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Petroleum source-rock evaluation of upper Eocene Kopili Shale, Bengal Basin, Bangladesh
International Journal of Coal Geology 172 (2017) 71–79
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Petroleum source-rock evaluation of upper Eocene Kopili Shale, Bengal Basin, Bangladesh Shakura Jahan a, Ashraf Uddin a,⁎, Jack C. Pashin b, Charles E. Savrda a a b
Department of Geosciences, Auburn University, Auburn, AL 36849, United States Boone Pickens School of Geology, Oklahoma State University, Stillwater, OK 74078, United States
a r t i c l e
i n f o
Article history: Received 6 November 2016 Received in revised form 2 February 2017 Accepted 3 February 2017 Available online 04 February 2017 Keywords: Bengal Basin Petroleum source rock Kopili Shale Rock-Eval pyrolysis Vitrinite reflectance Eocene
a b s t r a c t The upper Eocene Kopili Shale occurs throughout the Bengal Basin, including in the northwestern Indian platform and deeper basin areas (e.g., Sylhet Trough) of Bangladesh. Mudrocks presumed to be equivalent to the Kopili Shale in India are known hydrocarbon source rocks. However, the source-rock potential of the Kopili Shale in Bangladesh is not well established, thus prompting the current study of abundance, character, and maturity of organic matter in Kopili Shale samples from the Bengal Basin. Organic petrologic observations and Rock-Eval pyrolysis data indicate that organic matter in the Kopili Shale is largely terrigenous, including an admixture of type I/II (liptodetrinite, cutinite, bituminite), type III (vitrodetrinite), and type IV (inertodetrinite) macerals. Mean vitrinite reflectance values (Ro = 0.86–1.32%) and a single reliable Tmax value (433 °C) indicate that organic matter from all sampled sections is thermally mature. Total organic carbon (TOC) contents of samples from core and outcrop are generally low (b0.6%) and thus reflect relatively poor hydrocarbon-source potential. However, TOC values of ~1.0% and S2 values from one section indicate that source potential is locally higher in the Sylhet Trough area. An understanding of differences in Kopili source-rock potential between India and parts of the Bengal Basin will require more comprehensive comparative facies analyses. © 2017 Published by Elsevier B.V.
1. Introduction The Kopili Shale is a sequence of dark gray to black mudrocks and subordinate marlstones that accumulated in Himalayan foreland basins during the Late Eocene, purportedly in shallow marine settings (Reimann, 1993). The Eocene Kopili Formation of Assam, India, which consists of shallow marine to lagoonal shale, fine-grained sandstone, and marl streaks (Moulik et al., 2009) is a proven source-rock for both oil and gas in the well-defined Sylhet-Kopili/Barail-Tipam composite petroleum system (Wandrey, 2004). Previous workers (e.g., Shamsuddin et al., 2001) have proposed that the Kopili Shale of Bangladesh also may serve as an effective hydrocarbon-source rock that charges known and as-yet undiscovered Tertiary reservoirs in the Bengal Basin. However, owing to limited deep well control and lack of petrologic data, the source-rock potential of the Kopili Shale in this region remains poorly known. To address this problem, we initiated geochemical and petrologic studies of organic matter in core and outcrop samples of Kopili Shale that were obtained from different parts of the Bengal Basin. The objectives of the current paper are to: (1) summarize principal findings of organic carbon, Rock-Eval pyrolysis, and vitrinite ⁎ Corresponding author. E-mail address: [email protected] (A. Uddin).
http://dx.doi.org/10.1016/j.coal.2017.02.002 0166-5162/© 2017 Published by Elsevier B.V.
reflectance analyses; (2) discuss Kopili Shale source-rock potential based on amount, type, and maturity of organic matter; and (3) compare the source potential of the Kopili Shale in the Bengal Basin with that of the equivalent Kopili Formation in Assam, India. 2. Stratigraphy and depositional history of the Bengal Basin 2.1. Stratigraphy The Bengal Basin (Fig. 1) is a large foreland basin in which a relatively thick succession (up to 16 km) of Cenozoic sediment accumulated in response to the uplift and erosion of the Himalayas. The basin is bounded on the west by the Indian craton, on the east by the Indo–Burman ranges, and on the north by the Shillong Plateau, a Precambrian massif adjacent to the Himalayas. The basin extends southward into the Bay of Bengal and is contiguous with the Bengal deep sea fan (Fig. 1). Cenozoic strata within the basin thicken from west to east and from north to south (Uddin and Lundberg, 1999). The Bengal Basin has two broad tectonic provinces separated by a northeast-trending hinge zone (Fig. 1): (1) the northwestern Indian platform, where a relatively thin sedimentary succession (b6 km) overlies basement rocks of the Indian Craton; and (2) the southeastern deep basin, which hosts a thicker Tertiary sedimentary sequence that overlies
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Fig. 1. Map of Bangladesh showing major features of the Bengal Basin and locations of sediment cores (A); and outcrop sections (B) examined in this study. Stratigraphic sections of (A) and (B) are shown in Fig. 2. The hinge zone that separates the stable shelf (Indian Platform) from the deep basin continues to the northeast as the Assam Shelf. Green dots represent locations from which samples have been collected for this study. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
deeply subsided basement of undetermined origin (Fig. 2). In most areas of the basin, Tertiary strata are concealed by the overlying Quaternary section. However, Tertiary strata have been uplifted and exposed locally along the northern and eastern margins of the Sylhet Trough (also referred to as the Surma Basin) of northeastern Bangladesh and in the Chittagong fold belt in eastern Bangladesh. Outcrop studies in these areas, along with limited drilling and geophysical data (Anwar and Husain, 1980), have led to a preliminary understanding of Bengal Basin lithostratigraphy (Khan and Muminullah, 1980; Fig. 2). In the Indian platform area (Fig. 2A), Cenozoic strata overlie Precambrian basement, a thick (up to 955 m) succession of Carboniferous to Late Permian coal-bearing siliciclastic sediments of the Gondwana Group (Kuchma and Paharpur formations), and an ~ 500-m-thick sequence of Cretaceous flood basalts (Rajmahal Traps). The latter are overlain by marine carbonaceous sandstones and subordinate shales and marls of the Paleocene-Eocene Cherra Formation, deep-water nummulitic carbonates of the Middle Eocene Sylhet Limestone, and shallow-marine dark-gray to black, fossiliferous mudstone and subordinate marls of the Upper Eocene Kopili Shale. The Kopili Shale, which is ~30 m thick in the platform area (Banerji, 1981), is in turn overlain by sandstones and/or mudrocks of the Oligocene Barail Formation, Miocene Surma Group, and Plio-Pleistocene Dupa Tila Sandstone. In deep basinal areas, including the Sylhet Trough (Fig. 2B), rocks older and deeper than the Middle Eocene Sylhet Limestone have not been encountered in outcrops or by drilling. Here, the Sylhet Limestone is overlain by 40–90 m of the Kopili Shale, which consists of dark-gray to black, fossiliferous mudrock and marl that grades upward into brown siltstones and very light gray sandstones with localized carbonaceous streaks. The presence of nummulites in the calcareous shale, coupled with the wavy-pinstripe and lenticular bedding, indicates a shallow marine setting with probable tidal influence. The Kopili Shale is overlain by the Oligocene Barail Group, which in the northeastern Bengal Basin is divided into the argillaceous Jenum Formation and the arenaceous Renji Formation (Fig. 2B). The Barail Group, in turn, is overlain by the lower to middle Miocene Surma Group, which includes the Bhuban and Boka Bil formations, both of which comprise alternating mudrock and sandstone packages (Uddin and Lundberg, 1999; Uddin et al., 2010). The Surma Group is unconformably overlain by the upper Miocene to Pliocene Tipam Group, which includes the Tipam Sandstone
Fig. 2. Stratigraphic framework of the Bengal Basin, Bangladesh (modified from Uddin and Lundberg, 1999). Locations of A and B are shown in Fig. 1.
