source rock potential of organic-rich … · kamta titas chhatak bakhrabad rashidpur habiganj...

357Journal of Petroleum Geology, Vol. 35(4), October 2012, pp 357-376

© 2012 The Authors. Journal of Petroleum Geology © 2012 Scientific Press Ltd

SOURCE ROCK POTENTIAL OF ORGANIC-RICH

SHALES IN THE TERTIARY BHUBAN AND BOKA BIL

FORMATIONS, BENGAL BASIN, BANGLADESH

Md. Farhaduzzaman1*, Wan Hasiah Abdullah1, Md. Aminul Islam2

and M. J. Pearson3

Sandstones in the Miocene Bhuban and Lower Pliocene Boka Bil Formations contain all of thehydrocarbons so far discovered in the Bengal Basin, Bangladesh. Organic-rich shale intervals inthese formations have source rock potential and are the focus of the present study which isbased on an analysis of 36 core samples from wells in eight gasfields in the eastern BengalBasin. Kerogen facies and thermal maturity of these shales were studied using standard organicgeochemical and organic petrographic techniques.

Organic matter is dominated by Type III kerogen with lesser amounts of Type II. TOC is 0.16-0.90 wt % (Bhuban Formation) and 0.15-0.55 wt % (Boka Bil Formation) and extractableorganic matter (EOM) is 132-2814 ppm and 235-1458 ppm, respectively. The hydrogen indexis 20-181 mg HC/g TOC in the Bhuban shales and 35-282 mg HC/ g TOC in the Boka Bil shales.Vitrinite was the dominant maceral group observed followed by liptinite and inertinite. Gaschromatographic parameters including the C/S ratio, n-alkane CPI, Pr/Ph ratio, hopane Ts/Tmratio and sterane distribution suggest that the organic matter in both formations is mainlyderived from terrestrial sources deposited in conditions which alternated between oxic andsub-oxic. The geochemical and petrographic results suggest that the shales analysed can beranked as poor to fair gas-prone source rocks. The maturity of the samples varies, and vitrinitereflectance ranges from 0.48 to 0.76 %VR

r

. Geochemical parameters support a maturity rangefrom just pre- oil window to mid- oil window.

1 Department of Geology, Faculty of Science, Universityof Malaya, 50603 Kuala Lumpur, Malaysia.2 Department of Petroleum Geoscience, Faculty ofScience, Universiti Brunei Darussalam, Gadong BE1410,Brunei.3Department of Geology and Petroleum Geology,University of Aberdeen, King’s College, Aberdeen, AB243UE.*Corresponding author, email: [email protected],[email protected]

Key words: Bhuban Formation, Boka Bil Formation,Miocene, Pliocene, organic petrology, source rocks,thermal maturity, hopane, sterane, Bengal Basin,Bangladesh.

INTRODUCTION

The Bengal Basin covers on- and offshore Bangladeshand extends into the Indian states of West Bengal tothe west and Tripura to the east (Fig.1A). The basin

is bordered to the west by the Precambrian Indianshield, to the north by the Shillong Massif and to theeast by the frontal fold-belt of the Indo-BurmeseRange. To the south it extends for some distance intothe Bay of Bengal (Fig.1A). The deltas of three majorriver systems (Ganges, Brahmaputra (Jamuna) andMeghna) pass into the Bengal Fan whose frontal lobesextend about 3000 km south of the coast line (Currayand Moore, 1974).

358 Tertiary Bhuban and Boka Bil Formations, Bengal Basin, Bangladesh

Northward migration of the Indian plate andconvergence with Eurasia at about 55 Ma resulted inthe development of the Bengal Basin. The basin canbe divided into a so-called Platform unit (Province 1:Fig.1A) with a stratigraphic section including Permian,Cretaceous and Tertiary rocks overlying Precambrianbasement; and a Deep Basin unit (Province 2) whichhas a Tertiary sedimentary succession (Fig.1B) up to22 km thick (Curray, 1991; Imam, 2005). Thissuccession can be divided into the Jaintia Group(Paleocene to Eocene), Barail Group (Oligocene),Surma Group (Miocene to Early Pliocene), TipamGroup (mid-Pliocene) and overlying Dupi Tila andMadhupur Formations (Late Pliocene – Pleistocene)(Table 1) (Alam et al., 2003; Imam, 2005).

The Surma Group, up to 5 km thick, is composedof the Bhuban and Boka Bil Formations and is exposedin the Sylhet and Chittagong hills (Fig.1A). Bothformations are composed of sandstones and shalesinterpreted to have been deposited in a deltaic toshallow-marine environment (Holtrop and Keiser,1970). All of the hydrocarbon accumulations so fardiscovered in Bangladesh have been found within theBhuban and Boka Bil Formation sandstones, and theformations also contain shale intervals with importantsource rock potential (Imam, 2005). Overlying marineshales act as a basin-wide seal.

The Tertiary succession in the Bengal Basin inBangladesh can be correlated with outcrops in Lowerand Upper Assam (India) which were studied and

Shillong Massif

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Himalayan Foredeep

Bay of Bengal

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estern

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.

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elt o

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BelaboKamta Titas

Chhatak

Bakhrabad

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BibiyanaMoulvibazar

050 50kmScale

Major tectonic boundaryStudied gas field

Gas field

International boundary

LEGEND

Pakistan

China

Bangladesh

HIMALAYA

Mya

nmar

India

Nepal

PLATFORM

(Province 1)

DEEP BASIN

(Province 2)

Province 3

Fig.1A. Map of the Bengal Basin, Bangladesh, showing the location of the gasfields from which core sampleswere taken together with tectonic elements; the NW-SE cross-section is shown in Fig.1B. (Modified fromKhan, 1991; Reimann, 1993; Alam et al., 2003; Shamsuddin et al., 2004; Imam, 2005; Farhaduzzaman et al.,2012).

359Md. Farhaduzzaman, Wan Hasiah Abdullah, Md. Aminul Islam and M. J. Pearson

interpreted by Evans (1932). However thisstratigraphic classification was based almostexclusively on lithologic characteristics (Das Gupta,1977). Correlation between the basins is made difficultbecause of the absence of marker horizons (Khanand Muminullah, 1980), diachronism of the units andlithological and facies variations (Das Gupta, 1982;Reimann, 1993). The deltaic Tipam Sandstone, forexample, has been dated as Miocene in the UpperAssam Basin, but as Pliocene in the eastern portionof the Surma sub-basin in the Bengal Basin,Bangladesh.

Within the Surma Group, the Bhuban Formationis in general more sand-rich and the Boka Bil Formationmore argillaceous. Both formations show extensivelateral facies changes and vertical variations in sand:shale ratios, making it difficult to correlate them acrossthe basin (Johnson and Alam, 1991; Imam, 2005).Alam et al. (2003) emphasised that the contactbetween the formations is often difficult to recognizebased on Evan’s (1932) lithostratigraphic scheme.

The Bhuban and Boka Bil Formation shales havenot previously been investigated in detail in terms oforganic geochemistry or organic petrography. Belowwe report on the source rock potential of the twoformations and attempt to interpret the depositionalenvironment and thermal maturity of the organicmatter.

Hydrocarbons in the Bengal BasinThe natural gas and condensates currently producedin Bangladesh come from anticlinal structures in theEastern Foldbelt of the Deep Basin (Fig.1A)(Jamaluddin et al., 2001). Here Middle to LateMiocene reservoir sandstones are capped by UpperMarine shales in the upper part of the Surma Group.Source rock intervals occur in the Middle Oligocene

Jenum shales and the Miocene Surma Group shales.Estimated gas reserves (GIIP P+P) in Bangladesh are28.42 TCF (trillion cubic feet) (Shamsuddin et al.,2004) with about 41.6 TCF undiscovered (Jamaluddinet al., 2001). Petrobangla estimated total oil reservesat 137 million barrels STOIIP (Hossain, 2012). Crudeoil production took place here from 1987 to 1997. Of24 gasfields (and one small oilfield) so far discovered,only 19 are currently producing. Gas productionbegan in 1959 and output of gas and condensate isapproximately 2033 MMCFD (million cubic feet perday) and 6700 brl/day respectively (as of April, 2012).The majority of gasfields in Bangladesh produce drygas with a significant proportion of condensate (upto 18 barrels per million cubic feet of gas).

