A study on the effect of gas shale composition and pore structure on methane sorption

Journal of Natural Gas Science and Engineering 62 (2019) 144–156

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A study on the effect of gas shale composition and pore structure on methane sorption

T

Santanu Bhowmik∗, Pratik Dutta Department of Mining Engineering, Indian Institute of Engineering, Science & Technology, Shibpur, P.O.- Botanic Garden, Howrah, 711 103, West Bengal, India

A R T I C LE I N FO

A B S T R A C T

Keywords: Shale Methane absolute adsorption CO2 micropore adsorption Negative adsorption Pore-heterogeneity of shale Void volume estimation

Ten moist, powdered European shale samples were analyzed for their sorption properties by volumetric method. The adsorption capacities were correlated to the shale organic types and maturity. The pore-size distribution obtained from low-pressure CO2 micropore adsorption was also correlated with the porosity and shale organic types. Furthermore, pore volume and average pore width were taken into consideration to determine the dominant parameters controlling adsorption. To identify the discrepancy between available and actual pore space for adsorption, helium and krypton gases were used for void volume estimation. Methane adsorption isotherms follow Langmuir Type I behavior and, in general, showed a positive trend with Total Organic Content (TOC) and Hg-porosity although some deviations were also observed. Low to moderate level of hysteresis between adsorption and desorption isotherms for some samples was visible, which may be attributed to the experimental uncertainty and existence of heterogeneous pores for shale-methane interaction. The low-pressure micropore adsorption analysis indicated dominance of nanopore and very fine micropores in the shale matrix structure along with associated microporosity of the clay materials. The observed “negative” adsortion or “decline” in adsorption isotherm are related to the mismatch of the available pore spaces for helium and methane. In general, He-calibrated isotherms showed higher levels of adsorption than the corresponding Kr-calibrated isotherms although the unit void volume for all samples follow a negative trend with the maximum methane capacity.

1. Introduction Shale gas reservoirs are fine-grained, unconventional gas reservoirs where gases (mainly methane) are stored in the porous spaces in free state and also into the internal structures of the shale matrix in adsorbed state (Bustin et al., 2008a; Jenkins and Boyer, 2008). Unlike the coalbed methane reservoirs, where ∼90% of gas is in adsorbed state, shale gas reservoirs contain higher component of free gas stored both in the organic as well as the non-organic matter (Wang et al., 2009). The adsorbed gas capacity of the reservoir depends on the shale composition like total organic content, internal pore structure, presence of mudrock/ clay/kaolinite or other inorganic constituents in pores, and reservoir conditions like temperature, pressure etc. (Bustin et al., 2008b; Chalmers and Bustin, 2008; Ross and Bustin, 2007; Sondergeld et al., 2010; Zhou et al., 2018). As the organic matter present in shale is generally less than 10%, the adsorbed gas capacity is much less compared to that of coal (Kang et al., 2010). Also, the average pore-size and

∗

the available surface area in shale matrix are much less compared to that of coal matrix, which reduces the overall gas sorption capacity (GRI, 1996). The methane adsorption capacity of shale is generally measured by the isotherm experiments conducted in the laboratory, following the gravimetric or volumetric methods employing the mass-balance equations, same as that used in case of coal. Earlier studies of methane adsorption on shale reported that the adsorption isotherm follow the Langmuir Type I behavior and total organic content of shale mainly govern the gas sorption capacity (Chareonsuppanimit et al., 2012; Chen et al., 2017; GRI, 1996; Heller and Zoback, 2014; Kang et al., 2010; Lu et al., 1995; Rexer et al., 2014; Ross and Bustin, 2009; Weniger et al., 2010). However, it is also observed that the presence of clay materials (kaolinite, illite, mudrocks) have micro-porosities associated with them and can increase the gas sorption capacity by giving additional surface area for adsorption (Aringhieri, 2004; Ji et al., 2012; Gasparik et al., 2014). The degree of thermal maturity and types of organic matter are

Corresponding author. Department of Petroleum Engineering & Earth Sciences, University of Petroleum & Energy Studies, Dehradun, Uttarakhand, 248007, India. E-mail address: [email protected] (S. Bhowmik).

https://doi.org/10.1016/j.jngse.2018.12.009 Received 19 June 2018; Received in revised form 19 November 2018; Accepted 11 December 2018 Available online 13 December 2018 1875-5100/ © 2018 Elsevier B.V. All rights reserved.

