Journal of Natural Gas Science and Engineering 32 (2016) 239e255
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Journal of Natural Gas Science and Engineering
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FTIR, XRF, XRD and SEM characteristics of Permian shales, India
Bodhisatwa Hazra a, 1, Atul Kumar Varma a, *, Anup Kumar Bandopadhyay b,Sanchita Chakravarty c, John Buragohain a, Suresh Kumar Samad a, Amal Kishore Prasad a
a Coal Geology and Organic Petrology Lab., Dept. of Applied Geology, Indian School of Mines, Dhanbad, 826004, Indiab Central Institute of Mining and Fuel Research, Dhanbad, 826001, Indiac CSIR National Metallurgical Laboratory, Jamshedpur, 831007, India
a r t i c l e i n f o
Article history:Received 27 December 2015Received in revised form29 March 2016Accepted 30 March 2016Available online 14 April 2016
The emergence of shale gas as potential hydrocarbon resource has changed the global energy landscape.Fourier Transform Infrared (FTIR), X-ray diffraction (XRD), X-ray florescence (XRF) and Scanning ElectronMicroscope (SEM) characteristics of thirty nine borehole shale samples belonging to the Barakar (LowerPermian), Barren Measures (Upper Permian) and Raniganj (Upper Permian) Formations from differentparts of Raniganj basin, India were studied. FTIR analysis indicates the presence of aromatic hydrogen,aromatic carbon, aliphatic CeH stretching, aliphatic CeH bending, OH functional group within theorganic matter and presence of kaolinite, quartz and carbonates within the studied samples. XRF studiesindicate that the shales have undergone intermediate to strong weathering condition, and are marked bypresence of clay minerals mainly illite and kaolinite. In addition to illite, kaolinite and quartz, alkalifeldspar, siderite and calcite were identified within the shales through XRD. Marked development ofamorphous character was noted in the XRD plot of one heat affected shale sample. FTIR analysis of thissample also indicates removal of aliphatics and disordering of kaolinite within the sample due to theimpact of heat. Through SEM studies different types of surface morphologies, different types of pores andpore shapes in organic matter were identified. SEM studies also indicate intimate mixing of organicmatter and mineral matter in shales even at submicroscopic levels. This intimate association appears tohave impact on the retention of hydrocarbons by the mineral matrix during Rock Eval pyrolysis. Thevarious micropores, microcracks, fracture traces, macropores and vacuoles may play significant role indiffusion and flow of hydrocarbons.
Oil and Natural Gas Corporation Limited (ONGC), in January2011, discovered gas at its pilot shale-gas well RNSG-1, drilled bySchlumberger at Icchapur, near Durgapur, West Bengal, in easternpart of Raniganj sub-basin of the Damodar Valley (LNG WorldNews, 2011). Following this, few works have been carried outrelated to assessment of organic richness, hydrocarbon generationpotential, methane sorption dynamics and pore system character-istics of Raniganj basin shales (Varma et al., 2014a, b, c; 2015a, b;Hazra, 2015; Hazra et al., 2015; Boruah and Ganapathi, 2015a, b).Using color manifestations by banded inhomogeneous shales,
ma).an Institute of Technology,
Varma et al. (2014a, b) tried to estimate TOC content of few Rani-ganj Formation shales. The studies by Varma et al. (2014c, 2015a, b)and Hazra et al., 2015 on organic richness, hydrocarbon generationcapability and methane sorption capacity revealed that for theRaniganj basin shales organic matter has primary control onmethane sorption, while mineral matter were observed to havesecondary role. Boruah and Ganapathi (2015a) for first time carriedout X-ray computer tomography (X-ray CT) of the Barren Measuresshales to understand the microstructures, porous media as well asheterogeneity in three dimensions of the shales. Their resultsindicated that the shales are marked by complex pore morphologyand multi scale pore dimensions, and the pore diameters of sam-ples vary from a few nanometers to micrometers.
The Raniganj basin, which is the birthplace of the Indian coalindustry, has been a centre of geological activities for more thantwo centuries. Moreover, the presence of both the Lower Gond-wana (Permian) and Upper Gondwana (Triassice Lower
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Cretaceous) Formations (Gee, 1932) within the basin makes it animportant target for gas assessment. The 300e600 m thickness ofthe Barren Measures Formation shales in the Raniganj basin, withexcellent TOC content, makes it a suitable target for shale gasassessment (Varma et al., 2015a; Boruah and Ganapathi, 2015b).
In this paper FTIR, XRD, XRF and SEM characteristics of theRaniganj basin shales have been examined. Not much informationexists about the morphologies of organic matter and mineralmatter within shales and hence the shales were studied under SEM.FTIR, XRD and XRF analyses were carried out for determining in-formation on the functional groups, mineral matter present withinthe shales and understanding the degree of weathering they hadundergone. Till date no information exists about the major oxidecontent of Raniganj basin shales. Similarly, not much literatureexists about the functional groups and mineral matter presentwithin the Raniganj basin shales. For the purpose of study, a total ofthirty nine borehole shale samples belonging to the Barakar (LowerPermian), Barren Measures (Upper Permian) and Raniganj (UpperPermian) Formations from the Raniganj basin were collected andanalyzed.
2. Geological setting
The Raniganj basin, the easternmost intracratonic rift basin ofthe Damodar Valley, covers an area of 1900 km2 (Fig.1). It is markedby a semi-elliptical, elongated shape and is bounded by latitudes23�220 N and 23�520 N, and longitudes 86�36ʹ E and 87�30ʹ E (Gee,1932). The Raniganj basin is also faulted down on the south and thewest. The southern boundary is marked by a series of faults, andexhibits an en echelon pattern with a general strike of E-W dippingtowards the major faults mostly towards more faulted southernboundary. The Salma dolerite dyke in the central part runs acrossthe basin and marks a NNW-SSE trending relatively long-livedbasement high (Ghosh, 2002). During the deposition of the Dam-uda Group (Barakar, Barren Measures and Raniganj Formations;Fig. 1), this basement high separated the eastern and western sub-
Fig. 1. Geological map of Raniganj coal basin (after Gee, 1932; GSI, 2003). The study areaA ¼ Andal area and I ¼ Icchapur area.
basins of the Raniganj basin. The generalized stratigraphic succes-sion of the Raniganj basin (after GSI, 2003; Mukhopadhyay et al.,2010) is given in Fig. 2.
