Water-bearing characteristics and their effects on the nanopores of overmature coal-measure shales in the Wuxiang area of the Qinshui Basin, north China

Abstract

In this study, a group of overmature coal-measure shale core samples was collected in situ from an exploration well located in the Wuxiang area of the Qinshui Basin, north China. The pore water contents (C_PW) of the shales under as-received conditions, equilibrium water contents (C_EW) of the shales under moisture equilibrium conditions (relative humidity: 100%), and nanopore structures of the shales under both as-received and dried conditions were measured. The results indicate that the C_PW values of these shales are much lower than their C_EW values, which implies that the bulk pore systems of these shales have low water-bearing extents. In addition, approximately half of the total pore volumes and surface areas of the as-received shales are occupied by pore water, and the effects of pore water on shale nanopores with various pore types and widths are different. The average water-occupied percentages (P_W) are 59.16%−81.99% and 42.53%−43.44% for the non-micropores and micropores, respectively, and are 83.54%−97.69% and 19.57%−26.42% for the inorganic-matter hosted (IM) and organic-matter hosted (OM) pores, respectively. The pore water in shales not only significantly reduces the storage of shale gas by occupying many pore spaces, but also causes the shale gas, especially the absorbed gas, to be mostly stored in the OM pores; meanwhile, the IM pores mainly store free gas. Therefore, the water-bearing characteristics and their effects on the pore structures and gas-bearing properties of coal-measure shales should be noted for the evaluation and exploration of shale gas in the Qinshui Basin.

Graphical abstract

Keywords

coal-measure shales / water-bearing characteristics / nanopore structures / shale gas / the Qinshui Basin

1 Introduction

Although organic-rich shales with shale gas potential developed widely in marine, marine-terrestrial transitional and terrestrial strata in China, only marine shale gas has achieved commercial development presently (Zhang et al., 2009; Jia et al., 2012; Guo, 2016; Zou et al., 2016; Zou et al., 2020a). The total shale gas production in China reached 200 × 10⁸ m³ in 2020, and 99% of this production was provided by the Lower Palaeozoic marine shales (Men et al., 2021). At present, however, the exploration and development of nonmarine shale strata are still in an early stage, and coal-measure shales are regarded as important potential exploration targets following marine shales (Dong et al., 2016b).

Gas-bearing marine shales generally contain certain levels of pore water, and the water saturations of commercial shale gas plays are generally lower than 45%, such as 25%−30%, 15%−20%, 15%−35%, and 30%−45% for the Barnett, Haynesville, Fayetteville and Longmaxi shale gas plays, respectively (Boyer et al., 2006; Cipolla et al., 2010; Wu and Aguilera, 2012; Fang et al., 2014; Wei and Wei, 2014). However, shale gas plays with water saturations greater than 45% generally have low shale gas yields, e.g., the Zhaotong shale gas plays in the Sichuan Basin, south China (Liu and Wang, 2013). Because substantial amounts of pore water have been expelled from shale pore systems due to the compaction of overlying strata and by displacement drainage of the generated hydrocarbons during the diagenetic and thermal evolution stages (Wardlaw and McKellar, 1998; Mahadevan et al., 2007; Cheng et al., 2019), the bulk pore systems of highly mature or overmature shales generally have low water-bearing extents. These shales may barely contain free liquid water, and most of the pore water is confined to the nanopores or is adsorbed on their inner surfaces (Bennion and Thomas, 2005; Cheng et al., 2017, 2018).

