Depositional environment and hydrocarbon source ... - umexpert

International Journal of Coal Geology 90–91 (2012) 162–179

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Depositional environment and hydrocarbon source potential of the Permian Gondwana coals from the Barapukuria Basin, Northwest Bangladesh Md. Farhaduzzaman a,⁎, Wan Hasiah Abdullah a, 1, Md. Aminul Islam b, 2 a b

Department of Geology, Faculty of Science, University of Malaya, 50603 Kuala Lumpur, Malaysia Department of Petroleum Geoscience, Faculty of Science, Universiti Brunei Darussalam, Gadong BE1410, Brunei

a r t i c l e

i n f o

Article history: Received 20 June 2011 Received in revised form 10 December 2011 Accepted 15 December 2011 Available online 29 December 2011 Keywords: Gondwana coal Depositional environment Hydrocarbon potential Biomarker Thermal maturity Kerogen type

a b s t r a c t Barapukuria Coal Basin is situated in Dinajpur district of the northwestern part of Bangladesh. A total of eight coal samples have been collected from two different locations of the basin and analyzed using organic geochemical and organic petrological methods. The extracted organic matter of the studied samples is a mixture of Type-III and Type-II kerogen as evaluated by the source rock analyzer (SRA) and PyGC pyrograms. The measured total organic carbon (TOC) ranges from 61 to 74 wt. % and the recovered extractable organic matter (EOM) varies from 27,561 to 41,389 ppm. These results suggest that the coals are ranked as good quality source rock. The hydrocarbon yield has been calculated which is also high and it ranges from 12,192 to 20,799 ppm. The organic matter is thermally mature for hydrocarbon generation considering their Tmax and measured mean vitrinite reflectance values of 431 to 435 °C and 0.72 to 0.81%Ro respectively. The hopane 22S/(22S + 22R), moretane/ hopane ratio and sterane parameters are also in support of these thermal maturity assessment. The maceral composition is dominated by the inertinite group with significant amounts of vitrinite and liptinite. The more dominant odd carbon numbered n-alkanes, high Pr/Ph ratio (4–8), high Tm/Ts ratio (13–18), predominant sterane C29 (i.e., C29 > C28 > C27) and Pr/nC17 – Ph/nC18 values, GI vs TPI cross-plot and dominance of inertinite macerals group clearly demonstrate that the organic matter has been derived from terrestrial inputs and the condition of deposition was oxic (i.e., dry forest swamp) which was also supported by the absence of alginite. It is most likely that the coals were deposited within a peat-swamp flood basin environmental setting. © 2011 Elsevier B.V. All rights reserved.

1. Introduction The aim of the present study is to interpret the depositional environment of the Permian Gondwana coals of the Barapukuria basin on the basis of biomarker distributions together with other organic geochemical and organic petrological methods. So far no record of working detail on depositional environment considering the organic geochemical and organic petrological approach have been published on the Permian Gondwana coals of Bangladesh although there are few publications on Gondwana coals of Bangladesh. Bostick et al. (1991) discussed on petrography of the Barapukuria coal. Akhtar and Kosanke (2000) published on Palynology of Permian Gondwana

⁎ Corresponding author. Tel.: + 60 149248160; fax: + 60 379675149. E-mail addresses: [email protected], [email protected] (M. Farhaduzzaman), [email protected] (W.H. Abdullah), [email protected], [email protected] (M.A. Islam). 1 Tel.: + 60 379674232; fax: + 60 379675149. 2 Tel.: + 673 2463001x1371; fax: + 673 2463051. 0166-5162/$ – see front matter © 2011 Elsevier B.V. All rights reserved. doi:10.1016/j.coal.2011.12.006

coals of Barapukuria. Shamsuddin et al. (2001) discussed on the source rock potentiality of Gondwana coals of Bangladesh as a partial study on Petroleum Systems of Bangladesh. Islam and Kamruzaman (2006) studied on inorganic geochemistry and techno-environmental issues related to mining and uses of Barapukuria coal of Bangladesh. Islam and Hossain (2006) worked on the lithofacies and Embedded Markov Chain analysis of Gondwana sequence of Barapukuria coal basin, Bangladesh. Farhaduzzaman et al. (2008) published on properties (e.g., moisture, ash, volatile matter, fixed carbon, calorific value, sulfur, etc.) of Gondwana coals of Bangladesh. Islam and Hayashi (2008) published on geology and coal bed methane resource potential of the Gondwana Barapukuria coal basin, Dinajpur, Bangladesh. Frielingsdorf et al. (2008) presented a paper on tectonic subsidence modeling and hydrocarbon potential from a structural point of view based on the wells located in the Northwest Bangladesh considering thermal and maturity modeling. The depositional environment is the focus of the present study emphasizing the biomarker characteristics of the Permian coals of Barapukuria and this study will certainly add further important information to the understanding of the condition of depositional settings related to the coals of the Bengal basin.

M. Farhaduzzaman et al. / International Journal of Coal Geology 90–91 (2012) 162–179

2. Geological background of the study area Bangladesh lies in the northeastern corner of the Indian subcontinent at the head of the Bay of Bengal. The Bengal Basin (Fig. 1) includes, in addition to Bangladesh, part of the Indian state of West Bengal in the west and Tripura in the east. Barapukuria coal deposit was discovered at Dinajpur (Figs. 1 and 2) district in 1985 by Geological Survey of Bangladesh (GSB). Barapukuria Coal Mining Company Limited (a company of Petrobangla) has started its coal production using the underground mining method (Longwall slicing) since March 2007. Tectonically the Bengal Basin has evolved from collision of the Indian plate and the Asian plate. The Barapukuria is located on the Rangpur Saddle of Platform area of Bengal basin (Fig. 1). The sediment thickness is shallower (e.g., approximately 125 m at Maddhapara granite mine) in western Platform area while it is thicker (approximately 20 km) in the eastern deep basinal part of Bengal basin (Alam et al., 2003; Guha, 1978; Imam, 2005; Khan, 1991; Reimann, 1993; Shamsuddin et al., 2004). The Barapukuria structure is a north–south elongated coal bearing graben basin bounded by a major N–S oriented eastern boundary fault. The Gondwana sedimentary succession within the basin forms a singular asymmetric synclinal fold with axis running in direction of about N10˚W. The axial plane is dipping towards the east. Stratigraphically the Barapukuria basin includes the formations

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consisting of four different ages namely Archaean, Permian, Tertiary and Quaternary (Fig. 4) representing Basement Complex, Gondwana Group, Dupi Tila Formation and Barind Clay (Madhupur Clay) Formation respectively whereas the coal deposit is found within the Gondwana Group (Farhaduzzaman et al., 2008; Islam and Hayashi, 2008; Islam and Hossain, 2006; Islam and Islam, 2005; Islam and Kamruzaman, 2006; Wardell, 1991). This sedimentary basin lies above the basement complex within which Permian age formations preserved by down faulting and subsequently infilled with unconsolidated Tertiary and Quaternary sediments. The estimated coal reserve of Barapukuria basin has been approximated 390 million tons (mostly seam VI—approximately 90%) having coal top at depth of 118–509 m covering six different layers (seam VI alone represents 36 m). The following constituents have been measured (Islam and Hayashi, 2008; Wardell, 1991): • • • • • • •

Moisture—10%, Ash—12.4%, Volatile matter—29.2%, Fixed carbon—48.4%, Sulfur—0.53%, Calorific value—10,450 BTU/lbs (6604 kcal/kg), and Rank—high volatile bituminous.

