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Article

Evolution Mechanism of Microscopic Pore System in Coal-Bearing Marine–Continental Transitional Shale with Increasing Maturation

by
Jizhen Zhang
1,2,3,*,
Wei Lin
4,
Mingtao Li
4,
Jianguo Wang
3,
Xiao Xiao
3,
Yu Li
3 and
Xiaochan Zhang
3
1
State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Beijing 100083, China
2
Sinopec Key Laboratory of Shale Oil/Gas Exploration and Production Technology, Beijing 100083, China
3
College of Resources and Environment, Yangtze University, Wuhan 430100, China
4
Institute of Digital Geology and Energy, Linyi University, Linyi 276000, China
*
Author to whom correspondence should be addressed.
Minerals 2023, 13(12), 1482; https://doi.org/10.3390/min13121482
Submission received: 26 October 2023 / Revised: 19 November 2023 / Accepted: 23 November 2023 / Published: 24 November 2023
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Versions Notes

Abstract

:
The formation and evolution mechanisms of complex types and scales of marine–continental transitional shale pores are still indefinite, restricting the accurate evaluation of shale reservoir and the effective evaluation of coal-bearing marine–continental transitional shale gas resource quantity. Considering the Shanxi shale in Ordos basin of China as the research object, combining the FE-SEM images and petrophysical analysis, high-pressure mercury intrusion porosimetry, and CO2 and N2 adsorption–desorption experiments, the structure characteristics and differential evolution mechanisms of multiscale and multitype of coal-bearing shale pores were discussed. The results show that coal-bearing marine–continental transitional shales are rich in clay minerals and organic matters (OMs). Pores developed within organic matters, clay, and brittle minerals of coal-bearing shale have decreasing porosity values. OM pores are directly related to micro- and mesopores, with high specific surface areas, while the porosity of inorganic pores increases with the increasing pore diameter. The porosity of all pores shows a positive relationship with permeability, which changes periodically with the increase in maturity. Coal-bearing shale pores are mainly plate- and ink bottle-shaped, with multimodal pore size distributions. Controlled by both diagenesis and hydrocarbon generation, the evolution of coal-bearing shale pores could be mainly divided into four stages. Furthermore, the pore evolution model of coal-bearing marine–continental transitional shale was preliminarily constructed. This study would enhance the understanding of reservoir evolution of the coal-bearing shale and provide useful information for the assessment and evaluation of reservoir capacity.

1. Introduction

In recent years, following the great success of the shale gas revolution in North America, shale gas resources have received worldwide attention, with the focus of research fields shifting from marine shale to terrestrial shale [1,2,3,4]. Organic-rich shale is not only the source rock of shale gas, but also the reservoir rock of shale gas, with high heterogeneity and complexity of pore structure [5,6,7]. With the continuous advancement of shale oil and gas in unconventional oil and gas exploration and development worldwide, increasing attention has been paid to the study of shale reservoir structure [8,9,10,11]. Deciphering the methods to accurately and comprehensively characterize the pore structure characteristics of shale reservoir and judge the evolution law of shale pore structure during thermal maturation has become an important fundamental issue in the research of shale reservoir.
Shale gas is mainly stored in a shale pore system in adsorptive or free state, and thus, pore structure characteristics are crucial for the enrichment and seepage of shale gas [6,7]. During the geologic history, shale gas reservoir is in dynamic equilibrium; on the one hand, with the increasing maturity of shale organic matter, a large amount of thermogenic gas is generated; on the other hand, pore and adsorption characteristics of shale show regular changes during thermal evolution [12,13,14,15,16,17,18]. The investigation of pore structure evolution mechanism is significant to predict the porosity, permeability, and the saturated shale gas content [19,20,21,22,23,24,25,26].
At present, great progress has been made in the research on type, size, shape, spatial distribution and connectivity, and evolution of pores in shale, and controlling the factors of pore development; however, due to the large differences in the matrix composition and burial thermal maturation evolution of shale in different regions or shale layers, there are still large differences in the understanding of the development characteristics and thermal maturation evolution of microscopic pores in shale [21,22,27,28].
Unlike the pore evolution of conventional oil and gas reservoir commonly affected by diagenesis [21], the pore evolution of shale is mainly controlled by both hydrocarbon generation and diagenesis [15]. In particular, the progress in hydrocarbon generation and dissolution would increase pore space, while the progress in cementation and combination would reduce pore volume [29,30]. Generally, the porosity of conventional sandstone reservoirs decreases with the increase in burial depth, due to the compaction and cementation; in which, although dissolution and mineral transformation can locally expand the pore space, the trend of porosity reduction cannot be changed [31]. Comparatively, shale reservoir has extremely low porosity and permeability, and thus, conventional reservoir pore analysis techniques cannot effectively characterize the pore characteristics of shale reservoirs.
Many qualitative and quantitative techniques have been thoroughly developed so far to study the micrometer/nano-scale pore structure of shale, such as field emission-/scanning electron microscopy (FE-SEM/SEM) [27,28,32,33,34,35], broad ion beam SEM (BIB-SEM) [36,37], focused ion beam SEM (FIB-SEM) [11,27,38,39,40,41], transmission electron microscopy (TEM) [24,42,43], nano-CT [44], high-pressure mercury intrusion porosimetry (HMIP) [30], and N2/CO2 gas adsorption–desorption techniques [45,46,47]. According to the classification scheme reported by the International Union of Pure and Applied Chemistry (IUPAC), shale pores could be divided into micropores, mesopores, and macropores [48]. Due to the differences in testing methods and samples, there are large differences in the previous understanding of shale pore size interval. In this study, by utilizing the advantages of the measurement interval of multifarious technologies, we combined HMIP with N2 and CO2 adsorption–desorption techniques for the determination of the pore structures of macropores, mesopores, and micropores, respectively.
Previous studies conducted using the above techniques suggest that pores with sizes of <50 nm are mainly developed in the organic matters, and the size of pores within organic matters is generally smaller than that within inorganic minerals [24,43,49,50]. Few nanopores were found in the immature and low mature shales using intuitionistic SEM technique, whereas highly matured shales develop with abundant organic matter pores [51,52]. In addition, the diagenetic cementation of secondary quartz, carbonate, and pyrite and the mechanical compaction of rock greatly reduce the porosity of shale [30,53]. Therefore, hydrocarbon generation and multiple diagenesis would increase the complexity of pore structure during the evolutionary process.
Although recent progress has been made in the evolution characteristic of pores in organic matters, less attention has been paid to the evolution law of inorganic pores in shale. The consideration of organic matter pores alone cannot adequately explain the evolution mechanism of the whole pore system. Many researchers agree that the number of organic matter pores increase with the increase in the thermal evolution degree of organic matter of shale [26,43,54,55,56]. Based on the geochemical analysis data of Barnett shale samples with different maturity using organic geochemistry and spectroscopic techniques, Bernard et al. (2012) proposed that a large number of microscopic pores can be formed due to the secondary cracking of organic matter at the high evolutionary stage [42]. By observing pores in the Woodford shale in FIB-SEM images, Curtis et al. (2012) found that few secondary pores were generated in the shales with a vitrinite reflectance (Ro) value lower than 0.9%, while secondary pores were commonly observed in the shales with high maturity [44]. However, Curtis et al. (2011) considered these pores as the research object and found that the pore size and proportion of organic matter pores decreased with the increase in Ro value of the Marcellus shale in North America [8]. Fishman et al. (2012) also found that the pore size and quantity of organic matter pores of the Kimmeridge shale in the United Kingdom did not significantly increase based on the SEM image observation [57]. Thus, it can be seen that the current views and conclusions on the thermal evolution trend of organic matter pores in shale are not consistent. In addition, thermal maturity is not the only factor affecting the development of shale pores. Complex matrix composition, content, spatial distribution, and mineral transformation will further complicate the evolution characteristics of shale pore system [30,53,58].
The purpose of this study is to characterize the nanoscale pore characteristics and reveal the evolution mechanism of coal-bearing marine–continental transitional shale. Considering the coal-bearing marine–continental transitional shale of Shanxi Formation in the Ordos Basin of North China as the research object, combining multiple advanced technologies (e.g., X-ray diffraction (XRD), FE-SEM, HMIP, and N2/CO2 adsorption–desorption experiments), the factors controlling both multiscale and multitype pore structure evolution and distribution with diagenesis and the thermal evolution of organic matters were deeply investigated, and a preliminary pore evolution model of coal-bearing marine–continental transitional shale was established. The contributions made here have wide applicability. This study would provide both experimental and theoretical bases for explaining the shale gas occurrence and accumulation, providing useful information for reservoir assessment and evaluation, guiding the exploration and exploitation of coal-bearing marine–continental transitional shale gas systems.

