Petroleum Generation Potential of Miocene Bhuban Shales, Bengal Basin, Bangladesh

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1 1055 F a r h a d u z z a m a n, e t a l., I C E R I E Proceedings of the International Conference on Engineering Research, Innovation and Education 2013 ICERIE 2013, January, SUST, Sylhet, Bangladesh Petroleum Generation Potential of Miocene Bhuban Shales, Bengal Basin, Bangladesh Md. Farhaduzzaman 1 *, Wan Hasiah Abdullah 1 and Md. Aminul Islam 2 1 Department of Geology, Faculty of Science, University of Malaya, Kuala Lumpur, Malaysia. 2 Department of Petroleum Geoscience, Faculty of Science, Universiti Brunei Darussalam, Gadong BE1410, Brunei. Keywords: Bhuban shale, Petroleum potential, Organic matter, Thermal maturity, Hopane, Sterane, Bengal Basin Abstract: The present study is dealt with an investigation of petroleum generation potential of Miocene Bhuban shales. Organic geochemical and organic petrological methods were used for analyzing 11 drill core samples from 4 gas fields in the basin. Kerogen in the studied shale samples is classified mainly as Type III with lesser amounts of Type II. Vitrinite is the dominant maceral group observed in the analyzed Bhuban samples followed by liptinite and inertinite. Vitrinite reflectance, Tmax and other biomarkers parameters indicate the maturity range from just pre-oil window to mid-oil window. Considering its TOC, EOM, HI and other data, the analyzed Bhuban shales are ranked as poor to fair source rocks with good gas generation potential. 1. INTRODUCTION The Bengal Basin covers whole of Bangladesh and part of India and it is bordered with three sides by India and one small side (southeast) by Myanmar (Fig.1). The Bhuban is the most important geological unit of Bengal Basin since majority of the discovered petroleum resources of Bangladesh have been confirmed within this stratigraphic formation. It is believed that the Bhuban Formation is acting both as source rock (shale part) and reservoir rock (sandstone part) for the existing petroleum system of Bengal Basin (Imam, 2005). Here we present data from both techniques for Bhuban Formation and draw some conclusions considering kerogen facies, thermal maturity and petroleum generation potential. 2. GEOLOGICAL CONTEXT Bangladesh is situated in the northeastern part of south Asia. The first collision of the northwards moving Indian Plate with the Eurasian Plate took place in Pliocene/Lower Eocene. Subsequent subduction led to the rising Indo-Burman Orogeny. The later finally separated the Burmese basins in the east from the Bengal Basin in the west (Reimann, 1993). The identified stratigraphic formations of the Deep Basin unit (study area) include (from bottom upward) Tura Sandstone (Paleocene), Sylhet Limestone (Middle Eocene), Kopili Shale (Upper Eocene), Jenum (Oligocene), Renji (Oligocene), Bhuban (Miocene), Boka Bil (Early Pliocene), Tipam Sandstone (Middle Pliocene), Girujan Clay (Middle Pliocene), Dupi Tila (Late Pliocene), Madhupur Clay (Plio-Pleistocene) and Alluvium (Holocene) (Alam et al., 2003; Imam, 2005). The unit is traditionally believed to have been deposited in a deltaic to shallow marine environment. Mostly all of the discovered gas/oil fields have been found within the Bhuban Formation of the Deep Basin unit. Bengal Basin of Bangladesh comprises two major petroleum provinces (Fig.1). Estimated gas reserve (GIIP P+P) in *Corresponding author: farhadgeo@gmail.com

2 1056 F a r h a d u z z a m a n, e t a l., I C E R I E Bangladesh is TCF with about 42 TCF undiscovered (Jamaluddin et al., 2001; Shamsuddin et al., 2004). Petrobangla re-estimated the total recoverable oil reserves of 137 million barrels STOIIP. 3. SAMPLES AND METHODS A total of eleven shale core samples of Bhuban Formation were collected from four different wells drilled of respective four gas fields (Fenchuganj, Titas, Kamta and Begumganj) located in Deep Basin unit. All of the collected shale samples have been subjected to Source Rock Analyses (SRA). After screening, all of the samples were used for Soxhlet extraction followed by gas chromatography mass spectrometry (GCMS). The collected samples were crushed into fine powder and analyzed using a Weatherford Source Rock Analyzer (equivalent of Rock-Eval equipment). Bitumen extraction was also been performed using Soxhlet apparatus and subsequently separated into aliphatic, aromatic and NSO fractions. The aliphatic hydrocarbon fractions were analyzed by gas chromatography (Agilent 6890N Series GC) and gas chromatography mass spectrometry (GCMS). Fig.1. Location map of the study area showing the major tectonic elements of Bengal Basin (Khan, 1991; Reimann, 1993; Islam, 2009; Farhaduzzaman et al., 2012a & 2012b). For organic petrographic study, the samples were prepared by mounting whole rock fragments in resin blocks and polished to a highly reflecting surface using progressively finer alumina suspension (1μm, 0.3 μm and 0.05 μm). Petrographic examination was carried out under oil immersion using a LEICA DM6000M microscope and CTR6000 photometry system equipped with fluorescence illuminators (ultraviolet light). All the analyses were carried out in the UM Geology Department, Malaysia.