3. Materials and methods
3.1. Collection of samples
A total of thirty nine borehole shale samples (eleven belongingto the Barakar Formation, twelve belonging to the Barren MeasuresFormation and sixteen belonging to the Raniganj Formation) fromdifferent parts of the Raniganj basinwere studied. The details of thesamples in terms of depth, formation, geological age and area fromwhere they were collected are given in Table 1.
3.2. Rock eval pyrolysis and TOC analyses
The shale samples were crushed and screened through BritishStandard Specification 72 mesh size (�212 mm size) for Rock Evalpyrolysis and TOC analyses. Following this, the sieved samples werewell homogenized. The analyses were carried out at Keshava DevaMalaviya Institute of Petroleum Exploration, Oil and Natural GasCorporation Limited, Dehradun, India and a Rock Eval 6 was usedfor the purpose. Details about the functioning of Rock Eval, theparameters acquired, and interpretive guidelines have been dis-cussed by several workers (Peters,1986; Espitali�e et al., 1987; Petersand Cassa, 1994; Lafargue et al., 1998).
Rock Eval pyrolysis, is essentially a two-step process. It involvespyrolysis in an inert atmosphere (nitrogen) and combustion in anoxic atmosphere (air). The first stage (pyrolysis) begins by heatingthe sample at 300 �C. Released during this stage are free hydro-carbons, volatile compounds, such as short chain lipids and othersmall volatile compounds. These are recorded under S1 curve (mgHC/g rock) of Rock Eval pyrolysis. This stage is followed by a tem-perature rise of 25 �C/min till 650 �C is reached. Hydrocarbonsreleased due to cracking of heavier and larger molecules are
s have been shown in the map. Explanations: Si ¼ Sitarampur area, Ku ¼ Kulti area,
Fig. 2. Generalized stratigraphic succession of Raniganj basin (after GSI, 2003 andMukhopadhyay et al., 2010). Formation symbols are used on the geologic maps shownon Fig. 1. (#: These formations have not been marked in the geological map in Fig. 1;represents the analyzed shale formations.)
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released during this stage and are recorded under S2 curve (mg HC/g rock) (Lafargue et al., 1998). It represents the present day hy-drocarbon generating capability of the rock sample. Using flameionization detection (FID), hydrocarbons released under S1 and S2are detected. Carbon dioxide and carbon monoxide (mg oxides ofcarbon/g) are measured continuously by infrared (IR) spectroscopy,during the pyrolysis step S3. Following this, the sample is trans-ferred to an oxic chamber where all the remaining organic matter(OM) is burnt off by heating to 850 �C. The residual carbon (RC)fraction (wt % measured by IR) is thus produced. The TOC content isderived from the sum of these fractions (Lafargue et al., 1998). TheS1, S2 and S3 parameters are measured in milligrams of the productgenerated per gram of rock sample (equivalent to kg/t), where forthe S1 and S2 the products are hydrocarbons, and CO2 and CO forthe S3 parameter. TOC is reported in weight percent (wt. %) whileTmax (a maturity parameter based on the temperature at which themaximum amount of pyrolyzate (S2) is generated from the kerogenin a rock sample) is measured in degree Celsius.
For FTIR spectroscopy, pellets were prepared whereby 1 mg ofcrushed shale samples (of�75 mm size) was groundedwith 100mgKBr and were pressed into pellets in an evacuated die, followingprocedures outlined in Painter et al. (1981). The pellets were driedin a vacuum oven for 48 h to minimize the contribution of water tothe spectrum. FTIR spectroscopy of the shale samples were carriedout in absorbance mode at 4000 cm�1 to 200 cm�1 wavelength
frequency. A Bruker, 3000 Hyperion Microscope with Vertex 80FTIR system instrument was used for FTIR analysis.
3.4. X-ray diffraction (XRD) analysis of shale samples
XRD analysis of twenty four shale samples was carried out usinga Bruker D8 Advance machine with a Cu target and Lynxeye (siliconstrip) detector. The shale samples were crushed and passedthrough 72 mesh size (�212 mm size).
3.5. X-ray fluorescence (XRF)
XRF analysis of twenty three shale samples was carried out. Forthe purpose of analysis, shale ash residue obtained after burningthe samples (�75 mm size) was used for preparation of pellets andwere subsequently analyzed using a S8 Tiger XRF machine ofBruker.
3.6. Scanning electron microscopy and energy dispersive X-raystudies (SEM and EDX)
Chips were taken out from the borehole shale samples and wereanalyzed under a FEeSEM Supra 55 (Carl Zeiss, Germany) with anair lock chamber at the Central Research Facility (CRF), IndianSchool of Mines, Dhanbad, India. Prior to carrying out the experi-ment, the chip samples were coated with platinum to make themconductive.
4. Results and discussion
4.1. Organic richness and hydrocarbon generation potential
Organic richness and hydrocarbon generation potential of theRaniganj basin shales have been previously studied by Varma et al.(2014a, b, c, 2015a, b) and Hazra et al. (2015). Fig. 3a, b and c showsthe depth, HI values, TOC content and Tmax values of the Barakar,Barren Measures and Raniganj Formation shales. The resultsindicate that all the samples belonging to the Barakar and BarrenMeasures Formations have ‘excellent’ total organic carbon content(TOC >4 wt %), while the Raniganj Formation shales are marked bya wide range of TOC content 3.13e29.74 wt %. Tmax values fromRock Eval pyrolysis indicated that the shales belonging to the Bar-akar and Barren Measures Formations were placed within early topost mature stage, while the Raniganj Formation shales wereplaced within the early to peak mature stage (Figs. 3 and 4).Traditionally HI vs Tmax plot has been used to infer the type oforganic matter input. However, with increasing maturity as hy-drocarbons are generated from kerogen, hydrogen indices (HI) oforganic matter decrease (Behar and Vandenbroucke, 1987; Beharet al., 1992; Peters et al., 2005; Jarvie et al., 2007). They mayhence give a false impression about the type of organic matteractually present within the samples. Hydrogen indices (HI) of theBarren Measures Formation shales indicated input of dominantlytype III organic matter and type II/III admixed material at places.However, organic petrography revealed presence of type I (algin-ites), type II (liptinites other than alginites), type III (vitrinites) andtype IV (inertinites). It was hence inferred that organic matter typewas best inferred by organic petrography (Hazra et al., 2015).
