Assessment of organic richness and hydrocarbon generation potential of Raniganj basin shales, West Bengal, India

Marine and Petroleum Geology 59 (2015) 480e490

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Research paper

Assessment of organic richness and hydrocarbon generation potential of Raniganj basin shales, West Bengal, India Atul Kumar Varma a, *, Bodhisatwa Hazra a, Vinod Atmaram Mendhe b, Itishree Chinara a, Anurodh Mohan Dayal c a b c

Coal Geology and Organic Petrology Lab., Dept. of Applied Geology, Indian School of Mines, Dhanbad, 826004, India Central Institute of Mining and Fuel Research, Dhanbad, 826001, India National Geophysical Research Institute, Hyderabad, 500007, India

a r t i c l e i n f o

a b s t r a c t

Article history: Received 21 June 2014 Received in revised form 26 September 2014 Accepted 6 October 2014 Available online 15 October 2014

High energy prices and severe energy shortage has led shale gas to become the focus of study and exploration in many countries. India, like many other countries around the world with shale gas potential recognizes the strategic importance of developing its shale gas resources. For the purpose of shale gas assessment, the authors have selected sixty six borehole shale samples of different formations from different parts of Raniganj basin, West Bengal, India. Rock eval pyrolysis and total organic carbon (TOC) analysis and petrographic characterization of the shales were carried out. Shales from Barakar (Lower Permian), Barren Measures (Upper Permian) and Raniganj Formation (Upper Permian) are marked by ‘good’ to ‘excellent’ TOC content, input of type III organic matter and are capable of generating oil and thermogenic gas upon thermal cracking. Igneous intrusives (dykes and sills) in the formations occurring in and around the areas of Sitarampur (Si) and Kulti (Ku) in western part of the basin might have resulted in cooking of the shales, increasing their maturities (estimated vitrinite reflectance, VRo) as indicated by the Barren Measures shales of shallow depths from the above mentioned areas. Majority of the samples are marked by low oxygen index (OI) values. © 2014 Elsevier Ltd. All rights reserved.

Keywords: Shale gas TOC Rock eval pyrolysis Raniganj basin Increased maturity

1. Introduction The arrival of shale as hydrocarbon reservoir has drawn attention for deeper understanding and research (Montgomery et al., 2005; Jarvie et al., 2007; Loucks et al., 2009). Shales are unconventional gas systems where it acts as both source and reservoir rocks for gas mainly methane and are classes of continuous petroleum accumulations (Schmoker, 1995; Jarvie et al., 2007). The process of adsorption plays an important role in unconventional resource plays and accounts, in part, for the retention of oil that is ultimately cracked to gas in shale-gas systems (Jarvie, 2012). Organic matter in shale typically ranges from below 1 wt % to more than 20 wt % and is responsible for in situ gas generation which is stored in the micropore structure of organic matter (Loucks et al., 2009) and clay minerals (Chalmers and Bustin, 2007; Ross and Bustin, 2009). Hydrocarbon generative potential of shales depends on the amount, type and maturity of the organic matter present in it (Tissot and Welte, 1978; Sykes and Snowdon, 2002).

* Corresponding author. Tel.: þ91 326 2235271; fax: þ91 326 2296563. E-mail address: [email protected] (A.K. Varma). http://dx.doi.org/10.1016/j.marpetgeo.2014.10.003 0264-8172/© 2014 Elsevier Ltd. All rights reserved.

Rock eval pyrolysis and TOC analysis, the most widely used method for screening the petroleum generation potential, provides information on the quantity and type of organic matter in a sedimentary
et al., rock, in addition to the level of organic maturation (Espitalie 1977). In this paper the authors have tried to assess the hydrocarbon generative potential of borehole shale samples from different formations of Raniganj coal basin, West Bengal, India through rock eval pyrolysis and TOC analysis and organic petrography. Raniganj coal basin, sub-basin of Damodar Valley basin (part of a group of basins collectively named the ‘Gondwanas’), is the birthplace of the Indian coal industry and has been a centre of geological activities for more than two centuries. Official record on occurrence and extraction of coal in Raniganj basin dates back to 1774. Since then it has been trodden over by numerous geoscientists and exploiters. However as exploration has focused on the coal deposits, relatively little geologic data is available on the shales of different formations in this basin. After US, the shale gas revolution is knocking at the doors of the Indian gas market and has attracted the attention of scientists, technologists and policy makers (Varma and Panda, 2010; Varma et al., 2014a,b; Mani et al., 2014). India, like many other countries around the world with shale gas potential, recognizes the strategic

A.K. Varma et al. / Marine and Petroleum Geology 59 (2015) 480e490

importance of developing its shale gas resources. In January 2011, Oil and Natural Gas Corporation Limited (ONGC) struck gas at its pilot shale gas well RNSG-1, drilled by Schlumberger at Icchapur, near Durgapur, West Bengal, in eastern part of Raniganj sub-basin of the Damodar Valley (LNG World News, 2011). The well was drilled to a depth of around 2000 m and reportedly had gas shows at the base of the Permian Barren Measures Formation (985e1843 m). 2. Geological setting Raniganj coal basin, the easternmost intracratonic rift basin of the Damodar Valley, has a semi-elliptical, elongated shape, and covers an area of 1900 km2 between the Damodar and Ajay rivers. It is bounded by latitudes 23 220 N and 23 520 N, and longitudes 86 360 E and 87 300 E (Gee, 1932). The Raniganj basin is one of the few coal basins of peninsular India where both the Lower Gondwana (Permian) and Upper Gondwana (Triassice Lower Cretaceous) formations are present (Gee, 1932). The Gondwana Supergroup is about 3,200 m thick and is subdivided into six formal units. The Gondwana formations were deposited in the tectonic trough with faulted boundaries i.e., northern and southern faulted boundaries, on either side of the Damodar river which flows on the faulted trough. The Raniganj coal basin is faulted down on the south and west, the southern boundary being a series of faults, shows an en echelon pattern with a general strike of EeW dipping towards the major faults mostly towards more faulted southern boundary. The dip of the strata varies from 5 to 10 . Besides the boundary faults, there are also oblique and cross faults in the field with a general strike of NWeSE dipping towards northeeast. The field is traversed by igneous intrusions of dolerites or basalt and lamprophyres. The lower Gondwana formations were deposited over the Precambrian basement. The generalized stratigraphic succession