Fig. 1. Location map of the study area (Barapukuria coal basin) showing the tectonic elements and physiographic divisions of Bengal Basin (modified after Guha, 1978; Khan, 1991; Reimann, 1993; Imam, 2005; Shamsuddin et al., 2004).

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Fig. 2. Map showing the occurrence of Gondwana basins in the vicinity of Barapukuria coal deposit (modified after Uddin and Islam, 1992; Imam, 2005; Islam and Hayashi, 2008).

3. Experimental A total of eight coal samples were collected directly from the Barapukuria underground coal mine which is presently extracting the coal using multi-slicing method. Two different parts of the basin were selected for sample collection. Four samples have been chosen from the central northwestern part (depth ranges from 305 m to 315 m) of the basin and the remaining four have been taken from the central southeastern part (depth ranges from 360 m to 366 m) (Fig. 3). All samples belong to coal seam VI (Fig. 4). The collected samples have been crushed into fine powder and have been analyzed using Source Rock Analyzer (SRA-Weatherford)-TOC/TPH (equivalent of Rock-Eval equipment). Bitumen extraction has also been performed on approximately 15 g of the powdered samples using Soxhlet apparatus with an azeotropic mixture of dichloromethane (DCM) and methanol (CH3OH) (93:7) for 72 h. The extracts (EOM) have been separated by means of column liquid chromatography into aliphatic, aromatic and polar fractions using petroleum ether, DCM and CH3OH respectively. The aliphatic hydrocarbon fractions have been analyzed subsequently by gas chromatography (Agilent 6890 N Series GC) and gas chromatography mass spectrometry (GCMS). A FID gas chromatograph with HP-5MS column, temperature programmed from 40 to 300 °C at a rate of 4 °C/min and then held for

30 min at 300 °C, has been used for GC analysis. GCMS experiments have been performed on a V 5975B inert MSD mass spectrometer with a gas chromatograph attached directly to the ion source (70 eV ionization voltage, 100 mA filament emission current, 230 °C interface temperature). The fingerprints acquired from GC and GCMS analysis have been used for biomarker identification. For petrographic study, the samples have been prepared by mounting whole rock fragments in slow setting polyester (serifix) resin together with resin hardener and allowed to set, then ground flat on a diamond lap and subsequently polished using water lubricated silicon carbide paper of different grades (P800, P2400 and P4000). Finally, the samples were polished to a highly reflecting surface using progressively finer alumina suspension (1 μm, 0.3 μm and 0.05 μm). Petrographic examination has been carried out under oil immersion in plane polarised reflected light, using a LEICA DM6000M microscope and LEICA CTR6000 photometry system equipped with fluorescence illuminators. The filter system consists of BP 340–380 excitation filters, a RKP 400 dichromatic mirror and a LP425 suppression filter. Maceral compositions, based on a 1000 point count, have been determined under both normal reflected ‘white’ light and UV (ultraviolet) light. Random vitrinite reflectance measurements in oil immersion (%Ro) have been carried out in reflected ‘white’ light using the windowsbased DISKUS Fossil/Maceral software package.


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lower than normally expected based on the atomic O/C. At higher levels of maturity, proportionally more pyrolytic oxygen is released as carbon monoxide which is not analyzed by the SRA or Rock-Eval equipment. The recorded OI values of the samples analyzed in this study are very low (Table 1) and these can be caused by the inadequate detection by the thermal conductivity detector (TCD) of CO generation during pyrolysis of this high maturity coals as previously reported by Peters (1986), Hunt (1991) and Bordenave and Durand (1993) or may be related to different types of organic matter (e.g., Koeverden et al., 2011). Tmax values have been found to be very close to each other and ranges from 431 to 435 °C. These Tmax values correspond to initially matured oil window which is in good agreement with the mean vitrinite reflectance (%Ro = 0.72 to 0.81) data.

Fig.4(a)

Fig.4(b)

Fig. 3. Sample locations in the study area of Barapukuria basin, Bangladesh; the generalized stratigraphic columns are shown in Fig. 4.

4. Results and discussion 4.1. Source rock properties The Source Rock Analyzer (SRA) results have been shown in Table 1. The good quality source rock potential of the studied coal samples have been deduced based on the classification proposed by Peters and Cassa (1994) (Fig. 5). It is interesting to note their good potential although these coals are rich in inertinite thus this would require further study. The hydrocarbon generation potential of coals were discussed by different workers elsewhere worldwide, e.g., Vinchet et al. (1985), Thompson et al. (1985), Philp and Gilbert (1986), Littke et al. (1989), Hunt (1991), Wan Hasiah (1999) and Semkiwa et al. (2003). The discussion for the samples under current investigation has been dealt in Section 4.5. The recorded TOC value ranges from 61.14 to 72.84 (wt.%) based on this study. HI varies from 285 to 326 mg HC/g TOC and it shows modest variations which implies a mixture of kerogen types (III/II) of organic matter (Fig. 6). Peters (1986) showed that the coals of low maturity (%Ro less than 0.6%) generate large amounts of CO2 during pyrolysis and OI values are generally consistent with the corresponding atomic O/ C. However, some mature coals showed unusually low OI with values

4.2. Macerals composition and kerogen type Coal petrographic study has been carried out to evaluate the evolutionary history of the analyzed coals. The macerals, microlithotypes and the lithotypes provide the evidence on the nature and type of plant community, intensity and duration of humification and the type of depositional milieu. In addition, they provide a basis for the interpretation of paleogeography and paleoclimate of the peat forming basins (Singh and Sukhla, 2004; Stach et al., 1982; Teichmuller, 1989). Hence the depositional environment has been described based on the macerals composition together with the biomarker characteristics. In the studied samples, inertinite is the most dominant maceral group and followed by vitrinite and liptinite. These coal samples also contain a considerable amount of mineral matter (Table 2 and Fig. 7). Semifusinite, inertodetrinite and fusinite are the dominant inertinite macerals in the analyzed coal samples. Telocollinite, vitrodetrinite and telinite are the most common vitrinite macerals whilst cutinite, sporinite, liptodetrinite and bituminite are the most common liptinite macerals. These liptinite macerals display distinct fluorescence as described in Fig. 8B and C. These liptinite macerals contribute to the oil-prone nature of these coals which is further enhanced by the occurrence of perhydrous vitrinite and bituminite/ solid bitumen (Fig. 8). However alginite has not been observed in the studied samples thus ruled out a limnic depositional setting. Dembicki (2009) stated that in addition to other (e.g., Rock-Eval) geochemical data, PyGC provides a good solution to interpret kerogen mixtures as it shows a direct indication of hydrocarbon types that can be generated by the kerogen during maturation process as previously stated by earlier workers, e.g., Giraud (1970), Larter and Douglas (1980) and Dembicki et al. (1983). The >C15 fraction would be the least amount and bC10 fraction would be the highest abundance shown in the PyGC traces for the organic matter containing Type-III kerogens. In case of Type I kerogens, it would be the reversed situation, i.e., highest >C15 fraction and least bC10 fraction. The intermediate one represents Type-II kerogens (Dembicki, 2009). Following these discussions, the mixed kerogen (Type–III/II) fingerprints of predominantly n-alkane/alkene doublets and aromatic compounds have been displayed by the whole rock PyGC pyrograms (Fig. 9) where these traces show neither the typical signatures of Type-II nor Type-III, rather they show the intermediate signatures of these two. It is known that typeIII kerogen is composed mainly of vitrinite macerals with considerable amounts of inertinites. On the other hand, Type-II kerogen is composed mainly of liptinite macerals with considerable amounts of vitrinite macerals. Since PyGC indicates that the organic matter is a mixture of kerogens, the observed PyGC traces readily correspond to the dominance of inertinite macerals mixed with considerable amounts of vitrinite and liptinites in the coal samples. The relative abundance of aliphatic to aromatic hydrocarbons may be quantified by the ratio of n-octene (C8) to (m+ p)-xylene. The calculated C8/xylene ratio is low which ranges from 0.73 to 0.89. The analyzed samples show high abundance of aromatic hydrocarbons (e.g., benzene, toluene, xylene etc.) relative to the n-alkanes/alkenes (i.e., low C8/xylene ratio) in the pyrograms and it


Lithology 0

A

Lithology

Formation name & description

Age

B BARIND CLAY (MADHUPUR CLAY) Silty to sandy high plasticity clay with ferruginous nodules. Red-brown to yellowish-brown.