2. Geological Setting

Ordos basin, located in North China, is an important part of North China Platform, with an area of 3.7 × 105 km2 (Figure 1a). Based on the geological evolution history of the basin and the characteristics of its biogeological structures, the Ordos Basin is divided into five primary structural units, namely, the north–south trending structural belt on the western margin, the northern Yimeng uplift, the southern Weibei uplift, the eastern Jinxi flexure belt, and the central Yishan slope (Figure 1a) [59,60,61]. In the early Permian, due to the continuous expansion of the transgressive area on both sides, seawater covered the central ancient uplift. Then, with the further increase in the north–south tectonic sedimentary differences, in the sedimentary stage of the Shanxi Formation, the formation of the northern Mongolian Changbai Xing’an fold belt and the southern Qinling–Qilian–Kunlun fold belt caused the North China Plate to collide with the Siberian Plate and gradually be lifted into land, and seawater quickly retreated from the east and west sides. The formation of the Kunlun fold belt caused the North China plate to collide with the Siberian plate and gradually be lifted to land, and the sea water quickly retreated from the east and west sides, changing its sedimentary environment from marine to terrestrial and unveiling the prelude to terrestrial sedimentation, so that the arid climate reappeared. During this period, the southern boundary of the basin boundary was roughly distributed along the Lanzhou–Danfeng–Luonan area, the northern boundary to the Xingmeng orogenic belt, the eastern boundary extended to the boundary of the North China plate, and the western boundary was the west side of the Alashan massif [59,60,61,62].
During Late Paleozoic, the Upper Carboniferous Benxi Formation (C2b), the Lower Permian Taiyuan Formation (P1t), and the Shanxi Formation (P1s), as well as the Middle Permian Shihezi Formation (P2sh), as the main marine sedimentary system, were successively deposited from bottom to top in the Ordos Basin, and the sedimentation range gradually expanded. The Shanxi Formation, the target layer of this study, is an important layer for natural gas exploration in the Ordos Basin. The overall stratigraphic thickness in this period showed that the source area was thinner in the north and south, and the sedimentary area gradually thickened, and there was no obvious thickness difference in the east–west direction. Compared to the Taiyuan Formation, which is also a transitional deposit between sea and land, the Shanxi Formation has a thicker rock layer, with fewer coal seams and more sandstones. It is widely distributed with dark shale and coal seams, with the main lithology consisting of siltstone, dark gray–gray black mudstone, and interbedded layers of medium-to-fine sandstone. Sandstone is often developed in the middle and lower parts, but its stability is poor, and its thickness changes greatly (Figure 1b) [60,61,62].

3. Samples and Methods

3.1. Samples

Considering that the maturity values of Shanxi composition change slightly in a single well, in order to obtain the geological samples of natural evolution sequences, a total of 12 fresh core shale samples were collected from 12 wells of the Shanxi Formation in the Ordos Basin, and the sample locations were shown in Figure 1a. Avoiding exposure to strong deformation during drilling and coring, all the sampling sites were carefully selected to cover a relatively complete diagenetic evolution and organic matter maturation sequence, with the burial depth ranging 694.6–3797.1 m. All samples were freeze-dried within 48 h after collection and sent to the laboratory in time for experiments.