3 1057 F a r h a d u z z a m a n, e t a l., I C E R I E RESULTS AND DISCUSSION 4.1 Source Rock Properties The results obtained from Source Rock Analyzer (SRA) have been shown in Table 1. The source rock potential of the analyzed Bhuban Formation shales can be evaluated as mostly poor ranges to fair (Peters & Cassa, 1994). All samples are organic lean (<1%) and HI values of Bhuban Formation range from 39 to 232. Most samples are plotted in the Type III range but a sample showing admixtures of Type II which implies a mixture of kerogen types (III/II) of organic matter (Fig.2). The recorded OI varies from 64 to 168 CO 2 /g TOC and the cross-plot of HI versus OI (modified van Krevelen diagram; not shown here) reveals mostly Type III character. T max values vary from 429 to 441 C and the mean vitrinite reflectance value ranges from 0.57to 0.71 (%VRr) for the studied shales. 4.2 Maceral Composition Vitrinite (60-80 vol.%) is the dominant maceral group found in the analyzed Bhuban shales followed by liptinite (20-25%) and inertinite (8-15%). The important liptinitic macerals include sporinite, cutinite, resinite, amorphous, liptodetrinite and alginite (trace amount). These liptinitic macerals along with the solid bitumen (staining) contribute a minor oil-prone character to the dominantly vitrinitic assemblages. 4.3 Extractable Organic Matter and Biomarker Characteristics The concentration of aromatic hydrocarbons ( ppm) is higher than that of aliphatic hydrocarbons (9-300 ppm) in analyzed shales. The total soluble hydrocarbon yield ranges from 21 to 139 mg HC/g TOC. The total soluble extract varies from 132 to 2814 ppm in the analyzed shale samples. The fractionated aliphatic part was used for GC and GCMS analyses of the studied shale samples. The TIC (total ion current), m/z 191 and m/z 217 chromatograms have been used for the current interpretations (Fig.3). The unimodal distributions of n-alkanes from C 10 to C 35 with the maxima standing at C 16 (mostly) and/or C 18 have been observed in the gas chromatograms of the analyzed Bhuban shale samples (Fig.3A). The calculated CPI values are close to unity from 0.99 to 1.37 in Bhuban shales. In most of the analyzed samples, the odd carbon homologs dominate over the even carbon homologs whereas the even carbon homologs also dominate over

4 1058 F a r h a d u z z a m a n, e t a l., I C E R I E the odd carbon homologs in some other samples. The pristane/phytane ratio is fairly high to very high and it varies from 0.99 to Fig.2. Cross-plot of hydrogen index vs Tmax whereby the analyzed samples correspond mostly immature to peak mature oil window and Type III (mainly) kerogen (Peters & Cassa, 1994; Koeverden et al., 2011; Farhaduzzaman et al., 2012c and 2013a). The C 30 αβ-hopane is the dominant member of the abundant pentacyclic triterpanes (hopanes and moretanes) in all of the analyzed Bhuban shale samples (Fig.3B and 3C). Homohopanes are lower in concentration but dominated by C 31 -hopane in of the studied samples. The S-isomers are dominant over R-isomers in some analyzed samples (Fig.3B) indicate that the samples are thermally mature for hydrocarbon generation. On the other hand, R-isomers are dominant over the S-isomers among the homohopanes (C 31 - C 33 ) of some other analyzed samples (Fig.3C) indicate that the samples are thermally immature for hydrocarbon generation. In general αβ-hopanes are more prominent than the βα-hopanes (moretanes). The Ts/Tm ratio of the studied samples ranges from 0.26 to C 30 moretane/c 30 hopane and C 32 22S/(22S + 22R) ranges from 0.09 to 0.44 and 0.47 to 0.63 respectively for the analyzed Bhuban Formation shales. Considerable abundances of 18α(H)-oleanane (higher plant marker) have been found in all of the studied samples. C 29 sterane is the most predominant component observed in the m/z 217 mass fragmentograms which are dominated by regular steranes compared to the diasteranes of the analyzed Bhuban shale samples (Fig.3D). The most commonly used sterane parameters include C 29 sterane, sterane C 27 / (C 27 +C 29 ) and diasteranes / steranes and these values range from 36 to 64%, 0.21 to 0.48 and 0.05 to 0.42 respectively in the analyzed Bhuban shale samples.