Pore water and shale gas are concomitantly stored in the pore systems of gas shales, and thus the water-bearing characteristics of shales significantly affect their gas-bearing properties (Ambrose et al., 2010; Sondergeld et al., 2010; Gasparik et al., 2014; Merkel et al., 2015; Yang et al., 2020). Under certain geological conditions, the contents, distributions and occurrences of pore water are closely related to the pore types and widths of shale nanopores (McCutcheon and Barton, 1999; Passey et al., 2010; Wen et al., 2015; Li et al., 2016; Zolfaghari et al., 2017; Feng et al., 2018; Chen et al., 2019). It is generally believed that pore water is dominantly stored in the inorganic-matter hosted (IM) pores of shales, while the organic-matter hosted (OM) pores barely contain water, because the inorganic matter surfaces are hydrophilic and the organic matter surfaces are hydrophobic (Passey et al., 2010; Sondergeld et al., 2010; Odusina et al., 2011; Korb et al., 2014; Zolfaghari et al., 2017; Zou et al., 2020b). However, the wettability of organic matter is still unclear and may depend on its maturity and kerogen type (Bekyarova et al., 2002; Charrière and Behra, 2010; Hu et al., 2015, 2016; Gu et al., 2016; Gao et al., 2019). For the same type of shale nanopores, pore water preferentially occupies nanopores with small pore widths, because they have stronger capillary forces than nanopores with large pore widths (Striolo et al., 2005; Li et al., 2017; Wu et al., 2017).

Although logging data are generally used to calculate the water saturations of gas shale reservoirs during the exploration and development of shale gas, this method is inadequate for exactly recognizing the contents, distributions and occurrences of pore water in various shale nanopores (Miller and Shanley, 2010; Wu and Aguilera, 2012). Therefore, an increasing number of laboratory studies have performed on as-received shales to investigate their water-bearing characteristics (Cheng et al., 2017; Sun et al., 2020a, 2020b). However, few of these laboratory studies have been conducted on as-received coal-measure shales. Coal-measure and marine shales are quite different in geological and geochemical characteristics. For example, compared with marine shales, coal-measure shales are richer in terrestrial macerals and have fewer OM pores and wider ranges of GIP contents (De Silva et al., 2015; Jiang et al., 2017; Yang et al., 2017; Zhang et al., 2019b). Therefore, the two types of shales should exhibit diverse water-bearing characteristics and pore structures. At present, the water-bearing characteristics and their effects on nanopore structures are still unclear for coal-measure shales, and this is one of the important reasons that has limited their shale gas development.

The Upper Carboniferous and Lower Permian coal-measure shales developed extensively in the Qinshui Basin, north China (Cai et al., 2011; Dong et al., 2016a; Li et al., 2018; Liang et al., 2018; Zhang et al., 2019a; Liang et al., 2020), and they were expected to have high shale gas potential with a geological resource of more than 2.93 × 10¹² m³ (Liu, 2016). Recently, a few exploration wells that targeted these strata were drilled in the Wuxiang area of the basin, and a group of gas-bearing shale core samples were collected in situ at the drilling sites. The pore water contents (C_PW) of the shales under as-received conditions, equilibrium water contents (C_EW) of the shales under moisture equilibrium conditions (relative humidity: 100%) and nanopore structures of the shales under both as-received and dried conditions were investigated in this study. The results of this study preliminarily reveal the water-bearing characteristics and their effects on the nanopore structures of overmature coal-measure shales, which may promote accurate evaluations of their gas-bearing properties.

2 Geological background

The Qinshui Basin is located in the north China Craton and is delimited by Taihang Mountain in the east, Zhongtiao Mountain in the south, Huo Mountain in the west and Wutai Mountain in the north (Fig.1(a)). The basin has an area of 3 × 10⁴ km² and spans 120 km in the east–west direction and 330 km in the north–south direction. The strata in the Qinshui Basin were stably and continuously deposited during the Hercynian period, gently uplifted during the Indosinian period, and intensely uplifted during the Yanshan period. The final structural framework of this basin was formed at the end of the Yanshan period, and this basin remained structurally stable after this period (Ren et al., 2005; Song et al., 2019).

The marine-terrestrial transitional strata in the Qinshui Basin were deposited during the late Palaeozoic (Fig.1(b)). The Lower Carboniferous Benxi Formation, with a thickness of 0−75 m, was deposited in a carbonate tidal flat environment and contains mainly gray aluminous mudstones with a few thin coal and sandstone seams. The Upper Carboniferous Taiyuan Formation, with a thickness of 50−135 m, was deposited in a barrier bar environment and contains mainly black shales, sandy mudstones, sandstones and coal seams. The Lower Permian Shanxi Formation, with a thickness of 20−90 m, was deposited in a delta front environment and contains mainly shales, sandstones, and sandy mudstones with coal seams. The Upper Permian and Triassic strata, with thicknesses of 1350−2150 m, were deposited mainly in fluvial and lacustrine environments, and they are composed of thick silty mudstones and gray mudstones. In the Qinshui Basin, the shales and coals in the Taiyuan and Shanxi Formations were the main source rocks, and the silty and gray mudstones in the Upper Permian and Triassic strata were the main cap rocks (Fig.1(b)). Coalbed gas, shale gas, and tight sandstone gas coexist in this basin (Su et al., 2005; Cai et al., 2011; Qin et al., 2014; Song et al., 2019; Liang et al., 2020).