3.2. Experimental Method

The total organic carbon (TOC) analysis was carried out via a LECO-230 carbon–sulfur analyzer in the Key Laboratory of Exploration Technologies for Oil and Gas Resources, Wuhan. All experiments were conducted following the Chinese National Standard GB/T 19145-2022. The sample was crushed into granules with the size of <120 mm, treated by HCl to remove the carbonates, and washed by distilled water to wipe off residuary HCl before experiments.
The microstructure composition quantification and Ro value determination were performed using an MPV-3 microphotometer under the Chinese National Standards of SY/T 5124-2012 and SY/T 6414-2014. All shale samples were polished into thin sections with a thickness of <0.2 mm for light transmission, and then observed under reflected white light for observing transmitted light with fluorescence. Ro data were measured by the zigzag observation of 110 point counts for each sample.
XRD data were obtained by an RIGAK–D/Mas 2500PC Powder X–ray diffractometer with a Cu Kα radiation at the voltage of 40 kV and current of 30 mA, according to the SY/T 5163-2010 standard. All the samples were crushed to powder with particle size of <70 μm and pressed flat into the groove (25 mm × 35 mm × 1 mm) of a glass slide for preparation. Then, these samples were scanned from 2° to 80° (2θ) at a rate of 4°/min. According to the Powder Diffraction File (PDF) provided by Joint Committee on Power Diffraction-International Center for Diffraction Data (JCPDS–ICDD), quantitative phase analysis was performed using Rietveld refinement, with customized clay mineral structure models.
FE-SEM imaging was conducted using a Quanta 200F on the basis of the standard of SY/T 5162–2014. Shale samples were prepared as tiny pieces with sizes of about 10 mm × 10 mm × 2 mm and then subjected to ion milling via an Ar beam source to obtain a flat surface. After that, these samples were mounted to a gold-plated instrument to coat the sample surface with a 10 nm thick gold layer. Then, these samples were placed in the FE-SEM instrument and observed in vacuum environment.
The porosity and permeability were measured via an Ultrapore–200A Helium Porosimeter following the standard of SY/T5336-2006. Cylindrical samples with a diameter of 10 mm and a height of 25 mm were prepared and then mounted within the Helium Porosimeter instrument. The measurement of porosity was performed with the gas method based on Boyle’s law in a helium medium under the measuring pressure of 0.7 MPa. Permeability was analyzed at a confining pressure of 7 MPa with dry nitrogen as the medium.
The porosity of different types of shale pores were calculated using the petrophysical interpretation and mathematical calculation models reported in our previous study [46,63]. In which, shale was divided into four layers, including the brittle mineral layer, clay mineral layer, organic matter layer, and the interbedded micro-fractures. And the mathematical model calculating the different types of porosities was formulated based on the following equations:
φTotal = φMatrix + φFrac
φMatrix = ρABriVBri + ρAClayVClay + ρATOCVTOC
In these above equations, φTotal, φMatrix, and φFrac, respectively, represent the porosity of whole rock, matrix, and microfracture, %; ρ represents the rock density, t/m3; while the ABri VBri ABri, AClay, and ATOC are the mass percentage of brittle minerals, clays, and organic matters, %; and VBri, VClay, and VTOC are the pore volume per unit mass of brittle minerals, clays, and organic matters, respectively, m3/t.
The HMIP experiments were performed using a PoreMaster GT 60 Mercury Injection Apparatus according to the standard of GB/T 21650.1-2008. All samples were prepared as small cylinders with a bottom diameter of 3.5 mm and a height of 15–20 mm. All samples were dried in an oven for 24 h at a temperature of 110 °C and then placed in the autoclave for degassing by vacuuming before the experiment. After that, mercury is pressurized into the sample, with the upper limit of pressure of 60,000 Psia, and the corresponding minimum mercury entry pore was about 3.2 nm.
CO2/N2 adsorption–desorption experiments were operated using the Quantachrome-nova 2000 Surface Area Analyzer and Pore Size Analyzer following the standard of GB/T21650.3-2011. Before the experiment, the shale samples were crushed into 40–80 powder particles and degassed for about 5 h in a vacuum environment at 110 °C to remove the adsorbed water and capillary water. The text pore aperture sizes of N2 and CO2 adsorption–desorption experiments are 1.7−100 nm and <1.6 nm, with the corresponding relative pressures (P/P0) of 0.009–0.995 and 0.0001–0.032, respectively. The pore volume and specific surface area of mesopores were measured, respectively, with the Barrett–Joyner–Halenda (BJH) and Brunauer–Emmett–Teller (BET) models based on the N2 adsorption data [64,65]. And the micropore volume and specific surface area were calculated using the density functional theory (DFT) and the Dubinin–Astakhov (DA) theory, according to the CO2 adsorption data [66].

4. Results

4.1. Bulk Organic Characteristics and Mineralogy

The data of TOC analysis show that the Shanxi shale samples have a higher abundance of organic matter than that of typical marine shales in Southern China [67] and North America [17,22], with a TOC value of 1.53%–6.32% (averaging 3.10%). By using the analytical methods for determining macerals on whole rock polished surfaces and micro-fluorescence technique, a systemic study on the maceral composition characteristics of the Shanxi shales were carried out. Vitrinite is commonly composed of lignin and terrestrial plant cellulose and shows brown, rust, or no fluorescence under fluorescence (Figure 2d,e). The vitrinite reflectance measurement results show the Shanxi shales have a wide range of thermal maturity, with an Ro value of 0.47%–1.88%. In addition, the liptinite principally consists of liptodetrinite and sporinite, followed by keratose and resinite (Figure 2f).
The XRD results show that the mineral composition of Shanxi shale samples is complex and diverse and rich in clays and brittle minerals (Table 1). The marine shales in North America are rich in brittle minerals, generally with a mineral content of >40 wt.% [21,22,68,69,70]. Comparatively, the Shanxi shales have a higher proportion of clay minerals (Table 1, Figure 3), with a mineral content of 26.7 wt.%–65.6 wt.%. In clays, the content of illite/montmorillonite mixed layer is the highest, ranging from 17.5 wt.% to 48.8 wt.%, followed by illite with a content of 2.0 wt.%–23.7 wt.%, while kaolinite and chlorite have relatively low contents, ranging 0.7 wt.%–4.6 wt.% and 0.5 wt.%–5.1 wt.%, respectively. In addition, the contents of brittle minerals are slightly lower (Table 1, Figure 3), ranging between 19.7 wt.% and 53.3 wt.%. In which, quartz content is the highest, with a value of 14.5 wt.%–33.3 wt.%, while carbonate content ranges from 2.5 wt.% to 9.3 wt.%, and pyrite content varies greatly, ranging 0 wt.%–21.7 wt.% (Table 1).

4.2. Porosity and Permeability

Porosity and permeability are important parameters for evaluating shale reservoir and determining shale gas content [25,29,30,40]. The total porosity of shale samples investigated from the Shanxi Formation in the Ordos Basin range from 2.76% to 6.55%, with an average of 4.72% (Figure 4). However, the permeability of these samples range between 0.34 × 10−6 md and 1.68 × 10−6 μm2, with a mean value of 0.98 × 10−6 μm2 (Figure 4). As shown in Figure 4b, permeability has exhibited a strong linear fitting relationship with porosity, with the fitting coefficient (R2) of 0.743. The porosity of the main gas producing strata of the Barnett shale in North America and the Longmaxi shale in the Sichuan Basin of China are in the range of 2%–14% and 0.73%–7.4%, respectively, while their average permeability is less than 1.0 × 10−3 μm2 and 1.8 × 10−3 μm2, respectively [22,68,69,70]. Comparatively, the investigated lacustrine Shanxi shales have a similar porosity to the marine Longmaxi shale in the Sichuan Basin but a lower permeability than the Barnett and Longmaxi shales, which would be conducive to the storage and exploitation of the Shanxi shale gas resource in the Ordos Basin.

