aspects of organic geochemistry of nigerian coal university of ibadan

ASPECTS OF ORGANIC GEOCHEMISTRY OF NIGERIAN COAL
AS A POTENTIAL SOURCE-ROCK OF PETROLEUM
TAOFIK ADEWALE ADEDOSU
B.Tech. Chemistry (Ogbomoso), M.Sc. Organic Chemistry (Ibadan)
A Thesis in the Department of Chemistry
Submitted to the Faculty of Science in Partial Fulfillment of the requirements for
the
Degree of
DOCTOR OF PHILOSOPHY
of the
UNIVERSITY OF IBADAN
2009
1

DEDICATION
This thesis is dedicated firstly to Almighty Allah, the Omnipotent and Omnipresent who
guided me both physically and spiritually throughout the duration of this programme and to my
wife and my daughters; Aliyah and Atiyah.
2

ACKNOWLEDGEMENTS
All praises are due to Almighty Allah the Creator, the Cherisher and the Protector of the entire
Universe. I thank Him immensely for sparing my life and giving me sound health throughout the
duration of this research work. Certainly, He is the most glorious.
My gratitude goes to the Department of chemistry for the opportunity given me to have sound
training in the field of Organic geochemistry. My special gratitude goes to the Head of Department,
Prof. R.O. Oderinde and the entire members of staff (both academic and non-academic) for their
various contributions toward the successful completion of this thesis. My profound appreciation
goes to my supervisors, Prof. O. Ekundayo and Dr. O.O. Sonibare for their contributions, advice,
support, prayers and thorough supervision of this project. May the Lord in His infinite mercies
continue to be with them and their families. Once more, special thanks go to Dr. O.O. Sonibare for
given me solid foundation in Organic geochemistry. Also your dual role as Teacher/Mentor is
greatly acknowledged, may the good Lord continue to enrich you with knowledge and bless you.
My appreciation also goes to the immediate past Head of Department, Prof. O.O. Osibanjo for his
fatherly advice and encouragement throughout the duration of this programme. I thank Dr (Mrs.)
O.O. Aiyelagbe for her motherly support towards the successful completion of this research work.
This research work has benefited immensely from the Chinese Academy of Science and Third
World Academy of Science (CAS-TWAS) Postgraduate Fellowship awards. This afforded me
opportunity to carry out my research work with the ‘State of Art’ equipments at the Institute of
Geology and Geophysics, Lanzhou, China between April 2007 and January 2008 under the able
supervision of Prof. Jincai Tuo. I thank Prof. Jincai Tuo for the kindness and love extended to me
during the period of the Fellowship.
My appreciation goes to Prof. Meng, Dr (Mrs.) Yong Li (Associate Professor), all the
Laboratory Technologists and some postgraduate students at the institute especially, Ma Wanyun,
Li Zhoping, Zhang Mingfeng, Mr. Wang and Yu Wen Xio. I also thank Joan Q. Li and Ashley
Wang for their assistance during my stay in China.
The unforgettable assistance rendered to me by Dr Ehinola of Geology Department, University
of Ibadan both in Nigeria and China is highly appreciated. The good Lord used him positively
towards my achievement.
The Almighty God will reward him abundantly. My sincere appreciation goes to Mr. Adabanija
3

(LAUTECH) and Mr. Mathew (Itakpe) for their assistance in getting the samples used for this
research work. I appreciate Nigerian Coal Corporation, Enugu, Nigeria for the supply of some of
the coal samples.
Special thanks go to Profs. Olawore, Faboya, Odunola, Olajire and Ayodele for teaching me
foundation in chemistry. The great work done by Prof. C.M. Ekweozor, Prof. S.O. Akande and
Prof. N. Obaje on Benue Trough, which really assisted me during this research work, is greatly
acknowledged.
The encouragement and prayers received from my mother, siblings, uncles, in-law (Mr. and
Mrs. Ganiyu Obembe), Mr. Azeez, Dr. Yekeen, Dr Gbenga Bello, Dr. (Miss) Adekunle, Dr. (Mrs.)
Oladipo, Dr. Lateef Agbaje, Dr Olaide Lawal, Dr. Niyi Afolabi, Mr. and Mrs. Jelil Bello (Canada),
Dr. Ademola Idowu (USA), Mrs. A.O. Ibrahim and Dr. (Mrs.) Bello are highly commendable.
My appreciation goes to LAUTECH management for granting me study leave to take up the
CAS-TWAS Postgraduate Fellowship. Also both academic and non-academic members of staff of
Chemistry department, LAUTECH are highly appreciated for their various contributions towards
the completion of this work.
Lastly, I give a big thank to Queen Haleema, my darling wife for her love, care, support,
encouragement and understanding and to my beautiful girls, Aliya and Atiya.I pray that Allah
would grant us sound health, long life and prosperity to reap the fruit of our labour.
4

CERTIFICATION
This is to certify that Taofik Adewale ADEDOSU in the Department of Chemistry, University of
Ibadan, Ibadan carried out the work reported in this thesis under our supervision.
…………………………………… ………………………….
Supervisor Supervisor
Olusegun Ekundayo Oluwadayo Olatunde Sonibare
B.Sc (Lagos), Ph.D(London), FAS B.Sc (Ago-woye), PhD(Ibadan)
Professor of Chemistry Senior Lecturer
Department of Chemistry, Department of Chemistry,
University of Ibadan, University of Ibadan,
Ibadan. Ibadan.
5

ABSTRACT
Several studies have suggested that coal can be a potential petroleum source rock in
deltaic and other basins of the world. However despite its vast deposits in Nigeria,
there is a depth of information on its use as a source-rock of petroleum. This study
evaluated the source rock potential of Nigerian coal based on chemical and isotope
composition of biomarkers and polycyclic aromatic hydrocarbons in the coals.
Twenty-two coal and carbonaceous shale samples were collected from four boreholes in Mamu
and Awgu Formations of Lower and Middle Benue Trough, Nigeria. The samples were subjected
to Elemental analysis using Carlo Erba 1108 CHNS-O Analyzer. The source rock potential of the
samples were determined using Rock-Eval analysis. Biomarkers in the aliphatic and polar
fractions and aromatic hydrocarbon distributions in the samples were studied using Gas
Chromatography- Mass Spectrometry (GC-MS). The Carbon isotope analysis of individual n-
alkanes in the aliphatic fraction was performed using Gas Chromatography-Combustion-Isotope
Ratio Mass Spectrometer (GC-IRMS). The vitrinite reflectance measurements of the samples were
taken using Zeiss standard universal reflected microscope.
All the coals analyzed contained the minimum of 0.5wt.% and 2mg/g of Total Organic Carbon
(TOC) and Genetic Potential (GP) respectively of organic matter required to serve as good source
rock for oil and gas. Several plots from the elemental and Rock-Eval pyrolysis classified the
organic matter in Awgu and Mamu samples as type III and type II/III kerogen respectively. The
abundance of hopanes, homohopanes (C31-C35), benzohopanes and C29 steranes and diasteranes in
most of the samples indicate terrestrial plant, phytoplankton and cyanobacteria contributions to the
organic matter that formed the coal. High (Pr/Ph) ratio (1.73-12.47), distributions of polyaromatic
hydrocarbons and isotopic distribution of individual alkanes showed that Awgu samples consisted
of mixed terrestrial/marine organic matter deposited under oxic condition in lacustrine-
fluvial/deltaic depositional environment. Mamu samples consisted of terrestrial organic matter
with marine incursion deposited under oxic/suboxic-oxic in lacustrine-fluvial/deltaic environment.
The vitrinite reflectance values (0.48-1.15%Ro) and all the maturity parameters derived from the
elemental, Rock-Eval analysis and biomarker distributions showed that Awgu samples are in the
late oil window, and Mamu samples have low thermal maturity status.
6

The distribution patterns of C32-C35 benzohopanes in Mamu samples confirmed the redox
condition of organic matter deposition within the Formation. The presence of unsaturated
oleanenes in Mamu samples further confirmed their thermal immaturity status.
The kerogen types of the samples have capacity to generate both oil and gas. Benzohopanes
(C32-C35) and three oleanene isomers; olean-12-ene, olean-13 (18)-ene and olean-18-ene were
present in samples collected from Mamu Formation. These compounds were detected for the first
time in Nigerian coal. Awgu Formation coals might have generated gases into yet-to-be identified
reservoir. Coals from Mamu Formation have potential to generate both oil and gas but are
presently immature to have formed any significant hydrocarbons.
Keywords: Biomarkers, Carbonaceous shale, Benue-Trough, Carbon Isotopes, Hydrocarbon
potential.
Word count: 460.
7

TABLE OF CONTENTS
Subject Pages
Title ……………………………………………….………………………………i
Dedication………………………………………….……………………………...ii
Acknowledgements………………………………….……………………………iii
Certification………………………………………….…………………………….v
Abstract……………………………………………………………………………vi
Table of contents………………………………………………………………….viii
List of figures……………………………………………………………………...xii
List of tables……………………………………………………………………….xv
CHAPTER ONE INTRODUCTION
1.1 General Introduction………………………………………………………….……1
1.2 Coal Formation…………………………………………………………………….2
1.2.1 Peatification……………………………………………………………………..2
1.2.2 Coalification……………………………………………………………………..3
1.3 Coal Structure……………………………………………………………………...3
1.4 Petroleum potential of Coal………………………………………………………..4
1.5 Coal Reserves in Nigeria…………………………………………………………..5
1.6 Petroleum Source Rock Evaluation………………………………………………..9
1.6.1 Quantity of Organic Matter……………………………………………………...9
1.6.2 Quality of Organic Matter……………………………………………………...10
1.6.2.1 Optical Methods……………………………………………………………...10
1.6.2.2 Physico-chemical Methods…………………………………………………..10
1.6.2.3 Chemical Methods……………………………………………………………11
1.6.2.4 Carbon Isotopic Composition………………………………………………...12
1.6.3 Maturity of Organic Matter…………………………………………………….12
1.6.3.1 Rock-Eval Pyrolysis………………………………………………………….12
8

1.6.3.2 Biomarker Analysis…………………………………………………………..13
1.7 Aims and Objectives of this Study ………………………………………………14
CHAPTER TWO LITERATURE REVIEW
2.1 Biomarker Geochemistry………………………………………………………...15
2.1.1 Normal and branched Alkanes…………………………………………………15
2.1.2 Acyclic Isoprenoids…………………………………………………………….16
2.1.3 n-Alkanol, Alkanoic acids and Fatty acids……………………………………..18
2.1.4 Alkanones………………………………………………………………………19
2.1.5 Sesquiterpenoids………………………………………………………………..20
2.1.6 Diterpenoids……………………………………………………………………24
2.1.7 Triterpenoids…………………………………………………………………...25
2.1.7.1 Tricyclic and tetracyclic triterpanes………………………………………….25
2.1.7.2 Pentacyclic triterpanes (Non-Hopanoids)…………………………………... 26
2.1.7.3 Hopanoids……………………………………………………………………28
2.1.8 Steroids/Steranes……………………………………………………………….29
2.2 Non-Biomarker Compounds……………………………………………………..32
2.2.1 Polynuclear aromatic hydrocarbons (PAHs)…………………………………...32
2.2.2 Aromatic Sulphur Compounds…………………………………………………33
2.3 Isotope Geochemistry…………………………………………………………….35
2.3.1 Stable Carbon Isotope………………………………………………………….36
2.3.2 Hydrogen Isotopes……………………………………………………………...39
2.3.3 Sulphur Isotopes………………………………………………………………..41
2.3.4 Oxygen Isotopes………………………………………………………………..41
2.4 Analytical Methods Employed in Geochemical Analyses……………………….42
2.4.1 Pyrolysis………………………………………………………………………..42
2.4.1.1 Flash or Rapid temperature-Programmed Pyrolysis…………………………43
9

2.4.1.2 Hydrous Pyrolysis……………………………………………………………43
2.4.1.3 Rock-Eval Pyrolysis………………………………………………………….44
2.4.2Gas Chromatography/Mass Spectrometry………………………………………47
2.4.3Gas Chromatography-Isotope Ratio Mass Spectrometer (GC-IRMS)………….47
2.5 Geology of Benue Trough………………………………………………………..50
2.5.1 Geological Setting……………………………………………………………...50
2.5.2 Lithological Description………………………………………………………..53
CHAPTER THREE EXPERIMENTAL
3.1 SAMPLING AND SAMPLE PREPARATION………………………………..55
3.1.1 Sampling……………………………………………………………………….55
3.1.2 Extraction of Soluble Organic Matter…………………………………………58
3.1.3 Asphalthene Isolation………………………………………………………….58
3.1.4 Fractionation…………………………………………………………………..58
3.1.5 Derivatisation of Polar fraction………………………………………………..59
3.2 ANALYTICAL METHODS……………………………………………………59
3.2.1 Leco Analysis…………………………………………………………………59
3.2.2 Elemental Analysis……………………………………………………………59
3.2.3 Rock Eval Analysis……………………………………………………………60
3.2.4Gas Chromatography-Mass Spectrometry Analysis (GC-MS)………………...60
3.2.5Gas Chromatography-Isotope Ratio Mass Spectrometry (GC-IRMS)………...61
3.2.6 Vitrinite Reflectance Measurement…………………………………………...61
CHAPTER FOUR RESULTS AND DISCUSSIONS
4.1 ELEMENTAL ANALYTICAL DATA……………………………………….…62
4.1.1 Organic Matter Source and Depositional………………………………………62
4.1.1.1 Awgu Formation……………………………………………………………..62
10

4.1.1.2 Mamu Formation…………………………………………………………….63
4.2 Source Rock Evaluation of Nigerian Coal……………………………………….66
4.2.1 Organic Matter Concentration…………………………………………………66
4.2.1.1 Awgu Formation……………………………………………………………..66
4.2.1.2 Mamu Formation…………………………………………………………….68
4.2.2 Organic Matter Quality………………………………………………………...68
4.2.2.1 Awgu Formation……………………………………………………………..68
4.2.2.2 Mamu Formation…………………………………………………………….70
4.2.3 Thermal Maturity of Organic matter…………………………………………..70
4.2.3.1 Awgu Formation……………………………………………………………..70
4.2.3.2 Mamu Formation…………………………………………………………….73
4.3 Biomarker Geochemistry of the Nigerian Coal………………………………….77
4.3.1 n-Alkane and isoprenoid distributions…………………………………………77
4.3.1.1 Awgu Formation……………………………………………………………..77
4.3.1.2 Mamu Formation…………………………………………………………….87
4.3.2 Fatty acids and alkanones……………………………………………………...87
4.3.2.1 Awgu Formation……………………………………………………………..88
4.3.2.2 Mamu Formation…………………………………………………………….98
4.3.3 Tricyclic and C24 tetracyclic terpanes………………………………………….98
4.3.3.1 Awgu Formation……………………………………………………………..98
4.3.3.2 Mamu Formation……………………………………………………………104
4.3.4 Hopanes and homohopanes…………………………………………………...104
4.3.4.1 Awgu Formation……………………………………………………………104
4.3.4.2 Mamu Formation……………………………………………………………113
4.3.5 Steranes……………………………………………………………………….118
4.3.5.1 Awgu Formation…………..………………………………………………..118
4.3.5.2 Mamu Formation……………………………………………………………126
4.4 Polycyclic aromatic hydrocarbons in Nigerian coal…………………………….128
4.4.1 Naphthalene and alkylnaphthalenes…………………………………………..128
4.4.1.1 Awgu Formation……………………………………………………………128
11

4.4.1.2 Mamu Formation……………………………………………………………134
4.4.2 Phenanthrene and alkylphenanthrenes………………………………………..134
4.4.2.1 Awgu Formation……………………………………………………………134
4.4.2.2 Mamu Formation……………………………………………………………142
4.4.3 Dibenzothiophene and alkyldibenzothiophenes………………………………142
4.4.3.1 Awgu Formation……………………………………………………………143
4.4.3.2 Mamu Formation……………………………………………………………151
4.5 Carbon Isotopic Composition of Nigerian Coal………………………………...152
4.5.1 Origin and Depositional Environment of Organic matter…………………….152
4.5.1.1 Awgu Formation……………………………………………………….…...152
4.5.1.2 Mamu Formation……………………………………………………………155
CHAPTER FIVE
5.0 Summary and conclusion..……………………………………………………..159
REFERENCES……………………………………………………………………..161
APPENDIX…………………………………………………………………………182
List of Figures
Fig.1.1: Location of Anambra Basin……………………………………………….…7
Fig.2.1: Chemical structures of some compounds cited in the literature…………….21
Fig.2.2: Transformation of steranes at C-20 during thermal maturity……………….31
Fig.2.3: Scheme of Rock-Eval analysis……………………………………………...45
Fig.2.4: Geological map of Benue Trough, Nigeria………………………………….51
Fig.2.5: Stratigraphic sequence of Benue Trough, Nigeria…………………………..52
Fig.3.1: Geological map and Lithographic section of BH94
and BH120 of Lafia-Obi coal, Awgu Formation…………………………….56
Fig.3.2: Lithographic section of Onyeama and Okaba Mines in Mamu Formation…57
Fig.4.1: Plot of Atomic H/C against O/C of Coal Samples from Benue Trough…….65
Fig.4.2: Plot of HI vs. OI of Coal Samples from Benue Trough, Nigeria……………69
12

Fig.4.3: Plots of S2 vs. TOC of Coal Samples from Benue Trough, Nigeria…….…..71
Fig.4.4: Plots of Tmax vs. HI of Coal Samples from Benue Trough, Nigeria…….…72
Fig.4.5: Plots of HI vs. Tmax of Coal Samples from Awgu Formation……..………74
Fig.4.6: Plots of HI vs. Tmax of Coal Samples from Mamu Formation……..………75
Fig.4.7: Plots of PI vs. Tmax of Coal Samples from Benue Trough, Nigeria………..76
Fig.4.8: m/z 85 Mass chromatograms of aliphatic fractions of Awgu samples
showing the distribution of n-Alkanes……………………………………...78
Fig.4.9: m/z 85 Mass chromatograms of aliphatic fractions of Mamu
Formation sample (Okaba) showing the distribution of n-Alkanes……….....80
Fig.4.10: m/z 85 Mass chromatograms of aliphatic fractions of Mamu
Formation sample (Onyeama) showing the distribution of n-Alkanes…..…..82
Fig.4.11: Plots of Pr/nC17 against Ph/nC18 of Awgu and Mamu Formation samples..85
Fig.4.12: Plots of CPI against OEP of Awgu and Mamu Formation samples…….…86
Fig.4.13: m/z 74 Mass chromatograms showing the distribution of n-fatty acids
in Awgu samples…………………………………………………………....89
Fig.4.14: m/z 74 Mass chromatograms showing the distribution of n-fatty acids
in Mamu samples (Okaba)…..……………………………………………...91
Fig.4.15: m/z 74 Mass chromatograms showing the distribution of n-fatty acids
in Mamu samples (Onyeama)…..…………………………………………..92
Fig.4.16: m/z 58 Mass chromatograms showing the distribution of alkan-2-ones
in Awgu samples…………………………………………………………….94
Fig.4.17: m/z 58 Mass chromatograms showing the distribution of alkan-2-ones
in Mamu samples (Okaba)..………………………………………………...95
Fig.4.18: m/z 58 Mass chromatograms showing the distribution of alkan-2-ones
in Mamu samples (Onyeama)..…………………………………………….96
Fig.4.19: m/z 191 Mass chromatograms showing the distribution of tricyclic
and tetracyclic terpanes in Awgu samples……………………………...100
Fig.4.20: m/z 191 Mass chromatograms showing the distribution of tricyclic
and tetracyclic terpanes in Mamu Formation samples (Okaba)…………..101
13

Fig.4.21: m/z 191 Mass chromatograms showing the distribution of tricyclic
and tetracyclic terpanes in Mamu Formation samples (Onyeama)……….102
Fig.4.22: m/z 191 Mass chromatograms showing the distribution of hopanes
in Awgu samples………………………………………………………….106
Fig.4.23: m/z 191 Mass chromatograms showing the distribution of hopanes
and benzohopanes in Mamu Formation samples (Okaba).………………107
Fig.4.24: m/z 191 Mass chromatograms showing the distribution of hopanes
and benzohopanes in Mamu Formation samples (Onyeama).……….……108
Fig.4.25:Mass fragmentogram and spectra of Olean-18-ene in Okaba
Mine samples………………………………………………………………114
Fig.4.26:Mass fragmentogram and spectra of Olean-13(18)-ene in Okaba
Mine samples………………………………………………………………115
Fig.4.27:Mass fragmentogram and spectra of Olean-12-ene in Okaba
Mine samples………………………………………………………………116
Fig.4.28: m/z 217 Mass chromatograms showing the distribution of steranes
and diasteranes in Awgu samples………………………………………….119
Fig.4.29: m/z 217 Mass chromatograms showing the distribution of steranes
and diasteranes in Mamu samples (Okaba)……………………………..…120
Fig.4.30: m/z 217 Mass chromatograms showing the distribution of steranes
and diasteranes in Mamu samples (Onyeama)……..……………………..121
Fig.4.31:Ternary plots of C27, C28 and C29 steranes distributions in Nigerian Coal..123
Fig.4.32: Ternary plots of C27, C28 and C29 diasteranes distributions in
Nigerian Coal.…………………………………………………………..…124
Fig.4.33: Plots of 22S/22S+22R C32 hopanes against C29αββ/αββ+ααα steranes….125
Fig.4.34: m/z 156, 170 Mass chromatograms showing the distribution of naphthalene
and alkylnaphthalenes in Awgu Samples………………………………….129
Fig.4.35: m/z 156, 170 Mass chromatograms showing the distribution of naphthalene
and alkylnaphthalenes in Mamu Samples (Okaba)………………………….131
14

Fig.4.36: m/z 156, 170 Mass chromatograms showing the distribution of naphthalene
and alkylnaphthalenes in Mamu Samples (Onyeama)………………………132
Fig.4.37: m/z 178, 192, 206 Mass chromatograms showing the distribution
of phenanthrene and alkylphenanthrenes in Awgu Samples………………136
Fig.4.38: m/z 178, 192, 206 Mass chromatograms showing the distribution
of phenanthrene and alkylphenanthrenes in Mamu Samples (Okaba)……..137
Fig.4.39: m/z 178, 192, 206 Mass chromatograms showing the distribution
of phenanthrene and alkylphenanthrenes in Mamu Samples (Onyeama)..138
Fig.4.40: Organic matter source discrimination in the samples………………….…141
Fig.4.41: m/z 184, 198, 212, 226 Mass chromatograms of dibenzothiophene
and alkyldibenzothiophenes in Awgu Samples…………………………..144
Fig.4.42: Cross plot of total Sulphur vs. dibenzothiophene/phenanthrene (DBT/P)
for Nigerian Coal………………………..……………………………..…147
Fig.4.43: Cross plot of total Sulphur vs. methyldibenzothiophene/methylphenanthrene
(MDBT/MP) for Nigerian Coal……..….……………………………..…148
Fig.4.44: Cross plot of dibenzothiophene/phenanthrene (DBT/P)
vs. pristane/phytane for Nigerian Coal…….……………………………...149
Fig.4.45: Cross plot of methyldibenzothiophene/methylphenanthrene (MDBT/MP)
vs. pristane/phytane for Nigerian Coal…….……………………………...150
Fig.4.46: Carbon Isotopic distribution of individual n-alkanes in Awgu Samples…154
Fig.4.47: Carbon Isotopic distribution of individual n-alkanes
in Okaba samples, Mamu…………………………………………………157
Fig.4.48: Carbon Isotopic distribution of individual n-alkanes
in Onyeama samples, Mamu……………….……………………………..158
15

List of Tables
Table 1.1: Coal and Lignite Reserves of Nigeria…………………………………..…8
Table 2.1: Relevant Characteristics of the Light Stable Isotopes…………………....38
Table 2.2: Rock-Eval Parameters………………………………………………….…46
Table 4.1: Elemental Analysis and Vitrinite Reflectance Data of Nigerian Coal…....64
Table 4.2: TOC and Rock Eval Pyrolysis Data………………………………………67
Table 4.3: n-Alkanes and Isoprenoids Parameters…………………….……………..84
Table 4.4: Parameters calculated from n-Fatty acids and alkanones composition
of Nigerian Coal…………………………………………………………...97
Table 4.5: Tri- and Tetracyclic terpanes source and depositional
environment parameters…………………………………………………103
Table 4.6: Peak identities on m/z 191 mass chromatograms………………………..109
Table 4.7: Source and depositional environment parameters computed from
hopane and sterane distributions in the coals……………………………111
Table 4.8: Maturity parameters computed from hopanes and steranes distributions
in the coals……………………………………………………………….112
Table 4.9: Peak identities on m/z 217 mass chromatograms of Nigerian coal……..122
Table 4.10: Peak identities on m/z 156 and 170 mass chromatograms……………133
Table 4.11: Peak identities on m/z 178, 192, 206 mass chromatograms ……..……139
Table 4.12: Source and Depositional Environment and maturity parameters
derived from phenanthrene and dimthyldibenzothiophene and
their alkyl derivatives…………………………………………………..140
Table 4.13: Peak identities on m/z 184,198,212,226 mass chromatogram ………...146
Table 4.14: Carbon Isotopic Composition of n-alkanes in Awgu Samples
(δ 13 ‰PDB)……………………………………………………………….153
Table 4.15: Carbon Isotopic Composition of n-alkanes in Mamu Samples
(δ 13 ‰PDB)……………………………………………………………….156
16

