Structure characteristics and evolution mechanism of nanopore in transitional coal-bearing shale

Journal of Petroleum Science and Engineering 184 (2020) 106545

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Structure characteristics and evolution mechanism of nanopore in transitional coal-bearing shale Kun Yu a, *, Yiwen Ju a, **, Chunjing Shao b a b

Key Laboratory of Computational Geodynamics, College of Earth and Planetary Sciences, University of Chinese Academy of Sciences, Beijing, 100049, China School of Earth Sciences and Engineering, Nanjing University, Nanjing, 210023, China

A R T I C L E I N F O

A B S T R A C T

Keywords: Transitional coal-bearing shale Pore structure Pore type Characteristics Evolution

Nanopore plays a crucial role in shale gas adsorption, and its characteristics and evolution are significant for the evaluation of shale reservoirs with strong heterogeneity. In this study, transitional coal-bearing shale samples from the south margin of North China were selected for investigation of pore structure characteristics and evolution mechanism. Results indicated that nanopores of the studied shales are fractal with strong heteroge­ neity. The higher fractal dimension leads to larger surface area and micropore volume of shale samples. The abundant terrigenous material and limited hydrocarbon generation and expulsion are favorable for the devel­ opment of intraP pores in clay, so that the Organic matter (OM) pores are poorly developed and are partially filled with clay minerals and pyrite framboids. Shale samples having higher levels of clay content and lower levels of quartz content tend to develop more heterogeneous micropores, producing a more complex pore structure in shale. The evolution of nanopore in studied shales is simultaneously determined by the coupling relationship between clay content and the thermal maturation of OM. In the early oil and low clay content stage, the low degree of the thermal evolution of OM leads to generation of less acidic fluid during the decarboxylation of kerogen, resulting in a weak physical combination and chemical corrosion between OM and clay minerals, with the macropores taking the main place in the pore structure. In the main to late oil and medium clay content stage, hydrocarbon generation of OM leads to the development of pores in kerogen and the gradual generation of more acidic fluids that dissolve clay minerals, so that the mesopores are dominant. In the wet gas and high clay content stage, increases in hydrocarbon generation intensity and clay mineral content cause development of more complexes of OM and clay, with a large number of micropores produced in shale reservoirs.

1. Introduction In recent years, shale gas has become a hot spot in energy exploration and shale geology research. Transitional shale reservoirs have been extensively explored and exploited in China, revealing their great po­ tential for hydrocarbon generation and their abundance of shale gas resources (Chen et al., 2011; Zou et al., 2015; Xiong et al., 2017; Yu et al., 2019). Shale heterogeneity is central to evaluation of transitional shale reservoirs, being of great significance for predicting shale gas reservoir “hot spots” (Neimark et al., 2009; Nozawa et al., 2012; Tan et al., 2014; Tang et al., 2014; Huang et al., 2019). However, because of their complex geological conditions and reservoir characteristics, tran­ sitional coal-bearing shale reservoirs feature a high degree of hetero­ geneity in their nanopore structure, posing great challenges to the

evaluation of shale gas resources (Zhang et al., 2012; Wang et al., 2014a, 2014b, 2015; Zhu et al., 2018). Accordingly, study of the characteristics and evolution of nanoscale pores in transitional coal-bearing shale res­ ervoirs having strong heterogeneity is needed to identify the mecha­ nisms of shale gas storage. Recently, many studies have sought to characterize shale reservoirs from both the macro and the micro perspectives. (Ross and Bustin, 2008, 2009), for example, noted the importance of pore heterogeneity for evaluation of shale gas reservoirs. Loucks et al. (2015) and Labani et al. (2013) indicated the genesis and distribution characteristics of micro­ pores in the Mississippian Barnett Shale. Chalmers et al. (2012) revealed the micropore structure and connectivity of North American shale. Guo and Zhao (2015) studied the nanoscale heterogeneity characteristics of marine shale in the Sichuan basin, South China. Wang et al. (2014a,

* Corresponding author. ** Corresponding author. E-mail addresses: [email protected] (K. Yu), [email protected] (Y. Ju). https://doi.org/10.1016/j.petrol.2019.106545 Received 22 May 2019; Received in revised form 3 September 2019; Accepted 28 September 2019 Available online 30 September 2019 0920-4105/© 2019 Elsevier B.V. All rights reserved.

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Journal of Petroleum Science and Engineering 184 (2020) 106545

2014b) placed the genesis of micropores of marine shale in the Upper Yangtze area. Zhang et al. (2017) examined differences in pore structure and fractal characteristics between terrestrial and transitional shale. Bu et al. (2015) and Wang and Ju (2015) studied the fractal characteristics of transitional shale in Huainan coalfield, reporting that shale reservoirs have strong heterogeneity. In addition, because of limitations associated with the strong heterogeneity and complexity of transitional shale res­ ervoirs, evaluation methods for, influencing factors of, and the rela­ tionship between nanoscale heterogeneity and composition of shale reservoirs require further study. In conclusion, these works reveal the heterogeneity of shale reservoirs to some extent, but scarcely any investigation has been made of the heterogeneity and evolution of nanopore in transitional coal-bearing shale. Clearly, solving these problems is highly significant for predicting prospective areas and reducing the risks involved in shale gas exploration. Accordingly, in this work, we selected 13 transitional coal-bearing shale samples from well XJ1 in the south margin of North China. Using a comprehensive approach based on TOC, Ro, XRD, gas adsorption (CO2 and N2), and FE-SEM experiments, we systematically characterized the composition, structure, and fractal characteristics of shale samples to summarize the structure characteristics and evolution mechanism of nanopore in transitional coal-bearing shale.