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and the geological map of Raniganj coal basin with the study area is shown in Table 1and Figure 1 respectively. The areas from where the samples have been collected are marked in Figure 1. Kuldiha area (K in Fig. 1), easternmost part of the basin, is marked by a thick succession of Cenozoic sediments from surface and in then followed by Supra-Panchet (Upper Triassic) and Panchet (Lower Triassic) Formations. In the Northeastern portion of the basin lies Jaggannathpur (marked as J). In Icchapur area (I, east of central part of the basin) the first Formation encountered below the soil and weathered mantle is Panchet Formation (Lower Triassic). Moving westwards, the Andal area (A) is encountered. Here Raniganj Formation (Upper Permian) is encountered first. In the western part of the basin lies Sitarampur (Si) and Kulti (Ku) areas, wherefrom samples belonging to Barren Measures (Ironstone shales) Formation (Upper Permian) were collected. 3. Materials and methods 3.1. Collection of samples For the purpose of assessing the hydrocarbon prospectivity of shales from Raniganj coal basin, a total of sixty six borehole samples were collected from different parts of the basin belonging to different Formations. Location, depth and stratigraphic formation of the samples are provided in Table 2. 3.2. Rock eval pyrolysis Rock-Eval 6 was used for carrying out Rock Eval Pyrolysis (REP) and TOC analysis of the samples. Firstly the samples were washed, dried, crushed to powder and screened through BSS 60 mesh size ( 250 micron size) and were well homogenized prior to carrying

Table 1 Generalized stratigraphic succession of Raniganj coal basin (after GSI, 2003). Age

Formation

Lithology

Recent and Quaternary

Alluvial and residual soils; lateritic capping. ----------------------Unconformity-------------------------------------Light grey mudstone and siltstone with bands of marlstone; white, soft fine grained clayey sandstone, mottled clay and loose sand with pebbles of vien quartz; occasionally lignite at the basal part. -----------------------Unconformity------------------------------------Basic (dolerite) dykes; Ultrabasic (mica-peridotite, mica-lamprophyre, lamprophyre) sills and dykes.

Tertiary Cretaceous Cretaceous Upper Triassic*

Lower Triassic*

Igneous intrusive Rajmahal Formation Supra-Panchet/ Durgapur Beds Panchet Formation Raniganj Formation (Lopingian *)

Upper Permian*

Lower Permian*

Barren Measures/ Ironstone Shales (Guadalupian *) Barakar Formation with Karharbari Formation (?) at base (Cisuralian- Early Sakmarian to Kungurian *) Talchir Formation

Precambrian

Chotanagpur Complex

Gneissic

Greenish grey to black, fine to medium grained vesicular porphyritic basalt and volcanic breccia; weathered aphanitic basalt at places; one to five inter-trappeans consisting of grey shale, fine grained sandstone and carbonaceous shale. ------------------------Unconformity-----------------------------------Massive, very coarse to coarse quartzose sandstone, conglomeratic at places; bands of dark red silty shale. ------------------------Unconformity-----------------------------------Coarse grained greenish yellow and greenish grey soft, micaceous, cross-bedded sandstone with slump structures; khaki green fissile silty shale; alternate bands of yellow coarse grained immature sandstone and bright reddish brown claystone with calcareous concretions; conglomeratic at the base. Grey to light grey fine and medium grained micaceous felspathic sandstone with calcareous clayey matrix in the upper part; siltstones and shales, often interlaminated with fine grained sandstone; carbonaceous shales and coal seams. Dark grey to black micaceous or carbonaceous, fissile shlaes with ferrugineous laminae and thin bands of dense, hard, cryptocrystalline clay ironstones; rarely interbanded with fine grained sandstone. Very coarse to medium grained arkosic sandstones, often cross-bedded; grey and carbonaceous shales, at times interbanded with fine grained sandstone; fire clay lenses and coal seams; pebbly and carbonaceous in lower part. Tillite or diamictite with sandy or clayey matrix at the base; medium to fine grained khaki or yellowish green feldspathic sandstone; siltstone, silty shale, needle shale and rhythmite with dropstones. -----------------------Unconformity------------------------------------Granite gneiss with migmatitic gneiss, hornblende schist, hornblende gneiss, metabasic rocks, pegmatite and quartz veins etc.

