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GEOCHEMICAL SEGREGATION OF PETROLEUM SYSTEMS OF POTWAR
BASIN USING GC-MS AND PYROLYSIS TECHNIQUES
Submitted By:
MUHAMMAD IRFAN JALEES 2006-Ph.D-Chemistry-03
Supervised by:
PROF. DR. FAZEELAT TAHIRA
CHEMISTRY DEPARTMENT
UNIVERSITY OF ENGINEERING AND TECHNOLOGY LAHORE-PAKISTAN 2014
i
GEOCHEMICAL SEGREGATION OF PETROLEUM SYSTEMS OF POTWAR BASIN
USING GC-MS AND PYROLYSIS TECHNIQUES
A Thesis Submitted
To
The University Of Engineering and Technology, Lahore in
Partial Fulfillment of the Requirements for the Degree of
Doctorate of Philosophy
In
Chemistry
By
Muhammad Irfan Jalees
2006-PhD-Chemistry-03
Supervised by:
Prof. Dr. Fazeelat Tahira
DEPARTMENT OF CHEMISTRY
University of engineering and technology,
Lahore-Pakistan 54890
2014
ii
GEOCHEMICAL SEGREGATION OF PETROLEUM SYSTEMS OF POTWAR BASIN USING GC-MS AND PYROLYSIS
TECHNIQUES
Research Thesis submitted Partial Fulfillment of the Requirements for
the Degree of
Doctorate of Philosophy in Chemistry
Approved on: _______________
Internal Examiner ______________________
Prof. Dr. Fazeelat Tahira
External Examiner ___________________________
(Prof. Dr. Makshoof Athar)
Chairperson, Chemistry Department ____ ___________________
Prof. Dr. Syeda Rubina Gilani
Dean Faculty of Natural Sciences, ____________________
Humanities and Islamic Studies Prof. Dr. Fazeelat Tahira
DEPARTMENT OF CHEMISTRY, University of engineering and technology,
Lahore-Pakistan 54890
iii
This thesis has been evaluated by the following examiners External examiners: a) From Abroad i) Dr. R. Paul Philp Professor Petroleum and Environmental Geochemistry The University of Oklahoma School of Earth and Energy 100 East Boyd street suite 810, Sarkeys Energy Center Norman, OK 73019 USA ii) Dr. Awal Noor Post doctorate Fellow, Inorganic Chemistry II, The University of Bayreuth, D-95440 Bayreuth, Germany. b) From within the country Prof. Dr. Makshoof Athar Director, Professor of App. Chemistry, PUIC, Lahore Internal Examiner Prof. Dr. Fazeelat Tahira, Professor of Organic Chemistry Dean of natural sciences, humanities and Islamic studies, UET Lahore
iv
Declaration I “MUHAMMAD IRFAN JALEES” declare that the thesis entitled: “GEOCHEMICAL
SEGREGATION OF PETROLEUM SYSTEMS OF POTWAR BASIN USING GC-MS AND
PYROLYSIS TECHNIQUES” is my own research work. This thesis is being submitted for the
partial fulfillment of the requirements for the degree of Ph.D. in Chemistry. This thesis contains
no materials that has been accepted and published previously for the award of any degree.
________________
Signature
v
DEDICATED
To
My Family
vi
ACKNOWLEDGEMENTS
First of all, I would like to praise Allah Almighty, the Omnipotent and the Omnipresent,
Who is the most Merciful, the most Knowledgeable and Worthy of all praises. All of my praises
are due to Holy Prophet Hazrat Muhammad (Peace Be upon Him), who came as the light of
knowledge for all the seekers.
I express my heartiest and sincere thanks to my respected and honorable Research
Supervisor, Prof. Dr. Fazeelat Tahira, Dean, Faculty of Natural Sciences, Humanities and Islamic
Studies, University of Engineering and Technology, Lahore, who’s keen interest, guidance and
encouragement has been a source of great help throughout this research work. Above all and the
most needed, she provided me unflinching encouragement and support in various ways. Her truly
scientific intuition has made her as a constant oasis of ideas and passions in science, which
exceptionally inspires and enriches my growth as a student, a researcher and a scientist to be.
Special and heartiest thanks to Prof. Dr. Thomas S. Bianchi, College of Oceanography,
Texas A & M, Texas, USA for providing me an opportunity to work with an excellent group. His
unforgettable cooperation, guidance, source of knowledge and kind behavior towards me will be
ever remembered. I am thankful to Prof. Dr. Syeda Rubina Gillani, Chairperson, Department of
Chemistry, University of Engineering and Technology, Lahore for providing me an opportunity
to complete my degree.