the Huainan coalfield (Fig. 1a; Bu et al., 2015; Yu et al., 2018), which is an important Carboniferous–Permian coal accumulation basin in North China (Fig. 1a; Chen et al., 2014). The XJ1 well, in the Xinji mining area at the western part of the Huainan coalfield (Fig. 1a), is drilled through the Carboniferous–Permian strata (Fig. 1b) to collect geological infor­ mation about transitional coal-bearing shale and allow further research of the pore structure characteristics and evolution mechanism of the studied shale. In this study, the main transitional coal-bearing strata are the Lower Permian Shanxi and Middle Permian Xiashihezi formations (Fig. 1b; Yu et al., 2019). In the Early Permian, against a backdrop of clearly weakening seawater, the Shanxi Formation was deposited in the delta facies, which consisted of coal, shale, and sandstone. In the Middle Permian, in response to enhanced fluvial action, the Xiashihezi Forma­ tion was deposited in the fluvial delta, forming a set of stratigraphic associations of coal, shale, mudstone, and sandstone (Yu et al., 2018, 2019). Overall, the excellent spatial distribution of coal-bearing strata provides geological conditions ripe for the formation of coal-bearing shale gas reservoirs. 3. Samples and methods 3.1. Samples

2. Geological settings

Considering the variability of TOC, shale composition, and Ro, a total of 13 shale drilling samples were obtained from well XJ1 on the south margin of North China (Fig. 1c). During sampling, we tried to select

Adjacent to the Qinling-Dabie orogenic belt, the south margin of North China is rich in coal and coalbed methane resources, especially in

Fig. 1. Well location map of the main structural subdivisions of the folds and faults (a) and general lithostratigraphic column of the Permian and sampling position of Well XJ1(b) in the south margin of North China. NCC: North China Craton, SCC: South China Craton, TC: Tarim Craton, QB: Qaidam Block, QM: Qiangtang Massif, QDOB: Qinling-Dabie Orogenic Belt. 2

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typical shale samples from well XJ1 that were well preserved and free of weathering. In addition, all shale samples were preserved during the drilling process. All samples were chosen from the Lower to Middle Permian, including six shale samples from the Shanxi Formation and seven from the Xiashihezi Formation.

from well XJ1 to observe pore morphology. Based on the pore classifi­ cation provided by Loucks et al. (2012), matrix-related pores in shale can be classified as interP pore, intraP pores, and OM pores. FE-SEM images of sample SX5 having a medium TOC value are presented in Fig. 2a–f and show intraP pores in clay (Fig. 2a and b), intraP pores in quartz (Fig. 2c), limited and isolated OM pores with fractures (Fig. 2d), and fractures in clay (Fig. 2e). OM pores in sample SX5 are irregular, having diameters between 10 nm and 200 nm. IntraP pores are usually angular or linear, with different pore diameters ranging from 50 nm to 250 nm (Fig. 2c). Many intraP pores developed in clay minerals are irregular, having pore sizes of 100–500 nm. In addition, the micro­ fractures in Fig. 2d may be caused by the preparation stage or drying, and those in clay (Fig. 2e) may be formed through diagenesis or tectonism. Compared with all samples, the TOC content of sample XS1 is lowest, and pore sizes range from 50 nm to 500 nm (Fig. 2f–k). The FE-SEM images indicate intraP pores in clay (Fig. 2f), intercrystalline pores in pyrite (Fig. 2g), limited and isolated intraP pores in clay (Fig. 2h), irregular pores in OM (Fig. 2i), and fractures in OM (Fig. 2j). In OM and clay particle, abundant intraP pores are heterogeneously distributed (Fig. 2h and i). Many intercrystalline pores exist in the partially filled pyrite framboids, some of which are filled with clay minerals (Fig. 2g,i). Pyrite framboids in XS1 show porosity similar to that of other shales, such as Posidonia shale and Opalinus clay (Bernard et al., 2012; Rexer et al., 2014; Klaver et al., 2012; Houben et al., 2013). Fig. 2k–o exhibits the FE-SEM images of organic-rich shales from sample XS2 having high TOC values. The images show intraP pores in clay (Fig. 2k), intercrystalline pores in pyrite (Fig. 2l), limited and iso­ lated intraP pores in clay (Fig. 2m), irregular pores in OM–clay aggre­ gates (Fig. 2n), and connected microfractures in OM (Fig. 2j). IntraP pores are regularly developed within clay (Fig. 2k). OM pores are irregularly distributed in organic matter, showing faveolate shapes (Fig. 2ln,o), and some organic matter has no or very few nanopores (Fig. 2n,o), a phenomenon generally thought to arise from differences in OM composition (Curtis et al., 2012). Most of the pyrite framboids are completely filled with OM (Fig. 2l). Accordingly, the intraP pores in clay are well developed, making them the main nanoscale pores.