Fig. 5 shows a generalized lithostratigraphic succession of theKulti (Ku) and Sitarampur (Si) areas of the basin, as indicated byborehole data. The Barren Measures Formation with a thickness ofaround 300e600 m, excellent TOC content and maturity placingthem within the oil window (Fig. 4; thereby being capable ofgenerating oil and thermogenic gas upon thermal cracking(Gentzis, 2013; Varma et al., 2015a), makes this formation a target
Table 1Location, geological age, formation name and depth of the studied borehole shale samples.
Note- Kulti (Ku) area: latitude 23�42' N and longitude 86�53ʹ E; Sitarampur (Si) area: latitude 23�43' N and longitude 86�54ʹ E; Icchapur (I) area: latitude 23�38' N and longitude87�15ʹ E; Andal (A) area: latitude 23�35' N and longitude 87�12ʹ E.
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for shale gas assessment. Towards the eastern part of the Raniganjbasin, the Barren Measures Formation occurs at greater depths andcan be a better target for shale gas assessment. In fact, in January2011, in their pilot shale gas well RNSG-1, drilled by Schlumbergerat Icchapur, near Durgapur, West Bengal, in eastern part of Raniganjsub-basin of the Damodar Valley (LNGWorld News, 2011), Oil andNatural Gas Corporation Limited (ONGC) struck gas. The well wasdrilled to a depth of around 2000 m and reportedly had gas showsat the base of the Permian Barren Measures Formation(985e1843 m). In this context it must also be pointed out that thethermal maturity of the current most productive shale gas plays inthe United States, Canada and China are in gas or even dry gaswindow. Shale in the oil window most likely cannot be ideal shalegas plays, since gas has not been significantly generated eitherthrough first (kerogen) or second cracking (oil to gas). However, thepresence of alginite and liptinite (other than alginite) maceralsranging in concentration between 0.84e23.58 and 7.64e16.20vol. % (mineral matter free basis; Hazra et al., 2015) at oil windowmaturity level can generate secondarily cracked gas (from oil).Earlier Hackley et al. (2009) had also observed onset of thermo-genic gas generation in Middle- Upper Pennsylvanian (LateCarboniferous) coal and carbonaceous shale samples with type IIIorganic matter which had estimated Ro values of 0.50e0.80%.Presence of several thick, organic rich, mature dark shale horizonsbelonging to the Barakar Formation especially from the Sitarampur
area of the basin (where they are placed in the condensate wet gaswindow; Fig. 5) also makes this formation a target for shale gasassessment.
The Barren Measures Formation in between the Barakar andRaniganj Formations (Fig. 2) are devoid of any commercial coalseams but are marked by the presence of thick dark shale horizons.The high thickness and large TOC content of these shales mayindicate an anoxic environment for a large period of geological time(11 Ma; Fig. 2), as if the conditions had been oxic, aerobic bacteriawould have thrived and consumed the organic matter (Tissot andWelte, 1984; Loucks and Ruppel, 2007; Tan et al., 2015).
Previously Slatt and Rodriguez (2012) observed that throughvariations in the relative hydrocarbon potential ratio [RHP;(S1 þ S2)/TOC], fluctuations in oxygenation conditions are re-flected. Slatt et al. (2012) and Miceli-Romero (2010) also observedstratigraphic differences in the RHP of the Barnett and Woodfordshales respectively. They had observed good correlation betweenchanges in oxygen levels (indicated by the RHP) with changes inrelative sea level fluctuations derived from the stratigraphic in-terpretations. Slatt and Rodriguez (2012) further suggested thatwhile minimum RHP values (oxic conditions) correlate with thelocation of sequence and parasequence boundaries, water depthswith maximum RHP values (anoxic conditions) correspond withinterpreted flooding surfaces. For the studied Raniganj basin shales,average RHP of the Barren Measures Formation shales (1.29;
Fig. 3. Vertical column plot showing depth (m), TOC content (wt %), HI (mg HC/g TOC), Tmax (�C) and RHP (relative hydrocarbon potential; (S1þS2)/TOC) values of the shale samplesfrom the Barakar (Fig. 3a), Barren Measures (Fig. 3b) and Raniganj (Fig. 3c) Formations.
Fig. 4. Relation between hydrogen index (mg HC/g TOC) and Tmax (�C) for the studied shale samples.
Fig. 5. Schematic diagram showing the generalized lithostratigraphy in the Kulti (Ku)and Sitarampur (Si) areas as indicated by borehole data.
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Fig. 3b) was observed to be larger than the Barakar (0.76; Fig. 3a)and Raniganj [1.12; excluding samples CG 1251 and CG 1013(samples with highest TOC content of 26.56 and 29.74 wt %) RHP forthese shales is 0.98; Fig. 3c] Formation shales, and hence furthercorroborates the observation that they were laid in a much moreanoxic condition. Incidentally, the shales CG 1005, CG 1010 and CG1011 from the Barren Measures Formation showing the maximumRHP values of 1.45, 1.95 and 2.86 (Fig. 3b) were also marked by
largest alginite maceral content of 16.15, 17.41 and 23.58 vol. %(mineral matter free basis) respectively (see Table 3; Hazra et al.,2015). This significantly indicates that deposition of these alginitemacerals within the Barren Measures Formation shales may havethus taken place under maximumwater levels (anoxic conditions).
