1 Introduction
Marine shale gas has been commercially produced in the United States and China (
Jarvie et al., 2007;
Pollastro 2007;
Guo and Zhang, 2014;
Dong et al., 2015;
Zhao et al., 2020), and marine-continental transitional shale gas has also received increasing attention in recent years (
Liu et al., 2018;
Xi et al., 2018;
Cortes et al., 2019;
Chen et al., 2020a;
Li et al., 2021a;
Zhang et al., 2021). Previous works have shown that marine-continental transitional shale has great potential for gas resources in China, and the estimated geological reserves have proven to be approximately 19.8 × 10
12 m
3, accounting for 25% of the total shale gas reserves in China (
Kuang et al., 2020). Marine-continental transitional deposits are mostly composed of coal measures (
Peng et al., 2019), which are also intercalated with organic-rich shales, i.e., so-called “coal-bearing shale” (
Peng et al., 2019;
Liang et al., 2020a).
Gas-in-place (GIP) is an important parameter for shale gas evaluation (
Ross and Bustin, 2008;
Li et al., 2022). Few authors have reported that the GIP content of Permian coal-bearing shales vary from 0.35 to 6.43 m
3/t (
Tang et al., 2016;
Guo et al., 2018;
Jia et al., 2020; Shao et al.,
2021), which are generally lower than that of marine shales (
Dong et al., 2015;
Zhao et al., 2016). The factors controlling the GIP content of shales have been extensively studied (
Chalmers and Bustin, 2007;
Ross and Bustin, 2008;
Zhang et al., 2012;
Gasparik et al., 2014;
Saidian et al., 2016), and mainly include shale compositions and geological conditions. The former include the total organic carbon (TOC) content, thermal maturity, kerogen type, inorganic mineral compositions, porosity, and pore structure. The latter include moisture, temperature, pressure, and preservation conditions. As for wells within the same block or adjacent to each other, they have similar geological conditions. Hence, it is widely accepted that the GIP content of marine shales is mainly controlled by TOC contents; with increasing TOC contents, the porosity and specific surface area of shales increase, which provide more storage space and adsorption sites for methane, thus leading to high GIP contents (
Ross and Bustin, 2008;
Zhang et al., 2015;
Sun et al., 2020a;
Li et al., 2021b). However, the TOC content of coal-bearing shales is comparable with or higher than that of marine shales, and the GIP content of the former is lower than that of the latter. Thus, the major factors influencing the GIP content of coal-bearing shales still remain controversial. Some authors have suggested that the TOC content is still the major factor controlling the GIP content of coal-bearing shales (
Li et al., 2020a). However, many authors have found that the adsorbed gas content of coal-bearing shales is controlled by clay contents rather than TOC contents due to the presence of a significant positive correlation between adsorbed gas and clay contents (
Zhang et al., 2019a;
Qiao et al., 2020). Therefore, it is necessary to study the compositional differences between marine shales and coal-bearing shale and their potential influences on the gas contents.
Coal-bearing shales show different characteristics of organic matter (OM) and inorganic mineral compositions relative to marine shale. In general, marine shales have oil-prone kerogen (type I-II) showing great hydrocarbon generation potential, while coal-bearing shales are gas-prone source rocks (i.e., type III kerogen) (
Vandenbroucke and Largeau, 2007;
Peng et al., 2019;
Sun et al., 2020b). The mineral composition of the Chinese coal-bearing shales mainly includes clay minerals (average = 30%−70%) (
Zhang et al., 2017a;
Zhang et al., 2018;
Tang et al., 2020;
Xie et al., 2021;
Li et al., 2021a), whereas that of marine shales is dominated by quartz and other brittle minerals (generally > 50%) (
Chen et al., 2020b;
Wang et al., 2020a). In particular, high-quality gas shale reservoirs have clay contents less than 20% (
Qin et al., 2010). In addition to the total clay contents, the relative contents of different clay species in coal-bearing shale and marine shale are different. For example, the clay species of marine shales are dominated by illite, while coal-bearing shales are characterized by high contents of kaolinite and illite/smectite mixed layers (I/S) (
Zhang et al., 2019b). The obvious differences in the GIP contents between coal-bearing shale and marine shale may be controlled by these internal factors. Nevertheless, the major factors influencing the GIP contents of coal-bearing shales still need to be further clarified.
