Introduction

Organic-rich shales, in recent years, have emerged as a source of excitement for researchers dealing with petroleum-systems, as these represent self-contained petroleum systems with vast oil and gas resources (Schmoker 1995; Loucks et al. 2009, 2012; Jarvie 2012a, b; Peters et al. 2016; Wood and Hazra 2017a). Beyond acting as sources of unconventional oil and gas, shale and other organic-rich reservoirs have also emerged as attractive targets for carbon dioxide (CO2) sequestration for combating the rising CO2 levels in the atmosphere (Vishal et al. 2013a, b, 2019; Godec et al. 2013; Merey and Sinayuc 2016). The factors which directly control the potential of shale to act as petroleum systems or CO2 sequestrating horizons are its organic-matter richness, kerogen type, thermal maturity of organic-matter, and the nature of pore structures within them which holds the gas/oil and can be possible sites for CO2 storage (Tissot and Welte 1978; Jarvie et al. 2007; Mastalerz et al. 2013; Hazra et al. 2019a).

For predicting the source rock properties, the Rock-Eval technique is used extensively by researchers, as it allows fast and reproducible analysis of samples, producing set-of vital source rock parameters utilizing only small sample-amounts for the experiments (Carvajal-Ortiz and Gentzis 2015). The pore structures within shales on the other hand control the mechanism of gas adsorption-desorption and mode of fluid-flow (Loucks et al. 2009). Thorough evaluation and depiction of shale-porosity are thus crucial for assessing the oil and gas present within them and to understand their storage capacity (Zhang et al. 2012; Wood and Hazra 2017b; Hazra et al. 2019b). While different techniques exist to map pore structures in shales, in recent years, subcritical gas-adsorption techniques, using nitrogen (N2), have emerged as convenient tools for distinguishing a range of pore-size components within the pore-scale distribution of shales (Ross and Bustin 2009; Yang et al. 2014, 2016a, b; Holmes et al. 2017; Psarras et al. 2017; Hazra et al. 2018a).

Fractal dimensions calculated from information derived from low-pressure N2 adsorption are successfully assessed to characterize the complex pore structures in organic-sedimentary rocks (Yao et al. 2008; Wood and Hazra 2017b). Recent works have also revealed the existence of two well-defined fractal indices in shales, corresponding to the adsorption behaviors at lower-relative pressure (D1; P/P0 < 0.50) and higher relative pressure (D2; P/P0 > 0.50) intervals (Wang et al. 2016; Hazra et al. 2018a, b).

The inability of N2 to penetrate at lower pressures and experimental temperatures conditions (− 196 °C) typically results in the undercounting of the ultrafine microporous components in organic-matter (Ross and Bustin 2009). This also leads to under-representation of the fractal-metric corresponding to the lower pressure zone. In this work, we examine the validity of fractal dimensions and pore structural data for several shale samples at different stages of thermal maturity and organic-matter contents using N2 as adsorbate.

Currently, India is strongly dependent upon oil and gas imports to supply its growing domestic energy consumption and large population. In this regard, shale petroleum systems and coal bed methane (CBM) offer indigenous resources that could potentially be exploited (Vaid 2017) to help and support the country’s energy needs. The United States Energy Information Administration (EIA 2013) calculated a total of approximately 584 trillion cubic feet risked shale gas-in-place in India. Among Damodar Valley basins, the Central Mine Planning and Design Institute of India estimated 45 trillion cubic feet of shale gas in 6 sub-basins of Jharia¸ Bokaro, North and South Karanpura, Raniganj, and Sohagpur (Press Information Bureau 2015). Consequently, source rock properties, organo-petrographic composition, mineralogical composition, methane storage capacity, and pore structural attributes of India’s Permian shale beds are the focus of attention in several recent studies (Varma et al. 2014, 2015; Hazra et al. 2015, 2018a, b; Boruah and Ganapathi 2015; Mendhe et al. 2017). However, only a few studies have focused on source rock properties and pore structural frameworks of the Jharia basin shales.