4.3. Different Types of Porosity Calculations and Result Verification

In the present study, three shale samples (N42-6, Y5-7, and Y61-3) were randomly selected from the middle part of the Shanxi Formation from a depth of 1883.2 m, 2206.8 m, and 2548.4 m (TOC corresponding to 3.23%, 1.95%, and 1.53%, respectively). And then, a ternary linear equation set was constructed based on Equation (2). After that, this equation set was solved according to the measured results of TOC content, mineral content, porosity, and rock density of the three groups of shale samples, and three unknown parameter values of VTOC, VClay, and VBri were calculated to be 0.2477, 0.0100, and 0.0126 m3/t, respectively (Table 2). This indicates that the density of pore development in the organic matters, brittle minerals, and clays in turn decreases. Finally, the calculated values of VTOC, VClay, and VBri were substituted into Equation (2), and thus, the porosity values of different types of pores were calculated (Figure 5).
In addition, according to Equations (1) and (2), the porosity of microfractures can be calculated by the difference between the measured helium porosity and the calculated matrix porosity, with a value of 0.1%–0.5%. As shown in Table 2 and Figure 5a, the porosity of pores within brittle minerals, clays, and organic matters are in the range of 0.9%–3.0% (averaging 1.4%), 1.0%–1.7% (averaging 1.1%), and 0.9%–3.9% (averaging 1.6%), respectively. As shown in Figure 5b, the calculated matrix porosity has a strong positive linear correlation with the measured helium porosity (R2 = 0.793), demonstrating that the mathematical model has high reliability and accuracy for the porosity calculation of different types of shale pores.

4.4. Pore Structures in the Shanxi Shales

Shale pores are continuously distributed ranging from micropores to macropores, and this provides space for the occurrence and seepage of shale gas. However, due to the limitation of experimental techniques, the pore structure characteristics of shale pores can only be more accurately characterized by sectional measurement. In the HMIP experiment, mercury first enters macropores under low pressure, and then enters mesopores and micropores under high pressure. Because of that, high pressure may lead to pore deformation, and the HMIP experiment is the most accurate method to characterize macropore structures. In the N2 and CO2 adsorption–desorption experiments, N2 and CO2 were primarily filled in the micropores and then adsorbed in the mesopore. However, due to the extremely high saturation vapor pressure of CO2 below 0 °C (3.218 MPa), CO2 could enter into the micropores much more easily than N2. Therefore, the CO2 adsorption experiment is more suitable to characterize the micropore distribution, while the N2 adsorption experiment is more suitable to characterize the structures of mesopores. By combining these three experiments, the test accuracy of micropore, mesoporous, and macropore distribution is improved, respectively, which is more conducive to the analysis of the distribution characteristics of the full-scale pores in shale.
As shown in the CO2 adsorption–desorption curves of the Shanxi shales (Figure 6a), in which, the CO2 adsorption capacity of most samples is close to saturation as the relative pressure reaches 0.03, and only the samples HS1-2 and Y61-3 with small adsorption capacity are asymptotically saturated at the relative pressure of about 0.02. According to the data of CO2 adsorption–desorption, the pore volume of the micropores was obtained using the DFT model, ranging from 0.009 to 0.022 cm3/g, with an average of 0.014 cm3/g. And the specific surface area of the micropores is in the range of 14.8–40.5 m2/g, with a mean value of 26.5 m2/g (Figure 7). As shown in the micropore size distribution of coal-bearing Shanxi shale samples based on CO2 adsorption data (Figure 8), most of the pore volume change rates present bimodal characteristics, with the peak pore size ranging between 0.5–0.65 nm and 0.75–0.9 nm, indicating that the micropore volume is mainly concentrated within the above pore size ranges.
The N2 adsorption curves rise slowly at the relative pressure P/P0 of <0.4, and the nitrogen initial adsorption capacity value is higher than 0, indicating that there are a certain number of micropores developed in the Shanxi shale (Figure 9). As the relative pressure is close to 1.0, the adsorption curve rises sharply and does not reach adsorption saturation, indicating that there are a certain number of large pores in the shale sample (Figure 9). Hysteresis loops are commonly observed in the N2 adsorption–desorption curves under low temperature (77 K), which can reflect the pore morphology [71,72]. IUPAC classified the hysteretic loops into four types (H1, H2, H3, and H4), which reflect regular tubular pores with openings at both ends, ink bottle pores with thin neck and wide body, narrow slit pores with open sides, and slit pores with parallel walls, respectively [71]. As shown in Figure 9, the hysteretic loops of the Shanxi shales are mainly observed in the mixture of H2 and H3 types, indicating that the pores in Shanxi shales are mainly ink bottle and slit shaped. With the increase in the maturity of organic matters, the hysteretic loops show a series of different characteristics. In the immature stage (Ro < 0.5%), hysteretic loops mainly present the characteristics of flat slits pore types. As Ro value is between 0.5% and 1.0%, hysteretic loops begin to show the mixed characteristics of ink bottle- and flat slit-shaped pore types, and the flat slit-shaped pores are dominant in the pore system. The ink bottle-shaped shale pores increase gradually with an Ro value of 1.1%–1.35%, and this pattern of pores dominates the pore system when the Ro value is 1.35%–2.0%.
On the basis of data from the N2 adsorption–desorption experiments and the DFT method, the measured pore volume of mesopores is in the range of 0.011–0.037 cm3/g, with an average value of 0.022 cm3/g (Figure 7). And the mesopore surface area ranges between 1.3 m2/g and 11.8 m2/g (mean of 4.6 m2/g), according to the BJH method (Figure 7). Figure 10 shows the rate of change in pore volume with pore size for mesopores and a part of macropores. Generally, with the increase in pore diameter, the curves of pore volume distribution with pore size obtained from the N2 adsorption branch of isotherms present bimodal characteristics, with the main peak interval of 2–6 nm and large pore diameter of 30–90 nm. But it is worth noticing that the pore volume change rates in the two main apertures above show different distribution characteristics at different degrees of thermal evolution. In the immature stage (Ro < 0.5), the pore volume change rates are relatively close to aperture ranges of 2–6 nm and 30–90 nm. When the maturity Ro is between 0.5 and 1.0%, the pore volume change rate within the small aperture range of 2–6 nm is higher than that at the large aperture range of 30–90 nm. When the Ro value is between 1.0% and 1.5%, the number of pores with small pore sizes decreases while that with large pore sizes increases. However, when the Ro value is between 1.5% and 2.0%, the pore quantity of small pores gradually increases, while the pore quantity of large pores decreases.
As shown in Figure 6b, the mercury intrusion and extrusion curves of 12 shale samples from the Shanxi Formation in the Ordos Basin have similar shape. Under a low pressure (P < 0.7 MPa), the amount of intrusion mercury into pores increases with the pressure. And the intrusion mercury amount increases slowly as the pressure reaches about 0.7 MPa, with the corresponding pore diameter of approximately 20 nm. At pressures ranging from 0.7 to 14 MPa, only a small amount of mercury was injected, indicating that pores are poorly developed in shales in this pressure range. When the pressure is greater than 14 MPa, the intrusion mercury amount increases rapidly again, and it continues to increase until the maximum pressure is reached, indicating that there are a large number of pores less than 10 nm in the Shanxi shales, which cannot be further tested due to the limitation of mercury injection technology. The mercury regression curves first rose and then fell, which is caused by the re-opening of pores closed by high pressure in the early stage during the process of pressure drop, indicating that the number of micropores tested would be smaller than the actual number of micropores. According to the HMIP experiments, the pore volume range of shale macropores in the Shanxi shale is 0.013–0.039 cm3/g, with an average of 0.023 cm3/g, while the specific surface area of macropores range from 0.3 to 1.2 m2/g, with an average of 0.6 m2/g.
The total pore volume and specific surface area of the Shanxi shales are in the ranges of 0.038–0.084 cm3/g and 21.9–45.4 m2/g, with an average value of 0.059 cm3/g and 31.7 m2/g, respectively. And the average pore size is between 35.6 nm and 257.4 nm, with an average value of 100.6 nm. The volume of macropores and mesopores are the main contributors for the total pore volume of the Shanxi shales, accounting for 31.0%–45.8% (averaging 38.6%) and 25.5%–43.8% (averaging 35.0%), respectively. The contribution rate of micropore volume is comparatively lower, accounting for 10.3%–42.1% (averaging 26.5%), but they are the main contributor of the total specific surface area, with a contribution rate of 53.2%–94.2% (mean of 83.2%). However, the contribution rate of mesopores and macropores are 4.6%–42.4% (mean of 14.9%) and 0.6%–4.3% (mean of 1.9%), respectively. All these results show that with the increase in specific surface area, the shale pore volume increases, and the average pore diameter decreases, which indicates that the smaller the pore diameter is, the larger the specific surface area provided for adsorption and the stronger the pore adsorption capacity will be. Micropores together with mesopores provides more than 95% specific surface area of shale and is the main site of shale gas adsorption. However, macropores together with micropores provide more than 75% of the pore volume of shale on average, which is the main space for shale gas storage.

