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Characteristics of the Nanoscale Pore Structure in Northwestern Hunan Shale Gas Reservoirs Using Field Emission Scanning Electron Microscopy, High-Pressure Mercury Intrusion, and Gas Adsorption Yang Wang,*,†,‡ Yanming Zhu,†,‡ Shangbin Chen,†,‡ and Wu Li‡ †

Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process, Ministry of Education, China University of Mining and Technology, Xuzhou, Jiangsu 221008, People’s Republic of China ‡ School of Resources and Earth Science, China University of Mining and Technology, Xuzhou, Jiangsu 221116, People’s Republic of China ABSTRACT: Nanostructure morphology and pore size distributions (PSDs) of 10 samples from the Lower Cambrian Niutitang Formation in northwestern Hunan were investigated using field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion (HPMI), low-pressure nitrogen gas adsorption (LP-N2GA), and carbon dioxide gas adsorption (LP-CO2GA). In combination with the geochemical parameters and mineral composition, the factors influencing the nanoscale pore structure were analyzed. The results indicate that the pores in the shale reservoirs are generally nanoscale and can be classified into four types: organic pores, intraparticle pores, interparticle pores, and microfractures, of which the most common are organic nanopores and interparticle pores between clay particles. The nanoscale pores primarily consist of slit-shaped pores with parallel plates and ink-bottle-type pores. The combination of the HPMI, LP-N2GA, and LP-CO2GA curves enabled the creation of the PSD for micro-, meso-, and macroporosities. The PSDs are either bi- or multimodal and include not only predominant mesopores (2−50 nm) but also a certain amount of micropores (50 nm). Micro- and mesopores with a diameter less than 50 nm amount to most of the pore volume, whereas those with a diameter less than 5 nm amount to most of the specific surface area. The total organic carbon (TOC) and clay minerals are the primary factors affecting the nanoscale pore (diameter < 1 μm, especially micro- and mesopores) structure characteristics, whereas micropores are predominantly controlled by the content of the TOC, and meso−macropores are primarily determined by the content of clay minerals, in particular the illite content.

1. INTRODUCTION Shale gas is an important unconventional gas resource. More and more research and exploration works about shale gas have been conducted in China while observing the rapid development of the shale gas industry in North America. A shale gas reservoir is a self-contained source reservoir system. Hydrocarbon gases are derived from the organic matter within the shales through biogenic and/or thermogenic processes.1,2 Abundant gas can be stored in pores and fractures as free gas, adsorbed on organic matter and clay particle surfaces, or dissolved in bitumen and kerogen.3,4 Shales contain extensive nanoscale pores, and the characterization of these pores is of great significance for recognizing the distribution and enrichment conditions of the shale gas. The pore structure types and evolution characteristics have a significant impact on the gas storage and flow capacity of shales. Nevertheless, the pore structure of shale gas reservoirs is difficult to characterize, and shales commonly contain a wide pore size distribution (PSD), necessitating the use of various techniques to investigate the entire PSD. Various techniques or hybrid techniques are applied to study the complex pore structure of shales. These methods include mercury injection capillary pressure, low-pressure N2 and CO2 gas adsorption,5−12 and small-angle neutron scattering (SANS) and ultra-small-angle neutron scattering (USANS) techniques8,12−14 to obtain the surface area and PSD. Focused ion beam scanning electron microscopy (FIB-SEM) and field © 2014 American Chemical Society

emission scanning electron microscopy/transmision electron microscopy (FE-SEM/TEM) have also been used to study the shapes, sizes, and distributions of pores in shales.12,15−17 In comparison to the numerous studies of shale gas reservoirs in North America, there are few similar studies of these reservoirs in China. Three sequences of marine shales are present in southern China, including the Lower Cambrian, Lower Silurian, and Upper Permian shales.18 Of the three formations, the Lower Cambrian Niutitang Formation in northwestern Hunan exhibits great thickness and total organic carbon (TOC) and is now regarded as a good target for marine shale gas exploration and development. On the basis of the above understanding, the purpose of this paper is to provide both quantitative and visual qualitative analyses of the gas shale reservoir pore system. The pore system was characterized qualitatively using FE-SEM images. Quantitative analyses using high-pressure mercury intrusion (HPMI), low-pressure nitrogen gas adsorption (LP-N2GA), and carbon dioxide gas adsorption (LP-CO2GA) were used to determine the PSD of 10 samples of Lower Cambrian Niutitang Formation gas shale. The PSD is between 20 nm and 100 μm based on HPMI analysis, between 1 and 20 nm based on LP-N2GA analysis, and between 0.35 and 1 nm based on LPReceived: October 31, 2013 Revised: January 28, 2014 Published: January 29, 2014 945