SAMPLES AND METHODS

A total of 36 core samples from the Bhuban Formationshales (14 samples) and Boka Bil Formation shales(22 samples) were collected from wells in eightgasfields (Rashidpur, Patharia, Shahbazpur,Bakhrabad, Kamta, Begumganj, Fenchuganj andTitas) which are located in the Eastern Bengal Basin(Figs.1 and 2). All the cores were collected from theCore Laboratory of Bangladesh Petroleum Explorationand Production Company Ltd (BAPEX), Petrobangla.Basic core data is given in Table 2.

The shale samples were analysed in a Source RockAnalyser (SRA) and after screening, 21 samples wereselected for Soxhlet extraction followed by gaschromatography – mass spectrometry (GCMS). Tensamples underwent pyrolysis – gas chromatographic(PyGC) analysis.

The shale samples were crushed into a finepowder and analyzed using a Weatherford SourceRock Analyzer (equivalent to a Rock-Eval instrument)

Note: Cross-section line shown in Fig.1A

? Pleistocene? Upper Pliocene

? Lower Pliocene

? Uppermost Miocene

Fault zone

? Upper MioceneOligocene / Eocene

Miocene

? Lower Pliocene

Upper Cretaceous

Unconformity

Erosional

BOGRAFAULT

(not

ext

ende

d)

Paleocene-Eocene

Sylhet LST (Middle Eocene)

Basalt flowassociated with rifting

PK-1 PK-1 Ext.

Oceanic crustTransitional crustContinental crust

Pre-Cretaceous“Basement”

0 5 10 15 Km

NW SINGRASP

1

2

3

4

5

6

7

1

2

3

4

5

6

7

400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800

TWTsec

TWTsec

SE

Fig.1B. Geological cross-section through the Platform (Province 1) and the southern part of the Deep Basin(Province 2) of the Bengal Basin; location of cross-section shown in Fig.1A. (After Alam et al., 2003).


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in Weatherford Laboratories, USA. Bitumen extractionwas performed on approximately 15g of the powderedsamples using a Soxhlet apparatus with an azeotropicmixture of dichloromethane (DCM) and methanol(CH

3OH) (93:7) for 72 hours. The extracts (EOM)

were separated by column liquid chromatography intoaliphatic, aromatic and polar fractions using petroleumether, DCM and CH

3OH respectively. The aliphatic

hydrocarbon fractions were analyzed subsequentlyby gas chromatography (Agilent 6890N Series GC)and gas chromatography–mass spectrometry(GCMS). An FID gas chromatograph with an HP-5MS column, temperature programmed from 40 to300 °C at a rate of 4 °C/min and then held for 30 minat 300 °C, was used for GC analysis. GCMS analysiswas performed using an Agilent V 5975B MSD massspectrometer with a gas chromatograph attacheddirectly to the ion source (70 eV EI mode). Thefragmentograms acquired from GC and GCMSanalysis were used for biomarker characterization.Rock-Eval 6 pyrolysis following Espitalie et al. (1977)was carried out in the organic geochemistry laboratoryof Geotechnical Services Pty Ltd, Australia, for sevensamples to enable comparison with the results of SRA.

The powdered samples (22) were treated with 1MHCL in order to remove the inorganic carbonate andthe samples were then dried before being run forelemental analysis using a Perkin Elmer 2400Elemental Analyzer (CHNS/O).

For petrographic study 25 samples were preparedby mounting whole rock fragments in resin blocksand then polished using progressively finer aluminasuspension (1μm, 0.3 μm and 0.05 μm). Petrographicexamination was carried out under oil immersion inplane-polarised reflected white light using a LEICADM6000M microscope and CTR6000 photometrysystem equipped with fluorescence illuminators.Maceral compositions were determined under bothnormal reflected white light and UV (ultraviolet) light.

Random vitrinite reflectance measurements in oilimmersion (%VR

r) were made in reflected white light

using Diskus fossil software equipped with a Baslerdigital camera.

EOM, PyGC, GCMS, CHNS and petrologicalanalyses were performed in the petroleumgeochemistry laboratory of the University of Malaya,Kuala Lumpur.

Rashidpur-4 Kamta-1 Patharia-5 Begumganj-1 Fenchuganj-2 Bakhrabad-9 Titas-11

Giru

jan

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y

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i Tila

Tipa

m

Gir

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Cla

y

Dup

i Tila

Tipa

m

Shahbazpur-1 0

TVD 2868m

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

3200

3400

3600

3800

4000

4200

4400

4600

4800

5000

Dep

th (m

)

TVD 3175m

TVD 3614m

TVD 3342m ?

TVD 3655m

TVD 3440m

TVD 4977m

TVD 3438m

S

urm

a G

r (B

oka

Bil

Fm)

Su

rma

Gr

(Bhu

ban

Fm)

S

urm

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r (B

oka

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(Bhu

ban

Fm)

S

urm

a G

r (B

oka

Bil

Fm)

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rma

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(Bhu

ban

Fm)

Fig. 2. Correlation of the eight studied wells (from north to south) in the eight gasfields in the Bengal Basin,Bangladesh; all of the samples analyzed were collected from the Boka Bil and Bhuban Formations at the baseof the succession (see Tables 1 and 2 for descriptions). After Moinul et al., 1977; Nazim et al., 1982; Khan, 1991;Reimann, 1993; Alam et al., 2003; Imam, 2005.


RESULTS

Source rock characteristicsfrom pyrolysis and elemental analysisThe results obtained from the Source Rock Analyzer(SRA) are shown in Table 2. The results obtained fromthe Rock-Eval 6 apparatus were compared with them,and there is good agreement between the resultsobtained from both methods.

The source rock potential of the Bhuban and BokaBil Formation shales was evaluated following theclassification of Peters and Cassa (1994) and rangesfrom poor to fair. All samples are organic lean (<1%).HI values for the Bhuban and Boka Bil Formationsrange from 39 to 277 and 58 to 281 mg HC/g TOCrespectively (Table 2). On a plot of T

max versus HI

(Fig. 3), most samples plot in the Type III kerogenfield but a few samples plot in the Type II-III field. Agraph of HI versus OI (not shown here) also supportsthe presence of mixed kerogen Type III/II. OI valuesfor the Bhuban and Boka Bil shales range from 60 to168 and 72-226 mg CO

2/g TOC respectively. T

max

values vary considerably, ranging from 421 to 457 °Cin the Bhuban and 421 to 446 °C in the Boka BilFormation. These T

max values correspond to immature

to early oil window maturities and are consistent with

the mean vitrinite reflectance values which rangesfrom 0.56 to 0.71 and 0.48 to 0.76 % VR

r for the

Bhuban and Boka Bil Formations, respectively.The total sulphur content for the shale samples is

0.006–0.150% (Bhuban Formation) and 0.007–0.012% (Boka Bil Formation). Total nitrogen is 0.110–0.334% and 0.115–0.259%, respectively. The C/Sratio is 2.81–128.57% and 2.38– 28.75% respectively,and C/N ratio is 0.55–5.26% and 1.12–2.52%. Thesevalues are typical of terrestrial organic matter depositedin a non-marine environment (the depositionalenvironment is discussed further below).

