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Petroleum geochemistry of the Potwar Basin, Pakistan: 1. Oiloil correlation

using biomarkers, d13C and dD

Muhammad Asifa,b,, Tahira Fazeelat c, Kliti Grice b

a Department of Basic Sciences and Humanities, University of Engineering and Technology, KSK Campus, Lahore, Pakistanb WA Organic and Isotope Geochemistry Centre, The Institute for Geoscience Research, Department of Chemistry, Curtin University, GPO Box U1987, Perth, WA 6845, Australiac Chemistry Department, University of Engineering and Technology, GT Road, Lahore, Pakistan

a r t i c l e i n f o

Article history:

Received 16 January 2011

Received in revised form 21 April 2011

Accepted 5 August 2011

Available online 16 August 2011

a b s t r a c t

Geochemical characterisation of 18 crude oils from the Potwar Basin (Upper Indus), Pakistan is carried

out in this study. Their relative thermal maturities, environment of deposition, source of organic matter

(OM) and the extent of biodegradation based on the hydrocarbon (HC) distributions are investigated. A

detailed oiloil correlation of the area is established. Gas chromatographymass spectrometry (GC

MS) analyses and bulk stable carbon and hydrogen isotopic compositions of saturated and aromatic

HC fractions reveals three compositional groups of oils. Most of the oils from the basin are typically gen-

erated from shallow marine source rocks. However, group A contains terrigenous OM deposited under

highly oxic/fluvio-deltaic conditions reflected by high pristane/phytane (Pr/Ph), C30 diahopane/C29Ts,

diahopane/hopane and diasterane/sterane ratios and low dibenzothiophene (DBT)/phenanthrene (P)

ratios. The abundance of C19-tricyclic and C24-tetracyclic terpanes are consistent with a predominant ter-

rigenous OM source for group A. Saturated HC biomarker parameters from the rest of the oils show a pre-

dominant marine origin, however groups B and C are clearly separated by bulk d13C and dD and the

distributions of the saturated HC fractions supporting variations in source and environment of depositionof their respective source rocks. Moreover, various saturated HC biomarker ratios such as steranes/

hopanes, diasteranes/steranes, C23-tricyclic/C30 hopane, C28-tricyclic/C30 hopane, total tricyclic ter-

panes/hopanes and C31(R + S)/C30 hopane show that two different groups are present. These biomarker

ratios show that group B oils are generated from clastic-rich source rocks deposited under more suboxic

depositional environments compared to group C oils. Group C oils show a relatively higher input of algal

mixed with terrigenous OM, supported by the abundance of extended tricyclic terpanes (up to C 41+) and

steranes.

Biomarker thermal maturity parameters mostly reached to their equilibrium values indicating that the

source rocks for Potwar Basin oils must have reached the early to peak oil generation window, while aro-

matic HC parameters suggest up to late oil window thermal maturity. Theextent of biodegradation of the

Potwar Basin oils is determined using various saturated HC parameters and variations in bulk properties

such as API gravity. Groups A and C oils are not biodegraded and show mature HC profiles, while some of

the oils from group B show minor levels of biodegradation consistent with high Pr/n-C17, Ph/n-C18 and

low API gravities.

2011 Elsevier Ltd. All rights reserved.

1. Introduction

The Potwar Basin is the main source of petroleum hydrocarbons

in northern Pakistan. A number of small and medium sized oil and

gas fields have been discovered from both terrigenous and marine

source rocks in the basin. These oil fields are in Precambrian to Ter-

tiary aged reservoir units. The Paleocene Patala Formation type II

and III kerogens have been assumed to be the primary source of

hydrocarbons in the area, but other potential source rocks may

have also contributed to different parts of the petroleum systems

within the basin (Wandrey et al., 2004; Fazeelat et al., 2010). The

oldest potential source rocks are from the Precambrian Salt Range

Formation with a mixture of clastic, carbonate and evaporite dom-

inant sections. Similarly, Permian Sardhai and Chhidru formations

have significantly higher total organic carbon (TOC) contents and

are possible source rocks (Quadri and Quadri, 1997). In the past,

a limited number of studies have been carried out mainly based

on RockEval pyrolysis data (Ahmed and Alam, 1990; Fazeelat

et al., 2010) and studies of the saturated hydrocarbon (HC) distri-

butions (Fazeelat, 1994; Ahmed and Alam, 2007) fromthe area. Re-

cently, a biodegraded oil seep and a crude oil from the Potwar

0146-6380/$ - see front matter 2011 Elsevier Ltd. All rights reserved.

doi:10.1016/j.orggeochem.2011.08.003

Corresponding author at: Department of Basic Sciences and Humanities,

University of Engineering and Technology, KSK Campus, Lahore, Pakistan.

Tel.: +92 3218850163.E-mail address: [email protected] (M. Asif).

Organic Geochemistry 42 (2011) 12261240

Contents lists available at SciVerse ScienceDirect

Organic Geochemistry

j o u r n a l h o m e p a g e : w w w . e l s e v i e r . c o m / l o c a t e / o r g g e o c h e m


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Table

1

Geologicalinformation,

n-a

lkanes,isoprenoidratiosandbulkisotopedata.

Sample

name

Depth

(m)

Reservoir

API

gravity

Pr/Pha

Pr/n-C17

b

Ph/n-C18c

CP

Id

OEPe

d13Csats

f

()

d13Caros

()

dDsats

g

()

dDaros

()

d13Caver

h

()

dDaver

()