I would like to thank Pakistan Oil Fields (POL) Limited and Oil and Gas Development
Corporation Limited (OGDCL), Islamabad. I take this opportunity to sincerely acknowledge the
Higher Education Commission (HEC), Government of Pakistan, Islamabad, for providing
financial assistance in the form of Indigenous Research Fellowship which buttressed me to
perform my work comfortably.
I am happy to acknowledge the love and prayers of my parents, brothers, sisters and my
wife. Their moral support is a great source of strength for me in every field of life. Without their
prayers, sacrifices and encouragements, the present work would have been a merry dream. My
parents deserve special mention for their inseparable support and prayers. My father, Muhammad
Jalees (1941-2013), was the person who contributed to the fundamentals of my learning
vii
character, showing me the joy of intellectual pursuit ever since I was a child. May his soul rest in
peace!
I am also obliged to all my colleagues; Dr. Muhammad Asif, Dr. Abdus Saleem, Ms Hina
Saleem, Dr. Arif Nazir, Shahid Nadeem, Shugufta Nasir and Imran Kaleem, for their advice and
their willingness to share their bright thoughts with me, which were very fruitful for shaping up
my ideas and research. I convey special acknowledgement to laboratory staff, Mr. Anwar
Nadeem, Mr. Anwar Zahid, Mr. Dilshad Hussain, Mr. Atif and Mr. Amanat for their
indispensable help.
Finally, I would like to thank everybody who was important to the successful realization
of thesis, as well as express my apologies that I could not mention them personally one by one.
Muhammad Irfan Jalees
viii
ABSTRACT
This study deals with characterization of Petroleum System of the Potwar Basin,
Pakistan. For this purpose, crude oils/condensates (12) obtained from reservoirs of Eocene,
Paleocene, Jurassic Permian ages, and sediments (121) selected from seven geological
formations and six wells namely A, B, C, D, E and F, were geochemically analyzed. The
geological formations are: Chorgali and Sakesar (Eocene), Patala, Dhak pass and Lockhart
(Paleocene), Datta (Jurassic) and Sardhai (Early Permian). Various methods and analytical
techniques were used in this study including TOC, Rock Eval pyrolysis, GC-FID, Gas
Chromatography-Mass Spectrometry (GC-MS), Elemental Analysis, Stable Carbon and
Nitrogen Isotopes, Spontaneous Potential (SP) log and Gamma Ray (GR) log. Both
biomarkers and non-biomarker parameters were applied for characterization of samples. This
thesis is comprised of eight chapters. Chapter 1 presents an introduction to: petroleum systems
of the Potwar basin, and introduction of analytical techniques and their applications in
geochemical evaluation. Chapter 2 describes samples and background geology of the study area,
lithological description, petroleum systems and source rocks of the Potwar Basin. The
experimental procedures and techniques for data collection and analysis are explained in Chapter
3. Chapters 4 to 8 independently contain abstract, introduction, results & discussion and
conclusions.
In chapter 4, Spontaneous Potential (SP) and Gamma ray (GR) logs have been used for
the identification of productive zones within the sedimentary sequences of Eocene (Chorgali and
Sakesar) and Paleocene (Patala) ages. The study encompasses three wells i.e. D, E & F. The
order of permeability (reservoir property) from SP log is Chorgali > Sakesar > Patala. Shale
contents and organic matter increases with depth within the sedimentary sequences. Patala
Formation on the basis of high shale content and organic matter was assigned as potential source
rock.
Chapter 5 elaborates the hydrocarbon source rock potential of Eocene, Paleocene and
Jurassic sediments obtained from three producing wells referred to as Well-A, Well-B and Well-
C, using Rock-Eval pyrolysis and total organic carbon (TOC) measurement. In Well-A, the
ix
upper ca. 100 m of the Eocene Sakesar Formation contained abundant Type III gas-prone
organic matter (OM) and the interval appeared to be within the hydrocarbon generation window.