dx.doi.org/10.1021/ef402159e | Energy Fuels 2014, 28, 945−955

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organic matter in the black shales of the Niutitang Formation is predominantly type I,21 with equivalent vitrinite reflectance values in the range of 2.0−3.5%.19 The geologic conditions of shale gas development in northwestern Hunan are similar to those of the Appalachian Basin Province of the eastern United States, which has been recognized as a productive area. Both areas contain organic-rich shale deposited in a Paleozoic marine environment. Exploration activities within and around the study area have been initiated by many companies, including Petrochina, Sinpec, and China Huadian Corporation. Recently, the Bureau of Coal Geology of Hunan Province took an interest in this area and developed plans to drill several shale gas exploratory wells. All of these efforts illustrate the good exploration prospects of this region.

CO2GA analysis. This paper will also discuss the relationships between the PSD and the composition and geochemistry of the shale.

2. GEOLOGICAL SETTING The study area is located in the southeastern Upper Yangtze platformal fold belt of the Yangtze paraplatform. The Lower Cambrian Niutitang Formation has been recognized as an effective source rock within and around northwestern Hunan. The stratigraphy primarily consists of black shale, dark gray shale, silty mudstone, and siliceous shale with abundant plankton (for example, red or brown algae). The bottom of the Niutitang Formation is richly carbonaceous and consists of dark gray/black shale, dark gray siltstones, and siltstones. The colors lighten upward, with gray/gray−green calcareous finegrained sandstones and siltstones present in the middle of the formation and yellow−green shales and siliceous shales at the top, interbedded with sparse dolomite. All of southern China experienced transgression during the Qiongzusi period of the Early Cambrian. The organic-rich source rocks forming oil and gas layers formed in an undercompensated basin in the study area during the Early Cambrian.20 This region has the characteristics of a ramp environment from the northwest to southeast. Because of the tectonic setting and sedimentary environment of the ancient Jiangnan land basement, the sedimentary thickness of the Lower Cambrian Niutitang Formation decreases from northwest to southeast (Figure 1). The Niutitang Formation is 140−180 m thick and has its depositional centers in the Longshan−Sangzhi area and widely distributed elsewhere in the study area. TOC contents of the black shales ranging from 3.9 to 15.4%. The kerogen of the

3. EXPERIMENTAL SECTION 3.1. Sample Collection and Preparation. Because few shale gas wells have been drilled in this area, it was thus difficult to obtain cores to better define the shale gas reservoir experimentally. In this study, then, outcrop samples were relied on instead of cores. The fresh outcrop samples are representative of a great extent of the primary zone of interest. The samples were used to describe the pore morphology qualitatively and analyze the PSD quantitatively. Table 1 lists the shale samples analyzed, including the location where they were collected, their TOC content, and thermal maturity.

Table 1. Shale Sample Propertiesa

a

sampling point

sample ID

TOC (wt %)

Ro (%)

Luxi Luxi Luxi Luxi Luxi Guzhang Guzhang Guzhang Zhangjiajie Zhangjiajie

Hw-1 Hw-2 Hw-3 Hw-4 Hw-5 Hw-6 Hw-7 Hw-8 Hw-9 Hw-10

14.2 11.6 11.0 15.4 4.4 7.9 14.6 10.6 3.9 9.7

2.74 ndb 3.07 nd 2.67 nd 2.45 nd nd 2.44

TOC, total organic carbon; Ro, vitrinite reflectance. bNo data.