Maceral characteristicsfrom petrography and kerogen typingVitrinite is the dominant maceral group in the samplesanalysed followed by liptinite and inertinite. Vitrinite,identified by its moderate grey reflectance underreflected white light, comprised 62-80 vol.% (by area)and 67-85vol.% in the Bhuban and Boka Bil samplesrespectively. Bitumen staining was commonlyobserved in association with vitrinite macerals(Figs.4A). Woody fragments were commonlyobserved (Figs.4B). Inertinite ranges from 7-14% inthe Bhuban Formation and 5-13% in the Boka BilFormation, and was distinguished by its higher

0

100

200

300

400

500

600

700

800

900

1000

390 410 430 450 470 490 510 530

Type I

Type II

Type III-II

Type III

Type IV Type IV-III

Type II-III

VRr = 0.62%

VRr = 0.88%

VRr = 1.1%

Mat

ure

(oil

win

dow

)

Imm

atur

e

Post

-mat

ure

Dry gas window

Condensate-wet gas window

Boka Bil shales

Bhuban shales

Hyd

roge

n In

dex,

HI (

mg

HC

/g T

OC

)

Tmax ( C) o

Fig.3. Plot of Tmax

(°C) versus hydrogenindex (HI) of the analyzed samples,showing that both the Bhuban and BokaBil Formations contain Type III/IIkerogen and plot within the immatureto mature oil window as indicated byvitrinite reflectance (VR

r) (cf. Peters and

Cassa, 1994; van Koeverden et al., 2011).


RP4SH2Boka Bil Shales

BG1SH5

FN2SH7

FN2SH8

T11SH54

KM1SH4

0.06

0.05

0.06

0.05

0.33

0.11

0.55

0.28

0.29

0.36

0.61

0.39

161

105

168

121

133

107

436

435

431

440

436

431

60

80

81

63

232

84

0.89

0.29

0.48

0.44

0.81

0.42

0.15

0.19

0.21

0.18

0.19

0.25

S1Tmax OITOCSample S3

0.33

0.22

0.23

0.23

1.41

0.33

S2 HI PI

0.67

0.71

0.57

0.60

0.70

0.63

KM1SH3 0.060.27 143433 960.39 0.190.26 0.60

T11SH55

T11SH57

T11SH59

T11SH64

T11SH66

T11SH65

0.09

0.06

0.51

0.33

0.03

0.03

0.44

0.35

0.90

0.49

0.35

0.34

96

89

93

155

60

64

441

429

433

457

426

459

169

71

277

244

37

39

0.42

0.31

0.83

0.76

0.21

0.22

0.11

0.19

0.17

0.22

0.19

0.19

0.74

0.25

2.48

1.20

0.13

0.13

na

na

0.71

T11SH62 0.080.36 107428 1210.39 0.150.44 0.56

0.68

na

0.62

PT5SH10

SB1SH5

SB1SH10

SB1SH14

SB1SH24

SB1SH18

SB1SH1

0.05

0.05

0.05

0.07

0.06

0.05

0.04

0.29

0.24

0.32

0.36

0.28

0.30

0.26

93

226

119

187

177

132

354

437

442

421

435

438

427

430

82

81

69

58

85

73

62

0.27

0.53

0.38

0.68

0.50

0.40

0.92

0.17

0.21

0.19

0.25

0.20

0.19

0.20

0.24

0.19

0.22

0.21

0.24

0.22

0.16

0.57

0.48

na

na

0.65

na

na

SB1SH28

SB1SH32

SB1SH33

SB1SH36

Note: na = not analyzed.

SB1SH29

0.06

0.06

0.08

0.05

0.06

0.24

0.15

0.27

0.22

0.23

139

281

150

121

142

432

444

440

443

443

97

281

132

85

94

0.33

0.18

0.41

0.27

0.33

0.21

0.25

0.18

0.21

0.21

T11SH67 0.040.16 75421 900.12 0.220.14 0.63

SB1SH11 0.050.33 110435 610.36 0.200.20 0.50

PT5SH12 0.040.28 86437 750.24 0.160.21 0.69

PT5SH14 0.130.28 72438 1230.20 0.280.34 0.73

0.23

0.18

0.36

0.19

0.22

na

0.64

na

na

0.53

SB1SH44 0.030.20 122433 870.24 0.150.17 0.50

SB1SH46

BK9SH69

BK9SH70

BK9SH71

SB1SH47

0.03

0.05

0.06

0.07

0.04

0.22

0.18

0.19

0.34

0.17

181

109

204

102

216

438

439

446

433

441

79

109

162

115

99

0.39

0.20

0.39

0.45

0.37

0.15

0.20

0.16

0.16

0.19

0.17

0.20

0.31

0.40

0.17

na

0.65

0.76

0.58

0.55

%VRr

Bhuban shales

1385

3100

3142

3772

3377

Depth (m)

3139

2715.8

2740.8

2788.6

2783.1

2739.2

2791.7

1836

3163

997.5

1003.5

1280.5

1279.5

1834

1285.5

1597.4

1773.8

1774.3

1777.3

2016.5

2012.5

1572.4

2714.2

2727.4

2721.5

4

1

2

2

1

Well no.Gas Filed

1

11

11

11

11

11

11

5

5

1

1

1

1

5

1

1

1

1

1

1

1

1

Rashidpur

Begumganj

Fenchuganj

Fenchuganj

11Titas

Kamta

Kamta

Titas

Titas

Titas

Titas

Titas

11Titas

11Titas

Titas

Patharia

Patharia

Shahbazpur

Shahbazpur

Shahbazpur

Shahbazpur

Patharia

Shahbazpur

Shahbazpur

Shahbazpur

Shahbazpur

Shahbazpur

Shahbazpur

Shahbazpur

Shahbazpur

2097.5

2294.5

2296.5

2301.2

2329.6

2318.6

1

1

1

9

9

9

Shahbazpur

Shahbazpur

Shahbazpur

Bakhrabad

Bakhrabad

Bakhrabad

Table 2. Data from the Source Rock Analyser (equivalent to Rock-Eval), including TOC, pyrolysis parametersand vitrinite refletance data from the studied samples (see Appendix A, page 375).


reflectance and characteristic whitish colour underreflected white light. Fusinite (Fig. 4C), semifusiniteand inertodetrinite were the most common inertinitemacerals observed. Both vitrinite and inertinite maceralsare dark under UV whereas liptinite macerals showfluorescence (Figs. 4D, E and F).

The liptinite content was estimated frompetrographic observation to be 11- 24 and 8-19 vol.%of the whole rock in the Bhuban and Boka Bil shales,

Fig.4. (A) Bitumen stained (bs) vitrinite (vt) maceral associated with pyrite (py) in the Boka Bil Formation,depth 2301.2 m, well Bakhrabad-9; (B) Dark brownish woody fragment (wf) in the Bhuban Formation, depth3100 m, well Begumganj-1; (C) Whitish inertinite maceral fusinite (fs) identified in the Bhuban Formation,depth 3772 m, well Fenchuganj-2; (D) Yellow fluorescent, rounded liptinitic maceral (sporinite, sp) observed inthe Boka Bil Formation, depth 1834 m, in well Patharia-5; also shown: intense yellow fluorescent, oval-shapedresinite (rs) with greenish rim observed in the Bhuban Formation, depth 2714.2 m in well Titas-11; (E) Yellowfluorescent narrow liptinitic maceral (cutinite, ct) in the Boka Bil Formation, depth 2329.6 m, well Bakhrabad-

9; also: greenish yellow fluorescent resinite (rs) found in the Bhuban Formation, depth 2727.4 m, in well Titas-11; (F) Light greenish yellow fluorescent liptinitic amorphous (am) materials which may be of alginite originobserved in the Boka Bil Formation, depth 1597.4 m, in well Shahbazpur-1.

Photomicrographs A, B and C were taken in normal reflected white light using oil immersion; photo-micrographs D, E and F were taken under ultraviolet light using oil immersion.

respectively. Liptinitic macerals include sporinite(Fig.4D), cutinite (Fig.4E), resinite (Figs.4D and E),amorphous material (Fig.4F), liptodetrinite and alginite(trace amounts). Similar maceral assemblages wereobserved in both the Bhuban and Boka Bil Formationshales. The liptinitic macerals together with the solidbitumen (staining) contribute a minor oil-pronecharacter to the dominantly vitrinitic maceralassemblages.