5. Discussion

5.1. Evolution of Pores in Organic Matters

Organic pores are hydrocarbon-generating residual pores formed during the thermal evolution of organic matter [73,74]. Generally, the shapes of organic pores are regular, and most of them are pits and honeycombs. The formation and evolution of organic matter pores are heterogeneous, and the size, quantity, and density of organic matter pores in shales at different evolution stages vary greatly [52]. In addition, even after the same thermal evolution, the development of organic matter pores in different regions is significantly different, indicating that thermal maturity is not the only factor controlling the development of organic matter pores [52,74,75]. In this study, coal-bearing Shanxi shale samples from the Ordos Basin experienced immature, low–medium–high maturity stages, with the Ro value ranging from 0.47% to 1.88% (Table 1). As shown in Figure 11, the developmental characteristics of organic matters and organic matter pores could be observed intuitively. As shown in the porosity characteristics of organic matter pores of the Shanxi shales in different evolution stages (Figure 11) and calculated porosity characteristics of organic matters (Figure 12), the organic matter pores of the coal-bearing Shanxi shales change periodically with the different development stages of maturity. At Ro < 0.7%, the thermal degradation energy is not enough to destroy chemically bonded adsorbed organic matters, which mainly generates a small amount of soluble asphalt. The generated oil and gas are mainly stored in the organic-rich aggregates in the form of physical adsorption, with less organic matter pores (Figure 11a–c). At 0.7% < Ro < 1.0%, a large amount of hydrocarbon is produced because of the pyrolysis of organic matters, and hydrocarbon generation residual pores are well developed in the organic matters. These pores are densely distributed, with uniform sizes of 30–650 nm and common shapes of ellipse and circle (Figure 11d–f). In addition, the volume of organic matters decreases because of their cleavage, resulting in the formation of pores between organic matters and their peripheral minerals (Figure 11d). At 1.0% < Ro < 1.3%, high volumes of oils and asphalt produced by the pyrolysis of organic matter are mostly retained in pores at this stage, and thus, a large number of organic pores are filled and blocked within pyrolytic asphalt (Figure 11g,h). At 1.3% < Ro < 1.7%, numerous organic matter pores are newly generated by the secondary cracking of organic matters, and the filled organic matter pores are released and expand due to the cracking of oil and asphalt, enlarging pore space and size. The pore morphology of organic matter developed in this stage is commonly ellipsoidal, semilunar, and spherical shaped (Figure 11i,j). At Ro > 1.7%, the dominant position of hydrocarbon generation of organic matter is replaced by diagenetic compaction. With the increase in burial depth, the large-scale organic matter pores are compacted and decreased, and the shapes of organic matter pores are compressed into slit, short columnar, ellipsoidal, and crescent shaped (Figure 11k,l).
Therefore, according to the above microscopic characteristics, the formation and evolution process of OM veins is restored. With the continuous burial depth and temperature increase, the maturity of organic matter in the study section gradually increased (Ro > 0.5 %), and entered the oil window, and kerogen generated from liquid hydrocarbons with low density [42] was transported and filled into inorganic pores in a dispersed form [43].