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and Girujan Clay. The latter is unconformably overlain by the Plio–Pleistocene Dupi Tila Sandstone (Hiller and Elahi, 1984). 2.2. Depositional history The stratigraphy of the Bengal Basin reflects a complex series of events that include earlier phases of deposition on once disparately disposed plates (Indian, Tibet and Burma plates) of Gondwanaland, various phases of rifting, plate collision and rotation, and eventual development of the Ganges-Brahmaputra Delta system. Sedimentation rates in the basin were unusually high from the Eocene through the Pliocene (Hiller and Elahi, 1984). In the middle to upper Eocene, deposition was marked by basinward subsidence, causing extensive marine transgression in the western part of the Bengal Basin and rapid deepening in the eastern parts of the basin. Transgression triggered the deposition of thick carbonates—i.e., the Sylhet Limestone—throughout the western shelf area of Bangladesh as well as the area south of the Shillong Plateau (Alam and Curray, 2003). Upper Eocene relative sea-level fall resulted in erosion and the cutting of channels into the carbonate shelf. During subsequent transgression, mudrocks of the Kopili Shale were deposited over the Sylhet Limestone (Roy and Chatterjee, 2015). Following the accumulation of the Kopili Shale and up to the present, deposition in the basin was dominated by the Ganges-Brahmaputra delta and its late Oligocene predecessor. Clastic input shifted with time due to tectonic events that formed basins and changed the drainages of rivers that contribute to the Ganges-Brahmaputra delta and Bengal Fan. The sediment source terrains changed with time due to the counterclockwise rotation of the Indian plate (EMRD, 2011). Uplift of the Shillong plateau in the Pliocene redirected rivers that drained the Himalayas. The Brahmaputra River captured the flow of the Zhangpo River, which had previously flowed into the China Sea (Curiale et al., 2002). The combined contributions of the Ganges, Brahmaputra, and smaller rivers have built the Ganges-Brahmaputra delta and the Bengal fan, filling the basin to an estimated thickness of N16 km (Fig. 2; EMRD, 2011). 3. Overview of the hydrocarbon source rock of the Bengal Basin The Bengal Basin is a prime target for hydrocarbon exploration in Bangladesh. Thus far, economic hydrocarbon accumulations have been discovered only southeast of the hinge zone (Fig. 1) in the Miocene Surma Group. Since commercial production began in 1962, 25 gas fields
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and 1 oil field have been discovered in the Surma Group. As of 2002, 69 wells in 22 gas fields had estimated proven reserves of 15.5 Tcf (Imam and Hussain, 2002; Alam et al., 2006). Reservoirs and seals in this petroleum system are sand-dominated units (with porosity of 10–20%; Uddin, 1987) and shale units, respectively, in the Boka Bila and Bhuban formations. Hydrocarbon traps are primarily anticlinal (Imam and Hussain, 2002; Alam et al., 2006), although some stratigraphic traps may exist, particularly in the southern part of the basin (Imam, 2012). The Oligocene Jenum Shale (Barail Group), with TOC contents of 1.4– 2.7%, is generally regarded as the principal source rock for this hydrocarbon system (Ismail and Shamsuddin, 1991; Curiale et al., 2002). Based on thermal modeling, the Jenum Formation reached the oil window ~28 Ma and the gas window ~5 Ma, and may still be generating hydrocarbons today (Shamsuddin, 1993; Shamsuddin and Yakovlev, 1987). While the Jenum Formation is likely the major source rock for the Surma Group oil and gas reservoirs, older shale units, including the Eocene Kopili Shale, also may have served as sources of hydrocarbons in these and other as yet unidentified reservoirs in the Bengal Basin (Shamsuddin et al., 2001). Thermal modeling (Curiale et al., 2002) indicates that, in the Surma Basin area, hydrocarbon generation from the Kopili Shale could have begun as early as ~ 32 Ma. However, to date, the source-rock potential and thermal maturity of the Kopili Shale have not been directly assessed and, thus, remain controversial (Imam and Hussain, 2002). The organic geochemical and petrographic studies described below were designed to test the hydrocarbon-source potential of the Kopili Shale in both the Indian platform and deep basin areas of the Bengal Basin. 4. Study location and methods Twenty-seven samples were collected to determine the source-rock potential of the Kopili Shale. Twenty-four of these were collected from outcrops of the Kopili Shale exposed on the northern margin of the Sylhet Trough in the northeastern part of the Bengal Basin (Figs. 1 and 3), and one sample was collected from cuttings from each of three wells in the northwestern Indian platform part of the basin (samples GDH-31, GDH-51, and GDH-55; Fig. 1). Of the 24 surface samples, eleven were collected at ~4–6 m intervals at the Dauki River section (samples D1–D11), five were collected at ~ 0.5–1.0 m intervals at the Tamabil section (samples T1–T5), and eight were collected at ~3–4 m intervals at the Sripur sections (samples S1–S8). The stratigraphic positions of samples are provided in Table 1.
Fig. 3. Map of outcrop sampling sites (white dots) in the northeastern study area, Sylhet Trough, Bengal Basin, Bangladesh. The Kopili Formation in the upper Assam is about 100–200 km away from Sripur section, northeast Bengal Basin, Bangladesh (Shamsuddin, 1993; Wandrey, 2004).
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Organic petrologic analysis of dispersed organic matter was performed on six subsamples (D2, D7, D10, T2, S6, and GDH-51). Shale subsamples were crushed, and particles passing the 20-mesh screen (b0.85 mm) were used to form ~3-cm-diameter polished pellets. Petrologic analyses of the pellets were performed in the Unconventional Reservoir/Basin Research Laboratory in the Boone Pickens School of Geology at Oklahoma State University using a Nikon petrographic microscope and a Craic Technologies 308PV microphotospectrometer driven by CoalPro III software. Analyses were conducted using oil-immersion objectives with magnification of 50 × and 100 ×. Spinel with Ro = 0.421%, yttrium-aluminum-garnet with reflectance Ro = 0.901%, and gadolinium-gallium-garnet with reflectance Ro = 1.733% were used as standards. For each sample, twenty-five dispersed organic particles were identified under reflected white light, and the fluorescence properties of liptinite, bituminite, and vitrinite macerals were measured under blue light excitation. Reflectance of all dispersed organics was measured and plotted, and vitrinite reflectance (Ro), and the reflectance of other macerals, were used to assess thermal maturity. Rock-Eval pyrolysis was completed on the same six samples employed for organic petrology. Analyses were performed using a Rock-Eval 6 instrument at ActLabs. Pyrolysis data—total organic carbon (TOC), hydrogen index (HI), oxygen index (OI), and Tmax (temperature of maximum pyrolysate yield)—were used to the extent possible to assess organic richness, thermal maturity, and petroleum source potential. The remaining eighteen samples were subjected to TOC analysis using an Elementar Vario Macro NCS Analyzer at the soil testing laboratory in the Department of Agronomy and Soils at Auburn University. 5. Results and implications 5.1. Organic petrologic analysis Organic petrologic analysis of the Kopili Shale reveals the presence of all major maceral groups–liptinite, bituminite, vitrinite, and inertinite
(Figs. 4 and 5). The two most common liptinite group macerals observed are cutinite and liptodetrinite. In reflected white light, cutinite macerals are dark in color (Fig. 4A) and give low reflectance values in the range of 0.0–0.5% Ro; they are weakly fluorescent with a brown color or are non-fluorescent (Fig. 4B). Liptodetrinite macerals also have low reflectance (Fig. 4C) and are weakly fluorescent to non-fluorescent. Bituminite macerals include brightly fluorescing exsudatinite (Fig. 4E and F), its diagenetic by-product micrinite (Fig. 4H), and other weakly to nonfluorescent particles (Fig. 4D). Vitrinite macerals, identified by their light gray color, plant-cell structures (Fig. 4I), and reflectance in the range of 0.8–1.5%, are dominated by non-fluorescent vitrodetrinite (Fig. 4J). Inertinite macerals include common inertodetrinite (Fig. 4K) and micrinite (Fig. 4H), and rare high-reflectance fusinite and semifusinite (Fig. 4L).
5.2. Hydrocarbon generation potential All data obtained from TOC analysis, Rock-Eval pyrolysis, and vitrinite reflectance studies are reported in Table 1. Results bearing on the three parameters governing hydrocarbon generative potential—organic richness, type, and maturity (Tissot and Welte, 1978)—are addressed separately below.
5.2.1. Organic richness Based on TOC content alone (Table 1), most of the sampled Kopili Shale intervals have relatively poor potential for hydrocarbon generation. This is also reflected in very low S2 values from Rock-Eval pyrolysis of five of the six samples analyzed (Table 1; see pyrograms Fig. 6A–E). However, the relatively high TOC contents of the Sripur section samples, in conjunction with a moderate S2 peak for the same section (sample S6, Table 1, Fig. 6F) indicate that, at least locally, intervals of the Kopili Shale may have fair potential for hydrocarbon generation.
