Method for measuring porosity of shale core

Abstract

This invention discloses a method for measuring the porosity of shale core samples, belonging to the petroleum field. It involves directly heating a shale core plunger sample using a controlled-temperature dry distillation method. This ensures complete removal of residual oil and gas while preserving the core plunger sample. The porosity is then directly measured using a helium porosity measuring device. Furthermore, a method for verifying the accuracy of the measured porosity is provided. To accurately measure the porosity of shale cores, this invention, through repeated experiments constraining the rate of increase in dry distillation temperature, heating time, and maximum temperature, ultimately determined a dry distillation process that completely removes residual oil while preserving the original appearance of the core sample. The porosity of the shale core is then directly obtained using a helium porosity measuring device. The total effective porosity calculated by adding the porosity measured by this method to the helium porosity measured after oil washing and the residual oil porosity measured by nuclear magnetic resonance after oil washing is less than 0.5%, sufficient to verify its accuracy.

Description

Technical Field

[0001] This invention belongs to the petroleum field and relates to a method for measuring the porosity of shale core samples. Background Technology

[0002] Accurate measurement of shale oil reservoir porosity is a crucial parameter for evaluating the oil-bearing potential of sweet spots and remains a global challenge. The difficulty lies in the fact that shale oil reservoirs primarily exhibit nanoscale and microscale pores. Traditional helium gas measurement methods, particularly the oil washing stage, cannot completely remove residual oil and gas from these nanoscale and microscale pores, resulting in measured values ​​lower than the actual porosity. Furthermore, the inherently low porosity of shale oil contributes significantly to the underestimation of total porosity, a situation that cannot be ignored. Accurately measuring shale oil reservoir porosity is a key factor restricting the evaluation of sweet spot properties and the calculation of resource quantities. Researchers in the shale oil field have made substantial efforts to address this challenge.

[0003] Currently, patents related to shale oil porosity measurement can be divided into four categories. One category involves indirectly calculating porosity by establishing functional relationships with other components. For example, in 2014, Chen Fangwen et al. (CN103822866A) estimated porosity using scanning electron microscopy data; in 2015, Wang Xingjian et al. (CN104977771U) indirectly measured porosity using the adsorption amount of shale samples; in 2019, Yang Zhenheng (CN112231882A) indirectly determined porosity values ​​through material composition by establishing a functional relationship between porosity and mineral composition; and in 2019, He Chencheng et al. (CN111122408A) calculated porosity for pore sizes between 0.3-10 nm by establishing a relationship between pore volume and TOC content. This type of calculation method requires high accuracy in establishing the function, and the accuracy is difficult to judge, making it difficult to accurately characterize porosity. The second type uses nuclear magnetic resonance (NMR) technology to determine porosity. For example, in 2014, Xu Hao et al. (CN104075974A) determined porosity by using different echo times and waiting times in NMR; in 2016, Zhang Pengfei et al. (CN105866002A) used the distribution of NMR T2 spectra to characterize the physical properties of oil-bearing shale reservoirs; and in 2018, Wang Min et al. (CN108458960A) established NMR T1-T2 spectrum standards for different components and compared the differences in T2 spectra to determine porosity values. These calculation methods have long testing cycles, and different basins and regions have different NMR characteristics, lacking universality. The third type calculates porosity using the difference method. For example, in 2019, Tao Guoliang et al. (CN111855521A) used mass difference to calculate porosity; in 2020, Qu Bin et al. (CN111650108A) used volume difference to calculate porosity (total rock volume - skeleton volume - particle volume - dust volume). This type of method involves a large amount of measurement data and has a large systematic error. The fourth type removes residual oil through distillation, extraction, pyrolysis, etc., and then determines porosity based on the mass of the residual oil. For example, in 2011, Tian Hua et al. (CN102252948A) used distillation extraction to remove residual oil and gas; in 2016, Bai Jiajia et al. (CN106323840A) vacuumed the rock sample, extracted it with solution, and determined porosity based on weight difference; in 2020, Xie Xiaomin et al. (CN111487176A) pyrolyzed residual oil and gas in gravel, weighed the residual oil and gas, and calculated its porosity. Distillation and extraction are time-consuming, and it is difficult to completely remove all residual oil. Pyrolysis, without temperature constraints, is prone to damaging rock samples, and errors are unavoidable in the measurement of parameters such as weight and density, making it difficult to accurately determine porosity.