5 1059 F a r h a d u z z a m a n, e t a l., I C E R I E Fig.3. (A) Full scan TIC pyrogram of a studied sample (BSH6) which displays unimodal distribution in the n- alkane members; (B) Mass fragmentogram m/z 191 of a studied sample (BSH6) which represents mature oil window; (C) Mass fragmentogram m/z 191 of another studied sample (KSH2) which represents immature oil window; (D) Mass fragmentogram m/z 217 of the studied sample (KSH2) whereas C 29 regular sterane peak is dominant compared to C 27 or C 28 sterane peak. 4.4 Thermal Maturity Thermally immature to mature oil window has been appraised for the investigated Bhuban Formation shales as evidenced by randomly measured mean vitrinite reflectance and T max values. The randomly measured mean vitrinite reflectance value ranged from 0.57 to 0.71 (%VRr) in the analyzed Bhuban samples. It implies that the thermal maturity condition of the analyzed shale samples varies from just pre-oil window to mid-oil window maturity condition for petroleum generation (Waples & Machihara, 1991; Peters & Cassa, 1994). The T max value obtained from SRA ranges from 429 to 441 C indicates that the analyzed Bhuban samples are of thermally immature to peak mature oil window which is in a good agreement with the interpretation made from vitrinite reflectance values. The recorded production index (PI) value ranges 0.17 to 0.25 in the analyzed Bhuban shales and it also suggests the immature to peak mature oil window condition (Peters & Cassa, 1994). The C 32 -homohopanes ratio (22S/(22S+22R)) rises from 0 to about 0.65 while 0.57 to 0.62 is the equilibrium range commonly observed during maturation (Seifert & Moldowan, 1986). The calculated ratio values of for the studied Bhuban shale samples falls within and outside the equilibrium range thus demonstrate the thermal maturity condition been reached partially, i.e., it represents immature to peak mature oil window. The calculated C 30 -moretane/c 30 -hopane ratio of the studied Bhuban shales varies from 0.09 to 0.44 which correspond again to the range of immature-mature thermal maturity condition (Mackenzie et al., 1980). Nonetheless the solid bitumen or bitumen stain is considered as free or expelled petroleum. This type of bitumen stain has been observed in the analyzed shale samples under microscope and it also suggests that the organic matter of the studied shales has already expelled the petroleum in part in the associated petroleum system of Bengal Basin, Bangladesh.

6 1060 F a r h a d u z z a m a n, e t a l., I C E R I E Fig.4. The cross-plot of Tmax and production index shows that the investigated Bhuban shale samples fall within (mostly) and outside the petroleum generation zone (Hakimi et al., 2010; Farhaduzzaman et al., 2013b). 4.5 Petroleum Generation Potential The cross-plot of T max ( C) and production index (PI) depicts that the organic matter of analyzed Bhuban shale samples have already started to generate petroleum (Fig.4) and it has also been supported by the earlier interpretation on the basis of vitrinite reflectance and T max values. The measured SRA T max of the analyzed shale samples varies from 429 to 441 C while the petroleum generation usually starts at the maturity level of 435 C (Peters & Cassa, 1994; Peters & Molodowan, 1993; Peters et al., 2005). The studied Bhuban shales with low to fair TOC ( %), low to fair S 2 values ( mg HC/g TOC), low to moderate total extract (Bhuban ppm), low to fair production index ( ), low to medium hydrocarbon yield ( mg HC/g TOC) and some liptinitic materials suggest poor to fair potential for petroleum generation. The mean vitrinite reflectance value ranged from 0.57 to 0.71 (%VRr) in the analyzed Bhuban shales (while the equilibrium value is 0.60 as stated by Philp, 1985 and Peters & Cassa, 1994) again agrees that the organic matter of the analyzed Bhuban samples have partially achieved the thermal maturity level for petroleum generation. The dominancy of short chain n-alkanes (C 16 -C 20 ) in the gas chromatogram (TIC) of Bhuban Formation indicates the generation of gaseous hydrocarbon together with some condensate. However the liquid hydrocarbon potential in the analyzed shale samples is most likely attributed to the contents of liptinitic macerals. In fact mostly the entire petroleum discovery is natural gas with little amount of oil and condensate in the Bengal Basin, Bangladesh and it is a good agreement with the present interpretation of petroleum generation potential of Bhuban Formation. 5. CONCLUSIONS The organic matter consists of a mixture of Type III/II kerogens with Type III dominant. The investigated Bhuban shale samples were found thermally immature to peak mature oil window for petroleum generation based on the mean vitrinite reflectance and T max values. The production index value and the biomarker parameters of 22S / (22S + 22R) hopane, moretane/hopane ratio and sterane data have also supported this level of thermal maturity.sra and biomarkers data concludes that the analyzed Bhuban shales of Bengal Basin, Bangladesh possess poor to fair quality source potential for petroleum generation. ACKNOWLEDGEMENTS The authors are grateful to Prof. Dr. Md. Hussain Monsur, Chairman of Bangladesh Oil, Gas and Mineral Corporation (BOGMC) for supplying the data/samples for current research. The first author cordially appreciated the cooperation and motivation provided by Prof. Dr. Khalil R. Chowdhury and his colleagues of Jahangirnagar University while continuing this study. The management of Sylhet Gas Fields Ltd, Petrobangla deserves the thanks for the official support to this research (M.F.). The authors also acknowledge the Bright

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