Pyrolysis-GC can be used to interpret mixedkerogen assemblages and to indicate the hydrocarbonslikely to be generated (Giraud, 1970; Larter andDouglas, 1980; Dembicki et al., 1983 and Dembicki,2009). Dembicki (2009) suggested that the <C

10 mode

dominates in PyGC traces of Type III kerogens withonly a minor >C

15 mode. The situation is reversed for

Type I kerogens and an intermediate situation ischaracteristic of Type II kerogens (Dembicki, 2009).Bimodal fingerprints of predominantly n-alkane/alkanedoublets with some specific abundant aromatic andcompounds are present in whole rock PyGCpyrograms and suggest mixed kerogens in the Bhubanand Boka Bil samples, possibly reflecting 75% TypeIII and 25% Type II input (Dembicki, 2009).

The ratio of n-octene (C8) to xylene (m+p) has

been applied as a measure of the comparativeabundance of aliphatic to aromatic hydrocarbons (vanAarssen et al., 1992). The C

8/xylene ratio of the

Bhuban and Boka Bil samples varies from low tomoderate (0.58-1.78). It is associated with a highrelative abundance of specific aromatic hydrocarbons(benzene, toluene and xylene) and a low ratio ofcadalene to xylene (Cd/xylene) (0.06 to 0.12). This isconsistent with a dominant input from vascular higherplants (Solli et al., 1984).

Soluble extract and biomarker characteristicsAromatic hydrocarbons (17-126 mg EOM/g TOC inthe Bhuban Formation and 30-209 mg EOM/g TOCin the Boka Bil Formation) are in general present inhigher quantities than aliphatic hydrocarbons (3-54mg EOM/g TOC and 2-115 mg EOM/g TOCrespectively). Measured total soluble hydrocarbonyields are 20-180 and 34-282 mg HC/g TOC in theBhuban and Boka Bil shales, consistent with minorhydrocarbon generation (Peters and Cassa, 1994).Total soluble extract is 132-2814 ppm (Bhuban) and235-1458 ppm (Boka Bil Formation). However thevery high extract values found in samples T11SH54and T11SH59 may indicate the presence of somemigrated bitumen.

GC and GCMS (full scan) analyses were carriedout on the aliphatic fractions of the shale samples,and TIC, m/z 191 and m/z 217 chromatograms wereused to derive specific ratios and parameters.Chromatograms of two representative immaturesamples are shown in Figs 5 and 6, and two maturesamples of the shales analyzed are illustrated in Figs7 and 8. Peak identifications were made on the basisof retention times and published literature: Waples andMachihara (1991), Hossain et al. (2009) and Wang etal. (2011) were used for TIC; Philp (1985), Ahmedet al. (2009), Kashirtsev et al. (2010) and Hakimi etal. (2011) for m/z 191 fragmentograms; Pearson andAlam (1993), Wan Hasiah (1999) and Fabianska and

Kruszewska (2003) for bicadinane and oleananes; andAbeed et al. (2011), van Koeverden et al. (2011) andSachse et al. (2012) for m/z 217 fragmentograms.Identification of these peaks and related other termsis described in Appendices A and B (page 375). Theunimodal distributions of n-alkanes from C

10 to C

35

with maxima at C16

(mostly) and/or C18

were observedin gas chromatograms of the Bhuban and Boka BilFormation shale samples. The calculated CPI1 valuesare close to unity (0.77 to 1.18) (CPI2 0.96-2.47) inthe Bhuban shales and 0.46 to 1.38 (CPI2 0.68-1.61)in the Boka Bil shales (Table 3). In most of the analysedsamples, odd carbon homologues dominate over evencarbon homologues, although this is not always thecase. The pristane/phytane ratio is high to very highand varies from 0.99 to 3.74 in the Bhuban Formationshales and from 0.58 to 2.32 in the Boka Bil Formationshales (Table 3).

Abundant pentacyclic triterpanes (hopanes andmoretanes) dominated by the C

30αβ-hopanes are

present in all the shale samples analyzed (Figs.5B,6B, 7B and 8B). Homohopanes are lower inconcentration but are dominated by C

31-hopane in both

formations. R-isomers are dominant over the S-isomers among the homohopanes (C

31 - C

33) in some

samples (Figs.5B and 6B), indicating that the samplesare thermally immature. However S-isomers aredominant over R-isomers in other samples (Figs.7Band 8B) indicating the samples’ maturity. Moretanes(βα-hopanes) are present in the studied samples,although in general αβ-hopanes are more prominent.The Ts/Tm ratio ranges from 0.14 to 0.87, consistentwith a mixed source inputs.

C30

moretane/C30

hopane and C32

22S/(22S + 22R)ratios range from 0.09 to 0.44 and 0.43 to 0.63respectively for the Bhuban Formation shales (Table4). These ratios range from 0.12 to 0.36 and 0.43 to0.61 for the Boka Bil Formation shales. It has beennoted that the values of these parameters are veryclose to each other compared to the analyzed Bhubanand Boka Bil samples. Considerable abundances of18α(H)-oleanane (a higher plant biomarker) werefound in all the studied samples, and 18β(H)-oleananewas identified in some of them (not shown here).The ol/C

30-hopane ratio (oleanane index) is 0.05 - 0.21

and 0.07 - 0.45 in the Bhuban and Boka Bil shales,respectively (Table 4). Bicadinane (both T and Rconfigurations) was identified in all the shale samplesanalyzed. The bc/C

30-hopane ratio is 0.07 - 0.48

(Bhuban) and 0.05-1.41 (Boka Bil) (Table 4). Therewas no significant correlation between bc/C

30 and ol/

C30

in the depth plots, either among themselves orwith depth.

C29

sterane is the most prominent componentobserved in the m/z 217 mass fragmentograms whichare dominated by regular steranes compared to


nCnC1616

nCnC1414

nCnC1515

nCnC11

nCnC1010

nCnC1313

nCnC1717

nCnC1818

nCnC1919

nCnC2020

nCnC2121

nCnC2222

nCnC2424

nCnC2626

nCnC2828

nCnC3030

nCnC3232

PrPr

PhPh

Pr/P

h =

1.67

CPI

=

0.94

VR

r = 0

.56

HI =

121

olol

C24

/4C

24/4

TsTm

C30 C30αβ

C29 C29αβ

C30 C30βα

C30 C30ββ

C30- C30-hopene

bcT bcTbcR bcR

C29 C29βα

C28 C28αβ

Ts/T

m =

0.7

9C

30βα

/C30

αβ =

0.1

522

S/(2

2S+2

2R) =

0.4

9

22S 22S22R 22R

C3131αβ

22S 22S22R 22R

C3232αβ

C29 C29 ααα 20R

C28 C28 ααα 20R

C27 C27 ααα 20R

C29 C29 ααα 20S

C28 C28 ααα 20S

C29 C29 αββ 20S

C29 C29 βα 20S

C28 C28 αββ 20S

C29 C29 αββ 20R

C29 C29 αβ 20R

C28 C28 αββ 20R

Ion

217

(216

.70

to 2

17.7

0)

Sam

ple:

T11

SH62

TIC

Sa

mpl

e: T

11SH

62

Ion

191

(190

.70

to 1

91.7

0)

S

ampl

e: T

11SH

62

1

5052

5456

5860

6264

520

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

2000

4000

6000

8000

1000

0

1200

0

1400

0

1600

0 0

5354

5556

5758

5960

6261

Ret

entio

n tim

e

Ret

entio

n tim

e

Ret

entio

n tim

e

Abu

ndan

ce

Abu

ndan

ce

Abu

ndan

ce

6000

0070

0000

2000

00

9000

00

1000

00

1510

2025

3035

4045

5055

6065

5000

0040

0000

3000

00

8000

00

1100

000

1000

000

A B C

nCnC1313

nCnC1717

nCnC1515

nCnC1414

nCnC1818

nCnC2121

nCnC2424

nCnC2828

nCnC3030

nCnC3131

nCnC3232

nCnC3333

nCnC1212

nCnC11

nCnC1010

PrPr

PhPh

Pr/P

h =

2.24

CPI

=

1.38

VR

r = 0

.57

HI =

82

ololC

24/4

C24

/4Ts

Tm

C30 C30αβ

C29 C29αβ

C30 C30βα

bcT bcTbcR bcR

C29 C29βα

C28 C28αβ

Ts/T

m =

0.1

2C

30βα

/C30

αβ =

0.3

622

S/(2

2S+2

2R) =

0.4

8

22S 22S22R 22R

C3131αβ

22S 22S

22S 22S

22R 22R

C3232αβ

22R 22R

C3333αβ

C29 C29 ααα 20R

C28 C28 ααα 20R

C27 C27 ααα 20R

C29 C29 ααα 20S

C28 C28 ααα 20S

C29 C29 αββ 20S

C29 C29 βα 20S

C28 C28 αββ 20S

C29 C29 αββ 20R

C29 C29 αβ 20R

C28 C28 αββ 20R

Ion

217

(216

.70

to 2

17.7

0)