Journal of Natural Gas Science and Engineering 62 (2019) 144–156

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2.2. Sorption isotherm tests

also reported to influence the gas sorption capacity (Zhang et al., 2012). Again, the heterogeneity of the pore-size distribution1 (i.e., mean porewidth and total pore volume) and filling of the pores with organic/ inorganic constituents within the shale have made it extremely difficult to get a clear picture of the internal pore structure (Bustin et al., 2008b). High-resolution scanning electron microscopy (SEM), transmitted electron microscopy (TEM), small-angle neutron scattering (SANS) results have revealed the complexity of the micro-/nano-pore system and associated total organic content (TOC) in shale (Chalmers et al., 2012; Clarkson et al., 2012, 2013; Loucks et al., 2009; Milliken et al., 2013). Although mass-balance equations are universally applied for calculating the sorption capacity, the same equations may be difficult to apply for calculating adsorption in shale samples, which sometimes may yield negative calculated methane excess adsorption (Gasparik et al., 2014; Marsh, 1987). Matching of the pore-throat diameter of shale and that of adsorbate gas is also an important consideration for void volume estimation in gas adsorption, which is normally done with a non-adsorbing gas like helium. As a consequence, the availability of pores for methane may be less than that estimated by helium, which in turn, may underestimate the sorbed gas capacity for methane (Bustin et al., 2008a; Ross and Bustin, 2007, 2009). This paper presents the results of pure methane adsorption/desorption characteristics on a set of shale samples and highlighting these deficiencies. The powdered and moist shale samples prepared for adsorption, were calibrated both with Helium and Krypton (which has almost similar molecular diameter as of methane) to observe the change in void volume estimation and then the pure methane adsorption capacities of the shale samples were measured following the volumetric isotherm tests. Finally, all the sorption capacities were correlated with shale composition, pore-size distribution, and other parameters governing the methane adsorption.

The methane sorption capacity of the shale samples was measured using a high-pressure manometric gas-sorption apparatus, the description of which is given by Dutta et al. (2011). The isotherm tests were conducted at 30 °C ( ± 0.1 °C), up to the highest sample cell pressure of ∼8500 kPa with ∼25 g of powdered, wet shale samples. The compressibility factors of gases were calculated based on Span-Wagner Equation-of-state (Span and Wagner, 1996), and the adsorbed capacities were calculated using Real Gas Law (Arri et al., 1992; Ozdemir, 2004) as shown in equation (1): Δnex = [{(PRi/ZRi) - (PRf/ZRf)} * VR – {(PSf/ZSf) - (PSi/ZSi)} *V0] /wRT (1) where, Δnex is the excess adsorption in a pressure step; PRi, PRf are the initial and final pressures of the reference cell, respectively; VR is the volume of the reference cell; ZRi, ZRf are the initial and final gas compressibility factors, respectively, at the corresponding pressure-temperature conditions within the reference cell; PSi, PSf are the initial and final pressures of sample cell, respectively; V0 is the void volume of samples cell; ZSi, ZSf are the initial and final gas compressibility factors, respectively, at the corresponding pressure-temperature conditions within the sample cell; w is the weight of the sample; R is the Universal Gas Constant and T is the temperature of isotherm measurement. The “Absolute” sorbed values were calculated from the experimental “Excess” values using the equation (Dutta et al., 2008; Hall et al., 1994): nabsolute = nexcess/(1-(ρgas/ρadsorbed))

(2)

where, nabsolute is the absolute sorption, nexcess is the excess sorption, ρgas is the gas density at a given pressure-temperature, and ρadsorbed is the sorbed phase density of the adsorbate gas, which was taken as 0.421 g/cc for CH4 (Harpalani et al., 2006) and the reporting was done at 30 °C and 101.3 kPa, on “as received basis”. The absolute adsorption values were statistically fitted to the Langmuir equation (Langmuir, 1918), shown below by non-linear regression through SPSS statistical package:

2. Materials and methods 2.1. Sample collection and preparation

V = VL (P / (P + PL))

The shale samples were received mostly in powdered form with a few small lumps and upon collection, the samples were wrapped in bubble wrapper to preserve the in-situ moisture. For TOC, standard rock evaluation tests are performed using ∼100 mg of pulverized rock samples. The samples were heated in stages at a temperature ranging from 100 °C to 850 °C and the corresponding results are recorded in a form of “peak” (Espitalie et al., 1984). The samples were classified as per the maturity of the Total Organic Content (TOC) (Atta-Peters and Garrey, 2014). The Mercury Intrusion standard technique was used to determine the porosity and grain density (ASTM Designation: D440418). However, during isotherm tests, the grain densities were estimated again by standard GRI method. For each sample, two sets of homogenous, powdered samples of −44 mesh (∼0.4 mm) were prepared by stage crushing. One sample was used for void volume estimation with helium and the other was used for such estimation with krypton. The ASTM procedure (ASTM Designation: D1412-04) for moisture equilibration of coal was used to prepare the moist shale samples after keeping them in environmental chamber for 48 h at 30 °C and the constant weight was recorded. Subsequently, the samples were directly transferred to the sample cell just before starting the sorption isotherm experiments.

