Organic Geochemistry 42 (2011) 1226–1240

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Organic Geochemistry

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Petroleum geochemistry of the Potwar Basin, Pakistan: 1. Oil–oil correlationusing biomarkers, d13C and dD

Muhammad Asif a,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 2011Received in revised form 21 April 2011Accepted 5 August 2011Available online 16 August 2011

0146-6380/$ - see front matter � 2011 Elsevier Ltd. Adoi:10.1016/j.orggeochem.2011.08.003

⇑ Corresponding author at: Department of BasicUniversity of Engineering and Technology, KSKTel.: +92 3218850163.

E-mail address: asifchaudhrry@gmail.com (M. Asif

a b s t r a c t

Geochemical characterisation of 18 crude oils from the Potwar Basin (Upper Indus), Pakistan is carriedout 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. Adetailed oil–oil correlation of the area is established. Gas chromatography–mass spectrometry (GC–MS) analyses and bulk stable carbon and hydrogen isotopic compositions of saturated and aromaticHC 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 underhighly 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 thedistributions 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 biomarkerratios show that group B oils are generated from clastic-rich source rocks deposited under more suboxicdepositional environments compared to group C oils. Group C oils show a relatively higher input of algalmixed with terrigenous OM, supported by the abundance of extended tricyclic terpanes (up to C41+) andsteranes.

Biomarker thermal maturity parameters mostly reached to their equilibrium values indicating that thesource 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. The extent of biodegradation of thePotwar Basin oils is determined using various saturated HC parameters and variations in bulk propertiessuch as API gravity. Groups A and C oils are not biodegraded and show mature HC profiles, while some ofthe oils from group B show minor levels of biodegradation consistent with high Pr/n-C17, Ph/n-C18 andlow API gravities.

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1. Introduction

The Potwar Basin is the main source of petroleum hydrocarbonsin northern Pakistan. A number of small and medium sized oil andgas fields have been discovered from both terrigenous and marinesource rocks in the basin. These oil fields are in Precambrian to Ter-tiary aged reservoir units. The Paleocene Patala Formation type IIand III kerogens have been assumed to be the primary source of

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Sciences and Humanities,Campus, Lahore, Pakistan.

).

hydrocarbons in the area, but other potential source rocks mayhave also contributed to different parts of the petroleum systemswithin the basin (Wandrey et al., 2004; Fazeelat et al., 2010). Theoldest potential source rocks are from the Precambrian Salt RangeFormation with a mixture of clastic, carbonate and evaporite dom-inant sections. Similarly, Permian Sardhai and Chhidru formationshave significantly higher total organic carbon (TOC) contents andare possible source rocks (Quadri and Quadri, 1997). In the past,a limited number of studies have been carried out mainly basedon Rock–Eval pyrolysis data (Ahmed and Alam, 1990; Fazeelatet al., 2010) and studies of the saturated hydrocarbon (HC) distri-butions (Fazeelat, 1994; Ahmed and Alam, 2007) from the area. Re-cently, a biodegraded oil seep and a crude oil from the Potwar

Table 1Geological information, n-alkanes, isoprenoid ratios and bulk isotope data.

Samplename

Depth(m)

Reservoir �APIgravity

Pr/Pha Pr/n-C17b Ph/n-C18

c CPId OEPe d13Csatsf

(‰)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 0P2 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 0P3 2063 Jutana Cambrian 33.0 2.0 1.0 0.5 1.0 1.0 – – – – – – 0.22 B 0P4 3640 Jutana Cambrian 19.3 1.2 1.3 0.9 1.0 1.0 – – – – – – 0.52 B 2P5 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 2P6 2773 Khewra Cambrian 26.6 1.3 1.4 0.9 1.0 1.0 – – – – – – 0.43 B 3P7 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 2P8 3063 Khewra/Tobra Cambrian 23.2 1.3 1.1 0.8 1.0 0.9 – – – – – – 0.39 B 1P9 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 1P10 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 3P11 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 3P12 2103 Chorgali/

SakaserEocene 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 0P18 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

–: not determined.a Pr/Ph, pristane/phytane.b Pr/n-C17, pristane/n-C17 alkanes.c Ph/n-C18, phytane/n-C18 alkanes.d CPI, carbon preference index.e OEP, odd even predominance.f d13C (‰) with respect to VPDB reported with in standard deviation of 0.2‰.g dD (‰) with respect of VSMOW with in standard deviation of 3.h d13Caver:age (d13Csats+ d13Caros)/2; dDaver: (dDsats + dDaros)/2.i DBT/P, dibenzothiophene/phenanthrene.j BL, biodegradation level (Wenger et al., 2001).