3.2. Methods A TOC content test was performed in accordance with Chinese In­ dustry Standard GB/T4762008, using a Leco CS230 analyzer. A vitrinite reflectance test was carried out in accordance with Chinese Industry Standard (SY/T5124-1995) using an Axio Imager Mlm microphotom­ eter. An X-ray diffraction analysis was performed using the Bruker D8 Advance XRD analyzer. The clay minerals were enriched using the flotation method, and the mineral composition was determined using the Rietveld semi-quantitative principle. Low-pressure N2 and CO2 adsorption were performed using the Autosorb iQ Station 1 Specific Surface Area Analyzer. During N2 adsorption, the pore surface area, pore volume, and pore size distribu­ tion of the shale samples were calculated using the DFT method (Gregg and Sing, 1982; Lastoskie et al., 1993; C. R. Clarkson et al., 2013a, 2013b). During CO2 adsorption, the surface areas, pore volumes, and pore distributions of the shale samples were calculated using the DFT model (Lastoskie et al., 1993; Seaton et al., 1989). Three shale samples having different levels of TOC content (XS1, SX5, and XS2, corresponding to low, medium, and high TOC values, respectively) were selected for pore morphology observation. The FESEM experiment was conducted at Suzhou University, China, using the Hitachi S-4700 cold FE-SEM to provide secondary electronic imaging with a super-resolution of 1.2 nm under a high vacuum of 15 KV, allowing clearer observation of the pore morphology of shale samples. All shale samples were coated with gold to increase their electrical conductivity, diminish accumulated negative charge, and improve im­ aging quality. 4. Results and analysis 4.1. Geochemistry and mineralogy

4.3. Quantitative analysis of N2 adsorption

The TOC content of all shale samples ranges from 0.60% to 6.05%, for an average of 2.48% (Table 1). The average TOC of Xiashihezi For­ mation is 3.01%, whereas Shanxi Formation is lower, at 1.88%. The results of Ro show a range of 0.65–1.37%, for an average of 0.91% (Table 1). The average Ro of Shanxi Formation and Xiashihezi Formation are 0.76% and 1.09%, respectively. The mineral composition of samples consists primarily of clay and quartz, with a small number of carbonate minerals and pyrite (Table 2). Clay mineral content is highest in the samples, ranging from 44.8% to 77.4%, for an average of 58.4%. Quartz is the primary mineral in the sample, with content ranging from 21.6% to 42.3%, for an average of 35.3%.

4.3.1. N2 adsorption curve According to the International Union of Pure and Applied Chemistry (IUPAC) classification of adsorption isotherm types (Gregg and Sing, 1982; Rouquerol et al., 1994), all the shale samples in this study correspond to the Type IV isotherm with a hysteresis loop (Fig. 3), as a result of capillary condensation occurring in the mesopore (Aplin et al., 2006), indicating that a large number of mesopores are developed in the shale samples. As a whole, the adsorption curve presented an inverse S shape. At the low-pressure stage of P/P0 < 0.4, the adsorption branch is coincident with the desorption branch and shows a slightly convex up­ ward trend with a lower rate, indicating that this stage is the transition from adsorption monolayer to multilayer. When 0.4 < P/P0 < 0.8, the adsorption curve begins to rise slowly; this stage is the multilayer adsorption stage. In the P/P0 > 0.8 segment, the adsorption curve rises sharply with increased pressure, but when the relative pressure is close

4.2. Pore morphology from FE-SEM Considering the influence of TOC content on pore morphology, FESEM analyses were performed on three samples (XS1, SX5, and XS2)

Table 1 Properties of Upper Carboniferous-Lower Permian shale in south margin of North China. Formation

Sample

Depth (m)

TOC (wt.%)

Ro (%)

Formation

Sample

Depth (m)

TOC (wt.%)

Ro (%)

Xiashihezi

XS7 XS6 XS5 XS4 XS3 XS2 XS1

797.1 830.7 838.9 875.3 889.4 895.7 908.0

2.23 1.90 3.74 2.42 4.10 6.05 0.60

1.21 0.78 0.75 1.37 1.01 0.92 1.06

Shanxi

SX6 SX5 SX4 SX3 SX2 SX1

961.2 970.8 981.1 995.1 1007.8 1012.6

2.28 0.80 2.66 2.08 1.54 1.90

0.91 0.83 0.95 0.68 0.65 0.7

3

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Table 2 Mineral compositions of the 13 shale samples. All the mineral contents are given in mass percent (%). MLIS ¼ Mixed-layer illite-smectite. Sample

Quartz

K-Feldspar

Plagioclase

Calcite

Dolomite

Siderite

Pyrite

Total clay

MLIS

Illite

Kaolinite

Chlorite

XS7 XS6 XS5 XS4 XS3 XS2 XS1 SX6 SX5 SX4 SX3 SX2 SX1

40.5 40.7 42.3 21.6 25.2 25.1 35.7 38.7 37.9 30.6 38.2 41.7 40

0 2.7 0 0 0 0 1.5 1.4 1.6 0.8 2.2 2.7 2.1

0 4.1 0 0 0 0 2.2 1.9 1.7 1 4 5.5 3.7

0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 2.1 0 0 0 0

0 1.5 1.5 1 1.5 3.4 0 2.4 6.4 1.3 7.7 3 7.3

0 0 0 0 0 0 0 0 0 0 1.4 2.3 1.2

59.5 51 56.2 77.4 73.3 71.5 60.6 55.6 50.3 66.3 46.5 44.8 45.7

4.8 29.6 25.9 7.0 7.3 6.4 26.1 27.2 32.7 23.9 30.2 30.5 29.7

0.6 2.0 0.6 0.8 0.7 1.4 1.8 8.9 6.5 4.0 4.7 4.0 5.0

44.6 15.3 23.0 59.6 52.0 51.5 25.5 16.7 8.6 31.2 9.3 8.1 8.2

9.5 4.1 6.7 10.1 13.2 12.2 7.3 2.8 2.5 7.3 2.3 2.2 2.7

to the saturated vapor pressure, adsorption saturation does not occur, because capillary condensation occurred in the macropore. Overall, samples from the Xiashihezi and Shanxi formations exhibit similar isotherm shapes, but N2 adsorption volumes have no significant relationship with TOC content, in contrast to the results obtained by Yang et al. (2016). This indicates that N2 adsorption volume may be controlled by TOC content and mineral composition, among other factors.