(3)

where, V is the adsorbed gas volume at equilibrium pressure P, VL is the maximum storage capacity of the gas and termed as Langmuir volume constant, and PL is the Langmuir pressure corresponds to the pressure at 50% of Langmuir volume. 2.3. Uncertainty analysis for experimental errors in isotherm test The experimental uncertainties at every step of the isotherm measurements were calculated using the theory of error propagation (Ozdemir, 2004). The objective function in gas adsorption step is expressed by equation (1) above. The maximum uncertainty in each pressure steps was calculated by taking the square root of the sum of squares of each individual variables of isotherm experiment (Mavor et al., 2004). The detail process was reported in Dutta et al. (2011) and the calculated uncertainty value is reported here. 2.4. Pore characterization by low pressure CO2 micropore adsorption Low-pressure CO2 isotherms were used to describe the pore space of organic rich, microporous shale samples as average pore size distributions into which methane can effectively penetrate. CO2 micorpore adsorption analysis were performed by Quantachrome® AsiQwin™ automated gas sorption analyzer at 273.15 °C with ∼0.5–1.0 g of powdered shale samples. Based on the theory of volume filling (Dubinin, 1975), the micropore adsorption volume was modeled by Dubinin-Raduskevich (DR) equation (Gregg and Singh, 1982):

1 According to the International Union of Pure and Applied Chemistry (IUPAC, 1994) pore classification, micropores are pores < 2 nm in diameter, mesopores 2–50 nm and macropores > 50 nm.

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Table 1 General information of the shale samples. Sample Name

Age

TOC, %

Porosity (Hg), %

Grain Density (GRI/Hg), g/cc

Tmax (S2), °C

Quartz, %

Clay, %

BC 06 BC 07 BC 09 CHE 02 CHE 03 EBN 20 NEXEN 007 NEXEN 015 NEXEN 033 NEXEN SH-1

Devonian Devonian Devonian – – Jurassic Carboniferous Carboniferous Carboniferous Carboniferous

0.48 1.92 5.28 2.54 4.43 5.67 3.27 3.21 2.01 7.56

0.40 1.27 3.90 3.50 6.0 6.56 1.57 10.80 2.83 1.30

2.69/2.69 2.67/2.67 -/2.49 2.67/2.62 -/2.56 2.60/2.62 2.53/2.56 2.57/2.74 2.61/2.53 2.51/2.48

441 396 425 335 505 477 481 484 484 338

15.5 32.8 50.0 26.2 32.0 10.1 44.5 44.8 7.8 73.9

26.6 18.5 29.7 55.9 51.6 26.6 40.3 35.1 24.0 21.3

V = V0 Exp [– K{ln (P0 / P)}2]