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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, havenever been reported, nor has a detailed oil–oil correlation everbeen 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; Maslenet 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 depositionalconditions (marine, lacustrine, hypersaline or fluvio-deltaic), (iii)lithology of potential petroleum source rocks (carbonate versusshale), (iv) relative thermal maturity of potential source rocksand (v) extent of biodegradation of petroleum HCs. However, manyof 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 andhydrogen) of crude oils, bitumens and kerogen is also useful. Thebulk isotope composition of saturated and aromatic fractions ofcrude oils has been applied to determine the source of OM (terrig-enous versus marine) for many oils worldwide (Sofer, 1984; Chunget al., 1992; Andrusevich et al., 1998). However, a recent study hasshowed limitations of bulk d13C data and reported a d13C values ofindividual aromatic HCs to determine the source OM of WesternAustralian crude oils (Maslen et al., 2011).

In the current study, organic geochemical parameters based onbiomarker distributions and stable carbon and hydrogen isotopesof 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 thePotwar Basin (Upper Indus Basin, Pakistan). Heavy to light crudeoils 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

Fig. 1. Map of the Potwar Basin indicating locations of oils used in this study (Wan

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 thelargest HC producing zone in northern Pakistan (Upper Indus Ba-sin). The source of these crude oils has not been fully correlatedwith any specific source rocks of the Upper Indus Basin. A fewstudies using organic geochemical properties from cuttings, out-crops and core samples of different geological formations wereundertaken and correlated partially with Potwar crude oils (Ahmedand 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 complexdue to the result of the Tertiary Himalayan collision between theEurasian and Indian plates (Farah et al., 1984). This intense tectonicactivity has significantly over thrust the Himalayan in the northand northwest and a series of faulted and unfaulted anticlinesdeveloped as the result of the multiple detachments of deep sur-faces from Cambrian. The Potwar Basin contains mostly carbonatereservoir rocks of Precambrian to Tertiary ages. The basin infillstarted with thick Precambrian evaporite deposits overlain by rel-atively thin Cambrian to Eocene age deposits followed by thickMiocene–Pliocene deposits. The Precambrian salt deposits pro-vided an easy detachment of Eocene-to-Cambrian (E–C) sequencesas a result of intense tectonic activity during Himalayan Orogenyduring the Pliocene to middle Pleistocene. This E–C sequence inthe Potwar Basin affected by compressional forces has generateda large number of folds and faults in the area (Aamir and Siddiqui,2006). These folds and faults have formed many small reservoirs

drey et al., 2004; modified from USGS Bulletin 2208B and references therein).

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).

M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240 1229

1230 M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240

and thus crude oils discovered in the Potwar Basin have shown tobe derived from a range of geological formations (Fig. 2).

The generalised stratigraphy of the Potwar Basin is shown inFig. 2. The oldest producing reservoir is a Precambrian Salt Rangeformation. 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 P6–P10 oils analysed in thepresent study. The overlying Jutana Formation consists primarily ofsandy carbonates and nearshore sandstones and reservoirs thathave led to the P3–P5 oils. The Permian Tobra Formation consistsof glacial tillites, siltstone and shales, and samples P8 and P9 arederived from the Tobra and the Khewra formations. The Jurassicstrata include the Datta and Shinawari formations, which are near-shore consisting of siliciclastics that contain some non-marinesandstone intervals (Khan et al., 1986). The Datta Formation hasled to the production of the P17 and P18 oils. Shallow marine car-bonate strata of the Eocene Chorgali and Sakaser formations forman important HC producing horizon in the Potwar Basin. Chorgaliand Sakaser formations consist of medium-bedded limestonesand fine crystalline dolomites. Both formations are oil and gas pro-ducing reservoirs and the P2 and P11–P16 oils are derived from theChorgali and Sakesar formations.

2.2. Sample preparation, liquid chromatography and 5A molecularsieving

The sample preparation and liquid chromatography proceduresused were similar to those described in Asif et al. (2009). Briefly,crude oils were separated using liquid chromatography on silicagel. Saturated HC fractions were eluted with n-hexane (30 ml), aro-matic fractions with a mixture of n-hexane:CH2Cl2 (7:3, 30 ml) andpolars with a mixture of CH2Cl2:CH3OH (1:1, 30 ml). Saturated andaromatic fractions were used for bulk d13C analyses and a portionof the saturated HC fraction was subjected to 5A molecular sieving.Straight chain HCs were separated from branched and cyclic HCsby treating the saturated fractions with 5A molecular sieve(Murphy, 1969) using the procedure described elsewhere (Griceet al., 2008; Maslen et al., 2009).

2.3. GC–MS

GC–MS was performed using similar conditions as in Asif et al.(2009). Briefly, we used a Hewlett–Packard (HP) 5973 Mass Selec-tive Detector (MSD) interfaced to a HP6890 gas chromatographequipped with a column (60 m, 0.25 mm ID) with a 0.25 lm 5%phenyl 95% methyl polysiloxane stationary phase (DB-5MS, J&Wscientific). The injector was operated at 280 �C and the He carriergas was maintained at a constant flow of 1.1 ml/min. The GC ovenwas programmed from 40–310 �C at 3 �C/min with initial and finalhold times of 1 and 30 min, respectively. The transfer line betweenthe gas chromatograph and the MSD was held at 310 �C. The MSsource and quadrupole temperatures were 230 �C and 106 �C,respectively. The saturated and aromatic HCs were identified usingrelative retention times, mass spectral data and comparison withliterature data (Trolio et al., 1999; Grice et al., 2001, 2005; Grimaltet al., 2002; Peters et al., 2005 and references therein).