3 Method, samples and experiments

3.1 Method

The water saturations of normal oil and gas reservoirs are generally calculated from well logging data; however, this method has low resolution for shale strata and fails to reveal the water distributions and occurrences in various shale nanopores (Miller and Shanley, 2010; Wu and Aguilera, 2012). Therefore, further laboratory analyses on the water-bearing characteristics of as-received shale samples are necessary to obtain this information (Ahmad and Haghighi, 2013; Cheng et al., 2018).

Gas shales generally have low pore water contents, and the water is strongly confined in the shale nanopores, which results in minimal evaporation when the shale samples are sealed and preserved at room temperature (Handwerger et al., 2011). The shale plunger samples used in this study were drilled from the inner part of shale core samples to eliminate the influences of drilling muds. In addition, all the selected shale samples contained shale gases which largely prevented drilling muds from immersing into the shale pore systems (Cheng et al., 2018). Therefore, gas-bearing shale samples, which are directly pretreated at drilling sites after being recovered from wells and preserved in plastic bags as soon as possible, are commonly used in laboratory studies, and the pore water content (C_PW) of the as-received shale samples can represent the approximate water contents under geological conditions (Hartman et al., 2008; Gensterblum et al., 2013; Korb et al., 2014). The equilibrium water content (C_EW) of a shale sample, which is measured when the shale has reached the moisture equilibrium state in an environment of 100% relative humidity, can represent its approximate maximum confined water content. In this study, the ratio of C_PW to C_EW is defined as the pore water equilibrium extent (E_PW) of shales, and the E_PW is used to approximately characterize the water-bearing extents of shales under geological conditions. The C_PW, C_EW, and E_PW values are used in this study to characterize the water-bearing characteristics of shales, and the differences in pore structures of the shales under as-received and dried conditions are applied to reveal the effects of pore water on shale nanopores. The main procedures of the method used in this study are shown in Fig.2.

3.2 Sample preparations

A total of 12 fresh coal-measure shale core samples (Tab.1) were collected in situ from the WXN-22 well in the Wuxiang area of the Qinshui Basin (Fig.1(a)). The collection and preparation procedures for the as-received shale samples are described below. After the full-size shale cores were taken out of the well, they were immediately broken into large blocks, and one of these blocks was immersed in water to determine whether it contained gas. Shale samples with blocks strongly bubbled in water were collected. Only the blocks from the inner parts of the gas-bearing shale cores were used to drill small plunger samples with 20 mm lengths and 15 mm diameters, and the small plunger samples were sealed in plastic bags and transported as soon as possible to the laboratory for analysis.

3.3 Experiments

3.3.1 Pore water and equilibrium water measurements

A prepared small plunger shale sample was directly weighed to obtain its as-received mass (m_AR, g). After being dried for 12 h in a vacuum oven at a temperature of 105°C and a pressure of < 30 mmHg, the shale samples were weighed again to obtain their dried mass (m_Dry, g). The pore water content (C_PW, mg/g) of the sample was calculated using Eq. (1):

(1)C_{\mathrm{P}\mathrm{W}}=[(m_{\mathrm{A}\mathrm{R}}-m_{\mathrm{D}\mathrm{r}\mathrm{y}})\times 1000]/m_{\mathrm{D}\mathrm{r}\mathrm{y}}.