1.1 Introduction
CHAPTER ONE
INTRODUCTION
Organic geochemistry deals with the process governing the origin and
fate of organic materials such as petroleum (crude oil and natural gas), coal,
oil shale and tar sands. Coals are remnants of terrestrial higher plants formed
under non-marine and paralic conditions (Tissot and Welte, 1984) and found
at its site of deposition as a solid and a relatively pure massive organic
substance. Many studies have suggested the possibility of non-marine coal
sediments having potential capacity to generate petroleum (Katz,
1983;Betrand et al., 1986; Boreham and Powell, 1991; Hunt 1991, 1996;
Hutton et al., 1994). Coal, the world’s most abundant, accessible and versatile
source of fossil energy was brought to the forefront of the global energy scene
by the industrial revolution of the 10 th century (Balogun et al., 2003). The
largest reserves of coal were deposited in the late Carboniferous and Permian
with lesser amounts in the Jurassic through the Tertiary (Kotarba et al., 2002).
During the past 20 years, coals and shales containing coaly organic matter
(coaly shales) have received increasing attention as commercial quantity of
petroleum (oil and gas) have been discovered in many basins around the
world containing these type of organic matter (Hendrix et al., 1995; Mario et
al., 1997; Petersen et al., 2000; Bechtel et al., 2001; Kotarba et al., 2002;
Boreham et al., 2003). Despite the huge reserves of coal in Nigeria, its
petroleum potential has not been extensively studied.
1.2 Coal Formation
17

Coal is a brown to black combustible rock that originated by accumulation
and subsequent physical and chemical alteration of plant materials over long
period of time, and on moisture free basis contains not more than 50 % mineral
matter.It is generally accepted that coal originated from plant debris including
ferns, trees, bark, leaves, roots and seeds some of which accumulated and settled
in swamps (Vlado and Valkovic, 1983). The result of accumulation of in-situ
residues and important debris in swamps leads to the formation of peat.
The coal is often interbedded with shale, sandstone and other sedimentary rocks.
The two main phases involved in coal formation are briefly discussed as follows:
1.2.1 Peatification
Peat is being formed today in marshes and bogs. The plant debris
accumulated in various wet environment, commonly called peat swamps, where
dead plants were largely protected from decay by high water table and oxygen
deficient water. The accumulating spongy, water saturated, plant derived organic
material known, as peat is the precursor of coal. Less than 10 % of plant debris
deposited in a typical peat-forming environment accumulates as peat, the rest
being recycled by the associated microbial community (bacteria, fungi) or lost
from the system through mineralisation and leaching. Oxidizing conditions
generally prevail at the surface of pit bogs but reducing conditions develop
where there is cover of stagnant water or with increasing compaction and depth.
Acidity increases with increasing burial depth, bacterial community changes
and their activities decreases and eventually ceases. This stage corresponds to
early diagenesis and the humic substances are the products of peatification.
There are gradual biochemical transformations of lignin involving
depolymerisation and defunctionalisation. Gases such as CH4, NH3, N2O and
CO2 are produced (Killops and Killops, 1993).
18

1.2.2 Coalification
This is the process whereby Peat is progressively transformed into lignite or
brown coal, sub-bituminous coal, bituminous coal and anthracite. Coalification
can be subdivided into biochemical and geochemical stages. At the biochemical
stage, there is further loss of oxygen containing compounds and condensation of
organic residue progresses to form brown coal containing about (50-70) %C and
(5-7) %H.
Temperature and pressure are the main agents during the geochemical stage and
as the carbon content increases there is a corresponding decrease in oxygen. The
hydrogen level remains constant initially but later it begins to decrease with
increasing rate at the highest level of maturity. The nitrogen content ranges
between (1-2) % while sulphur levels are variable but generally

As the original plant materials, consisting largely of well-ordered polymers
(e.g. cellulose and lignin) were degraded lighter, hydrogen rich compounds were
formed and trapped leaving macromolecular residue depleted in hydrogen and
rearranged as a completely disordered macromolecular material. As coalification
progressed, the aromatic character of the coal increased with ring fusing and
becoming crosslinked. Thus the degree of condensation increases in the order:
lignite, bituminous coal, and anthracite. The hydroxyl group in coals is mainly
phenolic or acidic. Hydroxyl oxygen may be present in concentration of about 9 %
in brown coals, but it is usually about 8 % with 65 %C and 27 %O.
As rank increases, the hydroxyl content decreases slightly untill, at 80 %C and
12.5 %O, a more rapid decrease is initiated, resulting in a hydroxyl oxygen
concentration of less that 1 % at 90 %C content.
Carboxyl group are absent in most coals above the lignite stage of development, but
are present in brown coals (lignite). At 83 %C content, all carboxyl group
dissappears.
The methoxyl group is lost early during metamorphism of coal but carbonyl
group are found at all stages of coalification. During the metamorphic process in
coals containing up to 70-80 %C, the methoxyl group are lost first, then the
carboxyl and carbonyl groups decrease rapidly. At 81-89 %C content, the hydroxyl
group decreases rapidly. At greater than 92 %C content, almost all oxygen is in
non-reactive stable forms. Hydroxyl and carbonyl groups may account for 70-90 %
of the oxygen in bituminous coals. Nitrogen in coal is almost completely in cyclic
structures.
1.4 Petroleum Potential of Coal
Petroleum generation from coal source rocks and its type are fundamentally
dependent on the availability of hydrogen (Hunt, 1996; Petersen and Nytoft,
2006). The importance of paraffinicity of coal for generating and expelling liquid
hydrocarbons has received great attention (Isasken et al., 1998; Killops et al.,
1998).
20

The longer the aliphatic chains the greater the potential for generating and
expelling liquid hydrocarbons during thermal maturation (Hunt, 1996; Isasken et
al., 1998; Petersen and Nytoft, 2006).
Isasken et al. (1998) have shown that the concentration of long-chained
aliphatic hydrocarbons in the coal matrix is the main factor responsible for
petroleum potential of humic coals. The debate on hydrocarbon generation and
migration within coal has intensified since the early work by Brooks and Smith
(1967,1969) who proposed that certain oils originated from coals. Today, it is
widely accepted that some coals can indeed generate oil (Betrand, 1986;
Boreham and Powell, 1991; Hunt, 1991,1996; Hutton et al., 1994).
1.5 Coal Reserves in Nigeria
Although coal deposits exist in nearly every region of the world, but vast
coal deposits occur only in Europe, Asia, Australia and North
America.Commercial coal deposits occur in sedimentary rock basins, typically
sand-witched as layers (beds or seams) between sandstone and shale. Nigeria has
one of the largest coal deposits and largest lignite deposits in Africa.
Coal was discovered in Nigeria in 1909 by the Minerals Survey of Southern
Nigeria in the South Eastern part of the country near Udi. Between 1909 and
1930,further coal outcrops were located in the viccinities of Enugu and Ezimo in
Enugu state, Orukpa in Benue state and Okaba and Ogboyoga-Odukpani in Kogi
state. Later, discoveries of the lignite fields in Delta state and bituminous coals
of Lafia-Obi in Nasarawa state were reported (Nigerian coal Corporation report,
2005). Majority of the coal deposits are located between latitudes 6 o 39’ and 8 o
35’N and longitudes 6 o 32’ and 9 o 21’E within the Cretaceous Mamu Formation
in the Anambra basin (Fig. 1.1).
21

The coal deposits of the Anambra basin located in southeastern Nigeria
appear to contain the largest and most economically viable coal resources. This
basin covers an area of approximately 1.5million hectares and is constrained by
the Niger River on the west, the Benue River on the north and the Enugu
Escarpment on the east. The coal is predominantly in one seam that outcrops
along the eastern side of the basin at the base of the Enugu escarpment and dips
gently towards the center of the basin. Coal outcroppings have also been
reported at Idah and Dekina on the northwestern part of the basin, demonstrating
that coal exists on the western side of the basin as well as the east. Detailed
distribution of reserves is shown in Table 1.1.
22

Fig. 1.1 : Location of Anambra Basin in Nigeria (boxed area of inset) showing the location of the coal, lignite
and shale deposits. Numbers indicate Cretaceous and Tertiary formations as follows: 1. Asu River Group;
2. Odukpani Formation; 3. Eze-Aku Shale; 4.Awgu Shale; 5. Enugu/Nkporo Shale; 6. Mamu Formation;
7. Ajali Sandstone; 8. Nsukka Formation; 9. Imo Shale; 10. Ameki Formation and 11. Ogwashi-Asaba
Formation (Akande et al., 2007).
23

Table 1.1 : Coal and Lignite Reserves of Nigeria.
Serial No Mine Location State Type of Coal
24
Estimated
Reserves (Million
tones)
Proven
Reserves
(Million tones)
Borehole
Records
Coal Outcrop and
SeamThickness
(m)
1 Okpara Enugu Sub-bituminous 100 24 20 Many (1.5)
2 Onyeama Enugu Sub-bituminous 150 40 Many Many (1.5)
3 Ihioma Imo Lignite 40 Not Available Nil Many
4 Ogboyoga Kogi Sub-bituminous 427 107 31 17(0.8-2.3)
5 Ogwashi-Azagba/Obomkpa Delta Lignite 250 63 7 4(3.5)
6 Ezimo Enugu Sub-bituminous 156 56 4 10(0.6-2.0)
7 Inyi Enugu Sub-bituminous 50 20 4 0.9-2.0
8 Lafia-Obi Nassarawa Bituminous 156 21.42 123 Nil (1.3)
9 Oba/Nnewi Anambra Lignite 30 Not Available 2 14(0.3-4.5)
10 Afikpo/Okigwe Ebonyi/Imo Sub-bituminous 50 Not Available Nil Not Available
11 Amasiodo Enugu Bituminous 1000 Not Available 3 Not Available
12 Okaba Kogi Sub-bituminous 250 3 Many 0.8-2.3
13 Owukpa Benue Sub-bituminous 75 57 Many 0.8-2.3
14 Ogugu/Awgu Enugu Sub-bituminous Not Available Not Available Nil Not Available
15 Afuji Edo Sub-bituminous Not Available Not Available Nil Not Available
16 Ute Ondo Sub-bituminous Not Available Not Available Nil Not Available
17 Doho Bauchi Sub-bituminous Not Available Not Available Nil Not Available
18 Kumuru-Pindosa Bauchi Sub-bituminous Not Available Not Available Nil Not Available
19 Lamja Adamawa Sub-bituminous Not Available Not Available Nil Not Available
20 Ganin Maigunga Bauchi Sub-bituminous Not Available Not Available Nil Not Available
21 Gindi Akwati Plateau Sub-bituminous Not Available Not Available Nil Not Available
22 Janata Kogi Kwara Sub-bituminous Not Available Not Available Nil Not Available
Source: Nigerian Coal Corporation Report, 2005.

1.6 Petroleum Source Rock Evaluation
A petroleum source rock may be defined as fine-grained sediment that
has generated and released enough hydrocarbons to form an accumulation of oil
and gas while potential source rock is one that is not mature to generate
petroleum in its natural setting but will form significant quantities of petroleum
when required thermal maturity is attained (Hunt, 1996; Hunt et al., 2002).
Accurate characterization of the oil generation potential of source rocks is
essential for hydrocarbon accumulation assesment in a petroleum system (Kwan-
Hwa Su et al., 2006). The petroleum potential of any source rock is evaluated by
determining the quantity, type and thermal maturity of organic matter contained
in such rock. These parameters are discussed briefly below.
1.6.1 Quantity of Organic matter
The quantity of organic matter in source rocks is usually expressed as the total
organic carbon (TOC). The minimum acceptable TOC values for various types
of source rocks are 0.5 % for shales, 0.3 % for carbonates and 1.0 % for clastic-
type rocks (Killops and Killops, 1993). A minimum of 1.5-2 % TOC has
generally been accepted for defining good source rocks (Hunt, 1996).
The amount of hydrocarbon isolated from the bitumen extracted from finely
ground rock samples can also provide a useful indication of whether any oil
potential exists. Oil source rocks are generally considered to require a minimum
hydrocarbon content of 200-300 ppm (Killops and Killops, 1993).
The Genetic Potential (GP) expressed in milligram hydrocarbon per gramme of
rock (mg/HC/g) can also be used to evaluate the maximum quantity of
hydrocarbon that a particular rock had already generated (S1) and would be
generated (S2) if exposed to a sufficient prolonged thermal stress i.e. (S1 + S2).
Both the S1 and S2 values can be obtained from the Rock-Eval pyrolysis of rocks.
25

1.6.2 Quality of Organic matter
The quality of organic matter contained in rocks can be determined by
Optical and Physiochemical methods. These methods are briefly described
below:
1.6.2.1 Optical Methods
These methods are based on maceral recognition techniques. Maceral
examination can be carried out using reflected light microscopy of thin sections
of the whole rock or of isolated organic particles. Transmitted light microscopy
can also be used for isolated maceral concentrates. Shape and degree of
transmittance or reflectance, and also fluorescence under uv-illumination, can be
used to identify broad maceral groups (liptinite, exinite, vitrinite and inertinite).
1.6.2.2 Physico-chemical Methods
Kerogen is the disseminated organic matter in sedimentary rock that is
insoluble in non-oxidizing acids, bases and organic solvents. Elemental analysis
of kerogen concentrate from rock is the most reliable method of characterizing
the types or quality of organic matter. It is based on the major constituents (C, H,
O), which have been used to define main types of kerogen based on the plot of
H/C versus O/C in Van Krevelen diagram. The plot of Hydrogen index (HI) vs.
Oxygen index (OI) provides an analogue to the van Krevelen diagram. Both the
HI and OI can be obtained from Rock-Eval pyrolysis. Based on the plot of H/C
vs. O/C and HI vs. OI, kerogen can be classified into types I to IV which are
broadly equivalent to the maceral groups, liptinite, exinite, vitrinite and inertinite
respectively for coals (Killops and Killops, 1993).
Type I kerogen has a high H/C ratio and a low O/C ratio. It contains a
significant contribution from lipid material. Algal material and bacteria remains
are the main contributors of its organic matter. The kerogen is deposited under
anoxic conditions in shallow water environment (e.g. Lagoon and Lake) with
total 4.6% oxygen. The type I kerogen is relatively rare but has high oil potential.
26

The type II kerogen has relatively high H/C and low O/C ratios. It is formed
from mixed authochthonous phytoplankton, zookplankton and microbial (mainly
bacteria) organic matter deposited under reducing condition in marine
environment. The type II kerogen has lower yields of hydrocarbon upon
pyrolysis compared to Type I kerogen. It is the most common type and has both
oil and gas potential.
The type III kerogen that is derived from vascular plants has low H/C and
high O/C ratio. Type III kerogen is formed from. Vitrinite concentrations
generally occur as coal or coaly shales, hence type III kerogen is comparable
with coals in terms of its composition and behaviour with increasing burial. Type
III kerogen is much less likely to generate oil compared to type II and I but may
be a source of gas (chiefly methane).
The type IV kerogen is probably formed from higher plant matter that has
been severely oxidized on land and then transported to its deposition site. It has
low atomic H/C and low O/C ratio. It can be derived from other kerogen types
that have been reworked and oxidized. It is sometimes not considered as true
kerogen because it has no hydrocarbon generating potential.
1.6.2.3 Chemical Methods
Chemical methods based on bitumen extracts for assessing the organic
matter in source rocks are mainly based on biomarkers. Analysis of biomarkers
in source rock extracts gives useful information on sources of organic material.
Biomarkers allow the recognition of main input of organic matter (Hunt et al.,
2002; Olvella et al., 2006). The application of biomarker in kerogen quality
assessment is discussed further in section 2.1.
27

1.6.2.4 Carbon Isotopic Composition
Carbon isotope distributions in whole source rock or extracts give
information on type of organic material. Kerogen from higher plant sources
usually exhibit lower δ 13 C values than those sourced by marine organism by a
difference of about 3-5 % (Killops and Killops, 1993; Revill et al., 1994; Meyers,
2003). This topic is discussed further in section 2.3.
1.6.3 Thermal maturity of Organic Matter
Information on the level of maturity of organic matter in the source rock
is needed to determine if the source rock has reached the stage of hydrocarbon
generation or not. The maturity status of source rock can be determined from
Rock-Eval pyrolysis, petrographic and biomarker analyses. These parameters are
briefly discussed below:
1.6.3.1 Rock-eval Pyrolysis
The major maturity parameters from the Rock-eval pyrolysis are
Production Index (PI) or Transformation Ratio (TR) and Tmax.These parameters
increase with increasing maturation. The PI or TR expressed as the ratio of
S1 /S1+S2 measures the extent to which the genetic potential of the rock has been
effectively utilized. It is expressed as the ratio of the hydrocarbon already
generated to the total genetic potential. Generally, the threshold of the oil zone is
fixed at about 0.1. The ratio reaches about 0.4 at the bottom of the oil-window
and increases to 1.0 when the hydrocarbon generative capacity of the kerogen
has been exhausted.
The Tmax indicates the temperature of the maximum generation of S2
peak. Generally, the threshold of the oil zone is fixed at Tmax of 430 o C - 435 o C
for type II and III kerogen while gas zone ranges from 450 o C - 455 o C and
465 o C - 470 o C for type II and type III respectively (Killops and Killops, 1993,
2005).
28

Organic petrographers also developed series of maturation indicators, the most
reliable of which is vitrinite reflectance (Hunt et al., 2002).
The use of vitrinite reflectance as a technique for determining the maturity
of oil in sedimentary rocks was first described by Teichmuller (1958).
Today, vitrinite reflectance is a widely used indicator of thermal stress because it
extends over a longer maturity range than any other indicator (Hunt et al., 2002).
Vitrinite reflectance can be used to asses thermal maturity in types II and III but
cannot be used for type I kerogen due to absence of vitrinite. Vitrinite reflectance
values for main phase of oil generation ranges from (0.65-1.3) %R0 and values
greater than 2.0 %R0 indicate dry gas generation (Tissot and Welte, 1984).
Macerals in rocks observed under microscope are affected by increasing
maturity. There is change in colour of spores and pollens observed under
transmitted light with increasing temperature. Colour changes from yellow in
immature samples through orange/yellow-brown during diagenesis and brown
during catagenesis to black in metagenesis.
1.6.3.2 Biomarker analysis
Maturity of source rocks can also be determined from the biomarker
distribution in source rock extracts. Many maturity parameters have been
developed from the distribution of terpanes, steranes and polyaromatic
hydrocarbons in source rocks.
29

1.7 Aims and Objectives of this Study
The debate on hydrocarbon generation and migration within coal has
intensified since the early work by Brooks and Smith (1967, 1969). Many
studies suggest the possibility of non-marine coal sediments having potential
capacity to generate petroleum by thermal transformation of organic matter
compounds during natural diagenesis when buried in sedimentary basins
(Betrand et al., 1986; Boreham and Powell, 1991; Hunt 1991, 1996; Hutton et
al., 1994). Today, it is widely accepted that some coals can indeed generate oil
(Hendrix et al., 1995; Mario et al., 1997; Petersen et al., 2000; Bechtel et al.,
2001; Kotarba et al., 2002; Boreham et al., 2003).
Nigeria is one of the countries with the largest deposits of coal in Africa,
however despite its vast deposits, there is a dearth of information on its use as
a source-rock of petroleum. The present study therefore aimed at:
(a) evaluating the source rock potential of some Nigerian coal,
(b) assessing the organic source, depositional environment and maturity
of the coal based on the distribution of biomarkers and polycyclic
aromatic hydrocarbons (PAH), and
(c) determining the carbon isotopic composition of individual n-
alkanes in the coal and its implication on organic source and
depositional environment.
30

2.1 Biomarker Geochemistry
CHAPTER TWO
LITERATURE REVIEW
Biomarker or geochemical fossils are organic compounds found in geosphere
whose structure can be unambiguously linked to their biological origin, despite the
possibility of some structural alteration due to diagenetic or other processes. Treibs
(1934) was the first to develop the biomarker concept with his pioneering work on
identification of porphyrins in crude oils and suggested that these porphyrins may
have originated from the chlorophyll of plants. All biomarker molecules have
definitive chemical structures, which can be related directly or indirectly through a set
of diagenetic alterations to biogenic precursors, and cannot be synthesized by
abiogenic processes (Simoneit, 2002). The use of biomarkers as indicators of biogenic,
paleoenvironmental, and geochemical processes on Earth has been widely accepted
(Mackenzie et al., 1982; Johns, 1986; Simoneit et al., 1986; Brassel, 1992; Imbus and
Mckirdy, 1993; Mitterer, 1993; Simoneit, 1998). Biomarkers are widely used in
petroleum geochemical studies in source rock evaluation, oil-oil or oil-source rock
correlations, basin evaluation and reservoir management (Peters et al., 2005). Some of
the biomarkers widely used in geochemical studies are briefly described below.
2.1.1 Normal and branched Alkanes
n-Alkanes are widely distributed in various plants and other organisms and are
probably the most exploited class of biomarkers (Philp, 1985).High proportions of
long chain C27-C31 members relative to the total n-alkanes especially, n-C27 and n-C29
are typical of terrestrial higher plants, where they occur as main components of plant
waxes i.e.leaf curticles, spores, pollens and resins (Bray and Evans 1961; Meinschein,
1961; Kvenvolden, 1962; Eglinton and Hamilton, 1963; Caldicott and Eglinton, 1973;
Miranda et al., 1999; Tissot and Welte, 1984; Barthlot et al., 1998).
31

The short chain n-alkanes with odd-to-even predominance in the medium molecular
weight region (C11-C17) maximizing at n-C16 are predominantly found in algae and
microorganisms (Clark and Blummer, 1967; Fowler et al., 1986; Miranda et al., 1999;
Ficken et al., 2000).
The ratio of odd/even carbon numbered n-alkanes has been in use over a long
period in estimating the thermal maturity of fossil fuels (Bray and Evans; 1961;
Philippi, 1965; Scalan and Smith, 1970; Tissot et al., 1977). These ratios can be
expressed as Carbon preference index, CPI (Bray and Evans, 1961) and improved
Odd-to-even predominance, OEP (Scalan and Smith, 1970). The CPI and OEP values
above or below 1.0 indicate low thermal maturity. Values of 1.0 suggest, but do not
prove, that an oil or rock extract is thermally mature. The CPI or OEP values below
1.0 are unusual and typify low maturity oils or bitumen from carbonate or hypersaline
environments (Peters et al., 2005). Organic matter inputs do affect these ratios and
therefore are mostly applied with caution.
2.1.2 Acyclic isoprenoids
Acyclic isoprenoids have been widely used in fossil fuel studies for
characterization and correlation studies and to obtain information on depositional
environment especially in lacustrine source rocks. The acyclic isoprenoids
hydrocarbons; pristane, (Pr)(structure I) and phytane, (Ph)(structure II) are ubiquitous
in sedimentary rocks, crude oils and coals (Bechtel et al., 2003). The most abundant
source of pristane and phytane is the phytol side chain of chlorophyll a and b (Powell
and McKirdy, 1973). In the presence of Oxygen, phytol would be oxidized to phytenic
acid, yielding pristane after decarboxylation. In the absence of Oxygen, phytol would
be dehydrated, yielding phytadienes, which eventually hydrogenated to phytane. The
Pr/Ph ratios have been proposed as an indicator for the oxicity of the depositional
environment (Powell and McKirdy, 1973; Didyk et al., 1978). Pristane/phytane ratio

However, the ratio is known to be affected by differences in the precursors of acyclic
isoprenoids (Volkman and Maxwell, 1986; Ten Haven et al., 1987).
A common precursor for pristane and phytane is inferred by the similarity in their
δ 13 C values (Hayes et al., 1990).
High Pr/Ph (>3.0) indicates terrigenous organic matter input under oxic
conditions, while low values (

Abundant lycopanes have been reported in hypersaline euxinic settings (Grice et al.,
1998) and in mesosaline carbonates, such as the Jurassic Malm stage carbonates
(Schwark et al., 1998). Lycopane has been proposed to be a bacterial marker derived
from reduction of lycopene (Killops and Killops, 2005).
Squalene (structure V) serves as precursor to polycyclic terpenoids, steroids and
carotenoids. Squalene is a major lipid produced by methanogenic, thermophillic and
thermoacidophilic archaea. Abundant squalane, a saturated C30 isoprenoidal alkane,
may represent a direct archaebacterial input (Matsumoto and Watanuki, 1990) or
derive from diagenetic reduction of squalene, which occur in a variety of organisms.
Squalane has been used as a biomarker for archaea and hypersaline depositional
environments (Ten Haven and Rulkotter, 1988).
2.1.3 n-Alkanol, Alkanoic acids and Fatty acids
Aliphatic wax lipids (n-alkanols, n-alkanoic acids, fatty acids) in the range of
C22-C32 were identified as the major extractable components of angiosperm leaves,
barks and roots (Huang et al., 1995; Lockheart et al., 2000; Kogel-Knaber 2002;
Yuang and Huang, 2003). Similar distributions have been reported in sediments and
macrofossils (Logan and Eglinton, 1994; Huang et al., 1995, 1996; Lockheart et al.,
2000). The functionalized lipids are partly degraded during diagenesis (Bechtel et al.,
2001). The wax esters, their hydrolysis products, and the free alkanol and fatty acids
are preferentially degraded to aldehyde, ketones and alkanes by microorganisms
(Puttmann and Bracke, 1995). These degradation pathways favor short chain (

Generally, short chain n-fatty acids (C25) homologs with a high odd carbon
number predominance were interpreted to originate from vegetation wax by oxidation
while the lower homologues (

