;

[0048] Figure 8 This is a schematic diagram of the closed porosity measurement results of sample S-2 provided in Embodiment 1 of the present invention;

[0049] Figure 9 This is a flowchart of the method for constructing the shale porosity identification chart provided in Embodiment 2 of the present invention;

[0050] Figure 10 This is one example of a shale porosity identification chart provided in Embodiment 2 of the present invention;

[0051] Figure 11 This is a second example of a shale porosity identification chart provided in Embodiment 2 of the present invention. Detailed Implementation

[0052] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0053] In practical work, the inventors discovered that single porosity testing methods all have limitations and are difficult to accurately characterize the actual reservoir space of shale. It is necessary to comprehensively analyze and compare multiple testing methods to establish a systematic shale oil reservoir space characterization system. This system should meet the needs of large-scale sample testing in industrial production, effectively address the anisotropy of mudstone and shale, improve the systematicity and representativeness of test samples, and, combined with porosity oil-bearing properties research, comprehensively characterize the pore and fracture structure of shale oil reservoirs at multiple scales. Therefore, this invention provides a method for characterizing shale oil reservoir space, a chart construction method, and a measurement method.

[0054] Example 1

[0055] Embodiment 1 of the present invention provides a method for characterizing shale oil reservoir space, referring to... Figure 1 As shown, the method may include the following steps:

[0056] Step S11: Perform wire cutting on the shale sample to obtain a plunger sample with a regular shape.

[0057] This step pre-treats the shale samples using wire cutting, laying the foundation for determining the sample's apparent volume. The apparent volume is no longer calculated through drying; that is, oil washing and drying are no longer performed, and the internal structure of the sample is not altered. This step also avoids using liquid chromatography for apparent volume detection, thus preventing larger errors in measuring the expansion volume of clay minerals.

[0058] Step S12: Perform helium gas injection measurements on the regularly shaped plunger sample to determine the effective porosity of the shale sample.

[0059] Step S13: Perform nuclear magnetic resonance porosity measurement on the plunger sample to determine the total porosity of the shale sample.

[0060] Step S14: Based on the effective porosity and total porosity of the shale sample, characterize the shale oil reservoir space of the shale sample.

[0061] The shale oil reservoir characterization method provided in this embodiment of the invention optimizes the pretreatment steps by performing wire cutting on shale samples. While ensuring the accuracy of experimental results, it avoids the influence of residual oil in the sample on the testing process and results. Based on this, the effective porosity and total porosity of the shale sample are determined by helium injection measurement and nuclear magnetic resonance measurement, thereby establishing a comprehensive characterization method for shale oil reservoir space, laying the foundation for actual production and resource evaluation.

[0062] In one specific embodiment, this invention provides a detailed method for characterizing shale oil reservoir space, referring to... Figure 2 As shown, the method may include the following steps:

[0063] Step S21: Perform wire cutting on the shale sample to obtain a plunger sample with a regular shape.

[0064] This step uses wire cutting technology to process the shale sample into regularly shaped plunger samples, which facilitates the measurement of the external volume in subsequent steps.

[0065] Step S22: Determine the apparent volume of the regularly shaped plunger sample based on the electronic vernier caliper measurement method.

[0066] This step measures the apparent volume of the sample using an electronic vernier caliper, eliminating the need for washing and drying the sample. This avoids changes in apparent volume caused by water absorption and expansion of clay minerals during liquid measurement, thus reducing measurement errors.

[0067] Step S23: Perform helium injection measurements on the regularly shaped plunger sample to determine the effective porosity of the shale sample.

[0068] In this step, a helium injection measurement was performed on a regularly shaped plunger sample using an injection pressure of 100 psi, and a high-precision pressure sensor was used for pressure monitoring to determine the effective porosity of the shale sample. The ambient temperature for the helium injection measurement of the regularly shaped plunger sample was 24 ± 0.5℃.

[0069] In this step, when conducting helium injection measurements, the equilibrium time is determined according to Boyle's Law. The specific measurement process is as follows: First, the effective porosity and pressure of the shale sample are obtained over a preset time period. Then, based on the power function approximation method, the pre-established correlation between porosity and time is fitted using the effective porosity and pressure changes over time to determine the effective porosity of the shale sample. To improve measurement accuracy, the effective porosity of the shale sample is calculated and recorded after 50 hours according to Boyle's Law to achieve precise measurement.

[0070] Step S24: Perform nuclear magnetic resonance porosity measurement on the plunger sample to determine the total porosity of the shale sample.