10 20

UPPER DUPI TILA Micaceous quartz sand and gravel, cobbly basal unit. Alternating yellow-brown and grey.

30

Pleistocene Un co n fo rm i t y

166

40 50

Pliocene

60 70 120 130 140 150 LOWER DUPI TILA Firm light grey & white cleyey sand and keolinitic clay.

160 170

Depth (m)

190

Seam I Seam II

Late Miocene to Pliocene

Seam III

200

Seam IV

210

Seam V

Seam I

220

Seam II

230

Seam III

240

Seam IV

250

Seam V

UPPER COALS SEQUENCE Feldspathic sandstones with some thin black coal layers (Seams I, II, III, IV & V) and occasional beds of siltstone & mudstone.

Un co n fo rm i t y

180

260 270 280 SEAM VI SANDSTONE SEQUENCE Coarse grained sandstones, gritstones & conglomerates with the thickest black coal seam VI.

290

Gondwana

300 310 320 330 340 350

Coal sampling locations. Base not seen

360 370

LOWER SANDSTONE SEQUENCE Interbanded sandstones, siltstones & mudstones with the thin black coal bands.

380 390

ARCHAEAN BASEMENT Veined gneissic metamorphic & metaigneous rocks.

Precambrian

Base not seen

Fig. 4. Generalized lithostratigraphic columns show sampling locations [(A) represents the central northwestern part of basin while (B) represents central southeastern part of the basin] of the Barapukuria coal basin, Bangladesh.]; Column locations are shown in Fig. 3.


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Table 1 Source rock analyzer (of Rock-Eval equivalent) parameters and vitrinite reflectane data of the analyzed coal samples (refer to Appendix A). Sample

Depth (m)

TOC

Ro

Tmax

S1

S2

S3

HI

OI

PI

PP

S1/TOC

BP6CL1 BP6CL2 BP6CL3 BP6CL4 BP6CL5 BP6CL6 BP6CL7 BP6CL8

305 308 312 315 360 362 366 364

62.45 61.14 73.47 74.03 65.63 68.92 72.84 70.72

0.72 0.73 0.80 0.75 0.80 0.78 0.81 0.80

431.1 432.7 431.3 434.9 433.2 432.9 434.8 433.7

2.57 2.47 2.91 5.10 2.81 2.76 4.63 2.92

202.26 174.03 232.47 207.06 203.78 226.96 210.72 230.53

0.53 0.78 0.93 0.79 0.68 0.92 0.81 0.73

324 285 316 280 311 329 289 326

0.85 1.28 1.22 1.07 1.04 1.33 1.11 1.03

0.01 0.01 0.01 0.02 0.01 0.01 0.02 0.01

204.83 176.50 235.38 212.16 206.59 229.72 215.35 233.45

0.04 0.04 0.04 0.07 0.04 0.04 0.06 0.04

1000

Excellent C Very good

O

900 Type I

Ro = 0.62%

800

700

600

Type II

500

Ro = 0.88%

Type II-III

400

Condensate-wet gas window

Type III-II

300

Good Fair

A

Poor

L

Good

Fair

Poor

or

Po

1

Dry gas window

Type III Post-mature

1

0.1 0.1

Ro = 1.1%

200

Excellent

10

Very good

S2 (mg HC/g rock)

100

t

en

ell

c Ex

1000

Mature (oil window)

The aliphatic fractions of the coal samples have been subjected to GC and GCMS analyses. The TIC (total ion current), m/z 191 and m/z 217 chromatograms (i.e., the most two common fragment ions) have been used for this study and two representative samples have been displayed in Figs. 10 and 11. The peaks of these traces have been identified on the basis of retention times and available literature (e.g., Ahmed et al., 2009; Hakimi et al., 2010, 2011; Kashirtsev et al., 2010; Koeverden et al., 2011; Monika Fabianska and Kruszewska, 2003; Wan Hasiah, 1999; Waples and Machihara, 1991). The identified peaks and other used terminology have been listed in Appendices A and B. The bimodal distributions of n-alkanes from C11 to C35 with the maxima at C23 and C30 have been observed in the gas chromatograms of the analyzed coal samples which suggest the dominance of higher plant input. Han and Kruge (1999) stated that the humic coals show the enrichment of n-alkanes in the range of C16–C26 (as observed in the studied coals) while the sapropelic coals show the dominance of shorter chain n-alkanes (bC20). However, the low molecular weight n-alkanes occur in low abundance probably because either of its humic nature or evaporation losses during fractionation. The TIC fingerprints show the dominancy of low to medium member hydrocarbons corresponding to gas/condensate generation. Odd carbon numbered n-alkanes are more dominant compared to those of even carbon numbers. The ratio of pristane to phytane is higher and it ranges from 4.05 to 7.73. The calculated CPI 2 values are close to

Immature

4.3. Biomarker distributions

unity (1.00–1.09) while CPI 1 is from 1.19 to 1.58 (Tables 3 and 4). These CPI values >1 would be expected as the coals predominantly consist of terrestrially derived higher plant materials. Abundant pentacyclic triterpanes (hopanes and moretanes) have been observed in the m/z 191 fragmentograms (Figs. 10 and 11). Their distribution is dominated by the C30 hopane. C31-hopane is the most dominant amongst the homohopanes while moretanes are also present as considerable amounts. The αβ-hopanes are more prominent than the βα-hopanes while the S-isomers are more dominant than the R-isomers among the homohopanes (C31–C35) and it clearly indicates that the samples are thermally mature for hydrocarbon generation. Tm and Ts are well known to be influenced by both maturation and organic matter type (e.g., Peters et al., 2005a, 2005b). The Tm/Ts ratio of the studied samples is high which is indicative of organic matter containing high terrestrial input. The calculated ratios of Tm/Ts, Ts/(Ts+ Tm), C30 moretane/C30 hopane and C32 22S/ (22S + 22R) range from 12.37 to 18.15; 0.05 to 0.07; 0.44 to 0.57 and 0.57 to 0.60 respectively (Table 5). The 18α(H)-oleanane that is widely known as a Cretaceous or younger higher plant marker (Peters and

Hydrogen Index, HI (mg HC/g rock)

implies the higher input of humic materials in the source. At the same time, the dominant inertinite macerals correspond to the vascular higher plants and it represents the terrestrial environment of deposition.