In this work, we examine source rock properties and the pore structural framework of the Jharia basin shales. The Jharia basin is the most important of the Damodar Valley sub-basins in terms of its exploitable coking coals resources (Mishra and Cook 1992). This is because the coals in Jharia basin are thermally more mature than the coals from adjoining basins (Mishra et al. 1990). The Jharia basin is also known to be strategically important for having significant CBM resources. Peters (2000) prioritized the Jharia basin as a key Indian basin for potential CBM exploration. The organic-matter in the coals from Jharia basin has the desired thermal maturity to generate gaseous hydrocarbons. Therefore, studying the organic-matter within the shales of basin of the same geological age (Lower Permian) can also be beneficial for understanding their gaseous hydrocarbon generation and gas storage potential.

Regional geology

The Jharia basin, located in Jharkhand state of India, is one of several hydrocarbon (petroleum and coal) resource-bearing, sub-basins of Damodar Valley, eastern India because of its coking coal reserves (Fox 1930). Showing a sickle-shape like structure, it covers approximately an area of 450 km2 (Peters 2000). The Jharia basin represents a half-graben structure (Chatterjee and Ghosh 1970), with an east-west trending basin axis that plunges westward. Furthermore, the southern-flank of the basin is abruptly curtailed by a major regional fault(southern-boundary-fault) with a throw of over 1500 m (GSI 1977).Exposures of all Lower Gondwana Formations of Permian age are present in the basin. The Upper Permian Raniganj Formation is also exposed in this basin (Peters 2000). The Barakar Formation contains the basin’s most prolific coal resources with eighteen coal well-developed seams (Fox 1930). The Upper Permian Raniganj Formation also includes thirteen coal seams. The Barren Measures Formation, amid the Raniganj and Barakar Formations, is devoid of any coal and attains a maximum thickness of ~ 750 m (Mukhopadhyay et al. 2010). Igneous intrusions in the form of mica-peridotite and dolerite dykes and sills are quite common at various locations scattered across the basin. These intrusions have increased the rank of coals adjacent to them due to thermal metamorphism (Pareek 1965; Chakrabarti 1969; Singh et al. 2007, 2008, 2013).

The studied area is placed to the east of the Parbatpur area in the Jharia basin (Fig. 1). CBM potential was initially evaluated in the Parbatpur area 2 decades ago (Peters 2000). Since then, commercial activities focusing on CBM flow have centered on the Parbatpur and adjoining areas. Peters (2000) estimated the Parbatpur block to have approximately 24 billion cubic meters of CBM resources.

Fig. 1
figure 1

Geographical position, geological features, formations, and sampling locations in Jharia basin (modified after Fox 1930; CIL 1993)

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Materials and methods

Sample details

Twenty-three shales, from different depths, were collected from two boreholes, A1 and A2 drilled in the Jharia basin, the locations of which are marked in Fig. 1. The depths and formations of these twenty-three samples are mentioned in Table 1.

Table 1 Jharia basin shale samples from wells A1 and A2: details and depths
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Non-isothermal programmed-pyrolysis experiments

A Rock-Eval 6 equipment with built-in “basic method” was utilized for conducting pyrolysis and oxidation experiments on these Jharia Basin samples. These tests were performed to understand their petroleum-generation potential, organic richness, and thermal maturity. The details of the equipment and the method used are given in Lafargue et al. (1998) and Behar et al. (2001). Furthermore, since Jharia Basin shales predominantly comprises of type III-IV kerogen, revised analytical protocols as suggested by Hazra et al. (2017, 2019c, 2019d) were adopted.

Nitrogen (N2) gas adsorption

Using N2 gas at low pressures and temperatures, adsorption-desorption tests were performed with a Micromeritics-TriStar 3000 device. Sample sizes used were approximately 212 μm or less. Adsorption-desorption isotherms are based on a relative pressures (P/P0) range between 0.01 and 0.995. Sample temperatures were less than the critical temperature of N2 at 77.35 degrees Kelvin (°K). Sample gas pressure/N2 saturation pressure ratio (P/P0) measurements enable P0 to be determined automatically at the known sample temperatures of 77.35 K. Pore surface areas, volumes, and pore sizes of each sample were calculated from the recorded data. The Brunauer-Emmett-Teller (BET) specific surface area (BET SSA) was derived over the relative-pressure range of 0.05 to 0.35 (Brunauer et al. 1938).

