Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India

Marine and Petroleum Geology xxx (2015) 1e17

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Research paper

Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India Devleena Mani a, *, D.J. Patil a, A.M. Dayal a, B.N. Prasad b a b

CSIR-National Geophysical Research Institute, Hyderabad, India Central Mine Planning & Design Institute Limited, Ranchi, India

a r t i c l e i n f o

a b s t r a c t

Article history: Received 20 February 2015 Received in revised form 12 August 2015 Accepted 14 August 2015 Available online xxx

This study investigates the source rock characteristics of Permian shales from the Jharia sub-basin of Damodar Valley in Eastern India. Borehole shales from the Raniganj, Barren Measure and Barakar Formations were subjected to bulk and quantitative pyrolysis, carbon isotope measurements, mineral identification and organic petrography. The results obtained were used to predict the abundance, source and maturity of kerogen, along with kinetic parameters for its thermal breakdown into simpler hydrocarbons. The shales are characterized by a high TOC (>3.4%), mature to post-mature, heterogeneous Type IIeIII kerogen. Raniganj and Barren Measure shales are in mature, late oil generation stage (Rr%Raniganj ¼ 0.99 e1.22; Rr%Barren Measure ¼ 1.1e1.41). Vitrinite is the dominant maceral in these shales. Barakar shows a post-mature kerogen in gas generation stage (Rr%Barakar ¼ 1.11e2.0) and consist mainly of inertinite and vitrinite. The d13Corg value of kerogen concentrate from Barren Measure shale indicates a lacustrine/ marine origin (24.6e30.84‰ vs. VPDB) and that of Raniganj and Barakar (22.72e25.03‰ vs. VPDB) show the organic provenance to be continental. The d13C ratio of thermo-labile hydrocarbons (C1eC3) in Barren Measure suggests a thermogenic source. Discrete bulk kinetic parameters indicate that Raniganj has lower activation energies (DE ¼ 42 e62 kcal/mol) compared to Barren Measure and Barakar (DE ¼ 44e68 kcal/mol). Temperature for onset (10%), middle (50%) and end (90%) of kerogen transformation is least for Raniganj, followed by Barren Measure and Barakar. Mineral content is dominated by quartz (42e63%), siderite (9e15%) and clay (14 e29%). Permian shales, in particular the Barren Measure, as inferred from the results of our study, demonstrate excellent properties of a potential shale gas system. © 2015 Elsevier Ltd. All rights reserved.

Keywords: Permian shales Raniganj Formation Barren Measure Formation Barakar Formation Source rock Geochemistry

1. Introduction Damodar Valley is an important coal repository amongst the Gondwana basins of India. Located in the northeastern part of Peninsular India, it comprises of series of east-west trending subbasins namely, Raniganj, Jharia, Bokaro, Ramgarh, Karanpura, Auranga, Daltonganj and Hutar (Fig. 1). Sediment deposition during early Permian in the Gondwana basin was primarily fluvio-glacial and lacustrine, leading to significant development of coal beds (Gupta, 1999). Talchir, Barakar, Raniganj and Karharbari are the

* Corresponding author. E-mail address: [email protected] (D. Mani).

main coal-bearing Formations in the basin. A marine/lacustrine succession that deposited between the continental depositions resulted in a coal-devoid Formation, the ‘Barren Measure’ (Gupta, 1999). Shale formations occur extensively interbedded within the coal-bearing horizons in the sub-basins. The PermianeCarboniferous Gondwana facies was deposited as basal glacial sediments, overlain by coal measures across large regions of Australia, Antarctica, India, Arabia, Madagascar, Africa and South America. In addition to the traditional mineable coal, the Permian basins in several of these regions also host major coal-seam gas and oil and/ or gas reserves. The organic rich, thermally mature shales occurring in Indian Gondwana's are likely source for the gaseous hydrocarbons. Wells drilled in the Damodar Valley basin have encountered gas flows in

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Please cite this article in press as: Mani, D., et al., Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India, Marine and Petroleum Geology (2015), http://dx.doi.org/10.1016/j.marpetgeo.2015.08.019

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Fig. 1. Geological map of the Jharia sub-basin showing the locations of boreholes for shale sample collection (modified after; Chandra, 1992).

the Raniganj region (Padhy and Das, 2013). Thermal maturity data on coals surrounding the Barren Measure shale suggest it to be within gas window (Padhy and Das, 2013), making it a potential shale gas target. The qualitative and quantitative aspects of thermal transformation of shale organic matter can provide the much needed information towards determining the presence and properties of hydrocarbons in potential source rocks (Tissot and Welte, 1984; Hunt, 1996; Peters et al., 2005). Geochemical attributes such as organic richness, kerogen type and thermal maturity of sedimentary organic matter are directly related to the hydrocarbon generation potential of a source rock (Peters and Cassa, 1994; Rodriguez and Philp, 2010). The kinetic parameters for the kerogen decomposition in source rocks provide quantitative estimates on the hydrocarbon generation (Tissot and Welte, 1984; Ungerer et al., 1986; Braun and Burnham, 1987; Tissot et al., 1987; Ungerer and Pelet, 1987; Sweeney et al., 1990; Jarvie, 1991). In this paper, the abundance, source and maturity of organic matter has been investigated on the drill cores of shale from one of the sub-basins, Jharia, located in the eastern part of Damodar Valley basin to evaluate the hydrocarbon potential. Subsurface Permian shales (320e1050 m) from the Raniganj, Barren Measure and Barakar Formations were subjected to open system pyrolysis using Rock Eval 6. The pyrolysis results were further used to obtain the kinetic parameters associated with the thermal maturation of shale organic matter at varying heating rates (Tissot and Espitalie, 1975; Ungerer and Pelet, 1987). Bulk and compound-specific carbon isotope measurements were performed on selected samples to identify the source of organic matter using closed system pyrolysis. The nature and proportion of organic constituents along with its rank were investigated using organic petrology, and the mineral

composition was ascertained by X-ray diffraction. The variation in geochemical parameters in the sedimentary sequences enabled the reconstruction of paleoenvironment and thermal conditions in which the organic rich sediments got preserved and matured, thus providing useful insights onto its generative potential. 2. Geologic setting and stratigraphy The Gondwana basins occur within the suture zones of the Precambrian cratonic blocks of the Peninsular India along some linear belts. These basins preserve a thick sedimentary pile deposited over nearly 200 million years from the Carboniferous to the Lower Cretaceous (Mukhopadhyay et al., 2010). Occurring along the major river valleys, the basins have been named after the respective rivers flowing through the region. The EeW to WNWeESE trending DamodareKoel basin lies along the Damodar river in the Trans-Indian basin belt (Mukhopadhyay et al., 2010). The Jharia sub-basin forms part of the eastern end of the Damodar Valley. The Jharia coalfield is roughly sickle shaped, extending for about 38 km in an east-west direction and a maximum of 18 km in north-south direction with an area of about 456 sq. km (Fig. 1; Chandra, 1992). It is marked by two prominent synforms and three high zones (Chandra, 1992). The basin is typically bounded by faults that developed along the Precambrian lineaments during deposition, as well as affected by intrabasinal faults indicating fault-controlled synsedimentary subsidence (Chakraborty et al., 2003). The Southern Boundary Fault is the most prominent and runs through the entire southern edge in WSWeESE direction (Fig. 1). It is marked by a zone of parallel fractures with a stratigraphic throw of about 1800 m towards the north. A number of interbasinal faults having inter- and intra-