[0004] In conclusion, there is an urgent need to develop a technology that is both accurate and convenient for measuring the porosity of shale cores. Summary of the Invention

[0005] The purpose of this invention is to overcome the shortcomings of existing methods for measuring the porosity of shale cores, such as large errors and inconvenience, and to provide a method for measuring the porosity of shale cores. To achieve the above objectives, the present invention employs the following technical solution: A method for measuring the porosity of shale core samples includes the following steps: Step 1) Process the shale core into plunger samples and wash the plunger samples with oil; Step 2) Measure the porosity of the plunger sample after oil washing to obtain the porosity of the plunger sample after oil washing and the porosity of the residual oil; Step 3) Dry distill and heat the plunger sample after washing the oil, and measure the porosity of the plunger sample after dry distillation and heat to obtain the porosity after dry distillation; Step 4) Add the porosity of the plunger sample after washing with the porosity of the residual oil to obtain the sum of porosity. Compare the sum of porosity with the porosity after dry distillation and calculate the absolute error. When the absolute error is less than or equal to 0.5%, the porosity after dry distillation is the total porosity of the shale core.

[0006] Preferably, in step 3), the conditions for dry distillation heating are: temperature 350-400℃, time 40-50h.

[0007] Preferably, in step 3), the dry distillation heating process is as follows: The core plunger sample was first heated to 100℃, then 100-200℃, with a temperature increase of 10℃ per hour. After reaching 200℃, the temperature was increased by 10℃ every 2 hours until it reached 350-400℃.

[0008] Preferably, in step 4), the calculation process for the absolute error is as follows:

[0009] In the formula, Φ1 is the porosity of the plunger sample after washing, Φ2 is the porosity of the residual oil after washing, and Φ3 is the porosity after dry distillation.

[0010] Preferably, in step 2), the test gas for porosity measurement is helium.

[0011] Preferably, in step 2), the test pressure is 200 psi when measuring porosity.

[0012] Preferably, in steps 2) and 3), the porosity measurement is performed using a nuclear magnetic resonance (NMR) measurement device.

[0013] Preferably, in step 1), when washing the plunger sample with oil, the washing cycle is 30 days.

[0014] Compared with the prior art, the present invention has the following beneficial effects: This invention discloses a method for measuring the porosity of shale core samples. The method involves directly heating a shale core plunger sample using controlled-temperature dry distillation, ensuring complete removal of residual oil and gas while preserving the core plunger sample. The porosity is then directly measured using a helium porosimeter. Furthermore, a method for verifying the accuracy of the measured porosity is provided. To accurately measure the porosity of shale cores, this invention, through repeated experiments constraining the rate of increase in dry distillation temperature, heating time, and maximum temperature, ultimately determined a dry distillation process that completely removes residual oil while preserving the original appearance of the core sample. The porosity of the shale core is then directly obtained using a helium porosimeter. The total effective porosity calculated by adding the porosity measured by this method to the helium porosity measured after oil washing and the residual oil porosity measured by NMR after oil washing shows a difference of less than 0.5%, sufficient to verify its accuracy. Meanwhile, the operation steps are convenient, the measurement is direct without calculation, the system error is small, the time is short, it can be completed within two days, the direct measurement is highly accurate, the influence of human calculation factors and multiple external factors is reduced, the system error is reduced, and the experimental process is convenient. Attached Figure Description