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

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 isotoperatio mass spectrometer interfaced to a EuroVector EuroEA3000elemental analyser. For bulk d13C analyses, each sample was

weighed accurately (0.05–0.15 mg) into a small tin capsule whichwas then folded and compressed carefully to remove any tracers ofatmospheric gases. The tin capsule containing the sample wasdropped into a combustion reactor at 1025 �C with the aid of anautosampler. The sample and capsule melted in an atmospheretemporarily 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 reactorat 650 �C containing copper granules, where any oxides of nitrogen(NO, N2O and N2O2) are reduced to N2 and SO2 were separated on a3 m chromatographic column (Poropak Q) at ambient temperature.After removing the oxides of nitrogen, oxidation products are thenpassed through a thermal conductivity detector (TCD) and into theirMS. 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 anddropped 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 separatedon a 1 m 5A molecular sieve, packed chromatographic column heldin an oven at 80 �C (isothermal), before passing through a TCD,then into the irMS. dD values were calculated and reported in deltanotation 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. Thetotal ion chromatogram (TIC) of a representative sample is shownin Fig. 3. n-Alkanes range from C10–37 along with isoprenoids fromC14–20 (except i-C17) are observed while n-alkanes less than C10 areabsent, probably because of evaporative loss during sample pro-cessing. The peak areas from the TIC are used to calculate n-alkaneand isoprenoid parameters listed in Table 1. All the samples showPr/Ph ratios from 1.0–2.0, representing marine oxic/dysoxic depo-sitional environment of OM, with the exception of the P1 oil whichshows 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 wherehigher abundance of C16–18 n-alkanes indicate an aquatic sourcewhile a C27–33 odd abundance of n-alkanes reflects terrigenousOM (Hunt, 1995). Maturation of OM significantly alters n-alkaneabundance, and CPI and OEP tend towards 1 in typical maturecrude 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). Aseries of oils ranging from low API condensate (API, 48) to highAPI oils (API, 16) from the Potwar Basin were examined for bulkd13C and dD. These results are reported in Table 1. d13C and dD ofsaturated and aromatic HC fractions were analysed to delineatedifferent groups of petroleum in the Potwar Basin. The crude oilsfrom eastern Potwar are characterised by less negative values ofd13C (isotopically heavy) and cluster together based on d13C of sat-urated and aromatic HC fractions (Fig. 4a; group B). More negative

20 40 60 80 100 120

d

c

b e a

Pr

C25

Ph

C17

Retention Times

Rel

ativ

e ab

unda

nce

Fig. 3. Representative total ion chromatogram of saturated hydrocarbon fractions of the crude oils, showing distribution of n-alkanes (n-C10–37) 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

δ13CSats (‰)

δ13C A

ros (

‰)

A

B

C

(a)

-150

-140

-130

-120

-110

-100

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

δ13Caver (‰)

δDav

er (‰

)

B

A

C

(b)

Fig. 4. Plots to delineate the three oil groups from the Potwar Basin (a) d13Csats

versus d13Caros and (b) d13Caver versus dDaver from average values of d13C and dD ofsaturated and aromatic hydrocarbon fractions.

M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240 1231

(isotopically lighter) d13C values (�25‰ to �26.1‰) are observedfor P15–P18 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 asgroup A (Fig. 4a). The group designation assigned to each crudeoil from the Potwar Basin is shown in Table 1. Group A comprises

a single oil, group B contains 13 crude oils and group C containsfour crude oils. The stable isotopic composition of group A oil ismost probably controlled by both source and depositional settingsas 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 3–4‰ heaviercompared 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 sourceorganisms for the saturated HCs. Another plot represents the dif-ferences between d13C and dD average values of both saturatedand aromatic HC fractions of crude oils (Table 1) and is shown inFig. 4b. This plot separates the crude oils into three similar groupsproviding additional evidence for the existence of at least three oilgroups in the Potwar Basin. The difference in d13C and dD of thePotwar Basin oils most likely suggests source variations.

The biomarker parameters listed in Tables 1–3 are used to ob-tain information regarding source OM, thermal maturity of crudeoils, depositional environment and lithology of OM and the extentof biodegradation in the Potwar Basin crude oils. The following sec-tions explain these geochemical characteristics one by one, againdifferentiating 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 wasused to determine the thermal maturity of the Potwar Basin oils.The data in Table 2 were obtained from GC–MS analysis of thebranched/cyclic fractions. The hopane based parameters were cal-culated from peak areas of 191 Dalton mass chromatograms. TheC32 homologue ratio 22S/(22S + 22R) varies between 0.57 and0.64, indicating equilibrium values for this ratio, suggesting thatthe maturity is at least equal to early oil generation window forall the oil samples of the Potwar Basin (Table 2). However this ratioreaches equilibrium in the oil window so has limited applicationfor studying the relative maturities of crude oils and condensates(Peters et al., 2005). Another hopane based maturity parameter isthe 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

Table 2Saturated and aromatic hydrocarbon biomarker thermal maturity parameters.