3.2. Experimental Protocol. The fluid invasion methods that have successfully been applied for pore structure characterization of shale include a combination of HPMI, which requires enormous injection pressures to approach the finest pores, and low-pressure adsorption using N2 and CO2 as adsorbates.5,6,22,23 The mercury intrusion analysis was performed at the Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process, Ministry of Education, China University of Mining and Technology, on vacuum-dried samples using a mercury porosimeter (AutoPore IV 9510, Micrometrics Instrument) at pressures up to 60 000 psia. The low-pressure N2 and CO2 isotherm analyses were performed at the Key Laboratory of Coal Preparation and Purification, Ministry of Education, China University of Mining and Technology. The samples (mass between 0.9632 and 1.045 47 g) prepared for adsorption analysis were first outgassed at 120 °C under high vacuum in the apparatus to remove air, free water, and other gases. N2 adsorption isotherms were obtained at 77 K using a Quantachrome Autosorb-1 on 60-mesh samples. CO2 adsorption data (273 K) were also obtained on the same apparatus. The N2 data collected on the crushed samples were interpreted applying Langmuir analyses and multi-point Brunauer−Emmett−Teller (BET) for surface area and density functional theory (DFT)24,25 analyses for PSD. The DFT molecular model provides a more accurate approach for pore size analysis and can be used for PSD determination in the micropore scale

Figure 1. Thickness of the Niutitang Formation and TOC distribution of black shales (modified with permission from ref 19). 946


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Figure 2. Organic matter pores in black shales of the Niutitang Formation. OM = organic matter. (a) Organic matter pores and dissolution pores (Hw-5; TOC = 4.4%). (b) Enlargement of the frame in panel a. (M and N) Element spectrum of panel a areas M and N. (c) Honeycomb organic matter pores of microfossils (Hw-1; TOC = 14.2%). (d) Organic matter pores in an organo−clay complex (Hw-7; TOC = 14.6%). (o) XRD pattern of shale sample Hw-5. (p) XRD pattern of shale sample Hw-7. as well as mesopore scale.26 Therefore, in this study, the DFT model was used for PSD determination because micropores play an

important role in the pore structure of the shales. CO2 adsorption data were analyzed using the BET, Langmuir, and DFT models. A 947


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Figure 3. FE-SEM images of black shales from the Niutitang Formation showing the (e−g) interparticle pores, (g and h) intraparticle pores, and (i and j) cracks. OM = organic matter. N2GA, and mesoporosity (diameter between 30 and 50 nm) and macroporosity (diameter > 50 nm) derived from HPMI. In this work, the specimens were examined on an X-ray diffraction (XRD) instrument (RIGAKU D/Max-3B diffractometer) at the Experimental Research Center of East China Branch, SINOPEC, and the intensity data were collected in the 2θ range of 5−80° at steps of 0.02° (Cu Kα). Si was used as the internal standard. A total of 10 samples (10 × 10 mm) that were subjected to ion milling using an Ar beam source were observed and analyzed at the State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum, Beijing Campus (CUP), using FE-SEM (Quanta 200F) equipped with an energy-dispersive spectrometer (EDS). These analyses were performed at a temperature of 24 °C and a humidity level of 35%.

detailed description of these theories and techniques can be found in the work by Gregg and Sing.27 To better describe PSD for micro-, meso-, and macroporosities, we have attempted to combine the HPMI, LP-N2GA, and LP-CO2GA curves. As suggested by Clarkson et al.,12 for some pore geometries (for example, slit pores), pore bodies are the same as pore throats; in this case, in theory, LP-N2GA, LP-CO2GA, and HPMI analyses should yield similar results. Kuila and Prasad28 have also suggested that the PSD curves from N2 adsorption and mercury instrusion capillary pressure shown good correlations. Therefore, we just neglect the intrinsic characteristics of the HPMI, LP-N2GA, and LP-CO2GA techniques and connect the PSD [dV/d(log w)] curves of the shale samples with microporosity (diameter < 2 nm) derived from LPCO2GA, mesoporosity (2 nm < diameter < 30 nm) derived from LP948