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formational nature have been identified in the basin. All major faults initiated as contemporaneous faults and extended their strike length in subsequent times (Chandra, 1992). The general stratigraphic succession is given in Fig. 2 (after, Chandra, 1992). The metamorphic rocks are overlain by the Talchir Formation of fluvio-glacial origin, which is followed by the deposition of fluviatile coal-bearing Barakar Formation. Marine/Lacustrine Barren Measure Formation overlies Barakar and is coaldevoid. Raniganj, the coal-bearing Formation overlies it. A combination of resurgent and block tectonism, with variable time lag in different parts of the reformed basin furnished a setting for centripetal dispersed pattern with the streams flowing in from the surrounding upland areas into the basin (Chandra, 1992). With the shifting of rivers, major parts of the depositional provinces were transformed into the back swamp areas, which were the sites for coal seam development (Chandra, 1992). It is generally known that the Gondwana deposits in the Jharia coalfield are of fresh water origin. However; marine incursions during Gondwana period have been indicated by the occurrence of lamellibranchs in Raniganj and Jharia as well as Bokaro, Karanpura, Sonhat and Wardha Valley fields (Chandra, 1990; Chandra and Betekhtina, 1990) and Rajmahal Group of coalfields (D'Rozario, 1988). 3. Materials and methods Twenty-four subsurface drilled shale cores of ~30 cm length were collected from the three blocks of Jharia sub-basin, namely West Mohuda (MMW-18), Singra (MSG-34) and Kapuria (MKP-29) (Fig. 1). The sampled shale horizons occur interbedded between the coal and sandstone lithology, in depths of ~150e1000 m. Litho-log for the boreholes selected for shale sampling is shown in the Appendix. The shales were washed thoroughly with Milli-Q water and air-dried at room temperature. Homogeneously powdered samples were used to carry out the geochemical analyses comprising of Rock Eval pyrolysis (Basic and Optkin cycle), bulk and compound-specific stable carbon isotope ratio determination, organic petrology and X-ray diffraction. 3.1. Rock Eval pyrolysis 3.1.1. Basic cycle About 50e70 mg of the shale sample was taken in a preoxidized crucible and pyrolysed using the basic cycle of Rock Eval 6 pyrolyzer (Turbo version). Pyrolysis was carried out in an inert atmosphere of nitrogen with a flow of 100 ml/min (Behar et al.,

3

2001). The pyrolysis oven was programmed with an initial isothermal temperature of 300  C maintained for 3 min and followed by a ramp of 650  C at the rate of 25  C/min. Further, the samples were oxidized using a zero air flow of 300 ml/min. The oxidation oven was programmed with an initial temperature of 300  C maintained for 1 min and followed by a ramp at the rate of 20  Ce850  C. Hydrocarbons released from the pyrolysis of organic matter were detected by the flame ionization detector, which had a hydrogen flame at flow of 30 ml/min. The carbon dioxide and monoxide evolving from the decomposition of organic matter and mineral matrix were detected by infrared detectors, two in numbers for the simultaneous pyrolysis and oxidation analyses. The results were reported on a dry weight basis (Mani et al., 2014).

3.1.2. Optkin cycle The distribution of kinetic parameters for thermal cracking of kerogen was obtained using the Optkin program (IFP/Beicip, Franlab). It uses the results of Rock Eval pyrolysis performed on source rocks and calibrates the kinetic parameters of thermal cracking of organic matter into hydrocarbons (Espitalie et al., 1987; Ungerer and Pelet, 1987). Taking into account the amount of oil and gas generated by primary cracking of kerogen when temperature increases through time, the kerogen degradation is described by series of parallel chemical reactions, each of which obey the firstorder kinetics, characterized by Arrhenius Law:

kðTÞ ¼ A*expð  E=ðRTÞ

(1)

where k is the reaction rate parameter dependent on absolute temperature (T, in Kelvin); E is the activation energy of the reaction (J/mol) and R is the molar gas constant (J/mol/K); A is the preexponential frequency factor/Arrhenius constant (sec1). Eq. (1) is expressed as:

dXi=dt ¼ Aexpð  Ei=RTÞ$Xi

(2)

dXi/dt is the hydrocarbon generation rate and Xi is the residual petroleum potential of the organic matter involved in reaction i. E is the activation energy related to reaction i (Tissot and Espitalie, 1975; Ungerer et al., 1986; Braun and Burnham, 1987; Ungerer and Pelet, 1987; Tissot et al., 1987). With increasing temperature, the primary products break down to smaller molecules through secondary cracking processes, and lead to gas and pyrobitumen as end products. The amount Q of oil and gas formed is expressed by:

Fig. 2. Generalized stratigraphy of the Jharia sub-basin, Damodar Valley (modified after; Chandra, 1992).

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D. Mani et al. / Marine and Petroleum Geology xxx (2015) 1e17

Q¼

N X

ðXio  XiÞ

(3)

i¼1

where Xio is the value of Xi at t ¼ 0. Pyrolysis curves for the Raniganj (R-4), Barren Measure (MKP29/BM-II, MSG-34/BM-II) and Barakar (MKP-29/B-2) shales were generated. Ideally, immature samples are used for kinetic analysis, however; in Damodar Valley basin, majority of Permian shales (n ~ 300) from studied formations exhibit a Tmax greater than 435  C (NGRI unpublished data; Varma et al., 2015), due to which very early/least mature (lower Tmax values) shales were selected. Also, the variation in mineral matrix and the amount and type of organic matter were taken into consideration, and representative shales from the selected intervals of core were used for the kinetic analysis. Pyrolysis was conducted on ~50 mg of shale samples using three different heating rates of 5, 15 and 30 /minute with initial temperature of 300  C to a final of 700  C. The input file for optimization was created for the parallel reactions of first-order using an activation energy step of 2 kcal/mole. Utilizing the Rock Eval pyrolysis time, temperature and heating rates and hydrogen index (HI), best fitting kinetic parameters (activation energies E, Arrhenius constants A, and initial petroleum potentials Xio) for the observed S2 (hydrocarbon peak obtained during cracking of kerogen) were calculated. The best adjustment corresponded to the minimum of the error function (summation of the quadratic differences) calculated between measured and computed values. 3.2. Carbon isotope analysis 3.2.1. Kerogen isolation Kerogen was isolated from the selected shale rocks by treating ~1 g of powdered sample with 20% HCl and stirring at 50  C for 6 h. The acid treated sample was washed thrice with Milli-Q water. Further, it was soaked in 20% HCl þ48% HF (1:4) acid mixture overnight. The acid treated samples were washed thoroughly with MilliQ water and dried at 50  C (Horvath and Jackson, 1981). 3.2.2. Bulk carbon isotope analysis Bulk carbon isotope analysis (d13Corg) of the kerogen concentrate was performed on a Thermo Finnigan Flash-Elemental Analyzer (TC/EA) connected to Delta plusXP isotope ratio mass spectrometer (IRMS). The samples, held in tin containers, were placed inside the auto-sampler drum, where they were purged with a continuous flow of helium and then dropped at preset intervals into a vertical quartz tube maintained at 1020  C (combustion reactor). Flash combustion of sample took place in the helium stream temporarily enriched with pure oxygen. The resulting gas mixture was directed to the chromatographic column (Porapak PQS) where the individual components were separated. The isotopic composition of evolved carbon dioxide (CO2) was measured using IRMS. The Flash EA-IRMS was calibrated using international standards, NBS-20 and graphite, and the precision was found to be within ±0.3‰ of the reported value. 3.2.3. Compound-specific carbon isotope analysis An offline, closed system pyrolysis of shales was performed at 300  C to desorb the thermo-labile gases present in it. 500 mg of powdered shale was heated in the pre-evacuated pyrolysis assembly for 3 min. Saturated KOH solution was added externally to glass ampoule and the thermally-desorbed gases released during the pyrolysis were collected by upward displacement in the graduated limb of apparatus fitted with silicone septum. KOH solution served the dual purpose of displacing the gases, as well as