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

ab/(ab + ba),C30-Hopc

S/(S + R)C32-Hopd

bb/(aa + bb)C29-Stere

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 0.85P2 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 1.01P4 0.36 0.94 0.87 0.60 0.64 0.44 6.3 1.61 1.03 1.03 0.80 0.88P5 0.37 0.93 0.88 0.58 0.63 0.45 5.7 1.44 0.98 1.00 0.90 0.94P6 0.38 0.93 0.90 0.56 0.61 0.45 6.2 1.64 1.05 0.96 0.85 0.91P7 0.41 0.94 0.87 0.57 0.63 0.45 7.8 1.50 1.00 1.08 0.92 0.95P8 0.40 0.93 0.88 0.59 0.61 0.47 8.1 1.85 1.12 1.15 1.04 1.03P9 0.45 0.92 0.88 0.61 0.64 0.47 8.0 1.61 1.12 1.11 0.89 0.93P10 0.35 0.96 0.89 0.57 0.59 0.48 8.4 1.96 1.14 0.97 0.91 0.94P11 0.31 0.94 0.90 0.59 0.59 0.46 5.7 2.31 1.24 1.07 0.85 0.91P12 0.38 0.93 0.85 0.60 0.62 0.45 6.9 2.17 1.18 1.07 0.90 0.94P13 0.45 0.97 0.92 0.60 0.63 0.45 5.5 1.39 0.95 0.95 1.26 1.16P14 0.73 1.00 1.00 0.64 0.63 0.47 6.8 1.25 0.95 0.97 1.14 1.08P15 0.67 1.00 1.00 0.63 0.61 0.45 7.7 1.29 0.91 1.01 1.16 1.10P16 0.66 1.00 1.00 0.63 0.61 0.43 7.1 1.23 0.96 0.98 1.14 1.08P17 0.70 1.00 0.92 0.61 0.63 0.44 7.4 1.39 1.00 1.00 1.07 1.04P18 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 3Source OM parameters for Potwar Basin oils.

Samplename

C19/(C19 + C23)TTa

C24TeT/(C24TeT + C23TT)b

C23

TT/C30

Hopc

C24-TeT/C30

Hopd

C28TT/C30-Hope

C29/C30 abhopf

Dia/hopC30

g

C30

Dia/C29

Tsh

C31(R + S)/C30 hopi

Steranes/hopanesj

Dia/sterC27

k

Dia/SterC29

l

TotalDia/Sterm

C27

abbC28

abbC29

abb

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 39P2 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 50P3 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 40P4 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 43P5 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 43P6 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 43P7 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 40P8 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 45P9 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 40P10 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 46P11 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 47P12 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 40P14 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 37P15 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 41P16 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 44P17 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 37P18 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 + C23TT), 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.

1232 M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240

0.75

0.80

0.85

0.90

0.95

1.00

0.75 0.80 0.85 0.90 0.95 1.00

αβ/(αβ+βα), C29-Hop

αβ/(α

β+βα

), C

30-H

op

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 of ab/(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 differentthermal 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/P

h

B

A

C

(b)

0

1

2

3

4

0.0 1.0 2.0 3.0 4.0

Pr/Ph

DB

T/P

1A: marine Carbonate1B: marine carbonate and marl2: Lacustrine hypersaline3: marine shale and lacustrine4:fluvio-deltaic shale Hughes et al, 1995

1A

1B

2 3 B & C 4 A

(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

Dia

ster

ane/

ster

anes

, C29(c) A

B

C

P14

ig. 6. (a) Pr/Ph versus DBT/P indicating lithology and depositional environmentughes et al., 1995) (b) a cross plot of API gravity and Pr/Ph separating the Potwar

asin oils into three groups, (c) C30 diahopane/hopane versus C29 diasterane/steraneatios.