These isoprenoid ketones could be produced from free phytol by bacteria degradation
and photosynthesized oxidation, photosynthesized oxidation of some isoprenoids
hydrocarbons and during photo degradation of α-chlorophyll (Tuo and Li, 2005).
The homologous series of alkan-2-ones is generally found with an odd carbon number
predominance and its source is likely microbial (Leif and Simoneit, 1995; Bai et al.,
2006). It has been proposed that n-alkan-2-ones are formed by microbially mediated
β-oxidation of alkanes (Simoneit et al., 1979; Cranwell et al., 1987;
Rieley et al., 1991) or from β-oxidation and decarboxylation of n-fatty acids
(Volkman et al., 1983). n-Alkan-2-ones maximizing at C25 or C27 have been reported
in higher plants,microalgae and phytoplankton(Gonzalez et al., 2003; Bai et al., 2006).
2.1.5 Sesquiterpenoids
Sesquiterpanes primarily those based on the cadinane skeleton, with their aromatic
derivatives, are found in many crude oils from inferred deltaic source rock
(Van Aarssen et al., 1990, 1992). Cadinanes (structure VI) and bisabolanes belong to
the most common sesquiterpenoids in the plant kingdom and are thus non-specific
(Otto and Wilde, 2001). Derivatives of longifolane, santalane, and himachalane were
reported from conifer species of the Pinaceae, Cupressaceae, and Podocarpaceae
(Otto and Wilde, 2001). Also, aromatic sesquiterpenoids, dihydro-ar-curcumene,
cuparene, calamene, cadina-1(10),6,8-triene and cadalene have been reported from
various origin including, higher plants, conifers, dammar resin, Dipterocarpacceae
and Cupressaceae sensu lato (Haberer et al., 2006),thereby supporting its non-
specificity. However, there are some specific sesquiterpenes like cuparene, which are
characteristic biomarkers for the conifer family Cupressaceae sensu lato including the
genera, Cupressus, Thuja and Juniperus (Grantham and Douglas, 1980; Otto and
Wilde, 2001) or sativene, a specific marker for Pinaceae (Otto and Wilde, 2001).
Sesquiterpenoids are valuable chemosystematic markers for extant conifers.
Examples include sesquiterpenoid classes of the cedrane, cuparane, valencane and
thujospane.
36

Their derivatives were reported only from modern species of the Cupresaceae and
Taxodiaceae (Stefanova et al., 2002). The biological precursors of cadalene type
sesquiterpenoids are common constituents of the resin of conifers (Simoneit et al.,
1986; Otto et al., 1997).
Cadalene precursors are resistant to diagenesis and thermal maturation and their
relative abundances in sedimentary organic matter have been used as proxies of higher
plant input in previous reconstructions of palaeo-vegetation and palaeo-climate (van
Aarssen et al., 2000).
37

Fig. 2.1: Chemical structures of some compounds cited in the literature
(Peters et al., 2005).
38

Fig. 2.1 (contd.): Chemical structures of some compounds cited in the literature
(Peters et al., 2005).
39

2.1.6. Diterpenoids
Diterpenoids form a large group of natural products, which are widely
distributed in the plant and animal kingdom. Diterpenoids originate mainly from
gymnosperms and can provide useful chemotaxonomic information on fossil and
extant Coniferales families (Thomas, 1970; Simoneit, 1977; Wakeham et al., 1980;
Simoneit et al., 1986; Otto et al., 1997; Otto and Simoneit, 2001; Otto and Wilde,
2001; Otto et al., 2003).
Large numbers of diterpenoids from various classes with the main groups being
abietanes, pimaranes, kauranes and phyllocladanes have been identified in recent
plant species (Sukh, 1989; Otto et al., 1997). Possible precursors of most of the
common diterpenoid skeleton-types can be found in species of nearly all conifer
family (Tuo and Philp, 2005). They can also be preserved in fossil plants and were
previously reported from several Tertiary and Cretaceous conifers (Otto et al., 1997,
2001, 2002; Otto and Simoneit, 2001), and are found in high concentration in the seed
cone of conifer species (Otto et al., 2003, 2005).
Diterpenoids containing the abietane, pimarane and kaurane skeletons have
been found in fossil resins, coals, crude oils, recent and older sediments (Otto et al.,
1997; Miranda et al., 1999; Bastow et al., 2001). Simonellite and its associated
aromatic abietanes are often referred to as biomarkers for Pinaceae, because abietic
acid only occurs in Pinaceae species (Simoneit, 1977; Simoneit et al., 1986).
Phenolic abietanes (ferruginol and derivatives) are characteristics for the conifer
families Cupressaceae senso lato, Podocarpaceae and Araucariaceae, and can be
used as their chemosystematic markers (Thomas, 1970; Otto and Wilde, 2001;Otto et
al., 2005). Tricyclic diterpenoids such as 18-norpimarane, pimarane and
dehydroabietane, simonellite and retene are thought to be derived from resins formed
by higher plants primarily gymnosperms (conifer), but also by some angiosperms;
pteridophytes, and bryophytes (Otto et al., 1997). For instance, simonellite and retene
may originate from other abietane-type precursors; such as taxodone and ferruginol
present in recent Taxodum species (Otto et al., 1997).
40

Sponges are the only marine organisms known thus far to contain tricyclic
diterpenoids (Wen et al., 2000).
The presence of tetracyclic diterpenoids, 16α(H)-phyllocladane and ent-16β(H)-
kaurane are usually considered to be indicative of Podocarpaceae, Cupressaceae and
Araucariaceae conifer contributions (Thomas, 1970, 1988; Sukh, 1989; Otto et al.,
1997), Taxodiaceae (Dehmer, 1995; Otto et al., 1997, Bechtel et al., 2002) and
probably from pteridophytes (Cheng et al., 1997). Two isomeric phyllocladanes, β-
and α- phyllocladane, have been identified in many sediments and coals (Simoneit,
1986). They have been reported as biomarkers for the Pordocarpaceae and
Araucariaceae, because high amounts of phyllocladane precursors have been detected
in recent species of these conifer families (Schulze and Michaelis, 1990).
The saturated and aromatized abietanes, pimaranes and phyllocladanes, commonly
identified in sediments and coals, can be related only to the whole Coniferales group.
This is because functionalized precursors of these diterpenoids occur in recent species
of several conifer families (Otto et al., 1997).
2.1.7 Triterpenoids
All triterpenoids appear to be derived from the acyclic isoprenoid squalene,
which is a ubiquitous component in organisms (Killops and Killops, 2005). Members
of triterpenoids include tricyclic-, tetracyclic and pentacyclic. Many terpanes originate
from prokaryotic bacteria membrane lipid (Ourisson et al., 1982). Some of the
triterpenoids often used are discussed briefly below.
2.1.7.1 Tricyclic and tetracyclic triterpanes
Tricyclic terpanes are common in crude oils and sediments and were first
observed in extract from the Green River Formation (Gallegos, 1971). The most
prominent tricyclic terpanes are important components in the saturated hydrocarbon
fractions of petroleum (Moldowan et al., 1983). C30 tricyclohexaprenol in bacterial
membranes or malabaricatrienes from algae or bacteria could be intermediates in the
biosynthetic pathway that account for tricyclic terpanes in petroleum (Peters, 2000).
41

Higher homologs may originate from C40 tricyclooctaprenol (Azevedo et al., 1998) or
larger precursors.
High concentration of tricyclic terpanes and their aromatic analogs commonly
correlate with high paleolatitude Tasmanite-rich rocks suggesting an origin from these
algal (Aquino Neto et al., 1983; Azevedo et al., 1992). A higher C19-C21 tricyclic
terpanes relative to C23 tricycloterpane can be interpreted as terrestrial organic matter
(Ozcelik and Altunsoy, 2005). Tricyclic terpanes can be used to correlate crude oils
and source rock extracts, predict source rock characteristics, and to evaluate the extent
of thermal maturity and biodegradation (Peters and Moldowan, 1993). C22/C21 and
C24/C23 tricyclic terpane ratios help to identify extracts and crude oils derived from
carbonate source rocks while C26/C25 tricyclic terpane ratio is useful as a supporting
method to distinguish lacustrine from marine oils (Peters et al., 2005).
Tetracyclic terpanes generally in the range C24-C27 are also frequent constituents of
oils and bitumens. There is tentative evidence for homologs up to C35
(Killops and Killops, 2005). They are structurally related to hopanes, for which they
may be formed by thermal or bacterial cleavage of the 17(21) C-C bond in the ring,
although a direct bacterial source cannot be discounted (Killops and Killops, 2005;
Peters et al., 2005).
C24-C27 tetracyclic terpanes are referred to as de-E-hopanes, or 17,21-secohopanes
and are more resistant to biodegradation and maturation than hopanes. Therefore they
are used in the correlation of biodegraded oils (Peters and Moldowan, 1993).
Abundant C24 tetracyclic terpane in fossil fuel indicate carbonate and evaporite source
rock settings (Connan et al., 1986) and are also common in most marine oils
generated from mudstones to carbonate source rocks. C25-C27 tetracyclic terpanes
have also been reported in carbonate and evaporite samples (Connan et al., 1986).
2.1.7.2 Pentacyclic triterpanes (Non-Hopanoid triterpenoids)
Today the biological origin of most pentacyclic triterpenoids is known (Borrego
et al., 1997). Angiosperms contain triterpenoids of β-amyrin, which on diagenesis
ultimately produced the C30 triterpane oleanane.
42

The use of α-and β- amyrins as terrestrial plant markers relies on the generally
accepted view that these triterpenoids are only synthesized in higher plant cells.
Although, possibility of contaminations has been suggested (Volkman, 2003).
Pentacyclic terpanes gives information on the organic matter type, maturation, and the
lithology of source rocks (Waples and Machiara, 1990). Pentacyclic triterpenoids
based on the oleanane, lupane and related skeletons have provided some of the most
useful markers inputs of organic matter from terrestrial plants to marine sediments
(Killops and Frewin, 1994; Volkman et al., 2000; Volkman, 2005). Oleanane
frequently encountered in sediments younger than Late Cretaceous, is therefore useful
as indicator of geological age (Nytoft et al., 2002; Ozcelik and Altunsoy, 2005).
Oleanane occurs in two isomers; 18α(H)-oleanane (structure VII) and 18β(H)-
oleanane (structure VIII), the relative amount of which changes with the level of
thermal maturation, and thus can be used as indicators of maturity (Ekweozor and
Telnǽs, 1990). Oleanane index (oleanane/C30 hopane) can also be used to indicate the
terrestrial and marine input into the organic matter (Waples and Machiara, 1990).
Gammacerane (structure IX) has been found in sediments from the Late
Proterozoic, which contains some of the earliest examples of fossil protozoan
(Summons et al., 1988) and bacteria in marine sediments (Kleemann et al., 1990). Its
presumed precursor is tetrahymanol first isolated from the ciliate protozoan
Tetrahymena pyriformis (Mallorry et al., 1963) and since then, it has been found in
other eukaryotes i.e. other ciliates, ferns and fungi (Volkman, 2005). Diagenetic
conversion of tetrahymanol to gammacerane most likely proceed by dehydration to
form gammacer-2-ene, followed by hydrogenation or may also arise by sulphurization
and subsequent cleavage of tetrahymanol (Sinninghe Damste et al., 1995). High
gammacerane is often seen in fresh water lacustrine sediments (Peters and Moldowan,
1993; Peters et al., 2005) and in certain marine crude oils from carbonate-evaporite
source rocks (Peters et al., 2005). It was proposed that the gammacerane is in fact an
indicator for water stratification during source deposition (Sinninghe-Damste et al.,
1995).
43

Lupanes (structure X) are probably derived mainly from angiosperms, and the
occurrence of these compounds should thus be expected to follow that of angiosperm
group (Nytoft et al., 2002). Various higher plant lupanoids e.g. lupane-3β, 20,28-triol,
lup-20 (29)-en-3β, 28-diol (betulin), lup-20 (29)-en-3β-ol (lupeol), and 3β-
hydroxylup-20(29)-en-28-oic acid (betulinic acid), may be possible biological
precursors. Lupane occurs frequently in coals and lignites (Wang and Simoneit, 1990;
Peters and Moldowan, 1993; Stefanova et al., 1995) and has been identified in
evaporitic sediments (Poinsot et al., 1995). Lupane is reported rarely in crude oils, and
this may be attributed to difficulties in its identification (Nytoft et al., 2002). Lupane
has similar mass spectrum and also co-elute with oleananes. Therefore lupane may be
resolved partially from oleanane using gas chromatography capillary columns with
polar stationary phases or via High Pressure Liquid Chromatography (Nytoft et al.,
2002) and best quantified using GC-MS/MS methods scanning the m/z 412.4 to 369.3
transition (Peters et al., 2005).
2.1.7.3 Hopanoids
Hopanoids are considered biomarkers for bacteria and cyanobacteria. Most
hopanes molecular fossils originate from polar constituents of prokaryotic organisms
(Nytoft et al., 2006). The most probable biological precursor of the hopane derivatives
is bacteriohopanepolyol, which are present in the cell membranes of prokaryotic
organisms (bacteria and blue algae) where they played the rigidifying role by steroids
in eukaryotic organisms (Ourisson et al., 1982; Rohmer et al., 1992; Durand, 2003;
Bechtel et al., 2007a&b). The C30 Hopanoids have also been found in some
cryptogams; moss, fern (Bechtel et al., 2007a&b). While hopanes with 30 or few
carbon atoms are often interpreted as diagenetic products of C30 hopanoids (e.g.
diploptene and diplopterol), the extended hopanes have been related to C35 precursors,
such as bacteriohopane polyols, aminopolyols and a number of composite hopanoids
(Wang et al., 1996).
44

High abundance of C35 hopane usually found in marine carbonates and evaporitic
sediments has been attributed to highly reducing depositional environments
(Yangming et al., 2005).
V-shape pattern of homohopane, i.e. C31>C32≥C33≤C34

The predominance of C27 steranes in non-marine strata indicates a deep lake facies
and source input of plankton (algae) while C29 sterane predominance shows a swamp
shallow water environment and a terrestrial higher plant input (Volkman, 1986; Peters
and Moldowan, 1993; Volkman et al., 1999; Otto et al., 2005; Jauro et al., 2007).
C28 sterane is a unique biomarker signature of organic matter deposited in saline
lacustrine facies. Sterane/hopane ratio is often used as a measure of the relative inputs
of eukaryotic versus prokaryotic debris (Peters and Moldowan, 1993). Low
sterane/triterpane ratio (Norgate et al., 1999) has been postulated to favour terrestrial
paralic facies rather than peat swamp facies as organic matter source. Sterane
isomerisation at C-20 have been found useful in assessing the level of thermal
maturity of oil and sediments (Fig. 2.2). The 20S/20S+20R ratio (usually measured
using the C29ααα steranes) is one of the most widely applied molecular maturity
parameters in petroleum geochemistry (Farrimond et al., 1998). It is based on the
relative enrichment of the 20S isomer compared with the biologically inherited 20R
stereochemistry with increasing maturity.
46

Fig. 2.2: Transformation of steranes at C-20 during thermal maturity
47

Sterane nuclear isomerisation ratio, (αββ/ αββ+ααα) is widely applied owing to its
operation beyond oil window (Farrimond et al., 1998). In relatively immature samples,
coelution of the ααα isomer with the αββ doublet is a common problem that is
responsible for the relatively high αββ values at shallow depth and apparent decreases
in the parameter with increasing depth (Farrimond et al., 1998). In highly mature
source rocks, an eventual decrease in this ratio occurs (Peters et al., 1990).
2.2 Non-Biomarker Compounds
2.2.1 Polynuclear aromatic hydrocarbons (PAHs)
Polycyclic aromatic hydrocarbons are a suite of organic compounds that are
ubiquitous in sediments. The possible source may be oil, coal, air-transported particles
combustion of fossil fuel, plant material, algae and bacteria or diagenesis (Pereira et
al., 1999).
The widespread occurrence of aromatic hydrocarbons in sediments whose carbon
skeletons are non-isoprenoidal (Polycyclic aromatic hydrocarbons) has led to
suggestion that such compounds are the products of sedimentary reactions (Radke et
al., 1982a; Smith et al., 1994). It is now widely accepted that assemblages of
polycyclic aromatic hydrocarbon (PAH) and their alkyl homologs found in recent
sediments are partly derived from non-aromatic biogenic precursors (Wakeham et al.,
1980; Radke et al., 1982a). These transformations occured in the subsurface, either
through microbial processes in the initial stages of diagenesis or during subsequent
burial in which such precursors experience the effects of temperature, pressure and
catalytic action of mineral matrix (Albrecht and Ourisson, 1971; Radke, 1987; Ellis et
al., 1997).
Alkylated polycyclic aromatic hydrocarbons (PAHs) have received attention as
indicators of thermal maturity (Budzinski et al., 1995). Throughout the oil window,
aromatic maturity indicators are thought to be more sensitive to maturity effects than
many biomarker maturity parameters (Alexander et al., 1986).
48

A variety of aromatic maturity parameters have been poposed on the basis of
ratios of the relative concentration of more thermally stable isomers to less stable ones
(Radke and Welte, 1983; Bastow et al., 2000). The compounds substituted in α-
positions are less stable than related isomers with β-substitution patterns.
Naphthalenes and its alkylated derivatives are common constituents of fossil fuels
(Bastow et al., 1998, 2000;van Aarssen et al., 1999).
Sesqui- and triterpenoids derived from microbial and land plant sources have been
suggested as major precursors for methylated naphthalenes (Puttmann and Villar,
1987; Strachan et al., 1988).
The distributions of methylated naphthalenes are highly variable between samples as
they are controlled by the effects of source, thermal stress and biodegradation (van
Aarssen et al., 1999). Several maturity ratios involving methylated naphthalenes have
been developed over the years and used to asses maturities of crude oils (Alexander et
al., 1985; Radke et al., 1990,1994; Bastow et al., 1998).
Phenanthrene maturity parameters are based on the greater stability of 3-methyl
phenanthrene and 2-methylphenanthrene compared to 9-methylphenanthrene and 1-
methylphenanthrene (Radke and Welte, 1983). The methyl phenanthrene index (MPI)
proposed by Radke is a widely used molecular maturity parameter and depends on the
relative stability of the isomers (Radke and Welte, 1983). 1,7-DMP can be suggested
as a marker of terrestrial input of organic matter (Budzinski et al., 1995).
2.2.2 Aromatic Sulphur Compounds
Dibenzothiophenes, benzodibenzothiophenes and their alkylated derivatives are
common constituents of aromatic fractions of fossil fuels. They are of geochemical
importance in the determination of type of organic matter, depositional environment
and thermal maturity of geological samples. Sulphurisation of organic matter is a
process that occurs either at an intermolecular level, forming low molecular weight
organic sulphur compounds, like, thiophenes, thilane or thiane moieties or the sulphur
atoms form (poly)-sulphide bridges between individual compounds resulting in
49

creation of macromolecular network (Schouten et al., 1995a; Kolonic et al., 2002).
It is now widely accepted that incorporation of reduced inorganic sulphur species into
functionalised lipids at early stages of diagenesis give rise to organosulphur
compounds which are readily preserved in sediments (Sinninghe Damste et al., 1989a;
de Graaf et al., 1992).
Low molecular weight organosulphur compounds and sulphur rich
macromolecules bear an unambiguous link with natural precursors and hence source
organisms and in turn provide valuable information on palaeoenvironments of
deposition (Grice et al., 1998). With increasing diagenesis, an increasing number of
C-S bonds are cleaved and compounds enter fractions of lower molecular weight (van
kaam-Peters et al., 1998). This implies that the amount of lower molecular weight
organosulphur compounds generated is directly linked to the number of sulphur
crosslinks by which compounds are bound in macromolecular fractions (van kaam-
Peters et al., 1998). Sulphur enrichment in coals suggests high activity of anaerobic
bacteria in a slightly acidic to neutral, sulphate bearing and methanogenic
environment (Grice et al., 1998; Sachsenhofer et al., 2000a; Bechtel et al., 2001).
High sulphur rich oils are indications of carbonate evaporite source rocks, while low
sulphur oils are more typical of siliciclastic source rock (Younes and Philp, 2005).
Sykes et al. (2004) adopted 0.5% sulphur (dry-ash-free) as the highest concentration
for entirely non-marine coal.
The low content of organosulphur compounds in the oils, as reflected in the low
dibenzothiophene/phenanthrene ratio,

more stable β-substituted isomer (4-MDBT).
A number of ratios are applicable for thermal maturity assessments on the basis of
aromatic sulphur compounds e.g.Lorgarithmic-scale cross plots of 4-MDBT/1-MDBT
(MDR) versus three maturity parameters (the ratios (4,6/1,4)-DMDBT, (2,4/1,4)-
DMDBT, and DBT/phenanthrene (Younes and Philp, 2005).
2.3 Isotope geochemistry
Isotope measurements combined with the study of molecular structures,
including those of biomarkers, are common and very efficient approach in modern
organic geochemistry. Isotope analysis of individual compounds separated online by
gas chromatography (Gas Chromatography-Isotope Ratio Mass Spectrometer) also
known as compound specific δ 13 C analysis have been applied to oil-oil and oil-source
rock correlations and the elucidation of petroleum generation mechanism (Hayes et al.,
1990; Rooney et al., 1998). Many workers have shown that structures and isotope
compositions of biomarkers provide valuable genetic information (Hayes et al., 1990;
Macko, 1994; Popp et al., 1997; Huang et al., 2000; Grice et al., 2001; Lu et al., 2003;
Wang et al., 2004b) and also useful for oil-source rock correlation. (Bogacheva and
Galimov, 1979; Galimov, 2006). The isotopic composition of the molecule can
indicate parent organisms and in turn, reveal the carbon source utilized by the
producer hence its position within the ancient ecosystem (Hayes, 1993). Stable
isotope compositions of organic matter and carbonates are widely used in
palaeoenvironmental studies of ancient ecosystems and for the assessment of
palaeoclimate (Sabel et al., 2005; Lis et al., 2006). However interpretation of the
stable isotope records is often complicated by the effect of facies dependent variations
in the sedimentary environment (Eh, pH, salinity, temperature etc.) and post
depositional events during and after early diagenesis that can substantially influence
the isotopic composition of organic matter and carbonates (Benner et al., 1987).
By convention, the relative abundance of stable isotopes is always referenced to the
heavy isotopes; thus an increase in the 15 N/ 14 N ratio would be reported rather than a
decrease in the 14 N/ 15 N.
51

This convention is codified in the ubiquitous delta (δ) notation. The δ 13 Csample
=[(Rsample – Rstandard)/Rstandard] x 1000‰, where R is the absolute 13 C/ 12 C ratio of the
sample or an internationally accepted standard (summarized in Table 2). The delta
value is the relative difference in isotope ratio between sample and standard, and is
expressed in units of permil (‰) or parts per thousand. Equivalent delta notation is
used for all of the stable isotopes i.e. δ 2 H (more commonly δD), δ 15 N, δ 18 O, δ 34 S, &
δ 37 Cl.
2.3.1 Stable Carbon Isotope
Stable carbon isotopes have played an important role in many aspects of
petroleum geochemistry. Early applications of bulk carbon isotope values included a
study by Silverman and Epstein (1958) of a number of Tertiary crude oils from
different environment. Marine and non-marine oils have been differentiated on the
basis of their carbon isotopic compositions (Revill et al., 1994; Hunt et al., 2002;
Meyers, 2003). Other early applications noted a general trend of enrichment of the
light 12 C isotope with increasing age (Welte et al., 1975; Stahl, 1977), possibly
caused by variations in intensity of photosynthesis and changes in the isotopic
composition of the atmospheric CO2. Kvenvolden and Squires (1967) successfully
used isotopic age trend to relate and distinguish crude oils on regional basis in West
Texas. The δ 13 C value may to a certain extent reflect the chemical composition of
organic material originating from the same vegetation type (Chabbi et al., 2007). The
distribution of 13 C among natural products is a sensitive palaeoenvironmental
indicator (Hayes et al., 1990) and can provide a great deal of information about
ancient biogeochemical processes (Hayes, 1993). Carbon isotopic compositions of
low rank coals have been suggested to be useful in reconstruction of changes in the
global carbon cycle as well as climatic changes (Lücke et al., 1999; Arens et al.,
2000).
52

Also, it has been shown that n-alkane distributions in kerogen using conventional
geochemical tools, without detailed stable carbon isotope data can sometimes lead to
erroneous interpretations of the precursors contributing to the kerogen even with
samples containing abundant biomarkers (Audino et al., 2002). Several studies have
utilized the stable carbon isotopic compositions of individual n-alkanes to resolve
source of n-alkanes or n-alkanes precursors in ancient sediments (Kennicult and
Brooks, 1990; Collister et al., 1994; Boreham et al., 1994, Chabbi et al., 2007).
53

Isotopes Sample
gas
Table 2.1 : Relevant characteristics of the light stable isotopes (Sessions, 2006).
Interface type
2 H/ 1 H H2 Pyrolysis
13 C/ 12 C CO2 Combustion
15 N/ 14 N N2
Combustion/
Reduction
18 O/ 16 O CO Pyrolysis
Reference
standard
(name)
Water
(VSMOW)
Carbonate
(VPDB)
Isotope ratio
of standard
54
Theoretical
Sensitivity,
nmol
Typical
precison (%0)
Typical
sensitivity (%0)
First
commercial
GC-IRMS
instrument
0.0000 15576 21 2-5 10-50 1998
0.011224 0.024 0.1-0.3 0.1-5 1988
Air (AIR) 0.003663 0.11 0.3-0.7 1-10 1992
Water
(VSMOW)
0.00200 52 0.19 0.3-0.6 4-14 1996
34 S/ 32 S SO2 Not Available Trolite (VCDT) 0.04416 0.0048 Not Available Not Availble Not Available
37 Cl/ 35 Cl CH3Cl Not Available
Chloride
(SMOC)
0.3196 0.00066 Not Available Not Available Not Available