In the Qinshui Basin of north China, the upper Carboniferous–lower Permian Taiyuan and Shanxi formations are mainly composed of coal and coal-bearing deposits; coal seams and organic-rich coal-bearing shales are widely developed, and the resources of coalbed methane (CBM) and coal-bearing shale gas are proven to be abundant, with predicted resources of 5.39 × 10
12 m
3 and 2.14 × 10
12 m
3, respectively (
Su et al., 2016). The CBM has been commercially exploited in the Qinshui Basin for a long time (
Zou et al., 2018;
Yu et al., 2020;
Zhu and Salmachi, 2021), but the progress of shale gas exploration and development is slow (
Li et al., 2018a;
Xi et al., 2018;
Yin and Guo, 2019;
Zhang et al., 2019b;
Liang et al., 2020a;
Zhang et al., 2020). Extensive exploration activities have revealed that coal-bearing shales generally have low and varied GIP contents (
Zhang et al., 2019a;
Zhang and Fu, 2019;
Li et al., 2020a). To exactly locate the ‘sweet-spot’, it is very urgent to explore the major factors that influence the GIP contents of the coal-bearing shales.
In this study, an integrated investigation of the coal-bearing shales from two wells in the Zuoquan Block in the eastern Qinshui Basin, including organic geochemistry, inorganic mineral compositions, pore characterizations, desorption tests and GIP evaluation, was conducted to explore the major factors that influence the GIP contents, thus providing a scientific basis for the further exploration and development of coal-bearing shale gas in the Qinshui Basin and other basins.
2 Samples and analytical methods
2.1 Samples
The Qinshui Basin, with a total area of 3 × 10
4 km
2, is located in Shanxi Province of north China, and the basin contains a sedimentary succession of the Cambrian, Ordovician, Pennsylvanian, Permian, Triassic, Jurassic, Neogene, and Quaternary (
Peng et al., 2017). The upper Carboniferous–lower Permian Taiyuan and Shanxi formations have received a succession of coal and coal-bearing deposits formed in the marine-continental transitional facies (
Zhang et al., 2017b;
Li et al., 2018b). Organic-rich coal-bearing shales are usually associated with coal seams, which are the primary target for shale gas exploration (
Li et al., 2018a). The Taiyuan Formation, with a total thicknesses of 76−177 m, is mainly composed of shale, fine-grained sandstone, limestone, and coal seams. The Shanxi Formation has total thicknesses of 35−72 m, which chiefly consists of fine-grained sandstone, shale, and coal (
Shao et al., 2007). The cumulative thicknesses of organic-rich coal-bearing shales vary from 40 to 120 m in both formations (
Zhong et al., 2020).
The Zuoquan Block located in the eastern Qinshui Basin is our study area, where the Taiyuan and Shanxi formations, with burial depths of 1400−1800 m, are favorable targets for shale gas exploration (
Xi et al., 2017b;
Zhao et al., 2019). A total of 15 coal-bearing shale samples were collected from the Wells 1-1 and 3-2 in the Zuoquan Block (Fig.1). Detailed information of the studied samples is provided in Tab.1. All samples were prepared for geochemical and mineralogical analyses by grinding to a 200 mesh size.
2.2 Analytical methods
2.2.1 In situ gas desorption and calculation of the GIP content
The
in situ gas desorption of fresh core samples was conducted, and the detailed principle and analytical processes were described by previous authors (
Deng et al., 2008). Natural desorption was conducted at the temperature of the reservoir, and the obtained gas was categorized as the desorbed gas. After natural desorption, samples were crushed for 2−4 h at the reservoir temperature and residual gas was obtained. Typically, the lost gas content is calculated using the USBM (US Bureau of Mines) linear regression method (
Zhou, 2002;
Deng et al., 2008;
Sun et al., 2018). Due to the greater burial depth, a higher proportion of free gas may be lost during the uplifting of core samples, and the lost gas contents calculated by the USBM method may be lower than actual values (
Wang et al., 2020b). Previous authors have suggested the polynomial regression method to calculate the lost gas contents of deeply-buried gas shale reservoirs (
Sun et al., 2018), and this method was also used in our study. The lost gas contents were calculated by the polynomial regression fitting method of the first 2 h of data from natural desorption (Fig.2). The GIP content is the sum of the desorbed gas, residual gas and lost gas.