(Explanation: * = age according to Mukhopadhyay et al., 2010)

Maximum Thickness (m) 90 300 ___ 120

300 600 1150 600 750

500 __

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A.K. Varma et al. / Marine and Petroleum Geology 59 (2015) 480e490

Figure 1. Geological map of Raniganj coal basin (after Gee, 1932; GSI, 2003). The study areas have been shown in the map. Explanations: K ¼ Kuldiha area, J ¼ Jaggannathpur area, I ¼ Icchapur area, A ¼ Andal area, Si ¼ Sitarampur area and Ku ¼ Kulti area.

out experiments. Rock eval pyrolysis, which is essentially a two step process, involves pyrolysis in an inert atmosphere (nitrogen) and combustion in an oxic atmosphere (air). The pyrolysis begins (first stage) by heating the sample at 300  C. During this stage free hydrocarbons, volatile compounds, such as short chain lipids and other small volatile compounds are released and are recorded under S1 curve (mg HC/g rock). This stage is followed by a temperature rise of 25  C/min until 650  C is reached. During this stage the hydrocarbons released are due to cracking of heavier and larger molecules and represents the present hydrocarbon generating capability of the rock and are recorded under S2 curve (mg HC/g rock) (Lafargue et al., 1998). Hydrocarbons released under S1 and S2 are measured by flame ionization detection (FID). During the pyrolysis step S3, carbon dioxide and carbon monoxide (mg oxides of carbon/g) are measured continuously by infrared (IR) spectroscopy. This is followed by transferring the sample to an oxic chamber where it is heated to 850  C thereby burning off all the remaining organic matter (OM). It produces the residual carbon (RC) fraction (wt % measured by IR). The TOC content is derived from the sum of these fractions (Lafargue et al., 1998). The S1, S2 and S3 parameters are measured in milligrams of produced hydrocarbons per gram of rock sample (equivalent to kg/t), where the products are hydrocarbons for the S1 and S2 parameters, and CO2 and CO for the S3 parameter. TOC is reported in weight percent (wt. %) and Tmax (a maturity parameter based on the temperature at which the maximum amount of pyrolyzate (S2) is generated from the kerogen in a rock sample) is measured in degree celsius. From the results of the tests, production index [PI ¼ S1/(S1 þ S2)], genetic potential [GP ¼ S1 þ S2], hydrogen index (HI ¼ S2/TOC) and oxygen index (OI ¼ S3/TOC) were calculated and are used to assess the shale gas potential of the sampled stratigraphic formations. 3.3. Micropetrographic analysis Micropetrographic analysis using shale pellets were carried out. The shale samples were crushed to <1 mm sizes to prepare pellets.

These samples were studied under reflected light in “Leitz MPV2” microscope with oil immersion lens and fluorescence attachment following standard procedures (ICCP, 1971, 1998, 2001). Macerals were identified following ICCP classification of macerals (ICCP, 1963, 1971, 1975, 1998, 2001). 4. Results and discussions 4.1. Rock eval pyrolysis and TOC analysis 4.1.1. Raniganj shales (Upper Permian) The shale samples belonging to Raniganj Formation from Raniganj basin shows a wide range of TOC content (Table 3) ranging between 0.82 and 29.74 wt %. Shales from Icchapur (I1eI15) and Andal (A1eA6) areas of the basin have ‘very good’ (2e4 wt %) to ‘excellent’ TOC content (>4 wt %). Barring sample K5 (TOC ¼ 0.82 wt %) the samples from Kuldiha (K1eK6) area of the basin have ‘good’ (TOC ¼ 1e2 wt %) to ‘very good’ TOC content (2e4 wt %). Samples from Jaggannathpur (J) area (J1eJ7) shows wide range of TOC content ranging between 1.60 and 27.46 wt %. The genetic potential (S1 þ S2; mg HC/g rock) of these samples varies between 0.42 and 58.38 mg HC/g rock. Ten samples from Icchapur (I) area have ‘fair’ to ‘excellent’ genetic potential while 5 samples (I2, I3, I4, I7 and I8) have ‘poor’ genetic potential. In addition to this the ‘very good’ to ‘excellent’ TOC content indicates this area to be good for hydrocarbon generation. The genetic potential (GP) of the samples from Andal (A) area varies between ‘good’ to ‘very good’ apart from samples A1 and A5 which have ‘poor’ GP. Samples J1 and J2 from Jaggannathpur (J) area of the basin have excellent genetic potential while the others have poor GP. Genetic potential of the shales in general are poor in Kuldiha (K) area of the basin. Apart from five samples [four from Jaggannathpur (J) area (J1eJ3, J5) and one from Kuldiha (K) area (K2) with Tmax < 435  C] all the borehole shale samples of this Formation falls within early to peak mature stage indicated by the Tmax values of rock eval

A.K. Varma et al. / Marine and Petroleum Geology 59 (2015) 480e490 Table 2 Location of selected borehole shale samples.

483

VRo) using the formula of Jarvie et al. (2001) from Tmax value of rock eval pyrolysis. The equation is mentioned below:

Area

Bh/No

SN

Fm

Depth (m)

Kuldiha (K)

BHK1

PF

Icchapur (I)

BHI1

P1 P2 I1 I2 I3 I4 I5 I6 I7 I8 I9 I10 I11 I12 I13 I14 I15 A1 A2 A3 A4 A5 A6 J1 J2 J3 J4 J5 J6 J7 K1 K2 K3 K4 K5 K6 Ku1 Ku2 Ku3 Ku4 Ku5 Ku6 Ku7 Ku8 Ku9 Ku10 Si1 Si2 Si3 Si4 Si5 Si6 Si7 Si8 Si9 Si10 Si11 Si12 Kd1 Kd2 B1 B2 B3 B4 B5 B6

755 812 177.10 227.50 303.10 506.40 524.10 494.00 591.00 606.00 626.40 703.40 732.00 700.00 371.90 413.50 639.00 791.50 908.50 847.00 885.00 772.60 328.35 567.00 286.00 301.50 332.00 399.00 431.00 449.00 913.00 1044.00 1123.00 1225.00 1233.00 1370.00 608 650 688 728.7 655.1 510 539 360.5 362.6 225 28.3 80.35 170.3 274.2 371.3 421.5 483.6 367 249.5 124 55.8 112.5 1440 1480 773 917.5 955 1066.2 1070 1095

Estimated %VRo ðfrom Tmax Þ ¼ 0:0180  Tmax  7:16

(1)

Explanations- Bh/No: Borehole number; SN: sample number; PF: Panchet Formation (Lower Triassic); RF: Raniganj Formation (Upper Permian); BMF: Barren Measures Formation (Upper Permian); BF: Barakar Formation (Lower Permian).