4.2. FTIR studies
Table 2 shows the different functional groups and mineralmatter identified in the samples through FTIR analysis. Among theBarakar Formation shales, aliphatic CeH stretching with weakpeaks at 2920 and about 2850 cm� 1 observed in all the shales fromthe Kulti (Ku) area, and CG 1283 and CG 1284 from the Sitarampur(Si) area, may be attributed to their comparatively smaller TOCcontent. The relatively stronger aliphatic CeH stretching peaks forsamples CG 1282 and CG 1286 can be attributed to their compar-atively larger TOC content (14.91 and 16.36wt % respectively; Fig. 6)(Hazra et al., 2015). However, in spite of having a very high TOCcontent (22.37 wt %; Fig. 6), the aliphatic CeH stretching region insample CG 1285 is represented by a very weak peak. The fortycentimeter thick lamprophyre intrusion occurring immediatelyabove the sample might have caused removal of the aliphatics fromthe sample (Hazra et al., 2015). Further, at approximately3030 cm�1 and 1600 cm�1 aromatic hydrogen and aromatic carbonwere observed in this sample. In addition to this, the absence ofaliphatic bending in CG 1285 at frequency interval of 1446 and1375 cm�1 at such large TOC level further confirms the likelyremoval of aliphatics from the sample (Fig. 7).
Weak aliphatic CeH stretch was also observed in the BarrenMeasures Formation shales and can similarly be attributed to theirlower TOC content. In case of the Raniganj Formation shales bothweaker and stronger aliphatic CeH stretch was observed depend-ing upon their TOC content. In all the cases the intensity of the peakat 2920 cm�1 is greater than the peak at 2850 cm�1, indicating thepresence of long aliphatic chains within the organic matter (Fig. 6;Varma et al., 2015b; Hazra, 2015).
The peak observed at 1430 cm�1 in all the samples belonging tothe BarrenMeasures Formation (CG 1001eCG 1012), few samples ofthe Barakar (CG 1234eCG 1239, CG 1283eCG1285) and the Rani-ganj Formations (CG 1014, CG 1016eCG 1018, CG 1020, CG 1253, CG
Table 2Functional groups and mineral matter identified through FTIR spectra in the shale samples.
Fm SN OH Aro. H Ali. CeH stretch Aro. C Carbo Ali. CeH bend K Q
Explanations- Fm: Formation; SN: sample number; BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation; CIA: chemical index of alteration; CIW:chemical index of weathering; ICV: index of compositional variation; XRF: X-ray florescence; note: concentrations of all the oxides are in weight percentage.
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Fig. 6. FTIR spectra of few shale samples (from the three formations) in the frequencyinterval 4000e1675 cm�1 showing the kaolinite (represented by the arrows AAʹ atapproximately 3620 and 3690 cm�1 respectively) and aliphatic CeH stretching region(represented by the arrows AAʹ at approximately 2920 and 2850 cm�1 respectively).
Fig. 7. FTIR spectra of few samples from the three formations in the frequency interval1600e1300 cm�1 showing the aliphatic bending region with peaks at 1445 and1376 cm�1 indicated by dotted lines 1 and 2 respectively. Note that in case of sampleCG 1285, line 1 doesn't point the exact peak at 1445 cm�1, rather the peak is slightlyoffset at approximately 1435 cm�1. Moreover the 1376 cm�1 peak represented by line 2is absent in sample CG 1285.
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1256, CG 1257, CG 1259, CG 1261 and CG 1263) can be attributed tothe presence of carbonates (Fig. 8). However, in the case of samplesCG 1282 and CG 1286 of the Barakar Formation, and samples CG1013, CG 1015, CG 1019, CG 1021 and CG 1251 of Raniganj Formation(all marked by very large TOC content), the peaks occurring atapproximately 1445 and 1376 cm�1 can be designated as peaks dueto aliphatic CeH bending (Fig. 7). Where aliphatic CeH bendingwas observed, intensity of the peak at 1373 cm�1 is much lower,than the peak at 1436 cm�1 indicating presence of methylene withlong side chains (Fig. 7) (Varma et al., 2015b; Hazra, 2015).
In addition to this, kaolinite (Fig. 6) and quartz were identified inall the shale samples through FTIR analysis. The effect of heat insample CG 1285 is also manifested from the disordering of thestructure of kaolinite (Fig. 6) (Hazra et al., 2015).
4.3. XRF and XRD studies
The results related to XRF analysis of the shales from the threeformations are given in Table 3. The oxides identified through XRFanalysis are SiO2, Al2O3, Fe2O3, K2O, CaO, MgO, TiO2, P2O5, Na2O,
BaO and MnO. SiO2 was observed to be the most abundant oxidewith its content varying between 57.26 and 65.89 wt %. Al2O3 wasobserved to be the next most abundant oxide with its contentranging within the limits of 18.92e27.08 wt %. The Barakar For-mation shales were marked by slightly smaller average SiO2(60.71 wt %) and higher Al2O3 (24.99 wt %) content relative to theother formations. Fe2O3 was noted to be the third most abundantoxide.
The mineralogical and chemical compositions of clastic sedi-mentary rocks are known to be indicators of the source rockcomposition, environmental parameters affecting the weathering,duration of weathering, mechanisms of transportation, deposi-tional environments and post depositional processes (Nesbitt andYoung, 1982, 1984; Dickinson et al., 1983; Bhatia, 1983; Roser andKorsch, 1988; Condie, 1993; McLennan et al., 1993; Nesbitt et al.,1996; Hayashi et al., 1997). During the process of weathering, cat-ions such as Al3þ and Ti4þ are stored in stable weathering products,whereas cations such as Naþ, Ca2þ and Kþ tend to be lost (Fedoet al., 1995). The chemical index of alteration (CIA) and the chem-ical index of weathering (CIW) are useful proxies and have beenused in determining the climate conditions (McLennan et al., 1993).The CIA (Nesbitt and Young, 1982, Eq. (1)) and CIW (Harnois, 1988,Eq. (2)) are calculated as follows:
CaO* is the amount of CaO incorporated into the silicate fraction ofrocks (Nesbitt and Young,1982). In the present study, the content ofCaO* was calculated using the method of Bock et al. (1998), i.e.,when CaO > Na2O, CaO* ¼ Na2O; and when CaO � Na2O,CaO* ¼ CaO. For the studied samples CIA and CIW varies between
Fig. 8. FTIR spectra of few shale samples from different formations showing the po-sition of carbonates at approximately 1435 cm�1 frequency.