Table 1 Sample site, stratigraphic position, and geochemical results of Kopili Shale. Sample site
Sample no.
Stratigraphic height
TOC TOC (wt.%) avg. (wt.%)
Dauki River
D5 D6 D7 D8 D9 D10 D11 D4 D3 D2 D1 T1 T2 T3 T4 T5 S1 S2 S3 S4 S5 S6 S7 S8 GDH-31 GDH-51 GDH-55
4 m from base 8m 11 m 14 m 18 m 22 m 26 m 30 m 33 m 36 m 39 m 0.5 m from base 1.5 m 2.5 m 3m 3.5 m 3 m from base 6m 10 m 13 m 16 m 19 m 22 m 25 m 796 m depth 431 m depth 358 m depth
0.45 0.53 0.64a 0.46 0.7 0.55a 0.66 0.61 0.76 0.83a 0.4 0.45 0.41a 0.35 0.36 0.34 1.43 1.07 0.77 1.03 1.2 0.97a 1.2 0.56 0.5 0.52a 0.45
Tamabil
Sripur
Core
a b
TOC data derived from Rock-Eval pyrolysis. Unreliable Tmax; low S2 peak.
Rock-Eval pyrolysis S1 mg HC/g rock
S2 mg HC/g rock
S3 mg CO2/g rock
HI mg HC/g TOC
OI mg CO2/g TOC
Tmax (°C)
Mean Ro (%) (each sample)
0.6
Mean Ro (%) (each section)
1.15 0.01
0.04
0.41
6
64
431b 1.02
0.02
0.1
0.22
18
40
436b 1.12
0.02
0.1
0.19
12
23
443b 1.32
0.01
0.08
0.26
21
68
443b 1.15
0.4
1.15
1
0.86
0.03
0.7
0.16
72
16
433
0.86
0.01
0.14
0.99
27
190
506b 1.24
0.5
1.24
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5.2.2. Organic matter type Information on the organic matter or kerogen types is commonly derived based on relationships between hydrogen and oxygen indices (HI and OI) determined from Rock-Eval pyrolysis. However, for all but one sample, S2 peaks for Kopili Shale samples are too low to yield reliable HI and OI values (Table 1). As indicated in the modified Van Krevelen diagram in Fig. 7, Sample S6 from the comparatively organic-rich Sripur section plots as gas-prone Type III kerogen.
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Organic petrologic analyses provided a more reliable assessment of organic matter type (Taylor et al., 1998). Examination under reflected white and blue light indicates a range in maceral types, including inertinite, vitrinite, bituminite, and liptinite (Fig. 4). Inertodetrinites are particularly common in the northwest sample (GDH-51; Fig. 5A) but are also recognized in samples from the Dauki River section (sample D2 and D7; Fig. 5C and D), suggesting Type IV kerogen. Vitrinite macerals (Fig. 4I) were identified in all
Fig. 4. Photomicrographs of the Kopili Shale from Bengal Basin, shot under white (A, C, H, I, K, and L) and blue (B, D–G, and J) light excitation. (A, B) Cutinite. (C) Liptodetrinite. (D) Weakly fluorescing or nonfluorescent bituminite. (E, F) Brightly fluorescing bituminite (exsudatinite). (G) Weakly to non-fluorescent bituminite with inclusions of brightly fluorescing alginite. (H) Micrinites over a dark bituminite. (I) Vitrinite. (J) Nonfluorescent vitrinite. (K,L) Inertodetrinite. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
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Fig. 5. Histograms showing reflectance, Ro (%), of the different macerals in Kopili Shale from northwest (A) and northeast (B-F), Bengal Basin, Bangladesh.
six samples (Fig. 5), which indicate the presence of Type III kerogen. Notably, some samples from the northeast and northwest contain brightly fluorescing exudatinite (Fig. 4E and F), indicating the presence of Type II kerogen. Liptodetrinite and cutinite macerals are present in all samples, representing Type I kerogen. Taken together, Rock-Eval pyrolysis data and petrographic observations indicate that organic matter in Kopili Shale is predominantly terrigenous in origin and represents an admixture of Type IV, Type III, and Type I/II kerogen. Vitrinite macerals of woody plant origin (Type III kerogen) tend to be more gas prone (Taylor et al., 1998). However, given the presence of cutinite and brightly fluorescing bitumen in some samples of the Kopili Shale, the potential for minor oil generation from Type I/II kerogen cannot be excluded altogether.
5.2.3. Maturation state of organic matter Thermal maturity of organic matter was assessed based on Tmax data derived from Rock-Eval pyrolysis, vitrinite reflectance (Ro) analyses, and fluorescence properties of organic macerals. Given generally low S2 values for all but the more carbonaceous Kopili Shale sample S6, almost all of the Tmax values reported in Table 1 are unreliable. The Tmax value of 433 °C for sample S6 suggests that the Kopili Shale at the Sripur section is immature to early mature. The presence of weakly to non-fluorescent liptinite macerals in the Kopili Shale as well as the high standard deviation (Fig. 5) of liptinite reflectance suggest a thermally mature source-rock. Bituminite in the Kopili Shale displays alteration from bituminite enclosing liptodetrinite/alginite at early mature stage (Fig. 4G; sample S6) to
micrinitised bituminite at mature stage (gas window; Fig. 4H). This type of alteration, including the presence of brightly fluorescing exsudatinites (Fig. 4E and F), is generally regarded as a result of liquid hydrocarbon generation from thermally cracked bituminite (Teichmüller, 1974). The presence of weakly to non-fluorescent bituminite (Fig. 4D) and micrinite (Fig. 4H) in the Kopili Shale also indicates a thermally mature source rock in these locations. Mean vitrinite reflectance (Ro) values (Table 1; Fig. 5) for all analyzed samples range from 0.86% to 1.32%. Ro values for sample GDH51 from the Indian platform and all but one sample from the northeastern outcrops range from 1.02 to 1.32%, indicating that the Kopili Shale in these areas is mature and falls within the oil to wet-gas generation windows (Table 2). In contrast, the lower Ro value for the S6 sample (Ro = 0.86%) indicates that the Sripur section had matured to the peak oil window prior to uplift. The presence of non-fluorescent vitrinite in Kopili Shale samples also support that the shale is mature. The higher reflectance of inertinite macerals in incident white light, the lack of fluorescence in blue light excitation, and the presence of micrinite over a degraded bituminite maceral (Fig. 4H) all suggest that the Kopili Shale has matured to the peak oil window.
6. Discussion 6.1. Source-rock potential of the Kopili Shale, Bengal Basin The results of the current study suggest that the Kopili Shale in most areas of the Bengal Basin has limited potential as a hydrocarbon source
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rock. Organic matter in the Kopili Shale of the northwest Indian Platform area is thermally mature despite relatively shallow burial depths. This is consistent with relatively high average geothermal gradients (21.1–31.6 °C/km) in the area (Hossain, 2009), which may be related to heat supplied by the Rajmahal volcanic trap that lies beneath this part of India. However, given its relatively low TOC content (b0.6%) and limited thickness (~30 m), the Kopili Shale in this region has very poor hydrocarbon-generation potential. Rather, the Kopili Shale here likely plays a more significant role as the seal rock for the so-called Cherra-Sylhet-Kopili petroleum system in western Bangladesh (Shamsuddin et al., 2001). Organic matter from surface samples of the Kopili Shale in the Sylhet trough region also is thermally mature, generally falling in the oil-generation window. Similar maturation is expected in the subsurface to the south and east, given average geothermal gradients for the Sylhet Trough region (15.8–30 °C/km; Hossain, 2009) and the depth of burial
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of the Kopili Shale (N6 km) (Shamsuddin et al., 2001; Curiale et al., 2002). However, as with the Indian Platform samples, TOC contents and thus hydrocarbon source potential of the Kopili Shale in most sampled areas of Sylhet Trough are generally low. As the exception, organic contents of Kopili Shale samples from the Sripur section are comparatively high (mean TOC = 1.0%) and include some brightly fluorescing bitumen indicative of possible oil expulsion. Hence, at least locally in the Sylhet Trough region, the Kopili Shale has fair potential as a hydrocarbon source. Notably, the Sripur section lies geographically closest (150–200 km) to upper Assam, where the Kopili Formation is an established source rock. 6.2. Comparison with the Kopili Formation The Kopili Formation in Assam, India has been established as a source rock for oil and gas in the Sylhet-Kopili/Barail-Tipam composite
Fig. 6. Pyrograms showing S2 peaks of northwestern (A) and northeastern (B\ \F) Kopili Shale, Bengal Basin, Bangladesh. Free hydrocarbons are measured by the S1 peak and the hydrocarbons and non-hydrocarbons cracked from the kerogen during rock-eval pyrolysis (and, in some cases, the high-molecular weight soluble components in the extractable organic matter) are measured by the S2 peak. The CO and CO2 liberated upon pyrolysis of the sample from 300 °C to 390 °C, which include CO2 liberated from the organic matter and, in some cases, CO2 liberated from labile carbonates, are recorded as S3. Pyrolysis results were computed to determine amounts of pyrolyzable carbon, residual carbon, mineral carbon, and TOC content.