The underlying part of the Sakesar Formation contained mostly weathered and immature OM
with little hydrocarbon potential. The Sakesar Formation passes down into the Paleocene Patala
Formation. Tmax was variable because of facies variations which were also reflected in variations
in hydrogen index (HI), TOC and S2/S3 values. In Well-A, the middle portion of the Patala
Formation had sufficient maturity (Tmax 430 to 444°C) and organic richness to act as a minor
source for gas. The underlying Lockhart Formation in general contained little OM, although
basal sediments showed a major contribution of Type II/III OM and were sufficiently mature for
hydrocarbon generation. In Well-B, rocks in the upper 120 m of the Paleocene Patala Formation
contained little OM. However, some Type II/III OM was present at the base of the formation,
although these sediments were not sufficiently mature for oil generation. The Dhak Pass
Formation was in general thermally immature and contained minor amounts of gas-prone OM. In
Well-C, the Jurassic Datta Formation contained oil-prone OM. Tmax data indicated that the
formation was marginally mature despite sample depths of > 5000 m. The lack of increase in
Tmax with depth was attributed to low heat flows during burial. However, burial to depths of
more than 5000 m resulted in the generation of moderate quantities of oil from this formation.
In Chapter 6, elemental and isotopic composition of C and N has been applied to interpret
the depositional environment of source rocks and relative contribution of marine and terrigenous
OM. The study was conducted on 50 sediments analyzed in Chapter 4. High values total carbon
contents (TCC) and extremely low total nitrogen contents (TNC) reflect an enhanced amount of
terrestrial OM in these sediments. Low values of Pr/Ph (<1) and diasteranes/steranes (~0.2) and
high TOC suggest anoxic environments and marine carbonate depositional setting for OM.
Carbon isotope ratios of OM generally range from –25.8 to –24.2‰ with lower values occurring
in the some samples of Sakesar formation. The values are 2.8‰ greater than −27‰, the mean
value of C3 plants and suggest that OM was derived from C3 plants with significant input from
land plants and marine planktons. The plot of C/N vs. δ13C demonstrates that OM in Chorgali
and Sakesar samples is from a similar source such as vascular C3 plant as primary producers. The
trend toward low C/N values within the Chorgali and Sakesar formations is associated with
x
inclusion of marine planktonic OM into the source. Similarly low C/N values (< 20) observed for
Patala and Sardhai samples imply significant carbon input from marine planktons in mixed OM.
δ15N data show two trends, low values in the range of 2.3 to 3.8‰ observed for Chorgali,
Sakesar and some Patala sediments indicate mixed land plant and marine planktonic OM, while
slightly higher values 3.1 to 5.9‰ for Sardhai and Patala (Well-F) Formations illustrate
comparatively higher proportion of planktonic input. The δ15N versus δ13C diagram clearly
demonstrates the nature and origin of OM. It is composed of land plants mainly derived from C3
plants having variable proportions of marine planktonic input.
In Chapter 7, biomarker, Rock-Eval, TOC data has been used to characterize the OM
quantity and quality, and to interpret the depositional environment and thermal maturity in
sedimentary sequences of Eocene (Chorgali & Sakesar), Paleocene (Patala) and Early Permian
(Sardhai) ages described under chapters 4 & 6. Rock-Eval pyrolysis data indicate that Chorgali
and Sakesar Formations have good to very good quantity of type II/III OM with potential mainly
for gas generation. The samples have Hydrogen Index (HI) 275-374 mgHC/gTOC and S2/S3
mostly 4.5-5.5. Most of the Paleocene sediments show HI values in the range of 300-445
mgHC/gTOC and suggest major contribution of type II kerogen in these samples; S2/S3 ratios in
the range of 5.5-16 indicate both oil and gas prone sediments, while lower values (< 5) reflect
gas prone OM. The Early Permian, Sardhai samples have HI 218-354 mgHC/gTOC and S2/S3
up to 6.8 and represent mostly gas prone type II/III OM. All the samples show TOC about 2-
3.6% and Tmax 440 – 442°C which is consistent with good to very good organic richness and
thermal maturity of sediments in the peak oil window.
The relative distributions of C27–C29 steranes in order of C27>C29>C28, and C27/C29
steranes >1 suggest OM input of mixed nature, most likely of marine planktonic and terrestrial
origin. Low values of diasterane/sterane and Ts/ (Ts+Tm) for most samples (0.2-0.4 and 0.5-0.6)
as well as Pr/Ph ratios up to 0.2-0.8 suggest anoxic clay-poor/carbonates having high pH and low
Eh. The values of maturity parameters, ββ/ (ββ+αα) and 20S/ (20S+20R) C29 sterane, are lower
than the equilibrium values and represent early generation stage of samples; however, keeping in
view Tmax values 440 – 442°C, and that sediments under study are anoxic carbonates, wherein
generation stage is reached before the equilibrium, we propose that all samples have reached the
xi
peak of the oil window. The variations in biomarker and Rock-Eval parameters in some samples
suggest regional variations of organic facies in their source rocks.