absorbing the CO2 coming out during the pyrolysis of shale organic matter. 1 ml of the desorbed gas was injected into the Agilent 6890 GC, equipped with “Pora Plot Q” capillary column, 25 m in length and a diameter of 0.32 mm, in splitless mode with helium as carrier gas at a fixed oven temperature of 28  C. The chromatographically separated hydrocarbon gases eluted from GC column entered a preoxidized CueNiePt combustion reactor maintained at 960  C, where they were converted into carbon dioxide and water. Water was removed using a Nafion membrane tube prior to entry into the mass spectrometer. The purified CO2 after combustion entered the mass spectrometer for 13C/12C ratio measurement of the individual hydrocarbon components. GCeC-IRMS was calibrated using Natural Gas Standard (NGS-1) mixture and reported to the Vienna PeeDee Belemnite (VPDB). The precision was found to be within ±0.3‰ of the reported value for NGS-1 (Mani et al., 2011). 3.3. X-ray diffraction XRD analysis was carried out using Siemens D 500 diffractometer at XRD Laboratory, Atomic Mineral Directorate (AMD), Hyderabad. An accelerating voltage was maintained at 35 kV and the tube current at 22 mA. CuK a radiation (1.5418 A), monochromatised using curved graphite monochromator, was used for diffraction. For identification, a scanning speed of 0.03 2q/s, over a long angular range (4e90 2q), with a sampling time of 2 s, was selected. Mineral identification was done from the powder diffraction data so obtained by comparing the same with the relevant International Centre for Diffraction Data (ICDD) card. 3.4. Organic petrography The microscopic examination of the organic matter in shales was carried out in the Coal Petrology laboratories of Central Mine Planning & Design Institute Limited (CMPDIL), Ranchi and Indian School of Mines, Dhanbad. Maceral analysis and reflectance measurement of vitrinite grains in oil (Random; Rr% oil) was carried out on polished pellets under normal reflectance (incident light) and fluorescence modes using advanced polarizing microscope with photometer, following the standard protocol by ICCP (International Committee for Coal Petrography). 4. Results The shales (MMW-18/R-1 to MMW-18/R-9) from the Raniganj Formation, West Mohuda, show high Total Organic Carbon (TOC) content in the range of 2.86e23.09% (Table 1, Fig. 3). The S1 (thermally liberated free hydrocarbon) and S2 (hydrocarbon from cracking of kerogen) values range between 0.27e2.77 mg HC/g rock and 2.15e68.69 mg HC/g rock, respectively. The hydrogen index (HI) ranges between 75 and 297 mg HC/g TOC. The oxygen index (OI) is fairly low, ranging between 1 and 6 mgCO2/TOC (Table 1). The Tmax (temperature at highest yield of S2) ranges between 442 and 461  C, suggesting a mature stage for hydrocarbon generation (Fig. 4). Organic matter is characterized by mixed Type IIeIII oil/ gas-prone kerogen (Fig. 5). The Barren Measure shales from MSG-34 and MKP-29 boreholes from Singra and Kapuria blocks, respectively show a TOC content in the range of 4.36e4.48% with an average value of ~4.5% (Table 1). The S1 and S2 values range between 0.35e0.76 and 3.63e6.95 mg HC/g rock, respectively. The Tmax values range between 452 and 455  C, suggesting a mature kerogen in oil-condensate window (Table 1; Fig. 4). The HI values are between 83 and 143 mg HC/g TOC, and the OI values are <10 mg CO2/TOC (Fig. 5). The Barakar Formation shows TOC values ranging between 5.95 and 16.42% (Table 1). The S1 and S2 values range between 0.12 and

Please cite this article in press as: Mani, D., et al., Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India, Marine and Petroleum Geology (2015), http://dx.doi.org/10.1016/j.marpetgeo.2015.08.019

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Table 1 Rock Eval pyrolysis results of shales from the Jharia sub-basin, Damodar Valley. Block

Borehole/Depth (m)

W. Mahuda R-1 R-2 R-3 R-4 R-5 R-6 R-7 R-8 R-9 Singra BM-1 BM-2 B-I B-II B-III B-VA B-VB Kapuria BM-1 BM-2 B-I B-II B-III B-V B-VII B-IX

MMW-18 151.8e152.2 193.8e194.2 226.9e227.2 272.1e272.4 330.1e330.5 369.1e369.4 416.5e416.8 416.0e416.5 450.1e450.6 MSG-34 409.8e410.1 421.8e422.1 605.1e605.4 629.4e629.7 664.2e664.5 1012.8e1013.2 1048.8e1049.1 MKP-29 320.3e320.6 351.0e351.3 540.3e540.7 572.9e573.2 641.3e641.6 876.3e876.7 958.6e959.0 1009.0e1009.3

S1

S2

PI

Tmax

S3

PC (%)

RC (%)

TOC(%)

HI

OI

MINC (%)