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The greater thickness of the Kopili Formation results in overall greater organic richness (thickness * TOC) and likely contributes to its greater hydrocarbon-source potential (Naidu and Panda, 1997). Nonetheless, there are likely other as yet unrecognized factors that have operated to control differences in abundance, type and quality of organic matter between Assam and the Bengal Basin. Both the Kopili Shale and the Kopili Formation have been attributed to shallow marine deposition (Reimann, 1993; Moulik et al., 2009; this study). However, paleoenvironmental interpretations thus far have been based on cursory lithofacies analyses. Given the disparate thicknesses of these Eocene mudrock units, these areas likely experienced significantly different basin histories controlled by tectonics, paleogeography, paleoceanographic conditions, and paleoenviron ments of deposition. Understanding how these factors may have controlled source-rock potential will require more detailed analyses of subsurface stratigraphy, depositional facies, and structural geology, including within the poorly studied region that separates the Sylhet Trough and Assam regions. 7. Conclusions
Fig. 7. Pseudo van Krevelen diagram, showing the type of kerogen present in Kopili Shale from Bengal Basin. Green and red dots represent reliable and unreliable HI and OI data of Kopili Shale from Rock-Eval pyrolysis. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
petroleum system (Wandrey, 2004). The Kopili Formation in many ways is similar to the Kopili Shale at the Sripur section of the Bengal Basin (Table 2). The Kopili Formation of Assam is moderately carbonaceous (TOC ranges from 0.5 to 1.5%; Wandrey, 2004) and is characterized by Type II (oil-prone) and Type III (gas-prone) kerogen that lies in the oil generation window; vitrinite reflectance (Ro) ranges from 0.5 to 0.7%, and Tmax values range from 410 to 450 °C (Naidu and Panda, 1997). The primary difference thus far recognized between the Kopili Shale of the Bengal Basin and the Kopili Formation relates to stratigraphic thickness. While the Kopili Shale in the Bengal Basin typically is 30–40 m thick, the thickness of the Kopili Formation at its type locality is an order of magnitude greater (~ 500 m thick; Mandal, 2009).
Results from geochemical analyses in the current study suggest that the upper Eocene Kopili Shale is thermally mature. Vitrinite reflectance values for Kopili Shale samples from the northwest and two sections from the northeastern Bengal Basin lie in the oil to wet-gas generation windows. In contrast, samples from the Sripur section of the Bengal Basin are immature to early mature and lie in the peak oil window. The types of kerogen (Type-III and Type-II) in the Kopili Shale suggest the potential for both gas and minor oil expulsion. However, with the exception of the Sripur section, organic contents are relatively low. Hence, the potential of the Kopili Shale as a source rock for Eocene-Oligocene or Miocene petroleum systems in the Bengal Basin, Bangladesh, is regarded as poor. Evaluating apparent differences in source-rock potential between the Kopili Shale in the Bengal Basin and the thicker, relatively more carbonaceous Kopili Formation in Assam, India will require further comparative facies analyses. Acknowledgments This research was possible because of financial support from the American Association of Petroleum Geologists, the Geological Society of America, and the Geosciences Advisory Board of Auburn University. We thank Syed Humayun Akhter for his support with logistics during the field investigation, and Shajadul Thandu and Abdul Malek for assisting in sample collection from the Sylhet area. Discussion with Manowar Ahmed was helpful. We thank journal reviewer Joe Curiale for his constructive suggestions which significantly improved the manuscript.
Table 2 Comparison of source-rock potential of Kopili Shale in Bengal Basin and Assam Shelf.
Geochemical parameters Thickness (m) Organic richness
TOC (wt.%)
Organic matter type
Hydrogen index (HI) and/or maceral types
Maturity
Tmax (°C) Vitrinite reflectance (% Ro)
Generalized HC zone
Tmax and Ro
a
Unreliable Tmax; low S2 peak.
Northwest (Stable Shelf) Bengal Basin
Northeast (Sylhet Trough) Bengal Basin
Assam Shelf Assam, India
30–60 (drilled) 0.45–0.52 (poor) Type-I,II,III, and IV Oil and gas-prone 506a 1.24% Mature Wet-gas window
40–90 (outcrop) 0.34–1.43 (poor to fair) Type-I,II,III, and IV Oil and gas-prone (431–443)a; (S6 = 433) 0.86–1.15% Mature Peak oil window
300–700 (outcrop) 0.50–1.50 (fair to good) Type-II–III Oil and gas-prone 410–450 0.5–0.7% Immature to early mature Peak oil window
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References Alam, M.M., Curray, J.R., 2003. The curtain goes up on a sedimentary basin in south-central Asia: unveiling the sedimentary geology of the Bengal Basin of Bangladesh. Sediment. Geol. 155, 175–178. Alam, M.N., Nakayama, K., Toshifumi, M., Yohroh, T., 2006. Petroleum system of Bengal Basin in Bangladesh. Proceedings of the 6th International Conference & Exposition on Petroleum Geophysics, Kolkata, India, pp. 889–896. Anwar, J., Husain, M., 1980. Origin of petroleum and suitability of Bangladesh geological environment for the occurrence of oil and gas. Seminar and Exhibition, 08–12 October, 1980 (96 p). Banerji, K.R., 1981. Cretaceous-Eocene sedimentation, tectonism and biofacies in the Bengal Basin, India. Palaeogeogr. Palaeoclimatol. Palaeoecol. 34, 57–85. Curiale, J.A., Covington, G.H., Shamsuddin, A.K.M., 2002. Origin of petroleum in Bangladesh. AAPG Bull. 86, 625–652. Energy and Mineral Resources Division, 2011. Bangladesh petroleum potential and resource assessment 2010. Hydrocarbon Unit, Energy and Mineral Resources Division (Phase-II), ADB Grant 0019: GTDP: Government of the People's Republic of Bangladesh. Gustavson Associates (331 p). Hiller, K., Elahi, M., 1984. Structural development and hydrocarbon entrapment in the Surma Basin, Bangladesh (northwest Indo–Burman Fold belt). Proc. 4th Offshore Southeast Asia Conference, Singapore, pp. 650–663. Hossain, M.S., 2009. Overpressure in the Eastern Bengal Basin, Bangladesh, and its Relation to Compressional Tectonics. Unpublished M.S. Thesis. Auburn University, Auburn (102 p). Imam, M.B., Hussain, M., 2002. A review of hydrocarbon habitats in Bangladesh. J. Pet. Geol. 25, 31–52. Imam, B., 2012. Energy Resources of Bangladesh. University Grants Commission of Bangladesh (280 p). Ismail, M., Shamsuddin, A.H.M., 1991. Organic matter maturity and its relation with time, temperature and depth in the Bengal foredeep, Bangladesh. J. SE Asian Earth Sci. 5, 381–390. Khan, M.R., Muminullah, M., 1980. Stratigraphy of Bangladesh: Petroleum and Mineral Resources of Bangladesh, Seminar and Exhibition. Government of the People's Republic of Bangladesh, Dhaka, pp. 35–40. Mandal, S., 2009. Sedimentation and tectonics of lower Cenozoic sequences from southeast of Shillong plateau, India. Provenance History of the Assam-Bengal System, Eastern Himalayas. Auburn University, Auburn, AL Unpublished M.S. Thesis. (136 p).