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70.43e86.34 and 81.76e100.00 respectively (Table 3). Both theindices are higher than that of the Universal Continental Crust(60.11 and 70.89, respectively; McLennan, 2001), indicating an in-termediate to strong weathering condition (Fig. 9), indicating thatthe paleoclimate was relatively humid.
Index of compositional variation (ICV) of Cox et al. (1995) hasalso been calculated using the following equation:
This index measures the abundance of alumina relative to theother major cations in a rock or mineral. Silica is excluded to
Fig. 9. Al2O3, CaO*þNa2O and K2O ternary plot showing weathering trend (after Nesbitt andzoomed to show the distribution of the samples.
eliminate problems of quartz dilution. Also, the weight percents ofthe oxides are used rather thanmoles, and the values decreasewithincreasing degree of weathering. Here CaO includes all sources ofCa. The ICV for the studied shale samples varies between 0.40 and0.91 and thus indicates dominance of clay minerals in comparisonto the rock formingminerals inmineralogical composition. Anotherindex is the ratio of K2O/A12O3. Clay minerals and feldspars aremarked by different values of K2O/A12O3. For the studied shalesamples K2O/A12O3 varies between 0.10 and 0.23 with an averagevalue of 0.14, 0.13 and 0.15 for the Barakar, Barren Measures andRaniganj Formations respectively (Table 3). The highest value of0.23 is shown by sample CG 1285 of the Barakar Formation. Theratio indicates intermediate clay composition ranging from illite tokaolinite. This further confirms the intermediate to strong weath-ering inference from CIA index as the end products of intermediateto intense weathering are illite and kaolinite. Moreover, both illiteand kaolinite were identified within the shale samples throughXRD analysis, while kaolinite was identified in all the shale samplesthrough FTIR analysis.
Al2O3/TiO2 ratio in shales is considered to be very close to thoseof parental rocks. Al2O3/TiO2 ratio falls into the range of 3e8 formafic igneous rocks, 8e21 for intermediate igneous rocks, and21e70 for felsic igneous rocks (Hayashi et al., 1997). Al2O3/TiO2 ratiofor the analyzed shale samples ranges within 16.57e25.68 (Table 3)and suggests that source materials for these rocks are intermediate(dominantly) to felsic igneous rocks. However, MgO þ Fe2O3 con-tent within the shales ranges from 5.52 to 12.56 wt % indicatingsome input from mafic minerals also. In addition to this, a linearcorrelation was observed between Al2O3 and TiO2 (Fig. 10) indi-cating the aluminum bearing fraction as a terrigenous deriveddetrital fraction (Uffmann et al., 2012). In addition to this, fairlynegative correlation was observed between SiO2 and Al2O3 (Fig. 11)for the studied shale samples which might be attributed to theprimary hosting of Si in quartz (Uffmann et al., 2012; Zhou et al.,2015). Moreover, the results from XRD and FTIR also indicatepresence of quartz in addition to the clay minerals.
The main mineral phases identified within the shales throughXRD analysis are quartz, potash feldspar, kaolinite, illite, muscovite,biotite, calcite and siderite (Fig. 12). The identification of quartz,kaolinite, illite, potash feldspar and carbonates (siderite and calcite)through XRD substantiates the inferences from FTIR and XRFstudies. The XRD pattern of the sample CG 1285 markedly showsdevelopment of amorphous nature within the sample (indicated by
Young, 1984). CaO*: CaO content of silicate fraction; upper part of the triangle has been
15
17
19
21
23
25
27
29
56
Al 2O
3(w
t %)
58 60 62SiO2 (wt %
y = -0.57R²
64%)
77x + 58.31= 0.41
66 68
Fig. 11. Relationship between Al2O3 and SiO2.
Fig. 12. Identification of various mineral phases in CG 1285 (Barakar Formation) underXRD. Explanations: K: kaolinite; I: illite; Q: quartz; S: siderite; F: feldspar; C: calcite.
Fig. 13. Identification of various mineral phases in CG 1285 (Barakar Formation) underXRD. Explanations: K: kaolinite; Q: quartz; F: feldspar; C: calcite; S: siderite; I: illite.Note the bold arrows indicating the development of amorphous nature within thesample.
0.000.200.400.600.801.001.201.401.601.802.00
1
TiO
2(w
t %)
y =
15 17
= 0.050x + 0.01R² = 0.43
19
10
21 23
Al2O3 (wt %3 25
%)27 29
Fig. 10. Relationship between Al2O3 and TiO2 content of the studied shales.
Fig. 14. Ternary plot showing the mineralogical composition of the studied shales(following Tan et al., 2014). Quartz group includes quartz and feldspar, clay groupincludes clay and mica, carbonate group includes calcite and siderite.
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arrows in Fig. 13). This might have been caused due to the impact ofthe lamprophyre intrusion (Hazra et al., 2015). XRD results indicatefeldspar to be the most abundant mineral in the studied shales. TheBarakar Formation shales were marked by largest average feldsparcontent (34.65 wt %) relative to the Barren Measures (26.94 wt %)and the Raniganj Formations (30.23 wt %). Quartz was observed tobe more abundant in the Barren Measures Formation shales(average: 14.33 wt %) than the other two formations. Among thecarbonate group of minerals, siderite was observed to be moreabundant than calcite, with the Barren Measures Formation shales
being marked by the largest average siderite content (6.48 wt %)than the Barakar (3.87 wt %) and Raniganj Formation (1.11 wt %)shale samples. Kaolinitewas observed to be themost abundant claymineral, with its content varying between 21.86 and 30.81,12.98e31.47 and 17.38e49.54 wt % in the Barakar, Barren Measuresand Raniganj Formation shales respectively. The Raniganj Forma-tion shales were marked by higher average kaolinite content(32.61 wt %) than the shales from the other two formations.