2.2.2 SEM observation
The shale samples were first mechanically polished and then further polished by an argon ion milling system IM4000 to obtain highly smooth surfaces. Scanning electron microscope (SEM) observation of the polished samples were conducted on a high-resolution cold field emission scanning electron microscopy (Hitachi S-8000). Imaging was performed at 1−10 kV and a working distance of 1.5−15 mm under a vacuum.
2.2.3 Total organic carbon and Ro measurements
After the removal of carbonate minerals with 5% HCl, the total organic carbon (TOC) content of the powdered samples were measured with the total carbon and sulfur Leco CS-200 analyzer. The TOC contents were calculated by the peak area of CO
2 generated from the combustion of OM and calibrated by carbon in steel (TOC = 0.812 ± 0.006%) (
Wang et al., 2013).
The vitrinite reflectance (Ro) was determined on polished shale samples using a 3Y-Leica DMR XP microphotometer. The microscope was calibrated with a cubic zirconia reference (Ro = 3.11%) and an optical black (zero), and the measurements were conducted in oil immersion under incident light using a 50 × /0.85 oil lens. In each sample, 50 different vitrinite particles were randomly selected for measurements, and the data were averaged.
2.2.4 X-ray diffraction
X-ray diffraction (XRD) measurements of powdered whole-rock samples were conducted on a Bruker D8 Advance X-ray diffractometer equipped with a Cu-target tube and a curved graphite monochromator, operating at 40 kV and 30 mA. Samples were step-scanned from 3° to 85° with a step size of 0.04° (2
θ), and the mineral composition was semiquantitatively determined using peak area integration approach with correction for Lorentz polarization (
Pecharsky and Zavalij, 2008).
2.2.5 Porosity
Small cylindrical cores with a diameter of 25 mm and a length of 20 mm were drilled from the selected shale core samples. The cores were first dried at a temperature of 110°C to remove any moisture and weighed, and then porosity was determined using skeletal density and apparent density differences. Skeletal density was measured with a helium pycnometer from Quantachrome, the Ultrapyc 1200e, and apparent density was measured on a hydrometer (DAHO-120M) by the sealing paraffin method. The analytical procedures used in the present study were detailed by previous authors (
Tian et al., 2013).
2.2.6 Low-pressure N2 adsorption experiments
Approximately 2 g of crushed sample (60−80 mesh) was dried at 110°C in an oven for 24 h to remove moisture and volatile materials. Each sample was then analyzed for pore volume using low-pressure N
2 adsorption on a Micromeritics ASAP 2020 analyzer. The measured relative pressures were 0.005−0.995 and the tested temperature was 77.35 K (liquid nitrogen temperature). Pore volume (PV) and specific surface area (SSA) were calculated from the adsorption isotherm using the Barrett-Joyner-Halenda (BJH) model (
Barrett et al., 1951) and the modified Brunauer–Emmett–Teller (BET) equation (
Romero-Sarmiento et al., 2014;
Tian et al., 2015). In general, N
2 adsorption permits the identification of pores ranging from 1.7 to 100 nm.
3 Results
3.1 Bulk organic geochemistry
The TOC content of the studied shale samples vary from 0.92% to 16.1%, averaging 4.94% (Tab.1). The Ro value of the studied shale samples ranges from 2.55% to 3.16% (Tab.1), suggesting that the shale is currently in the thermally high- and overmature stage.
3.2 Mineralogical compositions
The studied shale is dominated by quartz and clay (Tab.1). The quartz content ranges from 22.84% to 69.16%, with an average of 43.20%; the total clay content varies from 23.27% to 61.49%, with an average of 43.98%. Some shale samples contain small amounts of feldspar, pyrite, siderite, and anatase, and their contents are generally less than 10%. Few shale samples also contain a small quantity of calcite, anhydrite, and hematite. The species of clay minerals are dominated by I/S, followed by kaolinite and chlorite. The I/S contents range from 8.06% to 48.66% (average 26.25%), and the kaolinite content varies from 0 to 36.37% (average 16.10%). The chlorite content is usually less than 5.53%. Overall, the studied coal-bearing shales are characterized by lower quartz contents and higher clay contents relative to typical marine shales (Fig.3).