DBT/Pi

Group

BLj

Formation

Age

P1

2680

Khewra

Cambrian

48.0

3.2

0.4

0.2

1.0

1.0

26.4

24.5

117

111

25.4

114

0.16

A

0

P2

2187

Chorgali

Eocene

36.2

1.5

1.0

0.7

0.9

1.0

23.1

20.8

155

130

21.9

142

0.17

B

0

P3

2063

Jutana

Cambrian

33.0

2.0

1.0

0.5

1.0

1.0

0.22

B

0

P4

3640

Jutana

Cambrian

19.3

1.2

1.3

0.9

1.0

1.0

0.52

B

2

P5

3645

Jutana

Cambrian

22.7

1.3

1.3

0.9

1.0

1.0

22.4

21.0

132

125

21.7

128

0.45

B

2

P6

2773

Khewra

Cambrian

26.6

1.3

1.4

0.9

1.0

1.0

0.43

B

3

P7

2694

Khewra

Cambrian

25.0

1.5

1.2

0.8

1.0

0.9

23.0

21.1

149

135

22.0

142

0.37

B

2

P8

3063

Khewra/Tobra

Cambrian

23.2

1.3

1.1

0.8

1.0

0.9

0.39

B

1

P9

3318

Khewra/Tobra

Cambrian

25.0

1.4

0.8

0.6

1.0

1.0

22.9

22.2

126

132

22.5

129

0.33

B

1

P10

2687

Khewra

Cambrian

18.4

1.2

1.3

0.9

0.9

0.9

22.6

21.9

132

141

22.2

137

0.66

B

3

P11

2179

Chorgali

Eocene

16.0

1.0

1.3

1.0

0.9

0.9

23.0

21.1

136

136

21.7

136

0.84

B

3

P12

2103

Chorgali/

Sakaser

Eocene

16.1

1.0

1.3

1.0

0.9

0.8

22.3

21.1

130

134

21.6

132

0.93

B

3

P13

3612

Chorgali/

Sakaser

Eocene

16.0

1.2

1.1

0.8

1.0

0.9

22.3

21.0

145

129

21.8

137

0.31

B

1

P14

Chorgali/

Sakaser

Eocene

40.0

1.5

0.8

0.5

1.0

1.0

23.1

20.5

145

139

23.5

142

0.27

B

0

P15

4096

Chorgali/

Sakaser

Eocene

45.0

1.4

0.9

0.7

1.0

1.0

25.0

22.0

148

139

23.6

143

0.26

C

0

P16

4174

Chorgali/

Sakaser

Eocene

46.0

1.4

0.9

0.7

1.0

1.0

25.1

22.1

23.8

0.26

C

0

P17

4485

Datta

Jurassic

38.4

1.6

0.6

0.4

1.0

1.0

26.1

21.5

129

122

23.7

126

0.25

C

0

P18

4450

Datta

Jurassic

41.1

1.6

0.8

0.6

1.0

1.0

26.1

21.4

25.4

0.16

C

0

:notdeter

mined.

aPr/Ph,pristane/phytane.

bPr/n-C17

,pristane/n-C17alkanes.

cPh/n-C18,phytane/n-C18alkanes.

dCPI,carbonpreferenceindex.

eOEP,oddevenpredominance.

fd13C()withrespecttoVPDBreportedwithinstandard

deviationof0.2.

gdD()withrespectofVSMOWwithinstandarddeviati

onof3.

h

d13Caver:age(d13Csats+

d13Caros)/2;dDaver:(dDsats+dDaros)/2

.

iDBT/P,d

ibenzothiophene/phenanthrene.

jBL,biod

egradationlevel(Wengeretal.,2001).

M. Asif et al. / Organic Geochemistry 42 (2011) 12261240 1227


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Basin have been correlated based on their biomarker distributions

(Fazeelat et al., 2011). Organic geochemical data, particularly bio-

markers from potential source rocks in the Potwar Basin, have

never been reported, nor has a detailed oiloil correlation ever

been undertaken.

The application of biomarkers and stable isotope analyses hasbeen recognised as a powerful tool in exploration petroleum geo-

chemistry (e.g. Dawson et al., 2005, 2007; Asif et al., 2009; Maslen

et al., 2011). Biomarkers (based on structural grounds) in bitumi-

nous organic matter (OM) can provide valuable information on:

(i) the source of their natural product precursors (i.e. Eukaryotes,

Prokaryotes and Archaea), (ii) paleoenvironmental depositional

conditions (marine, lacustrine, hypersaline or fluvio-deltaic), (iii)

lithology of potential petroleum source rocks (carbonate versus

shale), (iv) relative thermal maturity of potential source rocks

and (v) extent of biodegradation of petroleum HCs. However, many

of the above factors are often interrelated and have been consid-

ered collectively for correlation studies (e.g. Murray and Boreham,

1992). Variation in biomarker abundance has been used success-

fully for oil correlation between source rocks and/or other oils(e.g. Jiang and Li, 2002; Obermajer et al., 2002; Pasadakis et al.,

2004; Zhang and Huang, 2005). Bulk isotope analysis (carbon and

hydrogen) of crude oils, bitumens and kerogen is also useful. The

bulk isotope composition of saturated and aromatic fractions of

crude oils has been applied to determine the source of OM (terrig-

enous versus marine) for many oils worldwide (Sofer, 1984; Chung

et al., 1992; Andrusevich et al., 1998). However, a recent study has

showed limitations of bulk d13C data and reported a d13C values of

individual aromatic HCs to determine the source OM of Western

Australian crude oils (Maslen et al., 2011).

In the current study, organic geochemical parameters based on

biomarker distributions and stable carbon and hydrogen isotopes

of saturated and aromatic HC fractions have been used to investi-

gate the source and thermal maturity of OM, depositional paleoen-

vironment, lithology and extent of biodegradation of HCs from the

Potwar Basin (Upper Indus Basin, Pakistan). Heavy to light crude

oils have been identified in a small region of the Potwar Basin.

The causes for these differences in physical properties are pres-

ently unknown. The possible reasons for these different crude oil

types are related to the complex geology of the area and/or differ-

ences in the source of OM and its environment of deposition.

2. Experimental

2.1. Samples and geological setting

Eighteen crude oils were selected from the Potwar Basin

(Table 1). The oils cover half of the Potwar plateau, which is the

largest HC producing zone in northern Pakistan (Upper Indus Ba-

sin). The source of these crude oils has not been fully correlated

with any specific source rocks of the Upper Indus Basin. A few

studies using organic geochemical properties from cuttings, out-

crops and core samples of different geological formations were

undertaken andcorrelated partially with Potwar crude oils (Ahmed

and Alam, 1990, 2007). Both heavy and light oils have been discov-

ered in the basin (API gravity, Table 1). The heavy oils are geneti-

cally related to light oils, and bear a close spatial relationship

(Asif et al., 2008). The locations of crude oils used in this studyare shown in Fig. 1 and marked on a stratigraphic chart in corre-

sponding geological formations in Fig. 2.

The geological structure of the Potwar Basin is very complex

due to the result of the Tertiary Himalayan collision between the

Eurasian and Indian plates (Farah et al., 1984). This intense tectonic

activity has significantly over thrust the Himalayan in the north

and northwest and a series of faulted and unfaulted anticlines

developed as the result of the multiple detachments of deep sur-

faces from Cambrian. The Potwar Basin contains mostly carbonate

reservoir rocks of Precambrian to Tertiary ages. The basin infill

started with thick Precambrian evaporite deposits overlain by rel-

atively thin Cambrian to Eocene age deposits followed by thick

MiocenePliocene deposits. The Precambrian salt deposits pro-

vided an easy detachment of Eocene-to-Cambrian (EC) sequencesas a result of intense tectonic activity during Himalayan Orogeny

during the Pliocene to middle Pleistocene. This EC sequence in

the Potwar Basin affected by compressional forces has generated

a large number of folds and faults in the area ( Aamir and Siddiqui,

2006). These folds and faults have formed many small reservoirs

Fig. 1. Map of the Potwar Basin indicating locations of oils used in this study (Wandrey et al., 2004; modified from USGS Bulletin 2208B and references therein).

1228 M. Asif et al. / Organic Geochemistry 42 (2011) 12261240


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Fig. 2. Stratigraphy of the Potwar Basin. The reservoir formations corresponding to oil samples used in this study are also shown in the right column ( Wandrey et al., 2004;modified from USGS Bulletin 2208B and references therein).