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Moulik, S.K.R., Rawat, H.J.S., Akhtar, M.D.S., Mayor, S., Asthana, M., 2009. Sand distribution pattern and depositional model of Kopili formation (Eocene) with special reference to sequence stratigraphic framework from North Assam shelf, Assam-Arakan Basin, India. Discovery Article 50196. Oil and Natural Gas Corporation Limited (35 p). Naidu, B.D., Panda, B.K., 1997. Regional source rock mapping in Upper Assam shelf. Proceedings of the Second International Petroleum Conference and Exhibition. PETROTECH-97, New Delhi vol. 1, pp. 350–364. Reimann, K.U., 1993. Geology of Bangladesh. Borntraeger, Berlin, p. 154. Roy, A.B., Chatterjee, A., 2015. Tectonic framework and evolutionary history of the Bengal Basin in the Indian subcontinent. Curr. Sci. 109, 271–279. Shamsuddin, A.H.M., Yakovlev, G.E., 1987. Vertical catagenetic zonation of organic matter of sedimentary cover of the Bengal foredeep. In: Kumar, R.K., Dwivedi, P., Banerjie, V., Gupta, V. (Eds.), Petroleum Geochemistry and Exploration in the Afro-Asian Region. Balkema, Rotterdam, pp. 155–162. Shamsuddin, A.H.M., 1993. Study of Bengal basin including geochemical characteristics of kerogens, oils and ID basin modeling (GENEX). Post-doctoral research work, Institut Francais du Petrole, Paris, France. Indian J. Geol. 69, 93–121. Shamsuddin, A.H.M., Brown, T.A., Lee, S., Curiale, J., 2001. Petroleum systems of Bangladesh. Proceedings of the 13th Offshore South Asia (SEAPEX) Conference, pp. 85–103. Taylor, G.H., Teichmuller, M., Davis, A., Diessel, C.F.K., Littke, R., Robert, P., 1998. Organic Petrology. Borntraeger, Berlin, Stuttgart 3-443-01036-9, p. 704. Teichmuller, M., 1974. Entstehung und Veranderung bituminser substanzen in Kohlen in Beziehung zur Enstehung und Umwandlung des Erdols-Fortschr. Geological Rheinld. U. Westf. vol. 24 (65 p). Tissot, B., Welte, D.H., 1978. Petroleum Formation and Occurrence. Springer, Berlin Heidelberg-New York, p. 538. Uddin, A., 1987. A Geological Evaluation of the Hydrocarbon Potential of the Ganges/Bengal Delta of Bangladesh. M.S. Thesis. University of Hawaii, Honolulu, Hawaii (167 p). Uddin, A., Lundberg, N., 1999. A paleo-Brahmaputra? Subsurface lithofacies analysis of Miocene deltaic sediments in the Himalayan-Bengal system, Bangladesh. Sediment. Geol. 123, 239–254. Uddin, A., Hames, W.E., Zahid, K.M., 2010. Laser 40Ar/39Ar age constraints on Miocene sequences from the Bengal Basin: implications for middle Miocene denudation of the eastern Himalayas. J. Geophys. Res. 115:B07416. http://dx.doi.org/10.1029/ 2009JB006401. Wandrey, C.J., 2004. Sylhet-Kopili/Barail-Tipam composite total petroleum system, Assam Geologic Province, India. U.S. Geol. Surv. Bull. 2208-D (25 p).
Contents lists available at ScienceDirect
International Journal of Coal Geology journal homepage: www.elsevier.com/locate/ijcoalgeo
Petroleum source-rock evaluation of upper Eocene Kopili Shale, Bengal Basin, Bangladesh Shakura Jahan a, Ashraf Uddin a,⁎, Jack C. Pashin b, Charles E. Savrda a a b
Department of Geosciences, Auburn University, Auburn, AL 36849, United States Boone Pickens School of Geology, Oklahoma State University, Stillwater, OK 74078, United States
a r t i c l e
i n f o
Article history: Received 6 November 2016 Received in revised form 2 February 2017 Accepted 3 February 2017 Available online 04 February 2017 Keywords: Bengal Basin Petroleum source rock Kopili Shale Rock-Eval pyrolysis Vitrinite reflectance Eocene
a b s t r a c t The upper Eocene Kopili Shale occurs throughout the Bengal Basin, including in the northwestern Indian platform and deeper basin areas (e.g., Sylhet Trough) of Bangladesh. Mudrocks presumed to be equivalent to the Kopili Shale in India are known hydrocarbon source rocks. However, the source-rock potential of the Kopili Shale in Bangladesh is not well established, thus prompting the current study of abundance, character, and maturity of organic matter in Kopili Shale samples from the Bengal Basin. Organic petrologic observations and Rock-Eval pyrolysis data indicate that organic matter in the Kopili Shale is largely terrigenous, including an admixture of type I/II (liptodetrinite, cutinite, bituminite), type III (vitrodetrinite), and type IV (inertodetrinite) macerals. Mean vitrinite reflectance values (Ro = 0.86–1.32%) and a single reliable Tmax value (433 °C) indicate that organic matter from all sampled sections is thermally mature. Total organic carbon (TOC) contents of samples from core and outcrop are generally low (b0.6%) and thus reflect relatively poor hydrocarbon-source potential. However, TOC values of ~1.0% and S2 values from one section indicate that source potential is locally higher in the Sylhet Trough area. An understanding of differences in Kopili source-rock potential between India and parts of the Bengal Basin will require more comprehensive comparative facies analyses. © 2017 Published by Elsevier B.V.
1. Introduction The Kopili Shale is a sequence of dark gray to black mudrocks and subordinate marlstones that accumulated in Himalayan foreland basins during the Late Eocene, purportedly in shallow marine settings (Reimann, 1993). The Eocene Kopili Formation of Assam, India, which consists of shallow marine to lagoonal shale, fine-grained sandstone, and marl streaks (Moulik et al., 2009) is a proven source-rock for both oil and gas in the well-defined Sylhet-Kopili/Barail-Tipam composite petroleum system (Wandrey, 2004). Previous workers (e.g., Shamsuddin et al., 2001) have proposed that the Kopili Shale of Bangladesh also may serve as an effective hydrocarbon-source rock that charges known and as-yet undiscovered Tertiary reservoirs in the Bengal Basin. However, owing to limited deep well control and lack of petrologic data, the source-rock potential of the Kopili Shale in this region remains poorly known. To address this problem, we initiated geochemical and petrologic studies of organic matter in core and outcrop samples of Kopili Shale that were obtained from different parts of the Bengal Basin. The objectives of the current paper are to: (1) summarize principal findings of organic carbon, Rock-Eval pyrolysis, and vitrinite ⁎ Corresponding author. E-mail address: [email protected] (A. Uddin).
http://dx.doi.org/10.1016/j.coal.2017.02.002 0166-5162/© 2017 Published by Elsevier B.V.