M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240 1233

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 frommature source rocks (cf. George et al., 2004). The plot of hopanebased 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 levelindicating 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 anddepositional environment variations on these values (Rullkötterand Marzi, 1988; Isaksen and Bohacs, 1995). The Ts/(Ts + Tm) ratiocontinuously varies from the immature to postmature (Peterset 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 thermalmaturity, however a narrow range of this ratio is observed for indi-vidual groups. For example, group B show a Ts/(Ts + Tm) ratio inthe range of 0.31–0.45 while group C shows values in the rangeof 0.67–0.70. The single Group A oil (P1) has an intermediate value(0.53, Table 2). One oil sample (P14, Table 2) from group B shows ahigher value for Ts/(Ts + Tm), 0.73, indicating significant effects ofsource and depositional environments (Moldowan et al., 1986).Different Ts/(Ts + Tm) values for each group of oils indicate thatthis ratio is controlled by factors other than thermal maturity, mostprobably 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 0.41–0.48 and 0.59–0.66 respectively, supporting

F(HBr

a similar thermal maturity for these samples while the equilibriumoccurs between 0.52–0.55 and 0.67–0.7,1 respectively (Seifert andMoldowan, 1986). These values suggest that none of the oils havereached full maturity with respect to equilibrium values suggestedby Seifert and Moldowan (1986). However these lower than equi-librium values for both sterane parameters are consistent with thepeak oil generation window for the Potwar Basin oils (Peters et al.,2005). Despite the fact that 20S/(20S + 20R) ratio is very useful toindicate thermal maturity, factors other than thermal maturitycan affect this ratio. For example, reversal of this ratio withinhighly 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 parametersreach equilibrium at the onset of the oil window and thereforemay not be useful for highly mature oils and condensates (vanGraas, 1990). In this scenario, parameters based on aromatic HCsmay be more effective for evaluation of thermal maturity. Themethyl phenanthrene index (MPI-1; Radke et al., 1982) appearsto 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-1is in the range of 0.75–1.26 and Rc in the range of 0.85–1.15%.The Rc for P1 (0.85%, Table 2) suggests a maturity equivalent to

19 2021

23

24*

29H

30H

Ts

Tm

29Ts

31H

32H

33H34H 35H

(a) Group-A

(b) Group-B

(c) Group-C

R

S

RSRSRS

RS

61 71 9181 101

Relative retention time (min)

19

20

21

23

24*24

25 2829 30 31

32 3334

35 36 38 3940 41

19

24*

Sample: P10

Sample: P15

Sample: P1

29H

30H

30H

Rel

ativ

e in

tens

ity

Fig. 7. Mass chromatograms (m/z 191) showing distribution of tricyclic, tetracyclic and pentacyclic terpanes (hopanes, H) in typical Potwar Basin crude oils. Numbers onpeaks (19–41) indicate tricyclic terpanes; numbers with H (29H–35H) indicate hopanes; S and R indicate stereochemistry at carbon 22 of homohopanes (31H–35H);Ts: 18a(H)-22,29,30-trisnorneohopane; Tm: 17a(H)-22,29,30-trisnorhopane; C29Ts: 18a(H)-30-norneohopane; 24⁄: C24-tetracyclic terpane.

1234 M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240

peak oil generation while all other Potwar Basin oils indicate amaturity of late oil generation window (>0.9) (cf. Radke, 1987).Methylnaphthalene thermal maturity parameters are also listedin Table 2. The dimethylnaphthalene ratio (DNR-1, Table 2) >5.5(Table 2, mostly �7–8) clearly indicates that the thermal maturityof the Potwar Basin oils has reached the late oil generation win-dow. The trimethylnaphthalene ratio 1 (TNR-1, Table 2) has beencalibrated with the sterane isomerisation ratio (20S/20R), showingthat the sterane isomerisation ratio of oils reaches equilibriumwhen TNR-1 ratio is >1 (Alexander et al., 1985). TNR-1 values forPotwar Basin oils are >1 (mostly >1.2) for all samples, indicatingthat the maturity of source rocks generating these oils reached tohigher than the peak oil generation window (cf. Alexander et al.,1985). Similarly, the trimethylnaphthalene ratio 2 (TNR-2, Table2) is another useful aromatic HC thermal maturity parameterwhich 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 (0.9–1.2, Table 2) and calcu-lated vitrinite reflectance Rcb values (>0.95, Table 2) from TNR-2indicate thermal maturity of the oil samples from the Potwar Basinreached the late oil generation window (Radke et al., 1986). A crossplot (Fig. 5b) of calculated vitrinite reflectance values i.e. Rcb (TNR-2) versus Rc (MPI-1) clearly indicates that the thermal maturity ofPotwar Basin oils reaches to the late oil generation window. It hasbeen shown that the biomarker maturity parameters reveal early

to peak oil generation window for Potwar Basin oils, however theseparameters mostly reached equilibrium values so showed limitedapplication for maturity assessment. Finally, it is concluded thatequivalent vitrinite reflectance calculated from aromatic HC matu-rity parameters reveal source rocks of Potwar Basin oils reachedmaturities of late oil generation window.