4.4. Quantitative analysis of CO2 adsorption In the classification provided by Brunauer et al. (1940), the CO2 adsorption curves of the shale samples are type I, which is indicative of microporous material. In the Xiashihezi Formation, XS4, having the highest clay content (clay ¼ 77.4%), shows the highest amount of adsorption (2.40 cm3/g), followed by XS3; XS1 has the least adsorption (1.51 cm3/g; Fig. 6a). In the Shanxi formation, SX4, having the highest clay content (clay ¼ 66.3%), displays the highest amount of adsorption (1.61 cm3/g), followed by XS1; XS3 has the least adsorption (1.14 cm3/g), indicating the least microporosity (Fig. 6b). Additionally, the Xiashihezi Formation’s volume of CO2 adsorption is significantly greater than that of the Shanxi Formation. Overall, volume of CO2 adsorption is positively correlated with clay content and weakly posi­ tively correlated with TOC content (Fig. 6), suggesting that micropores are at least partially related to OM and mineral composition. The rela­ tionship between micropore volume and pore width is shown in Fig. 7, based on the DFT model. In the Xiashihezi Formation, XS4 has the highest pore volume, at 0.46 nm, whereas XS1 has the lowest (Fig. 7a). In the Shanxi Formation, SX4 has the highest pore volume, at 0.62 nm, whereas SX3 has the lowest (Fig. 7b).

4.3.2. Pore-size distribution by N2 adsorption Pore size distributions obtained by N2 adsorption suggest that all shale samples from the Xiashihezi (Fig. 4a) and Shanxi formations (Fig. 4b) have similar pore size distributions with several peaks, indi­ cating that the shale reservoirs of the Xiashihezi and Shanxi formations have a certain degree of heterogeneity. According to the IUPAC classi­ fication standard, the pore size of the Xiashihezi and Shanxi formations is concentrated primarily in three intervals: micropore, mesopore, and macropore. The N2 adsorption curves of all samples show development of less peak distribution in the microporous and macroporous range and multipeak distribution in the mesoporous range (Fig. 4). Additionally, the peak values of mesopore are significantly higher than for micropore and macropore, indicating that the samples primarily developed meso­ pores. In the Xiashihezi Formation, more than 70% of the total mesopore volume comprises pores having a width of less than 20 nm. There are trimodal distributions at pore widths of about 12 nm, 18 nm, and 30 nm in XS1 and XS6; XS4 and XS7 exhibit single peaks at 3.5 nm and 5.5 nm; and XS5 has four peaks at pore widths of about 12 nm, 18 nm, 30 nm, and 45 nm (Fig. 4a). In the Shanxi Formation, more than 80% of the total mesopore volume comprises pores whose widths range from 6 nm to 30 nm. All shale samples develop double peaks at 12 nm and 18 nm, along with a series of smaller peaks (Fig. 4b). In addition, based on the N2 adsorption curves as a whole, all samples can be seen to have a single peak in the microporous and macroporous range, with the peak position concentrated at 1.4 nm and 70 nm, respectively (Fig. 4). Pore surface areas of samples from the Xiashihezi and Shanxi for­ mations show similar distribution characteristics (Fig. 5). In the Xishi­ hezi Formation, XS4 shows the highest surface area, followed by XS2 and XS3 in the microporous range, with a similar distribution character in the mesoporous range. In the Shanxi Formation (Fig. 5b), the same distribution character can be found in Fig. 5a. The surface areas of shale samples in the Xiashihezi Formation are higher than in the Shanxi Formation. In addition, the surface area of micropores and mesopores is obviously larger than that of macropores, suggesting that macropores are not conducive to the development of the surface area of nanoscale pores in shale. Surface area did not significantly increase with respect to TOC content (Fig. 5), indicating that micropores are related to more than just organic matter, and this result depends on complex factors such as mineral composition.

5. Discussion 5.1. Heterogeneity of nanopore structure 5.1.1. Relative deviation of pore structure parameters Relative deviation (RD) characterize the heterogeneity of pore structure of shale reservoir by expressing a single measurement’s degree of deviation from the average value. Based on the pore structure pa­ rameters (total pore volume, pore surface area, and average pore width) of a shale reservoir, the relative deviation of each pore structure parameter is calculated, after which the relative deviation can be calculated as � � �x x� RD ¼ ; (1) x where RD is a relative deviation, X a single measurement value, and X an average value. Accordingly, radar charts of relative deviation are applied to compare the deviations of the pore structure parameters with the average values (Fig. 8). The RD of the total pore volume of the Xiashihezi Formation is smaller than that of Shanxi Formation, whereas the RDs of the pore surface area and average pore width of the Xiashihezi Forma­ tion exceed those of the Shanxi Formation (Fig. 8a and b). Accordingly, surface area and average pore width of shale samples in the Shanxi Formation are more homogeneously distributed than in the Xiashihezi Formation. Overall, both formations have strong heterogeneity, which complicates desorption and diffusion of shale gas. 4

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Fig. 2. FE-SEM images of SX5 (a–e), XS1 (f–j) and XS2 (h–o) samples. (a), (b), (f), (h), (k), (l) and (m) IntraP pores in clay; (c) IntraP pores in quartz; (d), (i) Irregular and elliptical OM pores; (e) Fractures in clay; (g) IntraP pores in pyrite; (j) and (o) Fractures in OM; (n) OM pores in the OM-clay aggregates.