3.3 Porosity, pore types and pore structure characteristics
The measured porosity values of the studied shale samples range from 2.00% to 9.47%, averaging 5.12% (Tab.2). SEM observations reveal that the pores in the studied shale samples mainly included OM-hosted pores, clay-hosted pores, mineral interparticle pores, and microcracks (Fig.4). In some OM fragments, original structures can be clearly observed, but rare organic pores are visible at this scale (Fig.4(a)). Few isolated organic pores can also be observed, and these pores display round shapes (Fig.4(b)−Fig.4(e)). Some organic pores are connected (Fig.4(d)). Clay-hosted pores are widely developed in the studied shale samples, and can be observed in the clay-OM associations, clay aggregates, and clay platelets (Fig.4(f)−Fig.4(j)). Abundant elongated and irregular clay-hosted pores occurr within the I/S (Fig.4(g) and Fig.4(j)). Slit-shaped intergranular pores widely occur between kaolinite aggregates (Fig.4(i)). Mineral interparticle pores are mainly developed between quartz grains (Fig.4(k)), which are also usually observed in the siderite and pyrite aggregates (Fig.4(k) and Fig.4(l)). Microcracks were usually visible along the margins of quartz grains in quartz-rich shale samples (Fig.4(k)).
The SSA values of the studied shale samples range from 2.05 to 17.88 m2/g, with an average of 11.29 m2/g. The PV values vary from 0.60 × 10−2 to 3.37 × 10−2 cm3/g, with an average of 2.16 × 10−2 cm3/g. The average pore size (APS) values range from 5.38 to 13.55 nm, averaging 8.57 nm (Tab.2).
3.4 GIP content
The contents of lost gas, residual gas, desorbed gas and GIP of the studied shale samples are presented in Tab.3. The GIP content ranges from 0.30 to 2.28 m3/t, with an average of 1.32 m3/t. The desorbed gas contents vary from 0.19 to 1.98 m3/t, with an average of 0.94 m3/t. The residual gas contents are in the range of 0.01−0.56 m3/t (average = 0.21 m3/t). The lost gas content ranges from 0.01 to 0.66 m3/t, with an average of 0.17 m3/t. The desorbed gas, lost gas, and residual gas account for 44.32%−94.13%, 1.07%−33.65%, and 1.13%−32.49% of the GIP, respectively (Fig.6). Thus, the desorbed gas dominates the GIP content.
4 Discussion
4.1 Influence of OM and mineral compositions on porosity
Numerous studies have suggested that the pore evolution of shales is controlled by both primary sedimentary compositions, including the OM and inorganic mineralogical composition, and subsequent diagenetic processes (
Loucks et al., 2009;
Mastalerz et al., 2013). For overmatured marine shales, the TOC content has always positively correlated with the porosity within a certain TOC range, indicating that organic pores are the predominant pore type and the porosity is directly controlled by the TOC content (
Tian et al., 2013;
Sun et al., 2020a). Such a significant correlation between the TOC content and porosity cannot be observed in this study (Fig.5(a)). Within the TOC range of 0.92%−5.24%, the TOC content displays a weak positive correlation with porosity values. The porosity began to diminish for TOC values in excess of 8.54% (Fig.5(a)). A similar trend also occurs in marine shales and coal-bearing shales in the Yangtze Block, South China (
Milliken et al., 2013;
Pan et al., 2015;
Teng et al., 2021). Such a reduction in porosity values has usually been attributed to pore collapse due to mechanical compaction (
Milliken et al., 2013;
Furmann et al., 2016). Therefore, TOC contents ≤ 5.24% can be defined as the uncompacted stage of OM in this study. Since the data sets of TOC values ranging from 5.24% to 8.54% are lacking in our study, the accurate turning point of porosity is very hard to predict.