Fig. 14 shows a ternary plot (following Tan et al., 2014) depictingthe mineralogical composition of the studied shales. Generallyidentifying mechanically brittle shale formations may help in shalereservoir simulation, while rock mechanical parameters, such asPoisson’s ratio and Young’s modulus help in understanding ductileor brittle behavior (Slatt and Abousleiman, 2011).All the analyzedshales from the Raniganj basin falls within zones A and B, while>83.33% of the samples fall in zone C. Although geomechanical
B. Hazra et al. / Journal of Natural Gas Science and Engineering 32 (2016) 239e255 249
analysis of the sampled shale samples is beyond the scope of thispaper, yet it would not be out of place to mention, that usingternary plots as a proxy for identifying brittle horizons should bedone carefully as simplified classifications may be misleading (Tanet al., 2014).
4.4. Scanning electron microscopy (SEM) and energy dispersive X-ray (EDX) studies
Through SEM and EDX analysis, organic matter has been iden-tified in most of the shale samples. The SEM and EDX analysisshows the intimate association of the organic matter with mineralmatter. Organic matters in the studied shales are mostly indispersed form (Fig. 15). Here organic matter which shows darkergray appearance is discernible from the shalematrix by their lightergray appearance. However organic matter in the form of massivebodies was also identified (Fig. 16). EDX analysis of organic matterat magnification of 200000� also shows some concentration of Al,Si, Fe etc. along with the organic matter (Fig. 15). This indicates theintimate association of mineral matter (especially clay) and organicmatter even at submicroscopic levels.
Significantly, the role of mineral matrix on hydrocarbon reten-tion has been discussed by several authors (Peters,1986; Katz,1983,1984; Espitali�e et al., 1985; Cornford, 1994; Cornford et al., 1998 andDahl et al., 2004) and this indication of intimate association ofmineral and organic matter further points towards hydrocarbonretention by mineral matrix especially in case of shales. In a S2 vsTOC plot, the matrix effect is indicated by a positive x-intercept(Langford and Blanc-Valleron, 1990). However, the regression lineshould pass through the origin, as during pyrolysis even very smallamounts of organic material should yield hydrocarbons (Langfordand Blanc-Valleron, 1990). For the studied shales in Fig. 17, a posi-tive intercept was observed on the x-axis (TOC axis). The x-inter-cept in the same figure (solving for x when y ¼ 0) is 3 wt % TOC,which indicates the amount of organic material (with a given HI)that must be present before hydrocarbons are liberated from therock and can be detected during pyrolysis. The process of retentionof hydrocarbons by the mineral matrix during pyrolysis wouldobviously be stronger in case of shales than in coals and hence
Fig. 15. SEM and EDX of sample CG 1234 showing th
signifies the impact of intimate association of mineral and organicmatter.
Previously for the studied shale samples, Hazra et al. (2015) hadtried to estimate their original hydrocarbon generative potential(S2O) prior to expulsion due to maturity, original HI (HIO), originalTOC (TOCO) and the fraction of conversion (f) that the kerogenwithin the samples have undergone (following Peters et al., 2005and Jarvie et al., 2007). Keeping in view of the matrix retentioneffects that are being shown by the studied shale samples (Fig. 17),it is very important to understand that the calculation of fraction ofconversion (f) typically in case of shales may give elevated values.Fraction of conversion is calculated following Jarvie et al. (2007) asgiven in Eq. (4):
f ¼ 1� HIPDf1200� ½HIO=ð1� PIOÞ�gHIO 1200� HIPD= 1� PIPDð Þ½ �f g (4)
where HIO and HIPD are hydrogen indices original and present day(from Rock Eval pyrolysis), PIO and PIPD are production indicesoriginal and present day (from Rock Eval pyrolysis) respectively. Forcalculation purposes, PIO is assumed to be 0.02 (Peters et al., 2005).HIO is calculated using the data from organic petrography (Jarvieet al., 2007; Varma et al., 2014c, 2015a; Hazra et al., 2015). As ma-trix retention takes place in case of shales (as in the present caseand most likely in case of all shales consisting of clay minerals) itwould lower the hydrocarbons released under S2 curve of Rock Evalpyrolysis i.e. it would lower the present day HI values (HIPD). Since fis calculated comparing HIO and HIPD, so in case of shales (con-sisting of clayminerals) one is more likely to get higher f values dueto matrix retention. Such data may ultimately lead to erroneousconclusions about how much of the source rock potential has beencompleted or wasted.
Through EDS at very high magnification both mineral matterand organic matter have been identified. The images revealdifferent types of surface morphologies for organic matter andmineral matter at 400e500 nm scale. Microcracks and pores inboth mineral matter and organic matter have been identified at theabove mentioned scale (Fig. 18). Though microcracks were identi-fied in both mineral matter and organic matter yet the density and
e dispersed nature of organic matter within it.
Fig. 16. SEM and EDX of samples CG 1282 (A) and CG 1251 (B) showing the massive forms of organic matter identified under SEM. Note the ‘boggen’ like structure observed in theorganic matter in sample CG 1251 (B).
y = 1.83x - 5.50R² = 0.78
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
0.00 5.00 10.00 15.00 20.00 25.00 30.00 35.00
S2 (m
g H
C/g
rock
)
TOC (wt %)
CG 1285
Fig. 17. Relationship between TOC (wt %) and hydrocarbons released under S2 curve ofrock eval pyrolysis (mg HC/g rock).
Fig. 18. SEM image of sample CG 1001 showing occurrence of mineral matter (i) and organic matter (ii) as indicated from EDX results. Lengths of microcracks A, B and C in mineralmatter (Fig. i) are 154, 184 and 191 nm respectively. Lengths of microcracks A*, B* and C* in organic matter (Fig. ii) are 58, 116 and 29 nm respectively.
