GEOCHEMICAL APPLICATIONS OF POLYCYCLIC AROMATIC HYDROCARBONS IN
CRUDE OILS AND SEDIMENTS FROM PAKISTAN
Submitted By: MUHAMMAD ASIF
05-Ph.D-Chemistry-02
DEPARTMENT OF CHEMISTRY
UNIVERSITY OF ENGINEERING AND TECHNOLOGY LAHORE – PAKISTAN
2010
GEOCHEMICAL APPLICATIONS OF POLYCYCLIC AROMATIC HYDROCARBONS IN
CRUDE OILS AND SEDIMENTS FROM PAKISTAN
A Thesis Submitted
To The University of Engineering & Technology Lahore In Partial fulfillment of the Requirements for the Degree of
Doctorate of Philosophy In
Chemistry By
MUHAMMAD ASIF 2005-Ph.D-Chemistry-02
Supervisor Prof. Dr. Fazeelat Tahira
DEPARTMENT OF CHEMISTRY UNIVERSITY OF ENGINEERING AND TECHNOLOGY
LAHORE – PAKISTAN 2010
GEOCHEMICAL APPLICATIONS OF POLYCYCLIC AROMATIC HYDROCARBONS IN CRUDE OILS AND SEDIMENTS FROM
PAKISTAN
Research Thesis submitted in Partial Fulfillment of the Requirements for the Degree of
Doctor of Philosophy in Chemistry
Approved on: _______________
Signature:__________________ Prof. Dr. Fazeelat Tahira Internal Examiner Signature:__________________ Prof. Dr. M. Akram Kashmiri External Examiner Signature:__________________ Prof. Dr. Saeed Ahmad Chairman of the Department Signature:___________________ Prof. Dr. Fazeelat Tahira Dean Faculty of Natural Sciences, Humanities and Islamic Studies
DEPARTMENT OF CHEMISTRY University of Engineering and Technology, Lahore-Pakistan,
This thesis has been evaluated by the following examiners External examiners: a) From Abroad i) Dr. R. Paul Philp Professor Petroleum and Environmental Geochemistry The University of Oklahoma School of Earth and Energy 100 East Boyd street suite 810, Sarkeys Energy Center Norman, OK 73019 USA ii) Dr. Paul Greenwood Senior Research Fellow, Biogeochemistry The University of Western Australia 35 Stirling Highway Crawley WA 6009 Australia b) From with in the country Dr. M. Akram Kashmiri Professor of Organic Chemistry Chairman, Board of Intermediate and Secondary Education, Lahore. Internal Examiner Prof. Dr. Fazeelat Tahira, Professor of Organic Chemistry Dean of natural sciences, humanities and Islamic studies, UET Lahore
Declaration
I “MUHAMMAD ASIF” declare that the Thesis entitled: “GEOCHEMICAL
APPLICATIONS OF POLYCYCLIC AROMATIC HYDROCARBONS IN
CRUDE OILS AND SEDIMENTS FROM PAKISTAN” is my own research work.
This thesis is being submitted for partial fulfillment of the requirements for the degree of
Ph.D. in Chemistry. This thesis contains no material that has been accepted and
published previously for the award of any degree.
_____________________
Signature
i
ACKNOWLEDGEMENTS I express my heartiest and sincere thanks to my respected and honorable
Research Supervisor, Prof. Dr. Fazeelat Tahira, Dean, Faculty of Natural Sciences,
Humanities and Islamic Studies, University of Engineering and Technology, Lahore,
who’s keen interest, guidance and encouragement has been a source of great help
throughout this research work. Special and heartiest thanks to Prof. Dr. Kliti Grice,
Director, WA-IOGC group, Curtin university of Technology, Perth, Australia for
providing me an opportunity to work with an excellent group. Her unforgettable
cooperation, guidance, source of knowledge and kind behavior towards me will be ever
remembered. I would like to give respectful thanks to Prof. Dr. Robert Alexander for his
guidelines for understanding of kerogen chemistry of sedimentary organic matter.
I thankful to Prof. Dr. Saeed Ahmad, Chairman, Department of Chemistry,
University of Engineering and Technology, Lahore for providing me an opportunity to
complete my degree.
I would like to acknowledge and thank to my friends Abdus Saleem, Saleem
Aboglila, Umair Akram, Amy Bowater, Birgit Nabbefeld, Svenja Tulipani, Dawn White,
Ercin Maslen, Christiane Eiserbeck, Christiane VVE, Pierre Le Metayer, Ken Williford,
Hina Saleem, Muhammad Irfan Jalees, Shagufta Nasir, Shahid Nadeem, Arif Nazir and
Imran Kaleem and many more for their friendly discussions and chat during this research
thesis. I also thank to Geoff Chidlow, Sue Wang, Kieran Pierce, Tanya Chambers, Zia-ul-
Hassan and Anwar Nadeem for technical support through out my research.
I am happy to acknowledge the love and prayers of my parents, brothers and
sisters. Their moral support is a great source of strength for me in every field of life. With
out their prayers, sacrifices and encouragements, the present work would have been a
merry dream.
Muhammad Asif
ii
ABSTRACT
Crude oils and sediments extracts from Kohat-Potwar Basin (Upper Indus
Basin) were examined for polycyclic aromatic hydrocarbons (PAHs), heterocyclic
aromatic hydrocarbons, biomarkers and stable isotope compositions. The first four
chapters provide background to the research. Chapter 5 discusses the petroleum
geochemistry of Potwar Basin where three groups of oils were recognized on the basis of
diagnostic biomarkers, distribution of PAHs and stable bulk carbon and hydrogen
isotopes. In chapter 6, PAHs distributions and compound specific stable hydrogen isotope
compositions have been used to assess minor biodegradation in Potwar Basin oils. The
final chapter of this thesis (chapter 7) describes the formation of heterocyclic aromatic
hydrocarbons and fluorenes in sedimentary organic matter through carbon catalysis
reactions.
Diagnostic biomarker parameters along with stable bulk δ13C and δD isotope
abundance reveal three groups of oils in Potwar Basin. Group A contains terrestrial
source of OM deposited in highly oxic/fluvio-deltaic clastic depositional environment
shown by high Pr/Ph, high diahopane/hopane, high diasterane/sterane, low DBT/P ratios
and higher relative abundance of C19 tricyclic and C24 tetracyclic terpanes. Aliphatic
biomarkers for rest of the oils indicate marine origin however two ranges of values for
parameters differentiate them into two sub-groups (B and C). Group B oils are generated
from clastic rich source rocks deposited in marine suboxic depositional environment than
group C oils which are generated from source rocks deposited in marine oxic depositional
environment. Group C oils show higher marine OM (algal input) indicated by extended
tricyclic terpanes (upto C41 or higher) and higher steranes/hopanes ratios. Distribution of
PAHs classified Potwar Basin oils into similar three groups based on depositional
environments and source OM variations. Abundant biphenyls (BPs) and fluorenes (Fs)
are observed in group A oils while group B oils showed higher abundance of
dibenzothiophenes (DBTs) and negligible presence of dibenzofurans (DBFs) and Fs and
group C oils showed equal abundance of DBTs and Fs. This relative abundance of
heterocyclic aromatic hydrocarbons in Potwar Basin oils broadly indicate that the
distribution of these compounds is controlled by depositional environment of OM where
iii
sulfur compounds (i.e. DBTs) are higher in marine source oils while oxygen compounds
(DBFs) and Fs are higher in oxic/deltaic depositional environment oils. Higher
abundance of aromatic biomarkers the 1,2,5-trimethylnaphthalene (1,2,5-TMN), 1-
methylphenanthrene (1-MP) and 1,7-dimethylphenanthrene (1,7-DMP) indicate major
source of OM for group A oil is higher plant supported by abundance of conifer plants
biomarker retene. Variations in distribution of triaromatic steroids (TAS) in Potwar Basin
oils clearly indicate source dependent of these compounds rather than thermal maturity.
Higher abundance of C20 and C21 TAS and substantional difference in distribution of long
chain TAS (C26, C27, C28) between the groups indicate different source origin of these
compounds. Group A shows only C27 and C28 TAS while group B shows C25 to C28 TAS
and absence of these compounds in group C oils revealed that the sterol precursors for
these compounds are most probably different. Aliphatic and aromatic hydrocarbon
maturation parameters indicate higher (late oil generation) thermal maturity for all oils
from the Potwar Basin. The crude oils of group A and C are typically non-biodegraded
mature crude oils whereas some of the oils from group B showed minor biodegradation
indicated by higher Pr/n-C17, Ph/n-C18 and low API gravity.
Distribution of PAHs and stable hydrogen isotopic composition (δD) of n-
alkanes and isoprenoids has been used to assess the minor biodegradation in a suite of
eight crude oils from Potwar Basin, Pakistan (group B). The low level of biodegradation
under natural reservoir conditions was established on the basis of biomarker distributions.
Bulk stable hydrogen isotope of saturated fractions of crude oils show an enrichment in D
with increase in biodegradation and show a straight relationship with biodegradation
indicators i.e. Pr/n-C17, API gravity. For the same oils, δD values for the n-alkanes
relative to the isoprenoids are enriched in deuterium (D). The data are consistent with the
removal of D-depleted low-molecular-weight (LMW) n-alkanes (C14-C22) from the oils.
The δD values of isoprenoids do not change during the minor biodegradation and are
similar for all the samples. The average D enrichment for n-alkanes with respect to the
isoprenoids is found to be as much as 35‰ for the most biodegraded sample. The relative
susceptibility of alkylnaphthalenes and alkylphenanthrenes at low levels of
biodegradation was discussed. Alkylnaphthalenes are more susceptible to biodegradation
iv
than alkylphenanthrenes while extent of biodegradation decreases with increase in alkyl
substitution on both naphthalene and phenanthrenes. A range of biodegradation ratios
(BR) are purposed from dimethylnaphthalene (DNBR), trimethylnaphthalenes (TNBR)
and tetramethylnaphthalene (TeNBR) that show significant differences in values with
increasing biodegradation and are suggested as good indicators for assessment of low
level of biodegradation.
Laboratory experiments have shown that activated carbon catalyses the reactions
of biphenyls (BPs) with surface adsorbed reactants that incorporate S, O, N or methylene
forming some common constituents of sedimentary organic matter namely,
dibenzothiophene (DBT), dibenzofuran (DBF), carbazole (C) and fluorene (F). A
relationship between the % abundance of the hetero element in kerogen and the
abundance of the related heterocyclic compound in the associated soluble organic matter
supports the hypothesis that these reactions occur in nature. More specific supporting
evidence is reported from the good correlation observed between methyl and dimethyl
isomers of the reactant BPs and the methyl and dimethyl isomers of the proposed product
heterocyclics compounds i.e. DBTs, DBFs, Cs and Fs. It is suggested that these
distributions reported for sediments and crude oils from the Kohat Basin are the result of
a catalytic reactions of compounds with BP ring systems and surface adsorbed species of
the hetero element on the surface of carbonaceous material. Similar distributions of
heterocyclic aromatic hydrocarbon from Carnarvon Basin (Australia) were illustrated to
show the global phenomenon of this hypothesis. Furthermore, the abundances of these
compounds (DBT, DBF and BP) show similar concentration profiles throughout the
Kohat Basin sediments suggesting that share a common source. These compounds also
correlate well with changes in the paleoredox conditions. These data tends to point
towards a common precursor perhaps lignin phenols of land plants. Coupling of phenols
leads to BP, which has been demonstrated in laboratory experiments to be the source of
C, DBT, DBF, and F.
v
PUBLICATIONS AND CONFERENCE PRESENTATION
Asif, M., Grice, K., Fazeelat, T., Dawson, D., 2008. Oil-oil correlation in the Upper
Indus Basin (Pakistan) based on biomarker distributions and compound-specific
δ13C and δD. In: 15th Australian Organic Geochemistry Conference, 8-12th
September, National Wine Centre, Adelaide, SA, Australia.
Asif, M., Grice, K., Fazeelat, T., 2009. Assessment of petroleum biodegradation using
stable hydrogen isotopes of individual saturated hydrocarbons and polycyclic
aromatic hydrocarbon distributions in oils from the Upper Indus Basin, Pakistan.
Organic Geochemistry 40, 301-311.
Asif, M., Alexander, R., Fazeelat, T., Pierce, K., 2009. Geosynthesis of dibenzothiophene
and alkyl dibenzothiophenes in crude oils and sediments by carbon catalysis.
Organic Geochemistry 40, 895-901.
Asif, M., Alexander, R., Fazeelat, T., Grice, K., 2010. Sedimentary processes for the
geosynthesis of heterocyclic aromatic hydrocarbons and fluorenes by carbon
reactions, Organic Geochemistry 41, 522-530.
Fazeelat, T., Asif, M., Saleem, A., Nazir, A., Zulfiqar, M., Nasir, S., Nadeem, S., (2009).
Geochemical investigation of crude oils from different oil fields of the Potwar
Basin. Journal of Chemical Society of Pakistan 31, 863-870
Asif, M., Fazeelat, T., Grice, K., Petroleum Geochemistry of Potwar Basin, Pakistan: oil-
oil correlation by bulk stable isotopes and aromatic hydrocarbons distributions (In
preparations for Organic Geochemistry).
vi
TABLE OF CONTENTS Chapter # Description Page#
ACKNOWLEDGMENTS i
ABSTRACT ii
PUBLICATIONS AND CONFERENCE PRESENTATION v
TABLE OF CONTENTS vi
LIST OF TABLES x
LIST OF FIGURES xi
Chapter–1 INTRODUCTION 11.1 Petroleum Geochemistry 1
1.2 Polycyclic Aromatic Hydrocarbons (PAHs) 1
1.3 Hetercyclic Aromatic Hydrocarbons and Fluorenes in Crude Oils and Sediments
8
1.3.1 Incorporation of N, S, O Elements into Sedimentary OM 9
1.3.2 S Compounds from Laboratory Simulations 11
1.4 Carbon Catalysis 12
1.4.1 Kerogen 12
1.4.2 Coal 13
1.4.3 Activated Carbon 13
1.5 Scope and Framework of the Thesis 13
Chapter–2 GEOLOGICAL SETTINGS AND DESCRIPTION OF SAMPLES
16
2.1 Geology Settings of Kohat-Potwar Geological Province 16
2.1.1 Depositional Settings of Kohat-Potwar Basin 18
2.2 Descriptions of Crude Oils and Sediments 21
2.2.1 Potwar Basin 21
2.2.2 Kohat Basin 24
2.2.3 Geochemical Description of Sediments 25
Chapter–3 EXPERIMENTAL 28
vii
3.1 Materials and Reagents 28
3.2 Geochemical Techniques 29
3.2.1 Sample Preparation 29
3.2.2 Liquid Chromatography of Crude Oils and SOM 30
3.2.3 Isolation of Branched and Cyclic Alkanes 31
3.3 Laboratory Experiments 32
3.3.1 Reference Compounds and Glass Tubes Preparation 32
3.3.2 Laboratory Heating Experiments 32
3.4 Analytical Methods and Instrumentation 34
3.4.1 Elemental Analysis of Sediments 34
3.4.2 δ34S of Pyrite from Sediments 35
3.4.3 Gas Chromatography-Mass Spectrometry (GC-MS) 35
3.4.4 Gas Chromatography-Isotope Ratio Mass Spectrometry 36
3.4.5 Elemental Analysis-Isotope Ratio Mass Spectrometry (Bulk Isotope Analysis)
37
Chapter–4 IDENTIFICATION OF BIOMARKERS AND AROMATIC HYDROCARBONS
39
4.1 Saturated Hydrocarbons 39
4.1.1 n-Alkanes and Isoprenoids 39
4.1.2 Tricyclic and Tetracyclic terpanes 40
4.1.3 Pentacyclic Terpanes 41
4.1.4 Steranes and Diasteranes 43
4.1.5 Diamondiod Hydrocarbons 44
4.2 Polycyclic Aromatic Hydrocarbons 45
4.2.1 Biphenyl and Alkylbiphneyls 46
4.2.2 Naphthalene and Alkylnaphthalenes 47
4.2.3 Phenanthrene and Alkylphenanthrenes 48
4.2.4 Dibenzofuran and Alkyldibenzofurans 49
4.2.5 Carbazole and Alkylcarbazoles 50
4.2.6 Dibenzothiophene and Alkyldibenzothiophenes 51
4.2.7 Fluorene and Alkylfluorenes 52
viii
4.2.8 Identification of Retene 53
4.2.9 Compound Identification of Laboratory Experiments 54
Chapter–5 GEOCHEMISTRY Of POTWAR BASIN CRUDE OILS 55 Abstract 55
5.1 Introduction 56
5.2 Results and Discussion 59
5.2.1 Normal Alkanes and Isoprenoids Distribution 59
5.2.2 Carbon and Hydrogen Isotopic Compositions 59
5.2.3 Polycyclic Aromatic Hydrocarbons (PAHs) 63
5.2.4 Thermal Maturity of Potwar Basin Oils 65
5.2.5 Lithology and Depositional Environment 70
5.2.5.1 Heterocyclic Aromatic Hydrocarbons 73
5.2.6 Source of OM 74
5.2.6.1 Alkylnaphthalenes and alkylphenanthrenes
5.2.6.2 Triaromatic steroids (TAS)
81
83
5.2.7 Biodegradation 87
Conclusions 91
Chapter–6 POLYCYCLIC AROMATIC HYDROCARBONS (PAHs) AND STABLE HYDROGEN ISOTOPE STUDY AS INDICATOR OF MINOR BIODEGRADATION
93
Abstract 93
6.1 Introduction 94
6.2 Results and Discussion 95
6.2.1 Assessment of Biodegradation 95
6.2.2 Bulk Hydrogen Isotopic Compositions of Saturated Fractions
100
6.2.3 Compound Specific Hydrogen Isotopic compositions of n-alkanes and isoprenoids
101
6.2.4 Affects of Biodegradation on Polycyclic Aromatic Hydrocarbons
106
6.2.4.1 Alkylnaphthalenes 106
ix
6.2.4.2 Alkylphenanthrenes 112
Conclusions 114
Chapter–7 GEOSYNTHESIS OF HETEROCYCLIC AROMATIC HYDROCARBONS AND FLUORENES BY CARBON CATALYSIS
116
Abstract 116
7.1 Introduction 117
7.2 Results and Discussion 118
7.2.1 Laboratory Experiments on Active Carbon 119
7.2.1.1 Probable mechanism of geosynthesis reactions 121
7.2.2 Distribution of Heterocyclic Aromatic Hydrocarbon in Sediments and Crude Oils
124
7.2.2.1 Parent compounds 124
7.2.2.2 Methylated homologous of heterocyclics and Fs 131
7.2.2.3 Dimethyl homologous of heterocyclics and Fs 138
a) DMBPs vs DMDBTs 138
b) DMBPs vs DMCs and DMFs 140
7.2.3 Paleoredox Conditions and Heterocyclics Formation 144
Conclusions 146
REFERENCES 147 APPENDIX 170
x
LIST OF TABLES
Table # Description Page#1.1 Aromatic hydrocarbons thermal maturity parameters 5
2.1 Geological information of crude oils 22
2.2 Geological settings and Rock Eval data of sediments from well Mela-1
23
2.3 Aliphatic biomarker maturity parameters of Mela-1 sediments 27
3.1 Heating experiments details 33
4.1 Identifications of pentacyclic triterpanes from Fig. 4.3. 42
4.2 Identifications of steranes and diasteranes from Fig. 4.4. 43
4.2 Identification of compounds from Fig. 4.14. 54
5.1 n-Alkanes, isoprenoid ratios and bulk isotope data 60
5.2 Thermal maturity parameters calculated from aliphatic and aromatic hydrocarbons
66
5.3 Source OM and depositional environments parameters of Potwar Basin oils
78
5.4 Biomarkers parameters limits for Potwar Basin oils 80
5.5 Assessment of biodegradation results of Potwar Basin crude oils 90
6.1 n-Alkanes, isoprenoids, aliphatic biomarkers and diamondoids hydrocarbons ratios
96
6.2 δD(‰)* values of n-alkanes and isoprenoids (pristane and phytane) from Potwar Basin oils
102
6.3 Biodegradation ratios (BR) and alkylnaphthalenes ternary plot ratios.
110
7.1 Concentrations of compounds and elemental kerogen composition for Kohat Basin sediments.
127
7.2 Ring position relationships between BP and related heterocyclic compounds and Fs
132
7.3 Concentration and Compound Ratios of Sediments and Crude Oils 136
xi
LIST OF FIGURES
Fig. # Description Page#1.1 Possible biological precursors and pathways for the generation of
alkylnaphthalenes after Püttmann and Villar [180], Strachan et al. [19] and Armstroff et al. [141].
3
1.2 Generalized comparison of biodegradation sequence between aliphatic and aromatic hydrocarbons of crude oils
7
1.3 Structurally related compounds 8
2.1 Geological and Location map of Kohat-Potwar Basin oils (modified from [106,108,110-111])
17
2.2 Stratigraphy of Kohat-Potwar Basin, Pakistan, and location of crude oils and sediments used in this study (Modified from Wandrey et al., 2004 and references therein)
19
4.1 Total ion chromatograms (TIC) of saturated hydrocarbon fraction shows n-alkanes (n-C10 to n-C37) and isoprenoids in crude oil (Missakeswal-1); a: 2,6-dimethylundecane (I, see appendix); b: 2,6,10-trimethylundecane (nor-farnesane, II); c: 2,6,10-trimethyldodecane (farnesane, III); d: 2,6,10-trimethyltridecane (IV); e: 2,6,10,-trimethylpentadecane (nor-Pristane, V); Pr: pristane, 2,6,10,14-tetramethylpentadecane (VI); Ph: phytane, 2,6,10,14-tetramethylhexadecane (VII). Refer to section 3.4.3 for GC-MS program
39
4.2 Mass chromatogram (m/z: 191) illustrating tricyclic and tetracyclic terpanes in Dhurnal-1 crude oils. Peak numbers 19-41 denote carbon number of tricyclic terpane (VIII); C24*: C24 17,21-secohopane (IX); C30: C30 17α(H)-hopane (Xb). Refer to section 3.4.3 for GC-MS program.
40
4.3 Mass chromatograms (m/z: 191) showing the distribution of pentacyclic triterpanes (hopanes, X-XV) in Adhi-5 crude oil. Identity of peaks refers to Table 4.1. Refer to section 3.4.3 for GC-MS program
41
4.4 Mass chromatogram (m/z: 217) of Dhurnal-1 crude oil shows the profile of steranes and diasteranes. Peak identity numbers refer to Table 4.2. See section 3.4.3 for GC-MS program.
43
4.5 Adamantane (XVIII) and methyladamantanes are shown by sum of mass chromatograms (m/z: 136+135) and diamantine (XIX) and methyldiamantanes are shown by sum of mass chromatograms (mz/: 188+ 187) from saturated fraction of representative oil sample (Adhi-5). See section 3.4.3 for GC-MS program.
44
4.6 (a) Sum of mass chromatograms (m/z: 154+168) showing 46
xii
biphenyl (BP, XXII) and methylbiphenyls and (b) mass chromatogram (m/z: 182) showing dimethylbiphenyls in aromatic fraction of a representative oil (Adhi-5). DPM, diphenylmethane; numbers on each peak refer to respective methyl and dimethyl biphenyl isome
4.7 (a) Naphthalene (N, XXIII), methylnaphthalenes, dimethylnaphthalenes are shown by sum of mass chromatograms (m/z: 128+142+156 respectively) and (b) trimethylnaphthalenes, tetramethylnaphthalenes are shown by sum of mass chromatograms (m/z: 170+184 respectively) in a representative oil (Adhi-5). Numbers on each peak refer to position of methyl substituent.
47
4.8 Phenanthrene (XXIV), methylphenanthrenes, dimethylphenanthrenes shown by sum of mass chromatograms (m/z: 178+192+206 respectively) from aromatic fraction of Adhi-5. Numbers on each peak refer to respective alkyl phenanthrene isomer.
48
4.9 (Sum of mass chromatograms (m/z: 168+182) showing DBF (XXV) and methyldibenzofurans in Kohat Basin sediment, depth: 4290 m. Numbers on each peak refer to methyl dibenzofuran isomer.
49
4.10 (a) sum of mass chromatogram (m/z: 167+181) showing carbazole (C, XXVI) and methylcarbazoles and (b) mass chromatogram (m/z: 195) showing dimethylcarbazoles from Kohat Basin sediment, depth: 4690 m. Numbers on each peak refer to respective methyl and dimethyl carbazole isomer.
50
4.11 (a) Sum of mass chromatograms (m/z: 184+198) sowing dibenzothiophene (DBT, XXVII) and methyldibenzothiophenes and (b) mass chromatogram (m/z: 212) showing dimethyldibenzothiophenes from Kohat Basin sediment, depth, 4710 m. Numbers on each peak refer to respective methyl and dimethyl dibenzothiophene isomer.
51
4.12 Sum of mass chromatograms (m/z: 166+180) showing fluorene (F, XXVIII) and methylfluorenes in Kohat Basin sediment, Depth: 4290 m. Numbers on each peak refer to respective methyl substituent.
52
4.13 Mass chromatograms m/z: 219 and 234 showed Retene (XXI) in aromatic fraction of Adhi-5 crude oil.
53
4.14 Total ion chromatogram of the extract of laboratory experiment at 300 °C of reactants (biphenyl, activated carbon, NaN3, Air) for 16 hrs. Identification is given in Table 4.3.
54
5.1 The plots (a) δ13Csats vs δ13Caros (b) δ13Caver vs δDaver to delineate 62
xiii
groupings of petroleum in the Potwar Basin.
5.2 TICs showing distributions of aromatic hydrocarbons in representative samples from the Potwar Basin; N, naphthalene; ..
64
5.3 (a) Hopanes maturity parameters plot between C29 vs C30 of αβ/(αβ+βα) (c.f. [152]) (b) calculated vitrinite reflectance diagram from Rcb (TNR-2; [11]) and Rc (MPI-1; []156) show different thermal maturation stages of oil generation window.
67
5.4 (a) Pr/Ph versus DBT/P plot indicates lithology and depositional environment [167] (b) C30 17α-diahopane/C30 17α-hopane vs C29 diasteranes/sterane plot shows the affects of clay and depositional environment on Potwar Basin oils (c.f. [45] and refernces therein).
72
5.5 Bar diagram shows relative percentages of DBTs, DBFs, Fs in Potwar Basin oils.
75
5.6 Mass chromatograms (m/z 191) showing distribution of tricyclic (TT) and pentacyclic terpanes (hopanes, H) in Potwar Basin crude oils. numbers on peak indicate TT, 24*, C24-tetracyclic terpane and number with H indicate hopanes.
77
5.7 Cross plot between C19/(C19+C23) TT and C24 TeT/(C24 TeT + C23 TT) shows difference in source material in Potwar Basin oils (c.f. [173-175]).
79
5.8 (a) Distribution relationship between TMN ratios of Potwar Basin oils (b) higher plant aromatic biomarkers ratios 1,7-DMP/X and 1-MP/9-MP [5] indicated terrestrial input for group A oil.
82
5.9 Distribution of triaromatic steroids in Potwar Basin crude oils a) Adhi-5, b) Kal-2, c) Toot-12. Carbon number on peak refers to corresponding TAS (XXa to XXh).
84
5.10 Distribution relationship between C20/C21 TAS and C27/C29 diasteranes from Potwar Basin oil clearly indicate three groups
86
5.11 Representative TICs of saturated fractions from Potwar Basin oils, Group A, Adhi-5; group B, Joyamir-4; group C, Dhurnal-1. Number on peaks refers to n-alkanes carbon numbers.
88
5.12 (a) Plot of Pr/n-C17 vs Ph/n-C18 and (b) API value vs. Pr/n-C17 showing biodegradation trends in crude oils used in this study.
89
6.1 Total ion chromatograms of saturated hydrocarbon fractions for Potwar Basin crude oils showing different degrees of biodegradation. C17, C25 indicate carbon number of n-alkanes. 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; UCM, unresolved complex mixture.
97
xiv
6.2 Relationship between API gravity and biodegradation parameters (BP1 and BP2, [203]) showing API to by controlled by biodegradation rather than any other factor such as mixing.
99
6.3 δDsats vs. Pr/n-C17 shows enrichment in deuterium of saturated fractions with increase in biodegradation.
100
6.4 The δD (‰) distribution of n-alkanes from Potwar oils, (a) n-C14 to n-C29 n-alkanes (b) significant effect of biodegradation is observed in n-alkanes, n-C14-n-C22.
103
6.5 Plot of δD(‰) difference between LMW n-alkanes (n-C14 - n-C22) and isoprenoids vs. (a) API gravity, and (b) Pr/n-C17
105
6.6 Biodegradation susceptibility for alkylnaphthalene distributions (m/z 156+170+184; dimethylnaphthalenes, DMNs; trimethylnaphthalenes, TMNs; tetreamethylnaphthalenes, TeMNs). Numbers on each peak refer to respective alkylnaphthalene isomer and highlighted peaks show isomer components most affected by rising biodegradation
107
6.7 Order of susceptibility of alkylnaphthalenes and alkylphenanthrenes to microbial attack in the Potwar Basin crude oils (cf. [15]). Numbers refer to positions of methyl substituents. Ternary plot was plotted using similar conditions for analysis and identifications as reported by van Aarssan et al. [38] for TMNr (1,3,7/1,3,7+1,2,5)-TMNs, TeMNr (1,3,6,7/1,3,6,7+(1,2,5,6+1,2,3,5)-TeMNs and PMNr (1,2,4,5,7/1,2,4,5,7+1,2,3,5,6)-PMNs.
108
6.8 Polymethylnaphthalenes biodegradation ratios vs. Pr/n-C17 showed a good correlation. A significant decrease in DNBR, TNBR and TeNBR is observed.
111
6.9 A combined chromatogram of MP’s and DMP’s (m/z: 192+206) shows decrease in relative intensity with in increase in biodegradations. The numbers on peaks indicate the respective alkyl substituted isomer of phenanthrene and highlighted peaks show significant depletion as move to more biodegraded sample.
113
7.1 Total ion chromatograms (TIC) of extracts from laboratory heating experiments. Samples were heated at 300 °C for16 hr. Each blank experiment was identical in composition, temperature and time but without activated carbon. AC, activated carbon; BP, biphenyl; S, sulfur; TMB, 1,2,3,4-tetramethylbenzene; MBPs, methylbiphenyls.
120
7.2 TICs of extracts from laboratory heating experiments at temperature 270 °C for16 hr. Each blank experiment was identical in composition, temperature and time but without coal, BP, biphenyl; S, sulfur.
122
xv
7.3 Mass chromatograms (m/z: 198) of the extract of heating experiments of 3-MBP with elemental S in the presence of active carbon at different temperatures.
123
7.4 TICs of extract of heating experiments of BP with activated carbon using different alkyl precursor compounds, heating temperature and duration was same for all experiments i.e. 300°C and 16 hr. AC, activated carbon; BP, biphenyl; MBPs, methylbiphenyls; TMB, 1,2,3,4-tetramethylbenzene.
125
7.5 Purposed reaction pathways on activated carbon for formation of heterocyclic aromatic compounds and F from BP. AC, activated carbon; S: sulfur; BP, biphenyl; F, fluorene; DBT, dibenzothiophene; DBF, dibenzofuran; C, carbazole.
126
7.6 Relationship of reactant (BP)-product (DBT, DBF and F) for Kohat Basin sediments (data given in Table 7.1).
129
7.7 Relationship between compounds in SOM and the N, S, and O concentration of kerogen from each sample (data given in Table 7.1).
130
7.8 Representative ion chromatograms show relative distributions of MDBTs (198), MDBFs (m/z: 182), MBPs (m/z: 168), MCs (m/z: 181) and MFs (m/z: 180) from the Kohat Basin, Pakistan sediment (Depth, 4345 m). Symbols relate precursor-product compounds.
133
7.9
Distributions of MBPs and methyl homologues of DBF, C and F in crude oils from two different basins. a) Chaknaurang, Upper Indus Basin, Pakistan; b) Barrow, Carnarvon Basin, NW Australia. MBPs (m/z 168), MFs (m/z 180), MDBFs (m/z 182) and MCs (m/z 181). Symbols relate precursor-product compounds
135
7.10 Relationship between MBPs and MDBTs in Kohat Basin sediments. a) absolute concentration plot shows association between individual isomers of MBPs and MDBTs. b) plot shows ratio of MBPs and MDBTs to the parent BP and DBT in sediment samples.
137
7.11 Relative distribution of DMBPs and DMDBTs in Kohat Basin sediments (depth, 4680 m). Numbers on peaks indicate dimethyl substituted isomers of BP and DBT (Table 7.2). Symbols relate precursor-product compounds.
139
7.12 Relative distributions of methyl and dimethyl biphenyls and dibenzothiophenes in crude oils from two different basins. a) Mela-1, Kohat Basin, Pakistan, b) Wanaea, Carnarvan Basin, Australia. MBPs (m/z 168), DMBPs (m/z 182), MDBTs (m/z 198) and DMDBTs (m/z 212). Symbols relate precursor-product compounds.
141
xvi
7.13 Relative distribution of DMBPs (m/z: 182), DMCs (m/z: 195) and DMFs (m/z: 194) in the Kohat Basin sediment (Depth, 4940 m) and the Carnarvon Basin Griffin crude oil. Numbers on peaks indicate dimethyl substituted isomers. Symbols show precursor-product relationships (Table 3)
142
7.14 δ34S(‰) of pyrite against concentrations of DBT, DBF, BP, C and Pr/Ph with depth in Kohat Basin sediments Pakistan.
145
____
1
Chapter - 1
INTRODUCTION
1.1 PETROLEUM GEOCHEMISTRY
Petroleum geochemistry is the study of geochemical processes that lead to the
formation, migration, accumulation and alteration of crude oils and natural gas [1]. Crude
oil is a complex mixture of thousands of organic compounds, formed through processes
i.e. deposition, thermal and bacterial alteration of organic matter (OM), catalytic effects
of clastic minerals, oxidation and reduction in sedimentary environment for millions of
years [2]. A biomarker is compound in geological samples that can structurally related to
the natural products of the living organism i.e. animals, higher plants, bacteria, fungi,
algae which are the source of OM. The distribution of these compounds is highly
diagnostic of source organisms, and their subtle structural transformation could be
indicative of depositional environment, thermal maturity and biodegradation. The relative
proportions of biomarkers are routinely being used by geochemists to reconstruct ancient
depositional environment and to correlate crude oils to their source rocks.
1.2 POLYCYCLIC AROMATIC HYDROCARBONS (PAHs)
Aromatic hydrocarbons are important constituents of petroleum and extracts of
both recent and ancient sediments [3-7]. PAHs are not synthesized in living organisms
and almost absent in natural OM [8]. The majority of PAHs in petroleum are the products
of complex chemical transformations of nephthenic and/or olefinic biological ancestors
during diagenesis and catagenesis [4,9]. The biological origin of a given PAHs is obvious
only in favorable conditions, where a characteristic part of the naphthenic structure has
been preserved unchanged.
Distributions of PAHs are potentially useful in many areas of applied
petroleum geochemistry. Abundance of certain aromatic hydrocarbons in crude oils and
sediments such as 1,2,5-trimethylnaphthalene (1,2,5-TMN), 1,2,5,6-
tetramethylnaphthalene (1,2,5,6-TeMN), 9-methylphenanthrene (9-MP), 1,7-
2
dimethylphenanthrene (1,7-DMP) originate from diterpenoid and triterpenoid natural
products [4-5] (Fig. 1.1). The most useful application of aromatic hydrocarbons is
evolution of thermal maturity of OM [10-11]. The correlation of oils using aromatic
hydrocarbon distributions and alteration of crude oils in reservoirs are other important
application discussed [12-13]. Furthermore, affects of biodegradation of aromatic
hydrocarbons has been reported in crude oils, coals and sediments [14-17].
Precursor compounds of PAHs
The widespread occurrence of PAHs in sedimentary OM is the result of
complex chemical transformation of biological precursors under sedimentary conditions.
Alteration of functional groups in biological structures commonly occurs through
decarboxylation or dehydration and unsaturated bonds provides a starting point for
cyclization and aromatization [4,9,18-19] (Fig. 1.1). Specifically, diagenetic and
catagentic transformations of carotenoids, terpenoids and alkaloids have been considered
as possible pathways/precursors for the formation of mono-, di- and tri- aromatics [19-
24] (Fig. 1.1). Alkylnaphthalenes has been suggested to be originated from terrestrial
sources [4]. Biological compounds such as cyclic sesquiterpenoids from resins of conifer
plants are potential precursors of alkylnaphthalenes, 1,2,7-Trimethylnaphthalene is
suggested to originate from compounds like β-amyrin that are constituents of
angiosperms (Fig. 1.1). It is commonly observed that alkyl substituted aromatics are the
major components as compared to their parent (non alkyl substituted) hydrocarbons [25-
29]. They are proposed to be the product of both the organic facies as well as the
processes (diagenesis and catagenesis) through which OM passes during thermal stress
[30]. Clay minerals act as a catalyst to enhance the alkylation and decomposition of
parent aromatic hydrocarbons during sedimentary processes [31] and abundant
alkylnaphthalenes has been attributed to ring isomerization and transalkylation processes
[19]. On the basis of laboratory heating experiments and examination of geological
samples Bastow [30] suggested precursor-product relationship between certain isomers of
tri-, tetra- and penta-methyl naphthalenes and reported methylation of naphthalenes and
phenanthrenes is a geosynthetic process. The abundance of certain isomers of
alkylphenanthrenes in geological samples indicate specific source precursors for these
3
Fig. 1.1 Possible biological precursors and pathways for the generation of
alkylnaphthalenes after Strachan et al. [19] and taken from Armstroff et al. ([23]
and references therein).
4
compounds, such as retene and pimanthrene could have formed through aromatization of
tricyclic diterpenoids of plant resins [32] or by the dehydrogenation of alkylated
dihydrophenanthrenes [33]. Biphenyls have lowest relative abundance compared to other
aromatic series. Minor amounts of these compounds and their alkyl analogues have been
identified in marine sediments of Cambrian age [13]. Previous study by Alexander et al.