EBN 20. There are some distinct groups of isotherms as seen from Fig. 1: BC 09 shows medium adsorption capacities, whereas, sample EBN 20 shows progressively increasing trend and never tends to attain equilibrium within the experimental pressure range. As a result, it shows abnormally high VL and PL values. Except for the BC 06, which show “negative” adsorption at most of the pressure steps, rest of the seven samples show very low adsorption capacities and “decline” of the isotherms at or near the final pressure steps. Maximum Langmuir volume of 39.56 cc/g, (as shown in Table 2), is obtained for EBN 20 and the minimum of 0.047 cc/g is observed for BC 06. The very high value of Langmuir volume (VL) with the experimental pressure range of EBN 20 sample is observed in Table 2 due to the continuously increasing trend of isotherm graph. As for the NEXEN 033, even the TOC content is 2.01%, it exhibits very low adsorption capacity which may be due to the low porosity but more adsorption capacity than BC 06 or BC 07 shale samples. For the Kr-calibrated shales, as shown in Fig. 2 and Table 3, the minimum and maximum adsorption capacities are shown by NEXEN 007 and BC 09 as 0.2912 cc/g and 0.9309 cc/g, respectively. Here also, NEXEN 007 and NEXEN 015 along with EBN 20 show low adsorption capacities, CHE 02 and NEXEN 033 show medium adsorption capacities while BC 09 shows the maximum adsorption capacity. EBN 20 surprisingly shows very low adsorption here compared to the adsorption observed for the sample with void volume calibration by Helium. This difference in adsorption isotherm for EBN 20 may be attributed to the difference in the representative samples for both the tests. Except EBN 20 and NEXEN 007, none of the samples show “decline” in the adsorption isotherm in the medium to high-pressure zone. It must be mentioned here that for some shale samples, adsorption isotherm graphs follow a “decline” in middle to high-pressure range (Figs. 1 and 2). Although it seems that there may be a “negative adsorption” or “desorption”, the reduction in pressure within the sample cell confirms that the adsorption is ongoing. Similar type of observations was found in methane adsorption studies reported elsewhere (Chareonsuppanimit et al., 2012; Gasparik et al., 2014; Ross and Bustin, 2007). Generally, the material balance equation is used to determine the adsorption capacities on shale. But discrepancies in material balance equations were also noted which, in turn, may give the “negative” adsorption characteristics. The available void volume for methane adsorption is “overestimated” due to the fact that in most of the cases, Helium (kinetic diameter ∼26 nm) is used for calibration, whereas, the adsorbate is methane (kinetic diameter ∼38 nm) (Cui et al., 2004). So, it may happen that the availability of pores for methane is less than that available for helium, which in turn, may underestimate the sorbed gas capacity for methane (Bustin et al., 2008a; Ross and Bustin, 2007, 2009). However, Chareonsuppanimit et al. (2012) explained that the observed “decline” in methane adsorption isotherm is due to experimental uncertainties associated with the test. Recently, Zhou et al. (2018) and Chen et al. (2017) showed that Langmuir theory may not be applicable to describe the gas adsorption on shale as pore structure are heterogeneous and Langmuir theory is suitable mainly for monolayer

(4)

where, V is the volume of the gas adsorbed, V0 is the volume of micropores, K is a constant for a particular adsorbate-adsorbent system and is equal to (RT/βE), where R is the universal gas constant, T is the absolute temperature of adsorption, E is the characteristic heat of adsorption and β is the adsorption affinity co-efficient, P0 is the saturation vapour pressure (defined as the maximum partial pressure exerted by the air which is saturated with the vapour at a particular temperature) and P is the experimental pressure. 3. Results and discussion 3.1. Shale petrology The general information of the samples and information on their associated elemental composition as received from source of the samples are shown in Table 1. Total Organic Content (TOC) varies from as low as 0.48% for the BC 06 sample to 7.56% for the NEXEN-SH1 sample. Except for BC 06, most of the shale samples can be classified as very good to excellent quality of shale based on the TOC quantity. Except for BC 09, the Jurassic and Carboniferous shale samples of EBN 20, CHE-series and NEXEN-series respectively, are very rich in terms of TOC content, which are important for the adsorbed gas capacity in shale. Similarly, Porosity of the samples varies from 0.4% for BC 06–10.80% for NEXEN 015. Except for NEXEN 015, all the samples are having a porosity of < 10% and so, it can be said that the pore volume of the rest of the samples are very less. The clay content of the samples are also varies from 18.5% for BC 07–∼56% for CHE 02 shale, whereas, the silica content is varied from 7.8% for NEXEN 033–73.9% for NEXEN SH-1. Generally, non-organic content like clay and silica/quartz are supposed to block the spaces where the gas can be adsorbed. As seen from the table, the BC 09 and NEXEN group of samples (except NEXEN 033) are showing higher quartz content than other shale samples. 3.2. High pressure methane absolute adsorption characteristics The absolute methane adsorption characteristics of ten shale samples after calibrating the void volume in the sample cell with Helium are shown in Fig. 1, whereas, the same after calibrating the void volume with Krypton for six shale samples are shown in Fig. 2. The overview of the absolute isotherm adsorption results is furnished in Table 2 and Table 3, along with the calculated Langmuir volumes. The uncertainties for the isotherm measurements vary within the range of 2.88%–4.47%, and, as the pressure increases in subsequent pressures steps, the uncertainty is reduced. In general, the isotherm graphs follow the Langmuir Type I sorption behavior for both the sets, matching well with the available gas sorption studies on shales (Chalmers and Bustin, 2007; Gasparik et al., 2014; Rexer et al., 2014). It can be seen from Table 2 that the maximum absolute adsorption values for He-calibrated samples vary from a minimum of 0.0381 cc/g for BC 06 to a maximum of 3.6706 cc/g for 146

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Fig. 1. Absolute adsorption characteristics of methane on shale for Helium-calibrated samples.