The commonly used Frenkel-Halsey-Hill (FHH) adsorption isotherm model was utilized to establish the fractal dimensions of the shale samples tested. It involves evaluating equation (i) (Qi et al. 2002; Yao et al. 2008):

$$ \ln \left(\frac{\mathrm{V}}{\mathrm{V}0}\right)=\mathrm{A}\left[\ln \left(\ln \left(\frac{\mathrm{P}0}{\mathrm{P}}\right)\right)\right]+\mathrm{constant} $$
(i)

where

P and P0 are equilibrium and saturation pressures of the used-gas, respectively;

V and V0 represent volume of adsorbed gas molecules and monolayer capacity, respectively;

A = power-law exponent which is controlled by the fractal dimension (D) and the means of adsorption.

D is worked out from the slope (S) of the straight-line in the lnV vs ln [ln(P0/P)] FHH plot using either equation (ii) or (iii).

$$ S=D-3 $$
(ii)
$$ 3S=\left(D-3\right) $$
(iii)

Together, equations (ii) and (iii) are used in practice to obtain the fractal dimension D (Qi et al. 2002). However, when equation (iii) was used to measure the fractal-metrics, D1 was observed to be negative in all cases, while D2 was observed to be negative in one instance (see Table 4). As fractal values should vary between 2 and 3, the fractal-metrics were calculated only using equation ii.

Results and discussions

Source rock characterization

Barren Measures Formation

The TOC contents of the Barren Measures Formation (BMF) shale samples vary between 2.08 and 6.15 wt%, i.e., within the ranges of “very good” to “excellent” source rock richness (Peters and Cassa 1994). The residual carbon (RC) component of the TOC (1.95 to 4.96 wt%) was observed to be much greater than the pyrolyzable carbon (PC) component (0.13 to 1.19 wt%). Not surprisingly, the RC/PC ratio varied from 4.17 to 15 and was the highest in the most thermally mature shale sample (BM-Sh-11) and least in the shale sample (BM-Sh-7) marked by the highest TOC and hydrogen index (HI) contents (Table 2).

Table 2 Source rock properties of Jharia Basin shales derived from Rock-Eval analysis
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The hydrogen indices of these varied in-between 66 and 206 mg HC/g TOC, signifying predominantly type-III kerogen (Peters and Cassa 1994). Temperature-maxima (Tmax) of S2 ranged between 442 and 460 °C, i.e., between “early mature” to “peak mature” stages of thermal maturity (Peters and Cassa 1994). The samples with the highest measured thermal maturity levels (BM-Sh-10 and BM-Sh-11) also displayed the lowest S2 and HI values. These relationships are consistent with the expected influence of thermal maturity on petroleum generation and expulsion from source rocks.

Figure 2 shows the HI-Tmax cross-plot for the Barren Measures Formation shales. Generally, when shales reach the oil-window stage of maturity, the HI values can be variable depending upon the type of kerogen present. However, once the oil-window is crossed, with some expulsion of petroleum having occurred, the S2 and HI values are reduced. Consequently, the ‘peak mature’ shales show least HI (Table 2; Fig. 2).

Fig. 2
figure 2

HI vs Tmax plot for the Barren Measures Formation Jharia Basin shale samples

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The HI vs TOC cross-plot (Fig. 3) distinguishes the oil and gas generating properties of the Barren Measures and the Barakar Formations. Boundaries displayed in Fig. 3 characterize the nature of the source rock in accordance with the distinctions identified by Jackson et al. (1985). Only sample BM-Sh-7 of the Barren Measures Formation shales falls within the “good oil source” category. This sample is also marked by the lowest RC/PC ratio, i.e., it contains more reactive or pyrolyzable carbon than residual carbon, which is consistent with its better petroleum generation potential than the other samples from Barren Measures Formation. It also displays the maximum S1 value among the Barren Measures Formation shales (Table 2).

Fig. 3
figure 3

HI vs TOC cross-plot for all Jharia Basin shale samples analyzed. The source rock-category compartments and boundaries displayed are modified after Jackson et al. 1985

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Barakar formation

The Barakar Formation shale samples analyzed contain substantially more organic material than the Barren Measures. Their TOC contents vary between 11.20 and 22.78 wt%. The Barakar Formation shale samples are also substantially more thermally mature (Tmax varies from 461 to 602 °C) than the Barren Measures shales. These samples lie within the condensate/wet-gas and dry-gas windows of thermal maturity (Fig. 4). This is likely to be due to the greater burial depths reached by the Barakar formation than the Barren Measures, allowing them to be exposed to higher temperatures.