Then, the dried shale sample was further used in an equilibrium moisture adsorption experiment by following the recommended method from the American Society for Testing and Materials (ASTM D1412-07, 2010). The experimental procedures have been adequately described in previous literature (e.g., Ross and Bustin, 2009; Cheng et al., 2017; Zolfaghari et al., 2017) and are briefly summarized here. The shale samples were placed on the platform of a vacuum desiccator, and the bottom of the desiccator was filled with deionized water to maintain its inner environment at a relative humidity of 100% (Zhang et al., 2004). The desiccator was then placed in a water bath at a temperature of 30°C, and the absolute pressure in the desiccator was evacuated to < 30 mmHg. The moist shale samples were weighed at 12 h intervals, and their pore systems were considered to have reached the moisture equilibrium state when the weighed mass remained constant (m_CE, g). Based on the m_Dry and m_CE values, the equilibrium water content (C_EW, mg/g) of the shale was calculated using Eq. (2). Then, the pore water equilibrium extent (E_PW, %) of each shale sample was further calculated using Eq. (3).

(2)C_{\mathrm{E}\mathrm{W}}=[(m_{\mathrm{C}\mathrm{E}}-m_{\mathrm{D}\mathrm{r}\mathrm{y}})\times 1000]/m_{\mathrm{D}\mathrm{r}\mathrm{y}},

(3)E_{\mathrm{P}\mathrm{W}}=C_{\mathrm{P}\mathrm{W}}/C_{\mathrm{E}\mathrm{W}}\times 100\mathrm{\%}.

3.3.2 Mineralogical analysis

The mineralogical composition analyses were based on dried shale powder samples using granularities of < 75 μm (i.e., < 200 mesh) and were conducted with an X-ray diffractometer (Bruker D8 Advance XRD instrument). The measurements were performed at 40 kV and 30 mA with Cu Kα radiation, and stepwise scanning was performed at a rate of 4°/min that ranged between 3° and 85° (2θ). Based on the peak area of each mineral, the mineralogical compositions of the shales were semiquantitatively estimated and corrected by the Lorentz-polarization method (Chalmers and Bustin, 2008). The average value of two XRD measurements for each sample was used.

3.3.3 Pore structure analysis

The International Union of Pure and Applied Chemistry (IUPAC) generally classifies shale nanopores into micropores (< 2 nm), mesopores (2−50 nm), and macropores (> 50 nm) (Chalmers et al., 2009). This study approximately characterized the micropores and non-micropores (including mesopores and macropores) by using low-pressure CO₂ and N₂ adsorption experiments, respectively. Shale grain samples with granularities of 380–830 µm (20–40 mesh) were used to carry out adsorption experiments by a Micromeritics ASAP 2020^M instrument. The CO₂ adsorption experiment was performed at a temperature of 0°C in an ice-water mixture environment, while the N₂ adsorption experiment was carried out at a temperature of –196.56°C in a liquid nitrogen environment. The relative pressures of the CO₂ and N₂ adsorption experiments are 0.00001–0.032 and 0.005–0.995, respectively. Before the gas adsorption experiments, the dried shale samples were degassed in situ for 6 h at a temperature of 105°C and a pressure of lower than 10 mmHg to further eliminate the potential influences of moisture in the ambient environment (Bustin et al., 2008). However, instead of the degassing procedure, the as-received shale samples in the testing apparatus were directly stored in an ice-water mixture or a liquid nitrogen environment prior to the CO₂ or N₂ adsorption experiments to prevent the potential evaporation losses of their pore water (Cheng et al., 2018, 2019). The micropore surface areas (S_mic) and pore volumes (V_mic) were obtained by using the CO₂ adsorption data according to the Dubinin-Astakhov equation (Dubinin, 1989). The non-micropore surface areas (S_non) were obtained by using the N₂ adsorption data based on the modified Brunauer‒Emmett‒Teller equation (Brunauer et al., 1938; Tian et al., 2015), and the non-micropore pore volumes (V_non) were calculated on maximum N₂ adsorption quantities.

4 Results and discussion

4.1 Geochemical and mineralogical characteristics of the studied shales

The geochemical and mineralogical data for the studied shales are presented in Tab.1. The TOC contents of the shales have a wide range of 1.33−13.82 wt.%, and the R_o and T_max values are 3.29%−3.40% and 590°C−606°C, respectively, which indicates that these shales have evolved to an overmature stage (Tab.1). The shales have low HI and OI values in the ranges of 6−25 mg/g TOC and 2−17 mg/g TOC, respectively (Tab.1).