It should be noted that the correlation coefficient between the TOC content and porosity in the coal-bearing shales is significantly lower than that in the lower Paleozoic marine shales from south China (
Tian et al., 2013;
Sun et al., 2020a;
Xi et al., 2021). Such a weak correlation can also be found in the coal-bearing shales from the Qinshui Basin (
Zhang and Fu, 2018) and other basins, e.g., the Ordos Basin (
Tang et al., 2016) and the Sichuan Basin (
Luo et al., 2019), which may be mainly attributed to the poor development of organic pores in gas-prone kerogen (i.e., type III). In contrast, organic pores have been suggested to be widely developed in marine shales with oil-prone kerogen (type I-II) (
Bowker, 2007;
Chalmers et al., 2012). In our study, SEM-visible organic pores seem to be not well developed (Fig.4(a)−Fig.4(f)). Due to the limitations of SEM observation in nanopores (generally > 5−10 nm), micropores and small mesopores in OM are very hard to be observe (
İnan et al., 2018). However, micropores and small mesopores might be mainly developed in the OM of coal-bearing shales, which have been widely reported in many sedimentary basins (e.g., the Ordos Basin (
Qiu et al., 2021), Sichuan Basin (
Yang et al., 2019), and Qinshui Basin (
Xi et al., 2017a)) in China.
An outlier shale sample (i.e., Sample 11) displays a low TOC content (1.93%) but high porosity (9.74%) (Fig.5), which may result from a higher content of pyrite (as high as 23.54%). As mentioned above, a large volume of interparticle pores is developed between pyrites (Fig.4(l)). The porosity values show a moderate positive correlation with total clay contents (
r = + 0.60,
n = 14; excluding an outlier sample) (Fig.5(b)), which can also be observed in coal-bearing shales from the Ordos Basin (
Qiao et al., 2020) and Sichuan Basin (
Yang et al., 2017;
Chen et al., 2021). The species of clay minerals in the studied shales mainly include kaolinite and I/S (Tab.1). Previous authors have found that the pore diameters of kaolinite and I/S are dominantly 10−70 nm, < 6 nm and 20−70 nm (
Ji et al., 2014). Thus, clay-hosted pores greatly contribute to shale porosity. Yang et al. (2017) also believed that the porosity of coal-bearing shales in the Sichuan Basin is mainly contributed by clays rather than the OM.
As one of the major brittle minerals in shales, quartz can esist to burial compaction. A high proportion of brittle minerals can form a rigid framework that can be favorable for the protection of organic pores, which has been widely reported in marine shales (
Milliken et al., 2013;
Zhang et al., 2013;
Furmann et al., 2016).
In our study, the quartz contents of the studied shales display no correlation with the porosity values (Fig.5(c)), which can be attributed to the following reasons. The quartz may be of terrigenous origin rather than biological origin, with relatively low contents in the studied shales, which plays a dilution role in the TOC and clay mineral contents, as suggested by the moderate negative correlation between the quartz and TOC or clay contents (Fig.7(a) and Fig.7). To explore the effect of quartz on the porosity, TOC-normalized and clay-normalized parameters (i.e., porosity/TOC ratio and porosity/clay ratio) are introduced in our study; these parameters refer to the relative contribution of inorganic porosity and organic porosity to total porosity, respectively. A moderate positive correlation between the quartz content and the porosity/TOC ratio can be observed in our studied shales (r = + 0.61; n = 13; excluding outliers) (Fig.7(c)), indicating that inorganic porosity may be protected by rigid frameworks formed by quartz grains from compaction. The lack of a relationship between the quartz content and the porosity/clay ratio probably suggests that the development of organic pores is not associated with quartz (Fig.7(d)), which also supports a terrigenous origin of quartz.
4.2 Influence of OM and mineral compositions on pore structures
In general, the TOC contents display a good positive relationship with the pore structure parameters (e.g., SSA and PV) of marine shales (
Milliken and Olson, 2017;
Tang et al., 2020). In our study, the TOC contents have moderately correlated with the SSA and PV with TOC contents less than 5.24% (Fig.8(a) and Fig.8(b)), suggesting that the OM during the uncompacted stage of shales has a certain contribution to total SSA and PV. Such an increasing trend disappears with increasing TOC contents (Fig.8(a) and Fig.8(b)).