TOC and Hg-porosity matches well with the earlier work of Wang et al. (2016). The Maximum adsorbed values for He-calibrated samples also follow the same trend with porosity for BC and CHE groups. However, it follows a non-linear trend for the NEXEN group of shale (Fig. 4a). For Kr-calibrated samples (Fig. 4b), the correlation does not exist. This may be an indication that there are some other factor(s), which are governing the methane adsorption capacity. In general, there exists an inverse relation of adsorbed gas capacity with the porosity (Ross and Bustin, 2007). Studies conducted on the shale pore structure revealed that both inorganic and organic constituents are stored into the micro-/nano-pore spaces of the shale (Chalmers et al., 2012; Loucks et al., 2009; Nelson, 2009). The maximum methane absolute adsorption capacities for all samples were plotted separately with the TOC values and the results are shown in Fig. 5 for Hee and Kr-calibrated. As a whole, the correlation between the methane adsorption capacity and TOC for all the samples is

adsorption. Zhou et al. (2018) also conducted pointed out that there may be a mixing of pore filling and monolayer adsorption during adsorption and any one concept may not be fully able to give the true adsorbed capacity for shale-gas interaction. It is well known that gas is adsorbed into the internal pore structures. To get a better idea about the shale-methane interaction, the Hgporosity values of the samples are correlated with TOC content and the methane adsorbed capacity and the graphs are shown in Fig. 3 and Fig. 4, respectively. It can be seen from Fig. 3 that, as a whole, all samples follow a polynomial trend, increasing TOC quantity and then decreasing as Hg-porosity increases, after reaching the highest level, further increase in porosity brings down TOC content. Upon closer look, it can be seen that for Devonian shales (BC group – triangular points) show a very strong positive trend, CHE group (rhombus points) also show a strong correlation, but the trend for Carboniferous shales (NEXEN group– round points) are scattered. This observation between

Fig. 2. Absolute adsorption characteristics of methane on shale for Krypton-calibrated sample. 147

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triangular points) show a very strong positive trend, CHE group (rhombus points) also show a strong correlation, but the trend for Carboniferous shales (NEXEN group – round points) are flat i.e., more or less constant sorption capacity for an incremental TOC. Earlier gas adsorption studies on shale reported that there is generally a positive correlation between adsorption capacity and TOC (Cui et al., 2004; Jarvie et al., 2007; Lu et al., 1995; Rexer et al., 2014; Weniger et al., 2010); although, for some shale the relationship did not hold true (Allen, 2014; Heller and Zoback, 2014; Ross and Bustin, 2009). The reason for this observation might be the combination of high silica content, post-maturity of the TOC contents and low porosity for NEXEN samples as seen from Table 1. Again, when the observation is connected to the Tmax values (as presented in Table 1), few samples like EBN 20, BC 09 are close to mature range and BC 06 have the most mature TOC as per the classification of Atta-Peters and Garrey (2014). Rest of the samples are either immature or already reached post-mature stage and so, cannot show an increasing trend of adsorption. It was reported that type of organic matter and degree of maturity could vary the adsorbed capacity significantly. However, Zhang et al. (2012) observed that the increase in sorption capacity with maturity was insignificant beyond the low-pressure range. To identify if there is any dependency of the clay material on porosity and gas adsorption, the corresponding Hg-porosity values and the maximum methane adsorption capacities were plotted with the clay composition and the results are shown in Fig. 6 and Fig. 7, respectively. It can be seen from Fig. 6 that the clay content follows a “mild” positive trend with the Hg-porosity, which matches with other studies on clay adsorption (Chen et al., 2015; Kuila et al., 2014; Ross and Bustin, 2009; Yingjie et al., 2015). It is also seen from Fig. 7a–b that the Langmuir volumes of BC samples show a steep, positive correlation, CHE samples show a mild but negative correlation with the clay content; but for the NEXEN samples there is mild positive or no change in the maximum adsorbed volumes with increase in clay content. In total, He-calibrated samples show a mild correlation between the Langmuir volume and the clay content. However, for Kr-calibrated samples, the relationship is not clear. It was reported that with maturity of shale, methane adsorption capacities also increased due to an increase in the micoporosity by disintegration of organic matters (Gasparik et al., 2014; Ji et al., 2012; Ross and Bustin, 2009). It was also observed that the degree and type of packing, clay particle size can also affect the microporosity of shale (Ross and Bustin, 2009). A low Langmuir pressure reported for matured organic-rich shale can indicate an abundance of very small pores (Loucks and Ruppel, 2007).