Sam

ple:

PT5

SH10

TIC

Sa

mpl

e: P

T5SH

10 (B

oka

Bil

shal

e)

g

Ion

191

(190

.70

to 1

91.7

0)

Sam

ple:

PT5

SH10

1

5052

5456

5860

6264

66

520

100

200

300

400

500

600

700

800

900

1000

1000 50

0

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000 0

5354

5556

5758

5960

61R

eten

tion

time

Ret

entio

n tim

e

Ret

entio

n tim

e

Abu

ndan

ce

Abu

ndan

ce

Abu

ndan

ce

4000

00

2000

00

1500

0010

0000

5000

0 010

1520

2530

3540

4550

5560

65

3500

0030

0000

2500

00

4000

00

A B C

Fig

.5. G

as

ch

rom

ato

gra

m (

TIC

) an

d m

ass

fra

gm

en

togra

ms

m/z

191 a

nd m

/z 2

17 o

f th

e a

lip

hati

c fra

cti

on

of B

hu

ban

Fo

rmati

on

sam

ple

T11S

H62 w

hic

h r

ep

rese

nts

th

e im

matu

re o

il w

ind

ow

(refe

r to

Appendix

B, p

. 375).

Fig

.6. G

as

ch

rom

ato

gra

m (

TIC

) an

d m

ass

fra

gm

en

togra

ms

m/z

191 a

nd m

/z 2

17 o

f th

e a

lip

hati

c fra

cti

on

of B

oka B

il F

orm

ati

on

sam

ple

PT

5S

H10 w

hic

h r

ep

rese

nts

th

e im

matu

re o

il w

ind

ow

(refe

r to

Appendix

B, p

. 375).


nCnC1717

nCnC1616

nCnC1818

nCnC1919

nCnC2121

nCnC2323

nCnC2525

nCnC2727

nCnC3030

nCnC3232

nCnC3434nCnC3535

nCnC1515

nCnC1414

nCnC1313

nCnC1212

nCnC11

nCnC1010

Pr Pr

PhPh

nCnC1616

Pr/P

h =

2.11

CPI

=

0.99

VR

r = 0

.71

HI =

80

ol olα

ol olβ

Ts

C24

/4C

24/4

TmC30 C30αβ C30 C30βα

C29 C29αβ

bcT bcTbcR bcR

C29 C29βα

C28 C28αβTs

/Tm

= 0

.57

C30

βα/C

30αβ

= 0

.18

22S/

(22S

+22R

) = 0

.61

22S 22S22R 22R

C3131αβ

22S 22S22R 22R

C3232αβ

22S 22S22R 22R

C3333αβ

22S 22S22R 22R

C3434αβ

C29 C29 ααα 20R

C28 C28 ααα 20R

C27 C27 ααα 20R

C29 C29 ααα 20S

C28 C28 ααα 20S

C29 C29 αββ 20S

C29 C29 βα 20S

C28 C28 αββ 20S

C29 C29 αββ 20R

C29 C29 αβ 20R

C28 C28 αββ 20R

Ion

217

(216

.70

to 2

17.7

0)

Sam

ple:

BG

1SH

5

TIC

Sa

mpl

e: B

G1S

H5

(Bhu

ban

shal

e)

Ion

191

(190

.70

to 1

91.7

0)

Sam

ple:

BG

1SH

5

1

5052

5456

5860

6264

66

200

400

600

800

1000

1200

1400

1000

2000

3000

4000

5000

6000

7000 0 0

5352

5455

5657

5859

6061

62R

eten

tion

time

Ret

entio

n tim

e

nCnC9

Ret

entio

n tim

e

Abu

ndan

ce

Abu

ndan

ce

Abu

ndan

ce

9000

0010

0000

011

0000

012

0000

0

8000

00

4000

0030

0000

2000

0010

0000 0

2015

105

2530

3540

4550

5560

65

7000

0060

0000

5000

00

A B C

nCnC1717

nCnC1818

nCnC1919

nCnC2020

nCnC2121

nCnC2222

nCnC2323

nCnC2525

nCnC2727

nCnC2929

nCnC3131

nCnC3333

nCnC1616

nCnC1515

nCnC1414

nCnC1313

nCnC1212

nCnC11

nCnC1010

PrPrPhPh

Pr/P

h =

1.02

CPI

=

1.04

VR

r = 0

.65

HI =

85

ololC

24/4

C24

/4

TsTm

C30 C30αβ

C29 C29αβ

C30 C30βα

C30 C30ββ

C30- C30-hopene

bcT bcTbcR bcR

C29 C29βα

C28 C28αβ

Ts/T

m =

0.7

4C

30βα

/C30

αβ =

0.1

422

S/(2

2S+2

2R) =

0.5

8

22S 22S22R 22R

C3131αβ

22S 22S

22S 22S

22R 22R

C3232αβ

22R 22R

C3333αβ

22S 22S22R 22R

C3434αβ

22S 22S22R 22R

C3535αβ

C29 C29 ααα 20R

C28 C28 ααα 20R

C27 C27 ααα 20R

C29 C29 ααα 20S

C28 C28 ααα 20S

C29 C29 αββ 20S

C29 C29 βα 20S

C28 C28 αββ 20S

C29 C29 αββ 20R

C29 C29 αβ 20R

C28 C28 αββ 20R

Ion

217

(216

.70

to 2

17.7

0)

Sam

ple:

SB

1SH

24

TIC

Sa

mpl

e: S

B1S

H24

Ion

191

(190

.70

to 1

91.7

0)

S

ampl

e: S

B1S

H24

1

5052

5456

5860

6264

6668

70

520

200

400

600

800

1000

1200

1400

1600

1800

2000

2000

1000

3000

4000

5000

6000

7000

8000

9000

1000

011

000 0

5354

5556

5758

5960

6261

Ret

entio

n tim

e

Ret

entio

n tim

e

Ret

entio

n tim

e

Abu

ndan

ce

Abu

ndan

ce

Abu

ndan

ce

1100

000

3000

00

1500

000

1000

00

1510

2025

3035

4045

5055

6065

9000

00

7000

00

5000

00

1300

000

1900

000

1700

000

A B C

Fig

. 7. G

as

ch

rom

ato

gra

m (

TIC

) an

d m

ass

fra

gm

en

togra

ms

m/z

191 a

nd

m/z

217 o

f th

e a

lip

hati

c fra

cti

on

of B

hu

ban

Fo

rmati

on

sam

ple

BG

1S

H5

wh

ich

rep

rese

nts

th

e m

atu

re o

il w

ind

ow

(re

fer

to A

ppendix

B, p

. 375).

Fig

. 8. G

as

ch

rom

ato

gra

m (

TIC

) an

d m

ass

fra

gm

en

togra

ms

m/z

191 a

nd

m/z

217 o

f th

e a

lip

hati

c fra

cti

on

of a B

oka B

il F

orm

ati

on

sam

ple

SB

1S

H24, in

terp

rete

d t

o r

ep

rese

nt

the m

atu

re o

ilw

indow

(re

fer

to A

ppendix

B, p

. 375).


diasteranes (Figs.5C, 6C, 7C and 8C). Commonlyused sterane parameter ratios include C

29 20S / (20S

+ 20R), C29

ββ / (ββ + αα), sterane C27

/ (C27

+C29

),diasteranes / steranes and diasterane 20S / (20S +20R).The values for these ratios listed in Table 5. Steraneabundance is very low compared to hopanes indicatingthe influence of terrestrial organic matter (Huang andMeinschein, 1979; Peters et al., 2005).