In this equation Tmax is expressed in degree celsius. The vitrinite reflectance oil window (VRo ¼ 0.60%e1.00 %) is defined as the thermal maturity zone where liquid hydrocarbons are the dominant product, although there is always associated gas formed in the oil window too. Using the above mentioned equation the corresponding Tmax for VRo values of 0.60% and 1.00% are 431 and 453  C respectively. Hydrogen index (HI ¼ S2/TOC) and oxygen index (OI ¼ S3/TOC) of the studied samples belonging to Raniganj Formation are shown in Table 3. Type I kerogen (oil prone) commonly possess HI values more than 600 mg HC/g TOC while type II (oil prone) are known to possess values greater that 300 but lower than 600 mg HC/g TOC (Peters and Cassa, 1994; Nicholas et al., 2004; Hakimi et al., 2012a,b; Hakimi et al., 2013). Samples with HI values between 200 and 300 mg HC/g TOC could be considered as type IIeIII (mixed oil and gas) admixed materials. Type III kerogen (gas prone) that are mostly comprised of woody materials have HI value lower than 200 but greater than 50 mg HC/g TOC while type IV (inert) materials typically have their values lower than 50 mg HC/g TOC. The HI values of the studied Raniganj Formation samples varies between 31 and 287 mg HC/g TOC with the majority falling between 50 and 200 mg HC/g TOC (Type III). The pseudo-van Krevelen diagram (HI vs OI; Fig. 3) for these samples show organic type and relative hydrocarbon potential and crudely the course of maturation. However, the oxygen indices (Fig. 3, Table 3) are notably lower than those normally reported for type III organic matter either in coals or dispersed in shales, and no relation between OI and thermal maturity (Tmax) is evident. Similar lower values were observed by Rice et al. (1989), Teerman and Hwang (1991), and Kotarba et al. (2002) in coals of different locations and concluded that these lower values are related to the presence of relatively stable oxygen moieties which are not cracked at relatively lower coal ranks. No obvious relationship was found between HI and Tmax for the whole group of samples and can be explained as wide range of HI values would prevail over major part of the oil window (VRo estimated from Tmax) until sufficiently high maturities are reached whereby the samples converge towards lower values. The graph of S2 vs TOC (Fig. 4) has been used following Langford and Blanc-Valleron (1990) and shows a high co-efficient of determination R2 ¼ 0.91. Here, logarithmic scale has been used for both the axes (TOC along abscissa and S2 along ordinate) instead of a linear one to construct HI lines along which HI values are constant. For example, along line ‘a’ all points will have HI values of 1000. So this plot along with the representation of the relationship between S2 and TOC also shows the kerogen type present and its hydrocarbon potential. Figure 5 shows relation between HI and TOC following Jackson et al., 1985. Samples K5 and K2 from Kuldiha (K) area falls under non-source field while K3 and K6 fall in the ‘poor source field’. Sample K4 represents fair oil source while K1 falls in the ‘gas and/or oil source’ field. Out of the 15 samples from Icchapur (I) area, only sample I2 falls in the poor source field while samples I3 and I4 falls in the gas and/or oil source field; rest plots in the fair oil source field. Samples from Andal (A) area of the basin falls in the ‘gas and/ or oil source’ and ‘fair oil source’ field as shown in the figure. Majority of the shale samples from Jaggannathpur (J) area falls in ‘fair oil source’ to ‘good oil source’ fields.

pyrolysis ranging between 435 and 450  C (Table 3, Fig. 2). Kerogen at this maturity level is within the oil window and is capable of generating oil and thermogenic gas upon thermal cracking (Gentzis, 2013). Here authors have estimated VRo (estimated %

4.1.2. Barren Measures Formation shales (Upper Permian) India's first shale gas exploration well targeted this shale Formation in the eastern portion of the Damodar Valley. In Sitarampur

BHI2

BHI3

Andal (A)

BHA1

Jaggannathpur (J)

BHJ1

Kuldiha (K)

BHK1

Kulti (Ku)

BHKu1

BHKu2

Sitarampur (Si)

BHSi1

BHSi2

BHSi3 Kuldiha (K)

BHK1

Kulti (Ku)

BHKu1

RF

BMF

BF

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A.K. Varma et al. / Marine and Petroleum Geology 59 (2015) 480e490

Table 3 Rock eval pyrolysis, TOC analysis, estimated vitrinite reflectance, f, TOCO and HIO of the shale samples. SN

S1

S2

S3

PI

HI

Tmax

TOC

OI

VRo*

f

TOCO

HIO

P1 P2 I1 I2 I3 I4 I5 I6 I7 I8 I9 I10 I11 I12 I13 I14 I15 A1 A2 A3 A4 A5 A6 J1 J2 J3 J4 J5 J6 J7 K1 K2 K3 K4 K5 K6 Ku1 Ku2 Ku3 Ku4 Ku5 Ku6 Ku7 Ku8 Ku9 Ku10 Si1 Si2 Si3 Si4 Si5 Si6 Si7 Si8 Si9 Si10 Si11 Si12 Kd1 Kd2 B1 B2 B3 B4 B5 B6