[34] refers to biphenyl carbon skeletons such as ellagic acid in natural products as
possible precursors of sedimentary biphenyls.
Thermal maturity applications of PAHs
The principal application of C10+ aromatic hydrocarbons has been as maturity
indicators for crude oils and sediments extracts [10,25-26,35-38]. The most common
approach exploits changes in the relative abundance between isomers of aromatic
hydrocarbons with increase in thermal affects. For example methylnaphthalene ratio
(MNR) is thermal maturity parameter derived by dividing thermodynamically less stable
isomer 1-methylnaphthalene (1-MN) (α-isomer) with thermodynamically more stable
isomer 2-methylnaphthalenes (2MN) (β-isomer) [25]. The concept is the shift of α-
methyl group to β- position with increase in thermal maturity [26] whereas methyl shift
resulted in a decrease in steric strain, hence β- position is thermodynamically more stable.
Similar principal has been used to devised number of polycyclic and sulfur aromatic
hydrocarbons maturity parameters [4,38 and references therein) shown in Table 1.1.
5
Table 1.1 Aromatic hydrocarbons thermal maturity parameters
Name and abbreviation Definition Reference
Methylnaphthalene ratio, MNR 2-MN/1-MN [26]
Dimethylnaphthalene ratio-1, DNR-1
(2,6-DMN + 2,5-DMN)/1,5-DMN [26]
Trimethylnaphthalene ratio-1, TNR-1
2,3,6-TMN/(1,4,6-TMN + 1,3,5-TMN) [10]
Trimethylnaphthalene ratio-2, TNR-2
(1,3,7-TMN + 2,3,6-TMN)/ (1,3,5-TMN + 1,3,6-TMN +
1,4,6-TMN) [11]
Trimethylnaphthalene ratio-1, TMNr
1,3,7-TMN/(1,3,7-TMN + 1,2,5-TMN) [38]
Tetramethylnaphthalene ratio, TeMNr
1,3,6,7-TeMN/(1,3,6,7-TeMN + 1,2,5,6-TeMN + 1,2,3,5-
TeMN) [38]
Petnamethylnaphthalene ratio, PMNr
1,2,4,6,7-PMN/(1,2,4,6,7-PMN + 1,2,3,5,6-PMN) [39]
Methylphenanthrene index-1, MPI-1
1.5 × (2-MP + 3-MP)/(P + 1-MP + 9-MP) [25]
Methylphenanthrene ratio, MPR 2-MP/1-MP [26]
Methyldibenzothiophene ratio, MDR 4-MDBT/1-MDBT [11]
Methyldibenzothiophene ratio, MDR′ 4-MDBT/(4+1)-MDBT [40]
MN: methylnaphthalene; DMN: dimethylnaphthalene; TMN: trimethylnaphthalenes; TeMN: tetramethylnaphthalene; PMN: pentamethylnaphthalene; MP: methylphenanthrene; MDBT: methyldibenzothiophene;
6
Biodegradation of PAHs
The effects of biodegradation on PAHs have been reported in different studies
[15,41-43]. In reservoir biodegradation of PAHs starts with smaller rings e.g. benzenes
are depleted first followed by naphthalenes and then phenanthrenes [15,41,43-44].
Alkylated PAHs show a range of susceptibility difference but generally methyl
substituted isomers are degraded in preference to dimethyl and trimethyl isomers of
benzene, naphthalene and phenanthrene [15,41,44]. However study by Huang et al. [43]
on Chinese biodegraded oils has reported higher susceptibility of trimethylnaphthalenes
over dimethylnaphthalenes and methylphenanthrenes over phenanthrene [43].
Demethylation of alkylnaphthalenes and alkylphenanthrenes was purposed as
biodegradation process as reason for this reverse susceptibility orders of depletion [43].
Biodegradation susceptibility order of saturated and aromatic hydrocarbons shows that
alkylbenzenes alter along with n-alkanes but persist till the depletion of isoprenoids [45].
Minor alteration of methyl and dimethylnaphthalenes are observed during depletion of n-
alkanes however trimethylnaphthalenes show depletion along with isoprenoids while
tetramethylnaphthalenes are resistant to biodegradation till the substantional removal of
steranes [15]. Biodegradation of alkylphenanthrenes indicates that depletion of
methylphenanthrenes starts after complete removal of n-alkanes while
dimethylphenanthrenes show resistant to biodegradation till steranes are altered [15,43].
A comparison biodegradation sequences between aliphatic and aromatic compound
classes is shown in Fig. 1.2.
7
L M H Severe Wenger et al., [46] Biomarker Biodegradation scale 0 1 2 3 4 5 6 7 8 9 10
n-alkanes
Alkylcyclohexanes
isoprenoids
C14-C16 bicyclic terpanes
Hopanes (25-norhopane present) steranes Hopanes
diasteranes
C26-C29 aromatic steriods
Porphyrins
Methyl- and dimethylnaphthalenes
Trimethylnaphthalenes
Methylphenanthrenes
Tetramethylnaphthalenes
Dimethylphenanthrenes
Methylbiphenyls
Ehtylphenanthrenes
Ethyl- and trimethylbiphenyls
Fig. 1.2 Generalized comparison of biodegradation sequence between aliphatic and
aromatic hydrocarbons of crude oils [45-46]. For more detail see Peters and
Moldowan, [47]; Fisher et al. [15,48], Triolio et al. [49]. Arrows indicate extent
of depletion of compound class where first altered (dashed lines), significant
depletion (solid grey line) and completely removed (black arrow). Wenger et al.
[46] indicates change in oil quality with extends of biodegradation; L: light, M:
moderate, H: heavy.
8
1.3 HETEROCYCLICS AROMATIC HYDROCARBONS AND FLUORENES IN CRUDE OILS AND SEDIMENTS
PAHs in petroleum are abundant with various structural features. Some of
them only contain benzene structures like naphthalene and phenanthrenes while some
have heteroatoms (S, O, N) within the benzene structures. The heteroatomic aromatic
hydrocarbons i.e. heterocyclics such as dibenzothiophenes (DBTs), dibenzofurans
(DBFs), carbazoles (Cs), and fluorenes (Fs) are important constituents of sedimentary
OM [6,11-12,50-51]. The origin of these compounds in sedimentary OM is under debate
for last three decades. Knowledge of specific source precursors and reaction pathways for
the formation of these compounds in crude oils and sediments has not been reported. It is
interesting to see that all these compounds show similar structural features except
heteroatoms (Fig. 1.3). It is noteworthy that biphenyl shows a structural associations with
these heterocylics compounds (Fig. 1.3). Here it may be supposed that these heterocyclics
compounds may have same origin and/or source precursors in sedimentary organic
matter.
S
NH
O
Biphneyl
Dibenzothiophene Dibenzofurane
Carbazole Fluorene
Fig. 1.3 Structurally related compounds
9
The sulfur heterocyclics aromatic hydrocarbons (dibenzothiophene and alkyl
dibenzothiophenes, DBTs) have been used to determine the thermal maturity of
sediments, coals and crude oils [4,7,37,52-53]. The oxygen heterocyclic aromatic
hydrocarbon, DBFs and related compounds are present in significant abundance in
terrestrial OM [6] and have also been suggested as oxidative degradation products of
coals [54]. Moreover, thermal maturity and lithology of source rocks are shown to control
the distribution of dibenzofuran and alkyldibenzofurans [55]. Pyrrolic nitrogen (N)
compounds have shown dependence on organic facies and thermal maturity of OM [50-
51]. Although contrasting results have been reported concluded from Canadian oils that
carbazoles concentration are not affected by variation in thermal maturity and
depositional environments [56]. Moreover, benzocarbazoles are reported as good
migration indicators in petroleum reservoirs [57]. A limited geochemical significance of
F are only reported for oil correlation studies along with DBT and DBF distributions
[12,58] where it is indicated that the distribution of these compounds depends on the
depositional environments of source OM while alkylfluorenes are not yet reported in any
from of sedimentary OM so for.
The abundance of heterocyclics aromatic hydrocarbons and fluorenes in crude
oils and sediments has been shown a relationship with sedimentary depositional
environments. For example sulfur heterocyclics (i.e. DBTs) are higher in marine water
depositional environments while oxygen heterocyclics (i.e DBFs and Fs) are higher in
freshwater depositional environments [12-13]. It is commonly observed that the
generation of heterocyclics in sedimentary environments is controlled by oxic/anoxic
depositional conditions. These finding could be used to build an idea that the formation
of heterocyclics aromatic hydrocarbons may depend on the abundance of heteroatomic
species in sedimentary OM. So the incorporation of hetero-elements in to sedimentary
OM is important and brief description about the topic is given below.
1.3.1 Incorporation of N, S, O Elements into Sedimentary OM
The incorporation of heteroatoms into the sedimentary OM takes place during
the early diagenesis [2]. The N containing biomacromolecules e.g. amino acids interact
10
and incorporate into OM at early diagenesis. The abundance of N incorporation depends
on the biological source of OM i.e. terrestrial plants contribute less N than
phytoplanktons. Depositional settings of OM also affect the relative preservation of N for
example clay rich contents interacted with biological OM and incorporate more N [59].
At the end of diagenesis, N content of OM do not change substantially up to the
formation of petroleum and natural gas [59]. However the structure of N containing
molecules varies with increase in thermal maturity of kerogen and coal [60-61].
Immature coals and kerogen show the presence of N in the form of amide/amine groups
[61] whereas pyrrole and pyridine N structures are observed during the formation of
petroleum [62]. A minor contribution of NH4+ ion in kerogen is always observed which
decreases with increase in thermal maturity; this could be due to the interaction of
pyridine and OH groups in the kerogen [60].
Sulfur (S) is the most abundant hetero-element in all types of sedimentary OM
found both in soluble and insoluble OM. The sulfate reducing bacteria produces S which
is the source of S at the water/sediment interface and results its incorporation at early
stage of diagenesis through abiotic reactions [63-64]. The mechanism of S incorporation
into the OM depends on the nature of sulfurized functional groups and can be
incorporated via intra- and intermolecular reactions [65]. The former process results in
the formation of cyclic alkyl sulfides (like thiolanes, thianes and thiophenes; e.g. Brassell
et al. [66] while Intermolecular sulfurization leads to the formation of (poly) sulfide
linkages between alkyl chains [67-68]. The occurrence of thiophenes in the S-rich
kerogen pyrolysates does not necessarily reflect a ubiquitous contribution of thiophenic
moieties to kerogen structure. However, such aromatic sulfur compounds may originate,
at least partly, from secondary transformation of (poly)sulfide-containing moieties [69].
In fact, heating (poly)sulfide-linked macromolecules results in the rapid formation of
thiophenic compounds [70-72]. Secondary thermal reactions of (poly)sulfide-bound
linear carbon skeletons were observed upon kerogen pyrolysis [73]. These findings
reflect the importance of incorporated S in kerogen for the formation of sulfur
compounds.
11
During early diagenesis, oxidation of OM is the major cause of decrease in
TOC and enrichment of residual OM in oxygen. Thus, oxidation is the partial degradation
of immature OM and increase in oxygen/carbon (O/C) ratio in the kerogen. Riboulleau et
al. [74] studied the kerogen pyrolysates from Kashpir oil shale (Russia) high abundance
of oxygen functional groups (C=O) on different carbons of alkyl chains was observed.
These results showed the O insertion at C=C in the kerogen after diagenetic isomerization
and random migrations. However in contrast to S incorporation, O incorporation may
occur at any stage of kerogen evolution [59].
1.3.2 Sulfur (S) Compounds from Laboratory Simulations
Examples of laboratory experiments of heteroatom species other than S with
hydrocarbons are scarce however there are many examples of laboratory chemical
reactions between S species and different biological compounds are reported. Common
sedimentary hydrocarbon precursors such as terpenes, steroids, alkylated aromatic
hydrocarbons, amino acids and humic acids has been used in these simulation
experiments [75-76]. S reactions with unsaturated isoprenoids followed by cyclization
and aromatization were reported for the formation of benzothiophenes [65,77].
Furthermore, the formation of dialkylated dibenzothiophenes was reported and related to
sulphurized triterpeniods source precursors [78]. Direct insertion of a heterosulfur bridge
into biaryls and angulary condensed arenes has been reported using hydrogen sulfide and
a heterogeneous catalysis [79]. The temperature (450-630 °C) involved in these reactions
is considerably higher than sedimentary temperatures. Insertion of S in aromatic
hydrocarbons at mild temperatures has been reported using elemental S/pyrite with and
without additives as catalyst [80]. This study was related to obtaining information about
the early stage of the coalification processes when elemental S is present.
These findings show that there are such examples where heteroatoms species
chemically react with sedimentary molecules with and with out catalyst. A new approach
is established where activated carbon has been successfully used as catalyst to evidenced
different sedimentary reactions [81]. A brief introduction for carbon catalysis and
12
structure comparison between different form of sedimentary OM (kerogen and coal) with
activated carbon is given in following section.
1.4 CARBON CATALYSIS
Activated carbons have long been used as a catalysts and catalyst support [82-84].
Carbon catalyst concept extends to study the formation of different sedimentary
hydrocarbons where it is supposed that carbonaceous material (kerogen and coal) provide
a catalyst support. Evidence that the solid–state carbonaceous material promotes
chemical reactions in sediments has been suggested from data obtained from hydrogen
exchange reactions between hydrocarbons [81,85]. In these studies, it has been shown
that carbon surface adsorbed species reacted with provided compounds to produce
structurally related compounds. Following section describe a structure comparison of
different form of carbonaceous material i.e. kerogen, coal and activated carbon. This
comparison provides an overview that the structure and nature of surface adsorbed
species in different forms of carbonaceous material is broadly same.
1.4.1 Kerogen
Forsman [86] recognized two types of kerogen on the basis of functional
groups and degradative studies. First, coaly kerogen which contains macromolecules
consisting of condensed aromatic rings interconnected by ether, alkoxy and S bridges
which attached the aromatic nuclei with hydroxyl, methoxyl groups. Second, non-coaly
type kerogen showed nearly open chain structure with cycloparaffine or aromatic rings
attached through O, N and S atoms. Later substantional work has been performed on
kerogens structure particularly on Green Rive Shale [87-89]. Kerogen structure purposed
by Siskin et al. [90] was balanced in all aspects of functional group analysis of the whole
kerogen and heteroatoms (N, S, O) distribution. Behar and Vandernbroucke [91] reported
a detailed structure evolution with change in diagenesis and catagenesis of the kerogen
type II. Chemical structure of kerogen at the beginning of diagenesis showed higher
aliphatic structures with higher hydrogen/carbon (H/C) ratio 1.34 while start of
catagenesis introduced aromatic moieties which further increased the aromatic clusters at
13
the end of catagenesis (H/C ratio 0.73). These kerogen structures contain different
macromolecular composition depend on rank/stage of diagenesis and catagenesis.
1.4.2 Coal
Significant work has been done on the coal structure models (for review see,
van Krevelen, [92]) and mostly focused on the quantitative distribution of functional
groups and carbon-carbon bond types. Coal structure at different coalification ranks has
been assumed to differ only in functional groups content and bond types [93]. The coal
structure showed similar type of saturated and aromatic macromolecules as that of the
kerogen [94]. Generally, as move from peat to bituminous to anthracite indicated
different coalification stages, the aromatic moieties of coal structure increases. Although
the elemental compositions (C, H) changed in same pattern as was reported in case of
kerogen but oxygen is exclusive part of bituminous coals [95].
1.4.3 Activated Carbon
Activated carbons structure has been proposed similar to the structure of coal
[96] and successful conversion of coal to active carbon has been reported by different
studies [97-98]. Boehm [99] studied the structure of active carbon and devised acidic and
basic surfaces groups. Different oxygen containing functional groups were reported such
as, carboxyl, carbonyl, carboxylic, phenolic, lactoles, ether and quinone. N adsorption on
active carbon has been devised by treatment with different nitrogen substances such as
NH3, HCN and reported the formation of nitrogen species such as amide, imide, lactam,
pyrroles and pyridines [100]. The carbon-sulfur surface compounds have been reported
on a wide variety of charcoals, activated carbons, carbon blacks, and coals. In the case of
activated carbons, they are generally formed by heating the carbon in the presence of
elementary sulfur [101] or sulfurous gases such as CS2 [102], H2S [103] and SO2 [104].
1.5 SCOPE AND FRAMEWORK OF THE THESIS
Previous studies have described oil correlations from Pakistani crude oils and
sediments from Upper Indus (Kohat-Potwar) Basin however these studies have focused
on basic geochemical analysis such as total organic carbon (TOC) and Rock Eval
14
analysis. Very little information is available on biomarkers and virtually no information
is available on aromatic hydrocarbons present in Pakistani crude oils and sediments so
for. This thesis broadly contained three objectives; first, classification of Potwar Basin
oils using aliphatic and PAHs distributions along with stable carbon and hydrogen
isotope compositions of saturated and aromatic fractions; Second, assessment of minor
biodegradation using PAHs distributions and stable hydrogen isotopes compositions of n-
alkanes and isoprenoids from selective Potwar Basin crude oils and third, geosynthesis of
heterocyclic aromatic hydrocarbons and fluorenes by carbon catalysis laboratory
simulation experiments. Distribution of heterocyclics and fluorenes is determined in
sediments and crude oils from Kohat Basin, Pakistan. Moreover, carbon catalysis
geosynthesis is supported by adding distribution of heterocyclics and fluorenes from
Carnarvon Basin, Australian crude oils.
The main objectives of any organic geochemical study are to establish i.e.
source of OM, thermal maturity, depositional settings and lithology of OM and affects of
biodegradation on hydrocarbons. In chapter 5 saturated and aromatic hydrocarbon
parameters used to establish oil-oil correlation study in a suite of 18 crude oils. Bulk
stable carbon and hydrogen isotopic compositions of saturated and aromatic hydrocarbon
fraction were used to delineate the oil groupings of Potwar Basin. The study gave an
insight to petroleum geochemistry of the area which is first ever of its kind.
In chapter 6 affects of minor biodegradation on alkylnaphthalenes and
alkylphenanthrenes, stable hydrogen isotopic composition of n-alkanes and pristane and
phytane were reported. It shows that susceptibility to biodegradation of alkylnaphthalenes
and alkylphenanthrenes varies with the extent of biodegradation. Compound specific
isotope analysis of n-alkanes and isoprenoids revealed that microbes preferentially
consumed isotopically lighter n-alkanes and residual compounds become enriched in D
of n-alkanes while isoprenoids D values are not affected at minor biodegradation.
In chapter 7, it is shown that activated carbon plays a key role in the
geosynthesis of heterocyclics aromatic hydrocarbons in subsurface environments.
Different heteroatomic species show adsorption on carbon surface at moderate heating
15
temperatures. These heteroatom adsorbed species reacted with biphenyl and
methylbiphenyls to produce heterocyclics aromatic hydrocarbons i.e. dibenzothiophene
(DBT), dibenzofuran (DBF), carbazole (C) and fluorene (F) and their methyl
homologous. Natural sedimentary OM has been shown a structure association between
biphenyls and these heterocyclics aromatic hydrocarbons. Abundance of these
compounds are used to show the product precursor relationship between biphenyls and
these compounds in sediments and crude oils from Kohat Basin, Pakistan and Carnarvon
Basin, Australia. The evidences of various carbon surface species are reported to devise
the reaction intermediate and pathways for geosynthesis of these compounds.
____
16
Chapter - 2
GEOLOGICAL SETTINGS AND DESCRIPTION OF SAMPLES
2.1 GEOLOGY OF KOHAT-POTWAR GEOLOGICAL PROVINCE
The Kohat-Potwar Basin also called Upper Indus Basin is situated in northern
Pakistan and located between lat. 32° and 34° N and, long. 70° and 74° E (Fig. 2.1). It is
an onshore basin bounded on the North by Parachinar-Muree fault, on the West by
Kurram fault, on the South by Surghar and Salt Ranges and on the East by Jehlum fault.
The Kohat-Potwar Basin is a portion of Indian plate deformed by Indian and Eurasian
plate collision and overthrust of Himalayas on the north and northeast [105]. The detailed
petroleum geology of the area has been described by different authors [106-108].
The geological division between Kohat and Potwar is done naturally by river
Indus, the East and West of river represent the Potwar and Kohat Basins respectively
(Fig. 2.1). The geological structure of the Potwar Basin is one of the most complex
structures of the world which is the result of the Tertiary Himalayan collision between
Eurasian and Indian plates [105]. This intense tectonic activity has affected Eastern
Potwar the most compared to Western Potwar. The eastern Potwar contains carbonate
reservoir rock of Cambrian to Tertiary ages. The basin infilled started with thick Infra-
Cambrian evaporate deposits overlain by relatively thin Cambrian to Eocene age platform
deposits followed by thick Miocene-Pliocene molasses deposits. The Infra-Cambrian salt
provided an easy detachment of Eocene-to-Cambrian (E-C) sequence as a result of
intense tectonic activity during Himalayan Orogeny during Pliocene to middle
Pleistocene time. This thinner E-C sequence in eastern Potwar affected by compressional
forces has generated large number of fold and faults. The E-C layer varies from a few
meters to 400 m in the eastern Potwar [109]. The crude oils discovered from this area
showed a range of reservoir formations (section 2.2).
17
Fig.2.1 Geological and Location map of Kohat-Potwar Basin oils (modified from [106,108,110-111]).
18
The Kohat Basin is tectonically complex area of northern Pakistan and is a
tilted plateau where moderate-steeper dips and asymmetrical structures resulted in a large
number of thrusts/normal faults [112]. Eocene through Pliocene are involved in a
complex fold and thrust belt in which Eocene salt occupies the cores of many of the
anticlines. Upper Eocene is more deformed than Lower Eocene where this area
deformation resulted in duplex structures in Kohat formation of Eocene [112]. Kohat
Basin showed absence and/or very thin deposition in Cretaceous times due to erosion and
emergence out of the area from sea. This emergence was higher in south and east of the
Basin evidenced by less deposition in cretaceous sections [112]. Although, the geological
information of Kohat Basin is scarce but unconformities and sharp variation in deposition
made this area is very unpredictable (see [112]).
2.1.1 Depositional Settings of the Kohat-Potwar Basin
Depositional record of the Kohat-Potwar geological province is given in Fig
2.2. Sedimentation in the Kohat-Potwar area began in the Precambrian and lasted until
the Pleistocene. Three major unconformities in the area are Ordovician to Carboniferous,
Mesozoic to late Permian and Eocene to Oligocene. The basin infilled started with thick
infra-Cambrian evaporates with carbonates and oil-impregnated shales represented by
Salt Range Formation which is overlain metamorphic rocks reported as the oldest
sedimentary rocks in the Kohat-Potwar Basin [106]. The salt lies unconfirmably on the
Precambrian basement above the Salt Range, massive sandstone and marine shales of
Lower Cambrian Jhelum Group, Khewra Formation are deposited. Cambrian rocks
comprised sandstone, siltstone, shale and dolomite represented by Kussak, Jutana, and
Baghanwala Formations (Fig. 2.2). This whole sequence is marine in origin and
terminated by a major unconformity [106].
Permian Nilawahan Group (Fig. 2.2) consists of sandstone, clay, marl and
fossiliferous limestone overlie the Cambrian rocks after an unconformity. The lower
Permian Tobra and Dandot Formations are comprised of glacial tillits and coarse-grained
sandstones with shales. Some fluvial sandstone with occasional shale and coal seams
were deposited within the marine sequence of Warcha and Sardhai Formations [106].
19
Crude oil Sediment
P2, P11-P16
P17-P18, P19P22
P8-P9
P1, P6-P10
P3-P5
P20
S1-S3S4 -S7S8-S9
S10
S11
S12-S13S14
Fig. 2.2 Stratigraphy of Kohat-Potwar Basin, Pakistan and location of crude oils and
sediments used in this study (Modified from [108] and references therein). Refer to Tables 2.1 and 2.3 for the identity of crude oils (P1-P22) and sediments (S1-S14) respectively.
20
The Permian rocks are generally preserved in the Potwar Basin but this section is missing
in the Kohat Basin [113] (Fig. 2.2). The Musa Khel Group from Triassic strata
represented by Mianwali, Tredian Formations contains limestone, dolomite, coarse- to
fine-grained sandstone and shale. The origin of Triassic sediments is mainly shallow
marine while freshwater sandstone was also reported in Tredian Formation [106].
The Jurassic and Triassic times of deposition are absent or very thin in Kohat
and Potwar Basin. The Jurassic Shinawri Formation consists of marine shales, with
occasional sandstones and thin bedded limestones and contains frequent fluctuations of
the shelf and terrigenous material which is decreased at the top. The depositional
environment of Datta Formation is versatile and represents nearshore, swamp, bay, mud
flat and delta front [107]. Upper Jurassic is represented by the interbedded shales and
thick limestone as much as 1400 m of middle and upper Jurassic Sulaiman limestone
group (Fig. 2.2). The Shinawari overlaying Samana Suk Formation contained thick
carbonates. During early Cretaceous times, the Indian plate entered into warmer latitudes,
marine shale and limestones were deposited over regional erosional surface on the
Sulaiman group. This erosional surface is present at the top of the Samana Suk Formation
and is overlain by sandstone and shales of lower Cretaceous Chichali Formation. The
Cretaceous sequence mainly contained shale and sandstone of Chichali and Lumshiwal
Formations with marl and limestone in some of the areas (Fig. 2.2). The shale layers of
Chichali Formation indicate reducing environments for sedimentation. The Lumshiwal
Formation composed of siltstone and shelly limestone represent marine environment
[107]. The Sembar and Goru Formations from Cretaceous strata are present in Kohat
Basin while are not deposited in the Potwar Basin (Fig. 2.2).
Paleocene-Eocene depositions represented by Makarwal Group (Fig. 2.2)
are composed of shallow marine foraminiferal limestone and grey fossiliferous shale
[106]. In early Paleocene, beginning with sedimentation of Hangu sandstone is coastal
setting with greater marine influence followed by Lockhart limestone depositions in
shallow water environments and that of Patala Formation in shallow marine to deltaic
environment [107]. Eocene Nammal and Panoba Formations show transitional contact
with Patala Formation which is deposited in shallow marine to lagoonal shales with
21
limestone. The overlaying Chorgali and Sakaser Formations consist of marine carbonates
and shale facies in the Potwar Basin area while evaporite facies consist of anhydrite,
gypsum with minor oil shales in the Kohat Basin. The Upper Eocene, Kohat Formation
comprised of shales with carbonate of the Oligocene Kirthar Formation. Oligocene was
deposited only in Kohat Basin and small area of northern Potwar while missing in most
of the Potwar Basin. The collision of Indian and Eurasian plates made regional uplift and
transport direction of south to north sediments on the Indian plate was reversed. A
carbonate platform was buildup as a result of large volumes of sediments shed by
Eurasian plate from Eocene through Miocene [108].
2.2 DESCRIPTION OF CRUDE OILS AND SEDIMENTS
A total of 23 crude oils and 14 sediments were analyzed, Tables 2.1 and 2.2
show geological and geochemical informations. The sediments mainly consist of well
cuttings obtained from Oil and Gas Development Corporation Limited, Pakistan
(OGDCL). Australian crude oils obtained from Carnarvon Basin were also studied in
order to compare the distribution of aromatic hydrocarbons with Pakistani oils and
sediments (Table 2.1). These crude oils from Carnarvon Basin have been reported
previously and indicate typical non-biodegraded mature hydrocarbon profile [114].
Following sections describe geological information of crude oils and sediments from
Pakistan.
2.2.1 Potwar Basin
Potwar Basin is one of the oldest area explored for petroleum in the world
while first commercial oil discovery was made in 1914 which was the first of South
Asian sub-Continent [106]. Since then Potwar is the main source of hydrocarbons and
about 25 wells of crude oils and condensates are explored in the Potwar Basin [115].
Petroleum reservoirs containing significant amount of hydrocarbons in range of medium
to high density oils (Table 2.1) have been found in the small area of the Potwar Basin and
causes of the vast diversity in physical characteristics of crude oils are unknown so for.
18 Crude oils of different API gravity from very light to heavy (16-48°) and reservoired
in various geological formations were selected from the basin (Table 2.1).
22
Table 2.1 Geological information of crude oils
Samples Reservoir No Name Depth (m) Age Formation
API Gravity(degree)
Potwar Basin P1 Adhi-5 2680 Cambrian Khewra 48.0 P2 Missakeswal-1 2187 Eocene Chorgali 36.2 P3 Missakeswal-3 2063 Cambrian Jutana 37.0 P4 Rajian-1 - Cambrian Jutana 22.2 P5 Rajian-3A 3645 Cambrian Jutana 22.7 P6 Kal-1 2773 Cambrian Khewra 26.6 P7 Kal-2 2694 Cambrian Khewra 24. 8 P8 Fimkassar-1 3063 Cambrian Khewra/Tobra 23.2 P9 Fimkassar-4 3318 Cambrian Khewra/Tobra 32.0 P10 Chaknaurang-1A 2687 Cambrian Khewra 18.4 P11 Minwal-1 2179 Eocene Chorgali 16.0 P12 Joyamir-4 2103 Eocene Chorgali/Sakaser 16.1 P13 Turkwal-1 3612 Eocene Chorgali/Sakaser - P14 Pindori-4 - Eocene Chorgali/Sakaser 41.0 P15 Dhurnal-1 4096 Eocene Chorgali/Sakaser 37.9 P16 Dhurnal-6 4174 Eocene Chorgali/Sakaser 38.5 P17 Toot-10A 4485 Jurrasic Datta 38.4 P18 Toot-12 4450 Jurrasic Datta 34.1
Kohat Basin P19 Chanda-1 4750 Jurassic Datta 33.4 P20 Chanda -2 4990 Triassic Kingriali 33.5 P21 Mela-1 4960 Jurassic Datta 37.9
Carnarvon Basin, Australia P22 Wanaea - - - - P23 Griffin - - - -
Note: Oil samples were collected from follwing oil companies of Pakistan. OGDCL, Islamabad, Pakistan POL, Pakistan OXY, Pakistan PPL, Islamabad
23
Table 2.2 Geological settings and Rock Eval data of sediments from well Mela-1a
No Depth range (m)
Lithology Age Geological Formation
TOC average
(%)
S1
(mg/g) S2
(mg/g) HI
(mg/g) Tmax
(°C)
S1 4290-95 Marl Paleocene Patala 1.0 4.75 3.01 295 427
S2 4310-15 Marl Paleocene Patala 0.7 3.19 2.29 347 431
S3 4345-70 Limestone, Shale Paleocene Patala 1.1 2.35 2.01 182 431
S4 4410-40 Limestone Paleocene Lockhart 1.0 0.49 0.45 55.5 442
S5 4510-12 Limestone Paleocene Lockhart 0.8 3.77 1.90 241 433
S6 4534-60 Limestone Paleocene Lockhart 0.8 1.00 0.75 71 431
S7 4650-52 Sandstone Paleocene Lockhart 0.3 - - - -
S8 4680-82 Sandstone Paleocene Hangu 0.4 - - - -
S9 4690-92 Shale, siltstone Paleocene Hangu 2.3 7.78 5.78 257 -
S10 4710-12 Shale, siltstone Cretaceous Lumshiwal 1.4 4.24 3.38 250 -
S11 4741-42 Shale Cretaceous Chichali 1.4 - - - -
S12 4834-50 Shale Jurassic Shinawri 0.4 - - - -
S13 4860-62 Shale, clayston Jurassic Shinawri 3.4 2.71 2.78 82 -
S14 4940-42 Claystone Jurassic Datta 0.6 0.61 0.33 55 -
a: OGDCL, Islamabad, Pakistan
24
The locations of crude oils are shown in Fig. 2.1 and marked on stratigraphic chart in
Fig. 2.2. The source origin of these crude oils is not fully correlated with any specific
source rock of the area. Few studies using geochemical properties from cuttings, outcrops
and core samples from different geological formations were undertaken and correlated
partially with Potwar crude oils [116-117].
The oldest producing reservoir in the Potwar Basin is Precambrian Salt Range
Formation. It consists of thick carbonates overlain by evaporates. Marine shales and
massive sandstones of lower Cambrian, Khewra Formation have reservoir potential.
Khewra Formation has produced Adhi-5, Chaknaurang-1A, Kal-1, Kal-2, Fimkassar-1
and Fimkassar-4 oils used in this study. The overlying Jutana Formation primarily
consists of sandy carbonates and nearshore sandstones has reservoired Rajian-1, Rajian-
3A and Missakeswal-3 oil fields. The Permian, Tobra Formation composed of glacial
tillites, siltstone, and shales, and Fimkassar oil field is produced Khewra/Tobra
Formation. The Jurassic Datta Formation has produced oils from Toot-10A and Toot-12
fields. Shallow marine carbonate strata of the Eocene Chorgali and Sakaser Formations
form an important hydrocarbon producing horizon in the northern Potwar Basin. Chorgali
and Sakaser Formation consist of medium-bedded limestones and fine crystalline
dolomites. Both Formations are oil and gas producing reservoirs, Dhurnal-1, Dhurnal-6,
joyamir-4, Turkwal-1, Pindori-1, Minwal-1 and Missakeswal-1 are producing from
Chorgali and Sakersar Formations.
2.2.2 Kohat Basin
Currently, the most active area for exploration in Upper Indus Basin is Kohat
Basin. In early nineties a number of wells were abandoned (e.g. Tolanj-1, Kahi-1 and
Sumari-1; for details see Paracha, [112]). But later on, discoveries of oil and gas (Chanda,
Mela, Makori and Manzalai) have increased the interest of exploration geoscientist in the
area. The details of crude oils used from the Kohat Basin are shown in Table 2.2. The
sandstones of Datta formation produced Chanda-1 and Mela-1 are mainly continental in
origin, with fine to coarse grained and very high porosity characteristics. While Kingriali
formation is predominantly composed of dolomites with minor limestone. The crude oils
25
show a similar range of API gravities (Table 2.2) and the source rock origin of Kohat
Basin oils and gas is not yet reported.
2.2.3 Geochemical Description of Sediments
Fourteen sediments cuttings were selected from the Mela-1 well of the Kohat
Basin. The location of well is marked in Fig. 2.1 and samples locations marked on the
stratigraphic section in Fig. 2.2. The geological information along with Rock-Eval data is
shown in Table 2.2. Patala Formation contains total organic carbon (TOC) in fair range
(0.7-1.1%), S1 & S2 show very good potential in terms of generated hydrocarbons and
poor for residual hydrocarbons. Tmax, 427-431 °C reveals that sediments are at the onset
of hydrocarbon generation, most likely both liquid and gaseous hydrocarbons as
supported by hydrogen index (HI) in the range of 182 to 347 mg/g TOC and suggest both
type II and type III as main components of OM. Lockhart Formation sediments contain
poor to fair amount of TOC, the genetic potential of the Formation is poor except one
sample (4510-12 m) where S1 shows good genetic potential. HI 241 mg/g TOC indicates
both oil and gas prone OM (Type-II/III kerogen). Anonymous reports showed recent
discoveries of oils and gas condensate in Hangu formation in the area (news). Hangu
Formation sample (6490-92 m) shows organic rich sediments (TOC: 2.3 %), S1 and S2
values (7.78 and 5.78 mg/g TOC) suggest very good potential in terms of both generated
and residual hydrocarbons. HI 257 mg/g TOC indicates OM derived from type II and
type-III kerogen. Lumshiwal Formation also contains good amount of TOC, S1 and S2
show fair and good potential in terms of generated and residual hydrocarbons. Chichali
Formation data is not available while Rock Eval data of single sample of Shinawari
Formation shows very good TOC with fair genetic and residual potential but low values
of HI (82 mg/g TOC) are consistent with type III/IV kerogen. Datta Formation shows
poor TOC and low values for both S1 and S2 also indicate very lean potential for
hydrocarbons which is further supported by low HI (55 mg/g TOC) and indicate type III
kerogen.
26
Thermal maturity of sediments
Tmax data for most of the sediments was not available therefore aliphatic
biomarkers parameters were used to assess thermal maturity of sediments from the Kohat
Basin. The parameters were calculated from branched/cyclic fractions of sediments
extracts and reported in Table 2.3. The C32 22S/(22S+22R) hopane ratio (0.41-0.44) show
immature range of thermal maturity for all sediments except single sample (4834-50 m)
which indicates marginal thermal maturity. The Ts/(Ts+Tm) ratios (0.42-0.67) are a
consistent with marginal range of maturity. The sterane thermal maturity parameters C29
ββ/(αα+ββ) and C29 20S/(20S+20R) ratios in the range of 0.58 to 0.61 and 0.43 to 0.48
respectively indicate a immature nature of OM for Patala Formation sediments. In case of
Lockhart Formation sediments, sterane maturity parameters show variation in thermal
maturity where C29 20S/(20S+20R) ratios (0.50-52) indicate mature range while C29
ββ/(αα+ββ) ratio (0.51-59) indicate marginal range of thermal maturity of these
sediments. The C32 22S/(22S+22R) ratios (0.42-0.50, Table 2.3) and C29 ββ/(αα+ββ)
ratios (0.52-0.58) of Hangu, Lumshiwal, Chichali and Shinawri Formations sediments
revealed immature thermal maturity while C29 20S/(20S+20R) ratio (0.42-53) indicate
immature to onset oil generation thermal maturity. The thermal maturity parameters from
steranes and hopanes (Table 2.3) indicate contrasting results where hopanes show
immature thermal maturity while steranes show marginal to mature thermal maturity of
Kohat Basin sediments.
27
Table 2.3 Aliphatic biomarker maturity parameters of Mela-1 well sediments
No Sample depth (m)
S/S+R C32-Hop.
Ts/ (Ts+Tm)
S/S+R C29-Ster
ββ/ββ+αα, C29-Ster.