In chapter 8, crude oils and condensates (12) have been analyzed for diamondoids and
biomarkers. GC and GC-MS parameters reveal that these samples are mature and contained
marine and algal/bacterial OM sources from an oxidizing environmental/dysoxic environment.
The total methyladamantanes/admantane ratios 4.05 to 15.25 show increasing levels of microbial
oxidation. The diamantane/adamantane ratios vary from 1.14 to 3.06 also supports the results.
The degree and classification of microbial oxidation was defined by plotting American
Petroleum Institute gravity versus diamondoid concentrations. This study demonstrated that
biomarkers and diamondoids provide the best means to determine the maturity level of crude oils
and condensates.
xii
PUBLICATIONS Publications fully used as Chapters
1. Fazeelat Tahira, Muhammad Irfan Jalees and Thomas Bianchi, “Source rock potential
of Eocene, Paleocene and Jurassic sediments of the Potwar Basin (northern Pakistan)”,
Journal of Petroleum Geology, 2010, Volume 33, Issue 1, pg 87-96, Wiley Inter science,
UK
2. Muhammad Irfan Jalees, Thomas S Bianchi, Roger Sassen and Fazeelat Tahira,
“Diamondoids and Biomarker: A novel parameter for microbial degradation and maturity
of crude oils from Pakistan” submitted in Carbonates & Evaporites, 2011, Volume 26, pg
155-165, Springer Link, UK
Publications partially used in thesis
3. Muhammad Irfan Jalees, Fazeelat Tahira and Hina saleem, “Study on the geochemical
correlation of crude oils of Paleocene and Jurassic ages from the Potowar Indus Basin in
northern Pakistan” Chinese Journal of Geochemistry, 2010, Volume 29, pg 82-93,
Springer Link, UK
4. Fazeelat Tahira, Muhammad Asif, Muhammad Irfan Jalees, Abdus Saleem, Hina
Saleem, Shahid Nadeem, Shugafta Nasir, “Source correlation between biodegraded oil
seeps and a commercial crude oil from the Punjab Basin-Pakistan” Journal of Petroleum
Science and Engineering, 2011, Volume 77, pg 1-9, Elsevier B.V.
Publications in Process
5. Muhammad Irfan Jalees and Fazeelat Tahira, “Geophysical well logs and stable
isotopes for the evaluation of source and depositional environmental of productive zones
of Potwar basin, Pakistan” (in process)
6. Muhammad Irfan Jalees and Fazeelat Tahira “ Source, Depositional Environment and
Maturity of OM of Eocene, Paleocene and Early Permian formation of Potwar Basin,
Pakistan” (in process)
xiii
TABLE OF CONTENTS
Sr. Description Page 1.INTRODUCTION 1.1. PETROLEUM SYSTEM 1 1.1.1. Source Rock 1 Source Rocks Of Potwar Basin 2 1.1.2. Reservoir Rock 3 Reservoir Rocks In Potwar Basin 3 1.1.3. Traps And Seals 3 Traps And Seals In Potwar Basin 3 1.1.4. Generation And Migration 5 Generation And Migration In Potwar Basin 6 1.2. ROCK-EVAL PYROLYSIS 6 1.2.1. Quantity Of Organic Matter 8 1.2.2. Thermal Maturation 8 1.2.3. Kerogen Classification 9 1.3. GEOPHYSICAL WELL LOGS AND WIRELINE LOG 12 Gamma Ray (GR) Log 12 Spontaneous Potential (SP) Log 14 1.4. BIOMARKERS IN SEDIMENTS AND PETROLEUM 15 1.4.1. Hopanes 16 1.4.2. Steranes 17 1.4.2. Diamondoids 18 1.5. STABLE ISOTOPIC ANALYSIS 19 1.5.1. Stable Carbon and Nitrogen Isotopes 21 1.5.2. C/N Elemental Ratio 22 1.6. AIMS AND SCOPE OF WORK 23 2. GEOLOGY AND SAMPLE DESCRIPTION OF STUDY AREA 24 2.1. DESCRIPTION OF STUDY AREA (POTWAR BASIN) 24 2.1.1. Depositional History 25 2.1.2. Stratigraphy of Potwar Basin 25 2.2. SAMPLE DESCRIPTION 27 2.2.1 Crude Oil And Condensates 27 2.2.2. Sediments 30 3. EXPERIMENTAL 32 3.1. Chemicals, Glassware and Apparatus 32 Standardization/activation of reagent 33 3.2. SAMPLE PREPARATION AND GEOCHEMICAL ANALYSIS 33 3.2.1. Extraction Of Soluble Organic Matter (SOM) From 33 Soxhlet Extraction 33 Accelerated Solvent Extraction (ASE) 34