The distribution pattern of individual n-alkane carbon isotopes in different kinds
of oil should respond to variations in organic source character (Murray et al., 1994).
The shape of n-alkane carbon isotopes with a trend towards isotopically lighter values
has been suggested for terrestrial organic matter; higher plant origin (Murray et al.,
1994; Schouten et al., 2001; Yangming et al., 2005). Marine oil commonly show a
flat or positively sloping profile for n-alkane isotopes, few studies have been reported
with respect to the sloping profiles of n-alkane carbon isotope from saline lake
environments (Murray et al., 1994). However, as suggested by Colister et al. (1994),
the mixing of materials from multiple sources could complicate n-alkane carbon
isotope profiles, because n-alkanes and their precursors are produced by a broad
range of organisms (e.g. algae, bacteria, and terrestrial vascular plants), with some
overlap among different classes of organisms.
2.3.2 Hydrogen Isotopes
Hydrogen isotope system is flexible, robust, accurate and provides a means for
measuring D/H ratios in many geochemically important organic compounds,
including hydrocarbons, sterols and fatty acids (Sessions et al., 1999). Hydrogen has
two (2) stable isotopes: proton and deuterium. The relative amount of these two
isotopes varies widely in different organic materials as a result of natural processes,
which cause isotopic fractionation. There is little isotopic variability within specific
compound classes in individual organisms, but there is significant variability between
compound classes, even among those that share common biosynthetic origins.
Hydrogen isotope (D/H) ratios of bulk organic hydrogen are a useful diagnostic tool
in fossil fuel research (Schimmelmann et al., 2004). The integration of hydrogen
isotopic data with conventional molecular parameter could provide improved
constraints for source depositional paleoenvironments, origin of organic matter, oil
maturity, migration and reservoir fluid mixing (Peters, 2000; Tuo et al., 2006). The
hydrogen isotope specific analysis was applied to oil and oil-source rock correlations
(Sessions et al., 1999; Sache et al., 2004; Tuo et al., 2006).
55

It was suggested that marine-derived sedimentary organic matter is likely to have
δD values near –150 ‰ if no significant isotopic exchange has occurred as a result of
secondary processes (Santos Neto and Hayes, 1999). Oils derived from terrestrial
organic matter preserve a much larger range of δD values than do oil derived from
marine organic matter (Schimmelmann et al., 2004). This presumably reflects the
greater variability of δD in the terrestrial hydrological cycle and provides a useful
tool for oil-to-source correlations (Tuo et al., 2006). The D/H ratios were also used as
a tool for correlating terrestrially sourced oils with potential rocks and for
recognizing related oils in complex basins (Schimmelmann et al., 2004). Thus,
compound specific isotope analysis can be used to enhance oil-source correlation in
coal bearing basin and greater understanding in the source of crude oils (Tuo et al.,
2006). The bulk δD values in oils can serve as proxy for isotopic composition of
ancient waters and thus serves as auxillary tool for paleoclimatic assessments (Santos
Neto and Hayes, 1999). The recent advent of compound specific hydrogen isotope
analysis (Burgoyne and Hayes, 1998; Hilkert et al., 1999) has allowed measurement
of the D/H composition of individual compounds in complex mixtures. Hydrogen
isotopes ratio of individual C27, C29 and C31 alkanes respond similarly to climatic and
environmental factors based on their similar range of values that is consistent with
their common origin from higher plant leaf waxes (Liu and Huang, 2005).
Considerable differences in hydrogen isotopic compositions occur among n-alkanes
from different terrestrial depsitional environments. A trend of depletion in deuterium
is observed for individual n-alkanes from terrestrial depositional environments in the
order of saline lacustrine, to fresh water paralic lacustrine, and to swamp. Therefore,
the δD of individual n-alkanes can be used to assess the origin of the organic matter
and depositional environment of the source rocks, and may possibly be helpful in
differentiating coal-derived oils from interbedded mud-stone-derived oils in coal
measures (Xiong et al., 2005; Tuo et al., 2006). However additional independent
geochemical evidence should be taken into account when depositional environments
of source rocks are reconstructed based on δD values of individual n-alkanes (Xiong
et al., 2005).
56

2.3.3 Sulphur Isotopes
Sulphur isotope ratios have been used to solve correlation problem but not as
widely employed as carbon isotopes (Hunt, 1996) because of the alteration of the
original δ 34 S of oils by secondary processes (Orr, 1974). Thode (1981) was able to
group thirty-eight oils from the Willston Basin of North Dakota and Saskatchewan
into source rocks of Ordovician, Mississippian (Bakken), and Pennsylvanian (Tyler)
age by their sulphur isotope ratios. Bordenave and Burwood (1990) used a crossplot
of δ 13 C versus δ 34 S to separate two groups of Iranian oils. It has also been shown
through sulphur isotope ratios that the heavy immature Monterey oils from Miocene
Monterey Formation was generated primarily by the Lower Monterey shale section;
in which the organic sulphur of the kerogen is >1 %. Thus high sulphur content is
characteristic of type IIA (II-S) kerogen and further support that the high sulphur
kerogens are the prime generators of immature, heavy oils (Hunt, 1996).
2.3.4 Oxygen Isotopes
Information concerning fractionation during photosynthesis of organic oxygen is
limited to studies of the δ 18 O of cellulose and other carbohydrates. Isotopic
composition of plant water determines the δ 18 O of organic bound oxygen in cellulose.
While there is no difference in δ 18 O of cellulose that can be related to photosynthetic
pathway, such as the C3 or C4 fixation pathway, real differences in the δ 18 O of
cellulose between species exists. The possible mechanism of these differences is
differential enrichment of leaf water with 18 O during evaporative transpiration
(Dongmann et al., 1974). Variations in the δ 18 O were recorded in submerged aquatic
plants (Sternberg et al., 1984). Overall photosynthetic rates and productivity of the
plant may also cause variability in δ 18 O.The relationship between climate, leaf water
and δ 18 O of cellulose may be substantially modified by subsequent exchange events.
57

2.4 Analytical Methods Employed in Geochemical Studies
Analytical techniques commonly in use for geochemical analysis has advanced
greatly over the last two decades. Some of these methods include Pyrolysis (hydrous,
non-hydrous and Rock-Eval pyrolysis), Gas Chromatography (GC), Gas
Chromatography-Mass Spectrometry (GC-MS), Pyrolysis-Gas Chromatography
Mass Spectrometry (Py-GC-MS), with the most recent addition of Gas
Chromatography-Isotope Ratio Mass Spectrometry (IRMS). These techniques are
briefly discussed below:
2.4.1 Pyrolysis
Most organic matter in source rock is insoluble in common organic solvents
and cannot be analysed directly by GC and GC/MS.Asphalthene which is a vital
constituent of source rock extracts and crude oil has limited solubility in most
solvents after isolation by precipitation and thus not directly amenable to GC and
GC/MS.Therefore characterization of asphalthenes and kerogens is possible through
their initial degradation by pyrolysis. Pyrolysis is an important step in all coal thermal
conversion processes. It is related with coal hydrogenation, combustion and
gasification. It is responsible for up to 70 % of the weight loss of coal, and it is
strongly dependent on its organic properties. The various forms of pyrolysis include:
58

2.4.1.1 Flash or Rapid temperature-programmed pyrolysis: This is a fingerprinting method
in which pyrolysis products are transferred rapidly to a GC column. The same
approach can also be used in an offline mode where the pyrolysis products are
trapped and then fractionated, if necessary, prior to analysis by GC or GC/MS
(Douglas and Grantham, 1974). Using a pyrobe analytical pyrolyser, directly coupled
to the inlet of a gas chromatograph and equipped with a mass spectrometer as
detector, pyrolysis becomes a powerful analytical technique for studying and
identifying the products of coal heating processes. Often, pyrolysis studies are
performed in small-scale reactors, simulating industrial scale reactors: wire mesh
reactor, curie-point reactor, pyrobe reactor, thermo-gravimetric reactor and
entrained-flow reactor (Bonfanti et al., 1997). A lot of products can be identified
with the coupling pyrobe-gas chromatograph-mass spectrometer (Bonfanti et al.,
1997).
2.4.1.2 Hydrous pyrolysis: Introduction of hydrous pyrolysis makes a significant
development in pyrolysis technique (Lewan et al., 1979; Winters et al., 1983). It is
undertaken in a high-pressure vessel in the presence of water. Reactions are typically
performed just below the critical temperature of water. By performing a series of
reactions at different temperature one can simulate the fate of the organic matter at
different burial depths. Information that is obtained in this manner can be used for
basin modelling purposes, or to determine the nature of the products generated and to
correlate them with other oils in the basin. The most significant impact of hydrous
pyrolysis is that it permits assessments of the fate of an immature rock as it is
matured at greater depths of burial. The related method of hydrous pyrolysis applies
thermal energy in the presence of water (Lewan et al., 1979; Winter et al., 1983;
Lewan, 1985; Barth et al., 1989) and has proved useful for releasing hydrocarbon
biomarkers weakly bound via sulphur or oxygen linkages to the kerogen moiety of
immature sulphur rich organic sediments (Greenwood et al., 2006).
59

2.4.1.3 Rock-Eval pyrolysis: This technique was developed by Espitalié et al. (1977).
It is a standardized pyrolysis method for source rock characterization and evaluation.
It gains widespread use in petroleum industry, where it became a principal analytical
tool. During the last 30 years the Rock-Eval apparatus has been routinely used in
organic geochemistry for examining the oil and gas potential of source rocks. Many
source evaluation parameters can be generated from the Rock-Eval analysis of source
rock (Table 3). Less than 100 mg of a sample is heated in an inert or oxidative
atmosphere under a programmed temperature pattern. The Rock-Eval instrument
mode of operation is shown in Fig. 4. Evolution of volatiles is examined in Rock
eval. A software OPTKIN has been developed for acquisition of pyrolysis kinetic
parameters using the Rock-Eval measurements. The more matured is an organic
matter; the higher is its Tmax. Rock-Eval pyrolysis is used to identify the type
(kerogen) and maturity of organic matter and to detect petroleum potential in fossil
fuels (Hunt, 1996; Peters et al., 2005; Moumouni et al., 2007). It has been noted that
Hydrogen Index (HI) values obtained from Rock-Eval analysis can be misleading, as
hydrocarbons may be adsorbed by the rock matrix (Langford and Blanc- Valleron
1990). Shale source rocks may therefore yield Rock-Eval pyrolysis-generated HIs
that are less than true average hydrogen index, while coaly source rocks may have
their HIs over-estimated. Therefore proposed the use of TOC vs. S2 and measuring
the adsorption of hydrocarbons by the rock matrix.
60

S2
S1
Free hydrocarbon, FID
Hydrocarbon, FID
Distillation, 300 o C
Total organic matter
Pyrolysis, 300-650 o C
Fig. 2.3 :Scheme of Rock-Eval analysis
61
S3
Kerogen
S4
COX (IR)
Residual
fraction
Oxidation,
850 o C
CO2 (IR)

Table 2.2:Rock-Eval Parameters (Johannes et al., 2007).
Sample Formula Description
S1 (mgHC/g sample) ― Free hydrocarbon (HC)
S2 (mgHC/g sample) ―
62
Hydrocarbon generated through thermal
cracking
S3 (mg CO2/g sample) ― Amount of CO2 produced during pyrolysis
S4 (mg CO2/g sample) ― Amount of CO2 produced during combustion
Tmax ( o C) ― The temperature at top of S2 peak
PI S1/S1+S2 Production Index
PC (%)
0.1[0.83(S1+S2) +0.273S3
+0.429(S3CO+0.53S3′CO)]
Pyrolysable organic carbon
TOC (%) PC+RC Total organic carbon
BI (mg HC/g TOC) 100S1/TOC Bitumen Index
HI (mg HC/g TOC) 100S2/TOC Hydrogen Index
OI (mg CO2/g TOC) 100S3/TOC Oxygen Index
RC (%) RC CO + RC CO2
Residual organic carbon

2.4.2 Gas chromatography/Mass spectrometry
The advent of GC/MS makes rapid analysis of an organic mixture with more
than 20 components possible (Simoneit, 2002). It requires very small sample size,
rapid and very high sensitivity. Much of the early work done was accomplished using
magnetic-sector mass spectrometers. When the quadrupole MS became
commerecially available in the mid-1970s the popularity of GC/MS increased
dramatically (Simoneit, 2002). Quadrupole systems although lacking high resolution
capabilities of magnetic sector instruments, were able to scan rapidly, did not have
any memory effects, were sensitive, easy to use; and did not require the elaborate
turning procedures of the magnetic sector systems. Computerized GC/MS is the
principal method used to evaluate biomarkers in fossil fuels. GC/MS can be used to
detect and provisionally identify compounds using relative gas chromatographic
retention times, elution patterns, and the mass spectral fragmentation patterns
characteristic of their structures. GCMS analyses can be operated in various modes.
Each mode provides a different type and quality of information.
2.4.3 Gas Chromatography-Isotope Ratio Mass Spectrometer (GC-IRMS)
GC-IRMS was first described by Mathews and Hayes (1978), but commercial
systems were available in the late 1980s (Simoneit, 2002). High precision isotope-
ratio detection of gas chromatographic analyte is now a mature technology, and is
enjoying widespread growth in a variety of fields including biogeochemistry and
paleoclimatology, archaeology, petroleum chemistry, environmental forensic, flavour
authentication, drug testing, metabolite tracing and others (Sessions, 2006). GC-
IRMS has been very useful in coal research through measurement of carbon,
hydrogen, oxygen, nitrogen and sulphur isotopes of biomarkers. For instance,
hydrogen isotopes are commonly fractionated to a much greater extent by different
processes than carbon isotopes and better respond to the hydrological cycle e.g.
meteoric water availability and isotope differences. Hydrogen isotope ratios are
strongly influenced by environment and biochemical studies (Bi et al., 2005).
63

Total organic hydrogen in coal encompasses hydrogen that is linked to carbon
either directly or via bridging heteroatoms like O, S and N.Some of this organic
hydrogen can isotopically exchange with hydrogen from ambient water, with
exchange half-lives ranging from seconds (in exposed hydroxyl, carboxyl and amino
groups) to millions of years; aliphatic carbon linked hydrogen (Schimmelmann et al.,
1999). The abundance of readily exchangeable organic hydrogen is expressed as
“hydrogen exchangeability”. Exchangeable organic hydrogen is the most chemically
reactive, polar hydrogen, and thus participates in oil and gas generation from coal. In
contrasts, non-exchangeable organic hydrogen may have preserved an isotopic
paleoenvironmental signal, but deuterium/hydrogen (D/H or 2 H/ 1 H) stable isotope
ratios in coals or coal kerogens are typically measured only for total hydrogen
(Mastalerz and Schimmelmann, 2002). The isotopically non-exchangeable portion of
organic hydrogen is chemically more stable than exchangeable hydrogen, and δDn
values of non-exchangeable hydrogen may therefore provide information about the
depositional environments (Mastalerz and Schimmelmann, 2002). Organic hydrogen
linked to oxygen and nitrogen tends to be more enriched in deuterium than carbon-
linked organic hydrogen (Schimmelmann et al., 1999). Some of this 2 H in functional
groups is sterically inaccessible to water during isotopic equilibration and thus
contributes to the pool of non-exchangeable hydrogen (Mastalerz and Schimmelmann,
2002). The integration of hydrogen isotopic data with conventional molecular
parameter could provide improved constraints for source depositional
paleoenvironments, origin of organic matter, oil maturity, migration and reservoir
fluid mixing (Peters 2000; Tuo et al., 2006). Tuo et al. (2006) compared the values of
δD measured for diterpenoids compounds with n-alkanes present in coal and reported
that diterpenoid hydrocarbons are 49-81 ‰ depleted in D relative to n-alkanes.
Hydrogen isotopic variations also occur between different diterpenoid compounds,
indicating a different source for these compounds (Tuo et al., 2006).
64

Based on the comparison of δD values of different classes of diterpenoid
compounds, which may be derived from the same biosynthetic precursors, a D
enrichment process (especially dehydrogenation) will be expected when a compound
is diagenetically altered from a natural precursor structure to a geological structure
(Tuo et al., 2006). Saline lakes are likely D-enriched due to evaporation of water,
while meteoric water as a main hydrogen source is relatively D-depleted in various
terrestrial environments (Xiong et al., 2005).
65

2.5 Geology of Benue Trough
2.5.1 Geological Settings
The Benue Trough (Fig. 2.4) is considered to have formed by the incipient
rifting during the breakaway of South America from Africa and the opening of south
Atlantic in Early Cretaceous (Albian) times (Whiteman, 1982). It trends SSW-NNE
for about 800 km in length and 150 km in width (Abubakar et al., 2006; Jauro et al.,
2007). The Benue Trough divide at its upper end to; the Gongola arm running north
into the Chad basin and the Yola arm terminating eastwards against the Cameroon
basement. There are various amounts of uplift and deformation that created a regional
unconformity in the Benue Trough.This is because full rifting never developed and its
sedimentary fill, accumulated in about 20Ma since Albian time, was folded by
complex stress created at the African plate margin in Santonian thereby regarded as
‘Failed Arm’ (Pearson and Obaje, 1999). The Trough contains about 6000 m thick of
Cretaceous-Palaeogene sediments that are organic rich in part. The Benue Trough can
be physiographically and lithostratigraphically subdivided into lower, middle and
upper BenueTrough (Fig. 2.5). The geology of Benue Trough has been extensively
reviewed (Carter et al., 1963; Peters, 1982; Peters and Ekweozor, 1982; Obaje 1994,
2000; Zaborski 2000; Obaje et al., 2004). Overlying the basal rift sandstones of Late
Necomian to Aptian age are thick shales and thin limestone deposited during marine
trangression (Peters and Ekweozor, 1982) in the Middle to Late Albian, Late
Cenomanian to Early Turonian, Late Turonian to Early Santonian, Campanian to
Maastrichtian, Paleocene, and Eocene.
66

Fig. 2.4 :Geological map of Benue Trough, Nigeria (modified after Obaje, 1994).
67

Fig. 2.5: Stratigraphic sequence of Benue Trough, Nigeria (Modified by Ehinola
et al., 2002).
68

The shale limestone sequence formed during Late Cenomanian to Early Turonian
includes Odukpani Formation of Calabar area, Eze-Aku/Makurdi Formation that
extends from North of Ishiagu in the Lower Benue Trough and Dukul, Gongila and
Pindiga Formations of Upper Benue Trough in the North Eastern Nigeria.The
limestone beds in these Formations are sufficiently thick in some places. After the
deposition of the limestone bearing sequence, the sea became shallower resulting in
the formation of swamps particularly in the Anambra basin. The swamps and
associated vegetation were later buried under thick sediments to produce coal-bearing
rocks.
2.5.2 Lithology Description
The coal bearing rocks consist essentially of Mamu Formation (lower coal
measure), Ajali sandstone (middle coal measure), and Nsukka Formation (upper coal
measures) in Anambra basin and Lower Benue Trough.In the Middle and Upper
Benue Trough, coaliferous beds also occur within Lafia and Gombe Formations,
which are considered as time equivalents of the Mamu and Nsukka Formations in the
southeastern Nigeria. The Mamu Formation consists of shale, siltstones, sandstones
and coals of a fluvio-deltaic to fluvio-estuarine environments whose lateral
equivalents are the conglomerates, cross-bedded and poorly sorted sandstones and
claystones of the Lokoja and Bida Formations in Bida basin (Akande et al., 2005).
Most of the previous authors described the depositional environment of the entire
Benue Trough as shallow marine and (in parts) anoxic (Peters 1977,1982). However,
more recent works on sedimentological structures and facies indicate different
depositional environments, at least in the Benue Trough based on new interpretation
of the limestone layers as turbidites and new faunal analysis (Gedhardt, 2001). On the
other hand, middle Benue Trough was deposited under marginal marine (paralic) and
continental conditions (Obaje, 1994; Gebhardt, 2001).
69

In the middle Benue Trough, the Precambarian Basement is overlain
uncomformably by the Asu River Group, and the Keana, Makurdi and
Awgu Formation overlie this unconformably while Lafia Formation unconformably
overlies the Awgu Formation (Ehinola et al., 2002). Different periods that were
recognized in the Middle Benue Trough are Albian, Cenomanian, Turonian,
Coniacian, Campanian-Maastrichtian and Paleocene.These periods have been
previously described (Ehinola et al., 2002). The upper Benue Trough bifurcates at its
northeastern end into the Gongola and the Yola basins (Abubakar et al., 2006; Jauro
et al., 2007). In this part of Benue Trough, a compressional phase occurred at the end
of the Maastrichtian.This event resulted in the folding and faulting of pre-Palaeogene
sediments (Abubakar et al., 2006). The oldest sediment consists of the Late Jurassic
to Albian continental Bima sandstone that rests uncomformably on Precambrian
basement rocks (Abubakar et al., 2006). The Bima Sandstone is comformably
overlain by the transitional marine Yolde Formation which is followed by marine
sequences of Pindiga Formation in the Gongola Basin, and their lateral equivalent of
Dukul, Jessu/Sekiliye, Numanha and Lamja Formations in the Yola Basin.The
youngest Cretaceous sediment in the upper Benue Trough is restricted to the Gongola
Basin.It is represented by the coastal (deltaic) Gombe Sandstone which
uncomformably covered the pre-mid-Santonian sequences in several places
(Abubakar et al., 2006).The continental sands,silts and shales of the Palaeogene
Kerri-Kerri Formation uncomformably overlie the Gombe Sandstone and mark the
end of sedimentation in the upper Benue Trough.Detailed description of upper Benue
Trough have been reported (Abubakar et al., 2006; Jauro et al., 2007).Regressive
sandstones along the basin margin interfinger with basinal marine and paralic
shale.These marine cycles and the early Cenomanian and Late Santonian
uncomformities in the Benue Trough provides a practical basis for subdividing the
sedimentary succession into the Albian Asu River group,a Late Cenomanian Early
Santonian sequence(Cross River group),and a post Satonian deltaic,Coal measures
and Paralic sequence (Peters and Ekweozor, 1982).
70

CHAPTER THREE
EXPERIMENTAL
3.1 SAMPLING AND SAMPLE PREPARATION
3.1.1 Sampling
A total of nine samples comprising of six coals, two carbonaceous shales and one
coaly shale were collected from 2 boreholes (BH94 and BH120) from Lafia-Obi,
Awgu Formation. The coal seams and interbedded shale in BH94 and BH120 were
sampled between 218-431 m and 131- 289 m depths respectively. The geological map
and detailed lithographic descriptions of the boreholes are presented in Fig. 3.1. In
Mamu Formation, twelve samples consisting of nine coals and three carbonaceous
shales were collected from Okaba and Onyeama.Okaba mine exposed on the floor of
the Okaba open cast mine located at Odagbo village (N07 o 28’ 41.2”, E007 o 43’46.
4”). The Onyeama seam is exposed along the Asata river channel situated at Enugu
escarpment (N06 o 28’ 23.8”, E007 o 26’ 44.7”). The lithographic section of Okaba and
Onyeama coal were presented in Fig. 3.2.
71

Fig. 3.1: Geological map and Lithographic section of BH94 and BH120 of
Lafia-Obi coal, Awgu Formation (Ehinola et al., 2002).
72

Fig. 3.2: Lithographic section of Onyeama and Okaba Mines in Mamu
Formation.
73

3.1.2 Extraction of Soluble Organic Matter
The samples were crushed with agate mortar and powdered to less than 120
mesh size prior to extraction. The powdered samples were Soxhlet extracted with
chloroform for 72 h. Activated copper powder was added to remove elemental sulphur
from the extracts. Excess solvent was distilled off using a hot water bath to an aliquot
volume of about 3 ml. The aliquot was then transferred to a weighed clean vial with a
micropipette and the remaining solvent removed under nitrogen gas flow at
temperature below 50 o C. The soluble organic matter was then weighed on a Mettler
balance.
3.1.3 Asphalthene Isolation
The asphalthene was separated from the coal extracts by gradual addition of n-
hexane with constant stirring (40 ml of n-hexane to 1 ml of extract). The resulting
mixture was kept inside dark cupboard overnight. The precipitated asphalthene was
removed by filteration on filter paper and purified by soxhlet extraction with n-hexane
until the solvent in the soxhlet is colourless. The asphalthene was recovered by
dissolution in dichloromethane. The dichloromethane was dried off, leaving the solid
asphalthene. The asphalthene was dried at 40 o C for 8 h in oven.
3.1.4 Fractionation
The maltene fraction left after asphaltene isolation was separated into saturated
and aromatic hydrocarbons and polar compounds (NSO compounds) by column
chromatography on neutral alumina over silica gel. Chromatographic column
(length/width ratio 50:1) was wet packed with activated silica gel (80-120 mesh,
ASTM) and aluminium oxide (70-325 mesh, ASTM) using n-hexane. Saturated,
aromatic and polar fractions were eluted with hexane (150 ml), dichloromethane (150
ml), and methanol (30 ml) respectively. The solvent was distilled off using rotary
evaporator to about 3 ml and thereafter transferred into a weighed clean vial. The
remaining solvent was removed under nitrogen gas flow at temperature below 50 o C.
The polar fraction was further derivatised prior to GC/MS analysis.
74