S1 4290-95 0.42 0.50 0.43 0.58
S2 4310-15 0.42 0.67 0.48 0.61
S3 4345-70 0.43 0.42 0.43 0.61
S4 4410-40 0.42 0.58 0.52 0.59
S5 4510-12 0.41 0.60 0.50 0.51
S6 4534-60 0.44 0.56 0.52 0.55
S7 4650-52 0.43 0.62 0.52 0.56
S8 4680-82 0.42 0.61 0.42 0.58
S9 4690-92 0.43 0.44 0.53 0.54
S10 4710-12 0.44 0.46 0.49 0.52
S11 4741-42 0.43 0.49 0.49 0.52
S12 4834-50 0.50 0.59 0.42 0.55
S13 4860-62 0.44 0.49 0.52 0.55
S14 4940-42 0.43 0.45 0.44 0.45
28
Chapter - 3
EXPERIMENTAL
The experimental work excluding GC-MS analysis and stable carbon and
hydrogen isotope analysis reported in this thesis was performed at chemistry department,
UET, Lahore. The GC-MS analysis and stable carbon and hydrogen analysis was
performed in geochemistry and isotope labs in Australia. However, the work was
repeated in order to keep consistencies in the data.
3.1 MATERIALS AND REAGENTS
Solvents
n-Pentane, n-hexane, cyclohexane, methanol, dicholoromethane
(Mallinkckrocdt, USA) were used without further purifications. The purity of these
solvent were checked by evaporating 10 mL of each solvent to 500 µL followed by
analysis of the residue by gas chromatograph-mass spectrometer.
Drying and neutralizing agents
Anhydrous magnesium suphate (AR grade, Unilab) was pre-rinsed with
solvent before use as a drying agent. For use as a neutralizing agent, sodium bicarbonate
(AR grade, chemsupply) was dissolved in milli-Q water until saturated solution obtained.
Silica gel
Silica gel 60 (0.063-0.200 mm, Merck) for column chromatography was
activated at 160 °C for at least 24 hrs and pre-rinsed with solvent (n-pentane or n-hexane)
prior to use.
Molecular sieves
Molecular sieves Type 5A (Merck) were activated at 240 °C for at least 24 hrs
prior to every use.
29
Copper (precipitated)
Precipitated copper powder and/or turnings (5 g, DBH chemicals) were
activated by rinsing with 3M HCl (5 mL), and then sequential rinsing with milli-Q water
till neutral pH, methanol (5 mL), dichloromethane (5 mL) and n-hexane (5 mL),
respectively.
Hydrofluoric acid and hydrochloric acid
Hydrofluoric acid (50 % w/v, Merck) was used for digestion of molecular
sieves. Hydrochloric acid (specific gravity, 1.18, Merck) was used for activation of
copper turnings.
3.2 GEOCHEMICAL TECHNIQUES
3.2.1 Sample Preparation
Sediments
The samples (well cuttings) were washed with water and air dried prior to
grinding. The samples were ground to particle size of about 150 µm or less using a ring-
mill (Rocklabs).
Extraction of soluble organic matter (SOM) from sediments
The extraction of SOM was performed in a Soxhlet apparatus. Prior to each
run the apparatus, thimble, cotton wool, activated copper turnings and anti-bumping
granules were extracted with mixture of solvents (9:1 v/v dichloromethane : methanol)
for at least overnight. The grounded sediment was weighed into a thimble, covered by
cotton wool and extracted using mixture of dichloromethane and methanol (9:1, 200 mL).
Fresh solvent mixture was introduced as required. The extraction was allowed to proceed
for at least 72 hrs for each sample or until the solvent became colorless. The solvent was
removed by a rotary evaporator to obtain SOM.
30
3.2.2 Liquid Chromatography of Crude Oils and SOM
Preparation of SOM sample
The soluble organic matter (up to 70 mg) was dissolved in minimum amount
of dichloromethane. The activated silica (up to 1.5 gm) was taken in clean vial (10 mL).
The SOM solution was carefully adsorbed on activated silica. The dichloromethane was
evaporated by heating vial on sand bath at 50 °C. The dried silica adsorbed SOM was
fractionated using column chromatography.
Small scale column chromatography
In a typical small scale separation, the SOM adsorbed silica gel sample
(maximum up to 20 mg SOM)) or crude oil (10 mg) was applied on the top of the column
(5.5 × 0.5 cm i.d. pasture pipette) of activated silica gel (pre-rinsed with n-pentane). The
aliphatic hydrocarbons (saturates) were eluted with n-pentane (2 mL); the aromatics with
a mixture of n-pentane and dichloromethane (2 mL, 7:3, respectively); and polar fraction
with a mixture of dichloromethane and methanol (2 mL, 1:1).
Large scale column chromatography
Soluble organic matter (up to 70 mg, adsorbed on activated silica) and crude
oil (50 mg) were separated by large open column chromatography with following details:
A glass column (40 × 0.9 cm i.d.) with cotton wool at bottom was washed with
dichloromethane prior to use. Activated silica gel (10 g) was packed as slurry in n-
hexane. The SOM adsorbed silica or crude oil was introduced on the top of the packed
column. The aliphatic hydrocarbons (saturates) fraction was eluted with n-hexane (35
mL); the aromatic fraction with a mixture of n-hexane : dichloromethane (35 mL, 7:3,
respectively) and aromatic/polar (fraction-3) with dichloromethane and polar fraction
with methanol (35 mL). Each fraction was recovered by removal of solvent on a sand
bath by maintaining temperature up to maximum 60 °C.
31
3.2.3 Isolation of Branched and Cyclic Alkanes
A saturated fraction obtained by liquid chromatography separation was used to
isolate branched and cyclic alkanes from straight chain alkanes. The saturated fraction
(up to 15 mg) in cyclohexane (1-2 mL) was added in to a 2 mL autosampler vial quarter
filled (2 g) with activated 5A molecular sieves. The autosampler vial was capped and
placed into pre-heated aluminum block (85 °C) for at least 8 hrs. The resulting mixture
was filtered through a small column of silica (5.5 × 0.5 i.d.) and rinsed thoroughly with
cyclohexane. The cyclohexane containing branched/cyclic alkanes was collected in pre-
weighed vial. The removal of excess cyclohexane under a slow stream of nitrogen
yielded branched and cyclic fraction.
Recovery of straight chain alkanes from molecular sieves
The molecular sieve containing n-alkanes were air dried and transferred to a 20
mL Teflon tube. n-Pentane (2-3 mL) was added to cover the sieves along with 1 mL of
milli-Q water. The mixture was homogenized by stirring magnetically while placing on
an ice bath. Hydrofluoric acid (50 %, 20-30 drops) was added drop wise while stirring
until the sieve had dissolved (45-50 minutes). The excess HF was neutralized by adding
saturated solution of sodium bicarbonate while stirring. The n-alkanes from sieves were
dissolved in n-pentane and separated by passing through a small column of anhydrous
magnesium sulfate. The aqueous mixture was further extracted with pentane (approx, 3 ×
1 mL). Excess pentane was removed carefully using sand bath (60 °C).
Quantification of aromatic hydrocarbons
Deutrated phenanthrene (d10) was used as internal standard for quantification
of aromatic hydrocarbons. The internal standard was prepared by dissolving 4 mg of
deutrated phenanthrene in 100 mL of isooctane solution, so each microliter (µL) of
solution contained 40 ng of deutrated phenanthrene.
32
3.3 LABORATORY EXPERIMENTS
3.3.1 Reference Compounds and Glass Tubes Preparation
Reference compounds were purchased from commercial suppliers: biphenyl
(Acros Organics), 3-MBP (TCI chemicals), Fluorene, 1-methylfluorne (1-MF), 9-MF, 4-
MF, 1,7-DMF (Chron AS, Norway), elemental sulfur (Technical Grade, Asia Pacific
Suppliers), NaN3 (Sigma-Aldrich), nonyl amine, secondary amine (diisopropyl amine),
acetonitrile (Sigma-Aldrich), NH3 gas (unknown), tetramethylbenzene (TMB) (Sigma-
Aldrich) and activated carbon (Technical Grade, Asia Pacific Suppliers) were used in
laboratory simulation experiments. Active carbon was conditioned at 340 °C (minimum 2
hrs) before use. The coal used in heating experiments was from Collie in Western
Australia [118] from the Hebe seam. It was sieved to pass 90 mesh.
Glass tubes (15cm × 0.3cm i.d) were soaked in hydrochloric acid (1M) for at
least 12 hours. After that one end of tube was sealed on oxygen-methane flame. The glass
tubes were then deactivated by keeping them in dichlorodimethylsilane solution (Alltech,
5% solution in toluene) for more than 24 hours. After washing tubes subsequently with
methanol and acetone were ready for heating experiments.
3.3.2 Laboratory Heating Experiments
In a typical experiment 1 mg of the biphenyl or 3-methylbiphenyl reactant with
1 mg of heteroatomic and methylene (alkyl) species compound mentioned in Table 3.1
and 10 mg activated carbon (or coal) were flushed with N2, and sealed under vacuum
before heating in a thermostat at selected temperatures between 200 °C and 300 °C.
Heating time was 15-16 hrs for all experiments. The reaction products were extracted
with dicholormethan and chromatographed by passing the extract through a small-scale
silica column. Blank experiments without carbon (or coal) were carried out in parallel.
The reaction products were analyzed using gas chromatography-mass spectrometry (GC-
MS).
33
Table 3.1 Heating experiments details
Reactant
Precursor compound Species compound
Active carbon
/coal
Temp.a
(°C)
Biphenyl Elemental Sulfur Active carbon 300
Biphenyl Elemental Sulfur Coal 300
Biphenyl Acetonitrile Active carbon 300
Biphenyl NH3 gas Active carbon 300
Biphenyl Nonyl amine Active carbon 300
Biphenyl NaN3 Active carbon 300
Biphenyl NaN3 Coal 270
Biphenyl Air (source of O) Active carbon 300
Biphenyl Tetramethylbenzene
(TMB)
Active carbon 300
3-methylbiphneyl Air (Source of O) Active carbon 300
3-methylbiphneyl Elemental S Active carbon 300
3-methylbiphneyl Elemental S Active carbon 250
3-methylbiphneyl Elemental S Active carbon 225
3-methylbiphneyl Elemental S Active carbon 200
a: heating time was 15-16 hrs for all experiments
Note: Blank experiments were performed with out active carbon/coal
34
3.4 ANALYTICAL METHODS AND INSTRUMENTATION
3.4.1 Elemental Analysis of Sediments
Analysis was performed on Carlo Erba NA1500 elemental analyzer. Samples
were weighed into tin capsules and dropped into a combustion tube at 1000 °C through
which a constant stream of helium was maintained. Just prior to sample introduction the
helium stream was dosed with a precise volume of pure oxygen. The sample was
instantaneously burned followed by intense oxidation of the tin capsule at 1800 °C (flash
combustion). The resulting combustion gases are passed over catalysts to ensure
complete oxidation and absorption of halogens, sulfur and other interferences. Excess
oxygen was removed as the gases were swept through a reduction tube containing copper
at 650 °C. Any oxides of nitrogen were reduced to nitrogen. The gases were separated
on a chromatographic column into nitrogen (N), carbon dioxide (C) and water vapour (H)
and quantitatively measured by a thermal conductivity detector (TCD). The system
response was calibrated to known calibration standards.
For oxygen analyses samples were precisely weighed into silver capsules and
dropped at preset times into a combustion tube (at 1050 °C) through which a constant
stream of helium was maintained. The resulting pyrolysed gases were passed over
catalysed carbon to ensure complete conversion of oxygen in the sample to carbon
monoxide. The carbon monoxide was separated from other pyrolysis gases on a
chromatographic column and quantitatively measured by a thermal conductivity detector
(TCD). The system response was calibrated to known calibration standards.
For sulfur analyses samples were precisely weighed into tin capsules and
dropped into a combustion tube (at 1000 °C) through which a constant stream of helium
was maintained. Just prior to sample introduction the helium stream was dosed with a
precise volume of pure oxygen. The sample was instantaneously burned followed by
intense oxidation of the tin capsule at 1800 °C (flash combustion). The resulting
combustion gases were passed over catalysts to ensure complete oxidation. The gas
stream was then dried by means of a water scrubber. Excess oxygen was removed as the
35
gases are swept through a reduction tube containing copper at 650 °C. Finally the sulfur
dioxide was separated from other interfering gases on a chromatographic column and
quantitatively measured by a thermal conductivity detector (TCD). The system response
was calibrated to known calibration standards.
3.4.2 δ34S of Pyrite from Sediments
The total reduced sulfur from the sediment was obtained by a distillation method
described by Fossing and Jorgsensen [119]. Details of this method are outlined in
Jørgensen et al. [120] and Grice et al. [121]. 34S/32S ratios were measured by means of
combustion isotope-ratio mass spectrometry (C-irmMS) using a Thermo Finnigan Delta+
coupled to an elemental analyzer (Eurovectro) via a split interface (Thermo Finnigan
Conflo III). Measured isotope ratios were calibrated with in-house and international
reference materials and are reported in the δ-notation relative to the V-CDT (Vienna
Canon Diablo Troilite) standard.
3.4.3 Gas Chromatography-Mass Spectrometry (GC-MS)
Full scan mode for compound identification
GC-MS analysis was performed using a Hewlett-Packard (HP) 5973 Mass
Selective Detector (MSD) interfaced to a HP 6890 gas chromatograph (GC). A 60 m ×
0.25 mm ID capillary column coated with a 0.25 µm 5% phenyl 95% methyl
polysiloxane stationary phase (DB-5 MS, J & W scientific) was used for the analysis.
1µL of the saturated or aromatic fractions (1 mg/mL in n-hexane) was introduced into the
split/splitless injector using the HP 6890 auto-sampler. The injector was operated at 280
in pulsed splitless mode. Helium maintained at a constant flow rate of 1.1 mL/min was
used as carrier gas. The GC oven was programmed from 40 °C to 310 °C at 3 °C/min
with initial and final hold times of 1 and 30 minutes, respectively. The transfer line
between the GC and the MSD was held at 310 °C. The MS source and quadrupole
temperatures were at 230 °C and 106 °C, respectively. Data was acquired in full scan
36
mode from 50 to 550 amu, with the MS ionization energy 70 eV and the electron
multiplier voltage 1800 V.
Full scan mode for heating experiment extracts
GC-MS analyses were performed using an Agilent Technologies 6890 gas
chromatograph coupled to an Agilent Technologies 5973 mass spectrometer with similar
condition as above for heating experiments (section 3.3.2) extracts except following
difference. The GC oven was programmed from 40 °C for 1 minute then at 5 °C/min to
310 °C for 10 minutes. The MS mass range was 10-500 a.m.u. with a scan rate of ~3
scans/sec.
Selected ion monitoring (SIM) mode
Aliphatic and aromatic hydrocarbons were analyzed by GC-MS in selected ion
monitoring mode for better resolutions of compound classes. Similarly, to increase the
resolution between individual isomers of alkylnaphthalenes was obtained by running GC-
MS in SIM mode using WAX column (0.60 m × 0.25 mm × 0.25 µm, DB-WAXETR, J
& W scientific). In these analyses GC-MS conditions were kept same as described in full
scan mode except MSD was operated in SIM mode.
3.4.4 Gas Chromatography-Isotope Ratio Mass Spectrometry
Gas chromatography-isotope ratio mass spectrometry (GC-irMS) was
performed using micromass IsoPrime mass spectrometer interfaced to an agilent
technologies 6890N Gas Chromatograph for compound specific stable hydrogen isotopic
compositions (δD). GC was operated with column of same dimensions used for GC-MS
analysis above for δD. During the analysis of a mixture of organic reference compounds
(hexadecane and docosane), the GC oven was programmed from 50 °C to 310 °C at 3°
C/min with initial and final hold times of 1 and 10 minutes respectively.
δD values were calculated by integration of the m/z 2 and 3 ion currents of the
H2 peaks produced by pyrolysis of the GC separated hydrocarbons using chromium
powder (350-400 µm, IsoScience Australia Pvt. Ltd.) at 1050 °C. An interfering species,
H3+ ions are produced in the mass spectrometer ion source as a result of H2
+ ion and H2
37
molecule collisions [122]. The amount of H3+ formed depends on the partial pressure of
hydrogen, and the species interferes isobarically at m/z 3. Thus, contributions from H3+
produced in the ion source are corrected by performing m/z 3 measurements at two
different pressures of the H2 reference gas to determine the H3+ factor. An electrostatic
sector is used to separate HD+ from the leading edge of the large signal produced at m/z 4
by the constant flow of helium (carrier gas) into the mass spectrometer. δD values are
reported relative to that of H2 reference gas pulses produced by allowing hydrogen (UHP,
BOC Gases Australia Ltd.) of a known D/H values into the mass spectrometer. The D/H
content of the H2 reference gas was monitored daily via analysis of mixture of reference
compounds (see above). Average values of at least two analysis and standard deviations
are reported. An internal standard (Squalane) with a predetermined δD value of -167‰
was used to monitor accuracy and precision of δD measurements. Isotopic compositions
are given in the delta notation relative to Vienna Standard Mean Ocean Water
(VSMOW).
3.4.5 Elemental Analysis-Isotope Ratio Mass Spectrometry (Bulk Isotope Analysis)
Bulk isotope analyses were performed on a micromass IsoPrime isotope ratio
mass spectrometer interfaced to a EuroVector EuroEA3000 elemental analyzer. For bulk
δ13C analysis, the sample was accurately weighed (0.05-0.15 mg) into a small tin capsule
which was then folded and compressed carefully to remove any tracers of atmospheric
gases. The tin capsule containing sample was dropped into a combustion reactor at 1025
°C with help of autosampler. The sample and capsule melted in an atmosphere
temporarily enriched with oxygen, where the tin promoted flash combustion. The
combustion products, in a constant flow of helium, 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 (PoropakQ) at
ambient temperature. After removing of oxides of nitrogen, oxidation products are then
passed through a thermal conductivity detector (TCD) followed by the irMs. Isotopic
38
compositions are given in the delta notation relative to Vienna Peedee belemnite
(VPDB).
For bulk δD analysis, the sample was accurately weighed (0.05-0.15 mg) into a
small silver capsule which was then folded and dropped into a pyrolysis reactor
containing glassy carbon chips held at 1260 °C. The sample was pyrolyzed 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. δD values were calculated and
reported similar to as above for compound specific isotope analysis (CSIA).
____
39
Chapter - 4
IDENTIFICATION OF SATURATED AND AROMATIC HYDROCARBONS
4.1 SATURATED HYDROCARBONS
Saturated hydrocarbons were identified using relative retention times, mass
spectra and comparison with literature data [45, 123-125 and references therein].
4.1.1 n-Alkanes and Isoprenoids
20 40 60 80 100 120
d
c
b
ea
Pr.
25 Ph.
C 17
Relative retention time (min)
C
10C
n-
n-
n-
Fig. 4.1 Total ion chromatograms (TIC) of saturated hydrocarbon fraction shows
n-alkanes (n-C10 to n-C37) and isoprenoids in crude oil (Missakeswal-1); a: 2,6-
dimethylundecane (I, see appendix); b: 2,6,10-trimethylundecane (nor-farnesane,
II); c: 2,6,10-trimethyldodecane (farnesane, III); d: 2,6,10-trimethyltridecane
(IV); e: 2,6,10,-trimethylpentadecane (nor-Pristane, V); Pr: pristane, 2,6,10,14-
tetramethylpentadecane (VI); Ph: phytane, 2,6,10,14-tetramethylhexadecane
(VII). Refer to section 3.4.3 for GC-MS program.
40
4.1.2 Tricyclic and Tetracyclic Terpanes
19
20
21
22
23
24
2526
24*
2829 30
31
33
34
35 36 38 39
60 70 80 90 100
40 41
C 30
Relative retention time (min)
m/z:191
Fig. 4.2 Mass chromatogram (m/z: 191) illustrating tricyclic and tetracyclic terpanes in
Dhurnal-1 crude oils. Peak numbers 19-41 denote carbon number of tricyclic
terpane (VIII); C24*: C24 17,21-secohopane (TeT: tetracyclic terpane, IX); C30:
C30 17α(H)-hopane (Xb). Refer to section 3.4.3 for GC-MS program.
41
4.1.3 Pentacyclic Triterpanes
: 191
TsTm
29
29Ts
30D
29M
30
30M
S
R
31
32
34 3533
86 10492 98Relative retention time (min)
S
R SR S R S R
m/z
Fig. 4.3 Mass chromatograms (m/z: 191) showing the distribution of pentacyclic
triterpanes (hopanes, X-XV) in Adhi-5 crude oil. Identity of peaks refers to
Table 4.1. Refer to section 3.4.3 for GC-MS program.
42
Table 4.1 Identifications of pentacyclic triterpanes from Fig. 4.3.
Peak# Identification
Ts 18α(H)-22,29,30-trisnorneohopane, C27, XIII
Tm 17α(H)-22,29,30-trisnorhopane, C27, XII
29 17α(H),21β(H)-30-norhopane, C29 Xa
29Ts 18α(H)-30-norneohopane,C29Ts, XV
30D 17α(H)-diahopane,C30, XIV
29M 17β(H),21α(H)-30-norhopane; C29 (moretane), XIa
30 17α(H),21β(H)-Hopane, C30, Xb
30M 17β(H),21α(H)-Hopane, C30 (moretane), XIb
31S 22S 17α(H),21β(H)-homohopane,C31, Xc
31R 22R 17α(H),21β(H)-homohopane,C31, Xc
32S 22S 17α(H),21β(H)-bishomohopane,C32, Xd
32R 22R 17α(H),21β(H)-bishomohopane,C32, Xd
33S 22S 17α(H),21β(H)-trishomohopane,C33, Xe
33R 22R 17α(H),21β(H)-trishomohopane,C33, Xe
34S 22S 17α(H),21β(H)-tetrakishomohopane,C34, Xf
34R 22R 17α(H),21β(H)-tetrakishomohopane,C34, Xf
35S 22S 17α(H),18β(H)-pentakishomohopane,C35, Xg
35R 22R 17α(H),21β(H)-pentakishomohopane,C35, Xg
43
4.1.4 Steranes and Diasteranes
m/z
1
2 3
4
5
6
78
9
10
11
12
13
14
15
1617
80 84 88Relative retention time (min)
:217
Fig. 4.4 Mass chromatogram (m/z: 217) of Dhurnal-1 crude oil shows the profile of
steranes and diasteranes. Peak identity numbers refer to Table 4.2. See section
3.4.3 for GC-MS program.
Table 4.2 Identifications of steranes and diasteranes from Fig. 4.4. Peak # Identification
1 20S 13β,17α-diacholestane, C27, XVIIa
2 20R 13β,17α-diacholestane, C27, XVIIa
3 20S 24-methyl-13β,17α-diacholestane, C28, (24 (S+R)), XVIIb
4 20R 24-methyl-13β,17α-diacholestane, C28, (24 (S+R)), XVIIb
5 20S 5α, 14α,17α-cholestane, C27, XVIa
6 20S 24-ethyl-13β,17α-diacholestane, C29, XVIIc + 20R 5α,14β,17β-cholestane, C27, XVId
7 20S 5α,14β,17β-cholestane, C27, XVId
8 20R 5α,14α,17α-cholestane, C27, XVIa
9 20R 24-ethyl-13β,17α-diacholestane, C29, XVIIc
10 20S 24-methyl-5α,14α,17α-Cholestane, C28, XVIb
11 20R 24-methyl-5α,14β,17β-cholestane, C28, XVIe
12 20S 24-methyl-5α,14β,17β-cholestane, C28, XVIe
13 20R 24-methyl-5α,14α,17α-cholestane, C28, XVIb
14 20S 24-ethyl-5α 14α,17α-cholestane, C29, XVIc
15 20R 24-ethyl-5α,14β,17β-cholestane, C29, XVIf
16 20S 24-ethyl-5α,14β,17β-cholestane, C29, XVIf
17 20R 24-ethyl-5α,14α,17α-cholestane, C29, XVIc
44
4.1.5 Diamondiod Hydrocarbons
adamantane
1-methyladamantane
2-methyladamantane
diamantane 4-methyldiamantane
1-methyldiamantane3-methyldiamantane
136+135
188+187
21 23 25
40 42 44
Relative retention time (min)
m/z:
m/z:
Fig. 4.5 Adamantane (XVIII) and methyladamantanes are shown by sum of mass
chromatograms (m/z: 136+135) and diamantine (XIX) and
methyldiamantanes are shown by sum of mass chromatograms (mz/: 188+
187) from saturated fraction of representative oil sample (Adhi-5). See section
3.4.3 for GC-MS program.
45
4.2 POLYCYCLIC AROMATIC HYDROCARBONS Aromatic hydrocarbons were identified using relative retention times, mass
spectra and comparison with the literature data [6,30,49,126-133]. Methylfluorenes are
not reported in sedimentary OM as per my knowledge and they were identified using
relative retention times and comparison with mass spectra of available internal standards
i.e. 9-methylfluorene (9-MF), 1-MF, 4-MF and 1,7-dimethylfluorene (1,7-DMF).
46
4.2.1 Biphenyl and Alkylbiphenyls
m/z: 154+168
2,2' 2,6' 2-E
2,3'
2,5
2,4+2,4'
3,3'
2,33-E
3,5
3,4'
4,4'
3,4
m/z:
40 42 44 46 48
39 40 41 42 43 44 45
182
BP
2 DPM
3
4
Relative retention time (min)
(a)
(b)
Fig. 4.6 (a) Sum of mass chromatograms (m/z: 154+168) showing biphenyl (BP, XXII) and
methylbiphenyls and (b) mass chromatogram (m/z: 182) showing
dimethylbiphenyls in aromatic fraction of a representative oil (Adhi-5). DPM,
diphenylmethane; numbers on each peak refer to respective methyl and dimethyl
biphenyl isomer.
47
4.2.2 Naphthalene and Alkylnaphthalenes
30 32 34 36 38 40 42
43 45 47 49 51 53
N
2
1
2,6
2,7
1,3+1,71,6
1,4+2,3
1,51,2
1,3,7
1,3,6
1,4,6+1,3,5
2,3,6
1,2,7
1,6,7
1,2,6
1,2,4
1,2,5
1,2,3
1,3,5,7
1,3,6,7
1,2,4,6+1,2,4,7+1,4,6,7
1,2,5,72,3,6,7
1,2,6,7
1,2,3,7
1,2,3,6
1,2,5,6+1,2,3,5
m/z: 128+142+156
m/z: 170+184
Relative retention time (min)
(a)
(b)
Fig. 4.7 (a) Naphthalene (N, XXIII), methylnaphthalenes, dimethylnaphthalenes are
shown by sum of mass chromatograms (m/z: 128+142+156 respectively) and
(b) trimethylnaphthalenes, tetramethylnaphthalenes are shown by sum of mass
chromatograms (m/z: 170+184 respectively) in a representative oil (Adhi-5).
Numbers on each peak refer to position of methyl substituent.
48
4.2.3 Phenanthrene and Alkylphenanthrenes
55 57 59 61 63 65
m/z:178+192+206P
3
2
9
1
Relative retention time (min)
3-E
9,2+1-E+3,6 3,5+2,6
2,7
1,3+3,9+2,10+3,10
2,5+2,9+1,6
1,7
2,31,9+4,9+4,10
1,8 1,2
Fig. 4.8 Phenanthrene (XXIV), methylphenanthrenes, dimethylphenanthrenes shown by
sum of mass chromatograms (m/z: 178+192+206 respectively) from aromatic
fraction of Adhi-5. Numbers on each peak refer to respective alkyl
phenanthrene isomer.
49
4.2.4 Dibenzofuran and Alkyldibenzofurans
Fig. 4.9 Sum of mass chromatograms (m/z: 168+182) showing DBF (XXV) and
methyldibenzofurans in Kohat Basin sediment, depth: 4290 m. Numbers on
each peak refer to methyl dibenzofuran isomer.
45 46 47 48 49 50 51
DBF
4
3+2
1
m/z: 168+182
Relative retention time (min)
50
4.2.5 Carbazole and Alkylcarbazoles
56 57 58 59 60
60 61 62 63 64
m/z :167+181
C
m/z:195
1
3
24
1,8
1,3
1,6
1,7
1,4+4-E
1,5+3-E
2,6
2,7+1,2
2,42,5
Relative retention time (min)
(a)
(b)
Fig. 4.10 (a) sum of mass chromatogram (m/z: 167+181) showing carbazole (C, XXVI)
and methylcarbazoles and (b) mass chromatogram (m/z: 195) showing
dimethylcarbazoles from Kohat Basin sediment, depth: 4690 m. Numbers on
each peak refer to respective methyl and dimethyl carbazole isomer.
51
4.2.6 Dibenzothiophene and Alkyldibenzothiophenes
53 54 55 56 57 58
59 60 61 62 63 64
m/z: 184+198
DBT
4
3+21
m/z: 212
Relative retention time (min)
4-E
4,6
2,4
2,6
3,6
3,7
1,4+1,6+1,8
1,3
3,4
1,2+1,9
(a)
(b)
Fig. 4.11 (a) Sum of mass chromatograms (m/z: 184+198) sowing dibenzothiophene
(DBT, XXVII) and methyldibenzothiophenes and (b) mass chromatogram
(m/z: 212) showing dimethyldibenzothiophenes from Kohat Basin sediment,
depth, 4710 m. Numbers on each peak refer to respective methyl and dimethyl
dibenzothiophene isomer.
52
4.2.7 Fluorene and Alkylfluorenes
47 48 49 50 51 52 53
F
9
1
4
m/z: 166+180
Relative retention time (min)
32
Fig. 4.12 Sum of mass chromatograms (m/z: 166+180) showing fluorene (F, XXVIII)
and methylfluorenes in Kohat Basin sediment, Depth: 4290 m. Numbers on
each peak refer to respective methyl substituent.
53
4.2.8 Identification of Retene
Identification of Retene was confirmed by monitoring ions 219 and 234 to
avoid any interference from tetrmethylphenanthrenes (m/z: 234).
68 69 70 71
m/z: 219
234m/z:
Retene
Relative retention time (min)
Fig. 4.13 Mass chromatograms m/z: 219 and 234 showed Retene (XXI) in aromatic
fraction of Adhi-5 crude oil.
54
4.2.9 Compound Identification of Laboratory Heating Experiments
28 30 32 34 36 38
1
2
3
4
5
Relative retention time (min) Fig. 4.14 Total ion chromatogram of the extract of laboratory experiment at 300 °C of
reactants (biphenyl, activated carbon, NaN3, Air) for 16 hrs. Identification is
given in Table 4.3.
Table 4.3 identification compounds from Fig. 4.14.
Retention Indices *
Zenkevich et al., [132]#
Rostad and Pereira, [126]≠
Peak# Compound name
Lee Kovat
Identification
Kovat Lee Kovat 1 Biphenyl 235.64 1394.2 MS 1379 236.59 1384
2 ortho-Hydroxybiphenyl 257.96 1529.9 Kovat 1506 - -
3 Dibenzofuran 259.51 1539.8 MS - 259.75 1526
4 ortho-Aminobiphenyl 269.79 1605.2 Kovat and Lee - 271.5 1598
5 Carbazole 308.55 1866.3 MS - 309.22 1851
*:Column and temperature program: DB-5MS (60 m × 0.25 mm × 0.25 µm I.D.) 40 °C
(1min) @ 5 °C/min, 310 °C (10min)
MS: Mass spectra
#: HP-5 (30. m × 0.25 mm × 0.25 µm) 50 °C (3 min) 3 °C /min 280 °C (20 min)
≠: DB-5 (30. m × 0.25 mm × 0.25 µm) 50 °C (4 min) 6 °C /min 300 °C (20 min)
____
55
Chapter - 5
GEOCHEMISTRY OF POTWAR BASIN CRUDE OILS
ABSTRACT
Geochemical classification of eighteen crude oils from the Potwar Basin
(Upper Indus), Pakistan was carried out using carbon and hydrogen bulk isotope
abundance and distribution of saturated and aromatic hydrocarbons. Aliphatic biomarkers
were used as supporting tool to deduce the geochemical characteristics such as thermal
maturity, depositional environments, source OM and extent of biodegradation. PAHs
distributions in regard to these geochemical characteristics were reported and
comprehensive oil correlation of the Potwar Basin was established. GC-MS analysis and
bulk stable isotopic compositions of saturated and aromatic fractions reveal that at least
three different groups of crude oils are present in the Potwar Basin.
Group A contains terrestrial source of OM deposited in highly oxic/fluvio-
deltaic clastic depositional environment shown by high Pr/Ph, high diahopane/hopane,
high diasterane/sterane, low DBT/P ratios and higher relative abundance of C19 tricyclic
and C24 tetracyclic terpanes. Aliphatic biomarkers for rest of the oils indicate marine
origin however two ranges of values for parameters such as steranes/hopanes,
diasteranes/steranes, C23-tricyclic/C30 hopane, C24-tetracyclic/C30 hopane, tricyclics
/hopanes, C31/C30 hopane ratios differentiate them into two groups (B and C). Group B
oils are generated from clastic rich source rocks deposited in marine suboxic depositional
environment than group C oils which are generated from source rocks deposited in
marine oxic depositional environment. Group C oils show higher marine OM (algal
input) indicated by extended tricyclic terpanes (upto C41 or higher) and higher
steranes/hopanes ratios. Distribution of PAHs classified Potwar Basin oils into similar
three groups based on depositional environments and source OM variations. Abundant
biphenyls (BPs) and fluorenes (Fs) are observed in group A oils while group B oils
56
showed higher abundance of dibenzothiophenes (DBTs) and negligible presence of
dibenzofurans (DBFs) and Fs and group C oils showed equal abundance of DBTs and Fs.
This relative abundance of heterocyclic aromatic hydrocarbons in Potwar Basin oils
broadly indicate that the distribution of these compounds is controlled by depositional
environment of OM where sulfur compounds (i.e. DBTs) are higher in marine source oils
while oxygen compounds (DBFs) and Fs are higher in oxic/deltaic depositional
environment oils. Higher abundance of aromatic biomarkers the 1,2,5-
trimethylnaphthalene (1,2,5-TMN), 1-methylphenanthrene (1-MP) and 1,7-
dimethylphenanthrene (1,7-DMP) indicate major source of OM for group A oil is higher
plant supported by abundance of conifer plants biomarker retene. Variations in
distribution of triaromatic steroids (TAS) in Potwar Basin oils clearly indicate source
dependent of these compounds rather than thermal maturity. Higher abundance of C20
and C21 TAS and substantional difference in distribution of long chain TAS (C26, C27,
C28) between the groups indicate different source origin of these compounds. Group A
shows only C27 and C28 TAS while group B shows C25 to C28 TAS and absence of these
compounds in group C oils revealed that the sterol precursors for these compounds are
most probably different. Aliphatic and aromatic hydrocarbon maturation parameters
indicate higher (late oil generation) thermal maturity for all oils from the Potwar Basin.
The crude oils of group A and C are typically non-biodegraded mature crude oils whereas
some of the oils from group B showed minor biodegradation indicated by higher Pr/n-
C17, Ph/n-C18 and low API gravity.
5.1 INTRODUCTION
The Potwar Basin has shown a number of small and medium size oil and gas
discoveries and still active for further explorations. Both heavy and light oils have been
discovered in the basin, heavy oils are genetically related to light oils, and bear a close
spatial relationship [134]. The properties and composition of these petroleum systems are
controlled by complex geological, physicochemical and biological processes during
generation as well as accumulation in reservoirs. Biomarker analysis of selected
sediments and crude oils has been performed and source to oil correlation has been
57
reported in a study [116]. However, organic geochemical data particularly PAHs and
isotopic compositions from potential source rocks in the Potwar Basin have never been
reported, nor has detailed an oil-oil correlation ever been undertaken up to my
knowledge. However rock-eval pyrolysis of some Precambrian source rocks has reported
and partially correlated with Potwar Basin crude oils [117].
The application of biomarkers and stable isotope analysis has been recognized
as powerful tool in exploration petroleum geochemistry. Biomarkers (on structural
grounds) in bituminous OM can provide valuable information on: i) the source of their
natural product precursors (i.e. Eukaryotes,, Prokaryotes and Archeae) ii)
paleoenvironmental depositional conditions - marine, lacustrine, hypersaline or fluvio-
deltaic iii) lithology of potential petroleum source rocks (carbonate vs. shale) (iv) relative
thermal maturity of potential source rocks and v) extent of biodegradation of petroleum
hydrocarbons. However, many of the above factors are often interrelated and have been
considered collectively for correlation studies [135]. The variation in biomarkers
abundances has been used successfully for oil correlation studies between source rocks
and/or other oils [e.g. 136-139].
Aromatic structures are almost absent in biological OM, however their
ubiquitous occurrence in sedimentary OM suggests that the compounds are the product of
sedimentary reactions [4]. The distribution and relative abundance of these compounds
have been used as source, depositional environment and thermal maturity indicators of
source rocks and petroleum [5-6,11,25,38,140-141]. Alexander et al. [5] suggested
aromatic biomarker, retene (XXI) as indicator of terrestrial OM and related it to
araucariaceae family of conifers and later on source of retene was specified to the conifer
resin [135]. The potential application of aromatic hydrocarbons has been recognized as
thermal maturity indicator of source rocks and crude oils [25-26,10-11,38]. Thermal
maturity parameters derived by comparing concentrations of thermodynamically least
stable isomers (α) to the thermodynamically most stable isomers (β). The principal
behind is that the methyl group shifts from α- to β- position with increase in thermal
maturity [26]. The alkylnaphthalenes maturity parameters have been described by van
Aarssen et al. [38]. In alkylphenanthrenes, methylphenanthrenes ratio (MPR) are derived
58
by dividing α-isomer (1-MP) to the β-isomer (2-MP). Methylphenanthrene index 1(MPI-
1) is the most significant molecular maturity parameter from aromatic hydrocarbons
which is successfully calibrated with mean vitrinite reflectance (Rm) for source rocks and
crude oils [4]. The calculated vitrinite reflectance (Rc) from MPI-1 differentiates crude
oils thermal maturity into immature (0.70), mature (0.85) and postmature (0.95). Among
aromatic sulfur hydrocarbons, methyldibenzothiophene ratio (MDR; 4-/1-MDBT) are
sensitive to maturity changes which shows good correlation with vitrinite reflectance in
range of 0.52 to 1.32% [11]. However MDR showed different thermal maturity trends in
early maturation stages [11], moreover MDR showed variation relevant to the expulsion
stage of aromatic sulfur hydrocarbons from type II/III kerogens [40].