xiv
TABLE OF CONTENTS
Sr. Description Page 3.2.2. Removal Of Free Elemental Sulfur From Crude Oil and
Sediment Extract 34
3.2.3. Liquid Chromatography Of Crude Oils And SOM 34 Small Scale Column Chromatography 34 Large Scale Column Chromatography 35 3.2.4. Isolation Of Branched And Cyclic Alkanes using 5A°
molecular sieve 35
3.3. ANALYTICAL TECHNIQUES 35 3.3.1. Total Organic Carbon 35 3.3.2. Rock-Eval Pyrolysis 36 3.3.3. Geophysical Well Logs 36 Spontaneous Potential Log (SP Log) And Gamma Ray Log 36 3.3.4. Elemental And Stable Isotopic Analysis For Carbon And 36 3.3.5. Gas Chromatography (GC-FID) 37 3.3.6. Gas Chromatography-Mass Spectrometry (GC-MS) 38 Full Scan Mode For Compound Identification For Oils 38 Selected Ion Monitoring (SIM) Mode 38 Selected Ion Monitoring (SIM) Mode For Diamondoids 38 4. INTERPRETATION OF PRODUCTIVE ZONES USING SPONTANEOUS POTENTIAL (SP) LOG AND GAMMA RAY (GR) LOG
40
ABSTRACT 40 4.1. INTRODUCTION 41 4.2. INTERPRETATION OF PRODUCTIVE ZONES 41 4.2.1. Productive Zones using Spontaneous Potential (SP) Log 41 4.2.2. Identification of Lithology from Gamma Ray (GR) Log 46 4.3 CONCLUSIONS 48 5. SOURCE ROCK POTENTIAL OF EOCENE, PALEOCENE AND JURASSIC DEPOSITS IN THE SUBSURFACE OF POTWAR BASIN, NORTHERN PAKISTAN
49
ABSTRACT 49 5.1. INTRODUCTION 50 5.2. BACKGROUND GEOLOGY 50 5.3. DEPOSITIONAL HISTORY 51 5.4. PETROLEUM SYSTEM 53 5.5. MATERIAL AND METHODS 54 5.6. RESULTS AND DISCUSSION 55 5.2.1 Well-A 55 Eocene Sakesar Formation 55 Paleocene Patala Formation 58 Paleocene Lockhart Formation 59
xv
TABLE OF CONTENTS
Sr. Description Page 5.2.2. Well-B 59 Paleocene Patala Formation 59 Paleocene Dhak Pass Formation 60 5.2.3 Well-C 60 Jurassic Datta Formation 60 5.7. CONCLUSIONS 61 6. STABLE CARBON AND NITROGEN FOR EVALUATION OF SOURCE AND DEPOSITIONAL ENVIRONMENT
64
ABSTRACT 64 6.1. INTRODUCTION 65 6.2. GEOLOGY AND STUDY AREA 67 6.3. EXPERIMENTAL 68 6.4. RESULTS AND DISCUSSION 69 6.4.1. Elemental Carbon and Nitrogen 69 6.4.2 Total Organic Carbon (TOC) 73 6.4.3. Stable Carbon And Nitrogen Isotopes (δ13C and δ15N) 73 6.4.4. C/N Ratios: Source Identification 74 6.5. CONCLUSIONS 77 7. SOURCE, DEPOSITIONAL ENVIRONMENT AND MATURITY Of EOCENE, PALEOCENE AND EARLY PERMIAN SEDIMENTS: BOMARKER AND ROCK-EVAL STUDY
79
ABSTRACT 79 7.1. INTRODUCTION 81 7.2. SOURCE, MATURITY AND DEPOSITIONAL ENVIRONMENT 82 7.3. RESULTS AND DISCUSSION 86 7.3.1. Well-D 86 Eocene Chorgali Formation 86 Eocene Sakesar Formation 97 Paleocene Patala Formation 98 7.3.2. Well-F 99 Eocene Chorgali Formation 99 Eocene Sakesar Formation 107 Paleocene Patala Formation 108 Early Permian Sardhai Formation 109 7.3.3. Well-F 111 Eocene Chorgali Formation 111 Eocene Sakesar Formation 119 Paleocene Patala Formation 119 Early Permian Sardhai Formation 120 7.4. CONCLUSIONS 122
xvi
TABLE OF CONTENTS
Sr. Description Page 8. DIAMONDOIDS AND BIOMARKERS: AS A TOOL TO BETTER DEFINE THE EFFECTS OF THERMAL CRACKING AND MICROBIAL OXIDATION ON OIL/CONDENSATES FROM RESERVOIR OF UPPER INDUS BASIN PAKISTAN