[0071] Two-dimensional nuclear magnetic resonance (NMR) porosity measurements were performed on the plunger samples under ambient temperature, drying, saturated water, and centrifugation conditions to determine the total porosity of the shale samples. The drying conditions were 70℃ for at least 48 hours and saturated water conditions were 15 MPa for at least 15 hours.

[0072] In this step, the sample is dried at 70℃ for 48 hours to remove any fluid that may have been present in the original pores; it is then saturated with water at 15 MPa for 15 hours to ensure that the volume of the connected pores is completely occupied by water; and centrifugation is used to remove the volume occupied by the movable water.

[0073] The specific parameters for nuclear magnetic resonance in this step are as follows: nuclear magnetic porosity measurement uses the SR-CPMG sequence, TE echo time is 0.06ms, NECH value is 18000, NTI value is 31, end time is 3000ms, and NS is repeated 32 times.

[0074] Step S25: Based on the effective porosity and total porosity of shale samples, characterize the shale oil reservoir space of the shale samples. Taking into account the unavoidable errors in each experiment, helium porosity values ​​are selected to characterize the effective porosity, and NMR results are used to characterize the closed pores. A comprehensive characterization process for the porosity and spatial distribution of shale oil reservoir space is established.

[0075] Step S26: Perform electron microscopy and nano-CT scanning on the plunger sample to determine the fracture porosity. Fracture porosity, as a type of effective porosity, is an important parameter describing the degree of voids within rocks or soils, and is of great significance in studies such as hydrocarbon migration.

[0076] The method provided in this embodiment of the invention optimizes the sample pretreatment, experimental process and parameter settings for different test experiments, thereby achieving the purpose of quantitatively evaluating the effective porosity and total porosity of shale oil samples, laying the foundation for actual production and resource evaluation.

[0077] In a specific example, shale samples from a study area were selected. Qualitative observations were performed using thin sections and scanning electron microscopy, followed by helium porosity and nuclear magnetic resonance porosity measurements. Two pure shale plunger samples, S-1 and S-2, were obtained from the same depth after wire cutting.

[0078] The above samples were prepared and observed using thin sections, scanning electron microscopy, and nano-CT. The samples exhibited felsic laminae, clay laminae, and shell laminae, with the mineral composition dominated by clay minerals, quartz, and carbonate minerals. CT results... Figure 3 The S-1 sample showed two relatively straight lamellar slits, perpendicular to the cylindrical surface of the plunger, with a slit porosity of 1.85%. Figure 4 The S-2 structure shows two sets of microcracks, which are parallel to the bedding planes and have a porosity of 0.93%.

[0079] Porosity of samples S-1 and S-2 was determined using helium porosity testing. The initial injection pressure for both samples was 100 psi, and the testing environment was controlled at 24 ± 0.5℃. The external volume measurement of S-1 showed a diameter of 2.506 cm, a length of 1.954 cm, and a mass of 23.44 g; the external volume measurement of S-2 showed a diameter of 2.494 cm, a length of 1.143 cm, and a mass of 13.49 g. Long-term porosity measurements of the samples showed the following results: Figure 5The S-1 shows a porosity of 5.5% after 25 minutes and 8.64% after 53 hours, as specified by national standards. Figure 6 The S-2 porosity value is 6.68% after 25 minutes and 8.38% after 53 hours, as specified by the national standard.

[0080] Using nuclear magnetic resonance (NMR) with an SR-CPMG sequence, a TE echo time of 0.06 ms, a NECH value of 18000, an NTI value of 31, an end time of 3000 ms, and 32 repeated NS scans, samples were tested sequentially at room temperature, dried at 70℃ for 48 h, and saturated with water at 15 MPa for 15 h. The porosity of the S-1 closed pore was measured to be 9.43%, and the porosity of the S-2 closed pore was measured to be 4.31%. The test results are referenced from [reference to other sources]. Figure 7 , Figure 8 Based on the comprehensive characterization results, after optimizing sample pretreatment, experimental procedures, and parameters, the effective porosity of S-1 was 8.64%, the total porosity was 18.07%, and the crack porosity was 1.85%; while the effective porosity of S-2 was 8.38%, the total porosity was 12.69%, and the crack porosity was 0.93%.

[0081] Example 2

[0082] Embodiment 2 of the present invention provides a method for constructing a shale porosity identification chart, referring to... Figure 9 As shown, the method may include the following steps:

[0083] Step S91: Obtain different types of shale samples and measure the organic matter abundance of different types of shale samples.

[0084] Step S92: Measure the effective porosity and total porosity of different types of shale samples, wherein the effective porosity and total porosity of the shale samples are measured according to the characterization method of shale oil reservoir space described in Example 1.