A few anomalies are observed in the alkylnaphthalene maturityparameters. For example, TNR-1 shows a wide range of values from1.04–2.31 although most of the values lie between 1 and 2. Highvalues (TNR-1 >2.0, Table 2) for some of the oils are probablydue to secondary effects such as biodegradation. Affects of biodeg-radation on alkylnaphthalenes have been shown to affect differentisomers and thus different susceptibilities towards biodegradation(Asif et al., 2009) and thermal maturity parameters are alteredwhen 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 anddepositional environment using aliphatic and aromatic biomarkerparameters. The Pr/Ph ratio shows a range of values from 1–2 (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 theratio are <1 for all samples supporting a shale lithology for the

0.2

0.3

0.4

0.5

0.6

0.7

0.8

C19/(C19+C23) Tricyclic terpanes

C24

tetr

acyc

lic te

rpan

e/(C

24 te

trac

yclic

terp

ane+

C23

tr

icyc

lic te

rpan

e)

B

A

C

Terrigenous

0.0

0.2

0.4

0.6

0.8

1.0

0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7

C27/C29, 20R, ααα, steranes

C28

/C27

,20R

, αββ

, ste

rane

s

(b)

A

C

B

(a)

Fig. 8. (a) C19/(C19 + C23) tricyclic ratio versus C24 tetracyclic/(C24 tetracyclic + C23 tricyclic) terpane ratio, and (b) C27/C29 aaa versus C27/C28 abb diagrams; both differentiatethese oils into three groups.

M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240 1235

Potwar Basin oils (Hughes et al., 1995). The Pr/Ph and DBT/P datafrom Potwar Basin oils are plotted based on the Hughes diagram(Hughes et al., 1995) and these results are shown in Fig. 6a. Thelargest set of oils from the Potwar Basin (group B and C) are shownto 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 isobserved for a lacustrine depositional environment of source rocksfor Potwar Basin oils. These results indicate that most of the oils inthe Potwar Basin were generated from marine shale source rocksand the single oil of group A was generated from fluvio-deltaicsource rocks.

Depositional environments based on Pr/Ph ratio and HC compo-sitional variations based on API gravity are used to differentiate thePotwar Basin oils. A cross plot of API gravity and Pr/Ph is shown inFig. 6b. The single oil positioned in the right top corner of the plotindicates higher Pr/Ph and API values consistent with an oxic depo-sitional environment and light oil typically generated fromterrigenous OM. An interesting feature of the plot (Fig. 6b) is theseparation of the group B and C oils that were shown to be similarin the Hughes diagram (Fig. 6a). The group B oils show lower Pr/Ph(mostly <1.4) and low API values while group C oils show

intermediate Pr/Ph values (1.4–1.6) and high API values. The Pr/Ph ratio and API gravity relationship differentiates Potwar Basincrude oils into similar three groups. However, sample P14 fromgroup B is positioned in group C (arrow in Fig. 6b).

The depositional environment and lithology interpretationsindicate three groups of oils are present in the Potwar Basin. Thisresult is further evaluated and supported using various biomarkerparameters (Fig. 6c). A plot of C30 diahopane/hopane versus C29

diasterane/sterane ratios is shown in Fig. 6c and samples fromthe Potwar Basin fall into the same three groups. Group B showsrelatively higher diasterane/sterane ratios compared to the groupC indicating that the group B oils are generated from more clasticrocks, while group C shows higher C30 diahopane/hopane ratiosindicating that the group C oils were generated from more oxicdepositional environment source rocks. The oil from group A (P1)shows higher values of diahopane/hopane and diasterane/steraneratios (0.38 and 0.97, respectively) separating this oil from all theother oils (Fig. 6c), and indicating a clay rich, oxic depositionalenvironment. The P1 oil sample was likely generated from oxic/clay rich source rocks, which is consistent with its C30 diaho-pane/C29Ts ratio. The C30 diahopane/C29Ts ratio has been suggestedas a good indicator of oxic/suboxic depositional settings of OM

1236 M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240

(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 sourcerocks based on lithology and environments of deposition (seeabove), 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 dysoxicdepositional settings for OM than for group C oils (cf. Peters andMoldowan, 1993). An anomalously high value relative to the groupB oils is observed for the P14 sample in the C30 diahopane/hopaneversus C29 diasteranes/sterane diagram (Fig. 6c). The reason for thisanomaly could be related to the depositional environment (highPr/Ph ratio for this sample) and source organic facies (Moldowanet al., 1991; Peters et al., 2005 and references therein).

3.5. Source of OM

The sources of OM were determined from the distributions oftricyclic, tetracyclic and pentacyclic terpanes and steranes. Fig. 7shows m/z 191 chromatograms of the representative oil samplesfrom all delineated groups from the Potwar Basin. The source bio-marker parameters are listed in Table 3. The group A oil shows asignificantly lower relative abundance of tricyclic and tetracyclicterpanes 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; Nabbefeldet al., 2010a). The oil correlation diagram of C19/(C19 + C23) tricyclic

C

C

C

C

CC27

28

29

27

2829

Group-A

Group-B

Group-C

81 85 89

Relative Retention time

13 , 17

14 , 17

14 , 17

Diasteranes

Steranes

Rel

ativ

e R

espo

nse

Fig. 9. Mass chromatograms (m/z: 217) showing distribution of steranes anddiasteranes from representative oil samples from the three delineated groups ofoils. Numbering on peaks refers to steranes and diasteranes compounds. Sample P1represents group A, sample P7 represents group B and sample P16 represents groupC.