The main minerals of the shales include clays, quartz, and pyrite, with contents of 34.0−71.9 wt.%, 17.4−53.0 wt.%, and 0.6−13.9 wt.%, respectively (Tab.1). In addition, some shale samples also contain small amounts of feldspar, anatase and dolomite (Tab.1). When compared with the marine gas shales from wells FY1, YQ1, and XK2 in the Upper Yangtze area, south China (Cheng et al., 2018; Sun et al., 2020b), the studied shales are richer in clay minerals and scarcer in carbonate minerals.

4.2 Water-bearing characteristics of the studied shales

The C_PW and C_EW values of the studied shales are 1.99−7.42 mg/g and 19.16−32.90 mg/g, respectively (Tab.2). The C_PW and C_EW values of the shales are closely correlated to their organic and inorganic compositions. Both the C_PW and C_EW values have positive relationships with the clay contents, and the correlation coefficients (R²) are 0.56 and 0.42, respectively (Fig.3(a)); this is mainly because the clays in the shales provide hydrophilic IM pore spaces for water storage (Passey et al., 2010; Wen et al., 2015; Zolfaghari et al., 2017). Except for the WXN22-9 sample, which has a high TOC content and a low clay content (Tab.1), the C_PW and C_EW values of the other samples also exhibit positive relationships with the TOC contents, and the correlation coefficients (R²) are 0.60 and 0.72, respectively (Fig.3(b)); this is probably because the organic matter in the shales generally developed OM micropores that could store water due to capillary binding force (Newsham et al., 2003; Liu and Monson, 2005). The C_PW and C_EW values are negatively correlated with the quartz contents, and the correlation coefficients (R²) are 0.51 and 0.40, respectively (Fig.3(c)); this is probably because the quartz in the shales barely developed nanopores and failed to provide pore spaces for water storage. The C_PW values are much lower than the C_EW values, with E_PW values ranging from 9.98% to 23.47% (Tab.2), which indicates that the bulk pore systems of the shales have low water-bearing extents. Additionally, the E_PW values of the studied shales exhibit positive correlations with the TOC and clay contents and a negative correlation with the quartz content (Tab.2 and Fig.4).

Cheng et al. (2017, 2018) reported that the C_PW, C_EW, and E_PW values of the FY1 and YQ1 overmature Lower Palaeozoic marine shales in the Upper Yangtze area, south China, were 3.70–5.29 mg/g, 8.13–15.04 mg/g, and 34.23%–45.51%, respectively. When compared with marine shales, the studied coal-measure shales have similar C_PW values but larger C_EW values. The low C_PW values for both types of overmature shales may be related to their strong water drainage during thermal evolution stages (Wardlaw and McKellar, 1998; Mahadevan et al., 2007; Cheng et al., 2019). The greater C_EW values of the studied shales are attributed to their higher clay contents (Tab.1) than the marine shales (17.7–40.4 wt% from Cheng et al., 2017) and to the organic matter, with type III kerogen, present in the coal-measure shales being more hydrophilic than the organic matter, with type II kerogen, present in the marine shales (Gu et al., 2016; Gao et al., 2019). In addition, because the filling extent of pore water in shale pores is significantly determined by pore volumes at high moisture equilibrium conditions (Seemann et al., 2017; Chen et al., 2021), the studied shales have larger total pore volumes than marine shales, which may also account for their higher C_EW values.

4.3 Pore structure characteristics of the studied shales

4.3.1 Micropores and non-micropores

The pore surfaces and volumes of the studied shales under as-received conditions are listed in Tab.3. These data indicate that the pore surface areas of the as-received shales are dominantly provided by micropores, while their pore volumes are co-controlled by micropores and non-micropores (Tab.3). The pore surfaces and volumes of the micropores and total pores have positive relationships with the TOC contents, with correlation coefficients (R²) ranging from 0.93 to 0.96 (Fig.5(a), Fig.5(c), Fig.5(d), Fig.5(f)), while those of the non-micropores show no obvious correlations with the TOC contents (Fig.5(b) and Fig.5(e)). The pore surfaces and volumes of all of the pores have no obvious relationships with the clay contents (Fig.6).