Table 2 Details of sorption parameters for He-calibrated shale samples. Sample Name

He Density, g/cc

Max. Exp. Pressure, kPa

Max. Abs Ads, cc/g

VL, cc/g

PL, kPa

BC 06 BC 07 BC 09 CHE 02 CHE 03 EBN 20 NEXEN 007 NEXEN 015 NEXEN 033 NEXEN SH1

2.768 2.773 8544 8406 8233 8661 8568

8206 8125 2.0393 0.5581 0.8119 3.6706 0.5859

0.0381 0.3756 3.43 0.81 1.28 39.56 0.75

0.05 0.51 5710.94 2100.74 3654.73 87226.89 2609.53

365.04 1363.81 2.667 2.696 2.725 2.671 2.726

7329

0.1788

0.33

3106.47

2.617

8203

0.3416

0.82

11315.00

2.750

8176

0.442

0.61

1280.46

2.566

Table 3 Details of sorption parameters for Kr-calibrated shale samples. Sample Name

Kr Density, g/cc

Max. Exp. Pressure, kPa

Max. Abs Ads, cc/g

VL, cc/g

PL, kPa

BC 09 CHE 02 EBN 20 NEXEN 007 NEXEN 015 NEXEN 033

2.642 2.714 2.739 2.644 2.634 2.630

8265 8195 8221 8247 8257 7920

0.9309 0.6300 0.3244 0.2912 0.2931 0.5698

1.43 0.90 0.48 0.51 0.37 1.11

4391.94 3201.63 1889.13 3319.46 1374.07 8280.54

Fig. 3. Relationship of Total Organic Content with porosity.

3.3. Comparison of methane absolute adsorption/desorption using He and Kr

not strong. For He-calibrated samples, the trend is moderate but the same correlation for the Kr-calibrated samples does not exist. Upon close observation, it can be seen that for Devonian shales (BC group –

To identify the factors behind the “negative adsorption” (as

Fig. 4. Relationship of Langmuir volume (VL) with Hg-porosity. 148

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Fig. 5. Relationship of Langmuir volume (VL) with Total Organic Content.

Helium can penetrate into more inter-molecular spaces, which are blocked for krypton resulting in a higher estimation” of void space than krypton. Thus, for the same sample, it can be said that volume available for adsorption will be higher in case of Kr-calibrated samples than the He-calibrated samples. So, Kr-calibrated are supposed to give higher adsorption capacity, which was true for CHE 02, NEXEN 05 and NEXEN 033. For other samples, this does not hold true. The reasons for this opposite observation may be attributed to the factors like complex heterogeneity of shale, internal composition of shale organic/non-organic constituents, their heterogeneous porosity and errors in preparation and proper mixing/representation of two parts from same shale sample for Hee and Kr-calibrated adsorption tests. But again, methane has a molecular diameter of ∼38 nm and so it can access all the void space calibrated by Kr, a little more than Kr but not all the pores calibrated by He. So, it can generally be said that the methane adsorption capacity measured by Helium, tend to give “overestimated” results. When the Langmuir volume plotted with the void volume per unit weight as in Fig. 9, all samples follow an inverse relation with the Langmuir volume, although, the trend is better for the He-calibrated shale samples. This suggests that the gas adsorption increases with a decrease in the unit void volume available during adsorption. For some of the graphs of Hee and Kr-calibrated methane absolute adsorptions, the isotherms graphs are going down, showing a “negative” adsorption. The reasons for this decline are explained in details in Section 3.2. The other possible reasons for this different nature of methane adsorption isotherms for the same shale samples may be due to the errors of governing equation for calculation of void volume, experimental uncertainties as mentioned earlier. Ross and Bustin (2007) also observed the “negative” methane adsorption on shale results and attributed to the mismatch of pore sizes of helium and methane as stated earlier. However, they also observed an increase in the void

Fig. 6. Correlation between the Clay content and Hg-porosity.

discussed in Section 3.2) and to ascertain whether there is any effect of calibration gas on the void volume estimation, six shale samples were chosen for methane adsorption isotherm tests after estimating the void volume in the sample cell with krypton. The methane absolute adsorption isotherms for Kr-calibrated samples along with those obtained with He-calibration are shown in Fig. 8. It can be seen that for BC 09, EBN 20 and NEXEN 007, the He-calibrated methane adsorption capacities are higher than their corresponding Kr-calibrated sorption values. Again, three of the samples, BC 09, CHE 02 and NEXEN 033, show more or less similar trend while rest of the samples show different nature of methane adsorption isotherms with Hee and Kr-calibration. Generally, the available pore volume of a sample with He-calibration is more than that for Kr-calibration of the same sample. This is due to the fact that the molecular diameter of Helium is ∼28 nm, whereas that for Krypton is ∼40 nm (Cui et al., 2004). So, for obvious reasons,

Fig. 7. Relationship between the Langmuir volume (VL) with clay content. 149

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Fig. 8. Comparison of absolute adsorption capacities using He (left column) and Kr (right column) Comparison of absolute adsorption capacities using He (left column) and Kr (right column).