versus C24 tetracyclic/(C24 tetracyclic + C23 tricyclic terpane) isshown in Fig. 8a where group A indicates clearly a different sourceof OM compared to the other groups (cf. Edwards et al., 1997; Volket al., 2005). The presence of the aromatic plant biomarker retenealso tends to support a terrigenous source of OM for the group Aoil, although this biomarker can also be ascribed to algae (Nabbe-feld et al., 2010b and references therein). The low values for the C23

tricyclic/C30 hopane (<0.1) and C28 tricyclic/C30 hopane ratios (�0;Table 3) also indicate a lower contribution of marine OM for thegroup A oil (cf. Peters et al., 2005). These values indicate that thegroup A oil was generated from source rocks containing terrige-nous OM.

A representative ion chromatogram (191) from group B oils isshown in Fig. 7b and shows a distribution of both tricyclic and pen-tacyclic terpanes as observed in typical mature marine crude oils.The highest components in the group B oils are C29 and C30 ho-panes; they are in higher abundance than tricyclic terpanes(Fig. 7b) differentiating group B from the other groups. The com-parative abundances of the homohopanes has been associated withsuboxic depositional environments (Peters and Moldowan, 1993)and a higher abundance of C35 and other homohopanes are ob-served in group B oils relative to group C oils (Fig. 7b and c). Thedistribution of steranes and rearranged steranes is used for furtherdifferentiation in source OM. Sterane and diasterane distributionsare shown by mass chromatograms (m/z 217) from representativeoil samples of each oil group in Fig. 9. While group A has a terrig-enous source, there is no significant difference observed in the dis-tribution pattern of regular steranes. The group A masschromatogram (m/z 217) shows a higher abundance of diasteranes

Group-A

Group-C

Group-B

C17

C25

C10

UCM

C35

20 40 60 80 100 120

Relative retention time (min)

Rel

ativ

e in

tens

ity

Fig. 10. Representative total ion chromatograms (TICs) of the saturated hydrocar-bon fractions from each group of the Potwar Basin oils. Number on peaks refers tothe n-alkane carbon number. UCM, unresolved complex mixture.

M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240 1237

compared to regular steranes consistent with a clastic source rockcommon 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 significantlyless abundant than the latter. These distribution differences areindicating 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 inthe group C oils (Fig. 9) indicating the significant contribution ofterrigenous and algal OM, respectively. These interpretations ofterrigenous and algal contribution to group C oils are consistentwith presence of higher concentrations of tricyclic terpanes thanhopanes (see below) (cf. Philp et al., 1989) and high API valuesfor these oils (Peters et al., 2005). The regular sterane correlationdiagram between C27/C29 aaa versus C28/C29 abb steranes isshown in Fig. 8b which differentiates the Potwar Basin oils intothe same three groups where group C shows higher C28 regularsteranes 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 sourceinput than group C oils.

The representative 191 ion chromatogram for group C oilsshows significantly higher abundance of tricyclic terpanes than ho-panes (Fig. 7c). The C23 tricyclic terpane is the most abundant m/z191 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 Cfrom groups A and B. Various organisms have been suggested asthe source of tricyclic terpanes in oils and bitumens (Ourissonet al., 1982; Volkman et al., 1989; Peters and Moldowan, 1993;Simoneit et al., 1993) and the ubiquitous occurrence of tricyclic

P1

P17

P14,P

0

0.2

0.4

0.6

0.8

1

1.2

Pr/n

Ph/n

-C18

(a)

P1

P17

P9

P14

0

10

20

30

40

50

60

0.2 0.4 0.6 0.8

0.2 0.4 0.6 0.8

Pr/

API

gra

vity

(°)

(b)

Fig. 11. (a) Pr/n-C17 and Ph/n-C18 (b) API value versus Pr/n-C17 showing a d

terpanes in sedimentary OM of varying ages has been related tonumerous source origins (Farrimond et al., 1999). The occurrenceof tricyclic terpanes in the Potwar Basin C oils is probably relatedto an algal source which is supported by comparative abundanceof regular C28 steranes in group C oils (Table 3; Fig. 8b). Higherabundance of tricyclic terpanes than hopanes has also been relatedto terrigenous input (Philp et al., 1989) that is consistent withhigher abundance of C29 steranes in group C oils. Similarly, a highertotal sterane/hopane ratio >0.6 (�1.0 for most of the oils) may re-flect a greater eukaryotic input (both algae and terrigenous) togroup C oils source rocks. The C23 tricyclic/C30 hopane and C24 tet-racyclic/C30 hopane ratios (0.5–1.5 and 0.4–1.2, respectively, Table3) indicate typically marine OM input for group B and C oils wherehigher values for group C oils shows a higher marine input (algalinput) (cf. Peters et al., 2005). This differentiation in numeroussource OM parameters shows a different origin for source inputfor 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 withrespect 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 forthe same sample such as C23 tricyclic/C30 hopane, C24 tetracyclic/C30 hopane, C23 tricyclic/C28 tricyclic terpane and steranes/hopanesplace 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 C27 P C29� C28, group B showsC29 P C27� C28 and group C shows C29 > C28 > C27 (Table 3). Therelative distribution profile of abb steranes (C27 P C29� C28) fromgroup A reveals higher lacustrine source input while it has beenshown that this group has a terrigenous origin. The abb steranesprofile from group B oils shows higher C29 compounds, indicatingterrigenous input in contrast to results drawn from this study that