reflectance analyses; (2) discuss Kopili Shale source-rock potential based on amount, type, and maturity of organic matter; and (3) compare the source potential of the Kopili Shale in the Bengal Basin with that of the equivalent Kopili Formation in Assam, India. 2. Stratigraphy and depositional history of the Bengal Basin 2.1. Stratigraphy The Bengal Basin (Fig. 1) is a large foreland basin in which a relatively thick succession (up to 16 km) of Cenozoic sediment accumulated in response to the uplift and erosion of the Himalayas. The basin is bounded on the west by the Indian craton, on the east by the Indo–Burman ranges, and on the north by the Shillong Plateau, a Precambrian massif adjacent to the Himalayas. The basin extends southward into the Bay of Bengal and is contiguous with the Bengal deep sea fan (Fig. 1). Cenozoic strata within the basin thicken from west to east and from north to south (Uddin and Lundberg, 1999). The Bengal Basin has two broad tectonic provinces separated by a northeast-trending hinge zone (Fig. 1): (1) the northwestern Indian platform, where a relatively thin sedimentary succession (b6 km) overlies basement rocks of the Indian Craton; and (2) the southeastern deep basin, which hosts a thicker Tertiary sedimentary sequence that overlies
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Fig. 1. Map of Bangladesh showing major features of the Bengal Basin and locations of sediment cores (A); and outcrop sections (B) examined in this study. Stratigraphic sections of (A) and (B) are shown in Fig. 2. The hinge zone that separates the stable shelf (Indian Platform) from the deep basin continues to the northeast as the Assam Shelf. Green dots represent locations from which samples have been collected for this study. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
deeply subsided basement of undetermined origin (Fig. 2). In most areas of the basin, Tertiary strata are concealed by the overlying Quaternary section. However, Tertiary strata have been uplifted and exposed locally along the northern and eastern margins of the Sylhet Trough (also referred to as the Surma Basin) of northeastern Bangladesh and in the Chittagong fold belt in eastern Bangladesh. Outcrop studies in these areas, along with limited drilling and geophysical data (Anwar and Husain, 1980), have led to a preliminary understanding of Bengal Basin lithostratigraphy (Khan and Muminullah, 1980; Fig. 2). In the Indian platform area (Fig. 2A), Cenozoic strata overlie Precambrian basement, a thick (up to 955 m) succession of Carboniferous to Late Permian coal-bearing siliciclastic sediments of the Gondwana Group (Kuchma and Paharpur formations), and an ~ 500-m-thick sequence of Cretaceous flood basalts (Rajmahal Traps). The latter are overlain by marine carbonaceous sandstones and subordinate shales and marls of the Paleocene-Eocene Cherra Formation, deep-water nummulitic carbonates of the Middle Eocene Sylhet Limestone, and shallow-marine dark-gray to black, fossiliferous mudstone and subordinate marls of the Upper Eocene Kopili Shale. The Kopili Shale, which is ~30 m thick in the platform area (Banerji, 1981), is in turn overlain by sandstones and/or mudrocks of the Oligocene Barail Formation, Miocene Surma Group, and Plio-Pleistocene Dupa Tila Sandstone. In deep basinal areas, including the Sylhet Trough (Fig. 2B), rocks older and deeper than the Middle Eocene Sylhet Limestone have not been encountered in outcrops or by drilling. Here, the Sylhet Limestone is overlain by 40–90 m of the Kopili Shale, which consists of dark-gray to black, fossiliferous mudrock and marl that grades upward into brown siltstones and very light gray sandstones with localized carbonaceous streaks. The presence of nummulites in the calcareous shale, coupled with the wavy-pinstripe and lenticular bedding, indicates a shallow marine setting with probable tidal influence. The Kopili Shale is overlain by the Oligocene Barail Group, which in the northeastern Bengal Basin is divided into the argillaceous Jenum Formation and the arenaceous Renji Formation (Fig. 2B). The Barail Group, in turn, is overlain by the lower to middle Miocene Surma Group, which includes the Bhuban and Boka Bil formations, both of which comprise alternating mudrock and sandstone packages (Uddin and Lundberg, 1999; Uddin et al., 2010). The Surma Group is unconformably overlain by the upper Miocene to Pliocene Tipam Group, which includes the Tipam Sandstone
Fig. 2. Stratigraphic framework of the Bengal Basin, Bangladesh (modified from Uddin and Lundberg, 1999). Locations of A and B are shown in Fig. 1.
S. Jahan et al. / International Journal of Coal Geology 172 (2017) 71–79
and Girujan Clay. The latter is unconformably overlain by the Plio–Pleistocene Dupi Tila Sandstone (Hiller and Elahi, 1984). 2.2. Depositional history The stratigraphy of the Bengal Basin reflects a complex series of events that include earlier phases of deposition on once disparately disposed plates (Indian, Tibet and Burma plates) of Gondwanaland, various phases of rifting, plate collision and rotation, and eventual development of the Ganges-Brahmaputra Delta system. Sedimentation rates in the basin were unusually high from the Eocene through the Pliocene (Hiller and Elahi, 1984). In the middle to upper Eocene, deposition was marked by basinward subsidence, causing extensive marine transgression in the western part of the Bengal Basin and rapid deepening in the eastern parts of the basin. Transgression triggered the deposition of thick carbonates—i.e., the Sylhet Limestone—throughout the western shelf area of Bangladesh as well as the area south of the Shillong Plateau (Alam and Curray, 2003). Upper Eocene relative sea-level fall resulted in erosion and the cutting of channels into the carbonate shelf. During subsequent transgression, mudrocks of the Kopili Shale were deposited over the Sylhet Limestone (Roy and Chatterjee, 2015). Following the accumulation of the Kopili Shale and up to the present, deposition in the basin was dominated by the Ganges-Brahmaputra delta and its late Oligocene predecessor. Clastic input shifted with time due to tectonic events that formed basins and changed the drainages of rivers that contribute to the Ganges-Brahmaputra delta and Bengal Fan. The sediment source terrains changed with time due to the counterclockwise rotation of the Indian plate (EMRD, 2011). Uplift of the Shillong plateau in the Pliocene redirected rivers that drained the Himalayas. The Brahmaputra River captured the flow of the Zhangpo River, which had previously flowed into the China Sea (Curiale et al., 2002). The combined contributions of the Ganges, Brahmaputra, and smaller rivers have built the Ganges-Brahmaputra delta and the Bengal fan, filling the basin to an estimated thickness of N16 km (Fig. 2; EMRD, 2011). 3. Overview of the hydrocarbon source rock of the Bengal Basin The Bengal Basin is a prime target for hydrocarbon exploration in Bangladesh. Thus far, economic hydrocarbon accumulations have been discovered only southeast of the hinge zone (Fig. 1) in the Miocene Surma Group. Since commercial production began in 1962, 25 gas fields
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and 1 oil field have been discovered in the Surma Group. As of 2002, 69 wells in 22 gas fields had estimated proven reserves of 15.5 Tcf (Imam and Hussain, 2002; Alam et al., 2006). Reservoirs and seals in this petroleum system are sand-dominated units (with porosity of 10–20%; Uddin, 1987) and shale units, respectively, in the Boka Bila and Bhuban formations. Hydrocarbon traps are primarily anticlinal (Imam and Hussain, 2002; Alam et al., 2006), although some stratigraphic traps may exist, particularly in the southern part of the basin (Imam, 2012). The Oligocene Jenum Shale (Barail Group), with TOC contents of 1.4– 2.7%, is generally regarded as the principal source rock for this hydrocarbon system (Ismail and Shamsuddin, 1991; Curiale et al., 2002). Based on thermal modeling, the Jenum Formation reached the oil window ~28 Ma and the gas window ~5 Ma, and may still be generating hydrocarbons today (Shamsuddin, 1993; Shamsuddin and Yakovlev, 1987). While the Jenum Formation is likely the major source rock for the Surma Group oil and gas reservoirs, older shale units, including the Eocene Kopili Shale, also may have served as sources of hydrocarbons in these and other as yet unidentified reservoirs in the Bengal Basin (Shamsuddin et al., 2001). Thermal modeling (Curiale et al., 2002) indicates that, in the Surma Basin area, hydrocarbon generation from the Kopili Shale could have begun as early as ~ 32 Ma. However, to date, the source-rock potential and thermal maturity of the Kopili Shale have not been directly assessed and, thus, remain controversial (Imam and Hussain, 2002). The organic geochemical and petrographic studies described below were designed to test the hydrocarbon-source potential of the Kopili Shale in both the Indian platform and deep basin areas of the Bengal Basin. 4. Study location and methods Twenty-seven samples were collected to determine the source-rock potential of the Kopili Shale. Twenty-four of these were collected from outcrops of the Kopili Shale exposed on the northern margin of the Sylhet Trough in the northeastern part of the Bengal Basin (Figs. 1 and 3), and one sample was collected from cuttings from each of three wells in the northwestern Indian platform part of the basin (samples GDH-31, GDH-51, and GDH-55; Fig. 1). Of the 24 surface samples, eleven were collected at ~4–6 m intervals at the Dauki River section (samples D1–D11), five were collected at ~ 0.5–1.0 m intervals at the Tamabil section (samples T1–T5), and eight were collected at ~3–4 m intervals at the Sripur sections (samples S1–S8). The stratigraphic positions of samples are provided in Table 1.
Fig. 3. Map of outcrop sampling sites (white dots) in the northeastern study area, Sylhet Trough, Bengal Basin, Bangladesh. The Kopili Formation in the upper Assam is about 100–200 km away from Sripur section, northeast Bengal Basin, Bangladesh (Shamsuddin, 1993; Wandrey, 2004).