5.1.2. Fractal dimensions from N2 adsorption Fractal theory has been widely used to characterize irregular crushing systems without characteristic length scales (Mahamud and Novo, 2008). Fractal dimension calculated by adsorption is an effective and reliable petrophysical parameter for describing and quantifying irregular porous solid-pore structures and complex surfaces

(Mandelbrot, 1983; Yang et al., 2016). Several methods and models have been used to measure fractal dimensions, including the fractal Frenkel–Halsey–Hill (FHH) model (Jaroniec, 1995), fractal BET model (Brunauer et al., 1938; Avnir and Jaroniec, 1989), and thermodynamic method (Pfeifer et al., 1989). Each method has its advantages and dis­ advantages, but the fractal FHH model based on gas adsorption, which 5

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Fig. 3. N2 adsorption isotherm collected for Xiashihezi Formation samples (a) and Shanxi Formation samples (b).

Fig. 4. Plots of the dV(logd) vs pore width of Xiashihezi Formation (a) and Shanxi Formation (b).

Fig. 5. Plots of the dS(logd) vs pore width of Xiashihezi Formation (a) and Shanxi Formation (b).

has been confirmed to be a reliable approach, has been widely used in many porous materials. The FHH model has been described by Jaroniec (1995). Based on the FHH model, the relationship between lnV and ln(ln(Po/ P)) and the fractal dimensions are presented in Fig. 9 and Table 3. The curves are divided into two completely different gradient parts, which represent two important stages of the N2 adsorption process, including

monolayer–multilayer adsorption and pore infilling. Both segments show excellent linear correlation, with all correlation coefficients higher than 0.96, indicating that the studied shales are fractal. Pore fractal dimensions of 2.0–4.5 nm (D1) and those exceeding 4.5 nm (D2) were calculated according to the data distribution characteristics while assuming a boundary relative pressure of 0.5. This boundary point is highly consistent with previous works on shale and coal (Kuila and 6

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Fig. 6. CO2 adsorption curves obtained for all samples. (a) Xiashihezi Formation; (b) Shanxi Formation.

Fig. 7. Microspore volume distribution obtained by CO2 adsorption. (a) Xiashihezi Formation; (b) Shanxi Formation.

Fig. 8. Radar charts of relative deviation of pore structure parameters. (a) Xiashihezi Formation; (b) Shanxi Formation.

Prasad, 2013; Yu et al., 2017a, 2017b; Tang et al., 2015). In the Xiashihezi Formation, the fractal dimension of the first segment (D1) ranges from 2.7383 to 2.8237, and that of the second segment (D2) varies from 2.7738 to 2.9112 (Fig. 9a, Table 3). In the Shanxi Formation, the fractal dimension of the first segment (D1) ranges from 2.6910 to 2.7956, and that of the second segment (D2) varies from

2.7616 to 2.8306 (Fig. 9b, Table 3). The values of the two segments are close, conforming to the definition of the fractal dimension, and are considered to be effective (Fishman et al., 2012). Accordingly, the fractal dimensions (D1 and D2) can be used to describe the fractal characteristics of the shale within the definition range. Of the fractal dimensions in the two formations, the D1 has a narrower distribution 7

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Journal of Petroleum Science and Engineering 184 (2020) 106545

Fig. 9. Fractal dimension results calculated by N2 adsorption isotherms of Xiashihezi Formation (a) and Shanxi. Table 3 Fractal dimensions obtained from FHH model. R2 ¼ the correlation coefficient. Formation

Sample

Equation 2

Xiashihezi

XS7 XS6 XS5 XS4 XS3 XS2 XS1 SX6 SX5 SX4 SX3 SX2 SX1

y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼

Shanxi

0.1293 0.1861 0.2262 0.0888 0.1225 0.1282 0.1718 0.2371 0.2056 0.1694 0.2384 0.2320 0.2129

R2 x þ 1.8697 x þ 1.7471 x þ 1.5623 x þ 2.1075 x þ 1.8182 x þ 1.7750 x þ 1.7912 x þ 1.0344 x þ 1.2657 x þ 1.4386 x þ 1.2267 x þ 1.3652 x þ 1.5005

0.9938 0.9715 0.9992 0.9947 0.9887 0.9763 0.9878 0.9957 0.9861 0.9964 0.9848 0.9858 0.9767

K2 0.1293 0.1861 0.2262 0.0888 0.1225 0.1282 0.1718 0.2371 0.2056 0.1694 0.2384 0.2320 0.2129

D2

Equation 1

2.8707 2.8139 2.7738 2.9112 2.8775 2.8718 2.8282 2.7629 2.7944 2.8306 2.7616 2.7680 2.7871

y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼ y¼

0.2534 0.2617 0.2503 0.1763 0.1769 0.1808 0.2504 0.2582 0.2363 0.2044 0.3090 0.2897 0.2955