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Table 2. Mineralogical Composition of the Shale Samples Based on XRD Analysis relative percent (%)

a

sample

quartz

feldspar

carbonate

pyrite

total claya

illite

montmorillonite

chlorite

montmorillonite−illite-mixed layer


58.7 53.6 46.2 45.8 62.1 64.1 49.6 64.8 51.3 61.1

4.6 4.7 18.2 4.8 10.2 5.4 3.2 2.6 12.8 3.4

6.0 2.9 2.2 3.1 4.1 3.2 8.3 1.3 2.2 2.6

1.2 2.3 2.2 1.4 2.1 1.4 2.3 3.9 2.8 1.1

26.4 33.9 30.3 42.2 20.1 24.3 35.3 24.5 28.7 30.3

13.2 23.7 6.4 28.7 15.3 17.0 18.4 13.0 14.1 14.9

2.6 3.4 4.5 1.7 1.6 2.4 4.2 3.2 2.6 3.6

4.8 1.7 3.0 8.4 0.8 1.7 3.5 2.2 6.3 7.0

5.8 5.1 16.4 3.4 2.4 3.2 9.2 6.1 5.7 4.8

Total clay = illite + montmorillonite chlorite + montmorillonite−illite-mixed layer.

Table 3. Structural Pore Parameters of Black Shale Samples pore structure/surface area data sample number

TOC (%)

skeletal density (g/cm3)

bulk density (g/cm3)

Hg total porosity (%)

Hg macropore volume (cm3/100 g)

N2 BET surface area (m2/g)

N2 DFT mesopore volume (cm3/100 g)

CO2 micropore volume (cm3/100 g)

CO2 equivalent surface area (m2/g)


14.2 11.6 11.0 15.4 4.4 7.9 14.6 10.6 3.9 9.7

2.04 2.05 2.16 1.94 2.07 1.87 2.23 2.00 2.07 1.89

1.96 1.98 2.11 1.83 2.04 1.82 2.13 1.9517 2.02 1.81

4.05 3.59 2.29 5.42 1.13 3.16 4.73 2.64 2.16 4.49

0.37 0.79 0.36 1.20 0.38 0.51 0.71 0.60 0.53 0.72

17.15 21.54 25.89 34.33 11.16 7.43 13.72 6.54 4.45 17.01

3.02 2.29 3.71 4.07 2.36 1.33 2.91 1.49 2.25 3.25

2.15 1.52 1.47 2.18 0.57 0.64 2.25 1.17 0.65 1.48

76.36 52.23 51.19 79.77 18.85 21.30 78.49 39.68 21.01 53.06

4. RESULTS AND DISCUSSION 4.1. Qualitative Description of Pore Morphology. Over the past few years, a number of researchers have observed the pore appearance features and identified many pore types in a variety of shales by means of FE-SEM and TEM. Slatt and O’Brien29 identified six types of pores, such as interparticle pores produced by flocculation, organoporosity produced during burial and maturation, intraparticle pores from organisms, intraparticle pores within mineral grains, microchannels in the shale matrix, and microfractures based on a study of the Barnett and Woodford Shales. A pore classification scheme by Loucks et al.30 consisting of three major matrixrelated pore types: interparticle pores, intraparticle pores, and organic matter pores. Qualitative and semi-quantitative descriptions of pore morphology have an important effect in studying the causes of microscopic pores and developing pore classifications in shale. The International Union of Pure and Applied Chemistry (IUPAC)31 pore size classification will be used to describe the pore types in this paper. Following the IUPAC recommendations, pores are classified according to their diameter size as micropores (50 nm). On the basis of research of pore classifications of marine shales in North America, qualitative and semi-quantitative observations combined with EDS X-ray characteristics of various elements were performed to analyze the appearance of pore features in the Niutitang Formation shale in northwestern Hunan. The results show that nanopores are well-developed in the shale and the micro- and mesopores are found primarily within and among the organic material and