100 Type IV-III Type IV

10

100

TOC (wt. %) Fig. 5. Plot of total organic carbon (TOC in wt.%) versus remaining hydrocarbon potential (S2 in mg HC/g rock) of the analyzed coal samples showing good quality source rock generative potential.

0 390

410

430

450

470

490

510

530

Tmax ( oC) Fig. 6. Distribution of vitrinite reflectance (%Ro) and Tmax (°C) plotting with hydrogen index (HI) of the analyzed coal samples depicts Type-III/II (gas–oil prone) kerogen and plotted within early mature oil window.

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Table 2 Macerals and mineral matter content (%) of the analyzed coal samples. GI and TPI values are also shown (refer to Appendix A). Maceral

BP6CL1

BP6CL2

BP6CL3

BP6CL4

BP6CL5

BP6CL6

BP6CL7

BP6CL8

Telinite Telocollinite Desmocollinite Corpocollinite Vitrodetrinite Vitrinite group Sporinite Cutinite Resinite Liptodetrinite Exsudatinite Bituminite Liptinite group Sclerotinite Inertoderinite Fusinite Semifusinite Micrinite Macrinite Inertinite group Mineral matter Total GI TPI

3 43 1 2 1 50 1 – – 3 1 11 16 – 22 1 6 1 – 30 4 100 1.72 2.45

– 20 – 1 2 23 3 1 – 3 2 16 25 1 27 1 17 – 1 47 5 100 0.53 1.46

– 2 – – – 2 2 1 – 2 2 18 25 – 2 1 56 1 – 60 13 100 0.03 29.50

– 5 – – – 5 1 1 1 3 1 14 21 – 15 2 50 1 1 69 5 100 0.07 3.93

– 12 6 1 1 20 2 1 – 5 1 9 18 – 23 3 26 1 1 54 8 100 0.40 1.75

1 34 1 2 1 39 2 – – 6 1 8 17 – 18 2 16 1 – 37 7 100 1.08 4.75

2 10 – – – 12 1 – – 7 2 12 22 – 10 2 43 4 2 61 2 100 0.25 0.25

– 9 – 1 – 10 2 1 – 2 1 8 15 – 18 3 37 1 1 60 15 100 0.19 2.63

Moldowan, 1993) has not been found in any of the studied samples since the analyzed samples are Permian in age. The m/z 217 mass fragmentograms are dominated by regular steranes over diasteranes with C29 sterane being the predominant component. The measured sterane parameters include C29 20S / (20S + 20R), C29 ββ/ (ββ+ αα), diasteranes/steranes and diasterane 20S / (20S+ 20R) which range from 0.35 to 0.42, 0.21 to 0.24, 0.09 to 0.18 and 0.68 to 0.73 respectively (Table 6). These range of values usually indicate the influence of terrestrial organic matter (e.g., Huang and Meinschein, 1979). Strong aromatization and high carbon content is a characteristic of inertinite rich coal (Teichmuller, 1989) and the analyzed samples of the present study support this observation. Monika Fabianska and Kruszewska (2003) reported that the fusinite (pyro-fusinite and pyro-semifusinite) rich coals contain relatively high amounts of anthracene and its methyl derivatives which should be found as biomarkers. It suggests the occurrence of intense natural combustion (i.e., forest fire and peat/swamp fire) since these compounds do not form from natural precursors. Jiang et al. (1998) showed that

% 50

50%

Vitrinite

50%

Liptinte

Inertinite

Fig. 7. Ternary diagram shows the compositional distribution of the macerals vitrinite, liptinite and inertinite in the studied coals.

polycyclic aromatic hydrocarbons (PAHs) is a well-established combustion source in modern geological settings especially in terrestrial environment while benzo(a)pyrene is the most stable and suitable marker. Therefore the abundance of fusinite of the analyzed coals with elevated aromatic compounds indicate that the organic matter contains numerous PAHs like pyrene, fluoranthene, benzo(a)pyrene, benzo(e)pyrene, anthracene, phenanthrene, cadalene and benzo(a) anthracene etc. 4.4. Thermal maturity The studied coal samples have achieved initial oil window maturity as evidenced by vitrinite reflectance and Tmax. The measured mean random vitrinite reflectance values ranges from 0.72 to 0.81% which implies high volatile bituminous B coal rank (Stach et al., 1982) and these coals therefore are thermally mature for oil generation based on classification of Peters and Cassa (1994). However the analyzed SRA Tmax value that ranges from 431 to 435 °C suggest early thermal maturity stage (Peters and Cassa, 1994). Apart from the hydrogenrich liptinite the inertinite is also perhydrous in nature as it apparent from its dull yellow fluorescence observed in the analyzed coal samples. Moreover, solid bitumen that represent ‘free’ or expelled hydrocarbons are also present in the studied coals thus would further support the Tmax values. It ought to be noted that Frielingsdorf et al. (2008) mentioned that Gondwana coal of Northwest Bangladesh is the major petroleum source rock in the region and has already released up to 29% of its generation potential. The maturity sensitive parameters of hopanes, steranes and diasteranes are mostly either at or close to their thermal equilibrium values. Typically C31- or C32-homohopanes are used for calculations of the 22S / (22S + 22R) ratio. This ratio rises from 0 to about 0.6 while 0.57 to 0.62 is the equilibrium range commonly observed during maturation (Seifert and Moldowan, 1986). The calculated ratio values of 0.57–0.60 for the studied samples falls within the equilibrium range thus demonstrate the thermal maturity condition been reached. The ratio of 17β(H),21α(H)-moretanes to their corresponding 17α(H),21β(H)-hopanes decreases with increasing thermal maturity from about 0.80 in immature bitumens to values of less than 0.15 in mature source rocks and in oils to a minimum of 0.05 (Mackenzie et al., 1980). The studied samples show slightly higher ratio (0.44–0.57) than the equilibrium value range and this could have been a


consequence of high terrestrial organic matter input where moretanes are known to be abundant in terrestrial environment as reported by Waples and Machihara (1991). The measured C29 sterane 20S / (20S + 20R) values (0.35–0.42) of the studied samples move toward to the equilibrium value of 0.52 to 0.55. The calculated diasterane 20S / (20S + 20R) ratios (0.68– 0.72) are close to their expected thermal end points of about 0.60 which have reached the onset of oil generation (Mackenzie et al., 1980). Van Graas (1990) stated that maturity specific ratios derived from sterane are not useful at peak to late oil window maturities. van Kaam-Peters et al. (1998) discussed that lithologically similar samples could show different diasterane ratios on the basis of its clay minerals. The absolute clay content is not useful for this

169

explanation whereby the clay minerals content to TOC ratio is correlated to its diasterane ratios. Farrimond et al. (1998) discussed that a reversal of sterane maturity ratios may occur at high thermal maturities. Therefore in the analyzed samples, the observed sterane parameters might be deviated (as indicated by a bit higher ratio of moretane-tohopane and a slight lower ratio of sterane 20S/(20S + 20R), Table 6) from the equilibrium values due to its maturity stage as well as the influence of mineral content. 4.5. Hydrocarbon generation potential Coal has long been recognized as a source for gas, primarily methane and carbon dioxide but its importance as a generator of economic