R2 xþ xþ xþ xþ xþ xþ xþ xþ xþ xþ xþ xþ xþ

1.6353 1.5607 1.5201 1.9469 1.7084 1.6635 1.6224 0.9745 1.1785 1.3606 1.0571 1.2165 1.2972

0.9965 0.9999 0.9992 0.9916 0.9955 0.9971 0.9994 1.0000 0.9999 0.9997 0.9998 0.9999 0.9999

K1 0.2534 0.2617 0.2503 0.1763 0.1769 0.1808 0.2504 0.2582 0.2363 0.2044 0.3090 0.2897 0.2955

D1 2.7466 2.7383 2.7497 2.8237 2.8231 2.8192 2.7496 2.7418 2.7637 2.7956 2.6910 2.7103 2.7045

range, positive and negative relationships occur in smaller and larger mesoporous intervals, respectively, suggesting that fractural dimension values have a complicated relationship with mesopore volume. The re­ sults show that the fractal dimension is positively correlated with total pore volume and mesoporous volume, with correlation coefficients of 0.5166 and 0.8083, respectively (Fig. 11e). Total pore volume increases with the development of macropores or microfractures, but D1 and D2 are related primarily to micropore complexity. The relationships be­ tween the fractal dimension and average pore size are negative (Fig. 10f), suggesting a more irregular and complex pore structure within a small pore range. Overall, pore combinations of different shapes and sizes form a complex pore system, and the fractal dimension has no significant correlation with the total pore volume and mesopore volume of shale.

range in both formations, and the D2 of the Shanxi Formation has a narrower distribution range from 2.7616 to 2.8306, for an average of 2.7841, but in the Xiashihezi Formation it ranges from 2.7738 to 2.9112, for an average of 2.8496 (Fig. 9, Table 3). Findings concerning fractal dimensions indicate that the shale reservoirs of the Shanxi and Xia­ shihezi formations are strongly heterogeneous, consistent with the re­ sults of relative deviation. The higher average fractal dimension indicates that the pore structure of the studied shales is more compli­ cated and that the law of self-similarity is followed by different het­ erogeneous structures in shale reservoirs. 5.2. Relationship between fractal dimension and pore structure parameters To investigate the effect of heterogeneity on pore structure, the related plots of the fractal dimension versus pore structure parameters are given in Fig. 10. The correlation between fractal dimension and pore structure is obvious and significant, showing that the fractal dimension can be regarded as a reliable index with which to reveal the complexity and heterogeneity of the studied shales’ pore structure (Fig. 11). Positive correlations exist between fractal dimensions and micropore volume, which have correlation coefficients of 0.7829 and 0.8662, respectively (Fig. 11a). Relationships between fractal dimension values and meso­ pore volume are complicated, with a parabolic trend existing between them within a certain range, except in the area indicated by the square (Fig. 11b). Negative relationships are observed between fractal dimen­ sion values and macropore volume (Fig. 11c). Relationships between fractal dimensions and total pore volume are also complicated: a similar parabolic trend exists between them within a certain range, except in the square (Fig. 11d), which is consistent with the mesopore volume (Fig. 11b). All the foregoing results indicate that shale having a higher fractural dimension values tends to have a greater micropore volume and a lesser macropore volume. Moreover, within the mesoporous

5.3. Relationship between mineral composition and pore structure parameters Fig. 11 gives related plots for investigation of the effect of mineral composition on pore structure in transitional coal-bearing shales. Clay minerals have a significant positive relationship with the micropore volume, with a correlation coefficient of 0.8026 (Fig. 11a)—much higher than the correlation between micropore volume and TOC con­ tent. Quartz has a negative relationship with micropore volume (Fig. 11a). However, no relationship of clay, quartz, and mesopore volume is apparent (Fig. 11b). Compared with Figs. 11a and c exhibits the opposite relationship between clay, quartz, and mesopore volume in the macroporous range. These results suggest that in the middle to highmaturity stage of the studied shales, clay minerals contribute more to the development of micropores than organic matter does, whereas quartz dominates in the development of macropores—and that mesopores are controlled by these factors. The correlations among clay minerals, quartz, and average pore 8

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Fig. 10. Plots of fractal dimensions vs pore structure parameters. (a) Micropore volume; (b) Mesopore volume; (c) Macropore volume; (d) Total pore volume; (e) Pore surface area; (f) Average pore size.

width show similar trends for macropore volume (Fig. 11d), indicating that quartz and clay minerals have different effects on the pore struc­ tures of the studied shales. Beyond the relationships between clay minerals, quartz and surface area are also similar to micropore volume (Fig. 11e), suggesting that micropores are related to surface area development. In addition, the relationships among clay minerals, quartz, and fractal dimensions are obvious, featuring larger correlation coefficients (R2 > 0.6; Fig. 11f). These results suggest that clay minerals develop many micropores and together with OM change shale’s pore structure, prompting increases in surface area and decreases in average pore width, whereas quartz typically contains a certain amount of macropores and thus has opposite relationships with surface area and average pore width. Overall, clay-rich shales, featuring as they do limited OM content

and moderate maturity, feature substantive contributions of clay to micropore structure, so that in combination with OM they change pore structure. Although higher clay content could bring the collapse of OM pores, sufficient numbers of rigid grains can partially preserve them. Accordingly, nanopores in clay minerals still occupy the major part in the studied shales. 5.4. Relationship between TOC, Ro, and pore structure parameters Fig. 12 shows the related plots for study of the relationship between TOC content, Ro, and pore structure parameters. The TOC contents of 13 shale samples show a weak positive relationship (R2 < 0.80) with the micropore volume (Fig. 12a), no apparent correlation with mesopore volume (Fig. 12b), and a weak negative correlation with macropore 9