Stable isotopes of carbon and hydrogen are the most useful tracers in crude oils
and sediments because they are the most abundant elements in any shape of sedimentary
OM. Variations in stable isotopic compositions or “isotope fractionation” occur in nature
due to different physical and chemical processes. Bulk isotope analysis represents the
measurement of stable isotopes of total carbon and hydrogen in the samples which
indicate the average values of all complex compounds. The entire sample such as whole
oil, saturated fraction or aromatic fraction of crude oils and sediment extracts are being
under use for bulk isotope determinations. The bulk isotope compositions of saturated
and aromatic fractions from crude oils has been applied to represent the source OM input
in hundred of oils in the world [142-144] while compound specific isotope analysis is
used as a powerful tool in the oil correlation studies [145-146].
In this chapter organic geochemical parameters based on PAHs and stable
carbon and hydrogen isotopes of saturated and aromatic fractions supporting with
aliphatic biomarkers have been used to investigate the source OM of the Potwar Basin
crude oils. A selection of saturated and aromatic biomarker parameters has been
determined for oils and source-rocks to establish thermal maturity of OM, depositional
paleoenvironmental information, lithology and extent of biodegradation of hydrocarbons.
Results were successfully applied to delineate the oils groupings of the Potwar Basin.
59
5.2 RESULTS AND DISCUSSION
5.2.1 Normal Alkanes and Isoprenoids Distribution
The crude oils analyzed in this study are listed in Table 5.1. The total ion
chromatogram (TIC) of the saturated fraction of a representative oil sample is shown in
Fig. 4.1 (Chapter 4). n-Alkanes from n-C10 to n-C37 are present in Adhi-5 with no odd or
even preference of n-alkanes as measured by CPI and OEP (Table 5.1). Low molecular
weight hydrocarbons (<n-C10) were not observed, probably because of evaporative loss
during sample processing. Ratios of isoprenoids to n-alkanes are very low (0.4 and 0.2
for Pr/n-C17 and Ph/n-C18 respectively) but Pr/Ph ratio is highest (3.2). Compared to
Adhi-5, a group of oils (P2-P14, Table 5.1) display different characteristics i.e. Pr/Ph
ratio 1-2 and less abundance of low molecular weight n-alkanes. Their isoprenoids to n-
alkanes ratios are higher, CPI and OEP of some samples are <1 suggesting even
preference for C22-C30 n-alkanes. The P15-P18 oils contained full suit of n-alkanes, low
values of Pr/n-C17 and Ph/n-C18 (0.6-0.9 and 0.4-0.7 respectively, Table 5.1).
This data in combination with API gravity (Table 2.1, chapter 2) broadly
classify the samples into three groups. Group A comprising a single oil Adhi-5, of
typically mature, non-biodegraded light oil (API: 48°), generated from highly oxic
depositional conditions. Group B (P2-P14) of medium to heavy (API: 16-41°) oils. The
source rocks generating Group B oils appear to have deposited under sub-oxic
depositional conditions. The Group B samples show low maturity likely to be affected by
biodegradation. Group C, consists of P15-P18 oils, shows characteristics of narrow range
medium gravity (API: 34-38°), mature, non-biodegraded petroleum.
5.2.2 Carbon and Hydrogen Isotopic Compositions
The isotopic composition of crude oil is mainly dependent on the δ13C and δD
value of the kerogen which in turn, depends on the biological OM and the depositional
environment [143,147-148]. Biodegradation and thermal maturity have little effect on the
stable carbon isotopic composition of the whole oil [149]. Since isotopic compositions of
oils change with type of OM, therefore bulk δ13C of saturated and aromatic fractions of
60
Table 5.1 n-Alkanes, isoprenoid ratios and bulk isotope data
No Oil and well Pr/Ph Pr/n-C17
Ph/n-C18
CPI OEP δ13Csats (‰)
δ13Caros (‰)
δDsats (‰)
δDaros (‰)
δ13Caver (‰)
δDaver(‰) Group
P1 Adhi-5 3.2 0.4 0.2 1.0 1.0 -26.4 -24.5 -117 -111 -25.4 -114 A P2 Missakeswal-1 1.5 1.0 0.7 0.9 1.0 -23.1 -20.8 -155 -130 -21.9 -142 B P3 Missakeswal-3 2.0 1.0 0.5 1.0 1.0 - - - - - - B P4 Rajian-1 1.2 1.3 0.9 1.0 1.0 - - - - - - B P5 Rajian-3A 1.3 1.3 0.9 1.0 1.0 -22.4 -21.0 -132 -125 -21.7 -128 B P6 Kal-1 1.3 1.4 0.9 1.0 1.0 - - - - - - B P7 Kal-2 1.5 1.2 0.8 1.0 0.9 -23.0 -21.1 -149 -135 -22.0 -142 B P8 Fimkassar-1 1.3 1.1 0.8 1.0 0.9 - - - - - - B P9 Fimkassar-4 1.4 0.8 0.6 1.0 1.0 -22.9 -22.2 -126 -132 -22.5 -129 B P10 Chaknaurang-1A 1.2 1.3 0.9 0.9 0.9 -22.6 -21.9 -132 -141 -22.2 -137 B P11 Minwal-1 1.0 1.3 1.0 0.9 0.9 -23.0 -21.1 -136 -136 -22.1 -136 B P12 Joyamir-4 1.0 1.3 1.0 0.9 0.8 -22.3 -21.1 -130 -134 -21.7 -132 B P13 Turkwal-1 1.2 1.1 0.8 1.0 0.9 -22.3 -21.0 -145 -129 -21.6 -137 B P14 Pindori-4 1.5 0.8 0.5 1.0 1.0 -23.1 -20.5 -145 -139 -21.8 -142 B P15 Dhurnal-1 1.4 0.9 0.7 1.0 1.0 -25.0 -22.0 -148 -139 -23.5 -144 C P16 Dhurnal-6 1.4 0.9 0.7 1.0 1.0 -25.1 -22.1 - - -23.6 - C P17 Toot-10A 1.6 0.6 0.4 1.0 1.0 -26.1 -21.5 -129 -122 -23.8 -126 C P18 Toot-12 1.6 0.8 0.6 1.0 1.0 -26.1 -21.4 - - -23.7 - C
CPI: 2(C23 + C25 + C27 + C29)/[(C22 + 2(C24 + C26 + C28) + C30]; OEP: (C21 + 6×C23 + C25)/(4×C22 + 4×C24) δ13C (‰) with respect to VPDB reported with in standard deviation of 0.2‰. δD (‰) with respect of VSMOW with in standard deviation of 3. -: not determined δ13Caver: (δ13Csats+ δ13Caros)/2 δDaver: (δDsats +δDaros)/2
61
oils are useful along with biomarker parameters in distinguishing crude oils from
different source and depositional settings [143-148].
Crude oils listed in Table 5.1 were examined for bulk stable carbon and
hydrogen isotopic compositions. Cross plots δ13C of saturated and aromatic fractions
were used to clearly delineate different groups of petroleum in the Potwar Basin (Fig.
5.1a, Table 5.1). The crude oils P2-P14 showed higher values of δ13C (isotopically
heaviest) and cluster together on right hand side of the plot (Fig. 5.1a, group B). More
negative (isotopically lighter) δ13C values (-25 to -26.1‰) are observed from the Dhurnal
and Toot well samples (Fig. 5.1a, group C, P15-P18). Among the sample suite of oils
analysed, Adhi-5 was isotopically lightest (more negative) in δ13C of both saturated and
aromatic fractions. It was designated as group A (Fig. 5.1a, Table 5.1, P1). The isotopic
composition of crude oils with in each group is most probably controlled by both source
and depositional settings as indicated by n-alkanes and isoprenoid distributions and
saturated and aromatic hydrocarbons distributions (following sections). Group B oils
showed enrichment in δ13Csats having values up to 3-4‰ compared to group C (Fig. 5.1a;
Table 5.1). The difference observed between δ13C of the saturated hydrocarbon fractions
between the groups indicates the difference in source organisms. Another plot represents
the difference between δ13C and δD average values of both saturated and aromatic
fractions of crude oils (Table 5.1) and same results were achieved (Fig. 5.1b). The crude
oils were separated into similar three groups hence provided an additional evidence for
the existence of at least three groups of petroleum in the Potwar Basin. The difference in
stable carbon and hydrogen isotopic compositions of saturated and aromatic fractions is
consistent with source variations.
62
-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. 5.1 The plots (a) δ13Csats vs δ13Caros (b) δ13Caver vs δDaver to delineate groupings of
petroleum in the Potwar Basin.
63
5.2.3 Polycyclic Aromatic Hydrocarbons (PAHs)
Distributions of PAHs were evaluated from GC-MS analysis of aromatic fractions.
Representative TICs of aromatic fractions from each group of the Potwar oils are shown in Fig.
5.2. The PAHs profiles of oils generally show variations in relative abundance between different
classes of aromatic hydrocarbons where diaromatic (two rings) and triaromatic (three rings) are
the predominant components in each representative oil chromatogram (Fig. 5.2). Group A
chromatogram shows higher abundance of diaromatic than triaromatic hydrocarbons where BPs
are the most abundant compounds from the all diaromatic hydrocarbons. Similarly Fs are
comparatively abundant than phenanthrenes in the triaromatic hydrocarbons of the same oil.
Significant abundance of BPs and Fs from naphthalenes and phenanthrenes separated group A
oil from other groups of oils (Fig. 5.2a). Similarly naphthalenes and phenanthrenes are the
predominant aromatic components in group B representative chromatogram (Fig. 5.2b).
However significant presence of triaromatic steroids (TAS) and DBTs differentiates group B
from group A and C where later groups showed less or absence of TAS and comparatively low
abundance of DBTs (Figs. 5.2b and 5.2c). Again, naphthalenes and phenanthrenes are present in
higher abundance in group C oil however naphthalenes showed a double order of the abundance
than phenanthrenes (Fig. 5.2c) and low abundance of TAS, DBTs, Fs, and BPs in representative
chromatogram of group C oil differentiates this group from other groups. Distribution of PAHs
indicate that at least three types of crude oils are present in Potwar Basin.
Generally aromatic hydrocarbons are not diagnostic compounds for the evaluation of
source OM characteristics of mature crude oils and sediments. However variations in relative
distribution of aromatic hydrocarbons indicate a difference in source and depositional
environment of OM. Following sections explained the distribution of each class of above
described aromatic compounds in Potwar Basin oils and they were used for evaluation of thermal
maturity and source of OM, lithology and depositional environment in combination with
commonly used aliphatic biomarkers.
64
Fig. 5.2 TICs showing distributions of aromatic hydrocarbons in representative samples from the Potwar Basin; N, naphthalene; MN, methylnaphthalenes; DMN, dimethylnaphthalenes; TMN, trimethylnaphthalenes; TeMN, tetramethylnaphthalenes; BP, biphenyl; MBP, methylbiphenyl; DMBP, dimethylbiphenyl; P, phenanthrene; MP, methylphenanthrenes; DMP, dimethylphenanthrenes; TMP trimethylphenanthrenes; MDBT, methyldibenzothiophenes; DMDBT, dimethyldibenzothiophenes; MF, methylfluorenes; DMF, dimethylfluorenes; TAS, triaromatic steroids
Rel
ativ
e in
tens
ity
40 50 60 70 80 90 10030Relative retention times (min)
N
MNBP
MBP
TMN
DMN
DMBP
PMP
DMP
MN
TMN
DMN
P
MP
DMPTMP
TeMN
MF
DMF
TAS TeMN
MDBTDMDBT
Group-Aa) Adhi-5
Group-Bb) Kal-2
Group-Cc) Toot-12
MN
DMN
P
MP DMP
TeMNTMP
TMN
N
65
5.2.4 Thermal Maturity of Potwar Basin Oils
A combination of saturated and aromatic hydrocarbons parameters were used to
determine the thermal maturity of the Potwar Basin oils. The data listed in Table 5.2 was
obtained from GC-MS analysis of branched/cyclic and aromatic hydrocarbon fractions. The
hopane based parameters were calculated from peak areas of 191 Dalton mass chromatograms.
The proportion of 22S relative to (22S + 22R) for C32 homohopanes (Xd) is a maturity parameter
for immature to early oil window. During maturation the ratio 22S/(22S + 22R) shows distinct
change from 0 to 0.6 whereas equilibrium lies between 0.57 and 0.62 [150]. For C32 homologue
22S/(22S+22R) ratio varies between 0.57 and 0.64 suggesting high maturity for all the oils
samples analysed in this study from the Potwar Basin (Table 5.2). These ratios reach equilibrium
in the early oil window so have limited application for studying the relative maturities of crude
oils and condensates. The other hopane based maturity parameter is the ratio of 17α(H),21β(H)-
hopane to 17β(H),21α(H)-hopanes [αβ/(αβ+βα)] for C29- and C30- compounds, which equilibrate
at somewhat higher thermal maturities [45,151]. The observed values for the parameter are in the
range of 0.81 to 1.0 (Table 5.2, mostly > 0.9) which are typical of oils generated from mature
source rocks [152]. The plot of hopane maturity parameter between C29- and C30- αβ/(αβ+βα) is
shown in Fig. 5.3a [152], most of the oil samples fall within an equilibrium and higher range of
thermal maturity except Adhi-5 which show low thermal maturity. The slight difference in
αβ/(αβ+βα) ratios with in the Potwar Basin shows the affects of source and depositional
environment variations on these values, which are known to have effects on these ratios [153-
154]. The Ts/(Ts+Tm) ratios show a wide range from 0.31 to 0.73; however narrow range of this
ratio is observed within individual groups. For example, group B shows Ts/(Ts+Tm) ratio in the
range of 0.31 to 0.45 while group C shows exceeding values of 0.67 to 0.70. Group A
representing a single oil Adhi-5 shows intermediate value (0.53). Pindori-4 (P14, Table 5.2)
shows maximum value of 0.73 which is different from other oils of group B. Three different
ranges of Ts/(Ts+Tm) indicates that this ratio is controlled by the source organic facies and
depositional environment, which are the factors known to have a control on this ratio [155].
66
Table 5.2 Thermal maturity parameters calculated from aliphatic and aromatic hydrocarbons
Ts/(Ts + Tm): 18α(H)-22,29,30-trisnorneohopane/(18α(H)-22,29,30-trisnorneohopane + 17α(H)-22,29,30-trisnorhopane); αβ/(αβ + βα), C29 hop: 17α(H),21β(H)-30-norhopane/(17α(H),21β(H)-30-norhopane + 17β(H),21α(H)-30-norhopane); αβ/(αβ + βα), C30 hop: 17α(H),21β(H)-hopane/(17α(H),21β(H)-hopane + 17β(H),21α(H)-hopane); S/(S+R), C32 hop: 22S/(22S+22R), 17α(H)-bishomohopane; (ββ/αα+ββ) C29-Ster: 14β(H),21β(H)/[14α(H),21α(H) + 14β(H),21β(H)] 20R-ethylcholestane; S/(S+R) C29 ster: 20S/(20S+20R) 14α(H),21α(H)-ethylcholestane; MAI: methyl adamantane index (1-MA/1-MA + 2-MA), [162]; MDI: methyl diamantane index (4-MD/1-MD + 3-MD + 4-MD), [162]; DNR-1: dimethylnaphthalene ratio 1 (2,6- + 2,7-DMN/1,5-DMN), [26]; TNR-1: trimethylnaphthalene ratio 1 (2,3,6-TMN/1,4,6- + 1,3,5-TMN), [10]; TNR-2: trimethylnaphthalene ratio 2 (2,3,6- + 1,3,7-TMN)/1,4,6- + 1,3,5- + 1,3,6-TMN); Rcb: 0.40+0.6×(TNR-2), [11]; MPI-1: methylphenanthrenes index {1.5 × [3-MP + 2-MP]/[P + 1-MP + 9-MP]}, [25]; Rc: calculated vitrinite reflectance (0.6 × MPI-1 + 0.4), [156]; MDR: 4-MDBT/1-MDBT, [11]; Rcs: 0.073×MDR + 0.51; [4]; MDR′: 4-MDBT/(4-MDBT + 1-MDBT), [40]; -: not determined
No Oil and Well Ts/ (Ts+Tm)
αβ /(αβ+βα), C29-Hop
αβ /(αβ+βα), C30-Hop
(S/S+R) C32-Hop
(ββ/ αα+ββ)
C29-Ster
(S/S+R) C29-ster MAI MDI DNR-
1 TNR-
1 TNR-
2 Rcb (%)
MPI-1
Rc (%) MDR Rcs
(%) MDR′
P1 Adhi-5 0.53 0.83 0.81 0.62 0.59 0.41 0.59 0.46 6.8 1.04 0.94 1.02 0.75 0.85 6.4 0.98 0.87 P2 Missakeswal-
1 0.40 0.93 0.86 0.61 0.66 0.43 0.63 0.47 7.6 1.43 1.04 1.02 1.07 1.04 8.6 1.13 0.90
P3 Missakeswal-3 0.36 0.92 0.86 0.62 0.65 0.41 - - 7.2 1.38 1.02 0.99 1.02 1.01 7.8 1.08 0.89
P4 Rajian-1 0.36 0.94 0.87 0.60 0.64 0.44 - - 6.3 1.61 1.03 1.03 0.80 0.88 5.5 0.91 0.85 P5 Rajian-3A 0.37 0.93 0.88 0.58 0.63 0.45 0.62 0.52 5.7 1.44 0.98 1.00 0.90 0.94 5.6 0.92 0.85 P6 Kal-1 0.38 0.93 0.90 0.56 0.61 0.45 - - 6.2 1.64 1.05 0.96 0.85 0.91 5.9 0.94 0.85 P7 Kal-2 0.41 0.94 0.87 0.57 0.63 0.45 0.62 0.50 7.8 1.50 1.00 1.08 0.92 0.95 6.5 0.99 0.87 P8 Fimkassar-1 0.40 0.93 0.88 0.59 0.61 0.47 0.64 0.53 8.1 1.85 1.12 1.15 1.04 1.03 6.4 0.98 0.86 P9 Fimkassar-4 0.45 0.92 0.88 0.61 0.64 0.47 - - 8.0 1.61 1.12 1.11 0.89 0.93 6.8 1.01 0.87 P10 Chaknaurang-
1A 0.35 0.96 0.89 0.57 0.59 0.48 0.64 0.53 8.4 1.96 1.14 0.97 0.91 0.94 4.7 0.85 0.82
P11 Minwal-1 0.31 0.94 0.90 0.59 0.59 0.46 0.62 0.50 5.7 2.31 1.24 1.07 0.85 0.91 4.5 0.84 0.82 P12 Joyamir-4 0.38 0.93 0.85 0.60 0.62 0.45 0.64 0.53 6.9 2.17 1.18 1.07 0.90 0.94 4.4 0.83 0.81 P13 Turkwal-1 0.45 0.97 0.92 0.60 0.63 0.45 0.59 0.48 5.5 1.39 0.95 0.95 1.26 1.16 8.2 1.11 0.89 P14 Pindori-4 0.73 1.00 1.00 0.64 0.63 0.47 0.65 0.48 6.8 1.25 0.95 0.97 1.14 1.08 11.6 1.36 0.92 P15 Dhurnal-1 0.67 1.00 1.00 0.63 0.61 0.45 0.62 0.47 7.7 1.29 0.91 1.01 1.16 1.10 11.5 1.35 0.91 P16 Dhurnal-6 0.66 1.00 1.00 0.63 0.61 0.43 - - 7.1 1.23 0.96 0.98 1.14 1.08 10.7 1.29 0.92 P17 Toot-10A 0.70 1.00 0.92 0.61 0.63 0.44 - - 7.4 1.39 1.00 1.00 1.07 1.04 9.2 1.18 0.90 P18 Toot-12 0.70 0.90 0.92 0.61 0.62 0.47 0.61 0.50 8.5 1.23 0.94 0.96 1.09 1.05 8.5 1.13 0.89
67
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/(αβ+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
R cb (% )
Rc (
%)
Late
Peak
Early
(b)
Fig. 5.3 (a) Hopanes maturity parameters plot between C29 vs C30 of αβ/(αβ+βα) (c.f.
[152]) (b) calculated vitrinite reflectance diagram from Rcb (TNR-2; [11])
and Rc (MPI-1; [156]) show different thermal maturation stages of oil
generation window.
68
The sterane based maturity parameters, 20S/(20S+20R) ethylcholestane and
ββ/(αα+ββ) ethylcholestane, lie with in a close range of 0.41 to 0.48 and 0.59 to 0.66
respectively (Table 5.2) whereas the equilibrium for these parameters occurs between
0.52 to 0.55 and 0.67 to 0.71 respectively [150]. The observed values are lower than
equilibrium values supporting a similar moderate maturity of analysed samples [150].
Despite the fact that 20S/(20S+20R) ratio is a useful maturity parameter, factors other
than thermal maturities which are likely to affect this ratio are reversal of this ratio within
high maturity interval [157-158], could be responsible for lower values. Moreover,
ββ/(αα+ββ) ratio is also influenced by source rock mineral matrix and migration, where
equilibrium for carbonate source oils is reached at comparatively lower values [159] and
more migrated oils show higher values of this ratio [160]. However in this study it is
suggested that the highest values of 20S/(20S+20R) and ββ/(αα+ββ) to reach equilibrium
for the Potwar basin oils is 0.48 and 0.66 respectively.
Few limitations have been put forward to thermal maturity parameters
described above; for example, sterane and hopane isomerization i.e. S/(S + R) parameters
reach effective end-points or equilibrium before the main part of oil window, therefore
not very effective for mature oils and condensates [161]. In this scenario parameters
based on diamondoid and aromatic hydrocarbons are more effective for better evaluation
of thermal maturity of mature oils and condensates. Chen et al. [162] suggested methyl
adamantane index (MAI) and methyl diamantane index (MDI) as maturity indicators for
crude oils and condensates from Chinese basins. The MAI and MDI values were
calculated using m/z 136, 137 and m/z 188, 187, respectively from saturated fractions and
are listed in Table 5.2. The MAI (0.59-0.65) and MDI (0.46-0.53) values clearly indicate
the same range of thermal maturities for these crude oils. The calibration of MAI and
MDI with vitrinite reflectance (Ro) reported by Chen et al. [162] for Chinese crude oils
and condensates show that MAI > 0.5 and MDI > 0.4 is equivalent to Ro > 1.1 and Ro >
1.3, respectively. The thermal maturity of Potwar Basin oils is based on equivalent
vitrinite reflectance shows the post oil generation window.
69
The commonly used thermal maturity parameter from aromatic hydrocarbons
is methylphenanthrene index 1 (MPI-1) and appears to be as useful as vitrinite reflectance
for maturity assessment [4,25]. The MPI-1 and calculated vitrinite reflectance (Rc) values
of the samples are listed in Table 5.2. The MPI-1 and Rc is in the range of 0.75 to 1.26
and 0.85 to 1.15 respectively show higher maturity of source rocks generating these oils.
The Rc for Adhi-5 (0.85, Table 5.2) showed mature status of thermal maturity while all
other values (>0.9) indicate postmature level of thermal maturity for Potwar Basin oils
[4]. Dimethylnaphthalene ratio (DNR-1, see Table 5.2 for definition) is another useful
aromatic hydrocarbon maturity parameter for samples having mean vitrinite reflectance
(Ro) equal or higher than 1% where it shows linear increase in value from 2 to 12 with
increase in thermal maturity [4,163]. The DNR-1 > 5.5 (Table 5.2, mostly ~7-8) clearly
revealed that thermal maturity of the Potwar Basin oils is reached late oil generation
window. Trimethylnaphthalene ratio 1 (TNR-1, see Table 5.2 for definition) has been
calibrated with sterane isomerization ratio (20S/20R) where sterane isomerization ratio of
oils reached to equilibrium value when TNR-1 ratio became >1 [10]. TNR-1 values for
Potwar Basin oils are shown in Table 5.2 that show >1 (mostly >1.2) for all samples
indicate maturity of source rocks generating these oils reached to postmature level [10].
Similarly, trimethylnaphthalene ratio 2 (TNR-2, see Table 5.2 for definition) is another
useful aromatic hydrocarbon thermal maturity parameter which was calibrated with mean
vitrinite reflectance (Ro) and show good agreement with increase in thermal maturity. The
TNR-2 value (0.9-1.2, Table 5.2) and calculated vitrinite reflectance Rcb values (>0.95,
Table 5.2) from TNR-2 indicate thermal maturity of the oil samples from the Potwar
Basin reached to late oil generation window [11]. A cross plot (Fig. 5.3b) were drawn
from calculated vitrinite reflectance values i.e. Rcb (TNR-2) vs Rc (MPI-1) clearly
indicate thermal maturity of Potwar Basin oils reached to late oil generation window.
Few anomalies are observed in alkylnaphthalenes maturity parameters.
For example, TNR-1 shows a wide range of values from 1.04 to 2.31 for Potwar Basin
oils although most of the oils lie between 1 and 2 but high values for some of the group B
oils are observed (TNR-1 > 2.0, Table 5.2). These differences in TNR-1 ratios are most
70
probably due to the effects of biodegradation on aromatic fractions in group B oils
(Chapter 6). Affects of biodegradation on alkylnaphthalenes have been shown to affect
different isomers and thus different susceptibilities towards biodegradation [17] and
thermal maturity parameters are adversely changed using certain isomers in thermal
maturity ratio calculations [38,164].
A number of studies have used alkyldibenzothiophenes as maturity parameters
[11,40,37,53,165]. Commonly used parameter, methyldibenzothiophene ratio (MDR)
derived based on similar chemical phenomenon as for MPI-1 i.e. a methyl shift from
thermally less stable isomer (1-MDBT) to thermally more stable isomer (4-MDBT) with
increase in thermal maturity [11]. Moreover, MDR was calibrated with vitrinite
reflectance and reported as Rcs [165]. DMR and calculated vitrinite reflectance (Rcs) from
Potwar Basin crude oils are shown in Table 5.2. A wide rang of values are observed for
DMR (4.4-11.6) and Rcs (0.83-1.36) indicate peak to late oil generation window thermal
maturity of these oils. DMR has shown to be affected by variation in expulsion stages of
1-MDBT and 4-MDBT isomers from kerogen [40] and Dzou et al. [166] pointed out its
limitation for coal samples where it does not show linear relationship between 0.5 to
1.0% vitrinite reflectance. Radke and Willsch [40] introduced a revised form of MDR as
MDR′ where it was calculated by traditional biomarker maturity parameters way i.e. 4-
MDBT/(4-MDBT + 1-MDBT). The values for MDR′ given in Table 5.2 indicate narrow
range of values (0.81-0.92) and results revealed higher thermal maturity for Potwar Basin
oils [40].
5.2.5 Lithology and Depositional Environment
The crude oils listed in Table 5.1 were examined for lithology and depositional
environment using aliphatic and aromatic hydrocarbon parameters. Pristane (VI) to
phytane (VII) (Pr/Ph) ratio is a commonly used for depositional environment. Pr/Ph
ratios > 3.0 have been described for terrestrial input deposited under oxic conditions and
low Pr/Ph ratios i.e. < 1 indicate anoxic/hypersaline or carbonate environment while
Pr/Ph ratios 1 to 3 have been associated with marine oxic/dysoxic conditions [1, 45]. The
71
ratio of dibenzothiophene (XXVII) to phenanthrene (XXIV) (DBT/P) is an indicator of
source rock lithology. The DBT/P ratio >1 indicates a carbonates type facies, whereas
incorporation of sulfur into OM produces higher DBT while DBT/P ratio <1 indicates a
shale type lithology, where sulfur reacts with iron species in the clay minerals and in turn
produces less DBT. DBT/P were measured from GC-MS analysis of the aromatic fraction
using m/z 184 and 178 for DBT and P respectively, while Pr/Ph ratios were determined
from TIC of saturated fractions. Cross plot of DBT/P vs Pr/Ph suggested by Hughes et al.
[167] has been used to infer lithology-depositional environment of the OM and results are
shown in Fig. 5.4a. The largest set of oils from the Potwar Basin (Group B and C) are
shown to have originated from marine-lacustrine shale source rocks and Pr/Ph ratio in the
range 1.0 to 2.0 support a marine oxic/dysoxic depositional environment (Table 5.1).
While group A oil (Adhi-5) shows a higher Pr/Ph ratio (3.2) indicating highly oxic
fluvio-deltaic depositional environment of OM. However, a study on crude oils from NW
Germany showed contrast results where marine sulfur rich samples indicate lacustrine,
sulfur poor lithology/depositional environment and caution was referred to use this
Hughes diagram [7].
C30 17α-diahopane (C30*, XIV) has been suggested to be a rearranged product
of regular hopanes [168] by clay-mediated acidic catalysis and it mostly occurs in marine
clastic oxic-suboxic depositional environments, where oxic/clay rich depositional
conditions rearrange hopanes to diahopanes [45]. The C30 17α-diahopane/ C30 17α-
hopane ratio is shown to be high in clastic source rocks and oxic depositional
environment. Similarly, the regular steranes change to rearranged steranes by clay
mediated rearrangement reactions in source rocks [169] and diasterane/sterane ratios have
been widely used for evaluation of source rock lithology of OM [45]. Low
diasterane/sterane ratios in petroleum indicate anoxic clay-poor source rocks that are
characteristics of carbonates while higher diasterane/sterane ratios refer to oxic clastic
source rocks indicative of marine and deltaic environments [45].
72
0
1
2
3
4
0.0 1.0 2.0 3.0 4.0
Pr/Ph
DBT/
P1A: marine Carbonate1B: marine carbonate and marl2: Lacustrine hypersaline3: marine shale and lacustrine4:fluvio-deltaic shale Hughes et al, 1995
1A
1B
23 Group B & C 4 Group 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
(b)A
B
C
Pindori
Fig.5.4 (a) Pr/Ph versus DBT/P plot indicates lithology and depositional
environment [167] (b) C30 17α-diahopane/C30 17α-hopane vs C29
diasteranes/sterane plot shows the affects of clay and depositional
environment on Potwar Basin oils (c.f. [45] and refernces therein).
73
A plot between C30 17α-diahopane/C30 17α-hopane vs C29 diasteranes/sterane
ratios is shown in Fig. 5.4b and samples from the Potwar Basin fall into three groups.
Groups B and C were similar in Hughes diagram (Fig. 5.4a) are separated into two
different groups, however both groups (B and C) showed consistent for depositional
environment is marine. Although both groups located near to each other in the diagram
but showed two different places in diagram indicate slight variation in lithology and
depositional environment of OM between these groups (Fig. 5.4b). This variation
revealed that group B shows relatively higher diasteranes/sterane ratios compared to the
group C indicating that the group B oils are generated from comparatively more clastic
rocks, while group C show higher diahopane/hopane ratios indicating that the group C
oils were generated from comparatively more oxic deposited source rocks [45]. The oil
from group A (Adhi-5) shows higher values of diahopane/hopane and diasteranes/sterane
ratio (0.38 and 0.97, respectively) separating this oil from all the other oils (Fig. 5.4b)
which indicate a clay rich oxic depositional environment as indicated by Hughes diagram
(Fig. 5.4a). The Adhi-5 was probably generated from oxic/clay rich source rocks and is
consistent with the C30 17α-diahopane/C29 18α-30-norneohopane (C29Ts, XV) ratio. The
C30 17α-diahopane/C29Ts ratio has been suggested as a good indicator of oxic/suboxic
depositional settings of OM [45] and this ratio for group A oil is significantly high (2.23)
indicating an oxic environment of deposition. An anomaly (high value) is observed in the
C30 17α-diahopane/C30 17α-hopane vs C29 diasteranes/sterane diagram for the Pindori-4
crude oil (Fig. 5.4b). The reason for this anomaly could be related to any factor such as
source organic facies, amount of clay contents and total organic carbon that has been
suggested to be affecting diahopane/hopane and/or diasteranes/sterane ratios ([45,170]
and references therein).
5.2.5.1 Heterocyclic aromatic hydrocarbons
Distribution of heterocyclic aromatic hydrocarbons such as DBTs, dibenzofurans
(DBFs) and Fs has been related to the source rock lithology and depositional environment
74
of OM [12-13,171-172]. Whereas abundance of DBTs was related to marine source rocks
while abundant Fs and DBFs were referred to freshwater source rocks [12].
Relative distribution of DBTs, DBFs and Fs were calculated from sum of the peak
areas of parent compounds (non-alkylated) and methyl substituted isomers. A bar
diagram was constructed that indicate relative percentages of DBTs, DBFs and Fs in
Potwar Basin oils (Fig. 5.5). Groups A show abundance of Fs than DBTs while DBFs are
also present in considerable abundance. Group B oils show higher abundance of DBTs
while DBFs and Fs are present in almost negligible concentrations while group C oils
show almost equal abundance of Fs and DBTs except last two oils (P17-P18). These
results reveal that group B oils showed a strong influence of marine suboxic deposition of
OM [12] where sulfur heterocyclic aromatic hydrocarbons (DBTs) are present in
abundance. While group A show oxic depositional environment of OM indicated by
abundant Fs consistent with previous reported results [12-13]. Group C crude oils showed
mixed distribution of Fs and DBTs where Dhurnal oils (P15 and P16) showed
comparable equal abundance of Fs and DBTs while Toot oils (P17 and P18) indicate
higher Fs than DBTs. These results most probably indicate indigenous variation in
depositional environment. Similarly, three mixed concentration profiles of Fs and DBTs
distribution has been reported from marine source rocks and crude oils for oil-source rock
correlation study [13].
5.2.6 Source of OM
Source OM of Potwar Basin oils were initially assessed using distribution of
aliphatic biomarkers and subsequently PAHs distributions are used to classify the source
origin of the petroleums. Specifically, alkylnaphthalenes, alkylphenanthrenes and
triaromatic steroids are reported as aromatic biomarkers from Potwar Basin oils.
Distribution of tricyclic terpanes (TT) and hopanes is shown in m/z 191 mass
chromatograms (Fig. 5.6) of the representative samples from all delineated groups of
Potwar Basin. The parameters for the assessment of source OM from tricyclic and
pentacyclic terpanes and steranes are listed in Table 5.3. Group A oil shows significantly
75
0 20 40 60 80 100
P1
P2
P3
P4
P5
P6
P7
P8
P9
P10
P11
P12
P13
P14
P15
P16
P17
P18
Oils
Relative percentage
Fs
DBFs
DBTs
Group C
Group B
Group A
Fig. 5.5 Bar diagram shows relative percentages of DBTs, DBFs, Fs in Potwar Basin oils.
76
low concentration of tricyclic terpane except for C19-TT and C24-tetracyclic terpane (TeT,
IX), both compounds are indicator of terrestrial source OM [45,173]. The correlation
diagram C19/(C19+C23) TT vs C24 TeT/(C24 TeT + C23 TT) shown in Fig. 5.7 clearly
differentiates three groups of petroleum on the bases of difference in source OM [174-
175]. Group A oil (Adhi-5) located in the top right corner of the plot indicating source
OM is terrestrial origin. Group B and C located in lower left corner of the diagram
indicate marine source OM (Fig. 5.7). However difference in positions of group B and C
in the diagram (Fig. 5.7) revealed slight variation in source OM for these oils. Moreover,
TT and hopane parameters such as C23 TT/C30 17α(H)-hopane, and C24 TeT/C30 17α(H)-
hopane ratios (Table 5.3) indicated typically marine OM for group B and C oils [45]
however two different ranges of these ratios indicate difference in source input in Potwar
Basin oils (Table 5.4). The triterpane distribution of group B oil is typical mature marine
crude oil (Fig. 5.6b) and the major compounds in the chromatograms are 30 and 29
17α(H)-hopanes. Hopanes are in higher relative abundance compared to TT and this
feature differentiates group B oils from other two groups. The representative mass
chromatogram m/z 191 for group C oil shows significantly higher abundance of extended
TT upto C41 and possibly higher (Fig. 5.6c) whereas C23 TT is the most abundant
compound while hopanes show significantly lower abundance. This is the important
feature of group C oils to differentiate from other groups of oils. Total TT/hopanes ratio
for group C oils is significantly high compared to the rest of the oils indicate a difference
in source OM for this group (Tables 5.3 and 5.4). The higher abundance of TT in Potwar
Basin oils is probably associated with algal source of OM. Similarly, higher total
sterane/hopane ratio >0.6 (~1.0 for most of the oils, Table 5.4) for group C oils reflects
greater eukaryotic input (higher algal input). It could be conclude that at least three
groups of petroleum have been produced from different source rocks within the Potwar
Basin. A comprehensive Table 5.4 is constructed to show different ranges of aliphatic
and aromatic biomarkers ratios of source and depositional environment interpretations for
Potwar Basin oils.
77
Fig. 5.6 Mass chromatograms (m/z 191) showing distribution of tricyclic (TT) and
pentacyclic terpanes (hopanes, H) in Potwar Basin crude oils. numbers on peak
indicate TT, 24*, C24-tetracyclic terpane and number with H indicate hopanes.