5.2. Mineral Diagenetic Evolution and Inorganic Pores

In the early diagenesis stage, the organic matter is immature, and the clay minerals consist largely of montmorillonite. Diagenesis is dominated by mechanical compaction, resulting in the rapid discharge of a large amount of water within pores, rapid increase in density, and rapid decrease in porosity. And the interlaminar pores and shrinkage fractures are well developed in this stage [52,74,75]. Montmorillonite was not detected in the Shanxi shale samples, which was mainly caused by the transformation of montmorillonite to illite through the mixed layer of illite/smectite. The transformation of montmorillonite to illite is an important mechanism for potash feldspar to overcome the dissolution kinetic barrier during diagenetic evolution [76].
In the middle diagenetic stage, the Ro value ranges between 0.35% and 0.7%, and the shale has been relatively compact because of the compaction of the previous stage. Affected by the cementation of quartz and carbonate, the contents of quartz and carbonate decrease gradually with the increase in burial depth (Figure 13). Additionally, due to the cracking of organic matters in organic-rich shale, acetic acid, oxalic acid, and other organic acids are produced in large quantities, which would dissolve the unstable minerals such as feldspar and calcite and produce secondary dissolution pores. The capacity of organic acid to supply H+ is 6–350 times that of carbonate; therefore, the main reason for the formation of secondary dissolution pore is that organic acid can dissolve a large number of feldspar and carbonate minerals. Potassium feldspar is dissolved by organic acid and releases potassium ions, which can form quartz; meanwhile, controlled by sedimentation and diagenesis, the potassium ion, illite, and kaolinite can further evolve into illite (Figure 13).
With the Ro value ranging from 0.7% to 1.3%, in which, the mechanical compaction in diagenesis weakens, and the chemical filling cementation enhances. Due to the influence of cementation, the porosity of pores within brittle minerals and clays decreases (Figure 12). With the Ro value ranging from 1.3% to 1.7%, a large amount of organic matter in shale is cracked to generate hydrocarbon. Organic acid and CO2 coexist in formation fluid, showing weak acidity. Weak acid environment dissolves feldspar and carbonate easily (Figure 13c,d), which produces dissolution pores. The results show that the content of illite increases gradually as the kaolinite transforms into illite (Figure 13f), and the porosity of clay minerals increases accordingly (Figure 12). Illite inherits the pore structure characteristics of kaolinite, and the pores are mainly sinter layer pores between plate-like particles and interparticle pores between clay aggregates. At an Ro value of >1.7%, a large amount of fluid in shale is discharged slowly, and the compaction effect is enhanced due to the decrease in the fluid pressure in shale. The hydrocarbon generation is mainly transformed from oil generation to gas generation, and the solution tends to be saturated and re-precipitated. Many fractures and pores are commonly filled and cemented by various newly formed minerals (such as carbonate minerals, authigenic quartz, pyrite, etc.) (Figure 13b,d) and recrystallized clay minerals, blocking some adjacent pores and fractures, destroying the original structure, and reducing the porosity (Figure 12).

5.3. Evolution of Different Scales of Shale Pores

Generally, pore volume, specific surface area, and average pore size are the key parameters for the quantitative characterization of shale pore structures. There are good positive linear correlations between pore volume and specific surface area in the coal-bearing Shanxi shales (Figure 14a). But it is worth noting that the fitting strength of pore volume and specific surface area of micro-, meso- and macropores in turn decreases, with the fit coefficient R2 of 0.985, 0.934, and 0.6184, respectively (Figure 14a). In addition, the pore volume of meso- and macropores show positive relationships with the average pore size, with the R2 value of 0.657 and 0.635, respectively (Figure 14b). However, the micropore volume has a weak negative linear correlation with the average pore size, with the R2 value of 0.270. These results show that the larger pores dominate the pore space, and thus, the pore volume of macro- and mesopores increase with the increasing of average pore size. And shales with much more micropores have a smaller average pore size.
As shown in Figure 15, different scales of pores in the coal-bearing Shanxi shales have different evolution rules with the increase in maturity. In the stage of Ro < 0.7%, the volume of pores with larger pore sizes (mesopores and macropores) decreases rapidly, which is mainly due to the increase in burial depth and strong compaction effect in immature and low mature evolution stages. Pores with larger pore size are compacted into small pores, with the volume decreasing rapidly. In addition, organic matter pores begin to develop because of the hydrocarbon generation of organic matter. During this stage, together with some protogenetic micropores developed in shale, more small pores formed by the compression of larger pores and organic matter micropores increase the pore volume of micropores. With the Ro value of 0.7%–1.0%, the organic matter pores are filled with oil and asphaltene generated by the hydrocarbon generation in the previous stage, which reduces the volume of organic matter pores. It is found that shales with a higher organic matter content have a relatively higher content of dissolution pores, and feldspar and carbonate minerals near the organic matter during the first cracking stage of organic matter commonly undergo dissolution, as shown in Figure 11d,e. The pore size of these pores is relatively larger than organic matter pores. Meanwhile, abundant meso- and macropores are developed in the process of massive transformation of montmorillonite into illite montmorillonite, under the internal pressure produced by the dehydration. Therefore, the pore volumes of macro- and mesopores show the increasing trend at this stage, and the result of the total pore volume also shows an increasing trend. With the Ro value of 1.0%–1.3%, the pores formed by dissolution pores and mineral transformation in the last stage gradually decrease under the influence of formation compaction, resulting in the pore volume of macro- and mesopores to decrease gradually and transform into micropores. With the Ro value of 1.3%–1.7%, micropores develop again, and organic matter pores filled by oils in the previous stage are released and expanded, due to the secondary cracking of organic matters. Meanwhile, new dissolution pores are formed due to organic matter hydrocarbon generation. Thus, the total pore volume increases again with the increase in meso- and macropores in this stage. With the Ro value of higher than 1.7%, the hydrocarbon generation of organic matter is reduced, and compaction and cementation play a dominant role again, which makes the pores further compacted, and the pore volume of full-scaled pores decreases, making the total pore volume decrease gradually.