DISCUSSION

Thermal maturityVitrinite reflectance values of 0.56-0.71 %VR

r in the

Bhuban Formation shales and 0.48-0.76 %VRr in the

Boka Bil Formation shales indicate that the samplesvary from immature to early mature in terms of oilgeneration (Peters and Cassa, 1994). T

max values from

SRA and Rock-Eval pyrolysis are consistent with

these VRr values. The production index (PI) values

(0.11-0.25 and 0.15-0.28 for the two formations) areconsistent with these thermal maturities (Peters andCassa, 1994). These are further supported by theEOM/TOC values (0.04-1.23 and 0.09-0.73,respectively).

Thermal maturity-linked parameters of hopanes,steranes and diasteranes for the Bhuban and Boka Bilshales are mostly either at, or close to, their thermalequilibrium values. C

31- or C

32-homohopanes can be

used to calculate the 22S/(22S+22R) ratio, whichcommonly ranges from 0.57 to 0.62 during thermalmaturation (Seifert and Moldowan, 1986). The ratiovalues of 0.43-0.63 (Bhuban Formation) and 0.43-0.61 (Boka Bil Formation) for the studied samplesindicates that their thermal maturity ranged fromimmature to early oil window. For example, BhubanFormation shale sample T11SH62 with a T

max of 428

RP4SH2

Bhuban shales

Boka Bil shales

BG1SH5

FN2SH7

FN2SH8

T11SH54

T11SH62

T11SH59

KM1SH4

554

243

239

235

2814

1498

1778

767

9.48

9.50

3.10

5.69

49.23

54.53

46.77

24.04

37.90

35.70

22.93

21.22

89.85

126.31

62.00

64.11

100.79

86.87

82.26

65.21

461.31

416.07

197.56

196.79

47.38

45.20

26.03

26.91

139.07

180.84

108.78

88.15

16

16

16

19

16

16

16

21

0.77

0.95

0.94

1.06

1.00

0.98

1.11

0.94

Tot extr

Sample no.

EOM (ppm of whole rock)

EOM (mg EOM/g TOC) n-alkane parameters

Tot extr Aliph Arom CPI1 2

2.47

1.09

0.99

1.11

1.37

1.02

1.27

1.00

T11SH65

PT5SH10

PT5SH14

SB1SH5

SB1SH24

SB1SH11

T11SH67

132

255

1458

731

264

504

230

3.97

1.98

72.67

38.29

11.03

28.90

15.39

16.66

32.73

209.12

97.10

30.08

55.00

56.42

38.87

88.04

520.57

261.21

94.26

152.87

143.61

20.43

34.72

281.79

135.39

41.11

83.89

71.81

18

18

21

16

16

16

16

1.18

0.91

1.38

1.00

0.81

0.65

1.04

1.06

0.96

1.61

1.12

1.01

0.88

1.03

SB1SH29 238

47

52

32

41

30

43

55

45

HC in extract(%)

53

39

54

52

44

55

50

51 11.76 41.15103.47 52.91 16 0.46 0.68

SB1SH32

SB1SH47

BK9SH70

BK9SH69

237

235

1381

548

9.99

10.79

94.83

55.67

61.94

37.75

184.39

74.22

157.85

138.43

727.03

304.63

71.93

48.54

279.22

129.89

16

16

16

16

1.05

0.67

0.76

0.97

1.23

1.21

0.80

1.08

BK9SH71 421

46

35

38

43

44 115.18 38.79123.96 53.97 16 1.14 1.33

CPITotal HC (yield)

n-alk max

0.54

1.08

0.98

1.33

1.19

1.31

2.26

1.36

1.00

2.11

1.95

3.74

1.55

1.67

2.76

0.99

0.47

0.27

0.39

0.32

0.91

0.40

0.30

2.42

1.44

1.39

1.38

2.45

1.26

0.58

2.24

0.81

0.56

1.17

0.50

0.85

0.55

1.05

1.38

0.93

1.28

1.05

1.10

0.70

1.42

1.02

1.38

1.50

1.21

1.24

1.16

1.23

0.42

0.37

0.46

0.31

0.41

0.82

0.93

1.052.32 0.82

0.73

Ph/nC18Pr/nC17Pr/Ph

Table 3. Soluble extract yield and alkane parameters of the studied shale samples from the Bhuban and BokaBil Formations, Bengal Basin (see Appendix A, p. 375).


Sample no.

0.65

0.03

0.04

0.07

0.04

0.04

0.05

0.75

0.57

0.82

0.33

0.87

0.38

0.59

1.35

0.83

0.26

0.68

0.32

1.08

0.89

0.29

0.15

0.09

0.31

0.18

0.39

0.20

0.41

0.58

0.47

0.49

0.44

0.33

0.55

0.06

0.05

0.11

0.14

0.20

0.14

0.12

0.52

0.61

0.49

na

0.50

na

na = not analyzed.

0.63

0.04

0.09

0.29

0.06

0.79

0.14

0.12

0.60

0.27

0.48

0.96

0.37

0.15

0.15

0.36

0.44

0.47

0.55

0.46

0.90

0.18

0.17

0.07

0.21

0.49

0.63

0.48

0.43

0.07

0.29

0.04

0.03

0.04

0.08

0.52

0.71

0.43

0.74

1.29

1.86

0.45

1.24

0.87

1.48

0.77

0.28

0.30

1.35

1.05

0.17

0.32

0.14

0.15

0.13

0.23

0.22

0.59

0.52

0.57

0.43

0.60

0.44

0.47

0.09

0.18

0.05

0.17

0.18

0.15

0.05

0.57

0.44

0.58

0.50

0.60

0.50

0.43

0.08

0.02

0.05

1.15

0.62

0.34

0.73

0.33

1.21

0.14

0.12

0.70

0.58

0.46

0.50

0.14

0.61

0.12

0.57

0.61

0.44

bc/C30-hopTs/Tm C29-hop/C30-hop

C30-mor/C30-hop

C31 22S/(22S+22R)

C32 22S/(22S+22R)

Oleanane index

RP4SH2

Bhuban shales

Boka Bil shales

BG1SH5

FN2SH7

FN2SH8

T11SH54

T11SH62

T11SH59

KM1SH4

T11SH65

PT5SH10

PT5SH14

SB1SH5

SB1SH24

SB1SH11

T11SH67

SB1SH29

SB1SH32

SB1SH47

BK9SH70

BK9SH69

BK9SH71

oC, vitrinite reflectance of 0.56 %VRr and C

32 22S/

(22S+22R) ratio of 0.49 is immature. However BhubanFormation shale sample BG1SH5 with T

max of 435 oC,

vitrinite reflectance of 0.71 %VRr and C

32 22S/

(22S+22R) ratio of 0.61 is early mature. Similarly BokaBil Formation sample PT5SH10 is immature and sampleSB1SH24 is early mature.

Mackenzie et al. (1980) reported that the ratio of17β(H),21α(H)-moretanes to the corresponding17α(H),21β(H)-hopanes decreases with increasingthermal maturity from about 0.80 in immaturebitumens to less than 0.15 in mature source rocksand in oils to a minimum of 0.05. The calculated C

30-

moretane/C30

-hopane ratio of the Bhuban and BokaBil shales is 0.09-0.44 and 0.12-0.70 respectively, againindicating marginal thermal maturity.

The calculated diasterane 20S / (20S + 20R) ratioof the studied shales varies from 0.13 to 0.70 (Bhuban)and 0.17 to 0.80 (Boka Bil Formation). Mackenzie etal. (1980) proposed that at thermal equilibrium theratio is 0.60. This ratio therefore indicates that theBhuban and Boka Bil shale samples are immature tomarginally mature.

The yellow-orange to orange-brown colour ofspores corresponding to a thermal alteration index(TAI) of 2.5-2.8 (normal white reflected light)indicates immature to early mature conditions. Thesolid bitumen or bitumen staining is considered to befree hydrocarbons, indicating that hydrocarbonexpulsion in these two formations has occurred.