The pore surfaces and volumes of the studied shales significantly increase after they are dried (Tab.3). The pore surface areas of the dried shales are still mainly provided by the micropores, while their pore volumes are dominantly contributed by the non-micropores (Tab.3). The pore surfaces and volumes of the micropores, non-micropores and total pores have positive relationships with the TOC contents, with correlation coefficients (R²) ranging from 0.65 to 0.97 (Fig.5). Meanwhile, these parameters also have weakly positive correlations with the clay contents, except for sample WXN22-9 (Fig.6).

The pore structures of the dried shales differ significantly from those of the as-received shales, and the differences in pore structures of the shales under the two conditions can indicate the extent of influence of pore water on the effective pore structures for the storage of shale gas (see Section 4.4).

4.3.2 OM pores and IM pores

At present, it is difficult to exactly determine the OM and IM pores of shales (Löhr et al., 2015; Gu et al., 2016). For the studied shales under dried conditions, the TOC contents exhibit remarkably positive linear correlations with the pore surfaces and volumes of the micropores and total pores (Fig.5(a), Fig.5(c), Fig.5(d), Fig.5(f)); thus, the OM and IM pore surfaces and volumes of the micropores (i.e., S_mic-OM and V_mic-OM, S_mic-IM and V_mic-IM) and total pores (i.e., S_total-OM and V_total-OM, S_total-IM and V_total-IM) can be approximately calculated by the linear regression method as described by Cheng et al. (2018). Then, the OM and IM pore surfaces and volumes of the non-micropores (i.e., S_non-OM and V_non-OM, S_non-IM and V_non-IM) can be obtained by subtracting the calculated micropore surfaces and volumes from the calculated total pore surfaces and volumes.

The calculated OM and IM pore surfaces and volumes of the studied shales are presented in Tab.4 and Fig.7, and a brief discussion is provided in this study that is based on each average pore structure parameter value. The micropore structures of shales are mainly contributed by the OM pores, while the non-micropore structures are mainly provided by the IM pores (Fig.7). Additionally, the S_total values of the shales are dominated by the OM pores, except for sample WXN22-10 (Fig.7(c)), while the V_total values of the shales are mainly contributed by the IM pores for shales with TOC contents < 4 wt.% and by both IM and OM pores for shales with TOC contents > 4 wt.% (Fig.7(f)). Combined with the pore structure data of the studied shales mentioned in Section 4.3.1, it can be further deduced that the S_total values of the studied shales are dominantly derived from S_mic-OM, and the V_total values of the shales are mainly contributed by V_non-IM as well as V_mic-OM.

4.4 Effects of pore water on shale nanopores

4.4.1 Effects of pore water on the micropores and non-micropores

In this study, the water-occupied pore surfaces and volumes of the as-received shale samples and their percentages (P_W) in these pore structures of the dried shale samples (Tab.5) are used to reveal the effects of pore water on various shale nanopores. The results indicate that, except for samples WXN22-9 and WXN22-10, the water-occupied pore surfaces and volumes of the other shales exhibit remarkably positive correlations with the pore water contents, with correlation coefficients (R²) ranging from 0.69 to 0.92 (Fig.8). In addition, the effects of pore water on non-micropores are more significant than those on micropores. Meanwhile, the extents of influence of the pore water are similar on S_mic and V_mic but are greater on S_non than on V_non (Tab.5), which indicates that the pore water may fill the micropores in a condensed state while occupying the non-micropore surface areas in an absorbed state (Cheng et al., 2017).

Although the studied coal-measure shales have pore water contents that are similar to those of the marine shales reported by Sun et al. (2020a), the pore water has greater effects on the pore structures of the coal-measure shales than on those of the marine shales. For example, the average P_W values of S_non and V_mic are 81.99% and 43.44% for the studied shales (Tab.6), respectively, while they are 61% and 30% for marine shales, respectively (Sun et al., 2020a). This is probably because the coal-measure shales are characterized by high clay contents and type III kerogen, which result in the studied shales having a stronger capacity to hold water than the marine shales (Gu et al., 2016; Gao et al., 2019).