150

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Fig. 8. (continued)

volume at high pressure for dry, shale samples and commented that it was due to the helium adsorption or accessibility of helium to finer pores within the sample. Although, it may be noted here that only six samples were chosen for Kr-calibrated isotherm test, which may not be sufficient to give a conclusive results of the comparison.

measurements, changes in internal structure, micropore volume of coal and capillary condensations in the micropores (Busch et al., 2003; Dutta et al., 2011; GRI, 1996).

3.4. Sorption hysteresis of methane on shale

Among the thirteen shale samples, six shale samples were chosen for the low-pressure CO2 micropore adsorption analysis. Generally, many pores in the shale are in the micropore range (i.e., - < 2 nm) and so, the pore distribution is difficult to obtain through the N2-adsorption. Therefore, only low-pressure CO2 adsorption is conducted to get the pore-size distribution. The adsorbed volume in micropores was plotted as per the DR-model discussed in Section 2.5 earlier, with relative pressure fraction and the overview of results is shown in Table 4 and the results are shown in Fig. 11. It can generally be seen that the adsorbed capacities varied from a minimum of 0.8592 cc/g for EBN 20 shale, to a maximum of 1.8608 cc/g for NEXEN 015 shale. A close look in the maximum adsorbed values reveal that among six shales, NEXEN

3.5. Low pressure CO2 sorption analysis for micropores

Among the ten shale samples, eight He-calibrated shale samples were subjected to complete methane ad-/desorption and the corresponding results are shown in Fig. 10. It can be observed from Fig. 10 that hysteresis is negligible or absent for five of the He-calibrated samples, whereas the other three samples, NEXEN 007, NEXEN 033, and BC 09 samples show moderate to significant hysteresis. In general, desorption curve should follow or stay a little below from the adsorption curve to show no hysteresis. Although no hysteresis of methane adsorption on shale is reported, similar studies on coal reported that it was mainly due to the errors/uncertainties in the isotherm tests

Fig. 9. Variation of Langmuir volume with unit void volume. 151

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Fig. 10. Sorption hysteresis of methane on shale using Helium for void volume calibration.

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Table 4 Details of low-pressure CO2 adsorption results. Sample Name

TOC, %

Porosity, %

Max. ADS, cc/g

Surface Area, m2/g

Pore Width, nm

Micropore volume, cc/g

CHE 02 CHE 03 EBN 20 NEXEN 007 NEXEN 015 NEXEN 033

2.54 4.43 5.67 3.27 3.21 2.01

3.5 6.0 6.56 1.57 10.8 2.83

1.2804 1.4038 0.8648 1.3582 1.8608 1.7502

1.302 0.678 0.811 1.443 1.674 0.492

0.548 0.548 0.548 0.548 0.573 0.627

4.24E-04 2.13E-04 2.60E-04 4.57E-04 5.68E-04 1.79E-04

highest one is seen for NEXEN 015. If these observations are compared with the shale composition (shown in Table 1), it can be observed that an increase in quartz content is seen to be positively related with the Hg-porosity values obtained for Devonian BC group of shale, but for Carboniferous NEXEN group, high in quartz content with very low porosity. The Jurassic EBN shale is showing high porosity although having low quartz and clay content. Whereas, CHE group, high amount of clay may have attributed to their high porosity values. Earlier, low-pressure micropore adsorption studies on pore-size distribution of shale stated the complexities and not-so-clear characteristics on shale-adsorbate interactions within the pore. It was reported that the pre-requisite of drying the samples in high vacuum pressure could alter the pore fabric (Bustin et al., 2008a) or might allow the water/moisture present in the clay material of shale also block the space for adsorption (Passey et al., 2010). It was found that for Devonian and Jurassic shale (as BC group of shale and EBN shale, respectively), a good correlation was found among the porosity with silica and clay content. However, for carboniferous shale, porosity decreased with increasing carbonate content. It was stated that there exists a bi-modal pore distribution for most of the shale with very little pore volume in 10–1000 nm range (Bustin et al., 2008a), which matches well with the pore networks of shale used in current research. With a varying shale composition of silica and clay minerals (low Si/Al ratios), the porosity increases with a shift in modal distribution of pores from micropore to mesopores (Ross and Bustin, 2009). Also, the mineral composition of clay is supposed to affect the affinity of methane for the available surface of adsorption and the stronger affinity is marked by the higher value of Langmuir volume (Ji et al., 2012).