Fig. 8. A. Solid bitumen (BS) (representing ‘oil’ in coal) in ‘white’ reflected light (A1) that fluoresces dull yellow in UV light (A2); Spherical shaped dark brown resinite (R) in ‘white’ reflected light (B1) that fluoresces yellowish green in UV light (B2); Sporinite (S) brownish black in reflected ‘white’ light (C1) that fluoresces bright yellow in UV light (C2). Field of view = 26 mm in oil immersion. B. Dark grey vitrinite (V) of perhydrous nature in ‘white’ reflected light (A1) which shows dull fluorescence in UV light associated with bright fluorescing cutinite and amorphous organic matter (A2); Oil smears (OS) associated with vitrinite and liptinite macerals in reflected ‘white’ light (B1) and intense yellow fluorescing bituminite in UV light (note that the oil smears do not fluorescence) (B2); brownish black starred of cutinite (C) with structureless bituminite in reflected ‘white’ light (C1) and cutinite displays faint yellow fluorescence while bituminite displayed intense yellowish fluorescence in UV light (C2). Field of view = 26 mm in oil immersion. C. Highly reflecting fusinite (F) in normal ‘white’ light associated with vitrinite and solid bitumen (‘oil’) (A1) whereby fusinite/vitrinite does not fluoresce in UV light while the bitumen displayed a dull yellow fluoresces (A2); Light grey vitrinite in association with inertodetrinite (ID), sporinite, cutinite and fusinite in reflected ‘white’ light (B1) whereby vitrinite/inertodetrinite is not fluorescing in UV light while sporinite and cutinite fluoresces intense yellow (B2); Grayish white semifusinite (SF), highly reflecting fusinite appearing bright white and light grey vitrinite in reflected ‘white’ light (C1) and structured telinite (T) in reflected ‘white’ light (C2). Field of view = 26 mm in oil immersion.

170


Fig.8. (continued)

accumulations of oil is difficult to prove as coals are often interbedded with shales which may be the source beds. The question is not whether humic, cannel or boghead coals can generate oil but rather what is the minimum liptinite or fluorescent organic matter content required to make any coal as a source of oil? However, there are some basins in the world where the evidence is pretty strong that coal is contributing to accumulations of liquid petroleum (Hunt, 1991). There are about 100 gas fields and 10 oil fields in the Permian-Triassic CooperEromanga basin of South Australia. The Permian coal measures have long been considered the major source of gas and/or oil of this basin (Vinchet et al., 1985). The identified macerals of these coals included predominantly inertinite and vitrinite with liptinite (mainly sporinite and cutinite) b10%. The hydrogen index was as high as 320 suggesting capability for liquid generation. All the analyzed crude oils from Cooper basin showed the predominance of C29 steranes which is the characteristic of terrigenous source input. The analyzed samples under current investigation show close geochemical similarity to those of the Permian coals of Australia. Thompson et al. (1985) examined coals in three Indonesian basins namely Kutai, NW Java and Sunda. The hydrogen index measured from these coals ranged from 250 to 450 mg HC/g TOC. The crude

oils of these Indonesian basins have the characteristic odd-even predominance in the n-alkanes along with a pristane to phytane ratio greater than >5 which is typical of an oxic depositional environment. These authors concluded that the liptinitic constituents of these coals were responsible for this oil generation (Thompson et al., 1985). The oil and condensates of the Gippsland basin of southwestern Australia have Pr/Ph ratio >5, low sulfur, dominancy of C29 steranes and high wax. These are all characteristics of oils originating from terrestrial organic matter and the source of these oils is believed to be from the coals which contain high abundance of sporinite, cutinite, resinite and suberinite (Philp and Gilbert, 1986). Semkiwa et al. (2003) published a paper on the Permian coals of Tanzania and he suggested good hydrocarbon generation potential from these coals (i.e., being inertinite rich, organic matter Type-II/III are dominant with %Ro 0.62–0.83 and Tmax 426–440 °C) which is similar to coals analyzed in this study. However, the hydrocarbon generation from coals and in particular the expulsion mechanism are complex and are known to depend on several factors such as maceral type, maceral association, coal micro-texture etc. and also interrelated with original precursor material, depositional environment, microbial activity and mineral matter


171

Fig.8. (continued)

(e.g., Hunt, 1991; Littke et al., 1989; Scott and Fleet, 1994; Snowdon, 1995; Wan Hasiah, 1997, 1999, 2003). In the analyzed samples, the liquid hydrocarbon potential is most likely attributed to the high contents of liptinitic macerals (e.g., bituminite, cutinite, exsudatinite and sporinite) albeit the analyzed coals are rich in inertinites. The characteristic behavior of exsudatinite that commonly formed crack networks suggest a significant role in hydrocarbon expulsion into carrier beds (Hunt, 1996; Teichmuller, 1974, 1989; Wan Hasiah, 1999, 2003). The high proportion of bituminite, cutinite, exsudatinite and sporinite agrees with the moderate abundance of long-chain nalkanes (C15–C25) which indicate the good potential for more waxy hydrocarbons associated with coaly organic matter (e.g., Philp, 1985; Wan Hasiah and Abolins, 1998). In addition to liptinite, vitrinite may also be responsible for liquid hydrocarbon generation from coals as evidenced in New Zealand. For examples, Hunt (1991), Hartgers et al. (1994) and Wan Hasiah (1997, 1999) suggested that the hydrogen-rich perhydrous fluorescent (dull yellow to orangebrown) vitrinite and submicroscopic constituents (e.g., microbes) can contribute towards good hydrocarbon generation potential and this was also indicated by Powell et al. (1991), Curry et al. (1994) and Ahmed et al. (2009). The studied Permian coals with high liptinite contents (up to 25%), high total extracts (32,232–41,389 ppm) and very rich in hydrocarbon yields (14.77–30.66 mg HC/g TOC) indicate that they have already generated and expelled hydrocarbons. The mean vitrinite reflectance of 0.72–0.81% values support that these samples are

thermally mature for initial hydrocarbon generation. Hunt (1991) showed that the coals and terrestrial kerogen with H/C ratios above approximately 0.90 or hydrogen indices of about 200 by Rock-Eval pyrolysis and liptinite contents above 15% have the potential to generate and release oil and gas which are the typical examples from the oil fields of Indonesia and Australia. Moreover, Hunt (1991) expressed without any doubt that hydrogen-rich coal can generate economic quantities of liquid petroleum. HI values of 200 mg HC/g TOC have been proposed as the minimum values for liquid hydrocarbon expulsion from coals (Koeverden et al., 2011), as opposed to mere generation (Pepper and Corvi, 1995). The measured higher hydrogen indices of the analyzed coal samples in this study ranging from 280 to 326 mg HC/g TOC with considerable amounts of liptinite (e.g., cutinite, sporinite, bituminite, resinite etc.) corresponds to the generation potential both for gaseous and liquid hydrocarbons. The liquid hydrocarbon potential in the studied coals is most likely attributed to the high contents of liptinitic macerals whereby these macerals are commonly observed to be associated with oil smears. 4.6. Environment of deposition Biomarker distribution and maceral assemblages have been used to describe source input and condition of depositional environment of the analyzed coal samples. The distributions of n-alkanes with predominance of odd carbon number alkanes to even carbon number alkanes in the gas chromatograms of the analyzed coal samples indicate

172


Abundance

PyGC signal

Sample: BP6CL2

C6

1.3e+07 1.1e+07

Mixed kerogens (Type III/II)

C10

C8/Xylene = 0.73 C12

C7 C8

9000000

C13 C9 C15

7000000 5000000

1 Pristene

1.5e+07

C11

Xylene (m+p)

1.7e+07

Toluene

1.9e+07

C19

C23

C21

C27

3000000 1000000 5

10

15

20

25

30

35

40

45

50

55

60

65

Retention time Abundance

1.5e+07

Mixed kerogens (Type III/II)