6/16


and thus crude oils discovered in the Potwar Basin have shown to

be derived from a range of geological formations (Fig. 2).

The generalised stratigraphy of the Potwar Basin is shown in

Fig. 2. The oldest producing reservoir is a Precambrian Salt Range

formation. It consists of thick carbonates overlain by evaporites.

Marine shales and massive sandstones have been reported in theKhewra Formation of the Lower Cambrian Jhelum Group. The Khe-

wra Formation has yielded the P1 and P6P10 oils analysed in the

present study. The overlying Jutana Formation consists primarily of

sandy carbonates and nearshore sandstones and reservoirs that

have led to the P3P5 oils. The Permian Tobra Formation consists

of glacial tillites, siltstone and shales, and samples P8 and P9 are

derived from the Tobra and the Khewra formations. The Jurassic

strata include the Datta and Shinawari formations, which are near-

shore consisting of siliciclastics that contain some non-marine

sandstone intervals (Khan et al., 1986). The Datta Formation has

led to the production of the P17 and P18 oils. Shallow marine car-

bonate strata of the Eocene Chorgali and Sakaser formations form

an important HC producing horizon in the Potwar Basin. Chorgali

and Sakaser formations consist of medium-bedded limestonesand fine crystalline dolomites. Both formations are oil and gas pro-

ducing reservoirs and the P2 and P11P16 oils are derived from the

Chorgali and Sakesar formations.

2.2. Sample preparation, liquid chromatography and 5A molecular

sieving

The sample preparation and liquid chromatography procedures

used were similar to those described in Asif et al. (2009). Briefly,

crude oils were separated using liquid chromatography on silica

gel. Saturated HC fractions were eluted with n-hexane (30 ml), aro-

matic fractions with a mixture ofn-hexane:CH2Cl2 (7:3, 30 ml) and

polars with a mixture of CH2Cl2:CH3OH (1:1, 30 ml). Saturated and

aromatic fractions were used for bulk d13C analyses and a portion

of the saturated HC fraction was subjected to 5A molecular sieving.

Straight chain HCs were separated from branched and cyclic HCs

by treating the saturated fractions with 5A molecular sieve

(Murphy, 1969) using the procedure described elsewhere (Grice

et al., 2008; Maslen et al., 2009).

2.3. GCMS

GCMS was performed using similar conditions as in Asif et al.

(2009). Briefly, we used a HewlettPackard (HP) 5973 Mass Selec-

tive Detector (MSD) interfaced to a HP6890 gas chromatograph

equipped with a column (60 m, 0.25 mm ID) with a 0.25 lm 5%phenyl 95% methyl polysiloxane stationary phase (DB-5MS, J&W

scientific). The injector was operated at 280 C and the He carrier

gas was maintained at a constant flow of 1.1 ml/min. The GC oven

was programmed from 40310 C at 3 C/min with initial and final

hold times of 1 and 30 min, respectively. The transfer line between

the gas chromatograph and the MSD was held at 310 C. The MS

source and quadrupole temperatures were 230 C and 106 C,

respectively. The saturated and aromatic HCs were identified using

relative retention times, mass spectral data and comparison with

literature data (Trolio et al., 1999; Grice et al., 2001, 2005; Grimalt

et al., 2002; Peters et al., 2005 and references therein).

2.4. Elemental analysis-isotope ratio mass spectrometry (bulk isotope

analysis)

Bulk stable isotope compositions of both the saturated and aro-

matic HC fractions of Potwar Basin oils were analysed. Bulk stableisotope analyses were performed on a Micromass IsoPrime isotope

ratio mass spectrometer interfaced to a EuroVector EuroEA3000

elemental analyser. For bulk d13C analyses, each sample was

weighed accurately (0.050.15 mg) into a small tin capsule which

was then folded and compressed carefully to remove any tracers of

atmospheric gases. The tin capsule containing the sample was

dropped into a combustion reactor at 1025 C with the aid of an

autosampler. The sample and capsule melted in an atmosphere

temporarily enriched with oxygen, where the tin promoted flashcombustion. The combustion products, in a constant flow of he-

lium, passed through an oxidation catalyst (chromium oxide).

The oxidation products then passed through a reduction reactor

at 650 C containing copper granules, where any oxides of nitrogen

(NO, N2O and N2O2) are reduced to N2 and SO2 were separated on a

3 m chromatographic column (Poropak Q) at ambient temperature.

After removing the oxides of nitrogen, oxidation products are then

passed through a thermal conductivity detector (TCD) and into the

irMS. Average values of at least two analyses and standard devia-

tions are reported. Isotopic compositions are given in delta nota-

tion relative to Vienna Peedee belemnite (VPDB).

For bulk dD analysis, the sample was weighed accurately (0.05

0.15 mg) into a small silver capsule which was then folded and

dropped into a pyrolysis reactor containing glassy carbon chipsheld at 1260 C. The sample was pyrolysed to form H2 and CO,

along with N2 if applicable. The pyrolysis products were separated

on a 1 m 5A molecular sieve, packed chromatographic column held

in an oven at 80 C (isothermal), before passing through a TCD,

then into the irMS. dD values were calculated and reported in delta

notation relative to Vienna Standard Mean Ocean Water (VSMOW).

3. Results and discussion

3.1. Normal alkanes and regular isoprenoid distributions

The crude oils analysed in this study are listed in Table 1. The

total ion chromatogram (TIC) of a representative sample is shown

in Fig. 3. n-Alkanes range from C1037 along with isoprenoids fromC1420 (except i-C17) are observed while n-alkanes less than C10 are

absent, probably because of evaporative loss during sample pro-

cessing. The peak areas from the TIC are used to calculate n-alkane

and isoprenoid parameters listed in Table 1. All the samples show

Pr/Ph ratios from 1.02.0, representing marine oxic/dysoxic depo-

sitional environment of OM, with the exception of the P1 oil which

shows a value >3.2, suggesting more oxic depositional conditions.

Carbon preference index (CPI) and odd/even predominance

(OEP) are good indicators for OM type in immature samples where

higher abundance of C1618 n-alkanes indicate an aquatic source

while a C2733 odd abundance of n-alkanes reflects terrigenous

OM (Hunt, 1995). Maturation of OM significantly alters n-alkane

abundance, and CPI and OEP tend towards 1 in typical mature

crude oils. The CPI and OEP values for most of the Potwar Basin oilsare close to 1 (Table 1) indicating mid-oil window thermal maturi-

ties of the source at time of expulsion.