19 2021
2324*
29H30H
Ts
Tm
29Ts
31H
32H
33H34H 35H
a) Group-A
b) Group-B
c) Group-C
R
S
RSRSRSR
S
61 71 81 91 101
Relative retention time (min)
19
20
21
23
24*24
25 2829 30 31
32 3334
35 36 38 39 40 41
19
24*
Chanknaurang-1A
Dhurnal-1
Adhi-5
Rel
ativ
e in
tens
ity
78
Table 5.3 Source OM and depositional environments parameters of Potwar Basin oils
C19/ (C19+C23) TT: C19-tricyclic terpane/(C19-tericyclic terpane + C23 tricyclic terpane); C24TeT/ (C24TeT+C23TT): C24-tetracyclic terpane/(C24-tetracyclic terpane + C23 tricyclic terpane); C23 TT/C30-hopane: C23 tricyclic terpane/C30-αβ hopane C24 TeT: C24 tetracyclic terpane/C30-αβ hopane; C30*/C30 αβ-hopane: 30, αβ-diahopane/ C30 αβ- hopane; C30*/C29 Ts: 30, αβ-diahopane/18α(H)-30-norneohopane; C31 (R+S)/C30 hop: C31 αβ-homohopane (22S+22R)/C30 αβ- hopane; Ster/hop: total steranes/total hopanes; Dia/ster C29: βα/(αα+ββ) ethylcholestane; total TT/Hop: total tricyclics/hopanes; C27/C29 dia, βα-cholestane/βα-ethylcholestane, R+S; C20/C21 TAS, C20/C21 triaromatic steroids; 1-MP/9-MP: 1-methylphenanthrene/9-methylphenanthrene; 1,7-DMP/X; 1,7-dimethylphenanthrene/(1,3- + 3,9- + 2,10 + 3,10-DMP); TMN: trimethylnaphthalene
No oil and well C19/
(C19+C23) TT
C24TeT/ (C24TeT +C23TT)
C23 TT/C30 Hopane
C24-TeT/C30 hopane
C29/C30
αβ hop C30*/C30 αβ hop Ster/hop Dia/Ster
C29
Total TT/Hop C27/C29,
dia C20/C21
TAS
1-MP/9-
MP
1,7-DMP/X
1,2,6-/1,2,4-TMN
125-/127-TMN
P1 Adhi-5 0.88 0.77 0.07 0.24 0.65 0.38 0.29 0.97 0.22 0.43 1.76 0.84 0.53 2.49 3.46
P2 Missakeswal-1 0.49 0.47 0.40 0.35 0.58 0.26 0.23 0.60 0.49 0.83 1.23 0.85 0.27 1.54 1.19
P3 Missakeswal-3 0.46 0.49 0.31 0.30 0.55 0.22 0.24 0.63 0.34 0.70 1.25 0.75 0.28 1.46 1.19
P4 Rajian-1 0.40 0.56 0.32 0.42 0.74 0.15 0.23 0.57 0.36 0.75 1.84 0.74 0.24 1.55 2.31 P5 Rajian-3A 0.40 0.55 0.37 0.45 0.78 0.15 0.28 0.51 0.38 0.79 1.77 0.76 0.28 1.58 1.93 P6 Kal-1 0.39 0.54 0.37 0.44 0.76 0.17 0.27 0.54 0.42 0.82 1.68 0.75 0.25 1.52 2.00 P7 Kal-2 0.38 0.52 0.46 0.49 0.75 0.22 0.34 0.60 0.51 0.72 1.66 0.71 0.26 1.44 1.74 P8 Fimkassar-1 0.41 0.57 0.33 0.44 0.65 0.15 0.27 0.49 0.39 0.90 1.70 0.75 0.27 1.52 1.75 P9 Fimkassar-4 0.45 0.52 0.28 0.30 0.69 0.18 0.35 0.68 0.61 0.77 1.53 0.76 0.28 1.36 1.33
P10 Chaknaurang-1A 0.33 0.61 0.24 0.38 0.79 0.11 0.23 0.40 0.26 0.83 2.04 0.77 0.25 1.47 2.04
P11 Minwal-1 0.30 0.63 0.23 0.39 0.87 0.07 0.20 0.38 0.20 0.87 2.28 0.81 0.25 1.57 2.44 P12 Joyamir-4 0.38 0.55 0.43 0.52 0.75 0.20 0.33 0.59 0.45 0.72 2.35 0.77 0.25 1.55 2.36 P13 Turkwal-1 0.44 0.55 0.38 0.47 0.75 0.19 0.35 0.58 0.46 0.84 1.43 0.74 0.27 1.64 1.57 P14 Pindori-4 0.49 0.51 1.93 2.03 0.64 0.86 1.24 0.78 2.37 0.83 0.97 0.69 0.28 1.50 1.03 P15 Dhurnal-1 0.34 0.44 1.54 1.22 0.61 0.32 1.50 0.06 2.45 1.28 0.96 0.79 0.32 2.20 1.28 P16 Dhurnal-6 0.33 0.45 1.16 0.93 0.51 0.29 1.45 0.19 1.68 1.23 1.24 0.72 0.34 1.77 1.27 P17 Toot-10A 0.36 0.40 0.86 0.58 0.48 0.26 0.74 0.26 0.99 1.07 1.18 0.76 0.34 1.84 1.40 P18 Toot-12 0.32 0.44 0.50 0.40 0.57 0.23 0.58 0.27 2.15 1.27 1.04 0.79 0.33 2.16 1.15
79
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
C19/(C19+C23) TT
C24
TeT
/(C24
TeT
+ C
23 T
T)
B
A
C
Terrestrial
Fig. 5.7 Cross plot between C19/(C19+C23) TT and C24 TeT/(C24 TeT + C23 TT) shows
difference in source material in Potwar Basin oils [c.f. 173-175].
80
Table 5.4 Biomarkers parameters limits for Potwar Basin oils
Parameters* Group A Group B Group C Interpretation References
C19/(C19+C23) TT ~0.9 0.5-0.3 ~0.3 Gp A terrestrial, [45, 175] C24TeT/ (C24TeT+C23TT) ~0.8 >0.5 <0.5 Gp A terrestrial [173-175] C23 TT/C30 hopane <0.1 0.23-0.46 >0.5 (~1.0) Gp B and C marine, C higher
marine input [45]
C24-TeT/C30 hopane <0.3 0.3-0.5 >0.5 Gp B and C marine OM input [45] Total TT/Hopanes ~0.2 0.3-0.6 1.0-2.5 Gp C shows algal source OM [45,176] C31(R+S)/C30- αβ hopane - >0.8 <0.5 Gp B showed more reducing
depositional settings than Gp C [45,177]
Steranes/hopanes ~0.3 <0.4 >0.6 (~1.0) Higher marine (algal) input in Gp C [45, 178] βα/(ββ+αα) C27 - >0.45 <0.45 Gp B generated from more clastic
than Gp C [45, 179]
βα/(ββ+αα) C29 ~1.0 >0.4 <0.3 GP A and Gp B showed greater clay affects
[45, 155]
Total diasteranes/steranes >1.0 0.65-1.0 <0.4 Gp B shows higher clastic/mineral affects
[45]
Retene Present Absent Absent Gp A terrestrial [5,32] 1,7-DMP/X ~0.53 <0.28 > 0.32 GP A indicate terrestrial input [5]
*: definition in Tables 5.2 and 5.3 Gp: Group
81
5.2.6.1 Alkylnaphthalenes and alkylphenanthrenes
Abundance of certain methyl substituted isomers of naphthalene (XXIII) and
phenanthrene (XXIV) has been reported as aromatic biomarkers derived from specific
class of natural products [5,19,180]. β-Amyrine from higher plants angiosperm has been
showed a source precursor for alkylnaphthalenes [19,180]. Similarly abietane and
pimarane type biological precursors from diterpenoids are more likely the source of
alkylphenanthrenes [32]. Budzinski et al. [181] related a range of alkylphenanthrenes
with marine and terrestrial source OM along with affect of thermal maturation.
Distribution of certain isomers of alkylnaphthalenes and alkylphenanthrenes were
determined to evaluate the contribution of specific class of biological precursors to the
source OM of Potwar Basin oils.
In alkylnaphthalenes, abundance of 1,2,7-TMN, 1,2,5-TMN and 1,2,5,6-TeMN
(see XXIII for naphthalene numbering system) in sediments and crude oils are suggested
to be originate from angiosperms [19,182]. Aromatic seco-hopanes are also reported as
source for 1,2,5-TMN and 1,2,5,6-TeMN [180]. The 1,2,6-TMN, 1,2,5,7-TeMN and
1,2,3,5-TeMN are supposed to be generated from microbial origin [183] while 1,2,4-
TMN in marine sediments suggested as biomarker for tocopherole [66a]. In Potwar Basin
oils, there is no noticeable abundance of any certain isomer of alkylnaphthalenes were
observed. However different alkylnaphthalenes ratios were calculated and reported in
Table 5.3. Fig. 5.8a shows a cross plot between 1,2,5-/1,2,7-TMN vs 1,2,6-/1,2,4-TMN
ratios differentiate Potwar Basin oils into three groups. 1,2,7-TMN and 1,2,5-TMN has
been exclusively suggested as angiosperm markers [19] however non-angiosperm natural
products are also related to the source of 1,2,5-TMN [141]. The abundance of 1,2,5-TMN
relative to 1,2,7-TMN in group A oils indicate different source precursor for these
naphthalene isomers than those of angiosperms which is further supported by the absence
of oleanane (a angiosperm biomarker) and its related products in saturated fractions (Fig.
5.6). Grice et al. [184] suggested that the origin of 1,2,5-TMN in boghead coals is
drimanes by reporting similar δ13C values for both compounds.
82
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
0.0 0.5 1.0 1.5 2.0 2.5 3.0
1,2,6-/1,2,4-TMN
1,2,
5-/1
,2,7
-TM
NA
B
C
(a)
0.2
0.3
0.4
0.5
0.6
0.3 0.4 0.5 0.6 0.7 0.8 0.9
1-MP/9-MP
1,7-
DM
P/X
A
C
B
(b)
Fig. 5.8 (a) Distribution relationship between TMN ratios of Potwar Basin oils (b) higher
plant aromatic biomarkers ratios 1,7-DMP/X and 1-MP/9-MP [5] indicated
terrestrial input for group A oil.
83
Source of 1,2,5-TMN in group A oil is also most likely the drimanes which are
significantly abundant components in branch/cyclic fraction of group A oil (result not
showed). Group B and C oils locate near to each other in the TMN ratios diagram
indicate similar type of source for TMNs however both groups cluster at different places
in the diagram indicate some difference in the source input [4,19].
In alkylphenanthrenes, 9-MP is related to the marine character of OM while 1-MP
related to the terrestrial origin [181] and 1-MP/9-MP ratio was calculated from Potwar
Basin oils reported in Table 5.3. 1,7-DMP/X ratio (X is 1,3-, 3,9, 2,10, 3,10-DMP
isomers coeluted peak Radke et al., [11]) is successfully used for correlation study of
crude oils having different source OM from various ages [5]. A plot between 1-MP/9-MP
vs 1,7-DMP/X ratios (Fig. 5.8b) separated Potwar Basin oils in three groups where group
A oil shows a separate place in the top right corner of the diagram (Fig. 5.8b). The
abundance of 1-MP and 1,7-DMP clearly indicate terrestrial source precursor for these
compounds in group A oil. 1,7-DMP has been suggested a biomarker from pimarane type
diterpenoids abundant in ambers and resins [32,185]. Moreover the significant abundance
of conifer resin aromatic biomarker retene (XXI, Fig. 4.12, Chapter 4) is observed in
group A oil indicate that major contribution of source OM for this oil is higher plant
resins. Group B and C oils show similar place in the diagram that show similar origin of
alkylphenanthrenes however different position in the diagram indicate some difference in
OM input.
5.2.6.2 Triaromatic steroids (TAS)
The distribution of TAS was monitored by ion 231 from aromatic fractions and
Fig. 5.9 shows representative ion chromatograms (m/z: 231) from each group of Potwar
Basin oils. Short (C19 to C22, XXa to XXc) and long chain (C25 to C28, XXe to XXh) TAS
with different distributions are observed within the groups. Generally, short chain C20 and
C21 compounds are present in higher abundance than long chain compounds. While
84
Fig. 5.9 Distribution of triaromatic steroids in Potwar Basin crude oils a) Adhi-5, b) Kal-
2, c) Toot-12. Carbon number on peak refers to corresponding TAS (XXa to XXh).
Rel
ativ
e in
tens
ity
c) Group-C
Triaromatic steroids m/z: 231 (a) Group A
C20
C21 C27,S C28,S C28,R C27,R
C20 R C22 (b) Group-B S C26,R+C27,S C21 C26,S C28,S C28,R C25,S C25,R C27,R C19
72 76 80 84 88 92
Relative retention time (min)
85
distribution of long chain TAS clearly differentiates Potwar Basin oils into three groups.
Where group A shows only C27 and C28 compounds while group B shows C25 to C28
compounds (Fig. 5.9). The absence (or below detection limit) of long chain TAS in group
C oil representative chromatogram clearly differentiate this group from other two groups
(Fig. 5.9c).
Generally, TAS from C26 to C28 compounds have been supposed to be originated
from demethylation and aromatization of monoaroamtic steriods from corresponding C27
to C29 compounds [47,186]. While short chain compounds has been apparently generated
from homolytic scission of long chain triaromatic steroids with increase in thermal
maturity [187-188]. Monoaromatic and TAS are very effective thermal maturity
parameters for late oil generation window although it has been reported that these
parameters are potentially source dependent [45]. Significantly higher abundance of C20
and C21 compounds and comparatively negligible concentrations of C19 and C22
compounds in oils indicate a different source precursor for these compounds. In long
chain TAS, the presence of only two compounds (C27 and C28) in group A, C25 to C28
compounds in group B and totally absent in group C oils clearly revealed that TAS from
Potwar Basin are source dependent. Because full range of regular and rearranged steranes
(C27, C28, C29) are significantly abundant in Potwar Basin oils that has been suggested as
source for aromatic steroids [45]. But the presence and absence of certain carbon number
triaromatic steroids indicate different source precursor for these compounds.
TAS (C26, C27, C28) has been shown effective correlation parameters and
indicate similar associations with biological precursors (terrestrial, marine and lacustrine
input) as referred by regular steranes and monoaromatic steroids [45,189-190]. Long
chain TAS i.e. C26, C27, C28 are not fully observed in all samples of Potwar Basin oils,
however short chain compounds (C20 and C21) are present all samples. A correlation
diagram (Fig. 5.10) between C20/C21 triaromatic steroids and C27/C28 diasteranes
differentiate Potwar Basin oils into three groups revealed that variation in relative
abundance of aromatic steroids is controlled by source input.
86
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
0.0 0.5 1.0 1.5 2.0 2.5
C20/C21 TAS
C27
/C29
dia
ster
anes
C
B
A
Fig. 5.10 Distribution relationship between C20/C21 TAS and C27/C29 diasteranes from
Potwar Basin oil clearly indicate three groups
87
5.2.7 Biodegradation
The presence of heavy oils in reservoirs is mostly related by secondary
processes such as biodegradation, water washing and phase separation [14,45-46]. Light
to very heavy oils from Potwar Basin are present that indicate the alteration of
hydrocarbons composition in reservoirs. A number of commonly used parameters have
been used to assess the extent/level of biodegradation in Potwar Basin oils.
Representative total ion chromatograms (TICs) of the saturated hydrocarbons fractions
from each group of oils are shown in Fig. 5.11. The chromatograms from group A and C
show full suite of n-alkanes and isoprenoids with no unresolved complex mixture (UCM)
that indicates no signs of biodegradation. While TIC of saturated hydrocarbon fraction
from representative group B oil shows substantional UCM and lack of n-alkanes
indicating that these oils have been biodegraded and the remaining fraction has become
enriched in high molecular weight unresolved components. Isoprenoids show resistance
to biodegradation compared to the n-alkanes because n-alkanes are removed earlier than
isoprenoids by bacteria during biodegradation. Hence isoprenoid/n-alkane ratios from
saturated fractions increases with increase in biodegradation [191] and Pr/n-C17 and Ph/n-
C18 ratios greater than 1 typically show the affects of biodegradation on crude oils. The
plot of Pr/n-C17 vs. Ph/n-C18 (Fig. 5.12a) shows a trend consistent with biodegradation;
these latter ratios increase with rising biodegradation. The tope right corner of the
diagram (Fig. 5.12a) shows Pr/n-C17 ratio > 1 indicates the affects of biodegradation on
these oils. 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 (16-48°;
Table 5.1). Low API gravity (16-26.6°) for some of the oils particularly from eastern
Potwar is consistent with biodegradation. A plot of API gravity vs Pr/n-C17 (Fig. 5.12b)
shows inverse relationship, a high Pr/n-C17 and low API gravity (Fig. 5.12b) indicative of
the oils affected by biodegradation. The results shows that extent of biodegradation for
some of the crude oils in this study reaching up to level 3 on the biodegradation scale
[46]. The extent of biodegradation on each crude oil of Potwar Basin is represented with
level of biodegradation in Table 5.5. It is observed that some of the oils from group B are
affected by minor biodegradation while group A and C are non-biodegraded (Table 5.5).
88
Fig. 5.11 Representative TICs of saturated fractions from Potwar Basin oils, Group A,
Adhi-5; group B, Joyamir-4; group C, Dhurnal-1. Number on peaks refers to
n-alkanes carbon numbers.
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
89
0.0
0.2
0.4
0.6
0.8
1.0
1.2
0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6
Pr/n -C17
Ph/n
-C18
(a)
0
10
20
30
40
50
60
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6
Pr/n -C17
API
gra
vity
Biodegradation
(b)
Fig.5.12 (a) Plot of Pr/n-C17 vs Ph/n-C18 and (b) API value vs. Pr/n-C17 showing
biodegradation trends in crude oils used in this study.
Biodegradation
90
Table 5.5 Assessment of biodegradation results of Potwar Basin crude oils
No Oil and well Group# Bio/non-biodegraded Biodegradation Level*
P1 Adhi-5 A Non-biodegraded 0 P2 Missakeswal-1 B Non-biodegraded 0 P3 Missakeswal-3 B Non-biodegraded 0 P4 Rajian-1 B Biodegraded 2 P5 Rajian-3A B Biodegraded 2 P6 Kal-1 B Biodegraded 3 P7 Kal-2 B Biodegraded 2 P8 Fimkassar-1 B Biodegraded 1 P9 Fimkassar-4 B Biodegraded 1 P10 Chaknaurang-1A B Biodegraded 3 P11 Minwal-1 B Biodegraded 3 P12 Joyamir-4 B Biodegraded 3 P13 Turkwal-1 B Biodegraded 1 P14 Pindori-4 B Non-biodegraded 0 P15 Dhurnal-1 C Non-biodegraded 0 P16 Dhurnal-6 C Non-biodegraded 0 P17 Toot-10A C Non-biodegraded 0 P18 Toot-12 C Non-biodegraded 0
*Wenger et al., [46]
91
CONCLUSIONS
The hydrocarbon compositions of 18 crude oils from the Potwar Basin were
examined using biomarkers, aromatic and heterocyclic aromatic hydrocarbons
distribution and stable isotopic compositions of saturated and aromatic fractions, in order
to evaluate source OM, maturity, lithology and depositional environment and level of
biodegradation. These geochemical characteristics differentiate Potwar Basin oils into
three groups (A, B and C) with following key geochemical differences.
• Group A oil showed higher Pr/Ph with low DBT/P reveals fluvio-deltaic
source rocks deposited in highly oxic depositional environments. Abundance
of C19 TT and C24 TeT along with higher abundance of diagnostic aromatic
biomarkers i.e. 1,2,5-TMN, 1-MP, 2,7-DMP and retene revealed terrestrial
source OM for group A oil. Group A oil showed more negative (isotopically
lighter) in δ13C of both saturated and aromatic fractions from all other oils
clearly differentiates. Abundant BPs along with MFs is also important feature
of this group separate it from other groups. The saturate hydrocarbons profile
showed typical non biodegraded crude oil.
• Rest of oils from Potwar Basin analysed in this study are marine in origin
however δ13C and δD stable isotopes and biomarker parameters including TT,
TeT, hopanes, aromatic and heterocyclic aromatic hydrocarbons separated
these oils into 2 sub-groups (B and C). Group B oils showed heaviest δ13C of
both saturated and aromatic fractions. DBTs aromatic hydrocarbons are
abundant components in group B along with significant presence of short and
long chain TAS distinguished this group from others. Some of the group B
crude oils are showed depletion in low molecular weight hydrocarbons
particularly n-alkanes, by minor biodegradation (upto level 2-3) while OM is
generated from marine clastic rocks deposited in marine suboxic/dysoxic
depositional environments. TT are less abundance than hopanes.
92
• Group C represented typically non-biodegraded matured marine crude oils
deposited in marine oxic environments which are generated from source OM
enriched in algal source input indicated by higher extended TT. Group C oils
showed light δ13C of saturated fractions than group B oils however δ13C of
aromatic fractions of group B and C are not very different. Significant
presence of short chain TAS and totally absent of long chain TAS are
important feature of this group oils. TT are more abundant than hopanes.
93
Chapter - 6
POLYCYCLIC AROMATIC HYDROCARBONS (PAHs) AND STABLE HYDROGEN ISOTOPE
STUDY AS INDICATOR OF MINOR BIODEGRADATION
ABSTRACT
Distribution of PAHs and stable hydrogen isotopic composition (δD) of n-
alkanes and isoprenoids has been used to assess the minor biodegradation in a suite of
crude oils from Potwar Basin, Pakistan. The biomarker study revealed that crude oils
share a similar source and thermal maturity. The low level of biodegradation under
natural reservoir conditions was established on the basis of biomarker distributions. Bulk
stable hydrogen isotope of saturated fractions of crude oils show an enrichment in D
with increase in biodegradation and show a straight relationship with biodegradation
indicators i.e. Pr/n-C17, API gravity. For the same oils, δD values for the n-alkanes
relative to the isoprenoids are enriched in deuterium (D). The data are consistent with
the removal of D-depleted low-molecular-weight (LMW) n-alkanes (C14-C22) from the
oils. The δD values of isoprenoids do not change during the minor biodegradation and
are similar for all the samples. The average D enrichment for n-alkanes with respect to
the isoprenoids is found to be as much as 35‰ for the most biodegraded sample. The
relative susceptibility of alkylnaphthalenes and alkylphenanthrenes at low levels of
biodegradation was discussed. The dimethylnaphthalene, trimethylnaphthalene and
tetramethylnaphthalene biodegradation ratios were purposed that showed significant
differences with increasing biodegradation and are suggested as good indicators for
assessment of low level of biodegradation.
94
6.1 INTRODUCTION
Polycyclic aromatic hydrocarbons (PAHs) from sedimentary OM have been
widely used to assess thermal maturity [4,10,38,156] and multiple accumulation
histories of oils in reservoirs [38]. The higher relative abundance of certain PAHs
isomers (e.g. 1,6-DMN, 1,2,5-TMN, 1,2,7-TMN and 1,2,5,6-TeMN) in sediments and
thermally immature oils is generally related to source(s) [38,181]. The effects of
biodegradation on PAHs in reservoirs have been reported in several studies
[15,17,41,48,129]. Susceptibility of PAHs to biodegradation is dependent on the number
of aromatic rings and alkyl substituents on the rings. Generally, the susceptibility to
biodegradation decreases with an increase in the number of aromatic rings and in the
number of alkyl substituents on the aromatic moieties [41,44,192]. Alkylbenzenes are
the first aromatic compounds to be removed from oil during in-reservoir biodegradation
[43,44]. For alkylnaphthalenes and alkylphenanthrenes the thermodynamically more
stable isomers are generally more susceptible to biodegradation [15,41]. For the
alkylbiphenyls, the sterically-hindered isomers with alkylation in the 4 position are less
susceptible than other isomers [49].
The application of compound specific isotope analysis (CSIA) has become a
powerful tool for assessment of source, thermal maturity and biodegradation
[17,149,193-197]. In general, biodegradation leads to 13C enrichment in the residual
compounds by removing isotopically lighter 12C compounds from crude oils [44,198-
201]. The greater mass difference between hydrogen and deuterium compared with other
stable isotopes (e.g. carbon) results in a larger fractionation. In vitro biodegradation
studies of crude oils have demonstrated that fractionation of the LMW n-alkanes (i.e. n-
C15 to n-C18) can lead to 25‰ enrichment in D, whereas the HMW n-alkanes show little
isotopic change [193]. Sun et al. [149] reported a significant isotopic fractionation in
moderately biodegraded oils, a D enrichment in the n-alkanes of up to ca. 35‰ being
observed. Microbes preferentially utilize the lighter isotopes i.e. 12C and H, so the
residue becomes enriched in 13C and D [202].
In this study, a suite of eight crude oils from Potwar Basin (group B, section
5.2.6, Table 5.5) was analyzed for compound specific stable hydrogen isotopes of
95
saturated hydrocarbons and PAHs distributions. The affects of biodegradation on δD
values of n-alkanes and isoprenoids (Pr, Ph) and susceptibility to biodegradation of
PAHs is investigated. The notion behind the approach is that, during minor
biodegradation, microbes consume isotopically lighter compounds and the remaining
compound classes become enriched in isotopically heavy compounds. Biodegradation
susceptibilities order for individual isomers of alkylnaphthalenes and alkylphenanthrenes
is suggested from non-biodegraded to minor biodegraded crude oils from Potwar Basin.
6.2 RESULTS AND DISCUSSION
Bulk and compound specific hydrogen isotope analysis and distribution of
PAHs have been used to evaluate their applications for assessment of minor
biodegradation in Potwar Basin crude oils. A sample suit composing non-biodegraded to
minor biodegraded crude oils has been used (Table 6.1). The crude oils believed to share
a similar source and thermal maturity (Chapter 5, group B).
6.2.1 Assessment of Biodegradation
Evaluation of the extent of biodegradation was reported using different
biodegradation indicators (Pr/n-C17, Ph/n-C18, API gravity) and it has been observed that
a range of non-biodegraded to minor biodegraded crude oils are present in Potwar Basin
(Chapter 5, Section 5.2.7). A suite of eight crude oils show similar source OM and
thermal maturity were selected for detail assessment and affects of biodegradation on
hydrocarbons (Table 6.1). The sequential affects of biodegradation on saturated fractions
from these selected crude oils is shown by TIC of saturated hydrocarbons fractions in
Fig 6.1. For the Missakeswal-1 oil, the saturated hydrocarbons (Fig. 6.1a) show a typical
non-biodegraded profile, having a full suite of n-alkanes, while the Rajian-3A oil (Fig.
6.1b) shows a lack of the lower MW n-alkanes. In the Joyamir-4 oil (Fig. 6.1c) there is a
significant increase in the relative abundance of the UCM, the n-alkanes are significantly
lower in abundance and there is a lack of the lower MW isoprenoids. These finding
show that crude oils from this set of oils show a range from non-biodegraded to minor
biodegradation up to level 2 to 3 [46]. Similarly, API gravity with in this set of eight
96
crude oils show a subtle change from very light oil (Pindori-4, API gravity: 41°) to very
heavy oil (Joyamir-4, API gravity: 16.1°). A significant presence of n-alkanes in
saturated fractions along with substantional UCM in very heavy oil (Fig. 6.1c) indicates
the possibility of mixing of heavy biodegraded oils with non-biodegraded oils in the
reservoirs [124,203,205].
Table 6.1 n-Alkanes, isoprenoids, aliphatic biomarkers and diamondoids hydrocarbons
ratios
Oil# Name API Gravity Pr/Ph Pr/
n-C17 Ph/
n-C18 BP1 BP2 MA/
A MDIA/
DIA
P14 Pindori-4 41 1.5 0.8 0.5 0.65 0.01 5.3 2.5
P2 Missakeswal-1 36.2 1.5 1.0 0.7 0.84 0.04 5.3 2.6
P13 Turkwal-1 - 1.2 1.1 0.8 0.93 0.11 6.4 2.6
P7 Kal-2 26.6 1.3 1.2 0.9 0.99 0.06 5.0 2.5
P5 Rajian-3A 22.7 1.3 1.3 0.9 1.07 0.09 5.2 2.4
P10 Chaknaurang-1A 18.4 1.2 1.3 0.9 1.11 0.15 5.2 2.3
P11 Minwal-1 16 1.0 1.3 1.0 1.10 0.18 4.9 2.4
P12 Joyamir-4 16.1 1.0 1.3 1.0 1.15 0.06 4.9 2.4
Pr / Ph: Pristane / Phytane BP1: (Pr+Ph)/(n-C17+n-C18), Peak areas of pristane and phytane from m/z 183 and n-C17 and n- C18 from
m/z 57[203] BP2: 17α 21β(H) hopane/(Pr+Ph). Peak area of hopane from m/z 191 and pristane, phytane from m/z 183
[203] MA/A : ratio of methyladamantanes (1-MA +2-MA)/adamantane (A, XVIII). Peak areas of 1-MA + 2-
MA from m/z 135 and adamantane from m/z 136 [204,124] MDIA/DIA : ratio of methyldiamantanes (1-MD + 3-MD + 4-MD)/Diamantane (DIA, XIX). Peak areas
of 1-MD + 3-MD + 4-MD from m/z 187 and adamantane from m/z 188 [204,124]
97
Fig. 6.1 Total ion chromatograms of saturated hydrocarbon fractions for Potwar Basin
crude oils showing different degrees of biodegradation. C11 to C36 indicate carbon
number of n-alkanes. 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; UCM, unresolved complex mixture.
(a) P2- Missakeswal-1 API: 36.2
(c) P12-Joyamir-4 API: 16.1
(b) P5-Rajian-3A API: 22.7
Relative Retention Time
C17
Pr C25 Ph
Rel
ativ
e in
tens
ity
d c b e a
UCM
Incr
ease
in b
iode
grad
atio
n
C11 C36
98
In reservoir mixing
The relative abundance of the UCM in saturated hydrocarbon fractions rises
when the LMW components are removed [46]. In the case of the Potwar Basin oils
herein, the presence of both UCM and n-alkanes (Fig. 6.1c) might suggest petroleum
being comprised mixture of non-biodegraded oil with a severely biodegraded oil. The
API gravity of 16° (Joyamir-4) in the most biodegraded oil point to the possibility of in-
reservoir petroleum mixing. Components such as the 25-norhopanes are associated with
oils that have undergone significant biodegradation [205-206]. None of the oils from the
Potwar Basin was found to contain these components. Other than des-methylhopanes,
other hydrocarbon classes were examined to assess the level of mixing of the samples
(e.g. [124,203,207]). The mixing of a severely biodegraded crude oil with a fresh oil
charge has also been shown to affect various thermal maturity parameters [203,207] and
results in significant changes in δ13C and δD [208]. Interestingly the Potwar Basin oils
show a similar range of thermal maturity (Chapter 5, Section 5.2.3) and so appear not to
be mixtures. Koopmans et al. [203] proposed a mixing model for biodegraded
petroleum, based on (Pr + Ph)/(n-C17+n-C18) and 17α,21β(H) hopane/(Pr + Ph), and
showed some correlation with biodegradation and with viscosity. These parameters are
strongly affected when oils consist of mixtures with different levels of biodegradation.
The (Pr + Ph)/(n-C17 + n-C18) and 17α,21β(H) hopane/(Pr + Ph) values for the Potwar
Basin oils are shown in Table 6.1. These ratios have been plotted against API values and
show a very good correlation (R2 0.95 and 0.83, respectively, Fig. 6.2) indicating that the
oils do not appear to mixtures. Diamondoids are one of the most resistant hydrocarbons
to biodegradation [124]. The mixing of non-biodegraded with heavily biodegraded oils
has shown variations in the ratio of methyl adamantanes/adamantanes (MA/A) and
methyl diamantanes/diamantanes (MDIA/DIA; [124]). The diamondoid ratios for the
Potwar oils are similar (Table 6.1), again indicating little or no mixing. The available
biomarker distributions in the samples do not provide any firm evidence for in-reservoir
mixing, but the possibility of in-reservoir mixing cannot be conclusively excluded since
many petroleum reservoirs appear to contain mixtures. Further work for the
determination of possible biodegradation mixing is carrying on.
99
R2 = 0.95
0
10
20
30
40
50
0.4 0.6 0.8 1.0 1.2
(Pr+Ph)/(n-C17+n-C18)
AP
I
R2 = 0.83
0
10
20
30
40
0.00 0.05 0.10 0.15 0.20
17α, 21β (H) hopane/(Pr+Ph)
AP
I
Fig. 6.2 Relationship between API gravity and biodegradation parameters (BP1 and BP2,
[203]) showing API to by controlled by biodegradation rather than any other
factor such as mixing.
100
6.2.2 Bulk Hydrogen Isotopic Compositions of Saturated Fractions
A progressive change in δD values of bulk hydrogen isotopes of saturated
fractions of crude oils has been observed (Chapter 5, Table 5.1). It has been shown that
Pr/n-C17 is a good indicator to show the affects of biodegradation on Potwar Basin crude
oils (Chapter 5, section 5.2.6). A cross plot of δDsats vs Pr/n-C17 is used to show the
affect of minor biodegradation on δD of saturated fractions (Fig. 6.3). A straight
relationship between variables shows that with increase in biodegradation indicated by
increase in Pr/n-C17 is accompanied by increase in δD i.e. δD of saturated fractions move
to more positive. That means with increase in biodegradation the δD of saturated
fractions become isotopically heavy. This revealed that lighter isotopes of saturated
fractions are preferentially removed by microbes and remaining saturated fractions
become enriched in deuterium (D) and this is in agreement with previous study [202].
-160
-150
-140
-130
-120
0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5
Pr/n -C17
δD(‰
) sat
s
biodegredationenrichemnt in D
Fig. 6.3 δDsats vs. Pr/n-C17 plot shows straight relationship that increase in
biodegradation is accompanied by enrichment in deuterium of saturated
fractions.
101
6.2.3 Compound Specific Hydrogen Isotopic Compositions of n-
Alkanes and Isoprenoids
Table 6.2 shows δD values for n-alkanes and isoprenoids (Pr and Ph) in a suit
of crude oils ranging from non-biodegraded to minor biodegraded samples. non-
Biodegraded crude oils (Pindori-4 and Missakeswal-1, Table 6.2) show more negative
(lighter) values while minor biodegraded crude oils (Rajian-3A and Minwal-1, Table
6.2) show less negative (heavy) values for stable hydrogen isotopes of LMW n-alkanes.
The δD values for Pr and Ph are generally similar for all crude oils. This shows non-
biodegraded oils contained isotopically lighter compounds compare to the minor
biodegraded oils.
Based on extant studies by Sessions et al. [209] the D/H fractionation that
occurs between water is ca. 158‰ and ca. 235‰ for alkyl and isoprenoid lipids,
respectively. This leads to the fact that isoprenoid lipids are being depleted in deuterium
relative to n-alkyl lipids in organisms. Similar differences have been reported for
relatively ‘immature’ sediments dating from recent to Devonian (e.g. [197,210-212]),
whereby isoprenoid alkanes (e.g. Pr and Ph) are depleted in D relative to n-alkanes by up
to about 80‰. However, thermal maturity appears to have influence on this trend. With
rising maturity, Pr and Ph become enriched in D, whereas the δD values for n-alkanes
generally remain constant until a very high maturity level is reached [197,213]. These
studies have shown that hydrogen isotopic exchange occurs more readily for isoprenoids
that contain tertiary carbon centers, via a mechanism involving carbocation-like
intermediates. The δD compositions for individual n-alkanes from the same suit of oils
are shown in Fig. 6.4. Two different profiles are clearly visible across the n-alkanes δD
plots, one in the LMW region and other in the HMW region of the plot (Fig. 6.4a).
The LMW n-alkanes (n-C14 to n-C22) show a significant enrichment in D with
increasing level of biodegradation. These results are also consistent with respect to 13C
enrichment observed for LMW n-alkanes in previous biodegradation studies [214]. The
HMW n-alkanes (>n-C22) are less affected by minor biodegradation and
102
Table 6.2 δD(‰)* values of n-alkanes and isoprenoids from Potwar Basin oils
Sample P14 P2 P7 P5 P11
n-alkanes\name Pindori-4 Missakeswal-1 Kal-2 Rajian-3A Minwal-1
n-C14 -151 -165 -130 -129 -119
n-C15 -159 -169 -130 -129 -124
n-C16 -157 -166 -132 -133 -122
n-C17 -164 -168 -137 -139 -125
n-C18 -165 -169 -135 -140 -126
n-C19 -164 -167 -138 -141 -128
n-C20 -160 -166 -133 -135 -128
n-C21 -161 -165 -135 -126 -135
n-C22 -154 -163 -141 -129 -135
n-C23 -150 -168 -132 -123 -138
n-C24 -148 -150 -130 -117 -135
n-C25 -141 -153 -128 -119 -135
n-C26 -133 -126 -126 -116 -132
n-C27 -135 -123 -123 -117 -126
n-C28 -132 -127 -122 -115 -118
n-C29 -135 -129 -117 -118 -118
Aver n-C14-29 -151 -155 -131 -127 -128
Aver n-C14-22 -159 -166 -135 -132 -127
Pristane, Pr -154 -165 -157 -142 -157
Phytane, Ph -149 -157 -152 -141 -168
Aver, (Pr + Ph) -152 -161 -155 -142 -162
Difference (∆δ) (Pr+Ph)- (n-C14-22) 7 5 -20 -10 -35 *: δD (‰) with respect of VSMOW with in standard deviation of 5‰.
103
Fig. 6.4 The δD (‰) distribution of n-alkanes from Potwar oils, (a) n-C14 to n-C29 n-
alkanes (b) significant effect of biodegradation is observed in n-alkanes, n-
C14 to n-C22.
-180
-160
-140
-120
-100
n-alkanes
δD
‰
Pindori-4
Misakeswal-1
Kal-2Rajian-3AMinwal-1
n-C14 n-C16 n-C18 n-C20 n-C22
(b)
-180
-160
-140
-120
-100
n-Alkanes
Pindori-4
Misakeswal-1
Kal-2
Rajian-3A
Minwal-1
δD ‰
n-C14 n-C18 n-C22 n-C26 n-C29
(a)
n-C14 to n-C22
104
their δD values are probably representative of the original OM source for n-alkanes. The
average δD values for the n-alkanes were calculated for n-C14 to n-C22 (Table 6.2) since
these compounds are most affected by biodegradation. The δD of isoprenoids (average
of Pr and Ph) are shown in Table 6.2. A difference in δD values between isoprenoids and
n-alkanes represented as ∆δ, has been calculated by subtracting the average δD of LMW
n-alkanes from the average δD of Pr and Ph (Table 6.2). Interestingly the oils show a
large ∆δ offset between the n-alkanes and isoprenoids. These oils were shown to be the
most biodegraded on the basis of molecular compositional differences (API gravity,
isoprenoids/ n-alkanes). The plots of ∆δ against API values and Pr/n-C17 is shown in Fig.