1.3e+07 1.1e+07

C7

9000000

C8/Xylene = 0.81 C11 C10

C12 C13

C9

7000000

1 Pristene

1.7e+07

Sample: BP6CL7

C6 Toluene

1.9e+07

Xylene (m+p)

2.1e+07

PyGC signal

C15

5000000

C19

C21

C23 C27

3000000 1000000 5

10

15

20

25

30

35

40

45

50

55

60

65

Retention time Fig. 9. PyGC pyrograms of coal samples BP6CL2 and BP6CL7 which display a mixed kerogen of types III and II.

significant input of cuticular waxes from vascular higher plants (e.g., Peters and Moldowan, 1993; Philp, 1985). Huang and Meinschein (1979) showed that the relative proportions of the C27–C29 regular steranes (sterols) in living organisms are related to specific environments and suggested that steranes in sediments might provide valuable paleoenvironmental information. Strong terrestrial contribution is indicated by a predominance of C29 steranes whereby the marine influence is depicted by the dominance of C27 steranes. C28 has been found in general to be the lowest of the three steranes, but where relatively abundant it might indicate a heavy contribution by lacustrine algae. The triangular diagram (Fig. 12) has often been employed to represent the relative proportions of these three steranes. Humic and waxy coals generally display a strong dominance of the C29 steranes. The relative amount of diasteranes compared with regular steranes seems to depend on both sediment lithology (i.e., mineralogy) and maturity (Peters and Moldowan, 1993). Diasteranes seem to form most readily in clastic sediments where clay catalysts can play a role in their formation from other steranes. They are therefore frequently used to distinguish carbonate facies (low diasteranes) from clastic ones (Waples and Machihara, 1991). However, the facies dependence must be more subtle than simply one of clastic/nonclastic or of clay mineral content and Moldowan et al. (1986) suggested there might be some redox control on the diasterane/sterane ratio. In the studied coal samples, the more abundant odd carbon numbered n-alkanes, higher Pr/Ph ratio (4–8), high Tm/Ts ratio (13–18), bimodal distribution of n-alkanes, dominance of C29 steranes (73– 80%) over the C27 or C28 steranes (Fig. 12), cross-plot of Pr/nC17– Ph/nC18 (Fig. 13) and higher amounts of steranes over diasteranes clearly exhibit that the organic matter input was derived from

terrestrial higher plant constituents and the condition of deposition was oxic. The ratio of Pr/Ph has been used extensively as an indicator of oxic condition of a terrestrial depositional environment. This was originally reported by Brooks et al. (1969) and subsequently developed by Powell and McKirdy (1973) which is based on the premise that pristane is formed from phytol by various oxidation and decarboxylation reactions. On the other hand phytane is formed by hydrogenation and dehydration of phytol. The source of phytol is the side chain of chlorophyll and it has been stated that the formation of pristane occurs in oxidizing environments, such as swampy peat bogs, whereas phytane formation occurs in reducing type environments. Despite the complexity of different reactions it is still a useful guide to say that the samples with Pr/Ph ratio greater than 1 are more likely to have been formed in an oxidizing environment and even Pr/Ph ratio ranged from 5 to 11 indicates nonmarine source rock which is also in support of the analyzed samples. Peters and Moldowan (1993) discussed that samples within the oil-generative window, high Pr/Ph ratios (>3) indicate terrestrial organic matter input under oxic conditions which is quite consistent with the present explanation of depositional condition for the studied samples. Wan Hasiah and Abolins (1998) showed that the coals with Pr/Ph ratio exceeding 4 are typically deposited within a peat-swamp depositional setting indicating the oxic depositional condition and this statement is also consistent with the depositional settings of the analyzed coals all of which possess Pr/Ph ratios >4. The predominance of C31-homohopane and the considerable amounts of moretane also support the terrestrial environments as discussed by Waples and Machihara (1991) and Peters and Moldowan (1993). But the type of deposition (i.e.,


Abundance

TIC

173

Sample: BP6CL2

4000000 nC 23

3500000

Pr/Ph = 6.80 CPI2 = 1.05

nC 20

3000000

Ro = 0.73 HI = 285

2500000

nC 18 Pr

2000000

nC17

1500000

nC 26

nC 30

1000000

nC 32 nC 28 nC15

500000

nC 33

Ph

nC 35

0 20

25

30

35

40

45

50

55

60

65

70

Retention time

Tm/Ts = 15 C30βα/C30αβ = 0.48 22S/(22S+22R) = 0.58

22S 22R

C30βα

C31αβ

52

54

56

58

60

62

64

66

68

C35αβ 22S

C34αβ

22R

C29Ts

C28αβ

Ts*

Ts

C33αβ

22S 22R

C32αβ 22S 22R

C29βα

Tm

Sample: BP6CL2

C30αβ

Ion 191 (190.70 to 191.70) C29αβ

130000 120000 110000 100000 90000 80000 70000 60000 50000 40000 30000 20000 10000 0

22S 22R

Abundance

70

72


14000 12000

6000 4000 2000

C28ααα 20R

C29βα 20S

8000

C27ααα 20R C29αβ 20R C28ααα 20S C28αββ 20R C28αββ 20S

10000

Sample: BP6CL2 C29ααα 20R

16000

C29ααα 20S C29αββ 20R C29αββ 20S

Ion 217 (216.70 to 217.70)

0 54

55

56

57

58

59

60

61

62

63

64

Retention time Fig. 10. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of a studied Barapukuria coal sample (BP6CL2).

autochthonous or allochthonous or hypautochthonous) has not been indicated by the present analysis. Bituminite which is a form of liptinite maceral that fluoresces has been considered by a number of workers to be the decompositional product of algae, animal plankton and bacteria (Cook et al., 1981; Teichmuller, 1974, 1989). On the other hand, Cook et al. (1981) and Sherwood and Cook (1986) suggested that the bituminite originates from anaerobic degradation of higher plants and/or algae and may occur as amorphous or lamellar form. As for the current study, this appears not to be the case as there are strong supporting evidences (as previously discussed) that the studied coals were deposited in oxic depositional condition. This is also reflected in the Pr/nC17–Ph/ nC18 diagram (Fig. 13).

The Gelification Index (GI) and Tissue Preservation Index (TPI) has been used to interpret the paleoenvironmental settings in relation to the type of mire (after Diessel, 1986) whereby the studied coals were plotted in terrestrial region in Fig. 14 and corresponds to dry forest swamp to piedmont plain deposits with a high tree density. Diessel (1986) states that wet conditions of peat development are characterized by high GI and high TPI while peat formed in dry conditions gives a low GI and low TPI. The identified low GI (0.07–1.72) with low to moderate TPI (1.46–3.93 with one high value of 29.50) of the studied coals suggest the origin in intermittently (recurrence) dry forest swamps. In addition, the lateral variation of the analyzed TPI indicates the lateral increase in the rate of subsidence and depth of the basin. Similar interpretation of depositional environment was presented

174


Abundance

TIC

6400000

Sample: BP6CL7 nC 23

5600000

Pr/Ph = 5.90 CPI 2 = 1.03 Ro = 0.80 HI = 289

nC 20

4800000 4000000

nC 18

3200000

nC 17 Pr

2400000

nC 26 nC 30 nC 31 nC 32

nC 15

1600000

nC 28

nC 13

800000

nC 33 nC 34 nC 35

Ph

0 35

40

45

50

Ion 191 (190.70 to 191.70)