0.61 0.95 0.42 1.19 0.29 0.27 2.47 2.76 1.47

15.43 24.75 3.54 68.69 2.67 2.15 17.01 19.71 8.45

0.04 0.04 0.11 0.02 0.1 0.11 0.13 0.12 0.15

442 444 450 439 455 452 445 450 464

0.29 0.13 0.15 0.2 0.07 0.16 0.24 0.34 0.35

1.4 2.17 0.41 5.86 0.36 0.25 1.76 2.02 1

6.35 9.12 3.76 17.23 3.04 2.62 10.21 10.78 6.88

7.75 11.29 4.17 23.09 3.4 2.87 11.97 12.8 7.88

199 219 85 297 79 75 142 154 107

4 1 4 1 2 6 2 3 4

0.79 0.52 0.88 4.59 1.29 0.81 1.69 1.6 2.11

0.35 0.58 0.76 0.6 0.35 0.87 0.63

3.63 6.39 33.2 3.96 3.95 7.3 6.28

0.09 0.08 0.02 0.13 0.08 0.11 0.09

455 452 461 470 467 485 492

0.19 0.11 0.11 0.33 0.22 0.21 0.21

0.37 0.6 2.85 0.67 0.43 0.76 0.7

3.99 3.88 13.57 5.28 5.79 10.55 10.49

4.36 4.48 16.42 5.95 6.22 11.31 11.19

83 143 202 67 64 65 56

4 2 1 6 4 2 2

0.54 0.33 6.77 2.57 1.24 7.34 8.34

0.76 0.66 0.56 0.69 0.42 0.19 0.13 0.12

4.7 4.08 6.15 3.31 6.48 2.9 5.55 2.99

0.14 0.14 0.08 0.17 0.06 0.06 0.02 0.04

459 457 473 473 476 493 493 509

0.15 0.25 0.19 0.21 0.18 0.16 0.18 0.27

0.5 0.48 0.6 0.43 0.62 0.32 0.66 0.38

3.89 3.8 7.51 4.67 8.24 7.16 12.31 8.34

4.39 4.28 8.11 5.1 8.86 7.48 12.97 8.72

107 95 76 65 73 39 43 34

3 6 2 4 2 2 1 3

0.94 1.42 1.57 1.57 1.22 1.47 4.44 5.55

S1 ¼ mgHC/gTOC; S2 ¼ mgHC/gTOC; PI ¼ S1/S1 þ S2; Tmax ¼  C; PC ¼ Pyrolysable carbon (%); RC ¼ Residual carbon (%); HI ¼ mgHC/g TOC; OI ¼ mg CO2/g TOC; MINC ¼ mineral carbon (%); R ¼ Raniganj Formation; BM ¼ Barren Measure Formation; B ¼ Barakar Formation.

0.76 mg HC/g rock and 2.9e33.2 mg HC/g rock, respectively. HI ranges between 34 and 76 mg HC/g TOC. Organic matter is characterized by Type III gas-prone kerogen (Fig. 3). Tmax ranges between 461 and 509  C, showing a post-mature kerogen, between condensate-wet gas and dry gas window (Figs. 4 and 5). Bulk and compound-specific (C1eC3) carbon isotope ratios of the organic matter and thermo-labile gases obtained from the combustion-IRMS and offline pyrolysis of shales from Jharia coal field are shown in Table 2. The d13Corg values of the Barren Measure shales lie in the range of 24.6e30.84‰, indicating a lacustrine/ marine source for the shale organic matter. One sample from the Raniganj Formation shows a d13Corg of 24.28‰, whereas those of Barakar have a value of 22.72e25.03‰, suggesting the organic provenance to be continental. The d13C ratios for the individual compounds (C1eC3) obtained from the repeated (n ¼ 5) thermal

desorption at 300  C of the one shale sample belonging to the Barren Measure Formation is as follows: d13C1 ¼ 40.38e44.82‰; d13C2 ¼ 29.62e30.3‰; and d13C3 ¼ 27.0e29.21‰. The values, variable in a narrow range, indicate a thermogenic source for the matrix adsorbed gaseous hydrocarbons. The results of petrographic examination of the shale samples are given Table 3. Photomicrographs of the macerals recorded from the three formations are shown in Plates IeIII. The Raniganj (Rr % ¼ 0.99e1.22) and Barren Measure (Rr% ¼ 1.1e1.41) shales show vitrinite and inertinite macerals, with lesser occurrence of liptinite. The Barakar shales (Rr% ¼ 1.11e2.0) consist mainly of inertinite and vitrinite. Abundant clay minerals along with siderite and pyrite are present. The X-ray diffraction results (Table 4) on nine selected samples representing the three formations show quartz (42e63%), siderite (9e15%), and albite (2e13%) to be the main minerals. Clay content is dominated by Kaolinite (4e17%) and illite (9e13%). Traces of chlorite and chloritoid, minute traces of almandite, anatase, microcline, rutile and zircon are also observed.

5. Discussion 5.1. Organic richness and thermal maturity

Fig. 3. TOC versus S2 variation (after, Langford and Blanc-Valleron, 1990) in shales from MMW-18, MSG-34, MKP-29 borewells, Jharia sub-basin, Damodar Valley. RNG¼Raniganj; BM¼Barren Measure; BRK¼Barakar

Organic matter in the shales from Jharia sub-basin, Damodar Valley show excellent organic richness (TOC ¼ 2.86e23.09%), characterized by Type II/III and Type III kerogen with thermal maturities spanning the mature (oil window-gas condensate) to post mature (dry gas) zone for hydrocarbon generation. While the Raniganj and Barren Measure shales are in late oil generation window, the Barakar shales show post-mature stage for oil (Fig. 4). Raniganj (Rr% ¼ 0.99e1.22) and Barren Measure (Rr% ¼ 1.1e1.41) shales show vitrinite and inertinite as dominant macerals, with sparse occurrence of liptinite. Barakar shales (Rr% ¼ 1.11e2.0) consist mainly of inertinite and vitrinite. Thermal maturities of the

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Fig. 4. HI vs Tmax plots (after Espitalie et al., 1987) indicating the kerogen type and thermal maturity of shales from the Jharia sub-basin, a) Raniganj, b) Barren Measure c) Barakar Formations.

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Fig. 5. Modified van Krevelen diagram (Peters, 1986) indicating the kerogen type in the shales from Jharia sub-basin, Damodar Valley.

shales are also reflected in correlation plot of Rock Eval Tmax and Vitrinite reflectance (Fig. 6). Barakar shales have experienced highest maturity. The Raniganj shales are comparatively less mature and Barren Measure is in late mature stage. Organic matter typing or the kerogen classification is directly related to total hydrocarbon potential, oil chemistry, and hydrocarbon generation kinetics (van Krevelin, 1961; Obermajer et al., 1997; McCarthy et al., 2011; Hartwig et al., 2012; Rippen et al., 2013; Abbassi et al., 2014). With relatively lesser thermal maturity, the HI of Raniganj is highest (75e297 mg HC/g TOC), followed by Barren Measure (83e147 mg HC/g TOC) and Barkar (34e95 mg HC/g TOC; except, B-1 ¼ 202 mg HC/g TOC from MSG-34), respectively. The HI values correlate well with the Tmax. The shales with increasing maturity (higher Tmax) have lower HI. This is in particular for the Barren Measure and Barakar shales; except for two samples (MGS-34/BM-II & B-III), where the variation is in narrow range (Table 1). For the Raniganj shales (MMW-18), the variation of HI is not consistent with Tmax. HI and Tmax are functions of both the kerogen composition and burial and thermal history, which can possibly influence the correlation between these parameters. The OI for all of these shales is <10 mg CO2/g TOC (Fig. 5). The OI values vary in very narrow range (1e6 mg CO2/g TOC). Raniganj shales show Type IIeIII oil and gas-prone kerogen, whereas Barren Measure and Barakar consist of Type III kerogen (Fig. 5). The production index (PI) ranges from 0.02 to 0.11 and tends to gradually increase linearly with depth for the Raniganj and Barren Measure shales. The exploration targets comprise of significant Type II organic matter in thermally over-mature stage and Type III organic matter in mature to overmature stage (Martini

et al., 2003; Hamblin, 2006; Tan et al., 2015). The kerogen quantity and quality of Permian shales from Damodar Valley basin are very much in agreement with these requirements. 5.2. Stable carbon isotope compositions Bulk and individual carbon isotope ratios of hydrocarbon gases obtained from the flash-combustion and thermal desorption, respectively of the shales indicate a thermogenic gas from the continental/terrestrial organic matter, except for Barren Measure, wherein a lacustrine/marine source is inferred. Stable carbon isotope ratios have been utilized for the identification of varied locations or origins of diverse potential sources of the hydrocarbon gases, particularly methane (Schoell, 1983). The depositional environment of shales - marine versus non-marine, has a direct influence on the type and amount of organic matter that they contain. The marine and continental (terrestrial and freshwater) plants show different d13C signatures in land plants as compared with marine plants due to the difference in the isotopic composition of carbon sources. As a result, the gas systems originating from respective source organic matter have been classified into two distinct types namely biogenic (or microbial) and thermogenic (Whiticar, 1996; Martini et al., 2003; Tian et al., 2010). There can also be mixtures of the two gas types (Jarvie et al., 2007). Occurrence of thermogenic gas establishes the presence and/or possibility of a source rock in the subsurface and gives information on the elements of petroleum or gas system, which otherwise lacks in biogenically produced gases. Thermogenic signature of hydrocarbon gases from the Barren Measure shale indicates the