The low-pressure gas adsorption isotherms and pore size distributions (PSDs) of V_mic and S_non for samples WXN22-2, WXN22-3, and WXN22-4 were used to further demonstrate the effects of pore water on nanopores with diverse pore widths (Fig.9 and Fig.10). With successive increases in the TOC and clay contents of samples WXN22-2, WXN22-4, and WXN22-3 (Tab.1), the differences in the CO₂ and N₂ adsorption isotherms between the dried and as-received shale samples progressively increase (Fig.9 and Fig.10), which is consistent with the increases in their pore water contents (Tab.2). The micropore PSDs of all three samples show that micropores with pore widths < 0.5 nm were not detected in the as-received samples (Fig.9(d), Fig.9(e), Fig.9(f)), which indicates that these micropores may be fully blocked or occupied by pore water. Li et al. (2017) also reported that pore water can totally take up or block the IM pores of shales with pore widths < 0.6−0.7 nm. The N₂ gas adsorption and desorption isotherms show obvious hysteresis loops for the dried shales, while the hysteresis loops are absent for the as-received shales (Fig.10(a), Fig.10(b), Fig.10(c)). This implies that shales contain narrow pore network systems that induce pore retention effects; however, under as-received conditions, pore water may condense or form water films on the pore mouth of pores with narrow pore widths and block these pores, which obviously decreases the pore retention effects (Thommes et al., 2015; Bertier et al., 2016; Lahn et al., 2020). In addition, compared with the non-micropores with pore widths > 8 nm, the non-micropores with pore widths < 8 nm are occupied by pore water more significantly (Fig.10(d), Fig.10(e), Fig.10(f)), which probably occurs because the former non-micropores have stronger capillary binding forces than the latter non-micropores (Wu et al., 2017).

4.4.2 Effects of pore water on OM and IM pores

Because the hydrophilicity of the IM pores is higher than that of the OM pores when the two types of pores have similar pore widths (McCutcheon and Barton, 1999; Gu et al., 2016; Cheng et al., 2018), under certain geological conditions, the pore water may preferentially take up the IM pores of shales, and after the IM pores are fully occupied, the excess water would then occupy the OM pores. Therefore, if the water-occupied pore surface and volumes of the shales are smaller than their IM pore structures, this implies that the pore water only takes up part of the IM pores but none of the OM pores of shales. However, if the water-occupied pore surfaces and volumes of the shales are greater than their IM pore structures, this implies that pore water occupies all of the IM pore surfaces and volumes as well as a portion of the OM pore structures of the shales.

Based on the above assumptions, this study approximately evaluates the effects of pore water on the IM and OM pore structures of shales. The results show that the average water-occupied surface areas of the OM micropores (S_mic-OMW), non-micropores (S_non-OMW), and total pores (S_total-OMW) are 6.24 m²/g, 0.80 m²/g, and 7.04 m²/g, respectively, and that their P_w values are 26.23%, 28.73%, and 26.42%, respectively (Tab.5 and Tab.6). The S_mic-OMW values are much higher than the S_non-OMW values, but the P_w values are similar (Fig.11). The average water-occupied surface areas of the IM micropores (S_mic-IMW), non-micropores (S_non-IMW) and total pores (S_total-IMW) are 4.16 m²/g, 4.07 m²/g, and 8.23 m²/g, respectively, and their P_w values are 98.18%, 97.37%, and 97.69%, respectively (Tab.5 and Tab.6). The S_mic-IMW and S_non-IMW values as well as their P_w values are similar (Fig.11). The average water-occupied pore volumes of the OM micropores (V_mic-OMW), non-micropores (V_non-OMW), and total pores (V_total-OMW) are 0.0018 cm³/g, 0.0019 cm³/g, and 0.0037 cm³/g, respectively, and their P_w values are 21.74%, 16.61%, and 19.57%, respectively (Tab.5 and Tab.6). The V_mic-OMW values are similar to the V_non-OMW values, but the P_w values of the former are greater than those of the latter (Fig.11). The average water-occupied pore volumes of the IM micropores (V_mic-IMW), non-micropores (V_non-IMW), and total pores (V_total-IMW) are 0.0023 cm³/g, 0.0077 cm³/g, and 0.0100 cm³/g, respectively, and their P_w values are 98.26%, 80.20%, and 83.54%, respectively (Tab.5 and Tab.6). The V_mic-IMW values are much smaller than the V_non-IMW values, but the P_w values of the former are greater than those of the latter (Fig.11). Therefore, the effects of pore water are more significant on the IM pore structures than on the OM pore structures for either the micropores or non-micropores of the studied coal-measure shales.