A moderate positive correlation between clay contents and SSA values (r = + 0.71) indicates that clay minerals have complex surface areas and are a major contributor to the SSA of total pores (Fig.8(c)). Although the quartz contents are not correlated with the SSA and PV values (not shown in this study), they display weak-moderate positive relationships with the TOC-normalized pore structure parameters (Fig.8(d)), indicating that quartz may play a positive role in the protection of nanopores in the studied shales to some extent. Moreover, only a part of the pore volume is measured by N2 adsorption, which cannot fully represent the total pore volume of the studied shale samples.
In the uncompacted stage of organic matter (TOC ≤ 5.24%), there is a moderate negative correlation (
r = −0.59) (Fig.9(a)) between the TOC content and APS, probably implying that OM is mainly composed of micropores. A moderate negative correlation between clay contents and APS values can be observed in our study (
r = −0.63) (Fig.9(b)). Previous authors have found that pores with diameters < 20 nm in shales would significantly increase with the increasing clay contents, while larger pores (> 20 nm) would not significantly increase (
Yuan et al., 2021). Thus, the increase of clay contents gradually decreases the APS values of studied shales. A moderate positive correlation (
r = + 0.54) between quartz contents and APS values is also observed (Fig.9(c)), further indicating the role of quartz grains in the preservation of larger nanopores.
4.3 Factors that influence the GIP contents
As mentioned above, the porosity and pore structures of coal-bearing shales in this study are mainly controlled by clay contents, followed by TOC contents. The porosity and pore structure are directly related to shale GIP contents; therefore, the influences of shale compositions and pore characteristics on the GIP contents should be explored.
4.3.1 OM and mineral compositions
In this study, the GIP contents show a moderate positive correlation with TOC contents (Fig.10(a)). Such a positive relationship has also been reported in coal-bearing shales from the south–north China Basins (
Li et al., 2020a). The GIP contents appear to be lower in the high-TOC shale samples (TOC > 8.5%) (Fig.10(a)), which may have resulted from the collapse of pores during burial compaction. The GIP contents have a weak positive correlation with total clay contents (Fig.10(b)), implying that clay minerals have a certain contribution to gas contents. However, a weak negative correlation between the GIP and quartz contents is observed (Fig.10(c)), which may be attributed to two potential factors. First, quartz contents display negative correlations with TOC and clay contents (Fig.7(a) and Fig.7(b)), suggesting that terrigenous quartz grains play a dilution role in the OM and clay accumulations. Second, interparticle pores between quartz grains mainly consist of large pores (
Ge et al., 2020), which have weak adsorption capacities for methane (
Wang et al., 2020c;
Shi et al., 2021) but could provide a certain volume of storage space for free gas. However, the gas composition of the studied shales is mainly adsorbed gas, so the control of quartz contents on the GIP contents is relatively weak.
These results show that the GIP contents of the studied shales are mainly controlled by the TOC and total clay contents, which is different from marine gas-bearing shales (
Strąpoć et al., 2010;
Milliken et al., 2013;
Sun et al., 2020a). For marine shales, the GIP contents are always positively correlated with TOC contents (
Strąpoć et al., 2010;
Zheng et al., 2019), while they generally display no positive relationships with total clay contents (
Li et al., 2022).
It is widely accepted that the total gas of shales consists of lost gas, desorbed gas, and residual gas (
Liang et al., 2020b;
Xu et al., 2020a). Lost gas can be considered free gas in shale; residual gas is mostly occur in the form of adsorbed gas; and desorbed gas consists of both free gas and adsorbed gas (
Li et al., 2020b). The adsorbed + residual gas contents of the studied shales have a moderate positive correlation with the TOC contents but display no correlation with the lost gas contents (Fig.11(a)), suggesting greater controls of the OM on the adsorbed gas. Lost gas and adsorbed + residual gas contents display weak positive correlations with total clay contents (Fig.11(b)), but the clays have greater controls on lost gas, implying that the methane occurs in clays mainly as free gas. The adsorbed + residual gas contents of the studied shales show a moderate positive correlation with the I/S contents (Fig.11(c)), while it does not correlate with the kaolinite + chlorite contents (Fig.11(d)), indicating that the I/S is the major type of clay minerals of the studied shales and plays a leading role in methane adsorption relative to other clay species. Previous studies have also shown that the methane adsorption capacity of I/S is significantly stronger than that of kaolinite and chlorite (
Ji et al., 2014). In general, illite, smectite, and I/S could provide greater SSA values than kaolinite, thus affecting adsorption capacity.