6.5 and shows a good correlation (R2 = 0.86 and R2 = 0.67, respectively) also consistent
with an increase in biodegradation as these parameters decrease and increase,
respectively. It appears that the n-alkanes have been fractionated during biodegradation,
the order of difference being consistent with that reported for microbes, whereby
molecules containing the lighter isotope (i.e. H) are preferentially consumed, leading to
enrichment in D for the residual components, i.e. n-alkanes [202]. The δD values for the
isoprenoids (Pr and Ph) are fairly similar for all the oils and therefore do not appear to
have been affected by biodegradation. For the least biodegraded oil, Pindori-4 (Table
6.2), high API gravity and the similar δD values for n-alkanes, Pr and Ph are consistent
with trends reported for non-biodegraded oils [197]. On the other hand, the largest ∆δ
offset (35‰) and lowest API value is observed for the Minwal-1 oil, which is the most
biodegraded oil of the suite. The other oils fall between these two end-members. Using
molecular parameters to assess light to moderate biodegradation levels of oils is difficult
because components are removed in a quasi-stepwise fashion. This study shows that δD
differences for n-alkanes and isoprenoids, together with molecular parameters can be
used to assess low biodegradation levels (2-3) of petroleum.
105
-40
-30
-20
-10
0
10
10 15 20 25 30 35 40 45
API
∆δD
isop
reno
ids-
n-al
kane
s (‰
)(a)
-40
-30
-20
-10
0
10
0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4
Pr/n -C17
∆δD
isop
reno
ids-
n-al
kane
s (‰
)
(b)
Fig. 6.5 Plot of δD(‰) difference between LMW n-alkanes (n-C14 - n-C22) and
isoprenoids vs. (a) API gravity, and (b) Pr/n-C17
106
6.2.4 Effects of Biodegradation on PAHs
6.2.4.1 Alkylnaphthalenes
The biodegradation susceptibility of PAHs and their alkyl analogous is often
more complicated to discuss than that of aliphatic hydrocarbons. Certain aromatic
hydrocarbons isomers are more affected towards biodegradation than others [15,41,43].
Combination of mass chromatograms from aromatic fractions for the dimethyl- (DMNs),
trimethyl- (TMNs) and tetramethyl- naphthalenes (TeMNs) of selected least to most
biodegraded samples are shown in Fig. 6.6. The depletion in aromatic hydrocarbons can
be seen from the relative intensities of various aromatic compounds by biodegradation
identified in the aromatic fractions (Fig. 6.6). Methylnaphthalenes (MNs) appear to be
the highly susceptible alkylnaphthalenes based on their decrease in relative intensities
compared to other alkylnaphthalenes biodegradation increases. A significant depletion in
the 2-MN isomer relative to the 1-MN isomer is observed with rise in levels of
biodegradation (Fig. 6.7). Similar trends can also be seen for other higher
alkylnaphthalenes i.e. DMN, TMN and TeMN isomers (Fig. 6.6) at the higher
biodegradation levels. It indicates DMNs are more depleted by biodegradation than
TMNs and TMNs show more depletion to biodegradation than TeMNs. This
biodegradation susceptibility sequence between alkylnaphthalenes (DMNs, TMNs and
TeMNs) showed similar trends reported in previous results [41]. With in the DMNs, the
2,6-DMN is more susceptible to biodegradation than similar isomer i.e. 2,7-DMN (Figs.
6.6a and b). In highly biodegraded sample from the set of oils (level-3, Minwal-1, Fig.
6.6c), the 2,7- and 2,6- isomers are significantly altered in DMNs and the 1,7-DMN and
1,3-DMN appear to be the highly resistant to the biodegradation. Biodegradation
susceptibilities of aromatic hydrocarbons have been reported by laboratory simulation
and reservoir studies [see 45]. It has been reported that the 2,6- and 2,7-DMNs indicate
similar susceptibility towards biodegradation. The sequence of susceptibility to the
biodegradation for DMNs (Fig. 6.7) relates to the thermodynamic stability of the
isomers. For TMN isomers, similar biodegradation affects to the DMNs observed (Fig.
6.6). The 1,3,7-, 1,6,7- and 1,3,6- isomers from TMNs indicate to be more depleted to
biodegradation than the 1,2,4-TMN and 1,2.5-TMN
107
Fig. 6.6 Biodegradation susceptibility for alkylnaphthalene distributions (m/z
156+170+184; dimethylnaphthalenes, DMNs; trimethylnaphthalenes, TMNs;
tetramethylnaphthalenes, TeMNs). Numbers on each peak refer to respective
alkylnaphthalene isomer and highlighted peaks show isomer components
most affected by rising biodegradation.
Relative retention time (min)
1,7+ 2,7 1,3
1,6
2,6
1,4+2,3
1,5
1,2
1,3,6 2,3,6
1,3,7
1,3,5 +1,4,6 1,6,7
1,2,6
1,2,5
1,2,7
1,2,4
1,3,5,7
1,3,6,7
1,2,4,6 1,2,4,7 1,4,6,7
2,3,6,7
1,2,5,7
1,2,6,7
1,2,5,6
1,2,3,5
1,2,3,6
DMNs m/z: 156 TMNs
TeMNs
m/z: 170 m/z: 184
(a) P2-Missakeswal
(b) P5-Rajian
(c) P11-Minwal
1,2,3,7
40 42 44 46 48 50 52
108
Fig. 6.7 Order of susceptibility of alkylnaphthalenes and alkylphenanthrenes to microbial attack in the Potwar Basin crude oils (cf. [15]). Numbers refer to positions of methyl substituents. Ternary plot was plotted using similar conditions for analysis and identifications as reported by van Aarssen et al. [38] for TMNr (1,3,7/1,3,7+1,2,5)-TMNs, TeMNr (1,3,6,7/1,3,6,7+(1,2,5,6+1,2,3,5)-TeMNs and PMNr (1,2,4,5,7/1,2,4,5,7+1,2,3,5,6)-PMNs.
MNs 2>1
DMNs
2,6>2,7~1,6>1,4+2,3>1,2 >~1,5~1,3+1,7
TMNs 1,3,7>1,6,7>1,3,6~1,4,6+1,3,5>1,2,6>1,2,7>2,3,6>1,2,5>1,2,4
TeMNs
1,3,6,7>>2,3,6,7>1,2,6,7>1,2,5,7~1,2,4,6+1,2,4,7+1,4,6,7>1,2,5,6+1,2,3,5~1,2,3,7>1,2,3,6~1,3,5,7
MPs
2>3>9~1
DMPs 2,7~2,6+3,5>2,3~1,7>2,10+3,10+1,3+3,9~1,8~1,9+4,9+4,10>1,2~2,9+1,6+2,5
Most Susceptible Least Susceptible
PMNr
TeMNrTMNr
109
isomers (Fig.6.6). Fisher et al. [41] reported a significant abundance of the 1,3,6-TMN in
a minor biodegraded oil while Huang et al. [42] reported the 2,3,6-TMN as being the
highly susceptible isomer to biodegradation from reservoirs studies. For the Potwar
Basin oil samples, the order of most to least biodegradation susceptibility for the TMNs
is 1,3,7- & 1,6,7- > 1,3,6-. The exception of the 1,2,4- and 1,2,5-TMN isomers,
generally TMNs show a decrease in relative intensity with rising biodegradation (Figs.
6.6b and c). With in TeMNs, most of the isomers are not altered during biodegradation
with out few exceptions. The most resistant TeMN isomer in the Potwar Basin oils to
biodegradation is the 1,3,5,7-TeMN isomer and the least resistant the 1,3,6,7-TeMN
isomer, consistent with the data reported by Fisher et al. [41]. However, slight
differences in the relative intensities of some the TeMNs peaks are showing changed
with rise in the biodegradation (Fig. 6.7). These observations indicate biodegradation
level for the Potwar oils to be at a minor level of biodegradation.
The susceptibility sequence to the biodegradation of various isomers of
naphthalene is reported in Fig. 6.7. Fisher et al. [41] proposed different
polymethylnaphthalene ratios to determine the biodegradation level in a number of
coastal sediments. They were designated those ratios by different names, DMN
biodegradation ratio (DBR: 1,6-DMN/1,5-DMN), TMN biodegradation ratio
(TBR:1,3,6-TMN/1,2,4-TMN) and TeMN biodegradation ratio (TeBR: 1,3,6,7-
TeMN/1,3,5,6-TeMN) indicating affective assessment for biodegradation samples up to
about level 6 of biodegradation. In the Potwar Basin oils, the effect of biodegradation
appears to be light, up to about a level of 3. In light of this biodegradation sequence we
are proposing different methylnaphthalenes biodegradation ratios (MBRs) to determine
the low level biodegradation particularly in oil samples. These MBRs ratios were
calculated by dividing the area of the most susceptible isomer from respective methyl
naphthalenes to the least susceptible methyl naphthalene isomer and are shown in Table
6.3. It is noteworthy to observe that isomers which are structurally similar were applied
in these Biodegradation Ratios (BRs) from every alkylnaphthalenes. It contains DMN
biodegradation ratio (DNBR: 1,6-DMN/1,2-DMN), TMN biodegradation ratio (TNBR:
1,3,7-TMN/1,2,7-TMN) and TeMN biodegradation ratio (TeNBR: 1,3,6,7-
TeMN/1,3,5,7-TeMN) (Table 6.3). Although these alkylnaphthalene isomers are
110
Table 6.3 Biodegradation ratios (BR) and alkylnaphthalenes ternary plot ratios. Oil# Name
Biodeg. Level*
DNBRa
TNBRb
TeNBRc
TMNrd TeMNre
PMNrf
P14 Pindori-4 0 6.5 5.7 2.3 0.85 0.82 0.60 P2 Missakeswal-1 0 5.8 5.0 1.6 0.81 0.80 0.59 P13 Turkwal-1 1 4.4 4.9 1.4 0.77 0.79 0.57 P7 Kal-2 2 5.1 3.9 1.0 0.70 0.71 0.49 P5 Rajian-3A 2 4.6 3.4 0.8 0.64 0.70 0.47 P10 Chaknaurang-1A 3 3.9 2.3 0.6 n.d. n.d. n.d. P11 Minwal-1 3 3.8 2.1 0.4 0.46 0.51 0.39 P12 Joyamir-4 3 4.2 2.1 0.4 n.d. n.d. n.d. *: from Table 5.5. a DNBR: dimethylnaphthalene biodegradation ratio; 1,6-DMN / 1,2-DMN b TNBR: trimethylnaphthalene biodegradation ratio; 1,3,7-TMN / 1,2,7-TMN c TeNBR: tetramethylnaphthalene biodegradation ratio; 1,3,6,7-TeMN / 1,3,5,7-TeMN d TMNr: (1,3,7 / 1,3,7+1,2,5)-trimethylnaphthalenes [38] e TeMNr: (1,3,6,7 / 1,3,6,7+(1,2,5,6+1,2,3,5)-tetramethylnaphthalenes [38] f PMNr: (1,2,4,5,7 / 1,2,4,5,7+1,2,3,5,6)-pentamethylnaphthalenes [38] n.d.: not determined
111
Fig. 6.8 Polymethylnaphthalenes biodegradation ratios vs. Pr/n-C17 showed a good
correlation. A significant decrease in DNBR, TNBR and TeNBR is observed.
3.0
4.0
5.0
6.0
7.0
0.4 0.6 0.8 1.0 1.2 1.4
Pr/n-C17
DN
BR
(1,6
/1,2
)
1.0
2.0
3.0
4.0
5.0
6.0
0.4 0.6 0.8 1.0 1.2 1.4
Pr/n-C17
TNB
R (1
,3,7
/1,2
,7)
0.0
0.5
1.0
1.5
2.0
2.5
0.40 0.60 0.80 1.00 1.20 1.40
Pr/n-C17
(TeN
BR
(1,3
,6,7
/1,3
,5,7
)
112
structurally similar they tend to show a significant difference in susceptibility to
biodegradation (Figs. 6.7 and 6.8). The plots were drawn between these biodegradation
ratios and Pr/n-C17 (Fig. 6.8). Each plot shows a good correlation with Pr/n-C17 (R2 for
DNBR, 0.83; TNBR, 0.88; TeNBR, 0.96). The isomers which appear to have a higher
resistance to biodegradation have greater steric hindrance than those with less resistance
to biodegradation. For example, the most resistant, the 1,2-DMN isomer, has methyl
substitutions on adjacent carbon atoms, while the least resistant 1,6-DMN isomer has the
methyl groups positioned well apart. Similar results are observed for TNBR and TeNBR
[41].
Van Aarssen et al., [38] developed a ternary diagram to illustrate the effect of
maturity, biodegradation and mixing of oils, based on the distribution of
alkylnaphthalenes. It has been shown that alkylnaphthalene ratios (TMNr, TeMNr and
PMNr; see Fig.6.7 for definitions) affected by biodegradation plot away from the
maturity centre of the ternary plot. The alkylnaphthalene ratios for the Potwar Basin oils
(TMNr; TeMNr and PMNr; Table 6.3; c.f. [38]) were plotted in a ternary diagram (Fig.
6.7). The order of susceptibility to biodegradation for the isomers used in TMNr is 1,3,7-
TMN > 1,2,5-TMN and for the TeMNr isomers 1,3,6,7-TeMN > 1,2,5,6-TeMN and
1,2,3,5-TeMN (Fig. 6.7). Hence, biodegradation led to a decrease in the TMNr and
TeMNr values (Fig. 6.7). These results support a low level of biodegradation for the
Potwar Basin oils.
6.2.4.2 Alkylphenanthrenes
The affects of biodegradation on alkylphenanthrenes were reported using
variations in the distribution of methylphenanthrenes (MPs) and dimethylphenanthrenes
(DMPs). Combined representative chromatograms for the MPs and the DMPs from non-
biodegraded to minor biodegraded oil samples are shown in Fig. 6.9. The relative
intensity of the MPs compare to the DMPs is decreases with increase in biodegradation
(Fig. 6.9) that indicates MPs showed less resistance to biodegradation than the DMPs. It
shows that increase in alkylation on aromatic rings results in the decrease in
susceptibility to biodegradation which is consistent with previous studies [14,41,44,192].
113
29
1,3+2,10+
2,5+2,9+1,6
1,7
2,3
1,8 1,2
m/z: 192 m/z: 2063,9+3,10
(a) P2:Missakeswal-1
(b) P5:Rajian-3A
(c) P11:Minwal-1
Relative retention time (min)
MPs DMPs
3,5+2,6
2,7
31
1,9+4,9+4,10
59 61 63 65
Fig. 6.9 A combined chromatogram of MPs and DMPs (m/z: 192 + 206) shows
decrease in relative intensity with in increase in biodegradations. The
numbers on peaks indicate the respective alkyl substituted isomer of
phenanthrene and highlighted peaks show significant depletion as move to
more biodegraded sample.
Rel
ativ
e in
tens
ity
114
For the MPs isomers, it is observed that the 2-MP isomer is less resistant to
biodegradation while the 9-MP and 1-MP isomers show higher resistance to
biodegradation. The relative intensity of the 9-MP increases with increase in
biodegradation as moved from top to bottom in Fig. 6.9 while relative intensity of the 2-
MP and 3-MP isomers decreases. For the DMPs isomers, the susceptibility to the
biodegradation of the individual isomers is less clear due to large number of possible
isomers and coelution of different substitution isomers on common stationary phases
(Fig. 6.9). But rate of depletion for each peak is found considerable and most to least
susceptible order for DMPs is given in Fig. 6.7. The 2,7-DMP, 2,6+3,5-DMPs and the
2,3-DMP isomers are depleted faster than from all DMPs isomers as move from non-
biodegraded to minor biodegraded oil samples (Fig. 6.9). In minor biodegraded oil
sample (Fig. 6.9c) the four coeluted isomers (1,3+2,10+3,9+3,10-DMPs) peak observed
degraded relative to following peak representing the 2,5+2,9+1,6-DMPs isomers which
are most resistant to biodegradation indicated by continuous increase in relative intensity
with increase in biodegradation (Fig. 6.9). The susceptibility order for DMPs (Fig. 6.7)
is consistent with field study of Chinese biodegraded oils [43] while contradiction is
observed from laboratory biodegradation study [128] where 2,7-DMP was the most
refractory isomer to the biodegradation. It shows that affects of minor biodegradation
(up to level 3) on the MP and DMP isomers are not severe and only slight depletion is
observed across the biodegradation sequences (Fig. 6.9).
CONCLUSIONS
The δD values of selected aliphatic hydrocarbons (n-alkanes and isoprenoids)
in eight crude oils of similar thermal maturity from the Potwar Basin, Pakistan have
been measured. High Pr/n-C17 and Ph/n-C18 values and low API gravity values of some
of the oils are consistent with relatively low levels of biodegradation up to level 3. There
is no indication of mixing, based on various known molecular parameters. The δD
values for the LMW n-alkanes relative to the isoprenoids were found to be enriched in D
because of the removal of D-depleted LMW n-alkanes. The ∆δ between the n-alkanes
and isoprenoids of the most biodegraded oil was found to be as much as 35‰. A
115
significant change in the alkylnaphthalene and alkylphenanthrene distributions is used to
assess the affects of biodegradation on individual isomers. Different biodegradation
ratios were successfully purposed i.e. dimethylnaphthalene Biodegradation ratio
(DNBR: 1,6/1,2), Trimethylnaphthalene biodegradation ratio (TNBR: 1,3,7/1,2,7) and
Tetramethylnaphthalene biodegradation ratio (TeNBR: 1,3,6,7/1,3,5,7) showed
significant variation in values with increase in biodegradation indicate a valuable
parameters for the assessment of low level of biodegradation.
The affects of biodegradation on methyl and dimethylphenanthrenes showed
that with increase in alkylation of phenanthrene decrease in biodegradation extent is
observed in Potwar Basin crude oils.
____
116
Chapter - 7
GEOSYNTHESIS OF HETEROCYCLIC AROMATIC HYDROCARBONS AND FLUORENES
BY CARBON CATALYSIS ABSTRACT
Laboratory experiments have shown that activated carbon catalyses the reactions
of biphenyls (BPs) with surface adsorbed reactants that incorporate S, O, N or methylene
forming some common constituents of sedimentary OM namely, dibenzothiophene
(DBT, XXVII), dibenzofuran (DBF, XXV), carbazole (C, XXVI) and fluorene (F,
XXVIII). A relationship between the % abundance of the hetero element in kerogen and
the abundance of the related heterocyclic compound in the associated soluble organic
matter supports the hypothesis that these reactions occur in nature. More specific
supporting evidence was obtained from the good correlation observed between methyl
and dimethyl isomers of the reactant BPs and the methyl and dimethyl isomers of the
proposed product heterocyclics compounds.
It is suggested that these heterocyclic aromatic hydrocarbons distributions
reported for sediments and crude oils from the Kohat Basin (Pakistan) and Carnarvon
Basin (Australia) are the result of a catalytic reactions of compounds with BP ring
systems and surface adsorbed species of the hetero element on the surface of
carbonaceous material. Furthermore, the abundances of these compounds (DBT, DBF
and BP) show similar concentration profiles throughout the Kohat Basin sediments
suggesting that share a common source. These compounds also correlate well with
changes in the paleoredox conditions. These data tends to point towards a common
precursor perhaps lignin phenols of land plants. Coupling of phenols leads to BP, which
has been demonstrated in our laboratory experiments to be the source of C, DBT, DBF,
and F.
117
7.1 INTRODUCTION
Heterocyclic aromatic compounds occur widely in sediments and petroleum
[6,12,50-51,131]. The common members of this group include, dibenzothiophenes
(DBTs), dibenzofurans (DBFs) and carbazoles (Cs). These compounds comprise a BP
cyclic ring system with incorporation of a hetero-atom forming a third five-membered
ring. It is convenient for the purposes of this study to include the fluorenes (Fs) in this
group although in this case it is carbon which forms the third ring. It is require to
evaluate that all these compounds show similar arrangements of structure except
difference in heteroatoms. The mechanism of formation of these structurally similar
compounds has not been reported, although their abundance in sediments and crude oils
has been related to depositional environments [12,51,215], thermal maturity [37,56],
source organic facies [6,131,216], and migration effects [57]. A brief overview of these
suggestions now follows.
The changes in relative abundances of benzothiophenes (BTs) and DBTs has been
the basis for proposed thermal maturity indicators for OM [52,165,217]. The high
abundances of DBF and alkylated DBFs in coals led to the suggestion of their
relationship with oxidative degradation [54] and their terrestrial origin from lower
vascular plants, fungi and lichens [6]. The difference in distribution of DBF and
alkylated DBFs has also been reported changes in lithology and thermal maturity
[36,55]. Relative abundances of DBFs and DBTs have been reported in different
depositional environments where marine carbonates show higher amounts of DBT while
freshwater/lacustrine sediments show higher amounts of DBFs [12-13]. Fenton et al.
[215] reported a high relative abundance of DBT, DBF and BP in a Permian/Triassic
section from East Greenland. Their abundances coincide with a shift in δ34S of pyrite as
well as with the disappearance of the major vegetation types occurring during the
Permian/Triassic mass extinction event. In the latter study, the compounds have been
suggested to be derived from the same precursor i.e. lignin phenols, BP is formed
through phenol coupling. DBT and DBF have been suggested to have formed through
reaction of BP with S and O species [215]. Pyrrolic N containing compounds in
118
petroleum have been suggested as indicators of migration [57]. Less work has been done
on occurrence and distribution of Cs in sedimentary OM. The source of pyrrolic N has
been reported as facies dependent and concentration of both Cs and benzocarbazoles
(BCs) increases with rise in thermal maturity [50-51,216]. While contrasting results have
been reported from Canadian oils indicating thermal maturity and depositional
environment show no effect on the distribution of Cs [56]. The geochemical significance
of Fs is not well known except those reported in a few oil correlation studies [12-13]
while alkylated Fs are not yet reported in any from of sedimentary OM. These
contrasting concentrations and the relative distributions of heterocyclic aromatic
hydrocarbons in sediments and crude oils may be due to lack of knowledge about the
source and mechanism of formation of these compounds.
In this chapter, number of evidence reported for the geosynthesis of
heterocyclics aromatic hydrocarbons. The formation of DBTs, DBFs, Cs and Fs is
shown to occur in laboratory experiments through carbon surface reactions to introduce
a third ring in BPs. Evidence that these conversions have also occurred in sediments is
provided by relative abundance data showing precursor product relationship between
BPs and the heterocyclic compounds in crude oils and sediments reported from the
Kohat Basin (Pakistan). Distribution of heterocyclic aromatic hydrocarbons were
reported from the Carnarvon Basin, Australia crude oils to show the global feature of
this hypothesis i.e. precursor product relationship between BPs and heterocyclics.
Furthermore, abundances of DBT, BP, C and DBF throughout the Kohat Basin
(Pakistan) sediments have been measured and compared with δ34S of pyrite minerals and
pristane to phytane (Pr/Ph) ratio to establish their relationship with the paleoeredox
conditions. Paleoredox conditions appear to play a role in the formation of these
components and the availability of the hetero atom to undergo carbon surface catalysis.
7.2 RESULTS AND DISCUSSION
Evidence that the solid–state carbonaceous material promotes chemical
reactions in sediments has been suggested from data obtained from hydrogen exchange
119
reactions between hydrocarbons [81]. Here data and results are reported from laboratory
experiments showing reactions of S, O, N and C species on carbonaceous surfaces with
BPs form the heterocyclic and F ring systems. Distribution association is observed
between heterocyclics and BPs in sediments and crude oils revealed that kerogen is
catalysing such reactions in sedimentary OM.
7.2.1 Laboratory Experiments on Activated Carbon
Laboratory experiments have shown that carbon surfaces catalyse the reaction
between BP and surface reactants. Mass chromatograms (Fig. 7.1) of the reaction
products from heating experiments with activated carbon at 300 °C in deactivated,
evacuated glass tubes indicate significant concentrations of each of the compounds of
interest in the reaction products. Blank experiments without carbon (Fig. 7.1 blanks)
showed no significant products and activated carbon when heated alone gave no
products.
The carbon catalysed formation of DBT from reaction of BP and elemental S
under these reaction conditions is shown in Fig. 7.1a. The reaction was repeated by
replacing activated carbon with sub-bituminous coal and again a significant abundance
of DBT was observed (see below). This surface reaction extend by providing sources of
reactive O, N and C for reaction with BP. Fig. 1(b) shows a chromatogram indicating
formation of DBF. The surface O was provided to the activated carbon by molecular
oxygen [84]. This experiment was carried out after sealing the reaction tube without
evacuation to provide a source of O contained in air. Reaction of BP with surface N was
made possible by using sodium azide [218]. The reaction product contained both
aminobiphenyl and C as shown in Fig. 1(c). The reaction of 1,2,3,4- tetramethylbenzene
with BP under the same reaction conditions that resulted in formation of the heterocyclic
products from O and N donors produced F and MBP isomers as shown in Fig. 1(d).
A set of these experiments have also been carried out replacing activated carbon
with crushed coal. GC-MS analysis of the reaction products under these reaction
conditions with coal is shown in Fig. 7.2a. Clearly the S species in the presence of coal
120
28 32 36 40 28 32 36 40
Blanks
a) AC, BP , S
b) AC, BP, Oxygen (Air)
d) AC, BP, TMBMBPs
23
4
c) AC, BP, sodium azide
Relative retention times
S
O
NH
NH2
Fig. 7.1 Total ion chromatograms (TIC) of extracts from laboratory heating
experiments. Samples were heated at 300 °C for 16 hr. Each blank experiment was identical in composition, temperature and time but without activated carbon. AC, activated carbon; BP, biphenyl; S, sulfur; TMB, 1,2,3,4-tetramethylbenzene; MBPs, methylbiphenyls.
121
reacted with BP to produce DBT. Similar type of reaction was repeated where N species
reacted with BP at a reaction temperature of 270 °C. The chromatogram of the reaction
products showed significant C compared with that from the blank experiment (Fig.
7.2b). These results indicate that carbonaceous surfaces other than activated carbon
facilitate these reactions.
A similar experiment using activated carbon with 3-MBP was carried at
different heating temperatures from 200 °C to 300 °C. GC-MS chromatograms of
experiment extract showed the presence of 4-MDBT and 2-MDBT (Fig. 7.3). At low
heating temperatures the 2-MDBT isomer showed higher abundance while with increase
in heating temperature of reaction produced higher concentration of 4-MDBT. Blank
experiments without activated carbon gave no significant MDBTs. The reaction has
inserted S into the BP ring system without isomerization of the methyl group suggesting
that 1-MDBT and 3-MDBT would be formed from reaction of 2- and 4- MBP
respectively. The systematic change in the relative abundances of product with increase
in reaction temperature suggests that the position of the methyl substituent influences the
reaction energy of activation. This surface reaction at higher reaction temperatures
favours the formation of the heterocyclic compound with the methyl substituent adjacent
to the heteroatom. The preferential position of S addition to the BP system is an
important feature of the process that can also be recognized in the formation of DBTs
under natural conditions in sediments.
7.2.1.1 Probable mechanism of geosynthesis reactions
Catalysis by carbon surfaces is a known process [84,99] and formation of
active adsorbed surface reactants involves free radical reactions. Since carbon surfaces
have low polarity but are electrical conductors the reactions they facilitate are more
likely to involve radical rather than ionic intermediates. In this section possible reaction
intermediate and pathways for the formation of heterocyclic aromatic hydrocarbons and
fluorenes are reported with laboratory experiments results as evidenced obtained from
carbon catalyses surface reactions.
122
Dibenzothiophene
Blank
28 30 32 34 36 38Relative retention time (min)
Carbazole
BP
2-aminobiphenyl
Blank
a) Coal, BP,S
b) Coal, BP, sodium azide
Fig. 7.2 TICs of extracts from laboratory heating experiments at temperature 270
°C for16 hr. Each blank experiment was identical in composition,
temperature and time but without coal, BP, biphenyl; S, sulfur.
123
200°C
225°C
250°C
300°C
4-MDBT
2-MDBT
38.5 39.0 39.5 40.0Relative retention time
m/z :198
S
S
Fig. 7.3 Mass chromatograms (m/z: 198) of the extract of heating experiments of 3-
MBP with elemental S in the presence of active carbon at different
temperatures.
124
It is interesting to observe that both methylation of BP and methylene
substitution of BP to yield MBP isomers and F are present in extract of laboratory
reaction of BP and TMB (Fig. 7.4b). This formation of MBPs and F from BP could
involve surface carbenoid (or carbene) species [219]. A similar distribution of these
products resulted when the TMB was substituted with nonyl amine (Fig. 7.a) or
acetonitrile (Fig. 7.4c) indicating that the reactive methylene species can be formed
on the solid carbon surface by methylene abstraction from different compound types.
The formation of C from BP could similarly involve a nitrogen radical species such
as nitrene [220] by direct insertion or via 2-aminobiphenyl (Fig. 7.1c). A similar set
of radical processes appear to be responsible for formation of DBF from BP and
adsorbed oxygen. The proposed reaction sequence for formation of these compounds
is shown in Fig. 7.5.
7.2.2 Distribution of Heterocyclic Aromatic Hydrocarbon in
Sediments and Crude Oils
In order to asses the likelihood that the precursor-product relationships
observed in the laboratory experiments have also occurred in sedimentary OM
relative abundances of the parent compounds (non-alkylated) and their proposed
products have been examined in sediments and crude oils. Both the parent
(unsubstituted) and methyl substituted isomers of these compounds are common
constituents in sediments and crude oils.
7.2.2.1 Parent compounds
A sequence of sediments from the Kohat Basin, Pakistan have been
analysed for heterocyclic aromatic hydrocarbons. The quantitative measurements
were performed by comparing peak areas of compounds (BP, DBT, DBF, F, C) with
deuteriated phenanthrene and reported in Table 7.1. Fig. 7.6 shows the relationships
between the concentrations of the BP and the heterocyclic aromatic hydrocarbons
and F in these sediments. Formation of DBT, DBF, C and F support the
interpretation that BP is related to the formation of this group of compounds by its
reaction with a species containing the hetero element contained in the kerogen. The
abundance of O and S species vary significantly with depositional environments and
125
28 30 32 34
a) AC, BP, nonyl amine
b) AC, BP, TMB
c) AC, BP, Acetonitrile
Fluorene
Fluorene
Fluorene
MBPs
2-
3- 4-
BP
Relative retention time
Fig. 7.4 TICs of extract of heating experiments of BP with activated carbon using
different alkyl precursor compounds, heating temperature and duration
was same for all experiments i.e. 300 °C and 16 hr. AC, activated carbon;
BP, biphenyl; MBPs, methylbiphenyls; TMB, 1,2,3,4-tetramethylbenzene.
126
NH
O
:CH2
(NaN3)
O2 (Air)
AC
OH
NH2
CH3
BP
DBF
C
F
:NH2
AC
AC
SHS AC
S?
DBT
Fig. 7.5 Purposed reaction pathways on activated carbon for formation of heterocyclic aromatic compounds and F from BP. AC, activated
carbon; S: sulfur; BP, biphenyl; F, fluorene; DBT, dibenzothiophene; DBF, dibenzofuran; C, carbazole.
127
Table 7.1 Concentrations of compounds and elemental kerogen composition for Kohat
Basin sediments.
Samples Concentration (µg/g TOC) Elemental composition (%)
No Depth BP DBT DBF C F S O N
S1 4290-92 2.88 8.52 0.51 - 1.05 4.3 12.53 0.12
S2 4310-15 1.06 2.66 0.19 0.12 0.33 2.1 11.11 0.10
S3 4345-70 2.23 6.78 0.50 0.80 1.14 n.d. n.d. n.d.
S5 4510-12 0.22 0.74 0.05 0.07 0.12 0.3 27.28 0.01
S7 4650-52 1.80 3.67 0.38 0.25 0.71 n.d. n.d. n.d.
S8 4680-82 1.35 1.81 0.31 0.28 0.33 1.1 7.51 0.37
S10 4710-12 7.26 19.49 1.87 0.23 - n.d. n.d. n.d.
S12 4834-50 1.52 0.68 0.19 - 0.18 0.4 10.75 <0.01
S13 4860-62 2.01 3.29 0.47 0.19 0.89 1.7 14.37 0.11
S14 4940-42 0.27 0.31 0.10 - 0.14 1.7 3.39 0.03
BP, biphenyl; DBT, dibenzothiophene; DBF, dibenzofuran; C, carbazole; F, fluorene S: sulfur; O: oxygen; N: nitrogen -: below detection limit n.d.: not determined
128
abundant DBTs have been proposed to differentiate between marine and carbonate-
evaporate crude oils and sediments [167,171]. It has been reported that freshwater-
lacustrine oils showed higher abundance of DBFs than DBTs [6]. Fan et al. [12] reported
distribution relationship between DBT, DBF and F in a large suit of crude oils and
source rocks from different sedimentary environments. They have concluded that the
relative abundance of DBF and F was higher in freshwater environments while DBT was
higher in marine environments. The abundance of S in marine and carbonate-evaporate
environments and less abundance of S (hence more O) in freshwater-lacustrine
environments could be related in this scenario to that the formation of heterocyclic
aromatic hydrocarbons depend on the nature of kerogen surface species. The elemental
composition (%) of kerogen for S, O, and N was determined from similar suite of
sediments of Kohat Basin Pakistan and reported in Table 7.1. Plots of the % elemental
composition of the kerogen for the element that matches the hetero atom in each of the
compounds i.e. %S vs DBT; %O vs DBF and %N vs C is shown in Fig. 7.7. The plots
indicate clear relationship that increase in %age of S, O, N increases the concentrations
of DBT, DBF, C, respectively. The results suggest a probable relationship between the
solid state abundance of the hetero atom in the kerogen and the organic compound
formed from it after reaction with BP (or a related precursor).
Abundant BP has been reported in kerogen bound structures [221] and
similarly BP acids and alcohols have been found in abundance in kerogen degradation
study from Moroccon Timahdit oil shale [222]. Insertion and chemical reaction of
heteroatomic species with biological precursors has been observed in various stages of
sedimentary OM [65,77-79]. These results showed that insertion reactions are going on
in sedimentary environments where kerogen surface heteroatoms and methylene species
reacted with BPs to synthesize heterocyclics aromatic hydrocarbons and F respectively.
129
R2 = 0.95
R2 = 0.76
R2 = 0.970
2
4
6
8
10
12
14
16
18
20
0 1 2 3 4 5 6 7 8
Concentration, Biphenyl (µg/g TOC)
Con
cent
ratio
ns (µ
g/g
TOC
DBT
F
DBF
Fig. 7.6 Relationship of reactant (BP)-product (DBT, DBF and F) for Kohat Basin
sediments (data given in Table 7.1).
130
0
2
4
6
8
10
0 1 2 3 4 5
Elemental S (%)
Conc
. DBT
(µg/
g TO
C)
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0 5 10 15 20 25 30
Elemental O (%)
Conc
. DBF
(µg/
g TO
C)
0.0
0.1
0.2
0.3
0.4
0.0 0.1 0.2 0.3 0.4
Elemental N (%)
Conc
, C (µ
g/g
TOC)
Fig. 7.7 Relationship between compounds in SOM and the N, S, and O
concentration of kerogen from each sample (data given in Table 7.1).
131
7.2.2.2 Methylated homologous of heterocyclics and Fs
In order to facilitate easy recognition of heterocyclic compounds with
substituents on similar positions in the carbon ring system to the BP structural systems
Table 7.2 has been included to show these relationships for both methyl and dimethyl
compounds.
The representative mass chromatograms in Fig. 7.8 obtained from the
aromatic fraction of Kohat Basin sediment (Depth, 4345 m) show the relative
abundances of MBPs, MDBT, MDBFs, MCs and MFs. The thermal maturity of the
sample is immature to early oil generation window as indicated by C32 hopane and C29
sterane isomerization ratios (0.43 and 0.43, respectively) and Tmax value (431 °C). The
most abundant methyl substituted isomers from DBTs (4-MDBT), DBFs (4-MDBF), Cs
(1-MC) and Fs (1-MF) show structure association with most abundant methylbiphenyl
(3-MBP). Similarly the least abundant methyl substituted isomers from each compound
class i.e. 1-MDBT, 1-MDBF, 4-MC, and 4-MF show structure association with least
abundant MBP isomer i.e. 2- (Fig. 7.8; Table 7.2). The compounds related with BP in a
reactant-product sense are indicated by symbols in Fig. 7.8. It is noteworthy that the
relative abundance results for methyl isomers of the BP reactant and the products
indicate that the hetero atomic elements (S, O, N) and methylene insertion occurred into
MBPs in sediments to produce corresponding methyl homologous of DBT, DBF, C and
F, respectively. Keumi et al. [223] reported the positional reactivity for DBF with
different species and showed that the reactivity of position 4 is minimum as less as 5%
of all possible four substitution positions in DBF (1, 2, 3 and 4). In contrast, the 4-
MDBF is the most abundant isomer from MDBFs in sediments (Fig. 7.8b) indicates
MDBFs are formed from MBPs by insertion of O species. While there is some evidence
for methylation of the aromatic rings during these surface catalysed reactions the
majority of methyl heterocycles are derived from the methyl substituted BPs rather than
by methylation of the parent heterocyclic compounds.
132
Table 7.2 Ring position relationships between BP and related heterocyclic compounds and Fs.