C29αβ

20000 Tm

18000

C30αβ

22000

C30βα

14000 C29βα

12000

C32αβ

8000

Ts

C29

C28αβ

2000

Ts

6000 4000

70

Tm/Ts = 15.15 C30βα/C30αβ = 0.49 22S/(22S+22R) = 0.60

22S 22R

10000

65

Sample: BP6CL7

C31αβ

16000

60

22S 22R

Abundance

55

C33αβ

C34αβ

C35αβ 22R

30

22S

25

22S 22R

20

Retention time

22S 22R

15

0 52

54

56

58

60

62

64

66

68

70

72


Ion 217 (216.70 to 217.70)

Sample: BP6CL7

S

R

45000

C29

35000

C29

40000

R

30000

10000 5000

C29

C29

15000

C29 S

S

20000

R C27 C29 R S C28 C28 R S C28 C28 R

25000

0 54

55

56

Retention time

57

58

59

60

61

62

63

64

65

Fig. 11. Gas chromatogram (TIC) and mass fragmentograms m/z 191 and m/z 217 of aliphatic fraction of studied Barapukuria coal sample (BP6CL7).

Table 3 Normal and branched alkane parameters of the studied coal samples (refer to Appendix A). Sample no.


EOM (ppm of whole rock)

EOM (mg EOM/g TOC)

Normal and branched biomarker ratios

Tot extr

Aliph

Arom

Tot extr

Aliph

Arom

Total HC

HC/nonHC

EOM/TOC

n-alk max

CPI1

CPI2

37,634 32,232 41,389 27,561 32,634 38,280 39,915 27,969

8880 14,406 8151 2485 4824 4814 9840 3204

9162 4341 10,980 8449 9860 11,413 10,959 8988

60.26 52.72 56.33 37.23 49.72 55.54 54.80 39.44

14.22 23.56 11.09 3.36 7.35 6.77 13.51 4.52

14.67 7.10 14.95 11.41 15.02 16.56 15.05 12.67

28.89 30.66 26.04 14.77 22.37 23.54 28.55 17.19

0.92 1.39 0.86 1.21 0.82 0.74 1.09 0.77

0.06 0.05 0.06 0.04 0.05 0.06 0.05 0.04

16 15 15 16 16 16 16 16

1.58 1.45 1.19 1.49 1.31 1.44 1.45 1.31

1.09 1.05 1.01 1.07 1.08 1.00 1.03 1.01


175

Table 4 n-alkane and regular isoprenoid ratios of the analyzed coal samples. Sample no.

Pr/Ph

Pr/nC17

Ph/nC18


7.73 6.80 4.19 6.00 5.50 5.89 5.90 4.05

1.12 1.18 0.99 0.88 1.17 1.18 0.89 1.00

0.12 0.13 0.19 0.11 0.18 0.16 0.12 0.21

Table 5 Hopane biomarker parameters (measured from m/z 191) of the studied coal samples (refer to Appendix B). Samp no.

Tm/Ts

Ts/ (Ts + Tm)

C29-hop/ C30-hop

C30-mor/ C30-hop

C30-hop/(C30-hop + C30-mor)

C31 22S/ (22S + 22R)

C32 22S/ (22S + 22R)

C33 22S/ (22S + 22R)

C35-index


14.67 15.00 18.15 16.43 13.30 15.50 15.15 12.37

0.06 0.06 0.05 0.06 0.07 0.06 0.06 0.07

0.83 0.91 0.87 0.78 0.95 0.96 0.92 0.82

0.45 0.48 0.57 0.44 0.50 0.53 0.49 0.55

0.69 0.67 0.64 0.69 0.67 0.65 0.67 0.65

0.58 0.59 0.57 0.57 0.57 0.57 0.55 0.56

0.59 0.58 0.58 0.57 0.56 0.60 0.60 0.58

0.59 0.60 0.59 0.58 0.62 0.58 0.60 0.60

0.04 0.03 0.05 0.05 0.05 0.05 0.04 0.06

Table 6 Sterane and diasterane biomarker parameters (measured from m/z 217) of the studied coal samples (refer to Appendix B). Samp no.

C27-ster (%)

C28-ster (%)

C29-ster (%)

C28-ster/ C29-ster

C29-ster/ C27-ster

Ster C29 20S/ (20S + 20R)

Ster C29 ββ/ (ββ + αα)

Diaste/ Sterene

Diaste 20S/ (20S + 20R)


10.56 10.32 8.33 12.65 9.83 10.56 8.71 11.60

10.56 11.94 11.33 14.20 10.17 10.23 10.84 13.79

78.88 77.74 80.33 73.15 80.00 79.21 80.45 74.61

0.13 0.15 0.14 0.19 0.13 0.13 0.13 0.18

7.47 7.53 9.64 5.78 8.14 7.50 9.24 6.43

0.42 0.37 0.38 0.38 0.37 0.42 0.39 0.35

0.22 0.22 0.21 0.24 0.21 0.23 0.22 0.21

0.13 0.14 0.10 0.18 0.12 0.12 0.09 0.17

0.68 0.68 0.69 0.70 0.70 0.72 0.73 0.72

by Singh and Shukla (2004) based on the Permian coals of India and by Semkiwa et al. (2003) based on the Permian coals of Tanzania. The oxic (drier) depositional condition was also indicated by the dominance of inertinite macerals (e.g., semifusinite and fusinite) and absence of alginite. This observation is in good agreement with the environmental interpretation based on biomarker distribution.

Takeda et al. (2011) discussed about the origin of gas and condensate of Surma basin (a sub-basin of Bengal basin) on the basis of isotope analysis and organic geochemical interpretation and they concluded that the possible origin of this gas/condensate is

C285α20R 100

I

rine

cin

ing

al Alg

50 %

Typ

e II

Typ

Plankton

Ox

g

Ma

50% 0.1 0.1

1

Terrestrial

ty

turi

Ma

% 50

du

idiz

/III

e II

ed Mix

e arin nm e Ope custrin la r o e arin Estu allow h or s trine s lacu

Te

Bi

1

Typ

rrig

tion

ada

gr ode

us eno

Re

Pristane/nC17

e II

10

10

C275α20R

Higher plant

C295α20R

Phytane/nC18 Fig. 12. Relationship between sterane compositions, source input and depositional environment whereby the studied coal samples are shown to be dominated by terrigenous-derived higher plant organic matter input.

Fig. 13. Pristane/nC17 versus Phytane/nC18 for the analyzed coal samples infer oxicity and organic matter type of the source rock depositional environment (after Peters et al., 2005a, 2005b; Koeverden et al., 2011) whereby the studied samples being all coals concur to the terrigenous source input region.