3.2. Stable carbon and hydrogen isotopic compositions

The stable isotopic composition of crude oil is mainly depen-

dent on the d13C and dD value of the kerogen which, in turn, de-

pends on the biological OM and the depositional environment

(Schoell, 1984; Chung et al., 1992; Collister and Wavrek, 1996). A

series of oils ranging from low API condensate (API, 48) to high

API oils (API, 16) from the Potwar Basin were examined for bulk

d13C and dD. These results are reported in Table 1. d13C and dD of

saturated and aromatic HC fractions were analysed to delineate

different groups of petroleum in the Potwar Basin. The crude oilsfrom eastern Potwar are characterised by less negative values of

d13C (isotopically heavy) and cluster together based on d13C of sat-

urated and aromatic HC fractions (Fig. 4a; group B). More negative



7/16


(isotopically lighter) d13C values (25 to 26.1) are observed

for P15P18 crude oil samples (Fig. 4a; group C). Among the sam-

ple suite of oils analysed, P1 oil is the lightest (most negative) ind13C of saturated and aromatic HC fractions and is classified as

group A (Fig. 4a). The group designation assigned to each crude

oil from the Potwar Basin is shown in Table 1. Group A comprises

a single oil, group B contains 13 crude oils and group C contains

four crude oils. The stable isotopic composition of group A oil is

most probably controlled by both source and depositional settings

as indicated by n-alkanes and isoprenoid distributions and bio-

marker parameters (see below). Group B oils show enrichment in13C for the saturated HC fraction having values up to 34 heavier

compared to the saturated HC fraction d13C values of group C

(Fig. 4a; Table 1). The differences observed between d13C of satu-

rated HC fractions of groups B and C indicate a difference in source

organisms for the saturated HCs. Another plot represents the dif-ferences between d13C and dD average values of both saturated

and aromatic HC fractions of crude oils (Table 1) and is shown in

Fig. 4b. This plot separates the crude oils into three similar groups

providing additional evidence for the existence of at least three oil

groups in the Potwar Basin. The difference in d13C and dD of the

Potwar Basin oils most likely suggests source variations.

The biomarker parameters listed in Tables 13 are used to ob-

tain information regarding source OM, thermal maturity of crude

oils, depositional environment and lithology of OM and the extent

of biodegradation in the Potwar Basin crude oils. The following sec-

tions explain these geochemical characteristics one by one, again

differentiating the Potwar Basin crude oils into three groups.

3.3. Thermal maturity of Potwar Basin crude oils

A combination of saturated and aromatic HC biomarkers was

used to determine the thermal maturity of the Potwar Basin oils.

The data in Table 2 were obtained from GCMS analysis of the

branched/cyclic fractions. The hopane based parameters were cal-

culated from peak areas of 191 Dalton mass chromatograms. The

C32 homologue ratio 22S/(22S+ 22R) varies between 0.57 and

0.64, indicating equilibrium values for this ratio, suggesting that

the maturity is at least equal to early oil generation window for

all the oil samples of the Potwar Basin (Table 2). However this ratio

reaches equilibrium in the oil window so has limited application

for studying the relative maturities of crude oils and condensates

(Peters et al., 2005). Another hopane based maturity parameter is

the ratio of 17a(H),21b(H)-hopane relative to corresponding17b(H),21a(H)-moretanes [ab/(ab + ba)] for C29- and C30-com-pounds, which equilibrate at somewhat higher thermal maturities

(Seifert and Moldowan, 1980; Peters et al., 2005). The values for

20 40 60 80 100 120

d

c

b e

a

Pr

C25

Ph

C17

Retention Times

Re

lativea

bun

dance

Fig. 3. Representative total ion chromatogram of saturated hydrocarbon fractions of the crude oils, showing distribution of n-alkanes (n-C1037) and isoprenoids (a: 2,6-

dimethylundecane; b: 2,6,10-trimethylundecane (nor-farnesane); c: 2,6, 10-trimethyldodecane (farnesane); d: 2,6,10-trimethyltridecane; e: 2,6,10,-trimethylpentadecane

(nor-pristane); Pr: pristane and Ph: phytane).

-25.0

-24.0

-23.0

-22.0

-21.0

-20.0

-27.0 -26.0 -25.0 -24.0 -23.0 -22.0

13CSats ()

13CAros

()

A

B

C

(a)

-150

-140

-130

-120

-110

-100

-26.0 -25.0 -24.0 -23.0 -22.0 -21.0

13Caver()

D

aver

()

B

A

C

(b)

Fig. 4. Plots to delineate the three oil groups from the Potwar Basin (a) d13Csatsversus d13Caros and (b) d

13Caver versus dDaver from average values of d13C and dD of

saturated and aromatic hydrocarbon fractions.



8/16


Table 2

Saturated and aromatic hydrocarbon biomarker thermal maturity parameters.

Sample name Ts/(Ts + Tm)a ab/(ab + ba),C29-Hop

b

ab/(ab + ba),C30-Hop

c

S/(S+ R)

C32-Hopd

bb/(aa + bb)C29-Ster

e

S/(S+ R)

C29-sterf

DNR-1g TNR-1h TNR-2i Rcbj (%) MPI-1k Rc

l (%)

P1 0.53 0.83 0.81 0.62 0.59 0.41 6.8 1.04 0.94 1.02 0.75 0.85

P2 0.40 0.93 0.86 0.61 0.66 0.43 7.6 1.43 1.04 1.02 1.07 1.04P3 0.36 0.92 0.86 0.62 0.65 0.41 7.2 1.38 1.02 0.99 1.02 1.01

P4 0.36 0.94 0.87 0.60 0.64 0.44 6.3 1.61 1.03 1.03 0.80 0.88

P5 0.37 0.93 0.88 0.58 0.63 0.45 5.7 1.44 0.98 1.00 0.90 0.94

P6 0.38 0.93 0.90 0.56 0.61 0.45 6.2 1.64 1.05 0.96 0.85 0.91

P7 0.41 0.94 0.87 0.57 0.63 0.45 7.8 1.50 1.00 1.08 0.92 0.95

P8 0.40 0.93 0.88 0.59 0.61 0.47 8.1 1.85 1.12 1.15 1.04 1.03

P9 0.45 0.92 0.88 0.61 0.64 0.47 8.0 1.61 1.12 1.11 0.89 0.93

P10 0.35 0.96 0.89 0.57 0.59 0.48 8.4 1.96 1.14 0.97 0.91 0.94

P11 0.31 0.94 0.90 0.59 0.59 0.46 5.7 2.31 1.24 1.07 0.85 0.91

P12 0.38 0.93 0.85 0.60 0.62 0.45 6.9 2.17 1.18 1.07 0.90 0.94

P13 0.45 0.97 0.92 0.60 0.63 0.45 5.5 1.39 0.95 0.95 1.26 1.16

P14 0.73 1.00 1.00 0.64 0.63 0.47 6.8 1.25 0.95 0.97 1.14 1.08

P15 0.67 1.00 1.00 0.63 0.61 0.45 7.7 1.29 0.91 1.01 1.16 1.10

P16 0.66 1.00 1.00 0.63 0.61 0.43 7.1 1.23 0.96 0.98 1.14 1.08

P17 0.70 1.00 0.92 0.61 0.63 0.44 7.4 1.39 1.00 1.00 1.07 1.04

P18 0.70 0.90 0.92 0.61 0.62 0.47 8.5 1.23 0.94 0.96 1.09 1.05

: not determined.a Ts/(Ts + Tm), 18a(H)-22,29,30-trisnorneohopane/(18a(H)-22,29,30-trisnorneohopane + 17a(H)-22,29,30-trisnorhopane).b ab/(ab + ba) C29 Hop: 17a(H),21b(H)-30-norhopane/(17a(H),21b(H)-30-norhopane + 17b(H),21a(H)-30-norhopane).c ab/(ab + ba), C30 Hop: 17a(H),21b(H)-hopane/(17a(H),21b(H)-hopane + 17b(H),21a(H)-hopane).d S/(S + R), C32 Hop, 22S/(22S + 22R), 17a(H)-bishomohopane.e (bb/aa + bb) C29-Ster: 14b(H),21b(H)/[14a(H),21a(H) + 14b(H),21b(H)] 20R-ethylcholestane.f S/(S+ R) C29 ster: 20S/(20S + 20R) 14a(H),21a(H)-ethylcholestane.