Table 2 Bulk (combustion-IRMS) and compound-specific (offline pyrolysis-IRMS) carbon isotope ratios of the organic matter and thermo-labile desorbed gases, respectively, from the shales, Jharia sub-basin. Sample ID

Bulk d13C ratio (‰)

Sample

MKP-29/BM-2 MKP-29/B-3 MMW-18/R-4 MSG-34/BM-1 MSG-34/B-VA

30.8 25.0 24.3 24.6 22.7

MSG-34 MSG-34 MSG-34 MSG-34 MSG-34

BM-II BM-II BM-II BM-II BM-II

d13C1 (‰)

d13C2 (‰)

d13C3 (‰)

40.4 42.5 43.0 44.6 44.8

e e e 29.7 30.3

28.9 27.0 26.9 29.2 27.0

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Table 3 Petrographic analysis of the shales from Jharia sub-basin, Damodar Valley. Sample

Lithology

Rr%

Remarks

West Mohuda Block, MMW-18, R ¼ Raniganj Formation R-1 Sandy shale 0.99 Liptinite is abundant. Shows orangeeyellow color under fluorescence light. Clay minerals are dominant. Abundance of macerals: Liptinite > Vitrinite > Inertinite. R-2 Sandy shale 1.11 Vitrinite is common. Liptinite is sparse. Mineral matter abundant. Abundance of macerals: Vitrinite > Liptinite > Inertinite. R-3 Sandy shale 1.24 Vitrinite is common. Liptinite rare and Inertinite rare to sparse. Abundance: Vitrinite > Inertinite > Liptinite. Mineral matter dominant. R-4 Sandy shale 1.24 Vitrinite > Inertinite > Liptinite. Abundant mineral matter. R-5 Sandy shale 1.13 Inertinite common, Vitrinite sparse. Abundance: Inertinite > Vitrinite > Liptinite. Mineral matter abundant. R-6 Sandy shale 1.29 Vitrinite > Inertinite > Liptinite. Abundant mineral matter, clay minerals present. R-7 Shale 1.22 Inertinite > Vitrinite > Liptinite. Abundant mineral matter. Clay minerals and siderite observed. Singra Block, MSG-34; BM ¼ Barren Measure; B ¼ Barakar Formation BM-I Intercalation of 1.1 Grains of vitrinite and inertintes are large. Fusinite present. Inertinite > Vitrinite > Liptinite. Pyrite, siderite and clay shale and sandstone minerals present. BM-II Grey shale 1.15 Inertinite > Vitrinite > Liptinite. Mineral matter dominant. Siderite and pyrite observed. B-I Dark grey shale 1.41 Inertinite abundant, Vitrinite common and Liptinite rare. Abundance of macerals: Inertinite > Vitrinite > Liptinite. Siderite is common. B-II Intercalation of 1.11 Inertinite > Vitrinite > Liptinite. shale and sandstone B-III Shale 1.3 Vitrinite and Inertinite abundant. Liptinite rare. Mineral matter abundant, Pyrite common. B-VA Sandy shale 1.58 Inertinite > Vitrinite > Liptinite. Fusinite common, Siderite, pyrite abundant. B-VB Gray shale 1.6 Organic constituent abundant in ground mass, Inertinite > Vitrinite. Siderite abundant, Clay, quartz and few pyrites observed. Kapuria Block, MKP-29, BM ¼ Barren Measure; B ¼ Barakar Formation BM-1 Gray shale 1.41 Organic constituent sparse to common. Vitrinite > Inertinite. Liptinite rare. Abundant mineral matter. Some pyrite observed. Inertinite > Vitrinite > Liptinite. BM-2 Gray shale 1.32 Organic constituent sparse to common. Vitrinite > Inertinite. Liptinite rare. Abundant mineral matter. Some pyrite observed. Inertinite > Vitrinite > Liptinite B-1 Intercalation of 1.41 Vitrinite > Inertinite. Liptinite rare. Mineral matter Abundant. Clay & quartz > siderite > pyrite present. shale & sandstone B-2 Gray shale 1.24 Large grains of vitrinite and Inertinite. Vitrinite > Liptinite > Inertinite. Mineral matter abundant. Siderite and pyrite observed. B-3 Sandy shale 1.23 Vitrinite sparse, Inertinite common. Mineral matter dominant. B-5 Gray shale 1.32 Abundant Inertinite. Liptinite shows orangish color under fluorescence light. Mineral matter abundant. Some pyrite observed. B-7 Intercalation 1.20 Vitrinite grains are rare, Inertinite common to abundant. Organic constituents sparse. B-9 Gray shale 2.0 Vitrinites grains are altered. Inertinite abundant.

Table 4 Mineral identification in the shales from Jharia sub-basin using XRD technique. Sample id

Minerals identified

MMW-18/R-2 MMW-18/R-4 MMW-18/R-7 MMW-18/R-8 MSG-34/BM-I MSG-34/BM-II MSG-34/B-VA MKP-29/BM-I MKP-29/BM-II MKP-29/B-2

Quartz Quartz Quartz Quartz Quartz Quartz Quartz Quartz Quartz Quartz

(63%), (42%), (55%), (55%), (59%), (65%), (62%), (65%), (65%), (63%),

siderite siderite siderite siderite siderite siderite siderite siderite siderite siderite

Clay minerals identified (10%), (15%), (13%), (12%), (09%), (10%), (13%), (10%), (14%), (12%),

albite (3%), traces of chlorite, chloritoid, minute traces of almandite, microcline, rutile, zircon albite (13%), traces of chlorite, chloritoid, minute traces of microcline albite (5%), pyrite (4%), traces of chlorite, minute traces chloritoid and microcline albite (6%) albite (2%), minute traces of almandite, anatase, microcline, rutile, zircon pyrite (2%), albite (3%), traces of chlorite, minute traces of almandite, microcline, rutile, zircon albite (2%), traces of chlorite, chloritoid, minute traces of zircon pyrite (9%), traces of chlorite and chloritoid, minute traces of albite, almandite and microcline albite (4%), minute traces of anatase, chlorotoid, microcline, pyrite, titanite and zircon albite (3%), minute traces of chlorite, rutile, zircon

Kaolinite Kaolinite Kaolinite Kaolinite Kaolinite Kaolinite Kaolinite Kaolinite Kaolinite Kaolinite

(10%), (14%), (10%), (12%), (17%), (06%), (11%), (10%), (04%), (10%),

illite illite illite illite illite illite illite illite illite illite

(13%) (13%) (10%) (13%) (12%) (13%) (10%) (09%) (11%) (10%)

Fig. 6. Correlation plot of Rock Eval Tmax and Vitrinite reflectance data (Espitalie, 1986) from the shales of Jharia sub-basin, Damodar Valley.