176


TREE DENSITY

100

LEGEND

DECREASESINCREASES LIMNO TELMATIC

A Dry forest swamp

TELMATIC

B Coals deposited in piedmont plain C Coals deposited in upper delta plain

Marsh

D Wet forest swamp E Coals deposited in lower delta plain

10

LIMNIC

Gelification Index (GI)

E

D C

B

1

A TERRESTRIAL 0.1

0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

10

30

50

70

Tissue Preservation Index (TPI) Fig. 14. Coal facies depicted from the Gelification Index (GI) and Tissue Preservation Index (TPI) in relation to depositional setting and type of mire (after Diessel, 1986) whereby the studied coal falls in terrestrial environment.

the coaly source rocks derived from terrestrial depositional environment. Their observation is also in support of an oxic condition of depositional environment for the studied coal samples. In this regard, based on the present study and supporting data reported by previous workers, an oxic terrestrial depositional environmental setting as shown in Fig. 15 has been proposed for the Barapukuria coals. 5. Conclusions The depositional environment of coal and its condition of deposition is often considered as a very complex phenomenon since it is

related to numerous factors. The study reveals that the coals from Barapukuria basin possess good quality source potential for liquid hydrocarbon generation. This is evidenced from the organic matter content that is predominantly a mixture of Type-III and Type-II kerogens which is supported by cross-plots of TOC vs S2 and HI vs Tmax as well as the dominancy of aromatic compounds and n-alkane/alkene doublets in the PyGC pyrograms. The analyzed coals have been found thermally mature (initial oil window) for hydrocarbon generation based on the mean vitrinite reflectance in the range of 0.72 to 0.81%. Tmax and the biomarker values of 22S / (22S + 22R) hopane, moretane/hopane ratio and sterane parameters support this attained thermal maturity level.

al) f

orm

ing

sw

am p

Flood plain

r

(co

ve

Cr

ev

as

se

sp

aly

Pe

at

Ri

Fig. 15. Schematic block diagram represents the palaeodepositional environment of the Permian Gondwana coal succession of Barapukuria basin, Bangladesh.


The biomarker parameters such as high Tm/Ts ratio, high Pr/Ph ratio, more dominant odd carbon numbered n-alkanes and high abundance of C29 regular steranes support that the coaly organic matter was derived from higher land plants of terrestrial environment while the depositional condition was oxic (dry). The marine environmental influence has not been detected in the analyzed coal samples. GI vs TPI plot and predominance of inertinite maceral group also correspond to the depositional environment of a dry forest swamp. A peat-swamp flood basin environment has been proposed for the deposition of the Barapukuria coals based on the organic geochemical and organic petrological interpretations. Acknowledgements The authors are thankful to Prof. Dr. Md. Hussain Monsur, Chairman of Bangladesh Oil, Gas and Mineral Corporation (BOGMC) and Mrs. Monira Akhter Chowdhury, Director General of Geological Survey of Bangladesh (GSB) for permission to use the data/samples for this study. The first author pleasantly acknowledges the cooperation and motivation rendered by Prof. Dr. Khalil R. Chowdhury and his colleagues at the Jahangirnagar University in order to carry out this research. We are highly grateful to both anonymous reviewers for their constructive and fruitful comments that have improved this manuscript considerably. The authors also acknowledge the IPPP grant PV100-2011A for financial supports from the University of Malaya.

Appendix B. Peak assignments for alkane HCs in the gas chromatograms of the aliphatic fractions (i) in the m/z 191 mass fragmentogram and (ii) m/z 217 mass fragmentogram.

Peak identity (i) Fragmentogram Ts m/z 191 Ts* Tm C28αβ C29αβ C29Ts C29βα C30αβ C30βα C31αβ C31αβ 22S C31αβ 22R C32αβ C33αβ C34αβ C35αβ (ii) Fragmentogram m/z 217

Appendix A. Some definitions and measurement terms used in literature.

Term

Description

TOC S1 S2

Total organic carbon (wt.%). Free or thermally extractable HCs (mg HC/g rock). HCs generated by pyrolytic degradation of kerogen (i.e. hydrolysable HCs) (mg HC/g rock). CO2 generated from low temperature (up to 390 °C) pyrolysis (mg CO2/g rock). Maximum temperature at top of S2 peak (°C). Hydrocarbons. Petroleum Potential (i.e. Genetic Potential): S1 + S2 (mg HC/g rock). Production Index (i.e. Transformation ratio): {S1 / (S1 + S2)}. Hydrogen Index: (S2/TOC) * 100 (mg HC/g TOC). Oxygen Index: (S3/TOC) * 100 (mg CO2/g TOC). Extractable Organic Matter (Bitumen). Measured random vitrinite reflectance (%). Total extract.

S3 Tmax HCs PP PI HI OI EOM Ro Tot extr Alip Arom NSO nC15, .... C15, ....... Pr/Ph Pr/ nC17 Ph/ nC18 CPI1 CPI2 hop mor ster diaste GI TPI

Aliphatic. Aromatic. Polar compounds (e.g., N, S, O etc). Normal alkane with 15 carbon numbers, ........... Normal alkene with 15 carbon numbers, ............ Pristane / Phytane. Pristane / nC17. Phytane / nC18. Carbon Preference Index (Peters and Moldowan, 1993): 2(C23 + C25 + C27 + C29)/[C22 + 2(C24 + C26 + C28) + C30] Carbon Preference Index (Ahmed et al., 2009): 2[C21/(C20 + C22)] Hopane Moretane Sterane Diasterane (Vitrinite + Macrinite)/(Semifusinite + Fusinite + Inertodetrinite) (Telinite + Collotelinite + Semifusinite + Fusinite)/(Collodetrinite + Macrinite + Inertodetrinite + Vitrodetrinite + Corpogelinite)

177

C27ααα 20S C27αββ 20R C27αββ 20S C27ααα 20R C28ααα 20S C28αββ 20R C28αββ 20S C28ααα 20R C29ααα 20S C29αββ 20R C29αββ 20S C29ααα 20R C29βα 20S C29αβ 20R

Compound

Carbon no.

18α(H),22,29,30-trisnorneohopane Rearranged Ts 17α(H),22,29,30-trisnorhopane 17α(H),29,30-bisnorhopane 17α(H),21β(H)-norhopane 18α(H),30-norneohopane 17β(H),21α(H)-hopane (moretane) 17α(H),21β(H)-hopane 17β(H),21α(H)-hopane (moretane) 17α(H),21β(H)-homehopane (22S and 22R) 17α(H),21β(H)-homehopane (22S)

27 27 27 28 29 29 29 30 30 31

17α(H),21β(H)-homehopane (22R)

31

17α(H),21β(H)-homehopane (22S and 22R) 17α(H),21β(H)-homehopane (22S and 22R) 17α(H),21β(H)-homehopane (22S and 22R) 17α(H),21β(H)-homehopane (22S and 22R) 5α(H),14α(H),17α(H)-cholestane (20S) (sterane) 5α(H), 14β(H),17β(H)-cholestane (20R) (sterane) 5α(H), 14β(H),17β(H)-cholestane (20S) (sterane) 5α(H),14α(H),17α(H)-cholestane (20R) (sterane) 24-methyl-5α(H),14α(H),17α (H)-cholestane (20S) (sterane) 24-methyl-5α(H),14β(H),17β (H)-cholestane (20R) (sterane) 24-methyl-5α(H),14β(H),17β (H)-cholestane (20S) (sterane) 24-methyl-5α(H),14α(H),17α (H)-cholestane (20R) (sterane) 24-ethyl-5α(H),14α(H),17α (H)-cholestane (20S) (sterane) 24-ethyl-5α(H),14β(H),17β (H)-cholestane (20R) (sterane) 24-ethyl-5α(H),14β(H),17β (H)-cholestane (20S) (sterane) 24-ethyl-5α(H),14α(H),17α (H)-cholestane (20R) (sterane) 24-ethyl-13β(H),17α(H)-diacholestane (20S) (diasterane) 24-ethyl-13α(H),17β(H)-diacholestane (20R) (diasterane)

32

31

33 34 35 27 27 27 27 28 28 28 28 29 29 29 29 29 29

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