display such features as schistose-like texture and pit, oval, and honeycomb shapes (panels a−d of Figure 2). Furthermore, the coexistence of organic matter and pyrite grains is widespread and exhibits a relationship of one wrapping around the other (Figure 2a). Certain amounts of the organic matter and clay minerals have converted to an organo−clay complex developing plentiful micropores (Figure 2d). In contrast with the organic pores, the interparticle pores are usually observed at particle contact points (panels e−g Figure 3) and are polygonal or elongated. These pores are primary pores, are generally distributed irregularly in the matrix, and are usually larger than 100 nm. A great deal of the flocculated clay mineral aggregates are observed in the samples and display a “card house” structure of individual edge−face- or edge−edgeoriented flakes and/or domains of face−face-oriented flakes.32 The card house structure in the flocculated clay mineral aggregates provides pores between the flocs that are larger than 30 nm (Figure 3h). These pores may be interconnected to form permeability pathways. In addition, intraparticle pores are also well-developed and consist of pores between the clay mineral layers (panels g and j of Figure 3) and corrosion pores, resulting from the dissolution of certain unstable mineral, such as quartz, carbonate, feldspar, and mica, under conditions of burial. In addition to pores, microfractures usually develop in particles, on the edges of clastic particles (Figure 3j), or within organic matter (Figure 3i). Fractures 2 μm long and 20−400 nm wide are present as obvious zigzags with great extensibility. The microfractures are links connecting micropores and macrocracks, serving an important role in shale gas transfusion. 949


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Figure 4. Relationships between the porosity and (a) TOC and (b) total clay content.

Figure 5. Incremental pore volume plots for the 10 shale samples. Note the three styles of PSD.

4.2. Mineralogical Characterization of the Niutitang Formation. XRD was used to qualitatively and quantitatively analyze the 10 black shale samples (Table 2 and panels o and p of Figure 2). The results indicate that the Niutitang Formation has an extremely complex mineral composition and that quartz and clay are the primary mineral constituents, with a mean content of 55.7% (45.8−64.8%) and 29.6% (20.1−42.2%), respectively. The other mineral constituents are feldspar, carbonate, pyrite, dolomite, and traces of unidentified amorphous substances. It is suggested that all of the samples contain clay minerals consisting of illite, montmorillonite, montmorillonite−illite-mixed layers, and chlorite. Illite is the most abundant of the clay minerals, ranging from 6.4 to 28.7%, with a mean value of 15.5%. Quartz grains in the black shales originated as exogenous detrital particles and are present as discrete layers interbedded in the shale. Carbonate minerals are present primarily in the form of crack fillings and cements. The target strata formed in a deep-water reducing environment contain much pyrite in local areas. 4.3. Quantitative Analyses of PSD. On the basis of the FE-SEM images of the black shales, the pore network is

complex and shows the characteristics of a combination of various pore types. Although the FE-SEM imaging can provide much qualitative information on the pore types and sizes in the shales, HPMI, LP-N2GA, and LP-CO2GA were used to quantitatively characterize the PSD of the 10 samples. The mercury porosimetry analysis reveals total porosities ranging between 1.13 and 5.42% in the 10 samples (Table 3), with a mean value of 3.37%. The porosity correlates positively with the TOC (R2 = 0.661; Figure 4a) and total clay content (R2 = 0.604; Figure 4b). 4.3.1. HPMI Isotherms. HPMI analyses were carried out to quantitatively characterize the macro- and mesopores. It is also important to know that HPMI analyzes pore throats and not pore diameters, in contrast to low-pressure nitrogen or carbon dioxide adsorption techniques. Incremental intrusion plots using mercury intrusion (Figure 5) suggest significant pore volumes in the meso−macropore range and show uni- or multimodal PSDs among the samples. Samples Hw-1, Hw-5, Hw-7, and Hw-9 are dominated by mesopores (Figure 5a); samples Hw-2, Hw-3, Hw-6, and Hw-8 are dominated by multimodal meso- and macropores (Figure 5b); and sample 950


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Figure 6. Nitrogen gas adsorption and desorption isotherms for the 10 shale samples at liquid nitrogen gas temperature (77.3 K).