g DNR-1: dimethylnaphthalene ratio 1 (2,6- + 2,7-DMN/1,5-DMN), Radke, 1987.h TNR-1: trimethylnaphthalene ratio 1 (2,3,6-TMN/1,4,6- + 1,3,5-TMN), Alexander et al., 1985.i TNR-2: trimethylnaphthalene ratio 2 (2,3,6- + 1,3,7-TMN)/1,4,6- + 1,3,5- + 1,3,6-TMN).

j Rcb: 0.40 + 0.6 (TNR-2) Radke et al., 1986.k MPI-1: methylphenanthrenes index {1.5 [3-MP + 2-MP]/[P + 1-MP + 9-MP]}, Radke et al., 1982.l Rc: calculated vitrinite reflectance (0.6 MPI-1 + 0.4), Radke and Welte, 1983.

Table 3

Source OM parameters for Potwar Basin oils.

Sample

name

C19/

(C19 + C23)

TTa

C24TeT/

(C24TeT + C23TT)b

C23TT/C30Hopc

C24-

TeT/

C30Hopd

C28TT/

C30-

Hope

C29/

C30 abhopf

Dia/

hop

C30g

C30Dia/

C29Tsh

C31(R+ S)/

C30 hopi

Steranes/

hopanesjDia/

ster

C27k

Dia/

Ster

C29l

Total

Dia/

Sterm

C27abb

C28abb

C29abb

P1 0.88 0.77 0.07 0.24 0.00 0.65 0.38 2.23 0.77 0.29 0.53 0.97 1.15 43 18 39

P2 0.49 0.47 0.40 0.35 0.00 0.58 0.26 1.44 0.75 0.23 0.76 0.60 0.91 37 13 50

P3 0.46 0.49 0.31 0.30 0.00 0.55 0.22 1.78 0.75 0.24 0.53 0.63 0.80 39 21 40

P4 0.40 0.56 0.32 0.42 0.11 0.74 0.15 0.83 0.94 0.23 0.55 0.57 0.76 40 17 43

P5 0.40 0.55 0.37 0.45 0.12 0.78 0.15 0.75 0.97 0.28 0.50 0.51 0.73 41 16 43

P6 0.39 0.54 0.37 0.44 0.10 0.76 0.17 0.86 0.89 0.27 0.59 0.54 0.76 40 17 43

P7 0.38 0.52 0.46 0.49 0.17 0.75 0.22 1.13 0.90 0.34 0.50 0.60 0.76 40 20 40

P8 0.41 0.57 0.33 0.44 0.10 0.65 0.15 0.80 0.82 0.27 0.50 0.49 0.77 48 8 45

P9 0.45 0.52 0.28 0.30 0.09 0.69 0.18 0.64 0.86 0.35 0.61 0.68 0.82 38 22 40

P10 0.33 0.61 0.24 0.38 0.08 0.79 0.11 0.72 0.88 0.23 0.44 0.40 0.65 42 12 46

P11 0.30 0.63 0.23 0.39 0.07 0.87 0.07 0.56 0.96 0.20 0.45 0.38 0.63 42 12 47

P12 0.38 0.55 0.43 0.52 0.13 0.75 0.20 1.24 0.98 0.33 0.55 0.59 0.83 39 19 42P13 0.44 0.55 0.38 0.47 0.11 0.75 0.19 0.83 0.83 0.35 0.55 0.58 0.74 41 19 40

P14 0.49 0.51 1.93 2.03 0.64 0.64 0.86 1.34 0.89 1.24 0.65 0.78 0.97 45 18 37

P15 0.34 0.44 1.54 1.22 0.71 0.61 0.32 1.44 0.44 1.50 0.38 0.06 0.31 24 34 41

P16 0.33 0.45 1.16 0.93 0.55 0.51 0.29 1.59 0.44 1.45 0.40 0.19 0.40 22 34 44

P17 0.36 0.40 0.86 0.58 0.41 0.48 0.26 1.29 0.47 0.74 0.43 0.26 0.35 31 32 37

P18 0.32 0.44 0.50 0.40 0.27 0.57 0.23 0.91 0.50 0.58 0.38 0.27 0.34 30 31 39

a C19/(C19 + C23) TT, C19-tricyclic terpane/(C19-tericyclic terpane + C23 tricyclic terpane).b C24TeT/(C24TeT + C 23TT), C24-tetracyclic terpane/(C24-tetracyclic terpane + C23 tricyclic terpane).c C23 TT/C30-hop: C23 tricyclic terpane/C30-ab hopane.d C24 TeT/C30-hop: C24 tetracyclic terpane/C30-ab hopane.e C28TT/C30-Hop, C28 tricyclic terpane/C30 ab hopane.f C29/C30 ab hop, C29 30-norhopane/C30 ab-hopane.

g Dia/Hop C30, C30 ba diahopane/C30 ab-hopane.h C30 Dia/C29 Ts: C30, ba diahopane/18a(H)-30-norneohopane.i C31 (R+ S)/C30 hop, C31 ab-homohopane (22S + 22R)/C30 ab-hopane.

j Steranes/hopanes: total steranes/total hopanes.

k Dia/ster C27: ba/(aa + bb) cholestane.l Dia/ster C29: ba/(aa + bb) ethylcholestane.

m Total dia/ster, total ba steranes/(ab + aa) steranes; C27, C28, C29 abb steranes.