123
ABSTRACT 123 8.1. INTRODUCTION 124 8.2. GEOLOGY AND STUDY AREA 125 8.3. EXPERIMENTAL 127 8.3.1. Gas Chromatography 127 8.3.2. Gas Chromatography-Mass Spectrometry 127 8.3.3. Isolation of Branched and Cyclic Alkanes 128 8.3.4. Recovery of Straight Chain from Molecular Sieve 128 8.3.5. Diamondoids Analysis using Selected Ion Monitoring 129 8.4. RESULTS AND DISCUSSION 130 8.4.1. Depositional Environment And Organic Matter 130 8.4.2. Diamondoids 134 8.43. Maturity 136 8.4.4. Microbial Oxidation 138 8.5. CONCLUSIONS 139 9. REFERENCES 141-150
xvii
TABLES Sr. Description Page
Table-1.1: Essential elements and geological process for Total Petroleum System (TPS)
1
Table-1.2: Source Rocks Present in the Potwar Basin (OGDC, 1996; Quadri and Quadri, 1996)
2
Table-1.3: Geological Age, Reservoir type and oil/gas producing Formation found in Potwar Basin, Pakistan (Khan et al., 1986; Jaswal et al., 1997; Wandrey et al., 2004)
4
Table-1.4: Various seals and reservoirs present in different oil fields of Potwar Basin Pakistan (Quadri and Quadri, 1996)
5
Table-1.5: Geochemical parameters describing petroleum potential (quantity) of a source rock (Peters and Cassa, 1994)
8
Table-1.6: Geochemical Parameters Describing Level of Thermal Maturation (Peters and Cassa, 1994)
9
Table-1.7: Geochemical parameters describing kerogen type (Quality) and expelled product at peak maturity (peters and Cassa, 1994)
11
Table-1.8: Natural abundance of the most commonly used stable isotopes 20 Table-1.9 Variations of carbon isotopic ratio in different types of OM 21 Table-1.10 Table showing various types of organic matter along with their δ13C, δ15N
and C/N values (Hamilton and Lewis, 1992; Sarma et al. 2012) 22
Table-2.1: Description of geological age and reservoir formation of samples under study. The quantity of various classes of compounds is determined using column chromatography.
29
Table-2.2: Table showing the geological formations, no of sediments samples and Lithology of each formation of study area
31
Table-4.1: Description of geological information and total organic carbon in sediment samples taken from different wells under study.
43
Table-5.1 Summary of Rock-Eval/TOC data 61 Table-6.1: The elemental and stable isotope data of Carbon and Nitrogen for Well-D,
E and F. 70
Table-7.1: Rock-Eval and Biomarker parameters to evaluate source, maturity and depositional conditions of OM.
85
Table7.2: Rock-Eval and TOC data based on various parameters to access quality, quantity and thermal maturity of organic matter in Eocene and Paleocene sediments from Well-D
87
Table-7.3: Biomarker based parameters which describes source, maturity and depositional environment of organic matter (OM) in Eocene and Paleocene sediments of Well-D.
92
Table-7.4: Identification of hopanes and steranes using m/z 191 and m/z 217, respectively.
96
Table-7.5: Rock-Eval and TOC data based on various parameters to access quality, quantity and thermal maturity of organic matter in Eocene, Paleocene and Early Permian sediments from Well-E
100
xviii
Table-7.6: Biomarker based parameters which describe source, maturity and depositional environment of organic matter (OM) in Eocene, Paleocene and Early Permian sediments of Well-E.