Hydrocarbon generation potentialA cross-plot of T

max (°C) versus production index

(PI) shows that the organic matter in the Bhuban andBoka Bil shale samples may already have begun togenerate hydrocarbons (Fig.9). It is consistent withvitrinite reflectance, TAI (spore colour) and T

max

values. Tmax

values vary from 421 to 457 °C (BhubanFormation) and 421 to 446 °C (Boka Bil Formation);the onset of hydrocarbon generation is representedby T

max 435°C (Peters and Cassa, 1994).

In summary, the Bhuban and Boka Bil Formationshales have low to fair TOC (0.16-0.90% and 0.15-0.55%), low to fair S2 values (0.13-2.48 mg HC/gTOC; and 0.15-0.40 mg HC/g TOC), low to moderatetotal extract yields (235-2814 ppm; and 235-1458

Table 4. Hopane biomarker parameters (measured from m/z 191 fragmentogram) of the studied samples (seeAppendix B, p. 375).


ppm), low to fair production index (0.11-0.25; and0.15-0.28), low to medium hydrocarbon yield (20.43-180.84 mg HC/g TOC; and 34.72-279.79 mg HC/gTOC) and minor liptinite contents, and therefore havepoor to fair potential for hydrocarbon generation.However a cross-plot of hydrocarbon yield (mg HC/g TOC) versus hydrocarbon extract (%) indicatesthat the shales have variable potential ranging frommarginal to very good (Fig.10). But this good sourcepotential is not supported by other lines of evidence,and may indicate that the hydrocarbons are derivedfrom more deeply-buried source rocks.

A triangular diagram of vitrinite-liptinite-inertinite(Fig.11) indicates that the organic matter in theformations is mostly gas prone. Minor potential forliquid hydrocarbons is attributed to the contents ofliptinitic macerals.

SOURCE ROCK DEPOSITIONALENVIRONMENT

The triangular steranes plot (Fig.12) indicates thatshales in both formations were deposited mainly in aterrestrial setting with some marine-influenced input

(cf Huang and Meinschein, 1979). The cross-plot ofPr/nC

17 versus Ph/nC

18 (Fig.13) indicates that the

organic matter in the shales was derived mainly fromterrestrial material. Depositional conditions were oxicto anoxic (Peters et al., 2005). The cross-plot of Pr/Ph vs C

27/(C

27+C

29) sterane (Fig.14) likewise indicates

a terrestrial depositional environment with oxic-anoxicconditions although with slight marine influence(Waseda and Nishita, 1998).

Source rocks with Pr/Ph ratio > 1 are likely tohave been deposited in an oxidizing environmentalsetting (Peters and Moldowan, 1993). The Pr/Ph ratiosof the analyzed shales (0.99 - 3.74, Bhuban Formation;and 0.58-2.32, Boka Bil Formation) indicates aterrestrial depositional environment with oxicconditions. The presence of cadalene in the analyzedPyGC pyrograms and bicadinane in the gaschromatograms (m/z 191) also supports a terrestrialdepositional setting consistent with van Aarssen etal. (1992), Pearson and Alam (1993) and Wan Hasiah(1999).

Berner and Raiswell (1984) classified source rockswith C/S > 10 as deposited in a non-marineenvironment. C/S ratios of the analyzed shale samples

Sample no.

6.79

25.09

17.76

16.04

25.97

14.78

31.01

59.26

29.96

20.92

23.58

15.47

16.67

33.33

33.95

44.94

61.31

60.38

58.56

68.55

35.66

0.22

0.50

0.35

na

0.36

0.34

0.40

0.22

0.31

0.09

na

0.10

0.08

0.37

0.48

0.70

0.52

na

0.56

0.29

na = not analyzed.

0.58

0.28

0.42

0.35

na

0.05

0.07

22.52

14.98

9.29

24.70

22.07

23.67

26.23

31.22

55.41

61.35

64.48

44.08

0.35

0.46

0.40

0.32

0.12

0.05

0.23

0.03

0.19

0.13

0.51

0.27

0.17

0.22

0.26

0.15

0.27

C27-ster (%)

C28-ster (%)

C29-ster (%)

0.64

0.40

0.25

0.28

0.21

0.20

0.48

0.28

0.28

0.29

0.41

Ster-C27/ster-(C27+C29)

Ster C29 ββ/ (ββ+αα)

Diaste/Sterane

Diaste 20S/ (20S+20R)

0.81

0.62

0.63

na

0.63

0.70

0.66

0.58

0.66

0.68

0.59

33.15

17.83

19.18

17.79

21.05

20.30

23.96

34.25

18.55

32.24

20.19

24.74

33.46

36.87

32.60

63.61

48.57

62.02

54.21

46.24

39.17

0.48

0.04

0.41

0.34

0.36

0.34

0.13

0.38

0.23

0.22

0.16

0.24

0.07

0.34

0.65

0.47

0.56

0.19

0.19

0.39

0.17

0.34

0.05

0.15

0.16

0.18

0.09

22.77

19.62

33.66

27.09

43.56

53.28

0.39

0.32

0.38

0.07

0.80

na

0.49

0.39

0.16

0.51

0.23

0.40

0.25

0.31

0.42

0.48

0.44

0.34

0.89

0.93

0.95

0.57

0.59

0.72

0.87

0.69

na

0.46 0.62

14.0042.00 44.00 nana na0.49

Hopane/ Sterane

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

RP4SH2

Bhuban shales

Boka Bil shales

BG1SH5

FN2SH7

FN2SH8

T11SH54

T11SH62

T11SH59

KM1SH4

T11SH65

PT5SH10

PT5SH14

SB1SH5

SB1SH24

SB1SH11

T11SH67

SB1SH29

SB1SH32

SB1SH47

BK9SH70

BK9SH69

BK9SH71

Table 4. Sterane and diasterane biomarker parameters (measured from m/z 217 fragmentogram) of thestudied shale samples (see Appendix B, p. 375).


o

Tmax

( C

)

Production Index (PI)

420

430

440

450

460

470

480

0.00 0.20 0.40 0.60 0.80 1.00

Inert carbon

Hydrocarbon generation

Post mature

Non-indegenous hydrocarbon

Boka Bil shales

Bhuban shales

0

10

20

30

40

50

60

70

80

0 25 50 75 100 125 150 175 200 225 250 275 300

Hyd

roca

rbon

in e

xtra

ct (%

)

Hydrocarbon yield (mg HC/ g TOC)

Very good

Source rock potential

Good Nil

Mar

gina

l

Imm

atur

e M

argi

nal m

atur

e M

atur

e

Boka Bil shales

Bhuban shales

Liptinite

Inertinite Vitrinite

50%

50% 50

%

Oil

Barren

Dry Gas

Gas + Condensate

Boka Bil shales

Bhuban shales

Fig. 9. Cross-plot of Tmax

(oC) and productionindex (PI), showing that both the Bhubanand Boka Bil Formation shale samples fallwithin and outside the hydrocarbongeneration range (cf. Hakimi et al., 2011).

Fig. 11. Triangular diagram on the basis of visualkerogen analysis (vol %) showing that Bhuban andBoka Bil Formtion shales have the potential for drygas generation (after Tissot and Welte, 1978).

Boka Bil shales

Bhuban shales

C28ααα20R

C27ααα20R C29ααα20R

50%

50% 50

%

Higher plant

Terrestrial

Estu

arin

e

or s

hallo

w

lacu

strin

e

Ope

n m

arine

or la

custr

ine

Plankton

Fig. 12. Trainagular plot showing the relationshipbetween sterane compositions, source input anddepositional environment. Bhuban and Boka BilFormation shales are dominated by terrestrialorganic matter, together with a minor contributionfrom marine organic matter.