Hw-4 exhibits a single mode of macropores of approximately 20−500 nm (Figure 5c). 4.3.2. LP-N2GA Isotherms. LP-N2GA analyses provided data on the BET surface area and DFT mesopore volumes (Table 3). The total specific surface areas in the 10 samples range from 4.45 to 34.33 m2/g, with a mean value of 15.92 m2/g. Note that sample Hw-4 contains the greatest specific surface area, and sample Hw-9 contains the least specific surface area. The nitrogen isotherms for selected black shale samples are shown in Figure 6. Concerning the shape of the hysteresis loops, we suggest that the shales may be classified as type H3 according to the IUPAC classification, which indicates the presence of slit-shaped pores.27 The slit-shaped pores may be related to the plate structure of clay particles (Figure 3h). As we will see, these seven samples (Hw-1, Hw-2, Hw-3, Hw-4, Hw-7, Hw-8, and Hw-10) show a lack of total closure of the lowpressure hysteresis loop (Figure 6a), which has been interpreted as being due to swelling or adsorption in micropores.27 For the three other samples (Hw-5, Hw-6, and Hw-9), hysteresis loops were closed (Figure 6b). The distribution of the pore volume with respect to the pore size can be displayed as cumulative, incremental, or differential distribution curves.8,9,11−13 A plot of the derivation of the pore volume with respect to the pore diameter, i.e., dv/dw versus w, is referred to as a differential distribution plot, and the pore volume in any pore width range is given by the area under the curve (Figure 7). Because the adsorption branch is highly preferred for pore size calculations and hardly affected by the tensile strength effect (TSE) phenomenon33 (the breaking of the hemispherical meniscus in pores with a diameter of approximately 4 nm and, hence, making application of Kelvin’s equation invalid lead to the result that PSD obtained from the desorption curve is limited to ∼4−5 nm), we calculated the PSDs by the DFT model using the adsorption branch of the isotherm. As illustrated in Figure 7, the plot of dv/dw versus w shows a bimodal distribution, with modes of approximately 0.7−1 and 4−5 nm. 4.3.3. LP-CO2 GA Isotherms. Carbon dioxide (CO 2 ) adsorption is coupled with the N2 adsorption analysis to examine the micropore size fraction because the analytical temperature of N2 adsorption analysis is too low (−196 °C) for the nitrogen molecules to access the micropores.7,16 The analytical temperature used for the CO2 adsorption analysis (0 °C) provides the necessary kinetic energy for the CO2 molecule to access the micropores. LP-CO2GA analyses provided data on

Figure 7. Pore volume distribution with pore size, derived from the N2 adsorption branch for the isotherms of shale samples using the DFT model.

the CO2 equivalent surface area and DFT micropore volumes (Table 3). The CO2 equivalent surface areas in the 10 samples range from 18.85 to 79.77 m2/g, with a mean value of 49.21 m2/g. CO2 adsorption isotherms (Figure. 8) are manifested as type I, indicative of microporous solids. The adsorption isotherms of the 10 samples are of three types. Samples Hw-8, Hw-9, and