104
Table-7.7: Rock-Eval and TOC data based on various parameters to access quality, quantity and thermal maturity of organic matter in Eocene, Paleocene and Early Permian sediments from Well-F
112
Table-7.8: Biomarker based parameters which describe source, maturity and depositional environment of organic matter (OM) in Eocene, Paleocene and Early Permian sediments of Well-F.
116
Table-8.1 Location and general information of the sample wells 126Table-8.2: Diamondoids identified in crude oil/condensate samples 132 Table-8.3: Abundance and different ratios of n-Alkanes, iso-prenoids, Diamondoids
and Biomarkers in Crude Oils/Condensates from Upper Indus basin Pakistan.
133
xix
FIGURES
Sr. Description Page Figure-1.1: Distribution of producing reservoir based on number of field and
geological age (Wandrey et al. 2004) 4
Figure-1.2: Schematic diagram showing output of Rock-Eval analysis and application interpretation. (Tissot and Welte, 1984)
7
Figure-1.3: Atomic H/C vs. atomic O/C plot showing different types of kerogen and oil/gas generation zone (Tissot and Welte, 1978).
10
Figure-1.4: Classification of Kerogen Types based on HI/OI Diagram (Peters and Cassa, 1994)
10
Figure-1.5: Gamma ray log showing effect of various lithologies on gamma ray log readings (Selley, 1998).
13
Figure-1.6: A typical SP tool arrangement (Selley, 1998) 14 Figure-1.7: A typical responses of the SP log showing variation of potential
with permeability (Selley, 1998). 15
Figure-2.1: Generalized stratigraphy of the Potwar area (Wandrey et al. 2004, and references therein)
26
Figure-2.2: Location map of Well-A, B, C, D, E & F on map of Pakistan 28 Figure-4.1: Response of SP log with depth for Chorgali, Sakesar and Patala
formations within i) Well-D, ii) Well-E, iii) Well-F. Refer to Figure-2.1 for lithology of formations
45
Figure-4.2: Response of Gamma Ray (GR) log with depth for Chorgali, Sakesar and Patala formation within i) Well-D, ii) Well-E, iii) Well-F. Refer to Figure-2.1 for litholgy of formations.
47
Figure-5.1 General location map of the Potwar Basin, northern Pakistan, showing major structural elements and locations of Wells A, B and C referred to in this paper
51
Figure-5.2 Stratigraphic column for the Potwar Basin. #: source rocks; * reservoir rocks (modified from OGDC 1996; Wandrey et al., 2004)
52
Figure-5.3 Geochemical logs based on Rock-Eval / TOC parameters for Eocene, Paleocene and Jurassic sediments from wells A, B and C in the Potwar Basin
56
Figure-5.4 Plot of HI versus OI, showing type of OM in Eocene, Paleocene and Jurassic samples
57
Figure-5.5 Plot of TOC versus S2. The expanded section indicates the presence of inertinite in samples from the Patala and Dhak Pass Formations; however, other samples show very good to excellent
58
Figure-6.1: The variations in δ13C of some terrestrial plants. 66 Figure-6.2: Map of Pakistan showing location of Well-D, E & F. 68
xx
Sr. Description Page Figure-6.3: Depth profile showing variation in stable carbon and nitrogen
isotopes and total carbon and nitrogen contents in OM in Well-D, E & F.
72
Figure-6.4: C/N vs. δ13C diagram showing a variation of bulk matter in sediments of Chorgali, Sakesar, Patala and Sardhai formation (Modified from Meyers 1997)
76
Figure-6.5: δ13C versus δ15N diagram showing origin and varaiblity of OM in sediments
76
Figure-7.1: Geochemical well logs for Well-D, showing quality, quantity and thermal maturity of organic matter in Eocene and Paleocene formations
88
Figure-7.2: Modified Van Krevelan diagram for classification of kerogen type in Well-D sediments
89
Figure-7.3: Tmax vs. HI plot showing the classification and thermal maturity of OM.