12
3
45
6
12
3456
2'3'
7
89
4'5'
6'1'
X
12
345
6
78 9
Z
X: S = DBTs
O = DBFsZ: NH = Cs
CH = Fs2
BPs DBTs & DBFs Cs & Fs
2 1 4
3 4; 2 1; 3
4 3 2
2,2' 1,9 4,5
2,3' 1,8; 1,6* 3,5; 1,5*
2,5 1,4 1,4
2,4 1,3 2,4
2,4' 1,7 2,5
2,3 1,2 3,4
3,5 2,4 1,3
3,3' 4,6; 2,8; 2,6* 1,8; 3,6; 1,6*
3,4' 3,6; 2,7 1,7; 2,6
4,4' 3,7 2,7
3,4 2,3; 3,4 1,2; 2,3 *: after rotation of phenyl ring along single bond
133
1-MFm/z: 180
3-MF
2-MF
4-MF9-MF
2-MBP
3-MBP
4-MBP
m/z :168
4-MDBF
3+2-MDBF
1-MDBF
m/z: 182
m/z: 1811-MC
2-MC
3-MC 4-MC
Relative retention times
m/z: 198 4-MDBT
3+2-MDBT
1-MDBT
(a) (b)
(c)
(d) (d)
Fig. 7.8 Representative ion chromatograms show relative distributions of MDBTs
(198), MDBFs (m/z: 182), MBPs (m/z: 168), MCs (m/z: 181) and MFs (m/z:
180) from the Kohat Basin, Pakistan sediment (Depth, 4345 m). Symbols
relate precursor-product compounds.
134
These relationships between methyl substituted BPs and methyl homologous of
DBT, DBF, C and F are also a feature of crude oils. Distribution of these compounds in
the crude oils from two different basins of the world (Pakistan and Australia) is also
reported (Fig. 7.9) along with sediments to illustrate the global features of carbon
catalyses formation of heterocyclic aromatics hydrocarbons.
Quantitative Relationship between MBPs and MDBTs in Sediments
The quantitative measurements were performed for MBPs and MDBTs
isomers from Kohat Basin sediments and reported in Table 7.3. The absolute abundance
relationship between the corresponding individual isomers of MBPs and MDBTs in
sediments is shown in Fig. 7.10a. The concentration of associated isomers of MBPs is
plotted against associated MDBTs isomers. It is observed that the concentration of
corresponding isomers increase together. The most abundant 4-MDBT concentration
increases with increase in concentration of 3-MBP. Similarly, the least abundant 1-
MDBT concentration showed similar increase in abundance with 2-MBP. The good
straight line relationships (R2, 0.98) indicate that the MDBTs showed product precursor
link to the MBPs in sediments. Moreover, the ratios between methyl substituted BP and
DBT to the parent compounds from the suite of sediment and crude oils are shown in
Table 7.3 and is shown in Fig. 7.10b. It is Interesting to observe that both ratios showed
an excellent linkage between their values. Where MBPs/BP ratio increases the
MDBTs/DBT ratio decreases and vice versa. It shows that the methyl substituted DBT
isomers are formed from methyl substituted BP isomers rather than methyl substitution
of parent compounds i.e. DBT and BP respectively. Similarly, the MBPs/BP and
MDBTs/DBT ratios for crude oils (Table 7.3) are also in same of range of sediments.
The significant abundance of DBTs in sediments from range of low to
medium maturity [4] and the relative distribution of MDBTs vary with OM type. The
results from Kohat Basin sediments are consistence that the geosynthesis of MDBTs
occurred by surface reactions where bonded S still present on the kerogen surface.
135
2-
3-
4-
2-
3-
4-
9-
2-
3-
1-
4- 9-2-
3-
1-
4-
1-
3+2-4-
1-
3+2-
4-
1-3-
2-
4-
a) Upper Indus Basin, Pakistan b) Carnarvon Basin, Australia
MBPs
MFs
MDBFs
MCs
Relative retention time
1-
3-2-
4-
Fig. 7.9 Distributions of MBPs and methyl homologues of DBF, C and F in crude oils
from two different basins. a) Chaknaurang, Upper Indus Basin, Pakistan; b) Barrow, Carnarvon Basin, NW Australia. MBPs (m/z 168), MFs (m/z 180), MDBFs (m/z 182) and MCs (m/z 181). Symbols relate precursor-product compounds.
136
Table 7.3 Concentration and compound ratios of sediments and crude Oils
Samples Concentration (µg/g TOC) Compound
ratios
No Depth
(m) 2-
MBP 3- MBP 4- MBP 4- MDBT
3-+2- MDBT 1-MDBT MBPs/
BP MDBTs/ DBT
S3 4345-70 0.38 2.95 1.53 7.42 6.05 3.35 2.2 2.5
S4 4410-40 0.03 0.73 0.31 2.03 1.12 0.53 0.4 4.1
S5 4510-12 0.00 0.24 0.13 1.55 0.95 0.45 1.7 4.0
S6 4534-60 0.02 0.39 0.18 1.99 1.26 0.61 0.3 5.4
S8 4680-82 0.05 1.28 0.67 2.96 1.91 0.80 1.5 3.1
S9 4690-92 0.10 1.68 0.89 3.63 2.59 1.35 4.6 2.1
S10 4710-12 0.97 9.23 4.69 20.91 16.03 8.52 2.1 2.3
S11 4741-42 0.00 0.01 0.01 0.40 0.29 0.11 0.1 3.1
S12 4834-50 0.02 0.65 0.35 0.87 0.59 0.22 0.7 2.5
S13 4860-62 0.00 2.06 1.08 3.25 2.42 1.30 1.7 2.1
S14 4940-42 0.00 0.22 0.16 0.20 0.14 0.03 1.4 1.2
P19 - - - - - - 0.9 2.0
P20 - - - - - - 1.9 3.4
P21 - - - - - - 1.9 3.6
P22 - - - - - - 2.1 3.0
-: not determined
137
MBiPhs vs MDBTs
R2 = 0.98
R2 = 0.98
R2 = 0.98
0
5
10
15
20
25
0 1 2 3 4 5 6 7 8 9 10
Methylbiphenyls (µg/g TOC)
Met
hyld
iben
zoth
ioph
enes
(µg/
g TO
C)
3-MBP vs 4-MDBT
4-MBP vs 2+3-MDBT
2-MBP vs1-MDBT
0
1
2
3
4
5
6
Depth (m)
Rat
io
MBP/BP
MDBT/DBT
4345 4410 4510 4534 4680 4690 4710 4741 4834 4860 4940
Fig.7.10 Relationship between MBPs and MDBTs in Kohat Basin sediments. a)
absolute concentration plot shows association between individual isomers of
MBPs and MDBTs. b) plot shows ratio of MBPs and MDBTs to the parent
BP and DBT in sediment samples.
(b)
138
7.2.2.3 Dimethyl homologous of heterocyclics and Fs
The product-precursor relationship can also be extended to the compounds with
two methyl substituents. This approach is however limited by availability of GC-MS
data to enable reliable identification of isomers. Data is available for DMBPs and DMCs
[49,224] however no data is available for DMFs or DMDBFs although I have been able
to obtain an authentic sample of 1,7-DMF. The relationships between DMBP isomers
and isomers of DMDBT, DMC and DMF are described from sediments and crude oils in
following sections.
a) DMBPs vs DMDBTs
Dimethyl homologues of DBT and BP have been showed a structure
relationship in natural sedimentary OM and comparison of substitution pattern between
BP and DBT structural system is shown in Table 7.2.
The relative distributions of DMBPs and DMDBTs in representative sediment
sample are shown in Fig. 7.11. The two most abundant DMBP isomers 3,4′- and 3,3′-
have the corresponding structural DMDBT isomers 3,6- and 4,6- as the most abundant.
At a lower level of relative abundance the 3,5- and 3,4-DMBP isomers have a similar
lower relative abundance pair of DMDBT isomers namely 2,4- and 3,4-. It is interesting
that the set of DMBPs with a substituents in position 2 have a corresponding set of
DMDBT isomers with substituents in position 1 (Table 7.2). Although a number of the
DMDBT isomers with this substitution pattern showed co-elution it is apparent that the
abundance of this group relative to the 4,6- and 3,6- isomers are in a similar proportion
to the set of 2- substituted biphenyls relative to the 3- substituted biphenyls (Fig. 7.11).
It is interesting that the two most abundant DMBP isomers namely 3,3′- and
3,4′- could form two DMDBT isomer additional to the high abundance 3,6- and 4,6-
DMDBT isomers discussed above. These are 2,8- and 2,7- isomers, neither isomer has
been reported in geochemical samples [181,225] and probably reflects a strong
preference for substitution of the sulfur reactive species at ring position
139
2,2' 2,6' 2-E
2,3'
2,5
2,4+2,4'
3,3'
2,33-E
3,5
3,4'
4,4'
3,4
Dimethylbiphenylsm/z:182
4-E
4,6 3,6
2,6
2,4 3,7
1,4+1,6+1,8
1,3
3,4
1,2+1,9
m/z:212Dimethyldibenzothiophenes
Relative retention times
Fig.7.11 Relative distribution of DMBPs and DMDBTs in Kohat Basin sediments
(depth, 4680 m). Numbers on peaks indicate dimethyl substituted isomers of
BP and DBT (Table 7.2). Symbols relate precursor-product compounds.
140
adjacent to the methyl substituents. In 3,3′-DMBP isomer the phenyl ring rotation
across the single bond followed by sulfur insertion is the probable source for the 2,6-
DMDBT isomer.
These relationships between methyl and dimethyl substituted BPs and DBTs
is a common feature of crude oils. Fig. 7.12 shows the distribution of these compounds
in the crude oils from Pakistan and Australia. Again the symbols indicate relationships
between BP isomers and the product DBT isomers derived from them. While the peak
patterns are a little different to those from the sediment extract (Fig. 7.8 and 7.11) the
relative abundances of isomers indicates a reactant-product relationship consistent with
that discussed above for the sediment samples
b) DMBPs vs DMCs and DMFs
DMCs and DMFs have been showed a structure relationship with DMBPs in
natural sedimentary OM and comparison of substitution pattern between C, F and BP
structural system is shown in Table 7.2. The relationships between DMBP isomers and
isomers of DMC and DMF apparent in the chromatograms shown in Fig. 7.13 for a
sediment extract from the Kohat Basin, Pakistan and the Griffin crude oil from
Australia.
In both samples the two most abundant DMBP isomers 3,3′- and 3,4′- have 1,8-
and 1,7- DMCs as the two most abundant DMC isomers (refer to Table 7.2. for
comparison of related substitution patterns in BP and the heterocyclic compounds).
Again this relationship is consistent with a carbon catalysed derivation of the DMCs
from DMBPs. Some preference for the position of substitution into the BP ring system is
indicated by the relative abundances of reaction products. 1,6-DMC is the next most
abundant isomer. It is a co-product from 3,3`-DMBP and, like 2,6-DMC the co-product
from 3,4`-DMBP, it has a lower abundance than the alternative product with a methyl at
position 1 indicating the preference for substitution of the hetero atom adjacent to a
methyl substituent. This is again the case for preferential formation of 1,2-DMC rather
than 2,3-DMC from 3,4-DMBP.
141
a) Kohat Basin, Pakistan
3,3'
3,4'
2,4+2,4'
3,5
2,3 4,4'
2,2' 2,6' 2,3'
4,6 3,6 DMDBTs 1,4+1,6+1,8
2,4 3,7 3.4
1,3 1,2+1,9
4,6
3,6 1,4+1,6+1,8 2,6 1,3+ 3.4 2,4 3,7
1,2+1,9
3 MBPs MDBTs
3+2
1 2
3 4
3+2
1
2
3,3'
3,4'
2,4+2,4' 3,4
2,3 4,4'
2,2' 2,6' 2,3'
2,53,4 2,5 3,5
DMBPs
b) Carnarvon Basin, Australia
44
4MBPs MDBTs
2,6
Reletive retention time
Fig.7.12 Relative distributions of methyl and dimethyl biphenyls and dibenzothiophenes in crude oils from two different basins. a) Mela-1, Kohat Basin, Pakistan, b) Wanaea, Carnarvan Basin, Australia. MBPs (m/z 168), DMBPs (m/z 182), MDBTs (m/z 198) and DMDBTs (m/z 212). Symbols relate precursor-product compounds.
142
2,3'
2,5
2,4+2,4' 2,33-E
3,5
3,3'3,4'
4,4'3,4
1,8
2,42,7+1,2
2,52,6
1,3
1,6
1,7
1,4+4-E1,5+3-E
Relative retention times
DMBPs
DMCs
2,2' 2,6' 2,3'
2,5
2,4+2,4' 2,33-E
3,5
3,3'3,4'
4,4'3,4
1,8
2,42,7 2,52,6
1,3
1,6
1,7 1,4+4-E1,5+3-E
1,2
Kohat Basin, Pakistan Carnarvon Basin, Australia
3,9 2,9
1,9
4,9EF
1,8
1,3
1,7
1,6
DMFs
3,9 2,9
1,94,9
EF
1,8 1,3 1,7
1,6
∆∆
∆
X
X
2,2'
∆
Fig. 7.13 Relative distribution of DMBPs (m/z: 182), DMCs (m/z: 195) and DMFs (m/z: 194) in the Kohat Basin sediment (Depth, 4940 m)
and the Carnarvon Basin Griffin crude oil. Numbers on peaks indicate dimethyl substituted isomers. Symbols show precursor-product relationships (Table 3).
143
In the case of DMFs only the 1,7- isomer has been identified using an authentic
sample. The other peak assignments have been made assuming that the effect of
changing the position of ring substitution of methyl groups on Cs has the same effect on
retention time as that for DBFs and can be used to predict the retention time of the DMF
isomers relative to the 1,7-DMF reference compound. Again the relationships in relative
abundance of these isomers to those of DMBP support the proposed formation
relationship.
The relative abundance of DMFs showed two set of dimethyl isomers where one
set showed tentatively identified 1,8-, 1,3- and 1,6- isomers including 1,7- isomer
identified using authentic standard while second set show lower abundance collectively
mark as X (Fig. 7.13). It can be seen that the 1,7- and 1,8-DMF isomers from both
sediment and oil sample indicate higher abundance show a structure association with
most abundant DMBP isomer, 3,4′- and 3,3′-. However, it is noteworthy that the small
relative abundance difference between 3,4′-DMBP isomer with 3,3′-DMBP isomer in
sediment sample could be related to the similar relative abundance difference of
corresponding structure associated dimethyl isomers of F, i.e. 1,7- and 1,8- respectively
(Fig. 7.13). While in case of oil sample this observation is reversed where 3,3′-DMBP
isomer is relatively higher than 3,4′-DMBP isomer showed same difference in relative
abundance of corresponding dimethyl isomers of F i.e. 1,8-DMF isomer is higher than
1,7-DMF isomer (Fig. 7.13). Similarly, next abundant 1,3-DMF showed structure and
relative abundance relationship with next abundant DMBPs isomer, 3,4′-. The relative
abundance of second set of dimethyl isomers of F indicated by X could be related to the
dimethyl isomers of BP having lower abundance i.e. 3,4-, 4,4′- (c.f. Table 7.2).
The relative abundance results between structure associated isomer of DMBPs
with DMCs and DMFs revealed that the hetero-atomic element (N) and methylene
insertion occurred into DMBPs in sediments and crude oils to produce corresponding
dimethyl homologous of C and F, respectively.
144
7.2.3 Paleoredox Conditions and Heterocyclics Formation
Fig. 7.14 displays the abundances of DBT, DBF, C and BP, Pr/Ph and δ34S with
depth for the Kohat Basin sediments. Since all the aromatic components tend to show
similar abundance profiles with depth suggests to indicate a common precursor. Given
that both the Carnarvon Basin crude oil and Kohat Basin sediments contain Type III
kerogen (terrestrial-derived OM) the most likely natural product precursor for BP is thus
suggested to be lignin phenol. A similar observation was made by Fenton et al. [215].
Lignin is a co-polymer comprised of phenyl–propenyl alcohols [226] and it is likely that
these phenolic compounds could be the precursor for BP, and BP is thus intermediate
source of DBT, DBF, C and F. However, other natural product precursor(s) can not be
fully excluded for BP precursor. δ34S of pyrite in the Kohat Basin samples support
changes in the paleoredox conditions of the water column. δ34S vary from –6.5 to -31.1
‰. The δ34S results (-17.9 to -31.1 ‰) are mostly in the range of expected for periodic
fluctuating dysoxic/euxinic depositional conditions [121,215]. These trends reflect the
variations in the isotopic composition of seawater sulfate and imply a change in the
sulfur cycle and a relative increase in the fraction of sulfur buried as pyrite. The sample
with a δ34S of -6.5 ‰ is where C shows a maximum concentration and this result can not
be explained. The exact source of the N present in C is unknown, but the availability of a
specific N source is key here. The other aromatic compounds, BP, DBT and DBF, show
a similar abundance profile with depth as observed by Fenton et al [215]. The redox
conditions during this period of time (based on δ34S of pyrite and Pr/Ph) would favour
the formation of DBF, DBT from BP. Anoxic/euxinic conditions are periodic, therefore
it is not unexpected to observe similar abundance profiles of DBT, DBF and BP with
depth. The samples will reflect an average of the seasonal redox conditions spanning
several millions of years.
145
Fig 7.14. δ34S(‰) of pyrite against concentrations of DBT, DBF, BP, C and Pr/Ph with depth in Kohat Basin sediments Pakistan.
4200
4300
4400
4500
4600
4700
4800
4900
5000
-35 -25 -15 -5
δ34S (‰)
Dep
th (m
)
0 5 10 15 20
Dibenzothiophene (µg/g TOC)0 0.5 1 1.5 2
Dibezofuran (µg/g TOC)0 0.5 1
Carbazole (µg/g TOC)0 2 4 6 8
Biphenyl (µg/g TOC)0.3 0.4 0.5 0.6 0.7
Pr/Ph
146
CONCLUSIONS
DBT, DBF, C and F have been shown to form by reactions of BP with surface
active S, O, N and methylene species on carbon surfaces when heated at 300 °C.
Evidence that similar reactions occur in sediments was shown by enhanced
formation of the heterocyclic compounds relative to biphenyls when the appropriate
hetero element was present in the kerogen. More specific evidence for a reactant-product
relationship between BPs and heterocyclics (and Fs) was obtained from a comparison of
the methylated compounds in sediments and crude oil. Methyl substituted BPs (both
mono and dimethyl) were shown to have an isomer abundance profile similar to that
predicted for methylated heterocyclics (and Fs).
A similar abundances of DBT, DBF and BP, together with Pr/Ph and δ34S of
pyrite for the Kohat Basin sediments of various depths suggest that these compounds
share a similar precursor. Given that the Kohat Basin sediments contain Type III kerogen,
the most likely natural product precursor is lignin phenol. Phenol coupling can lead to
BP, the intermediate precursor for DBT, DBF, C and F. δ34S of pyrite of the sediments
vary from –6.5 to -31.1 ‰, reflecting periodic fluctuations in the redox (anoxic/euxinic)
depositional conditions.
_____
147
REFERENCES
[1]. Hunt, J.M., 1995. Petroleum Geochemistry and Geology, W.H.Freeman and
Company, New York, pp 743.
[2]. Tissot, B.P., Welte, D.H., 1984. Petroleum formation and occurrence, 2nd Edition,
Speringer-verlag, Berlin. 699 pp.
[3]. Blumer, M., Youngblood, W.W., 1975. Polycyclic aromatic-hydrocarbons in soils
and recent sediments. Science 188, 53–55.
[4]. Radke, M., 1987. Organic geochemistry of aromatic hydrocarbons. In: Brooks, J.,
Welte, D. (Ed.), Advances in Petroleum Geochemistry, Academic Press, London.
[5]. Alexander, R., Larcher, A.V., Kagi, R.I., Price, P.L., 1992. An oil-source correlation
study using age specific plant-derived aromatic biomarkers. In: biological markers
in sediments and petroleum. Eds, Moldowan, J.M., Albrecht, P., Philp, R.P.,
Prentice Hall, Englewood Cliffs, N.J., 201-221.
[6]. Radke, M., Vriend, S.P., Ramanampisoa, L.R., 2000. Alkyldibenzofurans in
terrestrial rocks: influence of organic facies and maturation. Geochimica et
Cosmochimica Acta 64, 275–286.
[7]. Radke, M., Vriend, S.P., Schaefer, R.G., 2001. Geochemical characterization of
lower toarcian source rocks from NW Germany: interpretation of aromatic and
saturated hydrocarbons in relation to depositional environment and maturation
effects. Journal of Petroleum Geology 24, 287-307.
[8]. Hase, A., Hites, R.A., 1976. On the origin of polycyclic aromatic hydrocarbons in
recent sediments: biosythesis by anaerobic bacteria. Geochimica et
Cosmochimica Acta 40, 1141–1143.
[9]. Albrecht, P., Ourisson, G., 1971. Biogenic substances in sediments and fossils.
Angew Chem Internat Edit 10, 209-225.
[10]. Alexander, R., Kagi, R.I., Rowland, S.J., Sheppard, P.N., Chirila, T.V., 1985. The
effects of thermal maturity on distributions of dimethylnaphthalenes and
trimethylnaphthalenes in some ancient sediments and petroleums. Geochimica et
Cosmochimica Acta 49, 385–395.
148
[11]. Radke, M., Welte, D.H., Willsch, H., 1986. Maturity parameters based on aromatic
hydrocarbons: influence of the organic matter type. In: Leythaeuser, D.,
Rullkötter, J. (Eds.). Advances in Organic Geochemistry 1985, Pergamon Oxford,
Organic Geochemistry 10, 51–63.
[12]. Fan Pu, Philp, R.P., Zhenxi, L., Guangguo, Y., 1990. Geochemical characteristics of
aromatic hydrocarbons of crude oils and source rocks from different sedimentary
environments. Organic Geochemistry 16, 427-435.
[13]. Jinggui, L., Philp, P., Zifang, M., Wenhui, L., Jianjing, Z., Guojun, C., Mei, L.,
Wang, Z., 2005. Aromatic compounds in crude oils and source rocks and their
application to oil source correlations in Tarim Basin NW China. Journal of Asian
Earth Sciences 25, 251-268.
[14]. Connan, J., 1984. Biodegradation of crude oils in reservoirs. In: Brooks, J., Welte,
D.H. (Ed.), Advances in Petroleum Geochemistry vol. 1. Academic Press,
London, pp. 299–335.
[15]. Fisher, S. J., Alexander, R., Kagi, R.I., Oliver, G. A., 1998. Aromatic hydrocarbons
as indicator of biodegradation in north western Australian reservoirs: In Purcell,
P. G., Purcell, R. R. (Eds),The sedimentary basins of Western Australia 2:
Proceedings of Petroleum Exploration Society of Australia symposium, Perth,
WA, 185-194.
[16]. Ahmed, M., Smith, J.W., George, S.C., 1999. Effects of biodegradation on
Australian Permian coals. Organic Geochemistry 30, 1311–1322.
[17]. Asif, M., Grice, K., Fazeelat, T., 2009. Assessment of petroleum biodegradation
using stable hydrogen isotopes of individual saturated hydrocarbons and
polycyclic aromatic hydrocarbon distributions in oils from the Upper Indus Basin,
Pakistan. Organic Geochemistry 40, 301-311.
[18]. Eglinton, G., Murphy, M. T. J., 1969. Organic Geochemistry: Methods and Results.
Springer-Verlag, Berlin, 828 pp.
[19]. Strachan, M.G., Alexander, R., Kagi, R.I., 1988. Trimethylnaphthalenes in crude
oils and sediments: effects of source and maturity. Geochimica et Cosmochimica
Acta 52, 1255–1264.
149
[20]. Mair, B.J., 1964. Terpenoids, fatty acids and alcohols as materials for petroleum
hydrocarbons. Geochimica et Cosmochimica Acta 28, 1303–1321.
[21]. Bendoraitis J. G., 1974. Hydrocarbons of biogenic origin in petroleum-aromatic
triterpenes and bicyclic sesquiterpenes. In Advances in Organic Geochemistry
1973 Tissot, B., Bienner, F., (Eds.), pp. 209-224. Editions Technip, Paris.
[22]. Cane, R.F., 1976. The origin and formation of oil shale. In oil shale, development in
petroleum science, Eds, Yen T.F., Chilingrian, G.V., Harward, London. 203-220.
[23]. Armstroff, A., Wilkes, H., Schwarzbauer, J., Littke, R., Horsfield, B., 2006.
Aromatic hydrocarbon biomarkers in terrestrial organic matter of Devonian to
Permian age. Palaeogeography, Palaeoclimatology, Palaeoecology 240, 253–274.
[24]. Byers, J.D., Erdman, J.G., 1983. In: M. Bjorøy, Editor, Advances in Organic
Geochemistry 1981, Wiley, London, 725–732.
[25]. Radke, M., Welte, D.H., Willsch, H., 1982a. Geochemical study on a well in the
Western Canada Basin: relation of the aromatic distribution pattern to maturity of
organic matter. Geochimica et Cosmochimica Acta 46, 1–10.
[26]. Radke, M., Willsch, H., Leythaeuser, D., Teichmüller, M., 1982b. Aromatic
components of coal: relation of distribution pattern to rank. Geochimica et
Cosmochimica Acta 46, 1831–1848.
[27]. Alexander, R., Kagi, R.I., Woodhouse, G.W., Volkman, J.K., 1983. The
geochemistry of some biodegraded Australian oils. APEA J 23, 53-63.
[28]. Smith, J.W., George, S.C., Batts, B.D., 1995. The geosynthesis of alkylaromatics.
Organic Geochemistry 23, 71–80.
[29]. Simoneit, B.R.T., 1996. High molecular weight polycyclic aromatic hydrocarbons
in hydrothermal petroleums from the Gulf of California and Northeast Pacific
Ocean. Organic geochemistry 24, 1065-77.
[30]. Bastow, T.P., 1998. Sedimentary processes involving aromatic hydrocarbons. PhD
theses, Curtin University of Techology, Perth, Australia.
[31]. Burkow, I.C., Jørgensen, E., Meyer, T., Rekdal, Ø., Sydnes, L.K., 1990.
Experimental simulation of chemical transformations of aromatic compounds in
sediments. Organic Geochemistry 15, 101–108.
150
[32]. Simoneit, B.R.T., Grimalt, J.O., Wang, T.G., Cox, R.E., Hatcher, P.G., Nissenbaum,
A., 1986. Cyclic terpenoids of contemporary resinous plant detritus and of fossil
woods, ambers and coals. Organic Geochemistry 10, 877–889.
[33]. Allan, J., Larter, S.R., 1983. Aromatic structures in coal maceral kerogens and
extracts. In Advances in Organic Geochemistry 1981, Edited by Bjoroy M. et al.,
John Wiley, Chichester. 534-546.
[34]. Alexander, R., Ngo, S. H., Kagi, R.I., 1991. Identification and analysis of
trimethylbiphenyls in petroleum. Journal of Chromatography 538, 424-430.
[35]. Garrigues, P., Connan, J., Parlanti, E., Belloco, J., Ewald, M., 1988. Relationship
between rank and distribution of methyl aromatic hydrocarbons for condensates
of different origins. In: L. Mattavelli and L. Novelli, Editors, Advances in
Organic Geochemistry 1987 Organic Geochemistry 13, Pergamon Press, Oxford,
1115–1121.
[36]. Ramanampisoa, L., Radke, M., 1995. Extractable aromatic hydrocarbons in a short-
term organic cycle of the Kimmeridge Clay formation, Yorkshire (U.K.):
Relationship to primary production and thermal maturity. Organic Geochemistry
23, 803–817.
[37]. Chakhmakhchev, A., Suzuki, N., Takayama, K., 1997. Distribution of alkylated
dibenzothiophenes in petroleum as a tool for maturity assessments. Organic
Geochemistry 26, 483-489.
[38]. van Aarssen, B.G.K., Bastow, T.P., Alexander, R., Kagi, R.I., 1999. Distributions
of methylated naphthalenes in crude oils: indicators of maturity, biodegradation
and mixing. Organic Geochemistry 30, 1213–1227.
[39]. Bastow, T.P., Alexander, R., Sosrowidjojo, I.B., Kagi, R.I., 1998.
Pentamethylnaphthalenes and related compounds in sedimentary organic matter.
Organic Geochemistry 28, 585-595.
[40]. Radke, M., Willsch, H., 1994. Extractable alkyldibenzothiophenes in Posidonia
shale (Toarcian) source rocks: relationship of yields to petroleum formation and
expulsion. Geochimica et Cosmochimica Acta 58, 5223-5244.
151
[41]. Volkman, J.K., Alexander, R., Kagi, R.I., Rowland, S.J., Sheppard, P.N., 1984.
Biodegradation of aromatic hydrocarbons in crude oils from the Barrow Sub-
basin of Western Australia. Organic Geochemistry 6, 619–632.
[42]. Rowland, S.J., Alexander, R., Kagi, R.I., Jones, D.M., Douglas, A.G., 1986.
Microbial degradation of aromatic components of crude oils: a comparison of
laboratory and field observations. Organic Geochemistry 9, 153–161.
[43]. Huang, H., Bowler, B.F.J., Oldenburg, T.B.P., Larter, S.R., 2004. The effect of
biodegradation on polycyclic aromatic hydrocarbons in reservoired oils from the
Liaohe basin, NE China. Organic geochemistry 35, 1619-1634.
[44]. George, S.C., Boreham, C.J., Minifie, S.A., Teerman, S.C., 2002. The effect of
minor to moderate biodegradation on C-5 to C-9 hydrocarbons in crude oils.
Organic Geochemistry 33, 1293–1317.
[45]. Peters, K.E., Walters, C.C., Moldowan, J.M., 2005. The Biomarker Guide, second
ed. Cambridge University Press.
[46]. Wenger, L.M., Davis, C.L., Isaksen, G.H., 2002. Multiple controls on petroleum
biodegradation and impact on oil quality. SPE Reservoir Evaluat. Eng. 5, 375–
383.
[47]. Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide, Interpreting molecular
fossils in petroleum and ancient sediments. Prentice-Hall, Englewood Cliffs, NJ.
[48]. Fisher, S.J., Alexander, R., Kagi, R.I., 1996. Biodegradation of alkylnaphthalenes in
sediment adjacent to an offshore petroleum production platform. Polycyclic
Aromatic Compounds 11, 35–42.
[49]. Trolio, R., Grice, K., Fisher, S.J., Alexander, R., Kagi, R., 1999. Alkylbiphenyls
and alkyldiphenylmethanes as indicators of petroleum biodegradation. Organic
Geochemistry 30, 1241-1253.
[50]. Clegg, H., Wilkes, H., Horsfield, B., 1997. Carbazole distributions in carbonate and
clastic rocks. Geochimica et Cosmochimica Acta 61, 5335–5345.
[51]. Zhang, C., Zhang, Y., Zhang, M., Zhao, H., Cai, C., 2008. Carbazole distributions
in rocks from non-marine depositional environments. Organic Geochemistry 39,
868-878.
152
[52]. Radke, M., Willsch, H., 1991. Occurrence and thermal evolution of methylated
benzo- and dibenzothiophenes in petroleum source rocks of western Germany. In:
Manning, D., Editor, Advances and Applications in Energy and the Natural
Environment 15th Meeting of the European Association of Organic Geochemists,
Manchester University Press, U.K., 480–484 Poster Abstracts.
[53]. Chakhmakhchev, A., Suzuki, N., 1995. Aromatic sulfur compounds as maturity
indicators for overmature petroleums from the Buzuluk depression, Russia.
Organic Geochemistry 23, 617-627.
[54]. Hayatsu, R., Winans, R.E., Scott, R.G., Moor, L.P., Studier, M.H., 1978. Trapped
organic compounds and aromatic units in coals. Fuel 57, 541–548.
[55]. Willsch, H., Radke, M., 1995. Distribution of polycyclic aromatic compounds in
coals of high rank. Polycyclic Aromatic Compounds 7, 231-251.
[56]. Li, M., Fowler, M.G., Obermajer, M., Stasiuk, L.D., Snowdon, L.R., 1999.
Geochemical characterization of middle Devonian oils in NW Alberta, Canada:
possible source and maturity effect on pyrrolic nitrogen compounds. Organic
Geochemistry 30, 1039-1057.
[57]. Larter, S.R., Bowler, F., Li, M., Chen, M., Brincat, D., Bennett, B., Noke, K.,
Donohoe, P., Simmons, D., Kohnen, M., Allan, J., Telnaes, N., Horstad, I., 1996.
Benzocarbazoles as molecular indicators of secondary oil migration distance.
Nature 383, 593–597.
[58]. Requejo, A.G., Sassen, R., McDonald, T., Denoux, G., Kennicutt II, M.C., Brooks,
J.M., 1996. Polynuclear aromatic hydrocarbons (PAHs) as indicators of the source
and maturity of marine crude oils. Organic Geochemistry 24, 1017–1033.
[59]. Vandenbroucke, M., Largeau, C., 2007. Kerogen origin, evolution and structure.
Organic Geochemistry 38. 719–833.
[60]. Kelemen, S.R., Gorbaty, M.L., Kwiatek, P.J., 1994. Quantification of nitrogen
forms in Argonne premium coals. Energy & Fuels 8, 896–906.
[61]. Kelemen, S.R., Freund, H., Gorbaty, M.L., Kwiatek, P.J., 1999. Thermal chemistry
of nitrogen in kerogen and low-rank coal. Energy & Fuels 13, 529–538.
153
[62]. Dorbon, M., Schmitter, J.M., Garrigues, P., Ignatiadis, I., Ewald, M., Arpino, P.,
Guiochon, G., 1984. Distribution of carbazole derivatives in petroleum. Organic
Geochemistry 7, 111–120.
[63]. Eglinton, G., Irvine, J.E., Vairavamurthy, A. Zhou, W., Manowitz, B., 1994.
Formation and diagenesis of macromolecular organic sulfur in Peru margin
sediments. In: Telnaes, N., van Graas, K. Øygard, Editors, Advances in Organic
Geochemistry, 1993 Organic Geochemistry 22, Pergamon Press, Oxford, pp. 781–
799.
[64]. Wakeham, S.G., Sinninghe Damsté, J.S., Kohnen, M.E.L., de Leeuw, J.W., 1995.
Organic sulfur compounds formed during early diagenesis in Black Sea
sediments. Geochimica et Cosmochimica Acta 59, 521–533.
[65]. Sinnighe Damsté, J.S., Rijpstra, W.I.C., de Leeuw, J.W., Schenck, P.A., 1988.
Origin of organic sulfur compounds and sulfur-containing high molecular weight
substances in sediments and immature crude oils. Organic Geochemistry 13, 593-
606.
[66]. Brassell, S.C., Lewis, C.A., de Leeuw, J.W., de Lange, F., Sinninghe Damste´, J.S.,
1986. Isoprenoid thiophenes: novelnproducts of sediment diagenesis. Nature 320,
160–162.
[67]. Richnow, H.H., Jenisch, A., Michaelis, W., 1992. Structural investigations of
sulphur-rich macromolecular oil fractions and a kerogen by sequential chemical
degradation. In: C.B. Eckardt et al. Advances in Organic Geochemistry, Organic
Geochemistry 19, Manchester University Press, 351–370.
[68]. Schaeffer, P., Reiss, C., Albrecht, P., 1995. Geochemical study of macromolecular
organic matter from sulfur-rich sediments of evaporitic origin (Messinian of
Sicily) by chemical degradation. Organic Geochemistry 23, 567–581.
[69]. Sinninghe Damsté, J.S., Kohnen, M.E.L., de Leeuw, J.W., 1990. Thiophenic
biomarkers for paleoenvironmental assessment and molecular stratigraphy. Nature
345, 609–611.
[70]. Krein, E.B., Aizenshtat, Z., 1994. The formation of isoprenoid sulfur compounds
during diagenesis: simulated sulfur incorporation and thermal transformation.
Organic Geochemistry 21, 1015–1025.
154
[71]. Schouten, S., de Graaf, W., Sinninghe Damsté, J.S., van Driel, B.G. de Leeuw,
J.W., 1994. Laboratory simulation of natural sulphurization II. Reaction of multi-
functionalized lipids with inorganic polysulphides at low temperatures. Organic
Geochemistry 22, 825-834.
[72]. Tomic, J., Behar, F., Vandenbrouke, M., Tang, Y., 1995. Artificial maturation of
Monterey kerogen (Type II-S) in a closed system and comparison with Type II
kerogen: implications on the fate of sulfur. Organic Geochemistry 23, 647–660.
[73]. Sinninghe Damsté, J.S., Kohnen, M.E.L., Horsfield, B., 1998. Origin of thiophenes
in pyrolysates of sulfur-rich kerogens. Organic Geochemistry 20, 1897–1903.
[74]. Riboulleau, A., Derenne, S., Largeau, C., Baudin, F., 2001. Origin of contrasting
features and preservation pathways in kerogens from the Kashpir oil shales
(Upper Jurassic, Russian Platform). Organic Geochemistry 32, 647–665.
[75]. Douglas, A.G., Mair, B.J., 1965. Sulfur: role in genesis of petroleum. Science 147,
499-501.
[76]. DeRoo, J., Hodgson, G.W., 1978. Geochemical origin of organic sulfur compounds:
thiophene derivatives from ethylbenzene and sulfur. Chemical Geology 22, 71-78.
[77]. Sinnighe Damsté, J.S., de Leeuw, J.W., Kock-van Dalen, A.C., de Zeeuw, M.A., de
Lange, F., Rijpstra, W.I.C., Schenck, P.A., 1987. The occurrence and
identification of series of organic sulphur compounds in oils and sediment
extracts. I. A study of Rozel Point Oil (U.S.A.). Geochimica et Cosmochimica
Acta 51, 2369-2392.
[78]. Budzinski, H., 1993. Les composés aromatiques alkylés dans les échantillons
pétroliers: aspects physico-chimiques et thermodynamiques. PhD Thesis,
University of Bordeaux, France.
[79]. Klemm, L.H., Karchesy, J.J., McCoy, D.R., 1979. Polycyclic thiophenes from the
direct insertion of heterosulfur bridges into vinylarenes, biaryls, and anularly
condensed arenes. Phosphorus, Sulfur, and Silicon and the Related Elements 7, 9-
22.