4.5 Implications for shale gas storage

Although pore water significantly occupies the pore surface and volumes of coal-measure shales, a certain amount of effective pore structures remains for the storage of shale gas. The effective pore spaces in the studied shales can be estimated by the differences between the pore spaces of the dried shales (Tab.4) and the water-occupied pore spaces of the as-received shales (Tab.5). The average percentages of each effective pore structure (P_E) for the studied shales are listed in Tab.7. The P_E values for S_mic-OM, S_non-OM, S_mic-IM, and S_non-IM are 44.90%, 3.31%, 0.76%, and 0.56%, respectively, with a total of 49.53%. The P_E values for V_mic-OM, V_non-OM, V_mic-IM, and V_non-IM are 21.55%, 15.59%, 0.43%, and 10.32%, respectively, with a total of 47.89% (Tab.7 and Fig.12). These data indicate that approximately half of the total pore spaces of the as-received shales are available for the storage of shale gas, and most of the effective pore spaces are provided by the OM pores.

Although overmature gas shales underwent strong displacement drainages during thermal evolution stages (Wardlaw and McKellar, 1998; Mahadevan et al., 2007; Cheng et al., 2019), these shales still retained certain amounts of pore water (Bennion and Thomas, 2005; Liu and Wang, 2013; Fang et al., 2014; Cheng et al., 2018). The pore water can significantly influence the gas-bearing properties of shales; it not only reduces the gas-in-place (GIP) contents by occupying many effective pore spaces for shale gas but also causes the shale gas, especially the absorbed gas, to be mostly stored in the OM pores of shales, while the IM pores mainly store free gas. In addition, although the coal-measure shales in the Qinshui Basin have similar pore water contents to those of the marine shales from some blocks in the southern China area (Cheng et al., 2018; Sun et al., 2020b), the effects of pore water are more significant on the former shales than on the latter shales because the two types of shales differ in their mineral compositions, organic matter types and nanopore structures. The bulk pore systems of coal-measure shales have greater water-bearing extents than those of marine shales, which results in retaining a smaller proportion of the pore structures to store shale gas. Therefore, the water-bearing characteristics and their effects on the nanopores of overmature coal-measure shales should be highly considered for shale gas exploration and development in the Qinshui Basin.

5 Conclusions

This study investigates the water-bearing characteristics and their effects on the nanopores of coal-measure shales taken from the Qinshui Basin, north China, and mainly reaches the following conclusions.

1) The pore water contents (C_PW) of the studied shales are much lower than their equilibrium water contents (C_EW), which indicates that the bulk pore systems of the shales have low water-bearing extents, with pore water equilibrium extents (E_PW) ranging from 9.98% to 23.47%.

2) The influences of pore water are more significant on the non-micropores and IM pores than on the micropores and OM pores, respectively, for the studied coal-measure shales, especially for the pore surfaces of IM pores.

3) The pore water of coal-measure shales not only takes up approximately half of the total pore surfaces and volumes, which reduces the storage space of shale gas, but also causes the shale gas, especially the absorbed gas, to be mainly stored in the OM pores; meanwhile, the IM pores mainly contain free gas.

6 Nomenclature

C_PW = pore water content

C_EW = equilibrium water content

E_PW = pore water equilibrium extent

OM = organic-matter hosted

IM = inorganic-matter hosted

S_mic = micropore surface area

V_mic = micropore volume

S_non = non-micropore surface area

V_non = non-micropore volume

S_total = total pore surface area

V_total = total pore volume

R_o = vitrinite reflectance value

T_max = maximum cracking temperature

HI = hydrogen index

OI = oxygen index

XRD = X-ray diffraction

P_W = percentage of water-occupied pore structure

P_E = percentage of effective pore structure

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