Fig. 4
figure 4

HI vs Tmax plot for the Barakar Formation shales from the Jharia Basin

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Previous studies (Pareek 1965; Chakrabarti 1969) have documented that Jharia basin is marked by higher geothermal gradients than the surrounding Permian basins, due to the greater impact of igneous intrusions. The presence of several coal seams at coking ranks within the Barakar Formation is consistent with high heat flows in the basin, which hosts significant reserves of coking coals.

As is the case for the Barren Measures shale samples, the residual carbon (RC) component of TOC (varying from 10.51 to 21.19 wt%) for the Barakar Formation shale samples is much greater than the pyrolyzable carbon (PC) component (varying from 0.43 to 2.13 wt%). The RC/PC ratio was observed to be highest in the thermally mature shales (Table 2). HI varied within the range of 19 to 141 mg HC/g TOC. A strong decreasing trend of HI was observed for these shales with increasing Tmax. This is consistent with the expectation that with increasing thermal maturity levels, expulsion of hydrocarbons takes place and lowers the present day HI.

The Barakar Formation shale samples show a wider spread on the HI versus TOC cross-plot (Fig. 3). Only the most thermally mature shales (Br-Sh-15 and Br-Sh-16) plot in the “gas source” field. The remaining samples from this formation fall into the “gas and/or oil source” category (Fig. 3) due to their elevated maturity levels. Only the least mature sample, BM-Sh-7, falls within the “good oil source” category on the HI-TOC plot. Furthermore, this shale sample also displays the maximum S1, S2, and HI values among the Barakar Formation shales (Table 2).

N2 adsorption of barren measures formation shales

Pore structure parameters and pore size distribution

Figure 5 displays the nitrogen-gas adsorption isotherms of the Barren Measures shales. All the samples are marked by considerable hysteresis, indicating the occurrence of capillary condensation within the mesoporous structures (Sing 1985). Hysteresis in adsorption isotherms describes the phenomenon in which desorption isotherms display higher equilibrium moisture contents than absorption at equal temperatures. However, none of the isotherms possess shapes similar to type IV isotherms i.e., absence of any plateau at the end of adsorption isotherms, which are typical of mesoporous materials. None of the isotherm shapes show a “reversible” nature, which is characteristic of type II macroporous materials. Rouquerol et al. (1998) defined these types of isotherms as II-B, which represents a combination of mesoporous and macroporous materials. All the Barren Measures shales displayed H2 hysteresis patterns, which characteristically indicates the presence of “ink-bottle” pore shapes (i.e., narrow neck-wide bodies) (Sing 1985).

Fig. 5
figure 5

N2 adsorption-desorption isotherms of the Barren Measures Formation shales

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The BET SSA of the shales varies within the range of 7.04 and 23.77 m2/g rock (Table 3). The highest SSA was displayed by sample BM-Sh-11, which also displayed the lowest average pore size, maximum Tmax, and lowest TOC values. The dependency between SSA of shales and their TOC and/or thermal maturity levels is apparent from studies of several shale basins (Wood and Hazra 2017a). The SSA of the Barren Measures shale samples shows no correlation relationship with their TOC contents (Fig. 6a). However, it does display a positive relationship with Tmax (Fig. 6b). The positive control of maturity levels on SSA in the Jharia Basin Permian shale samples is consistent with earlier findings for Permian shales from other basins of India (Hazra et al. 2018a, b, 2019b).

Table 3 Nitrogen gas adsorption results of the collected shale samples
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Fig. 6
figure 6

Barren Measures Formation shale samples: a BET SSA versus TOC; b BET SSA versus Tmax (6B)

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The SSA shows a negative relationship with average pore sizes of the studied shales (Fig. 7a; R2 = 0.84), which in turn is also influenced by the Tmax values (Fig. 7b). The most mature shale samples (BM-Sh-10 and BM-Sh-11) display the lowest average pore radii (19.78 and 19.52 Å). These relationships, combined with the lack of any correlation BET SSA with TOC content (Fig. 6a), suggest that thermal maturity is a key controlling factor in the evolution of porous structures within the organic-matter in these shale samples. The average pore radii in these samples varied between 19.52 and 30.74 Å.