9/16


both C29- and C30-moretanes, [ab/(ab + ba)] ratios are in the rangeof 0.81 to 1.0 (mostly >0.9, Table 2) typical for oils generated from

mature source rocks (cf. George et al., 2004). The plot of hopane

based maturity parameters between C29- and C30-ab/(ab + ba) isshown in Fig. 5a (cf. George et al., 2001), where most of the oil sam-

ples fall close to equilibrium and higher than equilibrium level

indicating higher thermal maturity except P1, which shows rela-

tively low thermal maturity. The slight difference in ab/(ab + ba)ratios for the Potwar Basin oils shows the affects of source and

depositional environment variations on these values (Rullktter

and Marzi, 1988; Isaksen and Bohacs, 1995). The Ts/(Ts + Tm) ratio

continuously varies from the immature to postmature (Peters

et al., 2005). The values for Ts/(Ts + Tm) ratio range from 0.31

0.73 for the oils indicating an immature to mature range of thermal

maturity, however a narrow range of this ratio is observed for indi-

vidual groups. For example, group B show a Ts/(Ts + Tm) ratio in

the range of 0.310.45 while group C shows values in the range

of 0.670.70. The single Group A oil (P1) has an intermediate value

(0.53, Table 2). One oil sample (P14, Table 2) from group B shows a

higher value for Ts/(Ts + Tm), 0.73, indicating significant effects of

source and depositional environments (Moldowan et al., 1986).

Different Ts/(Ts + Tm) values for each group of oils indicate that

this ratio is controlled by factors other than thermal maturity, most

probably source and depositional environments (Moldowan et al.,

1986) that are shown to affect the source OM of Potwar Basin oils

(see below).The sterane based thermal maturity parameters such as 20S/

(20S+ 20R) ethylcholestane and bb/(aa + bb) ethylcholestanerange tightly at 0.410.48 and 0.590.66 respectively, supporting

a similar thermal maturity for these samples while the equilibrium

occurs between 0.520.55 and 0.670.7,1 respectively (Seifert and

Moldowan, 1986). These values suggest that none of the oils have

reached full maturity with respect to equilibrium values suggested

by Seifert and Moldowan (1986). However these lower than equi-

librium values for both sterane parameters are consistent with the

peak oil generation window for the Potwar Basin oils (Peters et al.,

2005). Despite the fact that 20S/(20S+ 20R) ratio is very useful to

indicate thermal maturity, factors other than thermal maturity

can affect this ratio. For example, reversal of this ratio within

highly mature intervals could be responsible for the lower values

(cf. Bishop and Abbott, 1993; Edwards et al., 1997).

It has been shown that many biomarker maturity parameters

reach equilibrium at the onset of the oil window and therefore

may not be useful for highly mature oils and condensates (van

Graas, 1990). In this scenario, parameters based on aromatic HCs

may be more effective for evaluation of thermal maturity. The

methyl phenanthrene index (MPI-1; Radke et al., 1982) appears

to be useful to estimate vitrinite reflectance (Radke et al., 1982;

Radke, 1988). The MPI-1 and calculated vitrinite reflectance (Rc)values from Potwar Basin oils are reported in Table 2. The MPI-1

is in the range of 0.751.26 and Rc in the range of 0.851.15%.

The Rc for P1 (0.85%, Table 2) suggests a maturity equivalent to

0.75

0.80

0.85

0.90

0.95

1.00

0.75 0.80 0.85 0.90 0.95 1.00

/(+), C29

-Hop

/(

+

),C30

-Hop

Early oil generation

Equilibrium

(a)

0.6

0.7

0.8

0.9

1.0

1.1

1.2

0.6 0.7 0.8 0.9 1.0 1.1 1.2

Rcb(%)

Rc

(%)

Late

Peak

Early

(b)

Fig. 5. (a) Hopane maturity parameter plot between C29 versus C30 ofab/(ab + ba)(cf. George et al., 2001) (b) calculated vitrinite reflectance diagram from Rcb (TNR-2;

Radke et al., 1986) and Rc (MPI-1; Radke and Welte, 1983) showing different

thermal maturation stages of oil generation window.

0.5

1

1.5

2

2.5

3

3.5

10 20 30 40 50

API gravity ()

Pr/

Ph

B

A

C

(b)

0

1

2

3

4

0.0 1.0 2.0 3.0 4.0

Pr/Ph

D

BT/P

1A: marine Carbonate

1B: marine carbonate and marl

2: Lacustrine hypersaline

3: marine shale and lacustrine

4:fluvio-deltaic shale

Hughes et al, 1995

1A

1B

2 3 B & C 4A

(a)

0.0

0.2

0.4

0.6

0.8

1.0

0.0 0.2 0.4 0.6 0.8 1.0

Diahopane/hopane, C30

Dias

terane

/steranes,

C29(c) A

B

C

P14

Fig. 6. (a) Pr/Ph versus DBT/P indicating lithology and depositional environment

(Hughes et al., 1995) (b) a cross plot of API gravity and Pr/Ph separating the Potwar

Basin oils into three groups, (c)C30 diahopane/hopaneversus C29 diasterane/sterane

ratios.



10/16


peak oil generation while all other Potwar Basin oils indicate a

maturity of late oil generation window (>0.9) (cf. Radke, 1987).

Methylnaphthalene thermal maturity parameters are also listed

in Table 2. The dimethylnaphthalene ratio (DNR-1, Table 2) >5.5

(Table 2, mostly $78) clearly indicates that the thermal maturity

of the Potwar Basin oils has reached the late oil generation win-

dow. The trimethylnaphthalene ratio 1 (TNR-1, Table 2) has been

calibrated with the sterane isomerisation ratio (20S/20R), showing

that the sterane isomerisation ratio of oils reaches equilibrium

when TNR-1 ratio is >1 (Alexander et al., 1985). TNR-1 values for

Potwar Basin oils are >1 (mostly >1.2) for all samples, indicating

that the maturity of source rocks generating these oils reached to

higher than the peak oil generation window (cf. Alexander et al.,

1985). Similarly, the trimethylnaphthalene ratio 2 (TNR-2, Table

2) is another useful aromatic HC thermal maturity parameter

which has been calibrated with mean vitrinite reflectance (Ro)

and shows good agreement with increase in thermal maturity

(Radke et al., 1986). The TNR-2 value (0.91.2, Table 2) and calcu-

lated vitrinite reflectance Rcb values (>0.95, Table 2) from TNR-2

indicate thermal maturity of the oil samples from the Potwar Basin

reached the late oil generation window (Radke et al., 1986). A cross

plot (Fig. 5b) of calculated vitrinite reflectance values i.e. Rcb (TNR-2) versus Rc (MPI-1) clearly indicates that the thermal maturity of

Potwar Basin oils reaches to the late oil generation window. It has

been shown that the biomarker maturity parameters reveal early

to peak oil generation window for Potwar Basin oils, however these

parameters mostly reached equilibrium values so showed limited

application for maturity assessment. Finally, it is concluded that

equivalent vitrinite reflectance calculated from aromatic HC matu-

rity parameters reveal source rocks of Potwar Basin oils reached

maturities of late oil generation window.

A few anomalies are observed in the alkylnaphthalene maturity

parameters. For example, TNR-1 shows a wide range of values from

1.042.31 although most of the values lie between 1 and 2. High

values (TNR-1 >2.0, Table 2) for some of the oils are probably

due to secondary effects such as biodegradation. Affects of biodeg-

radation on alkylnaphthalenes have been shown to affect different

isomers and thus different susceptibilities towards biodegradation

(Asif et al., 2009) and thermal maturity parameters are altered

when using certain isomers in thermal maturity ratio calculations

(van Aarssen et al., 1999; Obermajer et al., 2004).