1.35 0.01 0.22 0.04 0.05 0.06 0.06 0.04 0.03 0.05 0.14 0.11 0.45 0.11 0.19 0.15 0.13 0.42 0.23 0.17 0.86 0.49 0.32 0.2 0.2 0.03 0.02 0.03 0.06 0.05 0.06 0.15 0.07 0.12 0.04 0.13 0.68 0.87 0.9 0.78 1.1 0.43 0.58 0.52 0.58 0.43 0.14 0.14 0.45 0.52 0.53 0.64 0.38 0.44 0.48 0.55 0.43 0.29 0.2 0.2 0.35 0.5 0.54 0.24 0.41 0.58

1.9 0.02 57.33 1.04 2.83 2.69 3.54 4.89 2.83 1.89 10.22 5.20 3.94 6.34 58.19 4.24 22.52 1.13 7.21 10.64 14.22 1.27 17.12 52.56 26.32 1.58 1.03 2.67 3.59 2.09 2.00 1.16 0.82 4.28 0.37 1.10 3.72 6.31 5.95 4.86 7.31 2.96 4.95 6.78 6.79 5.22 2.56 3.4 8.97 4.52 3.95 4.6 2.94 5.32 5.19 10.88 13.67 6.98 3.18 2.73 2.69 2.85 3.84 2.07 3.83 3.91

0.01 0.03 3.90 2.02 1.81 0.94 1.14 1.41 0.68 0.58 0.58 1.01 4.07 1.81 0.67 0.49 0.49 0.16 0.23 0.18 0.24 0.21 0.29 4.88 3.18 0.62 0.77 0.71 0.63 0.56 0.16 0.13 0.19 0.37 0.12 0.11 0.46 0.18 0.17 0.24 0.37 0.36 0.41 0.47 0.25 0.18 0.97 2.61 0.51 0.39 2.13 1.01 0.47 0.22 0.21 0.08 0.14 0.19 0.41 0.64 0.19 0.22 0.48 0.42 0.44 0.44

0.42 0.34 0.004 0.037 0.017 0.022 0.017 0.008 0.010 0.026 0.014 0.021 0.103 0.017 0.003 0.034 0.006 0.271 0.031 0.016 0.057 0.278 0.018 0.004 0.008 0.019 0.019 0.011 0.016 0.023 0.029 0.12 0.079 0.027 0.098 0.106 0.15 0.12 0.13 0.14 0.13 0.13 0.1 0.07 0.08 0.08 0.05 0.04 0.05 0.1 0.12 0.12 0.11 0.08 0.08 0.05 0.03 0.04 0.06 0.07 0.12 0.15 0.12 0.1 0.1 0.13

655 100 216 47 64 62 74 69 90 72 130 91 76 85 196 76 187 31 109 113 117 32 143 191 287 77 64 99 110 118 57 115 49 133 45 63 97 106 73 70 91 67 95 134 129 74 65 79 155 93 110 81 69 79 119 185 277 119 91 60 57 60 56 46 53 58

340 463 447 445 448 441 442 443 444 445 446 447 448 450 440 438 440 444 440 447 445 448 441 429 428 428 435 434 435 435 447 432 445 438 443 449 455 455 445 455 448 445 442 440 438 447 440 443 438 440 438 440 444 448 442 440 443 432 437 446 442 440 438 447 448 442

0.29 0.02 26.56 2.23 4.40 4.34 4.76 7.04 3.13 2.61 7.89 5.69 5.17 7.50 29.74 5.57 12.05 3.70 6.63 9.44 12.13 3.98 11.98 27.46 9.16 2.04 1.60 2.69 3.26 1.77 3.49 1.01 1.67 3.21 0.82 1.75 3.85 5.93 8.11 6.98 8.02 4.41 5.21 5.05 5.28 7.08 3.94 4.33 5.79 4.84 3.59 5.7 4.28 6.75 4.35 5.87 4.93 5.89 3.51 4.53 4.68 4.76 6.84 4.49 7.23 6.7

3 150 15 91 41 22 24 20 22 22 7 18 79 24 2 9 4 4 3 2 2 5 2 18 35 30 48 26 19 32 5 13 11 12 15 6 12 3 2 3 5 8 8 9 5 3 25 60 9 8 59 18 11 3 5 1 3 3 7 8 4 5 7 9 6 7

e 1.17 0.89 0.85 0.90 0.78 0.80 0.81 0.83 0.85 0.87 0.89 0.90 0.94 0.76 0.72 0.76 0.83 0.76 0.89 0.85 0.90 0.78 0.56 0.54 0.54 0.67 0.65 0.67 0.67 0.89 0.62 0.85 0.72 0.81 0.92 1.03 1.03 0.85 1.03 0.90 0.85 0.80 0.76 0.72 0.89 0.76 0.81 0.72 0.76 0.72 0.76 0.83 0.90 0.80 0.76 0.81 0.62 0.71 0.87 0.80 0.76 0.72 0.89 0.90 0.80

e e e 0.43 0.36 0.31 0.19 0.28 0.11 0.18 0.00 0.03 0.21 0.10 e 0.15 e 0.70 0.02 0.01 0.05 0.59 0.01 e e 0.17 0.23 0.03 0.07 0.01 0.19 0.13 0.52 0.01 0.53 0.44 0.17 0.13 0.19 0.30 0.12 0.34 0.10 0.06 0.07 0.18 0.21 0.06 0.04 0.15 0.11 0.13 0.23 0.19 0.08 e e 0.05 0.07 0.24 0.33 0.16 0.23 0.41 0.22 0.24