3.1.5 Derivatisation of Polar fraction
The polar fraction was derivatized using boron triflouric acid. 17-20 % BF3
(Boron triflouric acid) was prepared by adding 200 ml of BF3 to 300 ml CH3OH
(Methanol). 2 ml of prepared BF3 solution was added to about 1-2 mg polar fraction.
The resulting solution was kept in the water bath at about 60 o C for 24 h. The
esterified solution after 24 h was freed of the BF3 acid in a separating funnel by
addition of distilled water and diethyl ether. The mixture was shaken vigorously and
left for few minutes for the water and organic layer to separate. The aqueous layer
containing the BF3 was drained off. This procedure was repeated three times to wash
off the BF3 completely. The diethyl ether layer containing the derivatised polar
fraction was then collected and the solvent removed by evaporation.
3.2 ANALYTICAL METHODS
3.2.1 Leco Analysis
Total organic carbon (TOC) and Total Sulphur (TS) were measured by LECO
analyses. Carbon and sulphur concentrations in whole samples were measured in
duplicate by combustion in an induction furnace in a flow of oxygen, using a LECO
carbon-analyzer IR 112. Total organic carbon (TOC) was measured using samples that
had been treated with hydrochloric acid to remove carbonate.
3.2.2 Elemental Analysis
Elemental analysis (C, H, N, O) was performed using Carlo Erba 1108 CHNS-
O analyser. Hydrogen was determined by sample oxidation (1100 o C) and infrared (IR)
detection of H2O.The nitrogen content was obtained by thermal conductivity detection
(TCD) of N2. Oxygen was analyzed separately by transformation of all oxygenated
molecules into CO followed by oxidation over copper to CO2, which was measured
directly by IR detector.
75

3.2.3 Rock Eval Analysis
Rock Eval analyses were performed using standard technique as described by
Espitalié et al. (1977). This technique requires no demineralization or other
preparation except powdering the whole samples.
Less than 100 mg of a sample is heated in an inert or oxidative atmosphere under a
programmed temperature pattern with characterization of four peaks. S1 which is the
first peak represents hydrocarbon already present in the sample which are mainly
stripped at temperatures about 300 o C .The second peak, S2 represents hydrocarbons
generated through thermal cracking of kerogen at temperatures in the range of 300-
650 o C, while S3 peak represents the CO2 which is generated from the kerogen at the
same time the S2 hydrocarbons are being generated. The fourth peak, S4 indicates the
amount of CO2 produced through oxidation during combustion at a temperature of
about 850 o C. A software OPTKIN has been developed for acquisition of pyrolysis
kinetic parameters. The parameters include S1, S2, S3, HI, OI, S2/S3, PI, PC% and
Tmax for the assessment of kerogen qualities and maturation.
3.2.4. Gas chromatography-mass spectrometry analysis (GC-MS)
The GC-MS analyses of the fractions were performed on a Hewlett-Packard
6890N gas chromatograph interfaced to a Hewlett-Packard 5973N Mass spectrometer.
The gas chromatograph was equipped with a DB-5 MS fused silica capillary column
(30 m x 0.25 mm) and helium was used as carrier gas with a flow rate of 1ml/min.
The Mass spectrometer was operated with electron impact energy of 70 eV and ion
source temperature of 230 o C. The GC oven temperature was isothermal for 1min at
80 o C and then programmed from 80 to 280 o C at 3 o C/min and isothermal for 20 min
at 280 o C. Individual saturated, aromatic and NSO- compounds were monitored by
selected ion monitoring (SIM) at a cycle time of 1s.The GC-MS data were acquired
and processed with a Hewlett-Packard Chemstation data system.
76

3.2.5. Gas chromatography-isotope ratio mass spectrometry (GC-IRMS).
The Carbon isotope analyses of individual compounds were performed on a
Delta Plus XP Gas Chromatography-combustion-Isotope Ratio Mass Spectrometer.
The gas chromatography was performed using a Thermo Finnigan GC
COMBUSTION III system equipped with a DB-5 fused silica capillary column (30 m
x 0.25 mm) and helium was the carrier gas with a flow rate of 1 ml/min. The GC oven
temperature was isothermal for 1 min at 80 o C and then programmed from 80 to 280
o C at 3 o C/min and isothermal for 20 min at 280 o C.
Isotopic values were calculated by integrating the m/z 44,45 and 46 ion currents
of the peaks produced by combustion (830 o C) of chromatographically separated
compounds and those of CO2 standard spikes admitted at regular intervals. The
reproducibility and accuracy were evaluated routinely using laboratory standards of
known δ 13 C values (C16-C32 n-alkanes). Laboratory standard was injected for every
six-sample analysis. The isotope values are given with respect to the PDB standard.
The analyses were repeated twice and the results presented as an average value.
3.2.6. Vitrinite reflectance measurement
These analyses were carried out on the polished coal samples using a Zeiss
standard universal reflected microscope equipped with 100x oil immersion objective
and a 40x air objective. Measuremets were done at 546 nm (wavelength) on clear
spots of vitrinite particles (with distinct shape) of size approximately equal to or
greater than 10 µm before each series of measurements. The microscope set up was
calibrated with standard (glass) of known vitrinite reflectance within the range to be
measured. Thereafter, reflectance values were read off directly from the digital read
out.
77

4.1 ELEMENTAL ANALYTICAL DATA
CHAPTER FOUR
RESULTS AND DISCUSSIONS
Representative samples from Awgu and Mamu Formation were analysed for C,
H, O, N and S. The results in Table 4.1 were used to assess organic matter source,
depositional environment and thermal maturity of the samples.
4.1.1 Organic Matter Source and Depositional Environment
4.1.1.1 Awgu Formation
The C content varies from 76.04wt% to 82.10wt% with a mean of 79.40wt%
whilst H ranges between (4.79 to 5.16) wt% with a mean value of 5.03 wt%. Oxygen
values range from 8.10wt% to 10.40wt% with a mean value of 8.88wt% whilst
Nitrogen ranges between (1.76 to 2.29) wt% with a mean value of 2.06. The S content
varies from 0.38wt% to 1.29wt% with a mean value of 0.68wt%. The samples are
characterized by low sulphur contents (0.38 to 1.08) except a sample from BH120
with sulphur value of 1.29 wt%. The TOC/S ratio ranges from 8.1 to 52.8, indicating
non-marine coal (Berner, 1984; Bechtel et al. 2007a, b). It can be inferred from these
results that majority of the samples are of non-marine origin with few samples from
BH120 with values ranging between 8.10wt% to 15.00wt% which suggest little
marine incursion and/or organic matter deposited in lacustrine environment
(Brown and Kenig, 2004).
The TOC/N ratios range from 2.01-22.15 (Table 4.1). High TOC/N values (13.26-
22.15) obtained in three of the samples reflect terrigenous organic matter input
(Meyers, 1994; Bechtel et al., 2007a). The low values of (2.01-8.94) recorded in some
of the samples, indicating the presence of marine organic matter and/or lacustrine
algae (Meyers, 1994; Meyers et al., 2006; Bechtel et al., 2007a).
The plot of H/C against O/C ratios (Fig. 4.1) revealed all the samples plot within
the type III evolution path, indicating that the samples are derived mainly from
terrigenous organic matter (Van Krevelen et al., 1961).
78

4.1.1.2 Mamu Formation
The C content varies from 69.87wt% to 75.72wt% with a mean of 72.83wt%
whilst H ranges between (5.30 to 5.49) wt% with a mean value of 5.43 wt%. Oxygen
values range from 14.82wt% to 20.51wt% with a mean value of 17.42wt% whilst
Nitrogen ranges between (1.95 to 2.31) wt% with a mean value of 2.15wt%. The S
content varies from 0.094wt% to 1.94wt% with a mean value of 0.46wt%. Majority
of the samples have low sulphur content (0.09-0.52 wt%), except for the value of
1.94wt% obtained from sample OKB 8. The TOC/S ratios range from 12.9 to 234.7.
The low S content as well as the values of the TOC/S ratios indicates non-marine coal
(Bechtel et al., 2007b; Brown and Kenig, 2004).
The TOC/N ratios range from 20.49-31.51 (Table 4.1). These values reflect coal
derived from land plant organic matter (Meyers 1989, 1994; Dumitrescu and Brassell,
2006; Bechtel et al., 2007a). The samples show low H/C (

Samples
Awgu Formation
LB387
Table 4.1: Elemental Analysis and Vitrinite Reflectance Data of Nigerian Coal.
Lithology
(Rank)
Carbonaceous shale
Depth (m) TOC (%) % S % C % H % O % N H/C O/C C/N TOC/N TOC/S %VR
218.5-222.5 4.56 0.40 76.55 5.16 10.40 2.27 0.81 0.1 33.72 2.01 11.50 0.94
LB417 Coaly shale 407.4-412.5 6.72 0.45 ND ND ND ND ND ND ND ND 15.00 ND
LB420 Coal (B) 417.0-422.0 13.74 0.38 76.04 4.85 9.38 1.80 0.77 0.09 42.24 7.63 35.90 ND
LB514 Coal (B) 131.7-136.6 32.58 1.08 79.81 5.10 8.43 2.29 0.77 0.08 34.85 14.23 31.20 1.02
LB518 Coal (B) 148.0 30.38 0.90 ND ND ND ND ND ND ND ND 33.90 ND
LB523 Coal (B) 168.8-173.7 44.52 1.29 81.45 5.15 8.33 2.01 0.76 0.08 40.52 22.15 34.50 1.08
LB534 Coal (B) 212.1-216.2 19.85 0.38 82.10 5.10 8.10 2.22 0.75 0.07 36.98 8.94 52.80 1.15
LB542 Carbonaceous shale 247.0 5.81 0.72 ND ND ND ND ND ND ND ND 8.10 ND
LB551 Coal (B) 286.0-289.0 23.34 0.51 80.42 4.79 8.66 1.76 0.71 0.08 45.69 13.26 45.40 1.15
Mamu Formation
OY5
Carbonaceous shale
4.6-5.8 4.53 0.09 ND ND ND ND ND ND ND ND 12.90 ND
OY4 Coal (SB) 6.0-6.8 66.79 0.35 74.74 5.49 14.82 2.12 0.88 0.15 35.26 31.51 189.70 0.57
OY3 Coal (SB) 6.8-7.3 61.09 0.39 ND ND ND ND ND ND ND ND 157.50 ND
OY2 Coal (SB) 7.6-8.4 65.11 0.37 ND ND ND ND ND ND ND ND 177.90 ND
OY1 Coal (SB) 8.4-8.8 46.71 0.20 75.72 5.30 14.92 1.95 0.84 0.15 38.83 23.95 234.70 0.60
OY6 Carbonaceous shale 9.0-9.5 9.93 0.44 ND ND ND ND ND ND ND ND 22.60 ND
OKB4
Carbonaceous shale
16.5-17.6 4.14 0.17 ND ND ND ND ND ND ND ND 24.60 ND
OKB3 Coal (SB) 18.0-18.5 59 0.34 71.00 5.44 19.41 2.31 0.92 0.21 30.74 25.54 174.00 0.48
OKB2 Coal (SB) 18.6-18.9 52.81 0.52 ND ND ND ND ND ND ND ND 101.40 ND
OKB1 Coal (SB) 18.9-19.3 27.53 0.30 ND ND ND ND ND ND ND ND 93.00 ND
OKB7 Coal (SB) 19.3-19.6 54.72 0.41 ND ND ND ND ND ND ND ND 132.50 ND
OKB8 Coal (SB) 19.6-20.0 45.7 1.94 69.87 5.47 20.51 2.23 0.94 0.22 31.33 20.49 23.60 0.50
ND – not determined
OY – Onyeama
OKB – Okaba
(B) – Bituminous; (SB) – Sub-bituminous
80

Fig. 4.1: Plot of Atomic H/C against O/C of Coal Samples from Benue
Trough, Nigeria. (After Van Krevelen et al., 1961).
81

4.2 Source Rock Evaluation of Nigerian Coal.
The hydrocarbon potential of the coals was assessed by Leco analysis and Rock
Eval pyrolysis. Data from Leco and Rock Eval analyses are presented in Table 4.2.
4.2.1 Organic Matter Concentration:
The quantity of organic matter contained in the samples was evaluated from the Total
Organic Carbon (TOC) content and Genetic Potential (GP) values. The TOC and GP
values are presented in Table 4.2.
4.2.1.1 Awgu Formation
The TOC values for the carbonaceous shale and coaly shale range between
4.56wt% to 6.72wt% with a mean value of 5.70wt%. While the coal, TOC values vary
between 13.74wt% to 44.52wt% with a mean value of 27.40wt%. The TOC values in
all the samples exceeded the minimal 0.5 wt% required for a potential source rock
(Tissot and Welte, 1984; Killops and Killops, 1993; Hunt, 1996).
The GP values for the carbonaceous shale and coaly shale range between
3.2mg/g to 5.7mg/g with a mean value of 4.4mg/g. While the coal, GP values vary
between 19.1mg/g to 90.8mg/g with a mean value of 42.4mg/g. The GP values are
greater than 2 mg/g required for a potential source rock (Tissot and Welte, 1984;
Killops and Killops 1993,2005; Hunt, 1996; Peters et al. 2005). The values indicate
moderate to good source rock.
82

Samples
Awgu
Formation
LB387
Lithology
(Rank)
Carbonaceous
shale
Table 4.2 : TOC and Rock-Eval Pyrolysis Data.
OY – Onyeama
OKB – Okaba
(B) – Bituminous; (SB) – Sub-bituminous
S 1= hydrocarbon already present in the sample which are mainly stripped at temperatures about 300 o C.
S 2= hydrocarbons generated through thermal cracking of kerogen at temperatures in the range of
300-650 o C.
Depth (m) TOC (%) Tmax ( o C) S1 (mg/g) S2 (mg/g) S3 (mg/g) PI (S1/S1+S2) HI (mg/gTOC) OI (mg/gTOC)
218.5-222.5 4.6 446 0.91 4.82 1.1 0.16 105 24 5.7
LB417 Coaly shale 407.4-412.5 6.7 447 0.89 3.55 0.64 0.2 52 9 4.4
LB420 Coal (B) 417.0-422.0 13.7 453 1.92 17.76 2.08 0.1 129 15 19.7
LB514 Coal (B) 131.7-136.6 32.6 451 12.88 77.92 2.36 0.14 239 7 90.8
LB518 Coal (B) 148.0 30.4 469 3.58 25.16 2.48 0.12 82 8 28.7
LB523 Coal (B) 168.8-173.7 44.5 459 10.28 57.84 3.42 0.15 129 7 68.1
LB534 Coal (B) 212.1-216.2 19.9 455 4.32 23.48 1.44 0.16 118 7 27.8
LB542
Carbonaceous
shale
247.0 5.8 454 0.82 2.4 0.88 0.25 41 15 3.2
LB551 Coal (B) 286.0-289.0 23.3 455 2.34 16.76 2.86 0.12 71 12 19.1
Mamu
Formation
OY5
Carbonaceous
shale
S 3= CO 2 that is generated from the kerogen at the same time the S 2 hydrocarbons are being generated.
Tmax = Temperature of maximum generation of S 2 peak.
83
GP (mg/g)
4.6-5.8 4.5 438 0.48 15.58 1.08 0.03 343 23 16.1
OY4 Coal (SB) 6.0-6.8 66.8 432 4.18 166.48 7.2 0.02 249 10 170.7
OY3 Coal (SB) 6.8-7.3 61.1 433 3.6 154 7 0.02 252 11 157.6
OY2 Coal (SB) 7.6-8.4 65.1 435 4.66 168.96 6.92 0.03 259 10 173.6
OY1 Coal (SB) 8.4-8.8 46.7 437 2.2 109.52 5.38 0.02 234 11 111.7
OY6
OKB4
Carbonaceous
shale
Carbonaceous
shale
9.0-9.5 9.9 434 0.56 19.56 2.12 0.03 196 21 20.1
16.5-17.6 4.1 425 0.24 4.92 7.56 0.05 118 182 5.2
OKB3 Coal (SB) 18.0-18.5 59.0 421 6.8 160.72 14.32 0.04 272 24 167.5
OKB2 Coal (SB) 18.6-18.9 52.8 416 19.32 148.4 21.44 0.12 281 40 167.7
OKB1 Coal (SB) 18.9-19.3 27.5 425 4.58 127.2 26.96 0.03 462 97 131.8
OKB7 Coal (SB) 19.3-19.6 54.7 421 3.86 116 22.88 0.03 211 41 119.9
OKB8 Coal (SB) 19.6-20.0 45.7 423 4.44 121.12 21.92 0.04 265 47 125.6
S1 + S2

4.2.1.2 Mamu Formation
Samples from Mamu Formation have high TOC values ranging from
27.53wt% to 59.00wt% with a mean value of 47.95wt% in Okaba and 46.71wt% to
66.79wt% with a mean value of 59.93wt% in Onyeama coals. The TOC of
interbedded carbonaceous shale is 4.14wt% in Okaba while Onyeama samples have
values of 4.53wt% and 9.93 wt%.
The GP values for the coal samples range from 119.9-167.7 mg/g with a mean
value of 142.5mg/g in Okaba and 111.7mg/g to 173.6 mg/g with a mean value of
153.4mg/g in Onyeama coals. The interbedded carbonaceous shale from Okaba has
GP value of 5.2 mg/g while values of 16.1mg/g and 20.1 mg/g were recorded in
Onyeama. These values are greater than 0.5 wt% and 2 mg/g respectively required for
a potential source rock (Tissot and Welte, 1984; Killops and Killops 1993, 2005; Hunt,
1996; Peters, et al. 2005), and thus indicate good to excellent source rock potential.
4.2.2 Organic Matter Quality:
The quality of the organic matter contained in the coal samples was evaluated from
their Hydrogen Index (HI), plots of HI vs. OI (equivalent to van Krevelen diagram),
plot of Tmax vs HI and plots of S2 vs. TOC.
4.2.2.1 Awgu Formation
The HI values in Awgu samples range from 41-239 mg/gTOC (av. 107.3). These
low HI values indicate type III kerogen, capable of generating gas only (Peters 1986;
Sachsenhofer et al. 1995).
Plots of HI against OI, S2 vs. TOC and Tmax against HI for the samples are shown
in Figs. 4.2, 4.3 and 4.4 respectively. The samples fall within type III evolution path
on the plots of HI vs OI (Fig. 4.2) and S2 vs. TOC (Fig. 4.3), indicating gas prone
(Killops and Killops 1993, 2005). The potential of the samples to generate mainly gas
was further confirmed on the plot of Tmax vs HI where all the samples were plotted
within the gas prone zone (Fig. 4.4).
84

Fig. 4.2 : Plots of HI vs OI of Coal Samples from Benue Trough, Nigeria
(After Van Krevelen et al., 1961).
85

4.2.2.2 Mamu Formation
The Hydrogen index (HI) values for Onyeama samples range from 196mg/gTOC to
343mg/gTOC with a mean value of 255.5mg/gTOC, the highest value of
343mg/gTOC was recorded in the carbonaceous shale at the top of the seam. In Okaba
samples the HI values range from 118mg/gTOC to 462mg/gTOC with a mean value
of 268.2mg/gTOC. These values suggest that the coal is capable of generating both oil
and gas (Killops and Killops 1993, 2005). The plots of HI against OI and S2 against
TOC (Figs. 4.2 and 4.3), all the samples fall within type II/III kerogen fields. The
Tmax vs HI plot (Fig. 4.4), further reveal that the samples plot within oil and gas zone.
These features confirm their oil and gas generative potential.
4.2.3 Thermal Maturity of Organic Matter
The thermal maturity status of the samples was determined using pyrolysis
parameters (Tmax and Production index (PI), plots of PI vs. Tmax and plots of HI vs.
Tmax) and Vitrinite reflectance measurements from petrographic analyses.
4.2.3.1 Awgu Formation
The Tmax and PI values in Awgu samples range from 446-459 o C (av. 454) and
0.10-0.29 (av. 0.15) respectively. These values indicate organic matter within the main
phase of oil generation-late oil window. The Vitrinite reflectance (VR) values of Awgu
samples range from 0.94-1.14 %R0 (av. 1.07). These values show that the samples are
at the peak of oil generation (Killops and Killops, 2005; Peters et al., 2005). The high
vitrinite reflectance recorded for Awgu Formation samples at the shallow depth is
probably due to the activity of erosion, which has exposed the coal seam to the
surface.
86

Fig. 4.3 : Plots of S2 vs TOC of Coal Samples from Benue Trough, Nigeria
(After Langford and Blanc-Valleron, 1990).
87

Fig. 4.4 : Plot of Tmax vs HI. Of Coal Samples from Benue Trough, Nigeria
(After modified by Akande et al., 2007).
88

Vitrinite reflectance values were estimated from the plots of HI vs. Tmax for the
Awgu samples (Fig. 4.5). Majority of the samples have VR of about 1.0 %R0. These
values agreed with the vitrinite reflectance data obtained from the petrographic
analysis. The samples also fall within the oil/condensate field (Fig. 4.7).
4.2.3.2 Mamu Formation
The Tmax values range from 432-438 o C (av. 435) and 416-425 o C (av. 422) for
Onyeama and Okaba samples respectively. These values show that the samples are
presently thermally immature and are probably within the late diagenesis stage
(Killops and Killops 1993, 2005). The PI values for Okaba and Onyeama samples
range from 0.03-0.12 (av. 0.05) and 0.02-0.03 (av. 0.025) respectively. The low PI
values recorded for all the samples indicate that they are thermally immature.
The Vitrinite reflectance values range from 0.48-0.50 %R0 (av. 0.49) and 0.57-
0.60 %R0 (av. 0.58) Okaba and Onyeama samples respectively and indicate late
diagenesis - early oil window. The Vitrinite reflectance values estimated from the plot
of HI vs. Tmax. (Fig. 4.6) show VR

Fig. 4.5 : Plots of HI vs Tmax of Coal Samples from Awgu Formation.
90

Fig. 4.6 : Plots of HI vs Tmax of Coal Samples from Mamu Formation.
91

Fig. 4.7 : Plots of PI vs Tmax of Coal Samples from Benue Trough, Nigeria.
92

4.3 Biomarker Geochemistry of the Nigerian Coal
The source, depositional environment and thermal maturity status of the
organic matter contained in the samples were determined based on the distributions
and abundance of aliphatic biomarkers in the coal extracts.
4.3.1 n-Alkane and Isoprenoid distributions
The m/z 85 mass chromatograms showing the distribution of n-alkane and
isoprenoids in the samples are shown in Figs.4.8, 4.9 and 4.10. Geochemical
parameters calculated from the alkane distribution are given in Table 4.3.
4.3.1.1 Awgu Formation
The n-alkane distribution in Awgu samples range from C14-C35 maximizing at
n-C16 or n-C18 (Fig.4.8). This pattern of distribution indicates organic matter derived
from both marine and terrestrial (Peters et al., 2005). The samples plotted within the
terrestrial organic matter zone on the plots of Pr/nC17 vs. Ph/nC18 in Fig. 4.11.
Pr/Ph ratio calculated for the Awgu samples range from 3.04 to 11.07 (Table 4.3).
All the samples have Pr/Ph ratio greater than 3.0, typical of land plant detritus
deposited under aerobic (oxic) condition (Peters et al., 2005).
The Carbon Preference Index (CPI) and Odd-Over-Even Predominance (OEP)
values range from 0.98 to 1.12 and 0.98 to 1.06 respectively. These values reflect high
maturity status of the samples (Peters et al., 2005). Also, the plots of CPI against OEP
show that the samples are thermally mature (Fig. 4.12).
93

Fig. 4.8 : m/z 85 Mass chromatograms of aliphatic fractions of Awgu samples (BH 94)
showing the distribution of n-Alkanes.
94

Fig. 4.8 (contd.): m/z 85 Mass chromatograms of aliphatic fractions of Awgu samples
(BH 120) showing the distribution of n-Alkanes.
95

Fig. 4.9 : m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation samples
(Okaba) showing the distribution of n-Alkanes.
96

Fig. 4.9 (contd.): m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation
samples (Okaba) showing the distribution of n-Alkanes.
97

Fig. 4.10 : m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation samples
(Onyeama) showing the distribution of n-Alkanes.
98

Fig. 4.10 (contd.): m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation
samples (Onyeama) showing distribution of n-Alkanes.
99

Table 4.3 : n-Alkanes and Isoprenoids Parameters.
Samples Depth (m)
Awgu Formation
LB387 218.5-222.5
Pr- Pristane, Ph- Phytane
CPI = ½[(C25 + C27 +C29 + C31 + C33/C24 +C26+C28+C30+C32+C34) + (C25 + C27 +C29 + C31 +
C33/C26+C28+C30+C32+C34)], CPI (1) = 2(C23+C25+C27+C29)/[C22+2(C24+C26+C28) +C30]
OEP (1) = C21+6C23+C25/ 4(C22+C24), OEP (2) = C25+6C27+C29/ 4(C26+C28)
OY – Onyeama
OKB – Okaba
Lithology
(Rank)
Carbonaceous
shale
(B) – Bituminous; (SB) – Sub-bituminous
Pr/Ph Pr/nC17 Ph/nC18 CPI CPI (1) OEP (1) OEP (2) Crange Cmax
6.14 1.81 0.23 1.12 1.08 1.03 1.06 C13-36 C23
LB417 407.4-412.5 Coaly shale 3.16 0.50 0.13 1.02 1.01 0.98 1.00 C14-37 C18, C20
LB420 417.0-422.0 Coal (B) 5.49 0.30 0.03 1.07 1.02 0.99 1.00 C16-32 C18
LB514 131.7-136.6 Coal (B) 3.52 0.24 0.06 1.05 1.02 0.99 1.02 C13-35 C19
LB518 148.0 Coal (B) 5.25 0.68 0.11 1.09 1.04 0.99 1.06 C13-35 C20
LB523 168.8-173.7 Coal (B) 6.52 0.54 0.08 1.10 1.05 0.99 1.05 C13-35 C16
LB534 212.1-216.2 Coal (B) 4.60 0.28 0.06 1.07 1.04 1.01 1.03 C13-35 C16, C18, C20
LB542 247.0
Carbonaceous
shale
11.07 1.69 0.09 1.04 0.99 0.98 0.99 C15-33 C27
LB551 286-289 Coal (SB) 3.04 0.34 0.08 1.06 1.03 0.99 1.03 C13-35 C18, C20, C21, C22
Mamu Formation
OY5 4.6-5.8
Carbonaceous
shale
9.33 10.89 0.83 2.11 1.99 1.22 1.86 C14-35 C29
OY4 6.0-6.8 Coal (SB) 10.48 52.19 2.83 2.13 1.87 0.65 1.89 C13-35 C29
OY3 6.8-7.3 Coal (SB) 11.55 40.09 2.23 1.97 1.91 0.73 1.93 C13-35 C29
OY2 7.6-8.4 Coal (SB) 9.66 27.31 3.06 2.22 1.85 0.86 1.80 C13-35 C29
OY1 8.4-8.8 Coal (SB) 9.87 40.33 1.63 2.17 1.96 1.16 1.88 C14-35 C27, C29
OY6 9.0-9.5
OKB4 16.5-17.6
Carbonaceous
shale
Carbonaceous
shale
12.47 14.99 1.05 2.32 2.12 1.15 2.27 C14-35 C29
2.11 3.40 1.08 3.76 3.00 1.30 3.08 C14-37 C29
OKB3 18.0-18.5 Coal (SB) 1.73 2.94 0.72 5.18 5.82 1.29 5.16 C15-35 C29
OKB2 18.6-18.9 Coal (SB) 3.76 5.42 1.27 7.38 8.72 1.29 7.06 C12-35 C29
OKB1 18.9-19.3 Coal (SB) 4.08 4.51 0.74 6.51 7.20 1.28 6.28 C13-35 C29
OKB7 19.3-19.6 Coal (SB) 3.30 2.57 0.70 5.93 6.16 1.38 6.13 C12-35 C29
OKB8 19.6-20.0 Coal (SB) 2.11 2.53 0.86 6.02 6.48 1.16 6.02 C13-35 C29
100