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Journal of Petroleum Science and Engineering 184 (2020) 106545

Fig. 11. Plots of the clay, quartz contents vs pore structure parameters. (a) Micropore volume; (b) Mesopore volume; (c) Macropore volume; (d) Average pore width; (e) Pore surface area; (f) Fractal dimension (D1).

volume (Fig. 12c). Compared with TOC content, Ro has similar re­ lationships with pore volume (Fig. 12a–c). Overall, increases in the content and maturity of OM contribute more to micropores than to mesopores and inhibit the development of macropores. What’s more, these relationships indicate that the content and maturity of OM partly determine pore volume, although other factors also play important roles. A negative relationship exists between Ro and average pore width (Fig. 12d), suggesting average pore size noticeably decreases with in­ creases in the thermal evolution of OM and that more micropores will be developed in OM with enhanced hydrocarbon generation. Similar re­ lationships exist between TOC content and micropore volume (Fig. 12d). The positive correlation between Ro and surface area is obvious, but TOC content shows a weak positive correlation with surface area (Fig. 12e). These weak relationships indicate that the content and maturity of OM influence the development of the pore structure in the studied shales to some degree. Increases in micropore surface area and decreases in average pore size result in a positive correlation between fractal dimension and TOC content (Fig. 12f).

Based on the fractal results, it is clear that the studied shales are fractal, with fractal dimensions in Xiashihezi and Shanxi formations varying from 2.7383 to 2.8237 and from 2.6910 to 2.7956, respectively. Fig. 12f shows that TOC and Ro have a positive relationship with fractal dimension. Shale having higher TOC content tends to develop more heterogeneous micropores, leading to a more complex pore system­ —something not conducive to gas desorption and flow (Aplin and Macquaker, 2011). 5.5. Evolution of pore under different clay content and thermal mature stage Evolution of pore structure in shale is a complex process that is usually associated with compaction, the transformation of minerals, hydrocarbon generation, and dissolution, among other factors (Jarvie et al., 2007; Curtis, 2002; Mastalerz et al., 2013). Of these, trans­ formation of clay minerals and the thermal maturity of OM may be the most significant influences on the evolution of pore structure in 10

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Journal of Petroleum Science and Engineering 184 (2020) 106545

Fig. 12. Relationships between TOC content, Ro and a pore structure parameter. (a) Micropore volume; (b) Mesopore volume; (c) Macropore volume; (d) Average pore width; (e) Pore surface area; (f) Fractal dimension (D1).

transitional coal-bearing shale. Previous studies have indicated that pores in shale are closely related to hydrocarbon generation, with abundant OM pores generated during the maturation of organic matter (Bernard et al., 2012; CR Clarkson et al., 2013a, 2013b; Qi et al., 2019). Different degrees of thermal maturity in OM determine the character­ istics of pore structure in shale, and many pores are generated during the formation and evolution of clay minerals (Bernard et al., 2012). In addition, high levels of clay content suggest that many terrigenous materials participate in the fluvial sedimentary facies, with clay content directly affecting the development of pores in clay and clay–organic matter complex (Mortland, 1970; Mortland et al., 1986). Diagenesis is closely related to clay and quartz content in the sedimentary process (Pytte and Reynolds, 1989; Loucks et al., 2012; Dutton and Loucks, 2010). Clay’s ductility, compactness, and easy deformation give it un­ stable mechanical properties. Quartz is a hard particle that resizes compaction and forms a focal point around more resilient particles such as clay and OM, whose chemical properties are also relatively stable and which generally do not dissolve during diagenesis (Pittman, 1979;

Loucks et al., 2012). Accordingly, C/Q is a more objective parameter indicating provenance and diagenetic conditions, which can reflect nanopore evolution combined with thermal maturity. According to the burial history and thermal maturation state of the south margin of North China (Fig. 13), the transitional coal-bearing shales experienced several strong tectonic thermal events, and the OM reached the wet gas stage with a limited hydrocarbon generation ca­ pacity. Therefore, these OM pores, caused by hydrocarbon generation and expulsion, account for only part of the nanoscale pores. In addition, FE-SEM images show a substantial quantity of interP pores and intraP pores of clay minerals in all shale samples, indicating that the pores of clay minerals play a dominant role in nanoscale pores in studied shale (Fig. 2). To study the evolution of nanopore under different conditions of clay content and stage of thermal maturity, we combine ratio of clay content to quartz content (C/Q) and vitrinite reflectance (Ro) to fuel further discussion (Fig. 14) based on the data from the XJ1 well and Bu et al. (2015), Wang et al. (2015), and Yu et al. (2017a, 2017b). The Ro of all 11

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Journal of Petroleum Science and Engineering 184 (2020) 106545

Fig. 13. Burial history and thermal maturation state of the south margin of North China from the Late Carboniferous to the present (Yu et al., 2018). P2x and P1s stand for Xiashihezi and Shanxi formations, respectively.