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possibility of it being organic rich and thermally mature (Table 2). Under given conditions of sufficient burial and exposure to heat, the organic matter matured to generate the hydrocarbons, which might have been retained in the shale matrix. Upon desorption at 300  C, the thermo-labile components having petrogenic signature were liberated. Such isotopic signatures are essential for natural gas exploration and production strategies, maturity predictions and resource estimations (Osborn and McIntosh, 2010). The stable carbon isotope ratios have been shown to be susceptible towards fractionation due to migration, bacterial oxidation and thermal maturation of hydrocarbons (Prinzhofer and Huc, 1995; Rangel et al., 2003). The shale cores studied here are not contaminated by weathering and oxidation processes, hence, the thermally desorbed gases upon their pyrolysis reflect the pristine signature of gases derived from the thermal cracking of kerogen. Isotopic compositions tend to show enrichments with increasing thermal maturity (Burruss and Laughrey, 2010). The Damodar Valley shales are in thermally mature and post-mature stage of hydrocarbon generation, however; the exposure of organic matter to higher temperatures has not altered or enriched the d13C values significantly. The isotopic compositions vary in a narrow range and are nearly similar for all the studied samples (40.4e44.8‰; Table 2).

Measure shale indicate a marine/lacustrine source for the organic matter. Pyrolytic yields of the hydrocarbons and carbon dioxide are affected by associated mineral matrix (Espitalie et al., 1980; Horsfield and Douglas, 1980; Katz, 1983; Dembicki, 1992). Clay minerals have been shown to retain the heaviest hydrocarbon compounds and amount of adsorbed gases increase with the specific surface area of the argillaceous minerals. Similarly, higher OI has been observed for the shales containing carbonate minerals, which mainly results from the carbonate matrix-derived CO2 liberated during pyrolysis. Such relative differences in yields are most pronounced in organically leaner, immature samples. Low to moderate clay content (4e17%), low abundance of carbonates (0.33e8.34%) and minute traces of heavy minerals, characterize the mineralogy of Jharia shales (Table 4). The shales contain very high organic matter content (TOC ¼ 2.86e23.09%) in mature stage with very low OI (<10). Thus, any substantial effect of mineralogy on pyrolytic yield is not apparent and the high concentration of released hydrocarbons represent the ones that are free (S1) and those derived from the cracking of kerogen (S2), with low to negligible retention on the mineral matrix.

5.3. Maceral composition and mineralogy

The cracking of kerogen into simpler hydrocarbons is highly complex, as a result discrete bulk kinetic concepts, based primarily on the Arrhenius law (Eqs. (1)e(3)) are used (Tissot and Espitalie, 1975; Schenk and Horsfield, 1998). The A and E (Eqs. (1) and (2)) are properties of a specific reactant, and are related to the degree of the vibrational frequency of an activated complex formed in transition state of a reaction, thus are dependent on the type of organic matter (Dieckmann, 2005; Mahlstedt, 2012). The best fit between calculated and measured hydrocarbon generation rates were obtained with the activation energy distribution (Ea) and single preexponential factor (A) for the shales from each formation (Fig. 7). In general, broad distribution of activation energies (40e70 kcal/ mol) are observed, which are typical for the heterogeneous terrestrial organic matter derived from higher land plants (Mahlstedt and Horsfield, 2012). Raniganj shales, which are comparatively less mature, show the chemical bonds with activation energies between 42 and 62 kcal/mol, with peak energy for the hydrocarbon bond breaking at 48 kcal/mol (Fig. 7). Activation energy distribution is governed largely by the structure of kerogen. The rupture energy is attributable to variety of hydrocarbons bonds that are present in the kerogen, and is also influenced by the neighboring functional groups and length of hydrocarbon chains (Tissot and Espitalie, 1975). With increasing depth and temperature, various bonds corresponding to the successive activation energies are progressively broken, roughly in the order of increasing activation energies. Thus, the differences in Ea distribution are actually significant, which depict the variation in source rock organofacies and compositions, irrespective of the levels of thermal maturation attained by the kerogen. In the present study, the activation energy determined is for early mature to late and post mature samples, which might have experienced a partial conversion of organic matter into oil and gas. Lower activation energies for the Raniganj implicate towards the distinctive organic material, comparatively more homogenous and capable of generating the gas, in addition to having the oil prone character. This is also reflected in the organic matter quality of these shales, which is marked by presence of alginite and sporinite with oil & condensatewet gas-prone Type IIeIII kerogen (Fig. 4). The thermal degradation of kerogen in Barren Measure (44e68 kcal/mol) and Barakar (4268kal/mol) shows higher activation energies, with mean value of 52 kcal/mol. The Barren Measure shales are in late mature, gas

Maceral constituents in the Jharia shales are dominated by vitrinite and inertinite with sparse occurrence of liptinite (Table 3; Plates IeIII). The organic precursors are mainly woody tissues, derived from higher terrestrial land plants. Liptinite is more in Raniganj shales, and is marked by the presence of alginite and sporinite (Plate I). Vitrinite sub-type, collotelinite, is recorded in abundance. The organic matter assemblage is consistent with Type II/III organic matter in the Raniganj Formation. Kerogen pyrolysis of these shales also shows a lower Tmax and higher HI, and a Type II/ III kerogen in maure, oil generating stage. However; with increasing depth and maturation, vitrinite is the dominant constituent. In Barren Measure shales, collotelinite is recorded in the form of thick and thin bands (Plate II). Presence of framoboidal pyrites suggests the anoxic depositional environments (Plate II). Barakar shales show vitrinite and inertinite macerals with subtypes as collotelinite and inertodetrinite, respectively (Plate III). In general, the maceral composition is mainly a function of kerogen type (organic precursors) and is also dependent on extent of thermal exposure witnessed by the sediments. Damodar Valley is a Permian Gondwana basin and large percentage of organic matter is derived from higher terrestrial plants, wherein vitrinite dominates. Higher heat flow and effect of temperature on the liptinite rich sediments in the basin might result in cracking of it to oil and gas. The vitrinoid type (Vtype) distribution for the Raniganj and Barren Measure shales indicate large percentage of high to medium-volatile carbon, whereas for Barakar, low-volatile form is present. The vitrinite reflectance for Barakar shales (Rr% ¼ 1.1e2.0) suggests a postmature stage, where any residual oil or oil-prone kerogen will likely be cracked to gas. The Tmax values for these shales are high (460  Ce509  C). The variation of vitrinite (Rr%) with depth is almost linear for all the samples. Mineral content is dominated by detrital quartz (42e63%), siderite (9e15%) and clay (14e29%). Minute traces of heavy minerals are also observed (Table 4). Barren Measure shows the presence of pyrites (2e9%). It is mainly in framboidal form (Plate II). The formation of siderite is favored by alkaline reducing conditions, whereas the pyrite deposition commonly takes place in marine, reducing depositional environments in presence of organic material (Berner, 1981). The carbon isotope signatures of the Barren

5.4. Hydrocarbon generative potential

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Fig. 7. Frequency factors and activation energy distribution for the thermal cracking of organic matter in shales from the Jharia sub-basin, Damodar Valley.