Fig. 7
figure 7

Barren Measures Formation shale samples: a BET SSA versus average pore radius; b average pore radius versus Tmax

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The Barret-Joyner-Halenda (BJH) pore volume measurements show a strong positive correlation with the BST SSA values in these shale samples (Fig. 8). Closer examination of Fig. 8, and the data presented in Table 3, reveals that sample BM-Sh-12 has a greater pore volume (0.023 cc/g), than sample BM-Sh-11 (0.021), despite having a lower SSA, Tmax, and larger average pore radius.

Fig. 8
figure 8

Plot displaying the relationship between BET SSA and BJH pore volume of Jharia Basin Barren Measures Formation shales

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Figure 9a plots the adsorption isotherm of samples BM-Sh-11 and BM-Sh-12. These reveal that at up to relative pressure of 0.85, the gas adsorption amount for sample BM-Sh-11 exceeds that of BM-Sh-12. However, beyond that relative pressure, the sorption amount of BM-Sh-12 exceeds the sorption amount of BM-Sh-11; consequently, sample BM-Sh-12 achieves a larger sorption capacity (15.51 cc/g) than sample BM-Sh-11 (15.00 cc/g) from a larger pore volume but smaller SSA, with the volume of adsorbed by its SSA measuring portion being lower. However, at higher relative pressures, owing to the macro-porous character of sample BM-Sh-12, the sorption capacity is increased. The larger average pore radius (Table 3) and the dV/dlog(r) vs pore radius plot (Fig. 9b) also reveal the more macro-porous character of BM-Sh-12 relative to BM-Sh-11.

Fig. 9
figure 9

Adsorption isotherms of samples BM-Sh-11 and BM-Sh-12: a at lower relative pressures, the sorption capacity of BM-Sh-11 is higher, while at higher relative pressures, the sorption capacity of BM-Sh-12 exceeds that of BM-Sh-11, owing to its macro-porous character; and b dV/dlog(r) vs pore radius for these two samples

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Fractal dimensions

Figure 10 displays the fractal plots of the Barren Measures Formation shale samples from data listed in Table 4. At lower relative pressures (P/P0 < 0.50), the fractal metric D1 varies between 2.55 and 2.62, while higher relative pressure (P/P0 ≥ 0.50 < 1.00), fractal metric D2 varied between 2.68 and 2.81.

Fig. 10
figure 10

FHH plot of the Barren Measures shales

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Table 4 Fractal parameters calculated using N2 adsorption data for the Jharia Basin shales
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Those Barren Measures Formation shale samples that are the most thermally mature, BM-Sh-10 and BM-Sh-11, display the highest D1 and D2 values (Table 4). In line with pore properties of the Barren Measures shales, the D1 and D2 values display no correlation with TOC contents. On the other hand, D2 displays a positive correlation with Tmax, whereas D1 values do not display a high correlation with Tmax (Fig. 11a). Similarly, only a poor correlation exists between BET SSA and D1, while a strong positive correlation is apparent between BET SSA and D2 (Fig. 11b). On the other hand, average pore radius displays a moderate negative correlation with D1 (R2 = 0.69), but a strong negative correlation with D2 (R2 = 0.99; Fig. 11c). The stronger negative relation between D2 and pore size, the positive correlation between D2 and SSA (Fig. 11), and the negative relations between pore sizes and SSA, and with Tmax (Fig. 7), all indicates that with increase in maturity levels, finer pores are generated, yielding larger surface areas and more complex fractal dimension D2.

Fig. 11
figure 11

Cross-plots between fractal dimensions and other pore properties for the Jharia Basin Barren Measures Formation shale samples

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However, the lack of correlation between fractal metric D1 and several pore parameters indicates some complex mechanisms operating in controlling D1, which are not clear from the results presented for the Barren Measures Formation shale samples studied. The inference of macro-porous character for sample BM-Sh-12, as presented in Fig. 9, and already discussed, is also corroborated by its smaller D2 value (i.e., less complex pore structure) relative to samples BM-Sh-10 and BM-Sh-11, although sample BM-Sh-12 has a higher pore volume. As BM-Sh-12 is marked by larger macro-porous structures, its pore volume and radius are higher, while its D2 value is smaller.