4.3.2 Porosity and pore structures
Numerous studies have showed that porosity and pore structures provide storage spaces for methane and influence the adsorption capacity of methane, thus directly controlling the GIP contents of shales (
Curtis, 2002;
Jarvie et al., 2007;
Ross and Bustin, 2008). However, no positive correlations between GIP contents and the porosity or pore structure parameters (PV, SSA, and APS) are shown in all studied shale samples (Fig.12).
Zhong et al. (2020) collected data from 695 coal-bearing shale samples from the Qinshui Basin and found that 84.97% of shale samples displayed TOC values less than 4%. Thus, the coal-bearing shales in the Qinshui Basin are characterized by lower TOC contents. As mentioned above, the larger organic pores in the high-TOC shale samples would be strongly affected by burial compaction, thus resulting in the alteration of pore structures. Thus, it is necessary to explore the relationship between the GIP contents and the porosity or pore structure parameters (PV, SSA, and APS) in the low-TOC shale samples (TOC ≤ 5.24%) (Fig.13). The GIP contents display a weak positive relationship with the porosity and have a moderate correlation with the SSA values and PV values, respectively (Fig.13), suggesting that total gas is dominated by adsorbed gas, which is consistent with previous studies (
Ma et al., 2021).
In marine shales, the porosity and pore structure parameters are mainly controlled by the TOC contents, which have been revealed by numerous studies (
Milliken et al., 2013;
Zhao et al., 2018;
Sun et al., 2020a;
Xu et al., 2020b). Compared with marine shales, the GIP contents of the studied coal-bearing shales are relatively low, and the relationships between the GIP contents and the porosity or several pore structure parameters are weak, implying that the major factors controlling the GIP contents of coal-bearing shale are more complex than those of marine shale. The pore spaces of coal-bearing shales are primarily provided by clay minerals, followed by OM. In general, the clay-hosted pores are strongly hydrophilic and easily occupied by water molecules (
Borysenko et al., 2009;
Cheng et al., 2017;
Guo et al., 2021;
Sun et al., 2021). The clay surfaces may be partly or fully adsorbed by water molecules, so the adsorbed gas contents should be reduced due to the decrease of methane adsorption sites (
Cheng and Huang, 2004;
Merkel et al., 2015;
Tang et al., 2020). Although the water contents of shale samples are not measured in this study, we believe that the pores of coal-bearing shales are influenced by water contents to some extents, thus resulting in lower GIP contents and poor correlations between the GIP contents and porosity or pore structure parameters.
In addition, a weak negative correlation between the GIP contents and APS values was observed in this study (Fig.13(d)). With the increase of clay contents, the slit-shaped clay-hosted pores are increased in the studied shales, thus leading to the increase of porosity, PV, and ASS values (e.g., Fig.5(b)). However, the increasing proportions of slit-shaped pores would lead to a decrease in the APS values and an increase in GIP contents.
5 Conclusions
Major factors influencing the GIP contents in organic-rich coal-bearing shales from the Qinshui Basin have been studied, and the following conclusions can be drawn.
1) The coal-bearing shales are enriched in clay minerals, which are mainly composed of I/S, followed by kaolinite. Interparticle pores hosted in clay minerals are commonly developed in shales, while SEM-visible OM-hosted pores are not well developed.
2) The porosity, PV and SSA of coal-bearing shales were mainly contributed by clay minerals, followed by OM, which can provide storage spaces and adsorption sites for methane, thus influencing the gas contents.
3) The GIP contents of coal-bearing shales range from 0.30 to 2.28 m3/t, with an average of 1.32 m3/t, which are dominated by the desorbed gas contents. The major factors influencing the GIP contents of coal-bearing shales include both TOC and clay contents. Among all clay species, I/S plays a leading role in methane adsorption, which is favorable for methane enrichment in shales.
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