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generating stage with abundant vitrinitic, Type III organic matter. The total petroleum potential is higher for Raniganj (HI ¼ 257 mg/g TOC) compared to Barren Measure (HI ¼ 102e158 mg/gTOC) and Barakar (HI ¼ 78 mg/g TOC). In temperature span (DT) of 380e540  C, the Raniganj shales show the generated hydrocarbons to be 240 mg HC/g TOC, which is highest, compared to the Barren Measure (90e140 mg HC/g TOC) and Barakar (78 mg HC/g TOC). The generation rate per degree C for the different samples is shown in Fig. 8. Rate curves for each of the product groups shift towards higher Tmax with increasing rates. The effective interval of hydrocarbon generation is represented by a 10e90% kerogen conversion ratio and the temperature span DT of the effective interval of hydrocarbon generation. The temperatures have been described for onset (10% transformation), middle (50% transformation), and end (90% transformation) of hydrocarbon generation. The temperature for onset (10% KTR) of hydrocarbons is highest for the Barakar shales (400  C) when compared to Raniganj (370  C) and Barren Measures (380  C) (Fig. 9). At 50% and 90% conversions, Barakar shales exhibit effective temperature greater than that shown by the Raniganj shale (420  C and 460  C, respectively). The Barren Measure shows intermediate characteristics. The organic matter in Raniganj shales demonstrates a faster hydrocarbon generation rate compared to the other two formations. It is generally accepted that a reaction occurring in a natural sedimentary environment has the same chemical kinetic properties (E and A) as the reaction occurring under controlled conditions of laboratory, and the thermal cracking of kerogen under geological condition can be reproduced by integrating kinetic parameters with the burial and thermal history of a sedimentary basin (Tissot and Welte, 1984; Braun and Burnham, 1987; Ungerer and Pelet, 1987). Maturation of organic matter in Jharia shales has been significantly affected by its burial and thermal history. During early Barakar deposition, the entire basin subsided. Contemporaneous faulting took place by the time middle Barakar deposited (Ghosh and Mukhopadhyay, 1985). During Upper Barakar times, the Southern Boundary fault was initiated, which got extended along the present southern boundary with the deposition of Barren Measure (Ghosh and Mukhopadhyay, 1985). The center of maximum subsidence was around Mohuda (Chandra, 1992). By end of the Barren Measure deposition, subsidence and faulting led to an elliptical basin. The deep syn- and post sedimentary burial and related tectonic activity might have led to the increased maturity and thermal alteration of organic matter in the shales. According to Mishra and Cook (1992), the Permian sections of the basin suffered a major PermianeTriassic thermal event and a tensional tectonic regime probably prevailed in India, possibly centred in Jharia. This might have led to extensive subsidence and, consequently, a thicker sedimentary sequence was deposited in the sub-basin than in the other Gondwana basins of India. However; high rank Permian coals (mean maximum reflectance of vitrinite; Rv ¼ 0.93e1.27%) occur near the surface of the sub-basin and comparisons of the vitrinite reflectance versus depth profiles from the region indicate that 2.5e3.5 km of cover was eroded (Mishra and Cook, 1992). This is also corroborated from other works (Chandra and Chakraborti, 1989; Bardhan and Ghosh, 1999) in Jharia, where the estimated temperature attained is in range of about 160e220  C and corresponding paleodepth is reported to be ~1600e4000 m. Using a Time-Temperature Index (TTI) type reconstruction on coals, Mishra and Cook (1992) suggested that the hydrocarbon generation within the Permian section had commenced by the Late Jurassic. The Early Permian Barakar Formation produced significant amounts of oil while passing through the zone of oil generation, probably during the Jurassic to Cretaceous, and the Late Permian Raniganj Formation is presently in mature stage (Mishra and Cook,

11

Fig. 8. Hydrocarbons generation rate with increasing temperature during pyrolysis of shales from the Jharia sub-basin, Damodar Valley.

1992). The thermal maturity data on coals adjoining the Barren Measure suggest the shale to be thermally late mature within the wet gas/condensate (Ro of 1.0%e1.3%) window (Padhy and Das, 2013). The basin has a present-day temperature ranging from 34  C/km to 39  C/km (Rao and Rao, 1980; Mishra and Cook, 1992). Maturation data for Jharia boreholes indicate relatively high temperature levels during the Mesozoic and the main phase of oil generation occurred during the Late Cretaceous and oil generation from the lower part of the Permian ceased before the early Tertiary

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Plate I. Photomicrograph of Raniganj shale (MMW-18/R-2) showing the presence of macerals- collotelinite (Co) alginite (Al) e (Plate I a); pyrofusinite (Pf) and collotelinite (Co) e (Plate Ib); sporinite (Sp), clay (Cy) e (Plate I c), under reflected light (magnification 625).

typical of a Type II/III kerogen, while the Early Permian Barakar shales are over mature. The kinetic parameters and organic properties of Middle Permian Barren Measure shale show it to be thermally late mature, in the gas generating window. Fig. 9. Kerogen transformation ratio (%) with increasing temperature during pyrolysis of the shales from the Jharia sub-basin, Damodar Valley.

(Mishra and Cook, 1992). The kerogen quality suggests that it has passed the oil window; however it possesses excellent properties for the gas generation. This is also supported by the pyrolysis results of the shales from these formations. Late Permian Raniganj shale has lower activation energy with relatively higher potential,

5.5. Permian gas shales in Jharia? Increasing research activities on shale gas have led to establishment of certain characteristics of potential plays. The productive gas shales are in general >200 ft (65 m) thick, have TOC content > 3 wt % and HI >350 mg HC/gTOC, and contain type II marine kerogen of organic maturity >1.10% Ro (Curtis, 2002; Montgomery et al., 2005; Boyer et al., 2006; Jarvie and Lundell, 1991; Jarvie et al.,

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Plate II. Photomicrographs of Barren Measure shale (MKP-29/BM-1) showing the macerals e collotelinite (Co), pyrite (py) e (Plate II a); collotelinite (Co), clay (Cy), pyrofusinite (Pf) e (Plate II b); clay (Cy), sporinite (Sp)- (Plate II c); vitrodetrinite (Vd), collotelinite (Co), clay (Cy), e (Plate II d); clay (Cy), pyrofusinite (Pf)- (Plate II e); pyrite (Py) e (Plate II f) under reflected light (magnification of 625).