Fig. 4.11: Plots of Pr/nC17 against Ph/nC18 of Awgu and Mamu Formation samples.
101

Fig. 4.12 : Plots of CPI against OEP of Awgu and Mamu samples.
102

4.3.1.2 Mamu Formation
The n-alkanes distribution in Mamu samples range from C14- C35, maximizing at
C27 or C29 (Fig. 4.9, 4.10). This pattern indicates organic matter derived mainly from
terrestrial organic matter. High proportions of long chain C27-C31 members relative to
the total n-alkanes especially are typical of terrestrial higher plants (Eglinton and
Hamilton, 1963; Caldicott and Eglinton, 1973; Tissot and Welte, 1984; Barthlot, et al.,
1998; Miranda, et al., 1999). The Pr/Ph ratios range from 9.33 to 12.47 and 1.73 to
4.08 for Onyeama and Okaba samples respectively (Table 4.3). All the samples,
except some few from Okaba have Pr/Ph ratio greater than 3.0, typical of land plant
detritus deposited under aerobic (oxic) condition (Killops and Killops, 2005; Peters et
al., 2005; Tuo et al., 2007). The few samples having low Pr/Ph ratios can be
interpreted as being deposited under sub-oxic to oxic settings (Killops and Killops,
2005; Peters et al., 2005; Tuo et al., 2007).
The Carbon Preference Index (CPI) and Odd-over-even predominance (OEP)
values in Onyeama samples range from 1.85 to 2.32 and 0.65 to 2.27 respectively.
The for Okaba samples range from 3.00 to 8.72 and 1.16 to 7.06 respectively. The
high CPI (>>1) and OEP values observed are characteristic of low rank coal i.e. sub-
bituminous (Bray and Evan, 1961; Scalan and Smith, 1970; Tissot and Welte, 1984;
Bechtel et.al., 2004; Sabel et al., 2005; Stefanova et al., 2005). The plot of CPI
against OEP show that these samples are immature to low mature (Fig. 4.12).
4.3.2 Fatty acids and alkanones
The distributions of fatty acids in the polar fraction have been successfully
used to differentiate the biological source of geological materials (Duan et al., 1997).
The m/z 58 and m/z 74 mass chromatograms showing the distributions of the saturated
n-fatty acids and alkan-2-ones in the coal extracts are shown in Figs.
4.13,4.14,4.15,4.16,4.17 and 4.18 respectively. Parameters calculated from the fatty
acids and alkanones distribution in the coal extracts are listed in Table 4.4.
103

4.3.2.1 Awgu Formation
Awgu samples have n-fatty acids ranging from C14 to C30, maximizing at nC16 or
nC18 (Fig. 4.13). The short chain/long chain saturated fatty acid (ATRFA) ratios for the
samples which range from 0.97-1.00, indicate both terrestrial and marine organic
matter derived material (Wilkes et al., 1999). Abundance of short chain saturated
n-fatty acids (C20) in the samples can be attributed to curticular waxes of higher plants (Cranwell,
1974).
The carbon preference index (CPIFA) of the long chain n-fatty acids (C24-C30)
range between 1.98 and 3.29 (Table 4.4), indicating a strong even over odd-
predominance. These values inferred high maturity status for the samples (Wilkes et
al., 1999).
The distribution of straight chain n-alkan-2-ones range from nC14-nC33,
maximizing at nC17 (Fig. 4.16). Similar distribution has previously been observed in
stalagmites (Xie et al., 2003; Bai et al., 2006). However, some of the samples
maximize at nC23 or nC25 (Fig. 4.16), an indication of contribution from higher plants,
microalgae and phytoplankton organic matter inputs (Hernandez et al., 2001;
Gonzalez-Vila et al., 2003).
104

Fig. 4.13: m/z 74 mass chromatogram showing the distribution of n-fatty acids in
Awgu samples (Numbers refer to carbon chain lengths of n-fatty acids).
105

Fig 4.13 (contd.): m/z 74 mass chromatogram showing the distribution of n-fatty
acids in Awgu samples (Numbers refer to carbon chain lengths of n-fatty acids).
106

Fig. 4.14: m/z 74 mass chromatogram showing the distribution of n-fatty acids in
Mamu samples (Okaba) (Numbers refer to carbon chain lengths of n-fatty acids).
107

Fig. 4.15: m/z 74 mass chromatogram showing the distribution of n-fatty acids in Mamu
samples (Onyeama) (Numbers refer to carbon chain lengths of n-fatty acids).
108

Fig. 4.15 (contd.): m/z 74 mass chromatogram showing the distribution of n-fatty acids in
Mamu samples (Onyeama) (Numbers refer to carbon chain lengths of n-fatty acids). (Numbers
refer to carbon chain lengths of n-fatty acids).
109

Fig. 4.16: m/z 58 mass chromatograms showing the distributions of alkan-2-ones in Awgu
samples (Numbers refer to carbon chain lengths of alkan-2-ones).
110

Fig. 4.17: m/z 58 mass chromatograms showing the distributions of alkan-2-ones in Mamu
samples (Okaba) (Numbers refer to carbon chain lengths of alkan-2-ones).
111

Fig. 4.18: m/z 58 mass chromatograms showing the distributions of alkan-2-ones in Mamu
samples (Onyeama) (Numbers refer to carbon chain lengths of alkan-2-ones).
112

Table 4.4: Parameters calculated from n-Fatty acids and alkanones composition of Nigerian Coal.
Samples Depth (m) Lithology (Rank) ATR FA CPI LFA Pr-2-one/C17 CPI (alkanone)
Awgu
Formation
LB387 218.5-222.5 Carbonaceous shale 0.99 ND 0.58 0.84
LB417 407.4-412.5 Coaly shale 0.99 ND 0.80 0.85
LB420 417.0-422.0 Coal (B) 1.00 ND 1.09 1.14
LB514 131.7-136.6 Coal (B) 1.00 ND 0.51 0.89
LB518 148.0 Coal (B) 0.99 2.46 0.60 0.76
LB523 168.8-173.7 Coal (B) 0.99 1.98 0.39 1.01
LB534 212.1-216.2 Coal (B) 0.99 3.29 1.59 0.76
LB542 247.0 Carbonaceous shale 0.97 3.20 0.86 0.93
LB551 286.0-289.0 Coal (B) 0.98 ND 0.82 1.20
Mamu
Formation
OY5 4.6-5.8 Carbonaceous shale 0.95 1.47 4.39 1.27
OY4 6.0-6.8 Coal (SB) 0.91 1.37 10.54 1.45
OY3 6.8-7.3 Coal (SB) 0.92 1.61 8.69 1.51
OY2 7.6-8.4 Coal (SB) 0.92 2.07 12.18 1.69
OY1 8.4-8.8 Coal (SB) 0.96 1.25 7.45 1.30
OY6 9.0-9.5 Carbonaceous shale 0.94 1.61 4.10 1.60
OKB4 16.5-17.6 Carbonaceous shale ND ND ND ND
OKB3 18.0-18.5 Coal (SB) 0.85 2.78 8.68 2.66
OKB2 18.6-18.9 Coal (SB) 0.93 1.37 7.69 2.25
OKB1 18.9-19.3 Coal (SB) 0.94 1.95 12.69 2.59
OKB7 19.3-19.6 Coal (SB) 0.96 1.44 13.71 2.49
OKB8 19.6-20.0 Coal (SB) 0.91 2.51 21.43 2.10
ATR FA = Short chain/long chain saturated fatty acid
CPI LFA= Carbon Preference Index (Longchainfatty acids)
CPI (alkanones)= Carbon Preference Index (alkan-2-ones).
ATR FA = C 14 + C 16 + C 18 / C 14 + C 16 + C 18 + C 26 + C 28 + C 30
CPI LFA=½{(C24+C26+C28+C30/C21+C23+C25+C27)+(C24+C26+C28+C30/C23+C25+C27+C29)}
CPI(alkanones)=1/2{(C25+C27+C29+C31+C33)/(C22+C24+C26+C28+C30+C32)
+(C25+C27+C29+C31+C33)/ C24+C26+C28+C30+C32+34}}
OY – Onyeama
OKB – Okaba
(B) – Bituminous
(SB) – Sub-bituminous
ND – Not determined
113

4.3.2.2 Mamu Formation
Mamu samples have saturated n-fatty acids ranging from C8 to C32,
maximizing at nC16 or nC18 (Fig. 4.14 and 4.15). These distributions reflect organic
matter from both marine and terrestrial materials (Volkman et al., 1998). However the
dominance of short chain (nC22) in the samples can
be attributed to the contribution of higher plants to the organic matter (Cranwell,
1974). The ATRFA ratios range from 0.85 to 0.96. These values indicate organic matter
derived from mixed origin (Wilkes et al., 1999). The carbon preference index (CPILFA)
for the long chain saturated n-fatty acids range between 1.25 and 2.78, indicating a
slight even over odd predominance (Table 4.4). These values indicate low maturity
(Wilkes et al., 1999).
The n-alkan-2-ones range from nC12 to nC33, maximizing at nC17 or nC29
(Fig. 4.17 and 4.18). These distributions reflect higher plants and algae inputs to the
organic matter (Bai et al., 2006). The CPI values range from 1.27 to 1.69 and 2.10 to
2.66 in Onyeama and Okaba samples respectively (Table 4.4). These values indicate
low maturity status for all the samples (Tuo et al., 2007).
4.3.3 Tricyclic and C24 tetracyclic terpanes
The m/z 191 showing the distributions of tricyclic and tetracyclic terpanes in the
samples are shown in Fig. 4.19,4.20 and 4.21. Peak identities are listed in Table 4.6.
4.3.3.1 Awgu Formation
A series of tricyclic terpanes ranging from C19 to C29 are observed in Awgu
samples (Figs. 4.19). Higher percentages of C19-C21 compared to C23 tricyclic terpanes
indicate organic matter derived from terrestrial origin (Ozcelik and Altunsoy, 2005).
The C24 tetracyclic terpane is present in appreciable amounts in all the samples.
The C24tetra/C26tri(R+S) ratios range between 0.96 and 3.45, probably reflecting
terrigenous organic matter input (Philp and Gilbert, 1986).
114

Various ratios of tricyclic terpanes have been used to distinguish marine carbonate,
lacustrine, paralic, coal/resin and evaporitic source depositional environments
(De Grande et al., 1993; Tuo et al., 1999; Yangming et al., 2005; Peters et al., 2005).
C22/C21 tricyclic terpane ratio in the samples range from 0.16 to 0.42, suggesting
organic matter deposited in lacustrine-fluvial/deltaic depositional environment (Peters
et al., 2005). C24tetra/C30hopane ratio has also been used to assess depositional
environment of source rock (Peters et al., 2005). C24tetra/C30hopane ratios in the
sample range between 0.11 and 0.43. These values also indicate organic matter
deposited in lacustrine-fluvial/deltaic depositional environment (Peters et al., 2005).
115

Fig. 4.19 :m/z 191 showing the distribution of tricyclic and tetracyclic terpane in
Awgu samples.
116

Fig. 4.20: m/z 191 showing the distribution of tricyclic and tetracyclic terpane in
Mamu Formation samples (Okaba).
117

Fig. 4.21 : m/z 191 showing the distribution of tricyclic and tetracyclic terpane in
Mamu Formation samples (Onyeama).
118

Sample
Table 4.5 : Tri- and tetracyclic terpanes source and depositional environment parameters.
Awgu Formation
Depth
(m)
Lithology
(Rank)
C24tetra/
C30hopane
119
C24tetra/
C26(R+S)tri
C22/C21 triterpane
%C19-C21
triterpane
LB387 218.5-222.5 Carbonaceous shale 0.10 2.50 0.24 83.70 16.30
LB417 407.4-412.5 Coaly shale 0.18 2.47 0.24 77.30 22.70
LB420 417.0-422.0 Coal (B) 0.43 2.84 0.23 82.50 17.50
LB514 131.7-136.6 Coal (B) 0.18 2.55 0.17 82.40 17.60
LB518 148.0 Coal (B) 0.24 2.14 0.26 86.20 13.80
LB523 168.8-173.7 Coal (B) 0.24 3.45 0.17 84.70 15.30
LB534 212.1-216.2 Coal (B) 0.21 2.29 0.42 93.60 6.40
LB542 247 Carbonaceous shale 0.32 0.96 0.16 82.10 17.90
LB551 286.0-289.0 Coal (B) 0.18 1.33 0.27 72.70 27.30
Mamu Formation
OY5 4.6-5.8 Carbonaceous shale 0.08 2.40 0.65 83.00 17.00
OY4 6.0-6.8 Coal (SB) 0.09 2.86 0.46 90.00 10.00
OY3 6.8-7.3 Coal (SB) 0.05 2.11 0.61 72.30 27.70
OY2 7.6-8.4 Coal (SB) 0.08 2.21 0.64 87.50 12.50
OY1 8.4-8.8 Coal (SB) 0.09 2.70 0.55 78.50 21.50
OY6 9.0-9.5 Carbonaceous shale 0.06 0.98 0.61 85.80 14.20
OKB4 16.5-17.6 Carbonaceous shale 0.18 1.66 0.79 73.90 26.10
OKB3 18.0-18.5 Coal (SB) 0.09 2.04 0.66 53.40 46.60
OKB2 18.6-18.9 Coal (SB) 0.08 1.41 ND ND ND
OKB1 18.9-19.3 Coal (SB) 0.06 1.94 0.64 70.40 29.60
OKB7 19.3-19.6 Coal (SB) 0.10 2.53 0.84 81.00 19.00
OKB8 19.6-20.0 Coal (SB) 0.15 2.28 0.72 79.50 20.50
C24tetra/C30hopane = C24tetracyclic terpane/C30hopane
C24tetra/C26(R+S)tri= C24tetracyclic terpane/C26(R+S)tricyclic terpane
OY – Onyeama
OKB – Okaba
(B) – Bituminous
(SB) – Sub-bituminous
ND – Not determined
%C23
triterpane

4.3.3.2 Mamu Formation
Mamu samples are dominated by C19-C21 tricyclic terpanes (Table 4.5). These
distributions indicate organic matter derived from terrestrial matter (Ozcelik and
Altunsoy, 2005). The C22/C21 tricyclic terpane ratios range from 0.46 to 0.65 and 0.64
to 0.84 in Onyeama and Okaba samples respectively (Table 4.5). The observed
C22/C21 tricyclic ratios indicate fluvial/deltaic and lacustrine-fluvial/deltaic
depositional environment for Onyeama and Okaba samples respectively (Peters et al.,
2005).
The C24tetra/C26tri(R+S) ratios range between 0.98 and 2.86, probably reflecting
terrigenous organic matter input (Philp and Gilbert, 1986). The C24tetra/C30hopane
ratios also range from 0.05 to 0.09 and 0.06 to 0.18 in Onyeama and Okaba samples
respectively. These values also reflect fluvial/deltaic depositional environment and
lacustrine-fluvial/deltaic for Onyeama and Okaba samples respectively (Peters et al.,
2005).
4.3.4 Hopanes and homohopanes
The m/z 191 mass chromatograms showing the distribution of pentacyclic
triterpanes in the samples are shown in Figs. 4.22,4.23 and 4.24 and the peak
identities are given in Table 4.6.
4.3.4.1 Awgu Formation
C29 and C30αβ-hopane occur in appreciable amount in all the Awgu coaly shale
samples (Fig. 4.22), indicating significant contribution of prokaryotic organisms
(i.e. bacteria, cyanobacteria and blue algae) to the source organic matter.
The sterane/hopane ratio is often used as a measure of relative inputs of eukaryotic
versus prokaryotic debris (Peters and Moldowan, 1993). The sterane/hopane ratio
values range from 0.04-0.51(Table 4.7).
120

The ratio values (

Fig. 4.22: m/z 191 Mass chromatogram showing the distribution of hopanes in
Awgu samples.
122

Fig. 4.23 : m/z 191 Mass chromatogram showing the distribution of hopanes and
benzohopanes in Mamu sample (Okaba).
123

Fig. 4.24 : m/z 191 mass chromatogram showing the distribution of hopanes and
benzohopanes in Mamu samples (Onyeama).
124

Table 4.6 : Peak identities on m/z 191 mass chromatograms.
Peak Compound
C19t C19 tricyclic terpane
C20t C20 tricyclic terpane
C21t C21 tricyclic terpane
C22t C22 tricyclic terpane
C23t C23 tricyclic terpane
C24t C24 tricyclic terpane
C25tS C25 22(S)-tricyclic terpane
C25tR C25 22(R)-tricyclic terpane
C24tetra Tetracyclic hopane (secohopane)
C26tS C26 22(S)-tricyclic terpane
C26tR C26 22(R)-tricyclic terpane
C28tS C28 22(S)-tricyclic terpane
C28tR C28 22(R)-tricyclic terpane
1 C27 18α(H)-22,29,30-trisnorneohopane (Ts)
2 C27 17α(H)-22,29,30-trisnorhopane(Tm)
3 C27 17β(H)-22,29,30-trisnorhopane
4 C29 17α(H), 21β(H)-30-norhopane
4* Oleanene isomers; olean-18-ene, olean-13 (18)-ene, olean-12-ene
5 C29 17β(H), 21α(H)-normoretane
6 C30 17α(H), 21β(H)-hopane
7 C30 17α(H), 21α(H)-30-norhopane
8 C30 17β(H), 21α(H)-moretane
9 C31 17α(H), 21β(H)-30-homohopane (22S)
10 C31 17α(H), 21β(H)-30-homohopane (22R)
10* C30 17β(H), 21β(H)-hopane
11 C32 17α(H), 21β(H)-30,31-bishomohopane (22S)
12 C32 17α(H), 21β(H)-30,31-bishomohopane (22R)
11* C31 17β(H), 21β(H)-hopane
13 C33 17α(H), 21β(H)-30,31,32-trishomohopane (22S)
14 C33 17α(H), 21β(H)-30,31,32-trishomohopane (22R)
125

Table 4.6 (contd.) : Peak identities on m/z 191 mass chromatograms.
Peak Compound
15
C34 17α(H), 21β(H)-30,31,32,33-tetrakishomohopane (22S)
16 C34 17α(H), 21β(H)-30,31,32,33-tetrakishomohopane (22R)
17 C35 17α(H), 21β(H)-30,31,32,33,34-pentakishomohopane (22S)
18 C35 17α(H), 21β(H)-30,31,32,33,34-pentakishomohopane (22R)
Sp30 18α(H)-28-noroleanane
O 18α(H)-oleanane + 18β(H)-oleanane
126

Samples
Awgu Formation
Depth
(m)
Table 4.7: Source and depositional environment parameters computed from the hopane and
sterane distributions in the coals.
Lithology
(Rank)
%C27
sterane
%C28
sterane
%C29
sterane
%C27
diast.
LB387 218.5-222.5 Carbonaceous shale 25.43 20.04 54.53 27.46 54.50 18.14 0.47 55.74 0.11 0.06 0.43 0.06
LB417 407.4-412.5 Coaly shale 18.13 28.27 53.60 21.58 32.14 46.28 0.34 68.03 0.11 0.06 0.25 0.04
LB420 417.0-422.0 Coal (B) 24.04 29.02 46.94 30.53 31.25 38.22 0.51 67.35 0.51 0.07 0.15 0.05
LB514 131.7-136.6 Coal (B) 17.47 29.66 52.87 15.05 33.05 51.90 0.33 55.13 0.27 0.03 0.34 0.04
LB518 148.0 Coal (B) 23.19 23.28 53.53 10.79 32.29 56.93 0.43 73.80 0.32 0.03 0.37 0.04
LB523 168.8-173.7 Coal (B) 16.14 26.10 57.77 19.42 42.67 37.91 0.28 46.81 0.43 0.03 0.35 0.05
LB534 212.1-216.2 Coal (B) 18.71 36.88 44.41 27.97 45.89 26.14 0.42 70.97 0.04 0.06 0.33 0.06
LB542 247.0 Carbonaceous shale 31.89 31.20 36.91 25.86 42.26 31.89 0.86 62.81 0.11 0.26 0.58 0.10
LB551 286.0-289.0 Coal (B) 17.58 32.90 49.52 24.41 29.04 46.55 0.36 67.92 0.13 0.11 0.89 0.10
Mamu Formation
OY5 4.6-5.8 Carbonaceous shale 24.02 20.18 55.8 28.40 23.37 48.27 0.43 89.00 0.07 0.05 0.23 0.04
OY4 6.0-6.8 Coal (SB) 11.83 33.64 54.53 23.05 28.61 48.34 0.22 84.51 0.06 0.05 0.25 0.03
OY3 6.8-7.3 Coal (SB) 10.73 29.71 59.56 25.44 24.33 50.23 0.18 66.56 0.29 0.02 0.32 0.02
OY2 7.6-8.4 Coal (SB) 16.51 26.46 57.03 20.14 30.31 49.56 0.29 66.30 0.04 0.05 0.29 0.03
OY1 8.4-8.8 Coal (SB) 12.97 20.08 66.95 17.00 24.06 58.94 0.20 87.23 0.06 0.01 0.28 0.02
OY6 9.0-9.5 Carbonaceous shale 20.00 23.38 56.62 17.31 25.94 56.75 0.35 71.37 0.35 0.03 0.59 0.04
OKB4 16.5-17.6 Carbonaceous shale 20.98 43.2 35.82 13.91 29.66 56.43 0.59 50.32 0.16 0.09 0.62 0.13
OKB3 18.0-18.5 Coal (SB) 19.06 41.28 39.66 11.60 35.63 52.77 0.48 50.69 0.20 0.32 0.81 0.11
OKB2 18.6-18.9 Coal (SB) 10.59 27.73 61.68 21.89 42.34 35.78 0.17 63.72 0.10 0.06 0.76 0.09
OKB1 18.9-19.3 Coal (SB) 11.57 29.61 58.83 26.45 32.19 41.36 0.20 51.76 0.08 0.01 0.59 0.03
OKB7 19.3-19.6 Coal (SB) 17.06 39.20 43.79 32.76 31.00 36.24 0.40 73.84 0.08 0.02 0.92 0.11
OKB8 19.6-20.0 Coal (SB) 10.78 34.31 54.91 19.53 42.62 37.85 0.20 46.77 0.12 0.47 0.85 0.12
Sterane/Hopane=C27+C28+C29steranes/[(C29+C30)αβhopane + (C31+C32+C33)αβ(R+S)homohopane]
%C28
diast.
127
%C29
diast.
C27/C29
sterane
C35/C30 = C35αβ(R+S) homohopane/ C30αβ hopane + C30βα moretane
Homohopane ratio ,C35/C34 αβS = C35αβS/C34αβS homohopane
Homohopane index = C35/ C31+C32+C33+C34+C35) αβ(R+S) homohopane
OY – Onyeama
OKB – Okaba
(B) – Bituminous
(SB) – Sub-bituminous
%Diast./
sterane
Sterane/
hopane
C35/C30
hopane
C35/C34
αβS hopane
Homohopane/
index