e e e 2.29 4.53 4.44 4.83 7.19 3.16 2.64 7.90 5.70 5.23 7.56 e 5.62 e 3.89 6.64 9.45 12.15 4.09 12.00 e e 2.07 1.63 2.70 3.28 1.77 3.53 1.01 1.74 3.21 0.85 1.81 3.87 5.94 8.16 7.09 8.03 4.50 5.22 5.05 5.28 7.14 3.99 4.34 5.80 4.87 3.59 5.71 4.33 6.82 4.36 e e 5.91 3.52 4.59 4.76 4.77 6.89 4.59 7.29 6.76

e e e 81 97 88 90 94 100 87 130 94 96 94 e 88 e 99 111 114 123 75 145 e e 92 82 101 117 119 69 131 97 134 92 108 117 121 90 99 104 100 105 142 138 89 81 84 161 108 123 92 89 96 129 e e 125 98 78 83 71 72 76 67 76

Explanations- SN: Sample number; S1: free hydrocarbons present in the rock (mg HC/g of rock); S2: remaining generation potential (mg HC/g of rock); S3: oxidizable carbon, (mg CO2/g rock); PI: production index denoting ratio of free hydrocarbons to total hydrocarbons [S1/(S1 þ S2)]; HI: hydrogen Index, [(S2/TOC)  100 mg HC/g TOC]; Tmax: maturity parameter based on the temperature at which the maximum amount of pyrolyzate (S2) is generated from the kerogen in a rock sample; TOC(wt %): total organic carbon; OI: oxygen index [(S3/TOC)  100 mg CO2/g TOC]; VRo*: estimated vitrinite reflectance (%) from Tmax value of rock eval pyrolysis; f: factor of conversion of organic matter; TOCO: original TOC content of the samples; HIO: original HI content of the samples.

A.K. Varma et al. / Marine and Petroleum Geology 59 (2015) 480e490

485

Figure 2. Vertical column plot showing depth (m), TOC content (wt %), hydrocarbons released under S2 curve (mg HC/g rock), hydrogen index (mg HC/g TOC) and Tmax ( C) values of the studied samples.

(Si) area of Raniganj basin, Barren Measures Formation with thickness varying between 375 and 475 m is overlain by a 5e20 m thick soil-weathered mantle or Raniganj Formation (occasionally) and underlain by Barakar Formation. TOC content of the shales from this region (Si1eSi12) varies between 3.59e6.75 wt %. Only one sample (Si1) is marked by ‘poor’ GP (<3 mg HC/g rock) and one by ‘very good’ GP (>12 mg HC/g rock), while others have ‘fair’ to ‘good’ GP. Tmax values of the samples vary between 432 and 448  C placing them in the early to peak mature stage and estimated vitrinite reflectance oil window (VRo ¼ 0.62e0.90%). Seven out of the twelve Barren Measures shales from Sitarampur (Si) have OI < 10 mg CO2/g TOC (Table 3). In Kulti (Ku) area, Barren Measures Formation occurs in between a depth interval of 150e175 m to 750e775 m and is generally overlain by fine grained sandstone with shale lamellae of Raniganj Formation. The greater depth and thickness of the Formation in this part of the basin makes it more favorable for shale gas exploration. Barring one sample (Ku1, TOC ¼ 3.85 wt %) all the samples from this part of the basin have ‘excellent’ TOC content (Table 3) and the GP being ‘fair’ to ‘good’. In general the Barren Measures shales from Kulti (Ku) have higher Tmax values than those from Sitarampur (Si). Samples Ku1, Ku2 and Ku4 show maximum Tmax values (455  C) placing them in the late mature stage and hence within the condensate wet gas window with the rest falling in early to peak mature stage and estimated vitrinite reflectance oil window. Moreover, HI values of all the samples falls within the range of HI values of type III organic matter (gas prone, 50e200 mg HC/g TOC). Thus the slightly higher Tmax values (maturity), thickness, depth and organic matter type makes the Barren Measures shale in Kulti

(Ku) area an interesting prospect for shale gas exploration. All the samples are marked by very low OI value. The two borehole shale samples of Barren Measures Formation (Kd1 and Kd2) from Kuldiha (K) area are from the same borehole from which the samples K1eK6 belonging to Raniganj Formation were taken. The Tmax values of the samples (437 and 446  C) appear to be lower with respect to their depth compared to the samples from Sitarampur (Si) and Kulti (Ku). The HI vs OI pseudo van Krevelen diagram (Fig. 3) and hydrocarbons released under S2 curve vs TOC plot (Fig. 4) also shows input of dominantly type III organic matter for the Barren Measures shales. No clear relation between HI and Tmax was observed as in case of Raniganj Formation shales. In HI vs TOC plot (Fig. 5), the shales from this formation are placed in good/fair oil source and gas and/or oil source fields. Barring the samples from Kuldiha (K) area all the samples display a positive good fit between PI and depth (Fig. 6). These two samples (Kd1 and Kd2) show lower PI values (0.06 and 0.07) with respect to their depth compared to the samples from Sitarampur (Si) and Kulti (Ku) areas. The respectively higher PI and Tmax values of the samples from Sitarampur (Si) and Kulti (Ku) of the western part compared to the samples from Kuldiha (K) area of eastern part of the basin (with respect to depth) may be due to the effects of intrusion of dykes and sills in Sitarampur (Si) and Kulti (Ku) areas as indicated in the map. The Salma dolerite dyke (Fig. 1) which marks a relatively long-lived basement high trending NNWeSSE in the central part of the Raniganj basin situated to the east of Asansol town (central western part) (Ghosh, 2002) along with lamprophyres might have resulted in partial cooking of the shales from Sitarampur (Si) and Kulti (Ku) areas

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Figure 3. Relation between hydrogen index (HI; mg HC/g TOC) and oxygen index (OI; mg CO2/g TOC) of shales from Barakar, Barren Measures and Raniganj Formations following
et al., 1985 and Kotarba et al., 2002. Espitalie

Figure 4. Relation between hydrocarbons released under S2 curve (mg HC/g rock) and TOC (wt %) of shales from Barakar, Barren Measures and Raniganj Formations (modified after Langford and Blanc-Valleron, 1990).

resulting in slightly higher maturities. In contrast no intrusions have been reported from Kuldiha (K) area.