samples shows a range of 0.58–1.42%, for an average of 1.03%, indi­ cating the early oil to wet gas stage. The C/Q exhibits a range of 1.07–3.58, for an average of 1.80, indicating that abundance of terrig­ enous material and suitable diagenetic conditions are favorable to the development of clay minerals. Based on the relationships of C/Q, Ro, and nanopore type, Fig. 14 shows that nanopore evolution depends on stage of thermal maturity and clay content. In the early oil (0.5% < Ro < 0.7%) and low clay content (1.0 < C/Q < 1.5) stage, the low degree of the thermal evolution of OM prevents development of kerogen micropores and diminishes the quantity of acidic fluid, producing a weak physical combination and chemical corrosion between OM and clay minerals. Consequently, the macropores take the main place in shale reservoirs (Fig. 14). In the main oil to late oil (0.7% < Ro < 1.3%) and medium clay content (1.5 < C/Q < 3.0) stage, hydrocarbon generation of OM leads to the gradual development of pores in kerogen and more acidic fluids that dissolve clay minerals, so that mesopores take the main place in shale reservoirs, exhibiting a parabolic trend (Fig. 14). In the wet gas

(1.3% < Ro) and high clay content (3.0 < C/Q < 4.0) stage, increased intensity of hydrocarbon generation and clay mineral content caused development of more complexes of OM and clay, so that many micro­ pores are produced, which thus play a major role in shale reservoirs (Fig. 14)—indicating that the high clay content and strong hydrocarbon generation contribute to the development of micropores. Overall, intraP mesopores in clay minerals are primarily accompanied by increases in clay content, which are part of an effect pore network and gas storage space. Furthermore, organic matter can generate abundant pores in the process of thermal maturation, with OM pores developed in kerogen at the beginning of thermal maturation of hydrocarbon, so that with the progress of thermal evolution (0.58% < Ro < 1.42%) the number of micropores increases rapidly. The types of pores within the network during the different stages of evolution, which determine the number of pores of different diameters and the connectivity of those pores, are a major controlling factor in gas storage, migration, and reservoir permeability.

Fig. 14. The evolution path of nanopore in different thermal maturity and clay/quartz stage (Bu et al., 2015;Yu et al., 2017a; Wang et al., 2015). 12

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6. Conclusions

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Transitional coal-bearing shale reservoirs are fractal and have strong heterogeneity. The fractal dimensions of pores are principally related to micropores and macropores. In the microporous range, the fractal di­ mensions have a positive and negative relationship with micropore and macropore volume, respectively, and have no relationship with meso­ pore volume. The higher the fractal dimension, the larger the surface area and the larger the pore volume. The strong heterogeneity of shale reservoirs’ pore structure, which is controlled primarily by differences of mineral composition in different sedimentary environments and by diagenetic evolution, increases with increased clay content and decreased quartz content. The morphology of nanopores of transitional shale is quite different from that of marine shale, suggesting different pore characteristics and evolution processes. The intraP pores in clay are dominant, including parallel plate holes, slit-shaped pores, and intergranular cone-shaped pores, as a result of abundant terrigenous material and suitable diage­ netic conditions. As a result of limited hydrocarbon generation, OM pores are poorly developed and are partially filled with clay minerals and pyrite framboids. Shale samples having a higher clay content develop more micropores and thus have a more complicated pore system. Evolution of nanopore type depends on differences in clay content and stage of thermal maturity. In the early oil (0.5% < Ro < 0.7%) and low clay content (1.0 < C/Q < 1.5) stage, OM’s low degree of thermal evolution prevents the development of kerogen pores and leads to generation of less acidic fluid during decarboxylation of kerogen, resulting in a weak physical combination and chemical corrosion be­ tween OM and clay minerals. Consequently, the macropores take the main place in the pore structure. In the main to late oil (0.7% < Ro < 1.3%) and medium clay content (1.5 < C/Q < 3.0) stage, hydrocarbon generation of OM leads to the gradual development of pores in kerogen and more acidic fluids that dissolve clay minerals, so that mesopores are dominant in shale reservoirs. In the wet gas (1.3% < Ro) and high clay content (3.0 < C/Q < 4.0) stage, with in­ creases in hydrocarbon generation intensity and clay mineral content, more complexes of OM and clay are developed and greater quantities of micropores produced, so that micropores play a major role in shale reservoirs. The types of pores within the network during the different stages of evolution, which determine the numbers of pores of different diameters as well as their connectivity, are a major controlling factor in gas storage, migration, and reservoir permeability. Acknowledgment This research was financially supported by the National Natural Science Foundation of China (Grant Nos. 41530315, 41372213), the National Science and Technology Major Project of China (Grant Nos. 2016ZX05066003, 2017ZX05064006), and Strategic Priority Research Program of the Chinese Academy of Sciences (Grant No. XDA05030100). Appendix A. Supplementary data Supplementary data to this article can be found online at https://doi. org/10.1016/j.petrol.2019.106545. References Aplin, A.C., Macquaker, J.H.S., 2011. Mudstone diversity: origin and implications for source, seal, and reservoir properties in petroleum systems. AAPG (Am. Assoc. Pet. Geol.) Bull. 95 (12), 2031–2059. Aplin, A.C., Matenaar, I.F., Mccarty, D.K., Van, D.P.B.A., 2006. Influence of mechanical compaction and clay mineral diagenesis on the microfabric and pore-scale properties of deep-water Gulf of Mexico mudstones. Clay Clay Miner. 54 (4), 500–514.

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