B. Hazra et al. / Journal of Natural Gas Science and Engineering 32 (2016) 239e255250
length of the microcracks in the mineral matter are larger thanthose in organic matter.
Surface morphologies of organic matters identified under SEMwere observed to be highly variable showing several types of fea-tures. While some shows presence of microcracks, others showapparently uniformmorphology (Fig. 19). In some cases the organicmatters also showed several forms of surface ruggedness withdifferently shaped microcracks, cavities (Fig. 19).
In sample CG 1013 (Raniganj Formation), a peculiarity wasnoted. Fig. 20 shows a lump/mass of organicmatter identified in thesample under SEM-EDX. The image exhibits large pores (macro-pores) and pore-walls identified in the structure. CorrespondingEDX at those points indicate greater carbon content and smalleroxygen content within the pore while comparatively smaller car-bon and greater oxygen content within the pore-walls. Fig. 21 in-dicates development of fracture traces within samples CG 1018(Raniganj Formation) and CG 1285 (Barakar Formation). In sampleCG 1285, the fracture traces may have been caused due to the
impact of the lamprophyre intrusion occurring above the samplecausing the removal of volatiles and hence forming the fracture
Fig. 19. SEM-EDX of samples CG 1006 (A), CG 1014 (B and D), CG 1007 (C), CG 1282 (E) and CG 1286 (F) showing different types of identified organic matter. Apparently ho-mogeneous nature of the organic matter is manifested in Figs. A (with no microcracks) and B (very few microcracks). Figs. C and D show inhomogeneous nature of the organicmatter with different pigment like structures. Fig. E shows organic matter with presence of microcracks and pores. Fig. F shows presence of cavities in the identified organic matter.
Fig. 20. SEM-EDX of sample CG 1013 showing lump/mass of organic matter identified in the sample. Fig. A and the corresponding table show the composition of the pore whileFig. B and the corresponding table shows the composition of the pore-wall.
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traces.Fig. 22 exhibits different types of pores occurring within the
organicmatter. Fig. 22-i showsmacropores of diameters 414 nm (a),214 nm (b), 128 nm (c) and 367 nm (d) present within organicmatter. In Fig. 22-ii, aʹ and gʹ represents macropores with sizes88 nm and 101 nm respectively, while bʹ-fʹ represents mesoporeswith sizes 35 nm, 38 nm, 42 nm, 35 nm and 33 nm respectively. Inaddition to this, pores with different types of shapes viz. elongated(Aʹʹ), triangular (Bʹʹ), circular (Cʹʹ) and massive vacuole (Dʹʹ) werealso identified within the organic matter. The massive vacuole (Dʹʹ)appears to be formed due to the impact of the lamprophyreintrusion. All these indicate the different types of pores existentwithin the organic matter. The microcracks, fracture traces,
micropores, mesopores, macropores and vacuoles may play sig-nificant role in diffusion and flow of hydrocarbons. Gas or fluid flowin an unconventional reservoir, is a combination of desorption,diffusion and Darcy flow (Cui et al., 2009; Lu and Connell, 2007).Flow of gas in shale reservoirs is a combination of desorption anddiffusion within the micropores of organic matter to Darcy flowthroughmacropores of thematrix and fracture networks (Schlomerand Krooss, 1997; Marschall et al., 2005; Wei and Zhang, 2010). Themesopores on the other hand are considered to be transitionalzones with a combination of diffusion flow and Darcy flow(Chalmers et al., 2012a).To decipher the ability of shales to store andproduce hydrocarbons, understanding how porosity develops inthe organic matter of shales and the controls on its development is
Fig. 21. SEM images of samples CG 1018 (i) and CG 1285 (ii) showing the development of fracture traces within the samples. Aperture of fractures ‘a’ and ‘b’ in Fig. i are 0.45 mm and1.27 mm respectively. Note the black colored arrows showing the fracture traces in Fig. ii. They may have developed within the sample (CG 1285) due to the escape of volatiles causedby the lamprophyre intrusion.
Fig. 22. SEM images of samples CG 1019 (i) and CG 1285 (ii) showing different types of pores within the organic matter of the samples. Diameters of the macropores a, b, c and d inFig. i are 414 nm, 214 nm, 128 nm and 367 nm respectively. In Fig. ii, aʹ and gʹ represents macropores with sizes 88 nm and 101 nm respectively, while bʹ-fʹ represents mesoporeswith sizes 35 nm, 38 nm, 42 nm, 35 nm and 33 nm respectively. Aʹʹ, Bʹʹ and Cʹʹ represent elongated, triangular and circular shaped pores. Dʹʹ represents a massive vacuole that mayhave formed due to escape of volatiles from the sample due to the impact of heat.