4.1.3. Barakar Formation shales (Lower Permian) The six samples analyzed from Barakar Formation, all have ‘excellent’ TOC content (>4 wt %). The GP of the samples varies between 2.31 (B4) to 4.49 mg HC/g rock (samples B1eB3, B5, B6). Tmax values of Barakar Formation samples vary between 438 and 448  C and hence fall in the early to peak mature stage. The estimated VRo thus varies between 0.72 and 0.90% and hence falls in the oil window. Similar to most of the Raniganj Formation and Barren Measures Formation shales here also kerogen is within the oil window and is capable of generating oil and thermogenic gas upon thermal cracking (Gentzis, 2013). Oxygen index values of the samples are very low and ranges between 4 and 9 mg CO2/g TOC and the same reason as discussed under ‘Raniganj Formation shales’ is also considered here. HI values of the studied samples vary between 46 and 60 mg HC/g TOC and hence indicates input of dominantly type III organic matter. Based on the HI and OI values,

the pseudo-van Krevelen diagram (Fig. 3) for these samples (along with the samples from other formations) have been constructed and also indicate input of type III organic matter. HI vs TOC plot (Fig. 5) indicates that all the samples fall in the gas and/or oil field. 4.2. Micropetrographic analysis The total amount of macerals show a high, positive correlation with TOC content and hydrocarbons released under S2 curve (Fig. 7). Considering S2 as a property dependent among the type of organic matter present in a sample (which is ultimately controlling the HI value), a linear regression analysis was performed between S2 and organic matter (vitrinite, inertinite and liptinite) to determine the role of macerals in hydrocarbon generation. The regression equation determined is as follows:

S2 ¼ 3:01 þ 1:06V þ 0:116I þ 3:67L

(2)

where V ¼ vitrinite macerals; I ¼ inertinite macerals; L ¼ liptinite macerals. The equation indicates stronger role of vitrinite and

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487

Figure 5. Relation between HI (mg HC/g TOC) and TOC (wt %) content of shales from Barakar, Barren Measures and Raniganj Formations (in the diagram of Jackson et al., 1985).

Figure 6. Relation between PI (production index) and depth of shales of Barren Measures Formation from Kulti (Ku) and Sitarampur (Si) areas.

liptinite macerals and weaker role of inertinite macerals on hydrocarbons released under S2 curve of rock eval pyrolysis for the studied samples. Inertinite group of macerals were initially thought to be largely infusible during technological processes (Stach 1952) and their behavior and reactivity were studied by various scientists. Ammosov et al. (1957) and Schapiro et al. (1961) indicated that 30 vol. % of semifusinite macerals are reactive while 70 vol. % are inert and observed that semifusinites having slightly higher reflectance than vitrinite would be reactive. Okuyama et al. (1970), Nandi and Montgomery (1975), Mackowsky (1977), Duguid (1980), Diessel (1983) and Ko^sina and Heppner (1985), indicated that a substantial portion of inertinite may be reactive. Rentel (1987), Lamberson and Bustin (1993), and Varma (1996, 2002) exhibited significance of microlithotypes (association of macerals) in reactivity of inertinites. Martinez et al., (2000) through a kinetic study found out that gaseous hydrocarbons can be generated from easily transformed fraction of reactive inertinite.

4.2.1. Determination of fraction of conversion of organic matter Maceral analysis using point counting method was used to determine the abundance of each maceral type (vol. %) and the data were then converted to mineral matter free basis. The original hydrogen index of the samples were calculated applying Equation (3) (following Jarvie et al., 2007),

HIO ¼

ð%type I  750Þ ð%type II  450Þ ð%type III  125Þ þ þ 100 100 100 ð%type IV  50Þ þ 100 (3)

where HIO connotes original hydrogen index of the samples; type I, type II, type III and type IV indicate respective kerogen types. As no type I organic matter was identified in the studied shale samples, the equation thus became:

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Figure 7. Plot showing relationship between maceral content (vol. %), TOC content (wt %) and hydrocarbons released under S2 curve (mg HC/g rock).

 HIO ¼

%Lmmf  450 100



 þ

%Vmmf  125 100

 þ

  %Immf  50 100

(4)

where Lmmf, Vmmf and Immf are volume percentages of liptinite, vitrinite and inertinite on mineral matter free basis. The determined HIO was then used to calculate the fraction (f) of conversion of organic matter applying the following equation:

f ¼1

HIf1200  ½HIO =ð1  PIO Þg HIO f1200  ½HI=ð1  PIPD Þg

(5)

where PIO and PIPD are production index original and present day respectively. PIO can be assumed to be 0.02 (Peters et al., 2005) for calculation purposes. Following Peters et al., 2005, original TOC (TOCO) content of the samples was calculated using the following equation:

TOCO ¼

83:33ðHIÞTOC ½HIO ð1  f Þð83:33  TOCÞ þ HIðTOCÞ

4.2.2. Shale gas plays A shale horizon can become a shale gas resource depending on: a) organic matter abundance, type and maturity; b) porosityepermeability relationship; c) pore size distribution; d) brittleness; e) and their relationship to mineralogy and rock fabric (Josh et al., 2012). In this paper only the first requisite (for a shale horizon to become shale gas resource) has been studied for shales from different Formations in various parts of the Raniganj basin. The Raniganj and Barakar Formation shales sampled from eastern and western part of the basin respectively have desired maturities (within estimated vitrinite reflectance oil window) and TOC content to generate hydrocarbons. Earlier Hackley et al. (2009) observed onset of thermogenic gas generation in Middlee Upper Pennsylvanian (Late Carboniferous) coal and carbonaceous shale samples with type III organic matter which had estimated Ro values of 0.50e0.80%. That Ro values ranging between 0.50 and 0.60 % indicate the onset of thermogenic gas generation, is accepted by several workers (Rice, 1993; Hunt, 1996; Tang et al., 1996), while values of 1.00e1.20% or greater are considered for peak gas generation (Tissot and Welte, 1984; Michael et al., 1993; Tang et al., 1996). In terms of TOC content, maturity and GP, the Raniganj Formation shales from Icchapur area have greater potential in terms of successful shale gas plays. Though borehole data indicates presence of thick black shale horizons belonging to Barakar Formation in Sitarampur and Kulti areas, no data exists regarding thickness of Raniganj Formation shale horizons. Slatt and Rodriguez (2012) observed that productive gas shales are usually >200 ft (65 m) thick with TOC content being greater than 3 wt % and having hydrogen index values >350 mg HC/g TOC, containing type II kerogen and having organic maturity values >1.10% Ro. The black shales of Barren Measures Formation from Kulti (Ku) and Sitarampur (Si) areas in western part of the Raniganj basin have thickness varying between 300 and 600 m and TOC content >3 wt % which makes this formation a target for shale gas assessment. Moreover organic petrography and rock eval pyrolysis values indicate that the generated hydrocarbons from these shales would be gas prone. The greater depth and generally higher maturity of these shales from Kulti area makes this area more attractive. In eastern part of the basin the Barren Measures shales occur at greater depths and likely to be more matured (data unavailable) and hence may be important for shale gas plays. However, more detailed analysis in terms of their porosity, permeability, gas in place estimates, methane sorption capacity and brittleness needs to be carried out. Defining lateral distribution of individual shale beds and their net thickness in the subsurface through detailed log correlation-stratigraphic studies are essential for delineating prospective horizons. Unlike conventional reservoirs where gas is primarily stored as compressed gas in pores and fractures, a major portion of gas in shales are stored as sorbed gas. The mineral composition of the shale gas reservoir has important effects on the storage and development of shale gas.

(v)

For samples I1, I13, I15, Ji, J2, Si10 and Si11the calculated HI values (HIO) are lower than present day HI values. Peters (1986) earlier observed that some coals originally characterized by input of type III organic matter showed an unusually high potential of petroleum generation, due to reasons not fully understood. Reasons for such anomalous observations may be due to presence of some hydrogen-rich material as very fine-grained submicroscopic particles including per-hydrous vitrinites (Taylor, 1996; Bertrand et al., 1986) as well as due to presence of inertinites having thermally unstable bonds and showing high fluidity caused by their depolymerization (Ko^sina and Heppner, 1985).

5. Conclusions i. In general the shales from Barakar, Barren Measures and Raniganj Formation are marked by input of dominantly type III organic matter, ‘good’ to ‘excellent’ TOC content with majority of them being placed within the estimated vitrinite reflectance oil window and is capable of generating oil and thermogenic gas upon thermal cracking. The shales of Barren Measures Formation may be a horizon of interest for shale gas exploration. Igneous intrusion of dykes and sills in the Formations occurring in and around the areas of Sitarampur (Si) and Kulti (Ku) might have resulted in cooking of the shales, increasing their

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maturities as indicated by the Barren Measures shales of shallow depths from the above mentioned areas. Shale formations in proximity to the NNWeSSE trending Salma dyke in the central portion of the Raniganj basin may be potential sites for shale gas exploration. ii. The conceptual HI lines from the logarithmic plot of TOC and hydrocarbons released under S2 curve may be important as along a particular HI line all points will have same HI value. iii .The regression analysis between S2 (remaining hydrocarbon generation potential under rock eval pyrolysis) and organic matter indicates stronger role of vitrinite and liptinite macerals and a weaker role of inertinite macerals on hydrocarbons released under S2 curve of rock eval pyrolysis for the studied samples. However inertinite macerals can have positive effects on hydrocarbon generation as they may be reactive depending upon their composition, thermal stability bonds and associations with reactive macerals. Acknowledgment Authors thank the Head, Keshava Deva Malaviya Institute of Petroleum Exploration, Oil and Natural Gas Corporation Limited, Dehradun, India for helping them in analysis of Rock Eval Pyrolysis and TOC of the studied shale samples. The authors are indebted to the European Commission for providing research project (CO2 Geological Storage: Research into Monitoring and Verification Technology; Project acronym: CO2 ReMoVe; Proposal/contract no.: 518350) to carry out research works at Coal Geology and Organic Petrology Lab, Department of Applied Geology, Indian School of Mines, Dhanbad. Appendix A. Supplementary data Supplementary data related to this article can be found at http:// dx.doi.org/10.1016/j.marpetgeo.2014.10.003. References Ammosov, I.I., Eremin, I.V., Suchenko, S.I., Oshurkova, I.S., 1957. Calculation of coking charges on the basis of petrographic characteristics of coals. Koks Khim. 12, 9e12 (In Russian).
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