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Organic petrologic analysis of dispersed organic matter was performed on six subsamples (D2, D7, D10, T2, S6, and GDH-51). Shale subsamples were crushed, and particles passing the 20-mesh screen (b0.85 mm) were used to form ~3-cm-diameter polished pellets. Petrologic analyses of the pellets were performed in the Unconventional Reservoir/Basin Research Laboratory in the Boone Pickens School of Geology at Oklahoma State University using a Nikon petrographic microscope and a Craic Technologies 308PV microphotospectrometer driven by CoalPro III software. Analyses were conducted using oil-immersion objectives with magnification of 50 × and 100 ×. Spinel with Ro = 0.421%, yttrium-aluminum-garnet with reflectance Ro = 0.901%, and gadolinium-gallium-garnet with reflectance Ro = 1.733% were used as standards. For each sample, twenty-five dispersed organic particles were identified under reflected white light, and the fluorescence properties of liptinite, bituminite, and vitrinite macerals were measured under blue light excitation. Reflectance of all dispersed organics was measured and plotted, and vitrinite reflectance (Ro), and the reflectance of other macerals, were used to assess thermal maturity. Rock-Eval pyrolysis was completed on the same six samples employed for organic petrology. Analyses were performed using a Rock-Eval 6 instrument at ActLabs. Pyrolysis data—total organic carbon (TOC), hydrogen index (HI), oxygen index (OI), and Tmax (temperature of maximum pyrolysate yield)—were used to the extent possible to assess organic richness, thermal maturity, and petroleum source potential. The remaining eighteen samples were subjected to TOC analysis using an Elementar Vario Macro NCS Analyzer at the soil testing laboratory in the Department of Agronomy and Soils at Auburn University. 5. Results and implications 5.1. Organic petrologic analysis Organic petrologic analysis of the Kopili Shale reveals the presence of all major maceral groups–liptinite, bituminite, vitrinite, and inertinite
(Figs. 4 and 5). The two most common liptinite group macerals observed are cutinite and liptodetrinite. In reflected white light, cutinite macerals are dark in color (Fig. 4A) and give low reflectance values in the range of 0.0–0.5% Ro; they are weakly fluorescent with a brown color or are non-fluorescent (Fig. 4B). Liptodetrinite macerals also have low reflectance (Fig. 4C) and are weakly fluorescent to non-fluorescent. Bituminite macerals include brightly fluorescing exsudatinite (Fig. 4E and F), its diagenetic by-product micrinite (Fig. 4H), and other weakly to nonfluorescent particles (Fig. 4D). Vitrinite macerals, identified by their light gray color, plant-cell structures (Fig. 4I), and reflectance in the range of 0.8–1.5%, are dominated by non-fluorescent vitrodetrinite (Fig. 4J). Inertinite macerals include common inertodetrinite (Fig. 4K) and micrinite (Fig. 4H), and rare high-reflectance fusinite and semifusinite (Fig. 4L).
5.2. Hydrocarbon generation potential All data obtained from TOC analysis, Rock-Eval pyrolysis, and vitrinite reflectance studies are reported in Table 1. Results bearing on the three parameters governing hydrocarbon generative potential—organic richness, type, and maturity (Tissot and Welte, 1978)—are addressed separately below.
5.2.1. Organic richness Based on TOC content alone (Table 1), most of the sampled Kopili Shale intervals have relatively poor potential for hydrocarbon generation. This is also reflected in very low S2 values from Rock-Eval pyrolysis of five of the six samples analyzed (Table 1; see pyrograms Fig. 6A–E). However, the relatively high TOC contents of the Sripur section samples, in conjunction with a moderate S2 peak for the same section (sample S6, Table 1, Fig. 6F) indicate that, at least locally, intervals of the Kopili Shale may have fair potential for hydrocarbon generation.
Table 1 Sample site, stratigraphic position, and geochemical results of Kopili Shale. Sample site
Sample no.
Stratigraphic height
TOC TOC (wt.%) avg. (wt.%)
Dauki River
D5 D6 D7 D8 D9 D10 D11 D4 D3 D2 D1 T1 T2 T3 T4 T5 S1 S2 S3 S4 S5 S6 S7 S8 GDH-31 GDH-51 GDH-55
4 m from base 8m 11 m 14 m 18 m 22 m 26 m 30 m 33 m 36 m 39 m 0.5 m from base 1.5 m 2.5 m 3m 3.5 m 3 m from base 6m 10 m 13 m 16 m 19 m 22 m 25 m 796 m depth 431 m depth 358 m depth
0.45 0.53 0.64a 0.46 0.7 0.55a 0.66 0.61 0.76 0.83a 0.4 0.45 0.41a 0.35 0.36 0.34 1.43 1.07 0.77 1.03 1.2 0.97a 1.2 0.56 0.5 0.52a 0.45
Tamabil
Sripur
Core
a b
TOC data derived from Rock-Eval pyrolysis. Unreliable Tmax; low S2 peak.
Rock-Eval pyrolysis S1 mg HC/g rock
S2 mg HC/g rock
S3 mg CO2/g rock
HI mg HC/g TOC
OI mg CO2/g TOC
Tmax (°C)
Mean Ro (%) (each sample)
0.6
Mean Ro (%) (each section)
1.15 0.01
0.04
0.41
6
64
431b 1.02
0.02
0.1
0.22
18
40
436b 1.12
0.02
0.1
0.19
12
23
443b 1.32
0.01
0.08
0.26
21
68
443b 1.15
0.4
1.15
1
0.86
0.03
0.7
0.16
72
16
433
0.86
0.01
0.14
0.99
27
190
506b 1.24
0.5
1.24
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5.2.2. Organic matter type Information on the organic matter or kerogen types is commonly derived based on relationships between hydrogen and oxygen indices (HI and OI) determined from Rock-Eval pyrolysis. However, for all but one sample, S2 peaks for Kopili Shale samples are too low to yield reliable HI and OI values (Table 1). As indicated in the modified Van Krevelen diagram in Fig. 7, Sample S6 from the comparatively organic-rich Sripur section plots as gas-prone Type III kerogen.
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Organic petrologic analyses provided a more reliable assessment of organic matter type (Taylor et al., 1998). Examination under reflected white and blue light indicates a range in maceral types, including inertinite, vitrinite, bituminite, and liptinite (Fig. 4). Inertodetrinites are particularly common in the northwest sample (GDH-51; Fig. 5A) but are also recognized in samples from the Dauki River section (sample D2 and D7; Fig. 5C and D), suggesting Type IV kerogen. Vitrinite macerals (Fig. 4I) were identified in all
Fig. 4. Photomicrographs of the Kopili Shale from Bengal Basin, shot under white (A, C, H, I, K, and L) and blue (B, D–G, and J) light excitation. (A, B) Cutinite. (C) Liptodetrinite. (D) Weakly fluorescing or nonfluorescent bituminite. (E, F) Brightly fluorescing bituminite (exsudatinite). (G) Weakly to non-fluorescent bituminite with inclusions of brightly fluorescing alginite. (H) Micrinites over a dark bituminite. (I) Vitrinite. (J) Nonfluorescent vitrinite. (K,L) Inertodetrinite. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
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Fig. 5. Histograms showing reflectance, Ro (%), of the different macerals in Kopili Shale from northwest (A) and northeast (B-F), Bengal Basin, Bangladesh.
six samples (Fig. 5), which indicate the presence of Type III kerogen. Notably, some samples from the northeast and northwest contain brightly fluorescing exudatinite (Fig. 4E and F), indicating the presence of Type II kerogen. Liptodetrinite and cutinite macerals are present in all samples, representing Type I kerogen. Taken together, Rock-Eval pyrolysis data and petrographic observations indicate that organic matter in Kopili Shale is predominantly terrigenous in origin and represents an admixture of Type IV, Type III, and Type I/II kerogen. Vitrinite macerals of woody plant origin (Type III kerogen) tend to be more gas prone (Taylor et al., 1998). However, given the presence of cutinite and brightly fluorescing bitumen in some samples of the Kopili Shale, the potential for minor oil generation from Type I/II kerogen cannot be excluded altogether.