Samples Depth (m)
Awgu
Formation
LB387 218.5-222.5
Table 4.8 : Maturity parameters computed from the hopane and sterane distributions in the coals.
Lithology
(Rank)
Carbonaceous
shale
Mor/Hop = Moretane/Hopane (C30)
Hop/Hop + Mor = Hopane/Hopane + Moretane (C30)
C32HH = C32homohopane
OY – Onyeama
OKB – Okaba
(B) – Bituminous
(SB) – Sub-bituminous
Mor/Hop Hop/Hop+ Mor Ts/Ts+Tm
128
22S/22S+22RC32 HH
20S/20S+20R C29 steranes ββ/ββ+αα C29 sterane
0.12 0.89 0.61 0.60 0.58 0.47
LB417 407.4-412.5 Coaly shale 0.08 0.92 0.46 0.62 0.43 0.55
LB420 417.0-422.0 Coal (B) 0.11 0.9 0.64 0.61 0.44 0.51
LB514 131.7-136.6 Coal (B) 0.10 0.91 0.46 0.61 0.44 0.48
LB518 148.0 Coal (B) 0.09 0.92 0.53 0.60 0.48 0.49
LB523 168.8-173.7 Coal (B) 0.09 0.92 0.34 0.58 0.45 0.54
LB534 212.1-216.2 Coal (B) 0.06 0.94 0.59 0.58 0.44 0.42
LB542 247.0
Carbonaceous
shale
0.14 0.88 0.49 0.53 0.45 0.48
LB551 286.0-289.0 Coal (B) 0.08 0.93 0.66 0.61 0.44 0.51
Mamu
Formation
OY5 4.6-5.8
Carbonaceous
shale
0.46 0.69 0.04 0.54 0.04 0.25
OY4 6.0-6.8 Coal (SB) 0.56 0.64 0.03 0.59 0.15 0.19
OY3 6.8-7.3 Coal (SB) 0.63 0.61 0.04 0.55 0.17 0.20
OY2 7.6-8.4 Coal (SB) 0.54 0.65 0.03 0.54 0.11 0.24
OY1 8.4-8.8 Coal (SB) 0.61 0.62 0.02 0.55 0.19 0.16
OY6 9.0-9.5
OKB4 16.5-17.6
Carbonaceous
shale
Carbonaceous
shale
0.64 0.61 0.05 0.58 0.19 0.25
0.84 0.54 0.13 0.48 0.19 0.30
OKB3 18.0-18.5 Coal (SB) 0.85 0.54 0.16 0.43 0.10 0.33
OKB2 18.6-18.9 Coal (SB) 0.62 0.62 0.24 0.31 0.18 0.21
OKB1 18.9-19.3 Coal (SB) 0.59 0.62 0.11 0.37 0.19 0.50
OKB7 19.3-19.6 Coal (SB) 0.57 0.64 0.14 0.33 0.39 0.56
OKB8 19.6-20.0 Coal (SB) 0.93 0.52 0.24 0.16 0.22 0.45

4.3.4.2 Mamu Formation
The C27 to C35 hopanes are detected in all the Mamu samples but C28 was not
detected (Fig. 4.23 and 4.24). The most prominent hopane in Onyeama samples are
C29αβ-norhopane and C30αβ-hopane while C29αβ norhopane is predominant in Okaba
samples (Fig 4.23 and 4.24). In the Okaba samples, abundance of C29αβ-hopane in all
the samples reflects major contribution from terrestrial organic matter; however,
contribution from prokaryotic organisms is not excluded while abundant C30αβ-
hopane with notable presence of C29αβ in Onyeama samples reflects significant
contribution from prokaryotic organisms as well as vitrinitic (terrestrial) organic
matter. The unusual high abundance of 22R compared to 22S in the C31-17α (H),
21β(H) homohopane is evident in all Okaba samples. This is likely due to co-elution
of gammacerane (Peter and Moldowan, 1993; Kagya, 1996; Farrimond et al., 1998;
Peters et al., 2005).
Benzohopanes with different distributions were found in Onyeama and Okaba coal
samples (Fig. 4.23 and 4.24). There is no previous record of presence of
benzohopanes in Nigerian coal and coaly organic matter. The C32-C35 benzohopanes
were detected in Onyeama samples while C32-C33 benzohopanes were detected in
Okaba samples. Benzohopanes are thought to be secondary transformation products of
C35 bacteriohopanepolyol derivatives (Grice et al., 1998; Peters et al., 2005; Killops
and Killops, 2005; Bechtel et al., 2007a).
129

Fig. 4.25: Mass frangmentogram and spectra of Olean-18-ene in Okaba Mine
samples.
130

Fig. 4.26: Mass frangmentogram and spectra of Olean-13(18)-ene in Okaba Mine
samples.
131

Fig. 4.27: Mass frangmentogram and spectra of Olean-12-ene in Okaba Mine
samples.
132

Three isomers of oleanenes; olean-18-ene, olean-13 (18)-ene and olean-12-ene were
identified in Okaba samples (Fig. 4.25,4.26 and 4.27). Similar to the benzohopanes,
this is the first time oleanene isomers are being identified in Nigerian coal and coaly
organic matter. These three oleanene isomers are products of late diagenesis from
taraxerol and β-amyrin, which are biomarkers for angiosperm (Ten Haven and
Rullkötter, 1988; Ekweozor and Telnǽs, 1990; Rullkötter et al., 1994; Curiale, 1995).
They have also been found useful as indicators of thermal immaturity (Eneogwe et al.,
2002).
In Onyeama sample, C35/C30 hopane ratio range from 0.01 to 0.05 while Okaba
samples have values ranging from 0.01 to 0.47. These values indicate fluvial/deltaic
and lacustrine-fluvial/deltaic depositional environments for Onyeama and Okaba
samples respectively.
The homohopane index and homohopane ratio for the samples range from 0.02-
0.13 and 0.23-0.92 respectively (Table 4.7). These values indicate oxic depositional
environment for Onyeama samples and suboxic-oxic depositional environments for
Okaba samples (Peters and Moldowan, 1991; Hanson et al., 2001; Killops and Killops,
2005; Peters et al., 2005; Yangming et al., 2005). There is presence of gammacerane
in Okaba samples (Fig. 4.23 and 4.24), which indicate water column stratification
during organic matter source deposition (Sinninghe Damsté et al., 1995;
Yangming et al., 2005).
The Moretane/Hopane, Hopane/Hopane + Moretane, Ts/Ts + Tm, 22S/22S + 22R
C32 homohopane ratios in Onyeama samples range from 0.46 to 0.64; 0.61 to 0.69;
0.02 to 0.05; and 0.48 to 0.58 respectively. These values suggest low maturity status
(Rullkötter et al., 1985; Kagya, 1996; Peters et al., 2005). The Okaba samples have
Moretane/Hopane, Hopane/Hopane + Moretane, Ts/Ts + Tm, 22S/22S + 22R C32
homohopane ratios ranging from 0.59-0.93; 0.54-0.64; 0.11-0.24; and 0.16-0.48
respectively. These values also indicate that Onyeama samples are thermally
immature (Rullköter et al., 1985;Kagya, 1996; Peters et al., 2005).
133

4.3.5 Steranes
The m/z 217 mass chromatograms showing the distribution of steranes and
diasteranes in all the samples are shown in Figs. 4.28,4.29 and 4.30. Peak identities
are listed in Table 4.9.
4.3.5.1 Awgu Formation
The occurrence of C27 to C29 steranes and diasteranes were detected in Awgu
coaly samples (Fig. 4.28). The sterane and diasterane distributions for all the samples
occur in the order of C29>C28>C27 (Table 4.7). The predominance of C29 sterane over
C27 sterane reflects a greater input of terrestrial relative to marine organic matter
(Huang and Meinschein, 1979; Volkman 1988; Kagya, 1996; Sari and Bahtiyar, 1999;
Otto et al., 2005; Peters et al., 2005). The ternary plots of sterane distribution in Awgu
samples (Fig. 4.31) indicate organic matter derived from terrestrial materials
deposited in lacustrine – fluvial/deltaic settings (Huang and Meinschein, 1979;
Killops and Killops, 1993, 2005; Peters et al., 2005). The diasterane ternary plots
(Fig. 4.32) also show that Awgu samples are from terrestial organic matter. This
observation is supported by C27/C29 ratios (Table 4.7), which range from 0.28 to 0.56
(Peters et al., 2005). The dominance of dinosterol over C30 steranes in these samples
reflects typical fresh water lacustrine source rocks (Köhler and Clausing, 2000; Peters
et al., 2005).
The 20S/20S+20R and αββ/αββ+ααα C29 ratios range from 0.43 to 0.58 and 0.42
to 0.55 respectively. These values show that the samples are within the oil generative
window (Peters et al., 2005). Plots of 22S/22S+22R C32 hopanes against
C29αββ/αββ+ααα steranes show that Awgu samples are thermally mature (Fig. 4.33).
134

Fig. 4.28 : m/z 217 mass chromatograms showing the distribution of steranes
and diasteranes in Awgu samples.
135

Fig. 4.29: m/z 217 mass chromatograms showing the distribution of steranes and
diasteranes in Mamu samples (Okaba).
136

Fig. 4.30 : m/z 217 mass chromatograms showing the distribution of steranes and
diasteranes in Mamu samples (Onyeama).
137

Table 4.9 : Peak identities on m/z 217 mass chromatograms of Nigerian coal.
Peak Compound
1
C27 13β(H), 17α(H)-Diasterane (20S)
2 C27 13β(H), 17α(H)-Diasterane (20R)
3 C27 13α(H), 17β(H)-Diasterane (20S)
4 C27 13α(H), 17β(H)-Diasterane (20R)
5 C28 13β(H), 17α(H)-Diasterane (20S)
6 C28 13β(H), 17α(H)-Diasterane (20R)
7 C28 13α(H), 17β(H)-Diasterane (20S)
8 C27 5α(H), 14α(H), 17α(H)-Sterane (20S) + C28 13α(H), 17β(H)-Diasterane (20S)
9 C27 5α(H), 14β(H), 17β(H)-Sterane (20R) + C28 13β(H), 17α(H)-Diasterane (20S)
10 C27 5α(H), 14β(H), 17β(H)-Sterane (20S) + C28 13β(H), 17α(H)-Diasterane (20R)
11 C27 5α(H), 14α(H), 17α(H)-Sterane (20R)
12 C29 13β(H), 17α(H)-Diasterane (20R)
13 C29 13α(H), 17β(H)-Diasterane (20S)
14 C28 5α(H), 14α(H), 17α(H)-Sterane (20S)
15 C28 5α(H), 14β(H), 17β(H)-Sterane (20R)
16 C28 5α(H), 14β(H), 17β(H)-Sterane (20S)
17 C28 5α(H), 14α(H), 17α(H)-Sterane (20R)
18 C29 5α(H), 14α(H), 17α(H)-Sterane (20S)
19 C29 5α(H), 14β(H), 17β(H)-Sterane (20R)
20 C29 5α(H), 14β(H), 17β(H)-Sterane (20S)
21 C29 5α(H), 14α(H), 17α(H)-Sterane (20R)
C30 C30 5α(H), 14α(H), 17α(H)-Sterane
138

Fig. 4.31 : Ternary plots of C27, C28 and C29 steranes distributions in Nigerian
coal (After Huang and Meinschein, 1979).
139

Fig. 4.32 : Ternary plots of C27, C28 and C29 diasteranes distributions in Nigerian
coal (After Huang and Meinschein, 1979).
140

Fig. 4.33 : Plots of 22S/22S+22R C32hopanes against C29αββ/αββ+ααα steranes
(After Inaba et al., 2001).
141

4.3.5.2 Mamu Formation
C29 Diasteranes and steranes are the most abundant steranes in all the samples
except few samples from Okaba where C28 predominates. The sterane and diasterane
distributions in Okaba samples are increasing in the order of C29>C28>C27.
The predominance of C29 over C27 sterane reflects a greater input of terrestrial relative
to marine organic matter (Huang and Meinschein, 1979; Volkman, 1988; Kagya, 1996;
Sari and Bahtiyar, 1999; Otto et al., 2005; Peters et al., 2005). The appreciable
quantity of C27 and C28 in these samples also reflect contributions from phytoplankton;
algae, diatoms, dinoflagellates (Volkman, 1986; Volkman et al., 1998; Sari and
Bahtiyar, 1999; Peters et al., 2005). The ternary plot of C27, C28 and C29 sterane of
Mamu samples (Fig. 4.31) reflects major terrestrial input in Onyeama samples while
Okaba samples consist of both terrestrial and marine organic matter (Huang and
Meinschein, 1979; Killops and Killops, 1993, 2005; Peters et al., 2005).
The diasterane ternary plot (Fig. 4.32) shows that most of the Onyeama samples
are derived from terrestrial organic matter with few samples having mixed inputs
(i.e. terrestrial and marine). Samples from Okaba are majorly derived from mixed
origin. There is little variation in sterane and diasterane distribution in Onyeama
samples while significant variations are noticed in Okaba samples. This observation
possibly reflects same depositional environments for Onyeama samples
(fluvial/deltaic) and lacustrine-fluvial/deltaic depositional environments for Okaba
samples. This observation can be supported by the ratio of C27/C29 (Table 4.7) for the
samples. The values range from 0.2 to 0.7 and 0.18 to 0.43 in Okaba and Onyeama
samples respectively. The dominance of dinosterol over C30 steranes in Okaba
samples reflects typical fresh water lacustrine source rocks (Köhler and Clausing,
2000; Peters et al., 2005).
142

The 20S/20S+20R and αββ/αββ+ααα C29 ratios range from 0.04 to 0.19 and 0.16
to 0.25 respectively in Onyeama samples while the values range from 0.1 to 0.39 and
0.21 to 0.56 respectively in Okaba samples. The generally low values recorded
indicate that the samples are thermally immature. The plot of 22S/22S+22R C32
hopanes against C29αββ/αββ+ααα steranes also confirm the thermal immaturity status
of Mamu samples (Fig. 4.33).
143

4.4 POLYCYCLIC AROMATIC HYDROCARBONS IN NIGERIAN COAL
Mass chromatograms showing the distributions of naphthalenes, phenanthrenes
and dibenzothiophenes and their alkyl derivatives are shown in Figs.
4.34,4.35,4.36,4.37,4.38,4.39 and 4.41 respectively. Peak identities are given in Tables
4.10,4.11 and 4.13. These compounds were also used to assess the origin, depositional
environment and thermal maturity of the coal samples.
4.4.1 Naphthalene and Alkylnaphthalenes
4.4.1.1 Awgu Formation
The m/z 156 and 170 showing the distribution of dimethyl and trimethyl
naphthalenes are shown in Fig. 4.34. In the aromatic fractions of Awgu coally samples,
10 dimethylnaphthalene (DMN) and 10 trimethylnaphathalene (TMN) were detected.
Also the presence of appreciable amounts of 1,6-, 1,7-, and 2,6-DMNs in all the
samples indicate terrestrial organic matter input (Day and Edman, 1963; Achari et al.,
1973).The presence of 1,2,5- and 1,2,7-TMN in all the samples indicate both
angiosperm and gymnosperms material contribution to the organic matter that formed
the coals (Killops and Killops, 2005). There is predominance of 1,2,5-TMN over
1,2,7-TMNs in most of the samples except in LB542, LB523 and LB420. The other
prominent trimethylnaphthalene in the samples is 1,2,6-TMN. The occurrence of 1,2,6
TMN in sediments has been traced to microbial source (Alexander et al., 1992).
Therefore its presence in the samples also indicates microbial input to the biomass.
144

Fig. 4.34 : m/z 156, 170 mass chromatograms showing the distribution of naphthalene and
alkylnaphthalenes in Awgu Samples.
145

Fig. 4.34 (contd.): m/z 156, 170 mass chromatograms showing the distribution of naphthalene
and alkylnaphthalenes in Awgu Samples.
146

Fig. 4.35 : m/z 156, 170 mass chromatograms showing the distribution of naphthalene and
alkylnaphthalenes in Mamu samples (Okaba).
147

Fig. 4.36 : m/z 156, 170 mass chromatograms showing the distribution of naphthalene and
alkylnaphthalenes in Mamu Samples (Onyeama).
148

Table 4.10 : Peak identities on m/z 156 and 170 mass chromatograms.
Peak Compound
1,2-DMN
1,2-dimethylnaphthalene
1,3-DMN 1,3- dimethylnaphthalene
1,4-DMN 1,4- dimethylnaphthalene
1,5-DMN 1,5- dimethylnaphthalene
1,6-DMN 1,6- dimethylnaphthalene
1,7-DMN 1,7- dimethylnaphthalene
1,8-DMN 1,8- dimethylnaphthalene
2,3-DMN 2,3- dimethylnaphthalene
2,6-DMN 2,6- dimethylnaphthalene
2,7-DMN 2,7- dimethylnaphthalene
1,2,5-TMN 1,2,5- trimethylnaphthalene
1,2,6-TMN 1,2,6- trimethylnaphthalene
1,2,7-TMN 1,2,7- trimethylnaphthalene
1,3,5-TMN 1,3,5- trimethylnaphthalene
1,3,6-TMN 1,3,6- trimethylnaphthalene
1,3,7-TMN 1,3,7- trimethylnaphthalene
1,4,6-TMN 1,4,6- trimethylnaphthalene
1,6,7-TMN 1,6,7- trimethylnaphthalene
2,3,6-TMN 2,3,6- trimethylnaphthalene
149

4.4.1.2 Mamu Formation
Figures 4.35 and 4.36 show the m/z 156 and 170 distribution of dimethyl and
trimethyl naphthalenes in Mamu samples. The samples have similar alkyl naphthalene
distributions as observed in Awgu samples. Also 10 dimethylnaphthalene (DMN) and
10 trimethylnaphthalene (TMN) were detected in all the samples. The presence of
appreciable amounts of 1,6-, 1,7-, and 2,6-DMNs in all the samples indicate terrestrial
organic matter input (Day and Edman, 1963; Achari et al., 1973). Both 1,2,5- and
1,2,7-TMN were detected in the samples which indicate contributions from both
gymnosperm and angiosperm organic matter (Killops and Killops, 2005). In addition,
the occurrence of 1,2,6-TMN also indicates microbial contribution to the biomass
(Alexander et al., 1992).
4.4.2 Phenanthrene and alkylphenanthrenes
The m/z 178, 192 and 206 chromatograms showing the distribution of
phenanthrene and alkylphenanthrenes in the samples are shown in Fig. 4.37. The peak
identities are listed in Table 4.11. Phenanthrene, four methylphenanthrene (MP) and
ten dimethylphenanthrene (DMP) were detected in the aromatic fraction of the
samples.
4.4.2.1 Awgu Formation
Plots of 9MP/1MP+9MP ratio against Paq for Awgu samples are shown in
Fig. 4.40. This plot has been proposed to discriminate between terrestrial and marine
organic matter (modified after Fickens et al., 2000). All the samples fall within the
field of marine organic matter source (Fig. 4.40), an indication that the coals were
derived from organic matter formed mainly from marine materials. Also the
occurrence of 1,7-DMP (pimanthrene) in the samples is attributed to terrestrial
organic matter (Simoneit et al., 1986).
150

Various maturity parameters calculated from the distributions of phenanthrene and
methylphenanthrenes in the coal samples are given in Table 4.14. The calculated
vitrinite reflectance (%Rc), MPI-1, MPI-1, MPI-2, MPI-1*, MPDF and PAI values
range from, 0.78 to 1.17, 0.63 to 1.88, 0.78 to 1.23, 0.59 to 1.72, 0.46 to 0.77 and 1.01
to 1.68 respectively.
There is no remarkable difference between MPI-1, MPI-2 and MPI-1* ratios in the
samples. The calculated vitrinite reflectance (Rc) correlates well with vitrinite
reflectance obtained from the plot of HI vs. Tmax (Figs. 4.5 and 4.6) for type III
kerogen. The Rc values show that the samples are in late window/gas phase.
151

Fig. 4.37 : m/z 178, 192, 206 mass chromatograms showing the distribution of phenanthrene and
alkylphenanthrenes in Awgu Samples.
152

Fig. 4.38 : m/z 178, 192, 206 mass chromatograms showing the distribution of phenanthrene and
alkylphenanthrenes in Mamu Samples (Okaba).
153

Fig. 4.39 : m/z 178, 192, 206 mass chromatograms showing the distribution of phenanthrene and
alkylphenanthrenes in Mamu Samples (Onyeama).
154

Table 4.11 : Peak identities on m/z 178,192,206 mass chromatograms.
Peaks Compounds
P
155
Phenanthrene
1-MP 1-methylphenanthrene
2-MP 2-methylphenanthrene
3-MP 3-methylphenanthrene
9-MP 9-methylphenanthrene
1,2-DMP 1,2-dimethylphenanthrene
1,7-DMP 1,7-dimethylphenanthrene
1,8-DMP 1,8-dimethylphenanthrene
1,9-DMP 1,9-dimethylphenanthrene
2,3-DMP 2,3-dimethylphenanthrene
2,6-DMP 2,6-dimethylphenanthrene
2,7-DMP 2,7-dimethylphenanthrene
2,9-DMP 2,9-dimethylphenanthrene
3,6-DMP 3,6-dimethylphenanthrene
3,9-DMP 3,9-dimethylphenanthrene

Samples Depth (m)
Awgu
Formation
Table 4.12 : Source and Depositional Environment and maturity parameters
derived from phenanthrene and dimethylbenzothiophene and their alkyl
derivatives.
Paq= nC23 + nC25/ nC23 + nC25 + nC29 + nC31 - Alkanes
MPI-1 = 1.5 (2-MP + 3-MP)/ 0.69P + 1-MP + 9-MP; MPI-2 = 3(2-MP)/P + 1-MP + 9-MP
MPI-1* = 1.89(2-MP + 3-MP) / P + 1.26(1-MP + 9-MP); MPDF = 3-MP + 2-MP/ sum of methylphenanthrenes
PAI = 1-MP + 2-MP + 3-MP + 9-MP / Phenanthrene
%Rc, MPI-1 = 0.6(MPI-1) + 0.4; R0 < 1.35%, -0.6(MPI-1) + 2.3; R0>1.35%
MDR=4-MDBT/1-MDBT; MDR’=4-MDBT/1-MDBT+4-MDBT; EDR’=4,6-DMDBT/4-EDBT+4,6-DMDBT
OY – Onyeama
OKB – Okaba
Lithology
(Rank)
(B) – Bituminous
(SB) – Sub-bituminous
DBT / P MDBT / MP 9MP / 9MP+1MP Paq
156
%Rc,
MPI-1
MPI-1 MPI-2 MPI-1* MPDF PAI MDR MDR’ EDR’
LB387 218.5-222.5 Carbonaceous shale 0.07 0.08 0.53 0.64 0.88 0.8 0.78 0.75 0.49 1.68 4.23 0.81 0.80
LB417 407.4-412.5 Coaly shale 0.14 0.37 0.44 0.64 0.78 0.63 ND 0.59 0.46 1.28 8.74 0.90 0.85
LB420 417-422 Coal (B) 0.1 0.18 0.47 0.78 0.96 0.93 0.99 0.86 0.6 1.23 6.53 0.87 0.84
LB514 131.7-136.6 Coal (B) 0.16 0.28 0.66 0.69 1.08 1.13 ND 1.04 0.65 1.36 4.38 0.81 0.84
LB518 148 Coal (B) 0.01 0.1 0.48 0.70 0.96 0.93 0.91 0.86 0.56 1.47 5.53 0.85 0.86
LB523 168.8-173.7 Coal (B) 0.15 0.32 0.5 0.66 1.2 1.33 ND 1.21 0.71 1.37 6.13 0.86 0.84
LB534 212.1-216.2 Coal (B) 0.03 0.13 0.63 0.69 1.17 1.88 ND 1.72 0.77 1.83 6.49 0.87 0.91
LB542 247 Carbonaceous shale 0.14 0.36 0.53 0.61 0.95 0.92 0.96 0.83 0.64 1.01 7.08 0.88 0.9
LB551 286-289 Coal (B) 0.13 0.24 0.57 0.65 1.14 1.23 1.23 1.14 0.65 1.6 9 0.9 0.88
Mamu
Formation
OY5 4.6-5.8 Carbonaceous shale 0.04 0.05 0.58 0.26 0.8 0.66 0.68 0.62 0.46 1.42 3.06 0.75 0.78
OY4 6-6.8 Coal (SB) 0.18 0.33 0.94 0.16 0.61 0.34 0.26 0.32 0.3 1.09 0.42 0.30 0.92
OY3 6.8-7.3 Coal (SB) 0.15 0.18 0.93 0.19 0.64 0.4 0.31 0.31 0.26 1.42 0.67 0.40 0.90
OY2 7.6-8.4 Coal (SB) 0.13 0.16 0.82 0.29 0.69 0.48 0.4 0.45 0.41 0.98 0.75 0.43 0.87
OY1 8.4-8.8 Coal (SB) 0.31 0.14 0.75 0.29 0.77 0.61 0.63 0.57 0.41 1.66 1.01 0.50 0.91
OY6 9-9.5 Carbonaceous shale 0.02 0.11 0.57 0.25 0.65 0.42 0.4 0.38 0.48 0.59 2.61 0.72 0.92
OKB4 16.5-17.6 Carbonaceous shale 0.06 0.12 0.46 0.15 0.73 0.55 0.51 0.51 0.48 0.89 2.38 0.70 0.53
OKB3 18.0-18.5 Coal (SB) 0.1 0.11 0.72 0.06 0.68 0.46 0.42 0.39 0.44 0.7 2.71 0.73 0.68
OKB2 18.6-18.9 Coal (SB) 0.09 0.17 0.62 0.05 0.59 0.31 0.29 0.28 0.46 0.41 2.85 0.74 0.78
OKB1 18.9-19.3 Coal (SB) 0.08 0.09 0.67 0.06 0.64 0.41 0.41 0.37 0.39 0.82 2.68 0.73 0.52
OKB7 19.3-19.6 Coal (SB) 0.09 0.15 0.72 0.09 0.65 0.42 0.39 0.38 0.53 0.49 3.06 0.75 0.55
OKB8 19.6-20 Coal (SB) 0.1 0.21 0.59 0.07 0.64 0.41 0.36 0.36 0.59 0.4 5.42 0.84 0.79

Fig. 4.40 :Organic matter source discrimination in the samples (modified after Ficken et al., 2000).
157