[0015] Figure 1 This is a flowchart of the method for measuring the porosity of shale cores according to the present invention; Figure 2 The graph shows the relationship between residual oil porosity and NMR T2 relaxation time in Example 3. Figure 3 The graph shows the relationship between residual oil porosity and NMR T2 relaxation time in Example 14. Detailed Implementation

[0016] The present invention will now be described in further detail with reference to the accompanying drawings: Example 1 The method for accurate measurement of shale core porosity of this invention was used to analyze 17 shale oil core samples from the Fengcheng Formation in the Mahu Depression of the Zhungar Basin. The analysis was conducted according to the following steps, as follows: Figure 1 As shown, Step S1: Process the shale core into a plunger sample, and use an oil washing device to wash the shale core plunger sample with oil to meet the helium porosity measurement standard. Step S2: Use a helium porosity measuring device to measure the porosity of the shale core plunger sample after oil washing, and obtain the porosity Φ1 of the shale core plunger sample after oil washing; Step S3: Using nuclear magnetic resonance (NMR) measurement equipment, measure the residual oil porosity Φ2 of the shale core plunger sample after oil washing; Step S4: The shale core plunger sample is heated by temperature-controlled dry distillation. The core plunger sample is first slowly heated to 100°C, and the temperature is increased by 10°C per hour. After reaching 200°C, the temperature is increased by 10°C every 2 hours until the required maximum temperature of 350°C is reached. The dry distillation takes about 40 hours. Step S5: Use a helium porosity measuring device to measure the porosity of the shale core plunger sample after controlled-temperature dry distillation, and obtain the porosity Φ3 of the shale core plunger sample after controlled-temperature dry distillation; Step S6: After completing the above measurements on a batch of shale core plunger samples, the helium porosity Φ1 after washing the oil and the residual oil porosity Φ2 measured by NMR are added together and compared with the helium porosity Φ3 measured after temperature-controlled dry distillation. The absolute error is less than or equal to 0.5%, indicating that the porosity measured by the temperature-controlled dry distillation method has high accuracy. Step S7: The helium porosity value Φ3 measured after temperature-controlled dry distillation is used as the porosity of the shale core plunger sample.

[0017] Example 2 The method for accurate measurement of shale core porosity according to this invention was used to analyze 17 shale oil core samples from the Fengcheng Formation in the Mahu Depression of the Zhungar Basin. The steps (refer to Figure 1) are as follows: The shale cores were processed into plunger samples to meet the requirements for helium porosity measurement. The shale core plunger samples were washed with oil using an oil washing device. After washing, the fluorescence series measurements of the shale core plunger samples were lower than the level 3 fluorescence standard of the People's Republic of China Petroleum and Natural Gas Industry Standard "SY / T 5118—2005 Determination of Chloroform Bituminous Pitch in Rocks," meeting the helium porosity measurement standard, for approximately 30 days. The porosity of the washed shale core plunger samples was measured using a helium porosity measuring device (Ultrapore 300 helium porosimeter from Core Systems, USA), obtaining the porosity Φ1 of the washed shale core plunger samples (refer to Table 1). The residual oil porosity Φ2 of the washed shale core plunger samples was measured using nuclear magnetic resonance (NMR) equipment (refer to Figure 2). Nuclear magnetic resonance (NMR) technology quantitatively characterizes fluid content by detecting the relaxation signal of hydrogen nuclei in a unit volume of fluid. Current laboratory NMR instruments (such as the Oxford Instruments GEOSPEC2 NMR spectrometer) can essentially measure all fluid information within the pores of dense rocks. Without considering hydrogen content correction, the hydrogen content index of oil and water can be considered close to 1. By measuring the NMR spectrum of the core after oil washing treatment, information on the residual oil volume and porosity can be obtained. Shale core plunger samples were subjected to controlled-temperature dry distillation. The core plunger samples were first slowly heated to 100°C, increasing the temperature by 10°C per hour, and then increasing it by 10°C every 2 hours after reaching 200°C, until the required maximum temperature was reached. The maximum temperature was controlled to be around 400°C, and the process took approximately 40 hours. The porosity of shale core plunger samples after controlled-temperature dry distillation was measured using a helium porosity measuring instrument to obtain the porosity Φ3 of the shale core plunger samples after controlled-temperature dry distillation. After the above measurements were completed on 17 shale core plunger samples, the helium porosity Φ1 measured after oil washing and the residual oil porosity Φ2 measured by nuclear magnetic resonance were added together and compared with the helium porosity Φ3 measured after controlled-temperature dry distillation. The helium porosity value measured after controlled-temperature dry distillation was taken as the porosity value of the group of shale core plunger samples.