B. Hazra et al. / Journal of Natural Gas Science and Engineering 32 (2016) 239e255252
crucial (Curtis et al., 2012a). During the last few years research hasidentified different pore types in unconventional reservoir rocks,for example pores associated with organic matter, interparticle andintraparticle mineral pores, and micro-fractures (Milliken et al.,2013; Curtis et al., 2012a; Loucks et al., 2009, 2012; Slatt andO'Brien, 2011; Passey et al., 2010; Schieber, 2010). Porosity inshale reservoirs is dependent upon initial (depositional) porosity,compaction and chemical diagenesis (mineralogical trans-formation, cementation and dissolution) (Yang et al., 2016). Pres-ence of organic nanopores within most worldwide gas shale playsis now well known (Loucks et al., 2009, 2012; Slatt and O'Brien,2011; Curtis et al., 2012a; Chalmers et al., 2012b; Bernard et al.,2012a, 2012b) which are caused due to the exsolution of gaseoushydrocarbons during the secondary thermal cracking of retained oil(Loucks et al., 2009; Curtis et al., 2012a, 2012b). The heteroatom-rich organic precursors during these processes lose many of theirhydrogenated and oxygenated chemical groups as water, carbondioxide and gaseous or liquid hydrocarbons. As a result, the residualorganic matter becomes enriched in nanometer sized polyaromaticlayers which tend to stack and form polyaromatic basic structuralunits (Oberlin et al., 1980; Boulmier et al., 1982; Oberlin, 1989;Rouzaud and Oberlin, 1989). During hydrocarbon maturation,
growth of pore can explain many features found in associationwithintraparticle organic nanopores (Loucks et al., 2009). Owing tohydrocarbon generation, evolution of long and narrow pore throatsmay be driven by differential pressure buildup within evolvingadjacent pores (Loucks et al., 2009). Moreover, when closely spacedpores expand to form a connection between one another, morecomplexly shaped poresmay also be formed (Loucks et al., 2009). Inthe studied shales also different types of pores are observed. Thedifferent shapes of pores and the massive vacuole as seen in theheat affected shale (Fig. 22-ii) can similarly be assigned to devel-opment of a complex set of pores due to the impact of igneousintrusion. Most of the organic nanopores in the present study lackpreferred orientation, and the different shape of organic poreswithin organic matter indicates post compaction. However, forpredicting porosity in the organic matter, thermal maturity alone isinsufficient and other factors such as organic matter compositionalso plays significant role (Curtis et al., 2012a). On a maceral scale,larger vitrinite content corresponds to a larger micropore surfacearea and micropore volume (Mastalerz et al., 2008). Three dimen-sional arrangements of organic-matter grains might have stronginfluence permeability of shale gas systems, as connected organicmatter can enable limited flow (Loucks et al., 2009). Inorganic
Fig. 23. SEM images of samples CG 1234 (i) and CG 1019 (ii) showing the presence of kaolinite and illite respectively within the samples (indicated by arrows).
B. Hazra et al. / Journal of Natural Gas Science and Engineering 32 (2016) 239e255 253
matrix within shale systems are generally marked by compara-tively large, irregularly-shaped pores and fractures (Clarkson et al.,2016), with the pores being typically slit-like (Curtis et al., 2012a).For the studied shales, irregular larger micro-fractures were iden-tified within the inorganic matrix (Fig. 18) which further confirmsthe above statement. With increasing effective pressure duringshale oil/gas production, these slit-like pores are more prone tocollapse and hence can reduce matrix permeability, and corre-spondingly, the rate at which hydrocarbons are produced (Curtiset al., 2012a). Because of the typically broad pore size distributionwithin the shale matrix, the task of modeling several flow mech-anisms including Darcy (laminar) and Non-Darcy flow (slip-flow,diffusion) is critical. Flow mechanisms may be predicted using theKnudsen number (Klinkenberg, 1941; Beskok and Karniadakis,1999; Sakhaee-Pour and Bryant, 2012; Javadpour, 2009). Kuilaet al. (2012) observed that as pore sizes reduce to smaller than100 nm, the ratio of Knudsen flow constant to Poiseuille (Darcy)flow constant increases sharply. Moreover, with decreasing poresize, Knudsen diffusions contributions to flow increase, indicatingthat the relative abundance of small pore sizes compared to largepore sizes control the gas flow behavior of shales (Kuila et al., 2012).
In addition to these, through SEM and corresponding matchingof mineral matter structures as mentioned in SEM petrology atlas(Welton, 2003), kaolinite and illite were identified in differentsamples (Fig. 23). Previously, the positive influence of clay mineralson methane sorption capacity of shales has been studied byAringhieri (2004), Cheng and Huang (2004), Wang et al. (2004) andVarma et al. (2014c). Clay minerals provide larger surface areas andmore adsorption sites than other minerals (Aringhieri, 2004; Chengand Huang, 2004). Moreover, specific surface area of a clay mineralmay be influenced by its source, depositional environment anddiagenetic evolution (Aringhieri, 2004; Wang et al., 2004; Varmaet al., 2014c).
5. Conclusions
� Results related to XRF analysis indicate that the shales haveundergone intermediate to strong weathering conditions, andare marked by dominance of clay minerals mainly illite andkaolinite. Moreover, both illite and kaolinite have also beenidentified within the samples through SEM, XRD and FTIRtechniques. These clay minerals might have played some role indevelopment of micropores and macropores in inorganicfraction.
� Source materials for these rocks are intermediate (dominantly)to felsic igneous rocks combined with some input from maficminerals. The aluminum bearing fraction appears to be aterrigenous derived detrital fraction.
� The effect of igneous intrusion on shale horizons may be sig-nificant resulting in removal of aliphatics and volatiles, dis-ordering of kaolinite, development of amorphous character,formation of de-volatilization vacuoles and fracture traces.
� SEM and EDX analysis indicates intimate association of mineralmatter and organic matter in shales even at submicroscopiclevels. Moreover, this intimate association seems to causeretention of hydrocarbons by the mineral matrix during RockEval pyrolysis. Under conditions of retention of hydrocarbons byshale matrix, source rock reconstruction and determination offraction of conversion that kerogen within the samples haveundergone should be employed carefully.
� SEM studies indicate different types of surface morphologies(homogeneous, inhomogeneous with pigment like structures,cavities and rugged surfaces), different types of pores (macro-pores and mesopores) and different pore shapes (elongated,triangular, circular and massive vacuole) in the organic matter.Density and length of the microcracks in the mineral matterwere observed to be larger than those in the organic matter. Thismay help in diffusion and flow of hydrocarbons.
Acknowledgment
Authors wish to thank learned anonymous reviewers and DrDavid A.Wood, Editor-in-Chief, JNGSE for valuable suggestions toupgrade the quality of paper. Authors are also thankful to the Head,Keshava Deva Malaviya Institute of Petroleum Exploration, Oil andNatural Gas Corporation Limited, Dehradun, India for helping themin analysis of Rock Eval Pyrolysis and TOC of the studied shalesamples. The authors are indebted to the European Commission forproviding research project (CO2 Geological Storage: Research intoMonitoring and Verification Technology; Project acronym: CO2R-eMoVe; Proposal/contract no.: 518350) to carry out research worksat Coal Geology and Organic Petrology Lab, Department of AppliedGeology, Indian School of Mines, Dhanbad.
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