3.4. Lithology and depositional environments

The crude oils listed in Table 1 were examined for lithology and

depositional environment using aliphatic and aromatic biomarker

parameters. The Pr/Ph ratio shows a range of values from 12 (ex-cept sample P1, Pr/Ph = 3.2) for the Potwar Basin oils (Table 1).

DBT/P ratio is a good indicator of lithology and the values for the

ratio are


11/16


Potwar Basin oils (Hughes et al., 1995). The Pr/Ph and DBT/P data

from Potwar Basin oils are plotted based on the Hughes diagram

(Hughes et al., 1995) and these results are shown in Fig. 6a. The

largest set of oils from the Potwar Basin (group B and C) are shown

to originate from marine shale and lacustrine source rocks (Fig. 6a)

while the single group A oil (P1) indicates a highly oxic fluvio-del-

taic depositional environment. However no molecular evidence is

observed for a lacustrine depositional environment of source rocks

for Potwar Basin oils. These results indicate that most of the oils in

the Potwar Basin were generated from marine shale source rocks

and the single oil of group A was generated from fluvio-deltaic

source rocks.

Depositional environments based on Pr/Ph ratio and HC compo-

sitional variations based on API gravity are used to differentiate the

Potwar Basin oils. A cross plot of API gravity and Pr/Ph is shown in

Fig. 6b. The single oil positioned in the right top corner of the plot

indicates higher Pr/Ph and API values consistent with an oxic depo-

sitional environment and light oil typically generated from

terrigenous OM. An interesting feature of the plot (Fig. 6b) is theseparation of the group B and C oils that were shown to be similar

in the Hughes diagram (Fig. 6a). The group B oils show lower Pr/Ph

(mostly


12/16


(Peters et al., 2005) and this ratio for group A is very high (2.23, Ta-

ble 3) indicating an highly oxic depositional environment.

Although data for both groups B and C oils imply marine source

rocks based on lithology and environments of deposition (see

above), relative abundance of hopanes differentiates the groups

(Fig. 6c): group B is more reduced than group C. The C30 diaho-pane/C29Ts ratio (61.0 for most of oils) and C31 (R + S) hopane/

C30 hopane ratio (>0.75) for group B oils indicate more dysoxic

depositional settings for OM than for group C oils (cf. Peters and

Moldowan, 1993). An anomalously high value relative to the group

B oils is observed for the P14 sample in the C 30 diahopane/hopane

versus C29 diasteranes/sterane diagram (Fig. 6c). The reason for this

anomaly could be related to the depositional environment (high

Pr/Ph ratio for this sample) and source organic facies (Moldowan

et al., 1991; Peters et al., 2005 and references therein).

3.5. Source of OM

The sources of OM were determined from the distributions of

tricyclic, tetracyclic and pentacyclic terpanes and steranes. Fig. 7

shows m/z 191 chromatograms of the representative oil samples

from all delineated groups from the Potwar Basin. The source bio-

marker parameters are listed in Table 3. The group A oil shows a

significantly lower relative abundance of tricyclic and tetracyclic

terpanes except for C19 tricyclic terpane and C24 tetracyclic terpane

(Fig. 7), both indicators of terrigenous OM (Philp and Gilbert, 1986;

Grice et al., 2001; Peters et al., 2005; Volk et al., 2005; Nabbefeld

et al., 2010a). The oil correlation diagram of C19/(C19 + C23) tricyclic

versus C24 tetracyclic/(C24 tetracyclic + C23 tricyclic terpane) is

shown in Fig. 8a where group A indicates clearly a different source

of OM compared to the other groups (cf. Edwards et al., 1997; Volk

et al., 2005). The presence of the aromatic plant biomarker retene

also tends to support a terrigenous source of OM for the group A

oil, although this biomarker can also be ascribed to algae (Nabbe-feld et al., 2010b and references therein). The lowvalues for the C23tricyclic/C30 hopane (


13/16


compared to regular steranes consistent with a clastic source rock

common in deltaic/oxic depositional settings (Peters et al., 2005).

The regular steranes show almost equal abundance to the diaster-

anes in group B oils while in group C oils the former is significantly

less abundant than the latter. These distribution differences are

indicating that the group B oils were generated from more clasticsource rocks than the group C oils, consistent with above results

(Section 3.4). The C29 and C28 regular steranes are present in signif-

icantly higher abundance than other steranes and diasteranes in

the group C oils (Fig. 9) indicating the significant contribution of

terrigenous and algal OM, respectively. These interpretations of

terrigenous and algal contribution to group C oils are consistent

with presence of higher concentrations of tricyclic terpanes than

hopanes (see below) (cf. Philp et al., 1989) and high API values

for these oils (Peters et al., 2005). The regular sterane correlation

diagram between C27/C29 aaa versus C28/C29 abb steranes isshown in Fig. 8b which differentiates the Potwar Basin oils into

the same three groups where group C shows higher C28 regular

steranes representing a higher algal input. The distribution of rear-

ranged steranes also differentiate B from C oils ( Table 3). Group Bshows higher C27 and C29 ba/(bb + aa) ratios (>0.45 and >0.4,respectively) indicating comparatively more marine clastic source

input than group C oils.

The representative 191 ion chromatogram for group C oils

shows significantly higher abundance of tricyclic terpanes than ho-

panes (Fig. 7c). The C23 tricyclic terpane is the most abundant m/z

191 compound in the group C oils and the presence of extended tri-

cyclic terpanes up to C41 and possibly higher is an important fea-

ture of these oils, which can be used to differentiate group C

from groups A and B. Various organisms have been suggested as

the source of tricyclic terpanes in oils and bitumens (Ourisson

et al., 1982; Volkman et al., 1989; Peters and Moldowan, 1993;

Simoneit et al., 1993) and the ubiquitous occurrence of tricyclic

terpanes in sedimentary OM of varying ages has been related to

numerous source origins (Farrimond et al., 1999). The occurrence

of tricyclic terpanes in the Potwar Basin C oils is probably related

to an algal source which is supported by comparative abundance

of regular C28 steranes in group C oils (Table 3; Fig. 8b). Higher

abundance of tricyclic terpanes than hopanes has also been relatedto terrigenous input (Philp et al., 1989) that is consistent with

higher abundance of C29 steranes in group C oils. Similarly, a higher

total sterane/hopane ratio >0.6 ($1.0 for most of the oils) may re-

flect a greater eukaryotic input (both algae and terrigenous) to

group C oils source rocks. The C23 tricyclic/C30 hopane and C24 tet-

racyclic/C30 hopane ratios (0.51.5 and 0.41.2, respectively, Table

3) indicate typically marine OM input for group B and C oils where

higher values for group C oils shows a higher marine input (algal

input) (cf. Peters et al., 2005). This differentiation in numerous

source OM parameters shows a different origin for source input

for each group and it is concluded that petroleum from Potwar Ba-

sin contained three source oil families.