Figure 8. Carbon dioxide adsorption isotherms for the 10 shale samples. 951


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multimodal PSDs in the nanoscale pore, there is difficulty predicting sorbed gas capacities. Recent study by Ross and Bustin7 have shown that the micropore volume has a positive correlation with sorbed CH4 capacity based on Devonian− Mississippian shales. The first group (samples Hw-1, Hw-2, Hw-3, Hw-7, and Hw-8) may have higher sorbed gas capacity than the other two groups because of the large micropore volume. Furthermore, because of complex pore sizes, gas flow in shales is expected to be a combination of Knudsen diffusion and slip flow in nanoscale pores and Darcy-like flow in larger pores.34 It is assumed that the surface areas and pore volume calculated using HPMI are primarily a function of the meso− macropores (>30 nm), mesopores based on the N2 analyses (2−30 nm), and micropores based on the CO2 analyses (5 nm, and most of the specific surface areas are provided by the micropores (Figure 11). These results largely match those by Ross and Bustin,7 who studied Jurassic and Devonian−Mississippian shales. The pore volumes are due to the micro- and mesopores (Figure 12), and the pore volume of sample Hw-4 is primarily due to the macropores, which may be due to its high content of clay minerals, in particular the illite content. 4.4. Compositional Controls on Shale Pore Structure. Many scholars have discussed and researched the factors affecting the pore systems of shales. Chalmers and Bustin35 indicated that nanoscale pores were primarily dominated by the TOC based on related experiments. Loucks et al.36 found a majority of the nanopores developed within the organic matter after comprehensive observation of the nanopores in the Barnett Shale. Mastalerz et al.37 reported that organic matter transformation because of hydrocarbon generation and migration is a pivotal cause of the observed porosity differences. Ross and Bustin7 concluded that, in addition to the TOC, the clay content may constrain the nanopore volume and surface area. Correlational analysis between the TOC, clay content, quartz content, and pore volumes of various scales was performed on samples from the Niutitang Formation in northwestern Hunan in this study. The results indicate a strong correlation between the TOC and micropores (R2 = 0.898; Figure 13a), weakening gradually in the relationships with the meso- and macropores, which suggests that organic matter is an important contributor to micropores. On the other hand, the clay content, particularly the illite content, has a strong association with the macropores (panels b and c of Figure 13), which indicates that pores hosted by clay minerals are of sizes ranging from mesopores to macropores. The FE-SEM images of intraparticle pores in flocculated clay aggregates and interparticle pores between clay mineral layers are helpful in confirming this conclusion (panels g and h of Figure 3). There is no clear correlation between the quartz content and pore development of various scales (Figure 13d).

Hw-5 comprise one type, which exhibits low adsorption ( 50 nm); LP-N2GA was used to characterize the mesoporosity (2 nm < diameter < 30 nm); and LP-CO2GA was used to characterize the microporosity (diameter < 2 nm). The experimental results indicate that the samples may be placed in three groups based on their PSDs. The first group (samples Hw-1, Hw-2, Hw-3, Hw-7, and Hw-8) exhibits bimodal PSDs with peaks in the range of micropores and fine mesopores (diameter of approximately 2−3 nm) (Figure 10a). The second group (samples Hw-5, Hw-6, Hw-9, and Hw-10) exhibits multiple modes with peaks in the ranges of micropores, fine mesopores (2−3 nm), and large mesopores (20−30 nm pore size). A minor peak in the range of macropores is also observed (Figure 10b). Sample Hw-4 exhibits a multimodal PSD with a major peak at 80−400 nm and minor but prominent peaks in the range of micro- and mesopores (Figure 10c). As we know, the PSDs of samples have a significant impact on the gas storage and flow capacity of shale. Because of

5. CONCLUSION (1) FE-SEM equipped with an EDS provided images useful for appreciating the complexity of the pore networks. Micro- and mesopores within organic matter and macropores, including interparticle pores between or within clay particles, are well952


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Figure 10. Combination of PSD from HPMI, LP-N2GA, and LP-CO2GA.

Figure 11. Comparison of cumulative surface areas calculated using various techniques (HPMI, LP-CO2GA, and LP-CO2GA).

Figure 12. Comparison of the cumulative pore volume calculated using various techniques (HPMI, LP-CO2GA, and LP-CO2GA).

developed in the shales of the Niutitang Formation. (2) The black shales have a complex mineral composition, with the primary constituents being quartz (45.8−64.8%) and clay (20.1−42.2%). The total porosity of the shales ranges from 1.13 to 5.42%, and their total surface areas (SBET) range from 4.45 to 34.33 m2/g. Note that the porosity is primarily controlled by the TOC and clay contents. (3) The pore size distributions obtained using HPMI, LP-N2GA, and LP-CO2GA analyses can be effectively combined to reveal information regarding the micro-, meso-, and macroporosities. The PSDs

from the adsorption analyses may be divided into three groups of bi- or multimodal distribution. Note that the DFT-derived PSDs indicate that the pore volumes are primarily controlled by the micro- and mesopores, whereas the specific surface areas are primarily determined by the smaller pores (

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