[0085] Step S93: Based on the organic matter abundance, effective porosity, and total porosity of different types of shale samples, construct a shale porosity identification chart.

[0086] This invention employs numerical experiments to fit physical experimental results and predict porosity values ​​over subsequent time periods. Helium porosity experiments were conducted on different shale samples to obtain porosity and pressure variations over 60 hours. A power function approximation method was used to establish a general relationship and perform curve fitting. Based on the pre-established general relationship between porosity and experimental time, the fitting relationship between the porosity of the rock sample and experimental time was obtained by fitting the experimental data, thus determining the effective porosity of the rock sample.

[0087] Specifically, the general relationship between porosity and experimental time is: Porosity = a × t b +c; where Porosity is the porosity, t is the experimental time, and a, b, and c are constants to be determined.

[0088] Considering the impact of organic matter abundance on reservoir porosity, organic matter abundance tests were conducted on samples from different regions, and helium porosity-time curve fitting charts were established under different TOC backgrounds. It is anticipated that in the future, given a sample from a specific region with a known TOC, the charts will be used to determine the measurement equilibrium time of helium porosity and the final effective porosity of that sample, improving the accuracy and timeliness of the experiments.

[0089] Based on the same inventive concept, this invention also provides a rapid method for measuring the effective porosity of shale, which may include:

[0090] First, the organic matter abundance of shale samples from the study block is measured. Then, based on a pre-constructed shale porosity identification chart and organic matter abundance, the effective porosity and measurement equilibrium time of the shale samples are quickly determined. The shale porosity identification chart is pre-constructed according to the aforementioned method for constructing shale porosity identification charts.

[0091] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

Claims

1. A method for characterizing shale oil reservoir space, characterized in that, include: The shale samples were wire-cut to obtain plunger samples with regular shapes; Helium injection measurements were performed on a regularly shaped plunger sample using an injection pressure of 100 psi, and pressure monitoring was performed using a high-precision pressure sensor. The effective porosity and pressure of the shale sample over a preset time period were obtained. Based on the power function approximation method, the effective porosity of the shale sample is determined by fitting the pre-established correlation between porosity and time using the effective porosity change over time and the pressure change over time. The plunger sample was subjected to nuclear magnetic resonance porosity measurement to determine the total porosity of the shale sample; Based on the effective porosity and total porosity of the shale sample, the shale oil reservoir space of the shale sample is characterized.

2. The method according to claim 1, characterized in that, The step of performing nuclear magnetic resonance porosity measurement on the plunger sample to determine the total porosity of the shale sample includes: The total porosity of the shale sample was determined by performing two-dimensional nuclear magnetic resonance porosity measurements under ambient temperature, drying, saturated water, and centrifugation conditions. The drying conditions are as follows: drying at 70°C for no less than 48 hours; The saturated water condition is 15 MPa saturated water for no less than 15 hours.

3. The method according to claim 2, characterized in that, The nuclear magnetic resonance porosity measurement used the SR-CPMG sequence with a TE echo time of 0.06 ms, a NECH value of 18000, an NTI value of 31, an end time of 3000 ms, and NS repeated scans 32 times.

4. The method according to claim 1, characterized in that, The ambient temperature for conducting helium injection measurements on the regularly shaped plunger sample was 24±0.5℃.

5. The method according to claim 1, characterized in that, Before performing helium injection measurements on regularly shaped plunger samples, the following steps are also required: The apparent volume of a regularly shaped plunger sample was determined using an electronic vernier caliper measurement method.

6. The method according to any one of claims 1 to 5, characterized in that, Also includes: The plunger sample was subjected to electron microscopy and nano-CT scanning to determine the crack porosity of the plunger sample.

7. A method for constructing a shale porosity identification chart, characterized in that, include: Different types of shale samples were obtained, and the organic matter abundance of the different types of shale samples was measured; The effective porosity and total porosity of the shale samples of different types are measured, wherein the effective porosity and total porosity of the shale samples are obtained by the characterization method of shale oil reservoir space according to any one of claims 1 to 6; Based on the organic matter abundance, effective porosity, and total porosity of different types of shale samples, a shale porosity identification chart was constructed.

8. A rapid method for measuring the effective porosity of shale, characterized in that, include: The organic matter abundance of shale samples from the study block was measured. Based on a pre-constructed shale porosity identification chart and the organic matter abundance, the effective porosity and measurement equilibrium time of the shale sample are quickly determined. The shale porosity identification chart is pre-constructed using the method for constructing a shale porosity identification chart according to claim 7.

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