The data set presented here indicates a few contradictions with

respect to the classification of crude oils from the Potwar Basin. Inthe above correlations (Fig. 6b and c), sample P14 (group B) posi-

tioned with group C oils. Similarly many source parameters for

the same sample such as C23 tricyclic/C30 hopane, C24 tetracyclic/

C30 hopane, C23 tricyclic/C28 tricyclic terpane and steranes/hopanes

place this oil close to the group C oils (Table 3). Moreover, the C27,

C28 and C29 abb steranes show a different distribution trends foreach group i.e. group A shows C27P C29 ) C28, group B shows

C29P C27 ) C28 and group C shows C29 > C28 > C27 (Table 3). The

relative distribution profile ofabb steranes (C27P C29 ) C28) fromgroup A reveals higher lacustrine source input while it has been

shown that this group has a terrigenous origin. The abb steranesprofile from group B oils shows higher C29 compounds, indicating

terrigenous input in contrast to results drawn from this study that

P1

P17

P14,P18

P15P16

P2

P3

P8

P13P7

P11,P12

P10

0

0.2

0.4

0.6

0.8

1

1.2

Pr/n-C17

Ph/n-C18

Biodegradation(a)

1.2

P1

P17

P9

P14,P18

P15,P16

P2

P3

P8

P13P4-5

P11-12

P6

0

10

20

30

40

50

60

0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Pr/n-C17

APIgravity()

Biodegradation

(b)

P6

Fig. 11. (a) Pr/n-C17 and Ph/n-C18 (b) API value versus Pr/n-C17 showing a decrease in the API gravity of crude oils with increasing biodegradation.



14/16


this group is marine. Reasons for these contradictory findings could

be solved by evaluating the source rocks of Potwar Basin oils, but

source to oil correlation along with migration affects, reservoir

connectivity and oil mixing in Potwar Basin are still to be

determined.

3.6. Extent of biodegradation

Biodegradation is a process that alters the molecular composi-

tion and bulk properties (API gravity) of petroleum and sediments

(Connan, 1984; Fisher et al., 1998). A number of commonly used

parameters have been used to assess the extent/level of biodegra-

dation in the Potwar Basin oils. Representative TICs of the satu-

rated fractions from each group of oils are shown in Fig. 10. The

distribution pattern of saturated HC fraction from group A and C

shows the presence of a full suite of n-alkanes and the absence

of any unresolved complex mixture (UCM), indicating no biodegra-

dation. While TIC from the a representative group B oil shows a

substantial UCM in the saturated fraction and a lack of n-alkanes

indicating that these oils have been biodegraded andthe remainingfraction has become enriched in high molecular weight unresolved

components. Similarly, isoprenoids show resistance to biodegrada-

tion compared to the n-alkanes because the n-alkanes are removed

faster than isoprenoids during biodegradation (Peters et al., 2005).

Hence isoprenoid/n-alkane ratios from saturated fractions increase

with an increase in biodegradation (Winters and Williams, 1968)

and Pr/n-C17 and Ph/n-C18 ratios > 1 typically indicates the effect

of biodegradation on crude oils. The plot of Pr/n-C17 versus Ph/n-

C18 (Fig. 11a) shows a trend consistent with biodegradation; these

ratios increase with increasing biodegradation. The API gravity is a

bulk property that directly relates to gross compositions of crude

oils. The Potwar Basin crude oils show a wide range of API gravities

(1648; Table 1). A plot of API gravity versus Pr/n-C17 (Fig. 11b)

shows an inverse relationship, a high Pr/n-C17 and lower API grav-

ity (Fig. 11b) indicative of the oils affected by biodegradation. The

results show that extent of biodegradation for some of the crude

oils in this study reaching up to a level of 3 on the Wenger et al.

(2001) scale. The extent of biodegradation of each crude oil from

the Potwar Basin is represented with level of biodegradation in Ta-

ble 1. It is observed that some of the oils from group B are affected

by minor biodegradation while group A and C are non-biodegraded

(Fig. 11a and b).

The representative group B chromatogram shows a high UCM

but also the presence of n-alkanes (Fig. 10). This type of saturated

HC profile indicates the possibility of mixing of biodegraded and

non-biodegraded crude oils in the reservoir. Assessment of biodeg-

radation and in-reservoir mixing in the Upper Indus oils (Potwar

Basin) has been reported using biomarker parameters (Asif et al.,

2009).

4. Conclusions

Geochemical characterisation and classification of the Potwar

Basin crude oils were performed using biomarker and stable iso-

tope distributions. Saturated HC biomarkers indicate at least early

to peak oil generation window of thermal maturity while aromatic

HC parameters and calculated vitrinite reflectance from these

parameters reveal late oil generation window thermal maturity

for Potwar Basin oils. Stable carbon and hydrogen isotopes of sat-

urated and aromatic HC fractions delineated three groups in the

Potwar Basin oils. These three groups of crude oils are differenti-

ated based on source OM, depositional environment and lithology.

Group A oil suggests terrigenous source OM generated from

fluvio-deltaic source rocks deposited in an oxic depositional

environment. Group A oil shows more negative (isotopically

lighter) d13C of both saturated and aromatic HC fractions com-

pared to all other oils. The abundance of C19 tricyclic and C24tetracyclic terpanes along with a higher abundance of a diag-

nostic aromatic HC biomarker, retene, suggests a terrigenous

source OM for group A oil. The other oils from the Potwar Basin analysed in this study are

marine in origin. However d13C and dD of bulk HC fractions and

based on tricyclic, tetracyclic and pentacyclic terpane and ster-

ane distributions separate these oils into groups B and C. Group

B oils show the heaviest d13C for both saturated and aromatic

HC fractions. Some of the group B crude oils are biodegraded

(level 23) and the OM of this group was deposited in a subox-

ic/dysoxic depositional environment.

Group C oils are typically non-biodegraded, mature crude oils

generated from source OM rich in algae with terrigenous input

deposited under marine oxic environments, which is supported

by the presence of extended tricyclic terpanes and regular ster-

anes. This group shows light d13C in the saturated HC fraction

relative to group B oils; however d

13

C of the aromatic fractionof group B and C are not very different from one another.

Acknowledgements

The authors thank Mr. G. Chidlow for assistance with GCMS

and S. Wang for bulk isotope analysis and maintenance. The Higher

Education Commission, Islamabad, Pakistan is thanked for an IRSIP

fellowship and a travel award Grant (IRSIP-5-Ps-20) to MA. KG

acknowledges the ARC for a QEII fellowship (DP0211875,

DP0877167). The authors thank the following exploration compa-

nies for providing oil samples: Oil and Gas Development Coopera-

tion Ltd. (OGDCL), Islamabad, Pakistan Petroleum Ltd. (PPL) and

Pakistan Oilfields Ltd. (POL). J. Curiale and H. Huang are acknowl-

edged for constructive reviews of the initial version of this paper.

Associate EditorMaowen Li

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