5.4. Pore Evolution Model of Coal-Bearing Marine–Continental Transitional Shale

Although there is a certain degree of error between the calculated results of different types of porosity based on the model and the actual porosity, the predicted pore data obtained by the model still has high reliability. Figure 5 shows that the fitting coefficient between the predicted and actual values is 0.793. Influenced by both diagenesis and hydrocarbon generation, the evolution of coal-bearing marine–continental transitional shale pores could be mainly divided into four stages (Figure 16). In the early stage of deposition of the Shanxi shales (Ro < 0.5%), the argillaceous sediment consolidated into rock, the fluid in the formation was rapidly discharged, and the organic matter began to biodegrade. Pores within shale reservoir are mainly composed of inter-particle pores and intra-particle pores caused by mechanical accumulation. Under the action of overlying formation pressure, mesopores and macropores gradually decrease and transform into micropores. Plastic minerals are deformed and filled into inter-particle pores, which aggravate the loss of pore volume. Thus, the volume of mesopores and macropores decreases rapidly, and the volume of micropores increases slowly.
In the stage of low–medium mature oil generation (0.5% < Ro < 1.3%), the pore volume of shale shows complex evolution characteristics, and the shale pore volume increases at first and then decreases with the increase in maturity. On the one hand, with the increase in burial depth, the drainage of pore water becomes more and more difficult, and the intensity of compaction gradually weakens; on the other hand, with the thermal evolution of hydrocarbon generation, organic matter gradually begins to crack and produce organic matter pores. Meanwhile, a large number of organic acids are produced in the process of hydrocarbon generation, resulting in the dissolution of feldspar, carbonate and other soluble minerals to form secondary dissolution pores. In addition, the transformation of kaolinite to chlorite reduces the development of interparticle pores within clay mineral layers. Meanwhile, with the transformation of montmorillonite to illite, authigenic quartz cemented the shale pores and reduced the pore volume. Moreover, the transformation of potash feldspar to albite inhibited the dissolution of potash feldspar and acid plagioclase, thus reducing the development of secondary dissolution pores. With the Ro value of approximately 1.3%, the shale gas generated by the initial cracking of organic matter is less, the degree of crude oil cracking is low, and the pore fluid pressure is small. The organic matter pores are blocked by liquid hydrocarbon and macromolecular asphalt and asphaltene, which limits the flow of a small amount of gas generated by the initial pyrolysis of kerogen, resulting in the pore size and pore volume of organic matter to decrease in this evolution stage.
With the Ro value of 1.3%–1.7%, the organic matter is cracked to generate hydrocarbons again, forming condensate oil and moisture and increasing the pore fluid pressure and the number and volume of organic matter pores. Meanwhile, the pores filled with oil and asphaltene in the previous stage will release hydrocarbon generated by the cracking of oil and asphaltene, and the volume of original pores will be expanded, so that the connectivity between the organic matter pores will be strengthened and their volume will be increased.
With the Ro value of >1.7%, the volume of organic matter pores decreases slowly due to compaction. In addition, due to the organic acid produced by the re-cracking of organic matter continues to dissolve soluble minerals to form secondary dissolved pores, the newly generated and previously generated pores are connected to expand the pore volume. Thus, the volume of micropores decreases, while the volume of mesopores and macropores increases. The pores with larger pore size in inorganic minerals continue to be weakly compacted. The porosity generally shows a slow increasing trend in this stage.

6. Conclusions

(1)
The coal-bearing marine–continental transitional Shanxi shales are rich in clay minerals (26.7 wt.%~65.6 wt.%). Various pore types are developed in the different matrices of shale reservoir, and the pore density among organic pores, brittle minerals, and clay minerals decreases successively. Organic pores have an obvious correlation with micropores and mesopores, while inorganic pores are developed with larger pore sizes. Shanxi shales have low porosity and permeability, which change periodically with the increase in the maturity.
(2)
The pore morphology of the coal-bearing Shanxi shales is mainly plate slit and ink bottle shaped, and the pore morphology varies greatly in each evolution stage. The pore size distribution of shale is uneven and has the characteristics of multi-peaks, with an average pore size ranging from 35.6 to 257.4 nm (mean of 100.6 nm). The contribution rate of micropore volume is low, ranging from 10.3% to 42.1%, but it is the main contributor of specific surface area, with the contribution rate ranging from 53.2% to 94.2%.
(3)
With the evolution of hydrocarbon generation of organic matter and the diagenetic evolution of inorganic minerals, the organic matter pores of various inorganic mineral pores of coal-bearing shales change in stages with the increase in maturity, forming an important reservoir space for shale oil and gas.
(4)
The double cracking of organic matter generates a large number of organic matter pores, mainly providing small pore size pores. Meanwhile, the organic acid produced dissolves easily soluble minerals, expanding the pore space of brittle minerals and increasing the volume of macropores. The decrease in mesopores and macropores mainly stems from the reduction in pores within clay minerals.
(5)
Evolution characteristics of shale pores were affected jointly by diagenesis and hydrocarbon generation, which could be mainly divided into four stages. At Ro < 0.5%, controlled by compaction, the volume of large primary interparticle pores formed by the original loose accumulation decreases rapidly. At 0.5%< Ro <1.3%, large number of organic matter pores is formed by hydrocarbon generation, and these pores could be occupied by oil and pyrolytic asphalt, resulting in the decrease in porosity; additionally, numerous dissolved pores generated by organic acids dissolve soluble minerals, and the conversion of clay minerals increases the pore volume. At 1.3% < Ro < 1.7%, the volume of organic matter pores and dissolved pores increases again due to the secondary cracking of organic matters, whereas the volume of inorganic pores decreases slowly due to compaction. At Ro > 1.7%, with the decline in diagenesis and hydrocarbon generation, pore system gradually remains stable.

Author Contributions

Conceptualization, J.Z.; methodology, X.X.; software, W.L.; validation, M.L.; formal analysis, X.X. and X.Z.; investigation, J.W.; resources, J.Z.; data curation, Y.L.; writing—original draft preparation, J.Z.; writing—review and editing, J.Z.; visualization, J.Z.; supervision, J.Z.; project administration, J.Z.; funding acquisition, J.Z. All authors have read and agreed to the published version of the manuscript.

Funding

This study is funded by the National Natural Science Foundation of China (Grant No. 42202141) and the Open Fund Project of Sinopec Key Laboratory of Shale Oil/Gas Exploration and Production Technology (Grant No. 33550000-22-ZC0613-0204).