group of samples show higher micropore adsorptions than the EBN and CHE groups of samples. EBN 20 shale corresponds to the lowest adsorption value. The sorption characteristics also show a “hysteresis”, which may be due to the reasons explained in earlier section. The amount of hysteresis is significant for EBN 20 and NEXEN 033 samples. However, for rest of the samples, the hysteresis is more or less same. When the micropore volume is correlated with the maximum micropore adsorption and the available surface area within the pores, as shown in Fig. 12a and b, respectively; the adsorption values tend follow a V-shaped graph but the surface area shows a non-linear increasing trend with the micropore volume. The micropore adsorption and the maximum pore volume were also plotted with Hg-porosity values and the results are shown in Fig. 13. It can be observed that there may exist a mild relation for the micropore adsorption with porosity, whereas, the pore volume follows a non-linear trend for all samples. CHE group shale porosity gives a negative relationship with pore volume but NEXEN group of samples shows a U-shaped trend. The micropore adsorption values were also plotted with corresponding TOC values of the shale samples. It can be seen from Fig. 14 that a negative nonlinear trend exists between them. But again, in particular, CHE group of samples show a mild positive relation whereas, NEXEN group of shale are scattered and the relationship is not clear. The pore-size distribution analysis, shown in Fig. 15, shows that apart from the NEXEN 033, rest of the samples follow the same distribution with several “peaks” denoting that the micropore range is varying and the maximum pore width is ∼0.5 nm. NEXEN 033 shows only two “peaks”, having less incremental volume with an average pore width of 0.627 nm. It can clearly be seen from Table 4 that the lowest cumulative micropore volume is observed for NEXEN 033, and the

Fig. 11. Low-pressure CO2 sorption characteristics for micropores. 153

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Fig. 12. Correlation of a) micropore adsorption and b) surface area with maximum pore volume.

3.6. Reproducibility test To consider the overall accuracy of the methane adsorptions isotherm tests on shale, reproducibility tests for void volume calibration are conducted on same F1 sample by helium and the volume ratio results are shown in Fig. 16. For 1st calibration, the void volume in the sample cell (after the sample is loaded) is estimated as 39.942 cc and the He-density is calculated as 2.249 g/cc. Whereas, after the 2nd calibration, the same parameters are found to be 39.961 cc and, 2.252 g/ cc, respectively. The deviation of volume ratio between the two tests (as seen from Fig. 16), is very less or negligible, maximum is only 0.005 at ∼1500 kPa, which may be attributed to the small variation in temperature and/or the sample cell pressure at equilibrium. This shows a very small error of ∼0.047% in the void volume calibration. The overall agreement of the volume ratios in two tests for the same sample is a proof about the sample preparation and accuracy in void volume estimation.

Fig. 14. Correlation of micropore adsorption with TOC content.

exist for the Kr-calibrated samples. It is also observed that other than TOC, factors like maturity of the organics, clay content, porosity and associated pore-network also impact the adsorbed volume. c) Low to moderate hysteresis present in the sorption isotherm, which may be due to the changes in methane-shale interaction characteristics and heterogeneous porosity, internal structural composition of shale. d) Negative adsorption may occur due to the mismatch in available space for adsorption and actual availability of pores to the adsorbate gas. The reasons may be the difficulties associated with determination of the heterogeneous, nano-range pore-size distribution limit any specific conclusion for the negative adsorption. e) Void volume calibration is crucial for any sorption measurements and can vary the sorption capacity when pore-diameter of the calibrating gas and the adsorbate varies significantly.

4. Conclusions Pure methane sorption isotherm and low pressure CO2 micropore adsorption experiments were conducted to investigate into the methane adsorption capacities, pore-size distribution, micropore volume of the shale samples. Also the effect of different calibrating gas on void volume estimation was also studied. In overall, the following conclusions can be drawn from this study: a) The methane absolute adsorption capacity of the European shale follows the Type I Langmuir isotherm. Whereas, low-pressure CO2 micropore adsorption follows DR-model. b) Langmuir volume shows an increasing trend with the total organic content for the He-calibrated samples, but the correlation does not

Fig. 13. Correlation of a) micropore adsorption and b) Maximum pore volume with Hg-porosity. 154

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Fig. 16. Reproducibility test of F1 shale for void volume calibration at 30 °C.

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