5.2.3. Maturation state of organic matter Thermal maturity of organic matter was assessed based on Tmax data derived from Rock-Eval pyrolysis, vitrinite reflectance (Ro) analyses, and fluorescence properties of organic macerals. Given generally low S2 values for all but the more carbonaceous Kopili Shale sample S6, almost all of the Tmax values reported in Table 1 are unreliable. The Tmax value of 433 °C for sample S6 suggests that the Kopili Shale at the Sripur section is immature to early mature. The presence of weakly to non-fluorescent liptinite macerals in the Kopili Shale as well as the high standard deviation (Fig. 5) of liptinite reflectance suggest a thermally mature source-rock. Bituminite in the Kopili Shale displays alteration from bituminite enclosing liptodetrinite/alginite at early mature stage (Fig. 4G; sample S6) to
micrinitised bituminite at mature stage (gas window; Fig. 4H). This type of alteration, including the presence of brightly fluorescing exsudatinites (Fig. 4E and F), is generally regarded as a result of liquid hydrocarbon generation from thermally cracked bituminite (Teichmüller, 1974). The presence of weakly to non-fluorescent bituminite (Fig. 4D) and micrinite (Fig. 4H) in the Kopili Shale also indicates a thermally mature source rock in these locations. Mean vitrinite reflectance (Ro) values (Table 1; Fig. 5) for all analyzed samples range from 0.86% to 1.32%. Ro values for sample GDH51 from the Indian platform and all but one sample from the northeastern outcrops range from 1.02 to 1.32%, indicating that the Kopili Shale in these areas is mature and falls within the oil to wet-gas generation windows (Table 2). In contrast, the lower Ro value for the S6 sample (Ro = 0.86%) indicates that the Sripur section had matured to the peak oil window prior to uplift. The presence of non-fluorescent vitrinite in Kopili Shale samples also support that the shale is mature. The higher reflectance of inertinite macerals in incident white light, the lack of fluorescence in blue light excitation, and the presence of micrinite over a degraded bituminite maceral (Fig. 4H) all suggest that the Kopili Shale has matured to the peak oil window.
6. Discussion 6.1. Source-rock potential of the Kopili Shale, Bengal Basin The results of the current study suggest that the Kopili Shale in most areas of the Bengal Basin has limited potential as a hydrocarbon source
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rock. Organic matter in the Kopili Shale of the northwest Indian Platform area is thermally mature despite relatively shallow burial depths. This is consistent with relatively high average geothermal gradients (21.1–31.6 °C/km) in the area (Hossain, 2009), which may be related to heat supplied by the Rajmahal volcanic trap that lies beneath this part of India. However, given its relatively low TOC content (b0.6%) and limited thickness (~30 m), the Kopili Shale in this region has very poor hydrocarbon-generation potential. Rather, the Kopili Shale here likely plays a more significant role as the seal rock for the so-called Cherra-Sylhet-Kopili petroleum system in western Bangladesh (Shamsuddin et al., 2001). Organic matter from surface samples of the Kopili Shale in the Sylhet trough region also is thermally mature, generally falling in the oil-generation window. Similar maturation is expected in the subsurface to the south and east, given average geothermal gradients for the Sylhet Trough region (15.8–30 °C/km; Hossain, 2009) and the depth of burial
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of the Kopili Shale (N6 km) (Shamsuddin et al., 2001; Curiale et al., 2002). However, as with the Indian Platform samples, TOC contents and thus hydrocarbon source potential of the Kopili Shale in most sampled areas of Sylhet Trough are generally low. As the exception, organic contents of Kopili Shale samples from the Sripur section are comparatively high (mean TOC = 1.0%) and include some brightly fluorescing bitumen indicative of possible oil expulsion. Hence, at least locally in the Sylhet Trough region, the Kopili Shale has fair potential as a hydrocarbon source. Notably, the Sripur section lies geographically closest (150–200 km) to upper Assam, where the Kopili Formation is an established source rock. 6.2. Comparison with the Kopili Formation The Kopili Formation in Assam, India has been established as a source rock for oil and gas in the Sylhet-Kopili/Barail-Tipam composite
Fig. 6. Pyrograms showing S2 peaks of northwestern (A) and northeastern (B\ \F) Kopili Shale, Bengal Basin, Bangladesh. Free hydrocarbons are measured by the S1 peak and the hydrocarbons and non-hydrocarbons cracked from the kerogen during rock-eval pyrolysis (and, in some cases, the high-molecular weight soluble components in the extractable organic matter) are measured by the S2 peak. The CO and CO2 liberated upon pyrolysis of the sample from 300 °C to 390 °C, which include CO2 liberated from the organic matter and, in some cases, CO2 liberated from labile carbonates, are recorded as S3. Pyrolysis results were computed to determine amounts of pyrolyzable carbon, residual carbon, mineral carbon, and TOC content.
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The greater thickness of the Kopili Formation results in overall greater organic richness (thickness * TOC) and likely contributes to its greater hydrocarbon-source potential (Naidu and Panda, 1997). Nonetheless, there are likely other as yet unrecognized factors that have operated to control differences in abundance, type and quality of organic matter between Assam and the Bengal Basin. Both the Kopili Shale and the Kopili Formation have been attributed to shallow marine deposition (Reimann, 1993; Moulik et al., 2009; this study). However, paleoenvironmental interpretations thus far have been based on cursory lithofacies analyses. Given the disparate thicknesses of these Eocene mudrock units, these areas likely experienced significantly different basin histories controlled by tectonics, paleogeography, paleoceanographic conditions, and paleoenviron ments of deposition. Understanding how these factors may have controlled source-rock potential will require more detailed analyses of subsurface stratigraphy, depositional facies, and structural geology, including within the poorly studied region that separates the Sylhet Trough and Assam regions. 7. Conclusions
Fig. 7. Pseudo van Krevelen diagram, showing the type of kerogen present in Kopili Shale from Bengal Basin. Green and red dots represent reliable and unreliable HI and OI data of Kopili Shale from Rock-Eval pyrolysis. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
petroleum system (Wandrey, 2004). The Kopili Formation in many ways is similar to the Kopili Shale at the Sripur section of the Bengal Basin (Table 2). The Kopili Formation of Assam is moderately carbonaceous (TOC ranges from 0.5 to 1.5%; Wandrey, 2004) and is characterized by Type II (oil-prone) and Type III (gas-prone) kerogen that lies in the oil generation window; vitrinite reflectance (Ro) ranges from 0.5 to 0.7%, and Tmax values range from 410 to 450 °C (Naidu and Panda, 1997). The primary difference thus far recognized between the Kopili Shale of the Bengal Basin and the Kopili Formation relates to stratigraphic thickness. While the Kopili Shale in the Bengal Basin typically is 30–40 m thick, the thickness of the Kopili Formation at its type locality is an order of magnitude greater (~ 500 m thick; Mandal, 2009).
Results from geochemical analyses in the current study suggest that the upper Eocene Kopili Shale is thermally mature. Vitrinite reflectance values for Kopili Shale samples from the northwest and two sections from the northeastern Bengal Basin lie in the oil to wet-gas generation windows. In contrast, samples from the Sripur section of the Bengal Basin are immature to early mature and lie in the peak oil window. The types of kerogen (Type-III and Type-II) in the Kopili Shale suggest the potential for both gas and minor oil expulsion. However, with the exception of the Sripur section, organic contents are relatively low. Hence, the potential of the Kopili Shale as a source rock for Eocene-Oligocene or Miocene petroleum systems in the Bengal Basin, Bangladesh, is regarded as poor. Evaluating apparent differences in source-rock potential between the Kopili Shale in the Bengal Basin and the thicker, relatively more carbonaceous Kopili Formation in Assam, India will require further comparative facies analyses. Acknowledgments This research was possible because of financial support from the American Association of Petroleum Geologists, the Geological Society of America, and the Geosciences Advisory Board of Auburn University. We thank Syed Humayun Akhter for his support with logistics during the field investigation, and Shajadul Thandu and Abdul Malek for assisting in sample collection from the Sylhet area. Discussion with Manowar Ahmed was helpful. We thank journal reviewer Joe Curiale for his constructive suggestions which significantly improved the manuscript.
Table 2 Comparison of source-rock potential of Kopili Shale in Bengal Basin and Assam Shelf.
Geochemical parameters Thickness (m) Organic richness
TOC (wt.%)
Organic matter type
Hydrogen index (HI) and/or maceral types
Maturity
Tmax (°C) Vitrinite reflectance (% Ro)
Generalized HC zone
Tmax and Ro
a
Unreliable Tmax; low S2 peak.
Northwest (Stable Shelf) Bengal Basin
Northeast (Sylhet Trough) Bengal Basin
Assam Shelf Assam, India
30–60 (drilled) 0.45–0.52 (poor) Type-I,II,III, and IV Oil and gas-prone 506a 1.24% Mature Wet-gas window
40–90 (outcrop) 0.34–1.43 (poor to fair) Type-I,II,III, and IV Oil and gas-prone (431–443)a; (S6 = 433) 0.86–1.15% Mature Peak oil window
300–700 (outcrop) 0.50–1.50 (fair to good) Type-II–III Oil and gas-prone 410–450 0.5–0.7% Immature to early mature Peak oil window
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