The novel fractal-differentiating factor, ∆S, recently introduced by Hazra et al. (2018a, b), showed some important relationships. ∆S represents the difference between the slopes of the linear portions at P/P0 of 0.5–1.0 and 0–0.5 in the fractal plots, and is expressed by the equation (iv):

$$ \Delta S={S}^{\mathrm{P}/\mathrm{P}0:0.5-1.0}\hbox{--} {S}^{\mathrm{P}/\mathrm{P}0:0-0.5} $$
(iv)

∆S displays a positive relationship with SSA and Tmax (Fig. 12a, b), while showing negative relationship with pore sizes (Fig. 12c). These correlations indicate the effect of maturity on pore properties of these shale samples. It further establishes that ∆S can be used as a proxy to predict pore structural complexities and peculiarities.

Fig. 12
figure 12

Cross-plots showing the relationships between the novel fractal-differentiating factor ∆S, and other studied properties for the Jharia Basin Barren Measures Formation shale samples

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N2 gas adsorption of the Barakar Formation shales

Figure 13 displays the N2 gas-adsorption isotherms of the Barakar Formation shales. Similar to the Barren Measures shales, the Barakar Formation shale samples are also marked by considerable hysteresis. They match most closely with the type II-B shape i.e., a combination of meso-porous and macroporous structures (Rouquerol et al. 1998). While for the Barren Measures shale samples total closure of hysteresis loops is apparent, for the Barakar Formation shales for several samples, the hysteresis loops are open. Earlier studies have suggested that the opening of the hysteresis loops is caused by swelling and/or adsorption in the microporous structures of the material (Mastalerz et al. 2012).

Fig. 13
figure 13

N2 gas adsorption-desorption isotherms of the Jharia Basin Barakar Formation shale samples

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By some magnitude, the BET SSA of the Barakar Formation shale samples is substantially smaller (3.54–10.05 m2/g) than that of the Barren Measures shale samples. This is despite the Barakar Formation shale samples displaying much larger TOC contents and higher thermal maturity levels. The higher thermal maturity levels of these shales, associated with their greater abundance of organic-matter, suggest that they should possess more abundant microporous structures (Pommer and Milliken 2015). However, their low BET SSA values do not support this.

Poor correlations exist between SSA of Barakar Formation shales and Tmax (Fig. 14a) and TOC (Fig. 14b), especially if samples Br-Sh-15 and Br-Sh-16 are disregarded. Furthermore, only poor correlations exist between the average pore radii and TOC and Tmax for the Barakar Formation shale samples (Fig. 14c, d). However, the thermally most mature shales (Br-Sh-15 and Br-Sh-16) display the lowest average pore radii. The lack of any strong relationships for the Barakar Formation shale samples is noteworthy and indicates some peculiarities in the pore properties of these shales. The pore volumes of the Jharia Basin Barakar Formation shale samples are also smaller than that of the Barren Measures shales.

Fig. 14
figure 14

Jharia Basin Barakar Formation shale samples cross-plot relationships: a BET SAA vs thermal maturity; b BET SSA vs TOC; c average pore size vs thermal maturity; and d average pore size vs TOC

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Table 4 shows the details of the fractal parameters calculated for all shale samples. Fractal metrics D1 and D2 vary for the Jharia Basin Barakar Formation shale samples between 2.54 and 2.63 and 2.65 and 2.80, respectively. Although the Barakar Formation shale samples are more mature than the Barren Measures shales, the fractal dimensions for the Barakar Formation shale samples are quite similar and/or smaller than the Jharia Basin Barren Measures Formation shale samples (Fig. 15). The fractal dimensions display relatively poor correlations with TOC, Tmax, and BET SSA, especially if samples Br-Sh-15 and Br-Sh-16 are disregarded. On the other hand, they display moderate correlations with average pore radius (Fig. 16). These relationships and the existence of only poor correlations displayed in Fig. 14 are indeed conspicuous. They suggest that some peculiarities in the pore properties of the Barakar Formation shale samples also exist.