[0018] The results of the relationship between residual oil porosity measured in serial number 3 and NMR T2 relaxation time are as follows: Figure 2 The result for serial number 14 is as follows Figure 3 As shown, the porosity measured by the temperature-controlled dry distillation method is consistent with the porosity measured by NMR after conventional oil washing. This method saves time, requires no calculation, and has high accuracy compared to conventional methods.

[0019] Table 1. Statistical Table of Shale Core Porosity Analysis Serial Number Helium porosity Φ1 (%) after oil washing NMR residual oil porosity Φ2 (%) Helium porosity Φ3 (%) obtained by dry distillation Absolute error (%) 1 1.1 3.1 4.2 0.00 2 2.3 1.1 2.9 0.50 3 1.9 2.3 4.4 0.20 4 1.5 3.3 4.3 0.50 5 0.8 2.3 2.7 0.40 6 1.6 1.4 3.4 0.40 7 2.5 1.4 4.2 0.30 8 7.4 1.1 8.8 0.30 9 6.4 1.1 7.7 0.20 10 0.7 1.3 1.7 0.30 11 3.6 2.4 6.5 0.50 12 5.4 1.2 6.5 0.10 13 2.3 1.3 3.6 0.00 14 6.7 2.8 9.6 0.10 15 1.7 2.1 4.3 0.50 16 6.4 1.3 7.8 0.10 17 1.8 2.2 4.3 0.30 The results in Table 1 show that the absolute error is between 0% and 0.5%, indicating that the porosity measured by the temperature-controlled dry distillation method is highly accurate and meets the requirements of the People's Republic of China Petroleum and Natural Gas Industry Standard "SY / T5336—2006 Core Analysis Methods".

[0020] It should be noted that the residual oil porosity measured by nuclear magnetic resonance (NMR) is under the condition of not considering hydrogen content correction. The hydrogen content index of oil and water can be considered close to 1. The residual oil porosity can be obtained by measuring the NMR spectrum of the core sample after oil washing treatment. The same batch of samples is first washed with oil, and the helium porosity after washing is measured. The residual oil porosity is then measured using NMR. The two are added together to calculate the total porosity. Then, controlled-temperature dry distillation is performed, and the helium porosity after controlled-temperature dry distillation is measured. The experimental order is to verify the accuracy of the measured porosity data; therefore, the order cannot be reversed. When using this method to measure shale porosity, steps 1, 2, and 3 can be omitted, and direct pyrolysis can be performed, thus saving the time-consuming core washing process.

[0021] The porosity measured in shale cores using this invention can be directly used for sweet spot evaluation and geological reserve calculation without additional calculations. The helium porosity measuring device used in this invention is the Ultra Pore 300 helium porosimeter from Core Instruments, Inc. (USA), using helium as the test gas at a pressure of 200 psi. The nuclear magnetic resonance instrument used in this invention is a GEOSPEC2 model from Oxford Instruments, Inc. (UK), capable of measuring all fluid information within the pores of dense rocks. Besides its wide applicability to shale cores, this invention can also be applied to other dense rock cores with well-developed nano- and micro-pores and difficult oil washing processes.