18

P15P16

P2P3

P8P13

P7

P11,P12

P10

-C17

Biodegradation

1.2

,P18

P15,P16

P2P3

P8

P13P4-5

P11-12

P6

1 1.2 1.4 1.6

1 1.2 1.4 1.6

n-C17

Biodegradation

P6

ecrease in the API gravity of crude oils with increasing biodegradation.

1238 M. Asif et al. / Organic Geochemistry 42 (2011) 1226–1240

this group is marine. Reasons for these contradictory findings couldbe solved by evaluating the source rocks of Potwar Basin oils, butsource to oil correlation along with migration affects, reservoirconnectivity and oil mixing in Potwar Basin are still to bedetermined.

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 usedparameters 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. Thedistribution pattern of saturated HC fraction from group A and Cshows the presence of a full suite of n-alkanes and the absenceof any unresolved complex mixture (UCM), indicating no biodegra-dation. While TIC from the a representative group B oil shows asubstantial UCM in the saturated fraction and a lack of n-alkanesindicating that these oils have been biodegraded and the remainingfraction has become enriched in high molecular weight unresolvedcomponents. Similarly, isoprenoids show resistance to biodegrada-tion compared to the n-alkanes because the n-alkanes are removedfaster than isoprenoids during biodegradation (Peters et al., 2005).Hence isoprenoid/n-alkane ratios from saturated fractions increasewith an increase in biodegradation (Winters and Williams, 1968)and Pr/n-C17 and Ph/n-C18 ratios > 1 typically indicates the effectof biodegradation on crude oils. The plot of Pr/n-C17 versus Ph/n-C18 (Fig. 11a) shows a trend consistent with biodegradation; theseratios increase with increasing biodegradation. The API gravity is abulk property that directly relates to gross compositions of crudeoils. The Potwar Basin crude oils show a wide range of API gravities(16–48�; 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. Theresults show that extent of biodegradation for some of the crudeoils 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 fromthe Potwar Basin is represented with level of biodegradation in Ta-ble 1. It is observed that some of the oils from group B are affectedby minor biodegradation while group A and C are non-biodegraded(Fig. 11a and b).

The representative group B chromatogram shows a high UCMbut also the presence of n-alkanes (Fig. 10). This type of saturatedHC profile indicates the possibility of mixing of biodegraded andnon-biodegraded crude oils in the reservoir. Assessment of biodeg-radation and in-reservoir mixing in the Upper Indus oils (PotwarBasin) has been reported using biomarker parameters (Asif et al.,2009).

4. Conclusions

Geochemical characterisation and classification of the PotwarBasin crude oils were performed using biomarker and stable iso-tope distributions. Saturated HC biomarkers indicate at least earlyto peak oil generation window of thermal maturity while aromaticHC parameters and calculated vitrinite reflectance from theseparameters reveal late oil generation window thermal maturityfor Potwar Basin oils. Stable carbon and hydrogen isotopes of sat-urated and aromatic HC fractions delineated three groups in thePotwar 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 fromfluvio-deltaic source rocks deposited in an oxic depositional

environment. Group A oil shows more negative (isotopicallylighter) d13C of both saturated and aromatic HC fractions com-pared to all other oils. The abundance of C19 tricyclic and C24

tetracyclic terpanes along with a higher abundance of a diag-nostic aromatic HC biomarker, retene, suggests a terrigenoussource 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 andbased on tricyclic, tetracyclic and pentacyclic terpane and ster-ane distributions separate these oils into groups B and C. GroupB oils show the heaviest d13C for both saturated and aromaticHC fractions. Some of the group B crude oils are biodegraded(level 2–3) 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 inputdeposited under marine oxic environments, which is supportedby the presence of extended tricyclic terpanes and regular ster-anes. This group shows light d13C in the saturated HC fractionrelative to group B oils; however d13C 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 GC–MSand S. Wang for bulk isotope analysis and maintenance. The HigherEducation Commission, Islamabad, Pakistan is thanked for an IRSIPfellowship and a travel award Grant (IRSIP-5-Ps-20) to MA. KGacknowledges 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) andPakistan Oilfields Ltd. (POL). J. Curiale and H. Huang are acknowl-edged for constructive reviews of the initial version of this paper.

Associate Editor—Maowen Li

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