Fig. 15
figure 15

FHH plot of the Barakar Formation shales

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Fig. 16
figure 16

Cross-plots between fractal dimensions and other pore properties for the Jharia Basin and the Barakar Formation shale samples

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Discussions

The results presented in this study shows that the Barakar Formation shales, inspite of being thermally more mature and organic-rich, are marked by lower N2 surface areas, porosities, and fractal dimensions. Generally, with increasing thermal maturity levels, with formation of secondary organic-porosity, surface areas and fractal dimensions increase. At the smallest sizes of micropores, the walls of the pores are very closely spaced. This means that the gas adsorbate and the shale matrix adsorbent need little interaction energy for adsorption to occur. These ultra-small micropores therefore tend to adsorb gas at very low relative pressures (P/P0) (Rouquerol et al. 1998). However, N2 gas in low pressure adsorption tests is at a very low temperature and probably does not possess enough thermal energy to gain access to the smaller constricted micropore sizes at low relative pressures. The actual pore structural properties for highly mature or over mature Barakar Formation shales with abundant small-radii microporosity might not be thoroughly accessed using N2 as the adsorbate.

Furthermore, this lack of ability of N2 to penetrate and detect complex microporous structures also indicates that the low pressure fractal dimension (D1) might also be undercounted. Figure 17 displays a comparative-plot of D1 and D2 values for 112 diverse published shale samples from several studies focusing on shales from China and India, including those used in this study. For these samples, the fractal D2 values are always larger than D1 values. Lower D1 fractal-dimension values are observed for the 112 shales compared, including some over-mature shale samples with well-developed small-scale micropores. This supports the interpretation that there is a limited access to the finer scale micro-porosity present in many organic-rich shales during low pressure N2 gas adsorption tests.

Fig. 17
figure 17

D1 and D2 values for diverse shale samples, calculated using Eq. ii (the “Nitrogen (N2) gas adsorption “section). The line graph as shown in a reveals that D2 is larger than D1 in all the samples considered. Fig. b plots the ratio of D2/D1 vs D2 and also clearly shows that D2 is consistently greater than D1 in all the samples considered. The data includes samples used in this study, and those from Shihezi Formation, Huainan Coalfield, China (Bu et al. 2015); Lower Cambrian Qiongzhusi formation, South China (Li et al. 2016); upper Ordovician Wufeng and lower Silurian Longmaxi Formation shales, Sichuan basin China (Yang et al. 2016a, b); Lower Cambrian and Lower Silurian shale units, upper Yangtze area, China (Wang et al. 2016); Lower Cambrian Niutitang Formation Shale, China (Sun et al. 2016); lower Silurian Longmaxi shales, China (Shao et al. 2017); lower Permian shales, Raniganj basin, India (Hazra et al. 2018a, b)

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Conclusions

  • The Barren Measures Formation shales from the Jharia basin are characterized at “early to peak” thermal maturity and as “very good” to “excellent” source rocks in terms of their TOC contents. All samples analyzed are “fair to good” in terms of their oil-generation potential. The Barakar Formation shale samples are more organic-rich and thermally mature than the Barren Measures Formation shale samples, placing them within the condensate wet-gas and dry-gas windows of thermal maturity.

  • N2 gas adsorption-desorption experiments reveal the Barren Measures shale samples to have high BET SSA, with complex fractal dimensions. Most of the pore properties of these samples are strongly influenced by the thermal maturity levels. On the other hand, quiet conspicuously the Barakar Formation shale samples display lower BET SSA with less-complex fractal dimensions, despite having higher thermal maturities than the Barren Measures shale samples.

  • The observed discrepancy related to N2 gas adsorption data inferred porous structures in relation to organic-richness and thermal maturity levels could possibly be due to the lack of ability of N2 to penetrate and detect complex microporous structures, resulting in undercounting and improper representation of microporous structures.

  • The fractal D1 metric values compared with fractal D2 metric values reported for many shale types across different geological settings and countries is also consistent with the probable inability of low pressure N2−gas adsorption tests to adequately represent complex microporous structures and the corresponding low-pressure fractal metrics.