[0022] To avoid problems such as plunger deformation or cracking during the dry distillation heating process, while still ensuring the extraction of residual oil and gas, this invention strictly controls the rate of temperature increase during dry distillation. To prevent the pyrolysis of gums and asphaltenes, the maximum temperature is controlled between 350 and 400°C. The maximum dry distillation temperature is determined based on the pyrolysis temperature ranges for different oil components in the People's Republic of China Petroleum and Natural Gas Industry Standard SY / T5117—1996, "Methods for Pyrolysis Analysis of Rocks." Kerosene and diesel oil are pyrolyzed between 200 and 350°C, heavy oil between 350 and 450°C, and gums and asphaltenes between 450 and 600°C. To avoid the pyrolysis of gums and asphaltenes affecting the accuracy of porosity measurements in shale core plunger samples, the dry distillation temperature is controlled between 350 and 400°C. The specific temperature can be determined based on the density of the oil contained in the core.

[0023] In summary, the measurement method proposed in this application fully considers the characteristics of effective pore development in shale cores and the impact of residual oil caused by incomplete oil washing on porosity measurement. It directly employs a temperature-controlled dry distillation method to remove residual oil and gas, eliminating the influence of residual oil on porosity measurement. Simultaneously, by controlling the maximum temperature, it prevents the pyrolysis of resins and bitumen. The accuracy of the measurement method is further verified by adding the helium porosity measured after oil washing to the residual oil porosity measured by nuclear magnetic resonance after oil washing. This measurement method solves the problems of long measurement cycles, high difficulty, and inaccuracy in shale core porosity measurement, enabling those skilled in the art to accurately analyze shale physical properties and conduct reasonable exploration and development, thus benefiting the development of the shale oil industry.

[0024] The above content is only for illustrating the technical concept of the present invention and should not be construed as limiting the scope of protection of the present invention. Any modifications made to the technical solution based on the technical concept proposed in this invention shall fall within the scope of protection of the claims of this invention.

Claims

1. A method of measuring the porosity of a shale core, characterized in that, Includes the following steps: Step 1) Process the shale core into plunger samples and wash the plunger samples with oil; Step 2) Measure the porosity of the plunger sample after oil washing to obtain the porosity of the plunger sample after oil washing and the porosity of the residual oil; Step 3) The plunger sample after washing oil is subjected to dry distillation and heating. The porosity of the plunger sample after dry distillation and heating is measured to obtain the porosity after dry distillation. The dry distillation and heating conditions are: dry distillation temperature 350-400℃, dry distillation time 40-50h, and the dry distillation and heating process is as follows: The core plunger sample was first heated to 100°C, with the temperature increased by 10°C per hour. After reaching 200°C, the temperature was increased by 10°C every 2 hours until it reached 350-400°C. Step 4) Add the porosity of the plunger sample after washing with the porosity of the residual oil to obtain the sum of porosity. Compare the sum of porosity with the porosity after dry distillation and calculate the absolute error. When the absolute error is less than or equal to 0.5%, the porosity after dry distillation is the total porosity of the shale core.

2. The method of measuring shale core porosity of claim 1, wherein, In step 4), the calculation process for the absolute error is as follows: In the formula, Φ1 is the porosity of the plunger sample after washing, Φ2 is the porosity of the residual oil after washing, and Φ3 is the porosity after dry distillation.

3. The method of measuring shale core porosity of claim 1, wherein, In step 2), helium is used as the test gas for porosity measurement.

4. The method of measuring shale core porosity of claim 1, wherein, In steps 2) and 3), porosity measurement is performed using a nuclear magnetic resonance (NMR) measurement device.

5. The method of measuring shale core porosity of claim 1, wherein, In step 2), the test pressure is 200 psi when measuring porosity.

6. The method of measuring shale core porosity of claim 1, wherein, Step 1) When washing the plunger sample with oil, the washing cycle is 30 days.

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