2007; Loucks and Ruppel, 2007; Romero and Philip, 2012; Horsfield and Schulz, 2012; Slatt and Rodriguez, 2012 and several others). The organic richness and thermal maturity of Permian shales from Jharia sub-basin suggest these to be possible targets for shale gas. The thermogenic source, deduced from the carbon isotope ratios of these gases, further corroborates the occurrence of organic rich, thermally mature source beds in the region. The gas-prone shale formations are wide spread in the basin and have sufficient thicknesses at depth. About 58 km2 of the area is occupied by the Raniganj series, 218 km2 by the Barakar series and 181 km2 comprise rocks of Barren-Measures and the Talchir series in the Jharia sub-basin (Verma et al., 1979). The thickness of Raniganj is about 800 m, whereas the Barren Measure varies from 600 to 730 m (Chandra, 1992). The thickness of Barakar Formation varies from 800 to 1250 m. The variability in organic matter content and quality with increasing depths is attributed to the depositional facies, burial depths and partly to the igneous intrusive (Rullkotter et al., 1988; Huang et al., 2013) occurring all over the Jharia subbasin. West Mohuda block has extensive mica-peridotite

intrusives, which might be responsible for the cooking of the Type IIeIII kerogen in Raniganj shales (Verma et al., 1979; Paul and Chatterjee, 2011). Highly mature kerogen in the Barren Measure and Barakar Formations could be attributed to the dolerite dykes occurring in vicinity of the Singra and Kapuria boreholes in the central part of sub-basin (Verma et al., 1979; Paul and Chatterjee, 2011). The vitrinite reflectance for these shales is 1% Rr. The late to post-mature stage of organic matter is attributed to the significantly higher heat flow in the basin, apart from the increasing burial depths of these formations. The mean heat flow value reported from the main synclinal region, which forms the major part of the Jharia sub-basin, is 1.9 HFU (Heat Flow Unit; about 79 mWm2) (Rao and Rao, 1980). This is notably higher than the continental mean of 1.5 HFU and is nearly twice the value of 1.0 HFU, generally quoted for shields. When considering the source rocks in terms of gas shales, besides organic properties, factors such as mineralogy, matrix porosity/permeability and geological complexity become vital in assessment of the generation potential (Loucks and Ruppel, 2007;

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Plate III. Photomicrograph of Barakar shale (MKP-29/B-2) showing the presence of collotelinite (Co)-(Plate III a); alginite (Al), inertodetrinite (Ind), clay (Cy)- (Plate III b); collotelinite (Co), clay (Cy)- (Plate III c); collotelinite (Co), vitrodetrinite (Vd), pyrofusinite (Pf)- (Plate III d), alginite (Al), clay (Cy)- (Plate III e); collotelinite (Co)-(Plate III f), under reflected light (magnification 625).

Ross and Bustin, 2009; Horsfield and Schulz, 2012; Slatt and Rodriguez, 2012; EIA, 2015). Shales with a high percentage of quartz, when fracked lead to a vast array of small-scale induced fractures providing numerous flow paths from the matrix to the wellbore, when hydraulic pressure and energy are injected into the shale matrix (Loucks and Ruppel, 2007; EIA, 2015). This is opposed to that of shales with a high clay content, which being ductile are deformed instead of shattering leading to relatively few induced fractures. The XRD studies on shales from the Jharia sub-basin show them to be dominantly containing quartz, with low to moderate clay content. The quartz is largely detrital in nature (Dutta and Suttner, 1986; Dasgupta, 2006), and has higher porosity and permeability than the biogenic silica-rich quartz (Bustin and Bustin, 2012). In general, marine-deposited shales tend to have lower clay content and high brittle minerals such as quartz, feldspar and carbonates. Shales deposited in non-marine settings (lacustrine, fluvial) tend to be higher in clay, more ductile and less responsive to

hydraulic stimulation (EIA, 2015). With known gas shales mostly aquatic (marine/lacustrine) in origin, the Barren Measure has substantial geochemical and geological attributes to be a promising target. Bulk organic carbon isotopes show lacustrine/marine dominated signatures for the Barren Measure. Its Lower Member, the Shibabudih shale has the thickness of 148 m and is of lacustrine origin (Dasgupta, 2005). Shale having Type III organic matter in thermally mature to over mature states generates gas (Martini et al., 2003; Hamblin, 2006; Tan et al., 2015). Gas shows at the depth of 985e1843 m in Barren Measures Formation have been observed from the Raniganj sub-basin of the Damodar Valley. Central Mine Planning and Design Institute (CMPDI) has reported 45 TCF of shale gas in six sub-basins (Jharia, Bokaro, North Karanpura, South Karanpura, Raniganj & Sohagpur) of Damodar Valley (MoP and NG, 2015). The gas recovery efficiency from a shale gas basin/formation is largely dependent on the complex geologic features. Areas with

Please cite this article in press as: Mani, D., et al., Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India, Marine and Petroleum Geology (2015), http://dx.doi.org/10.1016/j.marpetgeo.2015.08.019

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extensive faults, deep seated, vertical or thrust faults can hinder gas recovery by limiting the productive length of the horizontal well, reducing the relative permeability and gas flow capacity (Curtis, 2002; EIA, 2015). In Damodar Valley basin, the transverse normal faults are distributed along the basin margin (Ghosh, 2002; Chakraborty et al., 2003). Conjugate sets of intrabasinal normal faults transverse to the basinal trend are common, and have truncated the entire Gondwana sediment package as well as the basement rocks. Other intrabasinal normal faults parallel to the basin margin are thought to have been active during the sedimentation (Ghosh, 2002). Compared to other sub-basins of Damodar Valley such as Bokaro, Raniganj etc., where the sedimentary overburden is substantial, the shallow depth of shale occurrences and structure complexities of Jharia require careful consideration in deciding upon the exploration methodologies in the basin.

6. Conclusion The organic richness, thermal maturity and kerogen type in Permian shales from Jharia sub-basin of Damodar Valley show excellent potential for the generation of gas. The carbon isotope ratios of the thermo-labile components suggest the source of the gaseous hydrocarbons to be thermogenic. The Raniganj and Barren Measure Formation are thermally mature in late gas generation stage, where as the Barakar shales are post-mature. The vitrinite reflectance also follows the corresponding pattern of organic matter abundance and maturity. Kinetic analysis of the thermal cracking of kerogen demonstrates the Raniganj shales to be more capable of generating gas and at a faster hydrocarbon rate compared to the Barren Measure and Barakar. With a lacustrine/ marine origin and sufficient thermal maturity for gas generation, the Barren Measure is a potential candidate for shale gas. Besides providing high rank coals, the Permian Gondwana shales can be a source of unconventional shale gas. These shales tend to have lower clay content and high brittle minerals such as quartz and siderite, owing to which the response to hydraulic stimulation could be favorable. With the surge in shale gas activities worldwide, the results of this study provide new information on the organic, mineralogical and kinetic properties of source rocks of Jharia sub-basin and have encouraging implications towards its exploration.

Acknowledgments The Oil Industry Development Board, New Delhi (4/5/2009OIDB) is acknowledged for the financial support towards establishment of laboratory facility. Officials of Central Mine Planning & Design Institute (CMPDI), Ranchi (Grant no. GAP-673-28(DJP)) are thanked for extending their support during field visits. The authors are grateful to The Director, Atomic Mineral Directorate (AMD) and Dr.Y.Singh for the XRD analysis. Prof. A. Varma and his research students, ISM, Dhanbad are acknowledged for the support extended towards micropetrographic analysis. Prof. M. K. Sen, UT, Austin is acknowledged for his support towards project activities. The manuscript was immensely benefited from comments of Profs. Barry J. Katz, Tongwei Zhang and Hui Tian. The Director, NGRI is thanked for permitting the publication of this work.

Appendix Litho-log of the boreholes selected for shale sampling. Please cite this article in press as: Mani, D., et al., Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India, Marine and Petroleum Geology (2015), http://dx.doi.org/10.1016/j.marpetgeo.2015.08.019

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Please cite this article in press as: Mani, D., et al., Thermal maturity, source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin, Eastern India, Marine and Petroleum Geology (2015), http://dx.doi.org/10.1016/j.marpetgeo.2015.08.019