4.4.2.2 Mamu Formation
The m/z 178,192 and 206 mass chromatograms showing the distribution of
phenanthrene and alkylphenanthrenes in the samples are shown in Figs. 4.38 and 4.39.
Plot of 9MP/1MP+9MP ratio against Paq is shown in Fig. 4.40. The samples classified
under organic matter derived majorly from terrestrial materials. Maturity parameters
derived from phenanthrene and methylphenanthrenes are presented in Table 4.12.
The calculated vitrinite reflectance (% Rc), MPI-1, MPI-2, MPI-1*, MPDF and PAI
values range from, 0.59 to 0.8, 0.31 to 0.66, 0.26 to 0.68, 0.28 to 0.62, 0.26 to 0.59
and 0.4 to 1.66 respectively. All the MPI ratios i.e. MPI-1, MPI-2, MPI-1* are in close
agreement with each other. The calculated vitrinite reflectance, Rc shows that
Onyeama samples are more mature than Okaba samples and are at the beginning of
oil generative window. The enhanced values of Rc recorded for Mamu samples
compared to vitrinite reflectance obtained from the plot of HI vs. Tmax
(Figs. 4.5 and 4.6) is consistent with type II and type II/III kerogen classification for
these samples. Rc has been reported to be more effective in estimating thermal
maturity of type III organic matter (e.g. Buldzinski et al., 1995; Dzou et al., 1995;
Hughes et al., 1995; Radke et al., 1995).
4.4.3 Dibenzothiophene and alkyldibenzothiophenes
The m/z 184, 198, 212 and 226 mass chromatograms showing the distributions
of dibenzothiophene and alkydibenzothiophenes are shown in Fig. 4.41. The peak
identities are listed in Table 4.13. Dibenzothiophene, four methyldibenzothiophene
(MDBT), 4-ethyldibenzothiophene, eleven dimethyldibenzothiophene (DMDBT) and
unidentified trimethyldibenzothiophene (TMDBT) were detected in the aromatic
fraction of the samples. Various geochemical parameters calculated from the
distributions are given in Table 4.12.
158

4.4.3.1 Awgu Formation
Dibenzothiophene / phenanthrene and methyldibenzothiophene /methylphenanthrene
ratios in the samples range from 0.07 to 0.16 and 0.08 to 0.37 respectively
(Table 4.12). Low amounts of dibenzothiophene to phenanthrene and
methyldibenzothiophene to methylphenanthrene indicate deposition of the organic
matter predominantly in lacustrine and/ or fluvial/deltaic environment
(Hughes et al., 1995). These values indicate appreciable quantity of terrestrial input
(Requejo, 1994). The plots of %S vs. DBT/Phen and %S vs. MDBT/MP have been
used to assess the depositional environment of organic matter (Hughes et al., 1995).
Majority of Awgu samples plot within marine shale, other lacustrine and
fluvial/deltaic field while few samples plot within mixed marine (Hughes et al., 1995).
The plots of dibenzothiophene/phenanthrene vs pristane/phytane and
methyldibenzothiophene/methylphenanthrene vs pristane/phytane are versatile tools
in discriminating different depositional environment of petroleum source rock
(Hughes et al., 1995). Majority of the samples fall within the field of fluvial/deltaic
depositional environment on both plots (Fig. 4.44 and 4.45).
159

Fig. 4.41: m/z 184,198,212,226 mass chromatograms showing the distributions of
dibenzothiophene and alkyldibenzothiophenes in Awgu Samples.
160

Fig. 4.41 (contd.): m/z 184,198,212,226 mass chromatograms showing the distributions of
dibenzothiophene and alkyldibenzothiophenes in Awgu samples.
161

Table 4.13 : Peak identities on m/z 184, 198, 212, 226 mass chromatograms.
Peaks Compounds
DBT Dibenzothiophene
4-MDBT 4-methyldibenzothiophene
2-MDBT 2-methyldibenzothiophene
3-MDBT 3-methyldibenzothiophene
1-MDBT 1-methyldibenzothiophene
4-EDBT 4-ethyldibenzothiophene
4,6-DMDBT 4,6-dimethyldibenzothiophene
2,4-DMDBT 2,4-dimethyldibenzothiophene
2,6-DMDBT 2,6-dimethyldibenzothiophene
3,6-DMDBT 3,6-dimethyldibenzothiophene
3,7-DMDBT 3,7-dimethyldibenzothiophene
1,4-DMDBT 1,4-dimethyldibenzothiophene
1,6-DMDBT 1,6-dimethyldibenzothiophene
1,8-DMDBT 1,8-dimethyldibenzothiophene
1,3-DMDBT 1,3-dimethyldibenzothiophene
1,2-DMDBT 1,2-dimethyldibenzothiophene
1,9-DMDBT 1,9-dimethyldibenzothiophene
TMDBTs Trimethyldibenzothiophenes
162

Fig. 4.42 : Cross plot of total Sulphur vs. dibenzothiophene/phenanthrene (DBT/P) for
Nigerian coal (Hughes et al., 1995).
163

Fig. 4.43 : Cross plot of total Sulphur vs. methyldibenzothiophene/methylphenanthrene
(MDBT/MP) for Nigerian coal (Hughes et al., 1995).
164

Fig. 4.44 : Cross plot of dibenzothiophene/phenanthrene (DBT/P) vs. pristane/phytane of
Nigerian coal (Hughes et al., 1995).
165

Fig. 4.45 : Cross plot of methyldibenzothiophene/methylphenanthrene (MDBT/MP) vs.
pristane/phytane of Nigerian coal (Hughes et al., 1995).
166

4.4.3.2 Mamu Formation
The dibenzothiophene/phenanthrene and methyldibenzothiophene
/methylphenanthrene ratios range from 0.02 to 0.31 and 0.05 to 0.33 (Table 4.12)
respectively. These values indicate appreciable quantity of terrestrial organic matter
(Requejo, 1994). Majority of the samples plot within zone I on the plots of %S vs.
DBT/Phen and %S vs. MDBT/MP (Figs. 4.42 and 4.43) which represents marine
shale, other lacustrine and fluvial/deltaic while only one Okaba sample plot at the
boundary with zone III which represent marine mixed (Hughes et al., 1995). The low
amounts of dibenzothiophene to phenanthrene and methyldibenzothiophene to
methylphenanthrene (Table 4.12) indicate deposition of the organic matter
predominantly in lacustrine and/ or fluvial/deltaic environment (Hughes et al., 1995).
Figure 31 show the plots of dibenzothiophene/phenanthrene vs pristane/phytane and
methyldibenzothiophene/methylphenanthrene vs pristane/phytane for Mamu samples
and most of the samples plot within the field of fluvial/deltaic depositional
environments.
167

4.5 Carbon Isotopic Composition of Nigerian Coal
The δ 13 C isotopic values for individual n-alkanes and whole saturate fractions
of the samples are presented in Tables 4.14 and 4.15.
4.5.1 Origin and Depositional Environment of Organic Matter
4.5.1.1 Awgu Formation
The carbon isotopic compositions of individual alkanes (nC14-nC33) for Awgu
samples range between –30.6 to –25.8 δ 13 ‰PDB. The most depleted values were
observed for the long chain alkanes (nC21-nC33). These features are characteristics of
plant wax derived n-alkanes of C3-plants (Schouten et al., 2000; Hu et al., 2002).
Significant contribution from marine organic matter (i.e.C3 algae or cyanobacteria) is
reflected in heavier δ 13 C isotope values of short (nC14-nC22) n-alkanes. The n-alkanes
become isotopically lighter with increasing chain length (Fig. 4.46). This observation
reflect terrigenous input (Murray et al., 1994; Schouten et al., 2001; Yangming et al.,
2005) deposited in fluvial/ deltaic depositional environment while the carbon isotopic
composition of n-alkanes for the samples that range from –29.0 to –26.3 δ 13 ‰PDB is
typical of lacustrine phytoplankton (Murray et al., 1994). Therefore Awgu samples
can be said to consist of both terrestrial and marine organic matter deposited in
lacustrine-fluvial/deltaic depositional environment.
The δ 13 C isotope ratios of Pr and Ph range from –30.2 to –25.5 δ 13 ‰PDB (av.
–27.9) and –30.9 to –26.6 δ 13 ‰PDB (av. –28.22) respectively. There is no significant
difference between the 13 C-values of Pr and Ph, which suggest that they were formed
from the same group of organisms or organisms depending on the same source of
carbon (Schwas and Spangenberg, 2007).
168

Table 4.14: Carbon Isotopic Composition of n-Alkanes in Awgu Samples (δ 13 ‰PDB).
Sample no Depth (m) C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 Weighted Av. Pr Ph
LB387 218.5-222.5 ND -26.5 -26.6 -26.6 -28.6 -27.2 -27.4 -27.6 -28.0 -28.0 -28.0 -27.9 -28.3 -28.8 -29.3 -28.5 -28.0 -28.5 -30.2 -29.6 -30.6 ND ND -28.2 -26.7 -26.6
LB417 407.4-412.5 ND ND -24.7 -26.8 -27.3 -30.1 -27.4 -27.8 -30.2 -29.5 -31.5 -28.4 -28.2 -27.3 -27.3 -27.5 -28.3 -29.4 -29.2 -29.5 -30.2 -29.4 -28.6 -27.3 -25.5 -29.4
LB420 417-422 ND ND -24.0 -27.7 -28.1 -28.5 -30.8 -29.1 -29.6 -28.2 -28.9 -29.5 -30.5 -28.8 -30.8 -28.8 -28.7 -29.0 -30.8 -25.8 -33.3 ND ND -29.0 -29.6 -26.1
LB514 131.7-136.6 ND -26.2 -25.6 -25.5 -26.5 -26.2 -25.5 -25.8 -26.0 -26.3 -26.4 -27.0 -26.9 -28.3 -27.5 -27.6 -26.2 -27.9 -28.7 -29.6 -30.1 ND ND -27.0 -30.2 -29.6
LB518 148.0 ND -26.0 -26.0 -26.6 -26.5 -26.7 -25.6 -27.0 -27.3 -27.5 -27.8 -28.3 -29.3 -28.0 -28.1 -27.9 -27.8 -28.4 -29.1 -28.8 -29.5 ND ND -27.6 -26.9 -28.6
LB523 168.8-173.0 -25.5 -26.0 -26.2 -27.2 -26.9 -26.7 -27.0 -27.3 -27.7 -27.5 -27.5 -27.4 -27.7 -27.4 -28.6 -28.7 -28.6 -29.8 -29.8 -29.9 -30.9 ND ND -27.8 -28.8 -27.0
LB534 212.1-216.2 ND -26.3 -25.9 -25.3 -26.7 -26.4 -26.1 -27.2 -27.6 -27.4 -28.9 -28.4 -28.1 -27.9 -27.9 -27.9 -27.8 -28.9 -29.3 -28.9 -30.6 ND ND -26.3 -29.9 -30.9
LB542 247.0 ND -24.3 -26.3 -26.2 -26.5 -27.9 -28.3 -26.7 -27.9 -27.1 -27.2 -27.5 -28.2 -28.6 -28.4 -28.4 -28.2 -28.4 -28.9 -29.1 -30.3 ND ND -27.7 -27.0 -26.5
LB551 286-289 ND ND -26.4 -26.3 -27.9 -29.4 -26.9 -26.7 -27.8 -27.4 -27.5 -28.2 -28.2 -28.1 -28.3 -28.4 -28.1 -30.5 -28.6 -28.1 -29.8 ND ND -28.0 -26.8 -29.3
Average of -25.5 -25.9 -25.8 -26.5 -27.2 -27.7 -27.2 -27.2 -28.0 -27.7 -28.2 -28.1 -28.4 -28.1 -28.5 -28.2 -28.0 -29.0 -29.4 -28.8 -30.6 -29.4 -28.6 -27.9 -28.2
Individual
n-Alkanes
169

Fig. 4.46 : Carbon isotopic distribution of individual n-alkanes in Awgu Samples
(Murray et al., 1994).
170

4.5.1.2 Mamu Formation
The δ 13 C isotopic values for n-alkanes range from –31.7 to –29.2 δ 13 ‰PDB and
–30.1 to –28.2 δ 13 ‰PDB in Onyeama and Okaba samples respectively. The isotopic
values are characteristics of plant wax derived n-alkanes of C3-plants (Canuel et al.,
1997; Sun et al., 2000; Bi et al., 2005; Tanner et al., 2007; Tuo et al., 2007). The
carbon isotopic compositions of individual alkanes (nC15-nC36) in Onyeama and
Okaba samples range from –32.19 to –27.15 δ 13 ‰PDB and –32.48 to –27.50
δ 13 ‰PDB respectively. The most depleted values were observed for the long chain
alkanes, which are characteristics of plant wax derived n-alkanes of C3-plants
(Schouten et al., 2000; Hu et al., 2002).
Significant contribution from marine organic matter (i.e.C3 algae or cyanobacteria)
is reflected in heavier δ 13 C isotope values observed in the short chain (nC15-nC18)
alkanes in all the samples (Figs. 4.47 and 4.48). Both pristane and phytane have
essentially the same δ 13 C values as the n-alkanes, suggesting that they were formed
from the same group of organisms (Schwas and Spangenberg, 2007).
However, there is notably flat portion pattern of the n-alkane profile between nC20-
nC25 and nC27-nC31 (Fig. 4.47 and 4.48) in Onyeama and Okaba samples respectively,
which is an indication of marine incursion (Murray et al., 1994). These features show
that Mamu samples consist of both terrestrial and marine organic matter deposited in
fluvial/deltaic (Onyeama) or lacustrine-fluvial/deltaic (Okaba) settings.
171

Table 4.15: Carbon Isotopic Composition of n-Alkanes in Mamu Samples (δ 13 ‰PDB).
Sample no Depth (m) C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36 Weighted Av. Pr Ph
Okaba
OKB4 16.5-17.6 ND ND -27.4 ND -29.3 -31.3 -30.1 -33.9 -30.8 -31.9 -28.5 -30.1 -29.9 -28.2 -28.2 -30.0 -30.1 -31.1 ND ND ND ND ND -30.1 -29.8 -32.1
OKB3 18.0-18.5 ND ND ND ND -29.7 -26.4 -29.0 ND ND ND ND ND ND -31.5 -32.0 -28.5 -28.5 -32.0 -31.1 -31.5 -32.2 -28.7 ND -30.1 -31.5 -35.4
OKB2 18.6-18.9 -26.2 ND -28.5 ND -29.7 ND ND ND ND ND ND ND ND -28.4 -26.3 -28.2 -26.1 -27.5 -29.7 -31.5 -27.9 ND ND -28.2 -30.4 -29.7
OKB1 18.9-19.3 -26.1 -27.2 -29.2 -27.4 -28.9 -28.3 -32.5 -31.2 -29.3 -30.0 -25.5 -31.2 -31.9 -28.8 -30.9 -27.5 -28.6 -32.6 -30.6 -31.1 -32.8 -28.1 -28.7 -29.5 -28.8 -30.6
OKB7 19.3-19.6 ND ND -27.1 -32.1 -28.2 -28.6 -27.1 -32.3 -32.1 -29.9 -32.4 -31.2 -32.1 -29.1 -28.0 -28.1 -27.7 -29.1 -28.6 -28.2 ND -29.2 ND -29.5 -28.5 -32.0
OKB8 19.6-20.0 ND ND -25.3 -26.1 -26.3 -31.0 -32.4 ND ND ND ND ND ND -29.4 ND -30.2 -29.4 -30.2 -30.9 ND -30.4 ND ND -29.3 -27.6 -30.6
Average of -26.1 -27.2 -27.5 -28.6 -28.8 -29.1 -30.2 -32.5 -30.7 -30.6 -29.8 -30.9 -31.3 -29.2 -29.1 -28.7 -28.4 -30.4 -30.2 -30.6 -30.8 -28.7 -28.7 -29.4 -31.7
Individual
n-Alkanes
Onyeama
OY5 4.6-5.8 ND -28.8 -28.9 -28.0 -30.0 -32.2 -32.2 -33.1 -33.3 -33.3 -33.0 -31.6 -31.8 -30.8 -31.7 -31.2 -34.2 -30.7 ND ND -33.6 ND ND -31.6 -29.8 -31.6
OY4 6-6.8 ND -27.6 -27.4 ND -30.1 -31.1 -30.1 -31.5 -30.6 -30.5 -30.1 -31.3 -30.0 -29.2 -30.4 -29.6 -32.1 -30.5 -32.0 -31.9 -29.4 -32.7 -33.1 -30.5 -28.9 -29.7
OY3 6.8-7.3 ND ND -33.9 ND -33.3 -34.1 -31.2 -29.9 -30.9 -31.0 -31.4 -31.7 -29.8 -29.2 -30.2 -29.1 -31.5 -30.6 -29.7 -29.5 -30.4 -33.0 ND -31.7 -29.8 -32.6
OY2 7.6-8.4 ND -27.9 -26.6 -26.8 -26.3 -28.8 -29.3 -30.6 -29.6 -29.9 -30.9 -29.5 -29.2 -28.8 -29.4 -28.8 -29.9 -30.1 -31.0 -28.6 -30.4 -31.4 -29.3 -29.2 -28.3 -29.5
OY1 8.4-8.8 ND -27.6 -27.5 ND -28.3 -29.1 -28.9 -29.5 -29.5 -30.4 -30.4 -31.0 -29.8 -28.7 -29.4 -28.8 -31.0 -30.0 -30.8 -33.3 -32.2 -31.6 -33.6 -30.1 -29.3 -28.6
OY6 9.0-9.5 ND -27.6 -27.7 -26.7 -30.8 -30.4 -30.9 -30.7 -33.1 -32.6 -33.6 -32.2 -31.9 -29.6 -30.7 -29.8 -32.3 -30.4 -32.2 -32.8 ND ND ND -30.8 -28.8 -30.7
Average of ND -27.9 - 28.7 -27.2 -29.8 -30.9 -30.4 -30.9 -31.1 -31.3 -31.6 -31.2 -30.4 -29.4 -30.3 -29.5 -31.8 -30.4 -31.1 -31.2 -31.2 -32.2 -32.0 -29.1 -30.5
Individual
n-Alkanes
172

Fig. 4.47: Carbon isotopic distribution of individual n-alkanes in Okaba Samples, Mamu
(Murray et al., 1994).
173

Fig. 4.48: Carbon isotopic distribution of individual n-alkanes in Onyeama Samples,
Mamu (Murray et al., 1994).
174

CHAPTER FIVE
SUMMARY AND CONCLUSION
Coal and coaly organic matter samples were collected from coal bearing
measures of Lower and Middle Benue Trough, Nigeria.These samples were subjected
to Leco, Rock-Eval pyrolysis, Elemental, Vitrinite reflectance measurement, Gas
Chromatography-Mass Spectrometry and Gas Chromatography-Isotope Ratio- Mass
Spectrometry analyses. This study was undertaken to re-appraise the hydrocarbon
potential of Nigerian coal through source rock evaluation studies, biomarker
parameters and carbon isotopic compositions.
Majority of the samples were characterized by low sulphur contents (

The Pr/Ph ratios of samples from Awgu and Onyeama samples reflect organic
matter deposition under oxic conditions in freshwater-lacustrine and freshwater
depositional environment respectively while Pr/Ph ratios of Okaba samples indicate
suboxic-oxic conditions during sedimentation in freshwater-lacustrine depositional
environments.
The presence of hopane, homohopane (C31-C35) in all the samples showed that
bacteriohopanetetrol and other polyfunctional C35 hopanoids common in prokaryotic
microorganisms have significant contributions to the organic matter that formed the
coals. The occurrence of oleanene isomers in Okaba samples favoured terrestrial
organic matter deposited in lacustrine-fluvial/deltaic environment. In addition, the
detection of gammacerane in Okaba samples represents water stratification during
organic matter source deposition. The abundance of C29 Steranes and diasteranes in
the samples indicate land input to the organic matter that formed the coal.
The distribution of polyaromatic hydrocarbons and carbon isotopic compositions
of the individual alkanes in the samples showed that Awgu samples were formed from
organic matter derived from both terrestrial and marine material deposited in
lacustrine-fluvial/deltaic depositional environment. The Mamu samples were derived
from mixed organic materials (terrestrial and marine) deposited in fluvio-deltaic
(Onyeama) and lacustrine-fluvial/deltaic settings (Okaba) respectively.
The Vitrinite reflectance values (0.48-1.15 %Ro) and all the maturity parameters
derived from the elemental, Rock Eval analysis and biomarkers distributions show
that Awgu samples were in the late oil window while Mamu samples have low
thermal maturity status. The Awgu Formation coals might have generated gases into
yet-to-be identified reservoir. However, coals from Mamu Formation have potential to
generate both oil and gas but are presently immature to have formed any significant
hydrocarbons.
176

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205

APPENDIX
206

Fig. 4.8 : m/z 85 Mass chromatograms of aliphatic fractions of Awgu samples showing the
distribution of n-Alkanes.
207

Fig. 4.8 (contd.): m/z 85 Mass chromatograms of aliphatic fractions of Awgu samples
showing the distribution of n-Alkanes.
208

Fig. 4.9 : m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation samples
(Okaba) showing the distribution of n-Alkanes.
209

Fig. 4.9 (contd.): m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation
samples (Okaba) showing the distribution of n-Alkanes.
210

Fig. 4.10 : m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation samples
(Onyeama) showing the distribution of n-Alkanes.
211

Fig. 4.10 (contd.): m/z 85 Mass chromatograms of aliphatic fractions of Mamu Formation
samples (Onyeama) showing distribution of n-Alkanes.
212

Fig. 4.13: m/z 74 mass chromatogram showing the distribution of n-fatty acids in Awgu
samples (Numbers refer to carbon chain lengths of n-fatty acids).
213

Fig 4.13 (contd.): m/z 74 mass chromatogram showing the distribution of n-fatty acids in
Awgu samples (Numbers refer to carbon chain lengths of n-fatty acids).
214

Fig. 4.14: m/z 74 mass chromatogram showing the distribution of n-fatty acids in Mamu
samples (Okaba) (Numbers refer to carbon chain lengths of n-fatty acids).
215

Fig. 4.15: m/z 74 mass chromatogram showing the distribution of n-fatty acids in Mamu
samples (Onyeama) (Numbers refer to carbon chain lengths of n-fatty acids).
216

Fig. 4.15 (contd.): m/z 74 mass chromatogram showing the distribution of n-fatty acids in
Mamu samples (Onyeama) (Numbers refer to carbon chain lengths of n-fatty acids).
(Numbers refer to carbon chain lengths of n-fatty acids).
217

Fig. 4.16: m/z 58 mass chromatograms showing the distributions of alkan-2-ones in Awgu
samples (Numbers refer to carbon chain lengths of alkan-2-ones).
218

Fig. 4.17: m/z 58 mass chromatograms showing the distributions of alkan-2-ones in Mamu
samples (Okaba) (Numbers refer to carbon chain lengths of alkan-2-ones).
219

Fig. 4.18: m/z 58 mass chromatograms showing the distributions of alkan-2-ones in Mamu
samples (Onyeama) (Numbers refer to carbon chain lengths of alkan-2-ones).
220

Fig. 4.19 :m/z 191 showing the distribution of tricyclic and tetracyclic terpane in
Awgu samples.
221

Fig. 4.20: m/z 191 showing the distribution of tricyclic and tetracyclic terpane in
Mamu Formation samples (Okaba).
222

Fig. 4.21 : m/z 191 showing the distribution of tricyclic and tetracyclic terpane in
Mamu Formation samples (Onyeama).
223

Fig. 4.22: m/z 191 Mass chromatogram showing the distribution of hopanes in
Awgu samples.
224

Fig. 4.23 : m/z 191 Mass chromatogram showing the distribution of hopanes and
benzohopanes in Mamu sample (Okaba).
225

Fig. 4.24 : m/z 191 mass chromatogram showing the distribution of hopanes and
benzohopanes in Mamu samples (Onyeama).
226

Fig. 4.28 : m/z 217 mass chromatograms showing the distribution of steranes and
diasteranes in Awgu samples.
227

Fig. 4.29: m/z 217 mass chromatograms showing the distribution of steranes and
diasteranes in Mamu samples (Okaba).
228

Fig. 4.30 : m/z 217 mass chromatograms showing the distribution of steranes and diasteranes
in Mamu samples (Onyeama).
229

Fig. 4.34 : m/z 156, 170 mass chromatograms showing the distribution of naphthalene and
alkylnaphthalenes in Awgu Samples.
230

Fig. 4.34 (contd.): m/z 156, 170 mass chromatograms showing the distribution of naphthalene
and alkylnaphthalenes in Awgu Samples.
231

Fig. 4.35 : m/z 156, 170 mass chromatograms showing the distribution of naphthalene and
alkylnaphthalenes in Mamu samples (Okaba).
232

Fig. 4.36 : m/z 156, 170 mass chromatograms showing the distribution of naphthalene and
alkylnaphthalenes in Mamu Samples (Onyeama).
233

Fig. 4.37 : m/z 178, 192, 206 mass chromatograms showing the distribution of phenanthrene and
alkylphenanthrenes in Awgu Samples.
234

Fig. 4.38 : m/z 178, 192, 206 mass chromatograms showing the distribution of phenanthrene
and alkylphenanthrenes in Mamu Samples (Okaba).
235

Fig. 4.39 : m/z 178, 192, 206 mass chromatograms showing the distribution of phenanthrene and
alkylphenanthrenes in Mamu Samples (Onyeama).
236

Fig. 4.41: m/z 184,198,212,226 mass chromatograms showing the distributions of
dibenzothiophene and alkyldibenzothiophenes in Awgu samples.
237

Fig. 4.41 (contd.): m/z 184,198,212,226 mass chromatograms showing the distributions of
dibenzothiophene and alkyldibenzothiophenes in Awgu samples.
238

239