Fig. 10. Cross-plot of hydrocarbon yield (mgHC/g TOC) and hydrocarbon in extract (%),showing that both the Bhuban and Boka BilFormation shale samples correspond mostlywith marginal to good quality petroleumsource rocks (after Powell, 1978).


range from 2.81 to 128.57 (Bhuban Formation) and2.38 to 28.75 (Boka Bil Formation). Therefore itindicates a mixed depositional environment, i.e. mostlyterrestrial with a slight marine influence. A mixeddepositional setting is also indicated by the C/N ratioof the analysed shale samples (Sampei andMatsumoto, 2001). A terrestrial setting is supportedby the dominance of vitrinite macerals and theabundance of woody fragments. The presence ofliptinite macerals indicates some marine influence.Banerji (1984) however studied the same SurmaGroup deposits in the Indian portion of the BengalBasin; he also proposed a mixed depositionalenvironment ranging from open-marine to terrestrial,consistent with the present interpretations.

The organic geochemical and petrological datasuggest that there is no major difference between theshales in the Bhuban and Boka Bil Formations in theanalysed wells.

CONCLUSIONS

Organic geochemical and petrological analyses of shalecore samples from the Bhuban and Boka BilFormations from eight wells in the eastern BengalBasin, Bangladesh, allow the following principalconclusions to be drawn:

• Shales in both formations include organic mattercomprising a mixture of gas-prone Type III and minorType II kerogen. The shales have poor to fair sourcerock potential as indicated by the contents of TOCand S

2, cross-plots of PI versus T

max, and hydrocarbon

yield versus hydrocarbons in extract, as well as adominance of aromatic compounds and n-alkane/alkene doublets in the PyGC pyrograms.

• The shale samples analysed were thermallyimmature to early mature as indicated by vitrinitereflectance (Bhuban Formation: 0.56-0.71 %VR

r; Boka

Bil Formation: 0.48-0.76 %VRr) and Rock-Eval T

max

0.1

1

10

100

0.1 1 10

Terrigenous Type III

Marine Algal Type II Reducing

Oxid

izing

Mixed Type II/III

Biodegradation

Maturity

Pris

tane

/nC

17

Phytane/nC18

Boka Bil shales

Bhuban shales

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

Terrestrial/ Coastal anoxic

Terrestrial/ Coastal oxic

Pelagic oxic

Stro

ng b

iode

grad

atio

n

Pelagic anoxic Boka Bil shales

Bhuban shales

Ster

ane

C27

/(C27

+C29

)

Pr/Ph

Fig. 13. Graph of pristane/nC17

versusphytane/nC

18 for the investigated

samples showing inferred oxicity andorganic matter type in the source rockdepositional environment (cf. Peters et

al., 2005; van Koeverden et al., 2011).Bhuban and Boka Bil Formationsamples correspond to terrigenousType III and mixed Type III/II materialdeposited under oxic-anoxicconditions.

Fig. 14. Cross-plot of Pr/Ph ratios andsterane C

27/(C

27+C

29) values with

interpreted depositional environment andsource input. Bhuban and Boka BilFormation shales correspond to aterrestrial (oxic-anoxic) depositionalsetting, with minor influence from pelagicmaterial (cf. Waseda and Nishita, 1998;Sawada, 2006; Hossain et al., 2009).


(421-457 oC and 421-446 oC, respectively). Theproduction index value, EOM/TOC ratio, TAI valueand the biomarker values of 22S / (22S + 22R) hopane,moretane/hopane ratio and sterane parameters areconsistent with this level of thermal maturity.

• Biomarker parameters such as low to high Tm/Ts ratio, moderate Pr/Ph ratio, alternating dominanceof odd-over-even and even-over-odd homologues inn-alkanes, high abundance of C

29 regular steranes and

medium-to-high C/S ratio indicate that the organicmatter is mostly derived from land plants with a minorcontribution from marine-influenced sources. Themarine influence was suggested by the presence ofresinite, liptodetrinite and other fluorescing amorphousmaterials under microscope.

ACKNOWLEDGEMENTS

The authors are grateful to the Chairman of BangladeshOil, Gas and Mineral Corporation (BOGMC) forsupplying the samples and data for this research. Md.Aqueel Ashraf helped to carry out the elementalanalyses. The first author cordially appreciates thecooperation and motivation provided by Khalil R.Chowdhury and his colleagues at JahangirnagarUniversity while continuing this study. Sylhet GasFields Ltd (Petrobangla) is acknowledged forproviding official support to the first author. Theauthors are grateful to P. K. Saraswati (Indian Instituteof Technology-Bombay) and two anonymous refereesfor their fruitful suggestions on earlier versions ofthe manuscript. The authors also acknowledge grantsPV100-2011A and RG145/11AFR from the Universityof Malaya for financial support.

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(i) F

ragm

ento

gram

m/z

191

(ii) F

ragm

ento

gram

m/z

217

C24/4

Tm

C28αβ

C29αβ

C29Ts

C30αβ

C29βα

C30βα

C31αβ

C31αβ 22S

C32αβ

C31αβ 22R

C33αβ

C34αβ

C27ααα 20S

C27αββ 20R

C27αββ 20S

C27ααα 20R

C28ααα 20S

C28αββ 20R

C28αββ 20S

C28ααα 20R

C29ααα 20S

C29αββ 20R

C29αββ 20S

C29ααα 20R

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)

C29βα 20S

C29αβ 20R

24-ethyl-13β(H),17α(H)-diacholestane (20S) (diasterane)

24-ethyl-13α(H),17β(H)-diacholestane (20R) (diasterane)

Ts

Tetracyclic terpane

17α(H),22,29,30-trisnorhopane

17α(H),29,30-bisnorhopane

17α(H),21β(H)-norhopane

18α(H),30-norneohopane

17α(H),21β(H)-hopane

17β(H),21α(H)-hopane (normoretane)

18α(H),22,29,30-trisnorneohopane

27

27

28

29

29

C30ββ 17β(H),21β(H)-hopane 30

bcT Bicadinane ‘T’ 30bcR Bicadinane ‘R’ 30

30

29

27

30

31

31

32

33

34

31

27

27

27

28

28

28

27

28

29

29

29

29

29

29

17β(H),21α(H)-hopane (moretane)

17α(H),21β(H)-homohopane (22S)

17α(H),21β(H)-homohopane (22R)

17α(H),21β(H)-homohopane (22S and 22R)


ol 3018α(H)-oleanane



Carbon no.

Peak identity Compound

TOC

S2

S3

HI

HCs

OI

EOM

Tot extr

Arom

Alip

NSO

Pr/Ph

Pr/nC17

S1

Total Organic Carbon (wt.%).

HCs generated by pyrolytic degradation of kerogen(i.e. hydrolysable HCs) (mg HC/g Rock).

CO2 generated from low temperature (upto 390 C) pyrolysis (mg CO2/g Rock).

Hydrogen Index: (S2/TOC)*100 (mg HC/g TOC).

Hydrocarbons.

Tmax Maximum temperature at top of S2 peak ( C).

PI Production Index (i.e. Transformation Ratio):{S1/ (S1 + S2)}.

Free or thermally extractable HCs (mg HC/g Rock).

Oxygen Index: (S3/TOC)*100 (mg CO2/g TOC).

Total extract.

VRr Mesured random vitrinite reflectance (%).

Aliphatic.

Aromatic.

Pr 2,6,10,14-tetramethylpentadecane

Ph 2,6,10,14-tetramethylhexadecane

Polar compounds (e.g., N, S, O etc).

Pristane / nC17.

Pristane / Phytane.

nC15, .... Normal alkane with 15 carbon numbers, ...........

C15, ....... Normal alkene with 15 carbon numbers, ............

Ph/nC18

CPI Carbon Preference Index (Peters and Moldowan, 1993):2(C23+C25+C27+C29)/[C22+2(C24+C26+C28)+C30]

Phytane / nC18.

hop Hopanemor Moretanester Steranediaste Diasterane

Extractable Organic Matter (Bitumen).

Term Description

1

CPI Carbon Preference Index (Peters and Moldowan, 1993):1/2*[(C25+C27+C29+C31+C33)/(C26+C28+C30+C32+C34)+ (C25+C27+C29+C31+C33)/(C24+C26+C28+C30+C32)]

2

Appendix A. Definitions of abbreviations andand units.

Appendix B. Peak assignments for alkanes in gaschromotagrams: (i) m/z 191 mass fragmentograms ; (ii) m/z217 mass fragmentograms.

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