[80]. White, C.M., Douglas, L.J., Schmidt, C.E., 1988. Formation of polycyclic
thiophenes from reaction of selected polycyclic aromatic hydrocarbons with
elemental sulfur and/or pyrite under mild conditions. Energy & Fuels 2, 220-223.
155
[81]. Alexander R., Dawson D., Pierce K. and Murray A., 2009. Carbon catalysed
hydrogen exchange in petroleum source rocks. Organic Geochemistry 40, 951-
955.
[82]. Boehm, H.P., Mair,G., Stoehr, T., de Rincbn, A.R., Tereczki, B., 1984. Carbon as a
catalyst in oxidation reactions and hydrogen halide elimination reactions. Fuel 63,
1061-1063.
[83]. Stohr, B., Boehm, H.P., Schlogl, R., 1991 Enhancement of the catalytic activity of
activated carbons in oxidation reactions by thermal treatment with ammonia or
hydrogen cyanide and observation of a superoxide species as a possible
intermediate. Carbon 29, 707.
[84]. Bansal, R.C., Goyal, M., 2005. Activated Carbon Adsorption, Taylor & Francis, p.
497.
[85]. Alexander, R., Dawson, D., 2008. Molecular evidence for catalyzed hydrogen
transfer reaction in sediments. In: 15th Australian Organic Geochemistry
Conference, 8-12th September, National Wine Centre, Adelaide, SA, Australia.
[86]. Forsman, J.P., 1963. Geochemistry of kerogen. In: I.A. Breger, Editor, Organic
Geochemistry, Pergamon Press, New York, 148–182.
[87]. Robinson, W.E., 1969. Kerogen of the Green River Formation. In: Eglinton, G.,
Murphy, M.T.J. (Eds.), Organic Geochemistry– Methods and Results. Springer-
Verlag, Berlin Heidelberg, New York, 619–637.
[88]. Djuricic, M., Murphy, R.C., Vitorovic, D., Biemann, K., 1971. Organic acids
obtained by alkaline permanganate oxidation of kerogen from the Green River
(Colorado) Shale. Geochimica et Cosmochimica Acta 35, 1201–1207.
[89]. Yen, T.F., 1976. Structural aspects of organic components in oil shales. In: Yen
T.F., Chilingarian, G.V., Editors, Oil Shale, Developments in Petroleum Science
5, Elsevier, Amsterdam, 129–148.
[90]. Siskin, M., Scouten, C.G., Rose, K.D., Aczel, T., Colgrove, S.G., Pabst Jr, R.E.,
1995. Detailed structural characterization of the organic material in Rundle
Ramsay Crossing and Green River oil shales. In: C. Snape, Editor, Composition,
Geochemistry and Conversion of Oil Shales, Kluwer Academic Publishers,
Dordrecht, 143–158.
156
[91]. Behar, F., Vandenbroucke, M., 1987. Chemical modelling of kerogens. Organic
Geochemistry 11, 15–24.
[92]. van Krevelen, D.W., 1993. Coal. Elsevier, Amsterdam.
[93]. Gavalas, G.R., Cheong, P.H.K., Jain, R., 1981. Model of coal pyrolysis. I.
Qualitative development. Ind. Eng. Chem. Fundam. 20, 113-122.
[94]. Hayatsu, R., Winans, R.E., Scott, R.G., McBeth, R.L., Moore, L.P. 1981.
Investigation of aqueous sodium dichromate oxidation for coal structural studies.
Fuel 60., 77-82.
[95]. Given, P.H., 1960. Fuel 39, 147.
[96]. Marsh, H., 1991. A tribute to Philip L. Walker. Carbon 29, 703-704.
[97]. Bodoev, N. V., Rokosov, Y.V., Koptyug, V.A., 1990. Aliphatic carboxylic acids
and ketones from sapropelitic coals. Fuel 69, 216.
[98]. Bodoev, N.V., Gruber, R., Kucherenko, V.A., Guet, J., Khabarova, T., Cohaut, N.,
Heintz, O., Rokosova, N.N., 1998. A novel process for preparation of active
carbon from sapropelitic coals. Fuel 77, 473-478.
[99]. Boehm, H.P., 1994. Some aspects of surface chemistry of carbon blacks and other
carbons. Carbon 32, 759–770.
[100]. Jansen, R.J.J., van Bekkum, H., 1994. Carbon 32, 1507.
[101]. Puri, B.R., Hazra, R.S., 1971. Carbon 9, 123.
[102]. Bansal, R.C., Gupta, U., 1980. Indian Journal Technology 18, 131–133.
[103]. Sinha, R.H., Walker, P.L., 1972. Removal of mercury by sulfurized carbons.
Carbon 10, 754–756.
[104]. Billinge, B.H.M., Evans, M.G., 1984. The growth of surface oxygen complexes on
the surface of activated carbon exposed to moist air and their effect on methyl
Iodide-131 retention. Journal de Chimie Physique et de Physico-Chimie
Biologique 81, 779–784.
[105]. Farah, A., Abbas, G., DeJong, K. A., Kees, A., Lawrence, R. D., 1984. Evolution
of the lithosphere in Pakistan. Tectonophysics 105, 207-227.
[106]. Khan, M.A., Ahmed, R., Raza, H.A., Kemal, A., 1986. Geology of petroleum in
Kohat-Potwar Depression, Pakistan. American Association of Petroleum
Geologists Bulletin 70, 396–414.
157
[107]. Kadri, I.B., 1995. Petroleum geology of Pakistan, Ferozsons (Pvt.) Ltd. Lahore-
Pakistan. pp. 275.
[108]. Wandrey, C.J., Law, B.E. Shah, H.A., 2004. Patala-Nammal Composite Total
Petroleum System, Kohat-Potwar Geologic Province, Pakistan. U.S. Geological
Survey Bulletin 2208-B. (http://pubs.usgs.gov/bul/b2208-b/)
[109]. Aamir, M., Siddiqui, M.M., 2006. Interpretation and visualization of thrust sheets
in a triangle zone in eastern potwar, Pakistan. The Leading Edge January 2006,
24-37.
[110]. Kazmi, A.H., Rana, R.A., 1982. Tectonic map of Pakistan. Geological Survey of
Pakistan, scale: 1:2,000,000.
[111]. Law, B.E., Shah, S.H.A., Malik, M.A., 1998. Abnormally high formation
pressures, Potwar Plateau, Pakistan, In Abnormal pressures in hydrocarbon
environments: Eds. Law, B.E., Ulmishek, G.F., Slavin, V.I., American
Association of Petroleum Geologists Memoir 70, p. 247–258.
[112]. Paracha, W., 2004. Kohat plateau with reference to Himalayan tectonic general
study. CSEG recorder, April 2004, 46-52.
[113]. Jaswal, T.M., Lillie, R.J., Lawrence, R.D., 1997. Structure and evolution of the
northern Potwar deformed zone, Pakistan: American Association of Petroleum
Geologists Bulletin, 81, 308–328.
[114]. van Aarssen, B.G.K., Alexander, R., Kagi, R.I., 1997. Plant biomarker study for
oil source rock correlation in the Carnarvon Basin. Minerals and Energy Research
Institute of Western Australia. Report No. 188, MERIWA Mineral House East
Perth WA 6004.
[115]. Pakistan petroleum limited, 2007. Pakistan oil and gas discoveries, Map. PPL
exploration.
[116]. Fazeelat, T., 1994. 8,14-secohopanes and related compounds: their occurrence in
sediments and applications to oil-source correlation. PhD theses, Curtin
University of Techology, Perth, Australia.
[117]. Ahmed, W., Alam, S., 2007. Organic geochemistry and source rock characteristics
of Salt Range formation, Potwar Basin. Pakistan Journal of Hydrocarbon
Research 17, 37-59.
158
[118]. Le Blanc-Smith G. (1990) Coal, in Geology and Mineral Resources of Western
Australia: Western Australian Geological Survey. Memoir 3. p 625-631.
[119]. Fossing, H., Jørgensen, B.B., 1989. Measurement of bacterial sulfate reduction in
sediments: evaluation of a single-step chromium reduction method.
Biogeochemistry 8, 205-222.
[120]. Jørgensen, B.B., Böttcher, M.E., Lüschen, H., Neretin, N., Volkov, I., 2004.
Anaerobic methane oxidation and a seep H2S sink generate isotopically heavy
sulfides in Black Sea sediments. Geochimica et Cosmochimica Acta 68, 2095-
2118.
[121]. Grice, K., Cao, C.Q., Love, G.D., Böttcher, M.E., Twitchett, R.J., Grosjean, E.,
Summons, R.E., Turgeon, S.C., Dunning, W., Jin, Y.G., 2005. Photic zone
euxinia during the Permian-Triassic superanoxic event. Science, 307(5710), 706-
709.
[122]. Coplen, T.B., 1988. Normalization of Oxygen and Hydrogen isotope data.
Chemical Geology, 72, 293-297.
[123]. Philp, R.P., 1985. Fossil Fuel Biomarkers: Applications and Spectra. Elsevier
Science, New York.
[124]. Grice, K., Alexander, R., Kagi., R., 2000. Diamondiod hydrocarbons ratios as
indicators of biodegradation in Australian crude oils. Organic Geochemistry 31,
67-73.
[125]. Grimalt, J.O., Campos, P.G., Berdie, L., Lopez-Quintero, J.O., Navarrete-Reyes,
L.E., 2002. Organic geochemistry of the oils from the southern geological
Province of Cuba. Applied Geochemistry 17, 1–10.
[126]. Rostad, C.E., Pereira, W.E., 1986. Kovats and Lee retention indices determined by
gas chromatography/mass spectrometry for organic compounds of environmental
interest. Journal of High Resolution Chromatography & Chromatography
Communications 9, 328-334.
[127]. Li, M., Larter, S.R., Stoddart, D., Bjoroy, M., 1992. Liquid chromatographic
separation schemes for pyrrole and pyridine nitrogen aromatic heterocycle
fractions from crude oils suitable for rapid characterization of geochemical
samples. Analytical Chemistry 64, 1337–1344.
159
[128]. Budzinski, H., Raymond, N., Nadalig, T., Gilewicz, M., Garrigues, P., Bertrand,
J.C., Caumette, P., 1998. Aerobic biodegradation of alkylated aromatic
hydrocarbons by a bacterial community. Organic Geochemistry 28, 337-348.
[129]. Frolov, E.B., 1997. Liquid chromatography of petroleum carbazoles. Organic
Geochemistry 26, 43-46.
[130]. Mössner, S. G., Lopez de Alda, M.J., Sander, L.C., Lee, M.L., Wise, S.A., 1999.
Gas chromatographic retention behavior of polycyclic aromatic sulfur
heterocyclic compounds,(dibenzothiophene,naphtho[b]thiophenes,
benzo[b]naphthothiophenes and alkyl-substituted derivatives) on sationary phases
of different selectivity. Journal of Chromatography A, 841, 207-228.
[131]. Bakr, M.Y., Wilkes, H., 2002. The influence of facies and depositional
environment on the occurrence and distribution of carbazoles and
benzocarbazoles in crude oils: a case study from the Gulf of Suez, Egypt. Organic
Geochemistry 33, 561–580.
[132]. Zenkevich, I.G., Moeder, M., Koeller, G., Schrader, S., 2004. Using new
structurally related additive schemes in the precalculation of gas chromatographic
retention indices of polychlorinated hydroxybiphenyls on HP-5 stationary phase.
Journal of Chromatography A 1025, 227-236.
[133]. Aracil, I., Font, R., Conesa, J.A., 2005. Semivolatile and volatile compounds from
the pyrolysis and combustion of polyvinyl chloride,. Journal Analytical and
Applied Pyrolysis 74, 465-478.
[134]. Asif, M., Grice, K., Fazeelat, T., Dawson, D., 2008. Oil-oil correlation in the
Upper Indus Basin (Pakistan) based on biomarker distributions and compound-
specific δ13C and δD. In: 15th Australian Organic Geochemistry Conference, 8-
12th September, National Wine Centre, Adelaide, SA, Australia.
[135]. Murrey, A.P., Boreham, C.J., 1992. Organic geochemistry in petroleum
exploration. Australian Geological Survey Organization, Canberra, 230pp.
[136]. Obermajer, M., Osadetz, K.G., Fowler, M.G., Silliman, J., Hansen, W.B., Clark,
M., 2002. Delineating compositional variabilities among crude oils from Central
Montana, USA, using light hydrocarbon and biomarker characteristics. Organic
Geochemistry 33, 1343-1359.
160
[137]. Jiang, C., Li, M., 2002. Bakken/Madison petroleum systems in the Canadian
Williston Basin, Part 3: geochemical evidence for significant Bakken-derived oils
in Madison group reservoirs. Organic Geochemistry 3, 761-787.
[138]. Pasadakis, N., Obermajer, M., Osadetz, K.G., 2004. Definition and
characterization of petroleum compositional families in Williston Basin, North
America using principal component analysis. Organic Geochemistry 35, 453-468.
[139]. Zhang, S., Huang, H., 2005. Geochemistry of Palaeozoic marine petroleum from
the Tarim Basin, NW China: Part 1. Oil family classification. Organic
Geochemistry 36, 1204-1214.
[140]. Van Aarssen, B.G.K., Alexander, R., Kagi, R., 1996. The origin of Barrow sub-
basin crude oils: A geochemical correlation using land-plant biomarkers.
Australian Petroleum Production and Exploration Journal 36, 465-476.
[141]. Armstroff, A., Wilkes, H., Schwarzbauer, J., Littke, R., Horsfield, B., 2006.
Aromatic hydrocarbon biomarkers in terrestrial organic matter of Devonian to
Permian age. Palaeogeography, Palaeoclimatology, Palaeoecology 240, 253–274.
[142]. Sofer, Z., 1984. Stable carbon isotope compositions of crude oils: applications to
source depositional environments and petroleum alteration. American Association
of Petroleum Geologist bulletin 68, 31-49.
[143]. Chung, H.M., Rooney, M.A., Toon, M.B., Claypool, G.E., 1992. Carbon isotope
compositions of marine crude oils. American Association of Petroleum Geologist
bulletin 76, 1000-1007.
[144]. Andrusevich, V.E., Engel, M.H., Zumberge, J.E., Brothers, L.A., 1998. Secular,
episodic changes in stable carbon isotope compositions of crude oils. Chemical
Geology 152, 59-72.
[145]. Murray, A.P., Summons, R.E., boreham, C.J., Dowleng, L.M., 1994. Biomarker
and n-alkane isotope profiles for Tertiary oils: relationship to source rock
depositional setting. Organic Geochemistry 22, 521-542.
[146]. Li, M.W., Huang, Y.S., Obermajer, M., Jiang, C.Q., Snowdon, L.R., Fowler, M.G.,
2001. Hydrogen isotopic compositions of individual alkanes as a new approach to
petroleum correlation: case studies from Western Canada sedimentary Basin.
Organic Geochemistry 32, 1387-1399.
161
[147]. Schoell, M., 1984. Stable isotopes in petroleum research. In: Advances in
Petroleum Geochemistry. Eds, Brooks, J., Welte, D. H., Academic Press, London.
1, 215-245.
[148]. Collister, J.W., Wavrek, D.A., 1996. δ13C compositions of saturated and aromatic
fractions of lacustrine oils and bitumen: evidence for water column stratification.
Organic Geochemistry 24, 913-920.
[149]. Sun, Y., Chen, Z., Xu, S., Cai, P., 2005. Stable carbon and hydrogen isotopic
fractionation of individual n-alkanes accompanying biodegradation: evidence
from a group of progressively biodegraded oils. Organic Geochemistry 36, 225–
238.
[150]. Seifert, W.K., Moldowan, J.M., 1986. Use of biological markers in petroleum
exploration. In: Methods in Geochemistry and Geophysics, Eds John, R.B., vol
24, 261-290.
[151]. Seifert, W.K. Moldowan, J.M., 1980. The effect of thermal stress on souce rock
quality as measured by hopane stereochemistry. In Douglas, A.G., Maxwell, J.R.,
(eds), Advances in Organic Geochemistry 1979, Pergamon, Oxford: 229–237.
[152]. George, S.C., Mark Liskb, Eadingtonb, P.J., 2004. Fluid inclusion evidence for an
early, marine-sourced oil charge prior to gas-condensate migration, Bayu-1,
Timor Sea, Australia. Marine and Petroleum Geology 21, 1107–1128.
[153]. Rullkötter, J., Marzi, R., 1988. Natural and artificial maturation of biological
markers in a toarcian shale from northern Germany. Organic Geochemistry 13,
639-645.
[154]. Isaksen, G.H., Bohacs, K.M., 1995. Geological controls of source rock
geochemistry through relative sea level; Triassic, Barents Sea. In: Katz, B.J.,
Editor, Petroleum Source Rocks, Springer, Berlin, 25–50.
[155]. Moldowan, J.M., Sundararaman, P., Schoell, M., 1986. Sensitivity of biomarker
properties to depositional environment and/or source input in the Lower Toarcian
of S.W. Germany. Organic Geochemistry 10, 915-926.
[156]. Radke, M., Welte, D.H., 1983. The methylphenanthrene index (MPI): a maturity
parameter based on aromatic hydrocarbons. In: M. Bjøroy et al., (Ed.), Advances
in Organic Geochemistry, Wiley, Chichester.
162
[157]. Bishop, A.N., Abbott, G.D., 1993. The interrelationship of biological marker
maturity parameters and molecular yields during contact metamorphism.
Geochimica et Cosmochimica Acta 57, 3661–3668.
[158]. Lewan, M.D., Bjorùy, M., Dolcater, D.L., 1986. Effects of thermal maturation on
steroid hydrocarbons as determined by hydrous pyrolysis of Phosphoria Retort
Shale. Geochimica et Cosmochimica Acta 50, 1977-1987.
[159]. McKirdy, D.M., Aldridge, A.K., Ypma, P.J.M., 1983. A geochemical comparison
of some crude oils from pre-Ordovician carbonate rocks. Proceedings of the
International Meeting on Organic Geochemistry 10, 99–107.
[160]. Seifert, W.K., Moldowan, J.M., 1981. Paleoenvironmental reconstruction by
biological markers. Geochimica et Cosmochimica Acta 45, 783–794.
[161]. van Grass, G.W., 1990. Biomarker maturity parameters for high maturities:
Calibration of the working range up to the oil/Condensate threshold. Organic
Geochemistry 16, 1025-1032.
[162]. Chen, J., Fu. J., Sheng, G., Liu, D., Zhang, J. 1996. Diamondoid hydrocarbon
ratios: novel maturity indices for highly mature crude oils. Organic Geochemistry
25, 179–190.
[163]. Radke, M., Leythaeuser, D., Teichmüller, M.,1984. Relationship between rank and
composition of aromatic hydrocarbons for coals of different origins. Organic
Geochemistry 6, 423–430.
[164]. Obermajer, M., Osadetz, K.G., Fowler, M.G., Li, M., Snowdon, L.R. 2004.
Variable alteration in heavy crude oils of west-central Saskatchewan, Canada.
Organic Geochemistry 35, 469–491.
[165]. Radke, M., 1988. Application of aromatic compounds as maturity indicators in
source rocks and crude oils. Marine and Petroleum Geology 5, 224-236.
[166]. Dzou, L.P., Noble, R.A., Senftle, J.T., 1995. Maturation effects on absolute
biomarker concentration in a suite of coals and associated vitrinite concentrates.
Organic Geochemistry 23, 681-697.
[167]. Hughes, W.B., Holba, A.G., Dzou, L.I., 1995. The ratio of dibenzothiophene to
phenanthrene and pristane to phytane as indicators of depositional environment
163
and lithology of petroleum source rocks. Geochimica et Cosmochimica Acta 59,
3581-3598.
[168]. Corbett, R.E., Smith, R.A.J., 1969. Lichens and fungi. Part VI. Dehydration
rearrangements of 15-hydroxyhopanes. Journal Chememical Society (C), 44–47.
[169]. Sieskind, O., Joly, G., Albrecht, P., 1979. Simulation of the geochemical
transformation of sterols: Superacid effects of clay minerals. Geochimica et
Cosmochimica Acta 43, 1675–1679.
[170]. Moldowan, J.M., Fago., F.J., Carlson, R.M., et al., 1991. Rearranged hopanes in
sediments and petroleum. Geochim. Cosmochim. Acta. 55, 3333-53.
[171]. Hughes, W.B., 1984. Use of thiophenic organosulfur compounds in characterizing
crude oils derived from carbonate versus siliclastic sources. In: Palacas, J.B.,
Editor, Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks
AAPG, Studies in Geology 18, 181–196.
[172]. Schou, L., Myhr, M.B., 1988. Sulfur aromatic compounds as maturity parameters.
In: L. Mattavelli and L. Novelli, Editors, Advances in Organic Geochemistry
1987 Organic Geochemistry 13, Pergamon Press, Oxford, pp. 61–66.
[173]. Philp, R.P., Gilbert, T.D., 1986. Biomarker distributions in oils predominantly
derived from terrigenous source material. In: Leythaeuser, D., Rullkötter, J.,
Editors, Advances in Organic Geochemistry 1985, Organic Geochemistry 10,
Pergamon, Oxford, 73–84.
[174]. Edwards, D.S., Summons, R.E., Kennard, J.M., Nicoll, R.S., Bradshaw, M.,
Foster, C.B. et al., 1997. Geochemical characteristics of Palaeozoic petroleum
systems in Northwestern Australia. Austral. Petrol. Produc. Explor. Assoc. J. 37,
351-379.
[175]. Volk, H., George, C.S., Middleton, H., Schofield, S., 2005. Geochemical
comparison of fluid inclusion and present-day oil accumulations in the Papuan
Foreland –evidence for previously unrecognised petroleum source rocks.
OrganicGeochemistry 36, 29–51.
[176]. Volkman, J. K., Banks, M. R., Denwer, K., et al., 1989. Biomarker composition
and depositional setting of tasmanite oil shale from northern Tasmania, Australia
164
[C]: 14th International Conference on Organic Geochemistry, Paris, September
18–22, Abstract, p.168.
[177]. Peters, K.E., Moldowan, J.M., 1991. Effects of source, thermal maturity, and
biodegradation on the distribution and isomerization of homohopanes in
petroleum. Organic Geochemistry 17, 47-61.
[178]. Peters, K.E., Moldowan, J.W., Schoell, M., Hempkins, W.B., 1986. Petroleum
isotopic and biomarker composition related to source rock organic matter and
depositional environment. In: D. Leythaeuser and J. Rullkötter, Editors, Advances
in Organic Geochemistry 1985Organic Geochemistry 10, Pergamon, Oxford, 17–
27.
[179]. Mello, M.R., Telnæs, N., Gaglianone, P.C., Chicarelli, M.I., Brassell, S.C.,
Maxwell, J.R., 1988. Organic geochemical characterisation of depositional
palaeoenvironments of source rocks and oils in Brazilian marginal basins. In: B.J.
Katz, B.J., Pratt, L.M., Editors, Advances in Organic Geochemistry vol. 1987,
Pergamon Press, Oxford, pp. 31–45.
[180]. Püttmann, W., Villar, H., 1987. Occurrence and geochemical significance of
1,2,5,6-tetramethylnaphthalene. Geochim. Cosmochim. Acta 51, 3023–3029.
[181]. Budzinski, H., Garrigues, P., Connan, J., Devillers, J., Domine, D., Radke, M.,
Oudin, J.L., 1995. Alkylated phenanthrene distributions as maturity and origin
indicators in crude oils and rock extracts. Geochimica et Cosmochimica Acta 59,
2043–2056.
[182]. Chaffee, A.L., Johns, R.B., 1983. Polycyclic aromatic hydrocarbons in Australian
coals. I. Angularly fused pentacyclic tri- and tetraaromatic components of
Victorian brown coal. Geochim. Cosmochim. Acta 47, 2141–2155.
[183]. Alexander, R., Bastow, T.B., Kagi, R.I., Singh, R.K., 1992b. Identification of
1,2,2,5-tetramethyltetralin and 1,2,2,5,6-pentamethyltetralin as racemates in
petroleum, Journal of the Chemical Society: Chemical Communications 23,
1712–1714.
[184]. Grice, K., Audino, M., Alexander, R., Boreham, C.J., Kagi, R.I., 2001.
Distributions and stable carbon isotopic compositions of biomarkers in torbanites
165
from different palaeogeographical locations. Organic Geochemistry 32, 1195-
1210.
[185]. Thomas, B. R., 1969. Kauri resins-modern and fossil. In Eglinton, G., Murphy,
M.T.G. (Eds.), Organic Geochemistry—Methods and Results. Springer-Verlag,
pp. 599-618.
[186]. Riolo, J., Hussler, G., Albrecht, P., Connan, J., 1986. Distribution of aromatic
steroids in geological samples: their evaluation as geochemical parameters,
Organic Geochemistry 10, 981–990.
[187]. Seifert, W.K., Moldowan, J.M., 1978. Application of steranes, terpanes and mono-
aromatics to the maturation, migration and source of crude oils. Geochimica et
Cosmochimica Acta 42, 77–95.
[188]. Mackenzie, A.S., Hoffmann, C.F., Maxwell, J.R., 1981. Molecular parameters of
maturation in the Toarcian shales, Paris Basin, France-III. In: Changes in aromatic
steroid hydrocarbons. Geochim. Cosmochim. Acta. 45, 1345–1355.
[189]. Moldowan, J.M., Seifert, W.K., Gallegos, E.J., 1985. Relationship between
petroleum composition and depositional environment of petroleum source rocks.
AAPG Bulletin 69, 1255–1268.
[190]. Peters, K.E., Moldowan, J.M., Driscole, A.R., Demaison, G.J., 1989. Origin of
Beatrice oil by co-sourcing from Devonian and Middle Jurassic source rocks,
Inner Moray Firth, UK. American Association of Petroleum Geologists Bulletin
73, 454–471.
[191]. Winters, J.C., Williams, J.A., 1969. Microbiological Alteration of Crude Oil. I The
Reservoir. Preprints. ACS Division of Fuel Chemistry, Paper PETR 86; E22–E31.
[192]. Palmer, S.E., 1993. Effect of biodegradation and water washing on crude oil
composition. In: Macko, S.A., Engel, M.H. (Ed.), Organic Geochemistry,
Principles and Applications. Plenum Press, New York, pp. 511–534.
[193]. Pond, K.L., Huang, Y., Wang, Y., Kulpa, C.F., 2002. Hydrogen isotopic
composition of individual n-alkanes as an intrinsic tracer for bioremediation and
source identification of petroleum contamination. Environmental Science and
Technology 36, 724–728.
166
[194]. Schimmelmann, A., Sessions, A.L., Boreham, C.J., Edwards, D.S., Logan, G.A.,
Summons, R.E., 2004. D/H ratios in terrestrially sourced petroleum systems.
Organic Geochemistry 35, 1169–1195.
[195]. Sessions, A.L., Sylva, S.P., Summons, R.E., Hayes, J.M., 2004. Isotopic
exchange of carbon-bound hydrogen over geologic timescales. Geochimica et
Cosmochimica Acta 68, 1545–1559.
[196]. Radke, J., Bechtel, A., Gaupp, R., Püttmann, W., Schwark, L., Sachse, D.,
Gleixner, G., 2005. Correlation between hydrogen isotope ratios of lipid
biomarkers and sediment maturity. Geochimica et Cosmochimica Acta 69, 5517–
5530.
[197]. Dawson, D., Grice, K., Alexander, R., Edwards, D., 2007. The effect of source and
maturity on the stable isotopic compositions of individual hydrocarbons in
sediments and crude oils from the Vulcan Sub-basin, Timor Sea, Northern
Australia. Organic Geochemistry 38, 1015-1038.
[198]. Boreham, C.J., Dowling, L.M., Murray, A.P., 1995. Biodegradation and maturity
influences on n-alkanes isotopic profiles in terrigenous sequences. In: Abstracts of
17 International meeting on Organic Geochemistry, San Sebastian, Spain, 539-
541.
[199]. Wilkes, H., Boreham, C., Harms, G., Zengler, K., Rabus, R., 2000. Anaerobic
degradation and carbon isotopic fractionation of alkylbenzenes in crude oil by
sulphate-reducing bacteria. Organic Geochemistry 31, 101–115.
[200]. Masterson, W.D., Dzou, L.I.P., Holba, A.G., Fincannon, A.L., Ellis, L., 2001.
Evidence for biodegradation and evaporative fractionation in West Sak, Kuparuk
and Prudhoe Bay field areas, North Slope, Alaska. Organic Geochemistry 32,
411-441.
[201]. Vieth, A., Wilkes, H., 2006. Deciphering biodegradation effects on light
hydrocarbons in crude oils using their stable carbon isotopic composition: A case
study from the Gullfaks oil field, offshore Norway. Geochemica et Cosmochimica
Acta 70, 651-665.
167
[202]. Vieth, A., Elias, R., Wilkes, H., 2007. Carbon and hydrogen isotopic compositions
of petroleum hydrocarbons to trace alteration processes in reservoirs, Geochimica
et cosmochimica acta 71, A1067-A1067.
[203]. Koopmans, M.P., Larter, S.R., Zhang, C., Mei, B., Wu, T., Chen, Y., 2002.
Biodegredation and mixing of crude oils in Eocene Es3 reservoirs of the Liaohe
basin, northeastern china. American Association of Petroleum Geologist bulletin
86, 1833-1843.
[204]. Wingert, W.S. 1992. GC-MS analysis of diamondoid hydrocarbons in Smackover
petroleums. Fuel 71. 37-43.
[205]. Volkman, J.K., Alexander, R., Kagi, R.I., Woodhouse, G.W., 1983a.
Demethylated hopanes in crude oils and their applications in petroleum
geochemistry. Geochimica et Cosmochimica Acta 47, 785–794.
[206]. Peters, K.E., Moldowan, J.M., McCaffrey, M.A., Fago, F.J., 1996. Selective
biodegradation of extended hopanes to 25-norhopanes in petroleum reservoirs.
Insights from molecular mechanics. Organic Geochemistry 24, 765-783.
[207]. Huang, H., Larter, S.R., Bowler, B.F.J., Oldenburg, T.B.P., 2004a. A dynamic
biodegradation model suggested by petroleum compositional gradients within
reservoir columns from the Liaohe basin, NE Chian. Organic geochemistry 35,
299-216.
[208]. Santos Neto, E.V., Hayes, J., 1999. Use of hydrogen and carbon stable isotopes
characterizing oils from the Potiguar basin (onshore), northeastern Brazil.
American Association of Petroleum Geologist Bulletin 83, 496-518.
[209]. Sessions, A.L., Burgoyne, T.W., Schimmelmann, A., Hayes, J.M., 1999.
Fractionation of hydrogen isotopes in lipid biosynthesis. Organic Geochemistry
30, 1193-1200.
[210]. Andersen, M.D., Shaffer, J., Jennings, P.A., Adams, J.A., 2001. Structural
characterization of protein kinase A as a function of nucleotide binding:
Hydrogen-deuterium exchange studies using matrix-assisted laser desorption
ionization-time of flight mass spectrometry detection. J. Biol. Chem. 276: 14204–
14211.
168
[211]. Yang, H., Huang, Y., 2003. Preservation of lipid hydrogen isotope ratios in
Miocene lacustrine sediments and plant fossils at Clarkia, northern Idaho, USA.
Organic Geochemistry 34, 413-423.
[212]. Dawson, D., Grice, K., Wang, S., Alexander, R., Radke, J., 2004. Stable hydrogen
isotopic composition of hydrocarbons in torbanites (Late Carboniferous to Late
Permian) deposited under various climatic conditions. Organic Geochemistry 35,
189-197.
[213]. Dawson, D., Grice, K., Alexander, R., 2005. Effect of maturation on the
indigenous dD signatures of individual hydrocarbons in sediments and crude oils
from the Perth Basin (Western Australia). Organic Geochemistry 36, 95–104.
[214]. Wilkes, H., Veith, A., Elias, R., 2008. Constraints on the quantitative assessment
of in-reservoir biodegradation using compound-specific stable carbon isotopes.
Organic Geochemistry 39, 1215-1221.
[215]. Fenton, S., Grice, K., Twitchett, R.J., Bottcher, M.E., Looy, C.V., Nabbefeld, B.,
2007. Changes in biomarker abundances and sulfur isotopes of pyrite across the
Permian-Triassic (P/Tr) Schuchert Dal section (East Greenland). Earth and
Planetary Science Letters, 262, 230-239.
[216]. Bakel, A.J., Philp, R.P., 1990. The distribution and quantitation of organonitrogen
compounds in crude oils and rock pyrolysates. In Advances in Organic
Geochemistry 1989, Durand, B., Behar, F.,(Eds.), Organic Geochemistry 16, 353-
367.
[217]. Santamaria-Orozco, D., Horsfield, B., di Primio, R., Welte, D.H., 1998. Influence
of maturity on distribution of benzo- and dibenzothiophenes in Tithonian source
rocks and crude oils, Sonda de Campeche, Mexico. Organic Geochemistry 28,
423-439.
[218]. Tasis, D., Tagmatarchis, N., Georgakilas, V., Prato, M., 2003. Soluble carbon
nanotubes. Chemistry. A European Journal 9, 4000-4008.
[219]. Smith, M.B., 1994. Organic Synthesis McGraw-Hill Inc. New York pp 1466.
[220]. Gilchrist, T. L. 1978. Nitrogen ions and radicals, nitrenes and related species. In:
Comprehensive Organic Chemistry.Ed I.O. Sutherland . Pergamon Press. Oxford.
Vol 2 273-301.
169
[221]. Brocks, J.J., Love, G.D., Snape, C.E., Logan, G.A., Summons, R.E., Buick, R.,
2003. Release of bound aromatic hydrocarbons from late Archean and
Mesoproterozoic kerogens via hydropyrolysis. Geochimica et Cosmochimica
Acta 67, 1521–1530.
[222]. Kribii, A., Lemée, L., Chaouch, A., Amblès, A., 2001. Structural study of the
Moroccan Timahdit (Y-layer) oil shale kerogen using chemical degradations. Fuel
80, 681–691.
[223]. Keumi T., Tomioka N., Hamanaka K., Kakihara H., Fukushima M., Morita T.,
Kitajima H. 1991. Positional reactivity of dibenzofuran in electrophilic
substitutions. J. Org. Chem. 56, 4671–4677.
[224]. Bastow, T.P., van Aarssen, B.G.K., Chidlow, G.E., Alexander, G.E., Kagi, R.I.,
2003. Small-scale and rapid quantitative analysis of phenols and carbazoles in
sedimentary matter. Organic Geochemistry 34, 1113-1127.
[225]. Kurge, M.A., 2000. Determination of thermal maturity and organic matter type by
principal components analysis of the distributions of polycyclic aromatic
compounds. International Journal of Coal Geology 43, 27-51.
[226]. Odier, K., Artaud, I., 1992. Degradation of lignin. In: G. Winkelmann, Editor,
Microbial Degradation of Natural Products, VCH Inc., New York.
---
170
Appendix
1 2 6 10 14Phytane
nor-Farnesane
2,6-diemthyundecane
22 27 32 37
Tricyclic terpanes (Cheilanthanes)
C24, 17,21-secohopane (Tetracyclic terpanes)
Isopreniods
Farnesane
2,6,10-trimethyltridecane
nor-Pristane
Pristane
I
II
III
IV
V
VI
VII
VIII
IX
171
Hopanes
117
21
22
29
20
2
3
1112
13
14
1516
18
623 24
25 26
27
28
X = H; 30-norhopane (C29 hopane) = CH3; C30 hopane = C2H5; C31 homohopane = C3H7; C32 bishomohopane = C4H9; C33 trishomohopane = C5H11; C34 tetrakishomohopane = C6H13; C35 pentakishomohopane S and R isomers at C22, 17α(H),21β(H) shown
30X
7
9
54
19
Y
Y = H; C29 moretane = CH3; C30 moretane = C2H5; C31 moretane 17β(H),21α(H) shown
10 8
C30, 17α(H)-diahopane C29, 18α(H)-30-norneohopane (C29Ts)
C27 18α(H)-22,29,30-trisnorneohopane (Ts)
C27 17α(H)-22,29,30-trisnorhopane (Tm)
X
XI
XIV XV
XII XIII
172
117
2
3
1112
13
14 15
16
18
6
20
7
9
54
19
10 8
2122
2324
25
27
26
R R = H; C27-sterane, a = CH3; C28-sterane, b = C2H5; C29-sterane, c S and R isomers at C20, 5α(H),14α(H),17α(H) R = H; C27-sterane, d = CH3; C28-sterane, e = C2H5; C29-sterane, f 14β(H),17β(H)
R
Diasteranes R = H; C27, a = CH3; C28, b = C2H5; C29 c S and R isomers at C20, 13β(H),17α(H)
1
2
3
6
9
54
710
8
Adamantane
1
2
3
6
9
5
4
7
108
1112
13
14
Diamantane
Steranes and diasteranes
X YTriaromatic steroids (TA) C19 TA; X=H, Y=H, a C20 TA ; X=CH3, Y=H b C21 TA ; X=CH3, Y=CH3 c
C22 TA ; X= CH3, Y=C2H5 d C25 TA ; X=CH3, Y=C5H11 e C26 TA ; X=CH3, Y=C6H13 f C27 TA ; X=CH3, Y=C7H15 g C28 TA ; X=CH3, Y=C8H17 h
XVI
XVII
XVIII
XIX
XX
173
12
34
5
6
1'2'3'
4'5'
6'
12
345
6
78
12
34
5 67
8
910
78
9
78
9
78
9
78
9
S1
23
4
5
6
O1
23
4
5
6
NH
12
3
4
5
6
123
4
5
6
Retene
Biphenyl Naphthalene Phenanthrene
Dibenzofuran Carbazole Dibenzothiophene
Fluorene
XXI
XXII XXIII XXIV
XXVXXVI XXVII
XXVIII
á â
---