Data Availability Statement

The data that support the findings of this study are available from the corresponding author upon reasonable request.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Location of the study area (a) and the comprehensive strata diagram of the Shanxi Formation in the Ordos basin (b) (modified based on [59,60,61,62]).
Figure 1. Location of the study area (a) and the comprehensive strata diagram of the Shanxi Formation in the Ordos basin (b) (modified based on [59,60,61,62]).
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Figure 2. Characteristics of microscopic composition of investigated Shanxi shale samples: (a) homogeneous vitrinite and matrix vitrinite, sample NT1-6, 3658.3 m, reflected light; (b) matrix vitrinite and vitrodetrinite, sample Y61-3, 2548.4 m, reflected light; (c) fusinite and vitrodetrinite, sample D8-2, 2678.3 m, reflected light; (d) liptodetrinite and sporinite, sample G1-5, 967.8 m, fluorescence and transmission light; (e) sporinite, sample N42-6, 1883.2 m, fluorescence and transmission light; and (f) resinite, sample HT1-5, 3707.1 m, fluorescence and transmission light.
Figure 2. Characteristics of microscopic composition of investigated Shanxi shale samples: (a) homogeneous vitrinite and matrix vitrinite, sample NT1-6, 3658.3 m, reflected light; (b) matrix vitrinite and vitrodetrinite, sample Y61-3, 2548.4 m, reflected light; (c) fusinite and vitrodetrinite, sample D8-2, 2678.3 m, reflected light; (d) liptodetrinite and sporinite, sample G1-5, 967.8 m, fluorescence and transmission light; (e) sporinite, sample N42-6, 1883.2 m, fluorescence and transmission light; and (f) resinite, sample HT1-5, 3707.1 m, fluorescence and transmission light.
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Figure 3. Mineralogical composition of the studied Shanxi shales and comparison with the typical shales of North America [21,22,68,69,70].
Figure 3. Mineralogical composition of the studied Shanxi shales and comparison with the typical shales of North America [21,22,68,69,70].
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Figure 4. The relationships of porosity and permeability with vitrinite reflectance Ro (a), and of porosity with permeability (b) of the Shanxi shale samples.
Figure 4. The relationships of porosity and permeability with vitrinite reflectance Ro (a), and of porosity with permeability (b) of the Shanxi shale samples.
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Figure 5. Different types of porosity calculation results (a) and the fitting verification with the measured porosity (b).
Figure 5. Different types of porosity calculation results (a) and the fitting verification with the measured porosity (b).
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Figure 6. CO2 adsorption–desorption curves (a) and mercury intrusion and extrusion curves (b) of coal-bearing Shanxi shale samples.
Figure 6. CO2 adsorption–desorption curves (a) and mercury intrusion and extrusion curves (b) of coal-bearing Shanxi shale samples.
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Figure 7. The value and percentage of macro-, meso-, and micro-pore volumes (a) and specific surface areas (b) of Shanxi shale samples.
Figure 7. The value and percentage of macro-, meso-, and micro-pore volumes (a) and specific surface areas (b) of Shanxi shale samples.
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Figure 8. Micropore size distribution of coal-bearing Shanxi shale samples based on CO2 adsorption data.
Figure 8. Micropore size distribution of coal-bearing Shanxi shale samples based on CO2 adsorption data.
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Figure 9. N2 adsorption–desorption curves of coal-bearing Shanxi shale samples.
Figure 9. N2 adsorption–desorption curves of coal-bearing Shanxi shale samples.
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Figure 10. Pore volume distribution with pore size obtained from the N2 adsorption branch of isotherms.
Figure 10. Pore volume distribution with pore size obtained from the N2 adsorption branch of isotherms.
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Figure 11. The FE-SEM images show the evolutionary characteristics of organic matter pores in Shanxi shale samples with the increase in Ro.
Figure 11. The FE-SEM images show the evolutionary characteristics of organic matter pores in Shanxi shale samples with the increase in Ro.
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Figure 12. Porosity evolution characteristics of different types of pores in the Shanxi shales with the increase in Ro.
Figure 12. Porosity evolution characteristics of different types of pores in the Shanxi shales with the increase in Ro.
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Figure 13. The content of different minerals in the Shanxi shale samples with the increase in Ro.
Figure 13. The content of different minerals in the Shanxi shale samples with the increase in Ro.
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Figure 14. Relationships of pore volume with pore surface area of different scales of pores (a) and average pore size (b) in the Shanxi shales.
Figure 14. Relationships of pore volume with pore surface area of different scales of pores (a) and average pore size (b) in the Shanxi shales.
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Figure 15. Evolution characteristics of pore structure parameters of the Shanxi shales with the increase in Ro.
Figure 15. Evolution characteristics of pore structure parameters of the Shanxi shales with the increase in Ro.
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Figure 16. Evolution mode of different scales and types of pores in the coal-bearing Shanxi shales with the increase in Ro.
Figure 16. Evolution mode of different scales and types of pores in the coal-bearing Shanxi shales with the increase in Ro.
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Table 1. Comparison of the pore-forming efficiency of different organic matter based on MAPS two-dimensional image.
Table 1. Comparison of the pore-forming efficiency of different organic matter based on MAPS two-dimensional image.
WellSample IDDepth (m)Ro (%)TOC (%)Mineral Composition (wt.%)
QuartzFeldsparCarbonatePyriteKaoliniteChloriteIlliteI/S
HS1HS1-2694.60.472.7833.312.89.38.01.21.92.027.8
G1G1-5967.80.502.4429.37.58.79.01.62.55.117.5
N23N23-31566.90.563.7514.51.73.51.02.81.17.447.6
N42N42-61883.20.726.3218.21.52.50.03.55.18.248.8
Y5Y5-72206.80.843.1726.32.55.53.04.63.79.737.6
Y61Y61-32548.40.931.5322.11.94.62.03.82.610.347.9
LT1LT1-42386.21.151.9525.22.46.73.02.62.012.437.8
D8D8-22678.31.292.8617.21.87.22.73.11.614.244.8
Y2Y2-52745.41.373.2318.41.37.811.22.50.918.838.7
D15D15-32835.71.573.2115.50.95.78.51.70.523.738.7
NT1NT1-63658.31.753.4517.30.73.016.91.20.820.631.7
HT1HT1-53707.11.882.5315.30.54.721.70.71.119.734.8
Table 2. Sampling point parameters in the Shanxi Formation.
Table 2. Sampling point parameters in the Shanxi Formation.
SampleDepth
(m)		Basic DataMicropore Volume per Unit Mass (m3/t)
Rock Density
(g/cm3)		Porosity
(%)		TOC (%)Clay Mineral Content (wt.%)Brittle Mineral Content (wt.%)VTOCVClayVBri
N42-61883.22.855.43.2360.9138.680.24770.01000.0126
Y5-72206.82.854.31.9554.7237.29
Y61-32548.42.503.51.5364.6030.60
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Zhang, J.; Lin, W.; Li, M.; Wang, J.; Xiao, X.; Li, Y.; Zhang, X. Evolution Mechanism of Microscopic Pore System in Coal-Bearing Marine–Continental Transitional Shale with Increasing Maturation. Minerals 2023, 13, 1482. https://doi.org/10.3390/min13121482

AMA Style

Zhang J, Lin W, Li M, Wang J, Xiao X, Li Y, Zhang X. Evolution Mechanism of Microscopic Pore System in Coal-Bearing Marine–Continental Transitional Shale with Increasing Maturation. Minerals. 2023; 13(12):1482. https://doi.org/10.3390/min13121482

Chicago/Turabian Style

Zhang, Jizhen, Wei Lin, Mingtao Li, Jianguo Wang, Xiao Xiao, Yu Li, and Xiaochan Zhang. 2023. "Evolution Mechanism of Microscopic Pore System in Coal-Bearing Marine–Continental Transitional Shale with Increasing Maturation" Minerals 13, no. 12: 1482. https://doi.org/10.3390/min13121482

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