89
Figure-7.4: Total organic carbon (wt %) vs. S2 (mg/g) plot for the quality of organic matter in Eocene and Paleocene formations in Well-D
90
Figure-7.5: Biomarker depth profile for Well-D, indicating various parameters regarding sources, maturity and depositional environment in Eocene and Paleocene formation
93
Figure-7.6: Isoprenoids vs. Sterane plot for Well-D indicting input from carbonates and shale in Eocene, Paleocene and Early Permian Sediments
94
Figure-7.7: Pristane/n-C17 vs. Phytane/n-C18 plot for Eocene and Paleocene Sediments for Oxicity and OM for Well-D
94
Figure-7.8: Representation of mass fragmentogram m/z 191 and m/z 217 for hopanes and steranes, respectively. The details of peaks are given in Table-7.4
95
Figure-7.9: Geochemical well logs for Well-E, showing quality, quantity and thermal maturity of organic matter in Eocene, Paleocene and Early Permian formations
101
Figure-7.10: Modified Van Krevelan diagram for classification of kerogen type in Well-E sediments
102
Figure-7.11: Tmax vs. HI plot showing the classification and thermal maturity of OM
102
Figure-7.12: Total organic carbon (wt %) vs. S2 (mg/g) plot for the quality of organic matter in Eocene, Paleocene and Early Permian formations in Well-E
103
Figure-7.13: Biomarker depth profile for Well-E, indicating various parameters regarding sources, maturity and depositional environment in Eocene, Paleocene and Early Permian formations
105
xxi
Sr. Description Page Figure-7.14: Isoprenoids vs. Sterane plot for Well-E indicting input from
carbonates and shale in Eocene, Paleocene and Early Permian Sediments
106
Figure-7.15: Pristane/n-C17 vs. Phytane/n-C18 plot for Eocene, Paleocene and Early Permian sediments for Oxicity and OM for Well-E
106
Figure-7.16: Geochemical well logs for Well-F, showing quality, quantity and thermal maturity of organic matter in Eocene, Paleocene and Early Permian formations
113
Figure-7.17: Modified Van Krevelan diagram for classification of kerogen type in Well-F sediments
114
Figure-7.18: Tmax vs. HI plot showing the classification and thermal maturity of OM
114
Figure-7.19: Total organic carbon (wt %) vs. S2 (mg/g) plot for the quality of organic matter in Eocene, Paleocene and Early Permian formations in Well-F
115
Figure-7.13: Biomarker depth profile for Well-F, indicating various parameters regarding sources, maturity and depositional environment in Eocene, Paleocene and Early Permian formations
117
Figure-7.14: Isoprenoids vs. Sterane plot for Well-F indicting input from carbonates and shale in Eocene, Paleocene and Early Permian Sediments
118
Figure-7.15: Pristane/n-C17 vs. Phytane/n-C18 plot for Eocene, Paleocene and Early Permian sediments for Oxicity and OM for Well-F
118
Figure-8.1 Map of Pakistan showing the location of the oil wells in Upper Indus Basin Pakistan
126
Figure-8.2 TIC of Balkasar, Balkasar Oxy and Dhakni oil well sample 129 Figure-8.3 The base ion peak chromatogram of the adamantanes (m/z 136 and
CnH2n-5 series), diamantanes (m/z 188 and CnH2n-9 series) and triamantanes (m/z 240 and CnH2n-13 series). The peaks are
1131
Figure-8.4 Base ion chromatogram of hopanes (m/z 191 and CnH2n-8 series) 135 Figure-8.5 Organic matter classification of sample analyzed (modified after
Hunt 1979) 135
Figure-8.6 Plot between API° gravity and total diamondoids concentration showing effect of cracking
136
Figure-8.7 Plot between maturity parameters i.e. 1-4MD/(1-, + 3-, + 4MD) x 100 versus 1-MA/ (1-, + 2-MA) x 100, showing relative thermal stability of the methylated diamondoid derivatives
137
Figure-8.8 Plot between biomarker parameters and diamondoid maturity parameter index for the relative thermal stability of the sample analyzed
138
xxii
LIST OF ABBREVIATIONS
ABBREVIATION DESCRIPTION % Percentage °C Celsius µ Micro ‰ per mil 1 EA 1-Ethyladamantane 1,,3,6, TEA 1,3,6_Trimethyladamantane 1,2 DMA 1,2-Dimethyladamantane 1,2,5,7 TtMA 1,2,5,7-Tetramethyladamantane 1,3 DMA 1,3_Dimethyladamantane 1,3,,5,7 TtMA 1,3,5,7-Tetramethyladamantane 1,3,4, TEA (cis) 1,3,4_Trimethyladamantane, cis 1,3,4, TEA (trans) 1,3,4-Trimethyladamantane, trans 1,3,5 TMA 1,3,5Trimethyladamantane 1,4 & 2,4 DMD 1,4 and 2,4_Dimethyldiamantane 1,4 DMA (cis) 1,4-Dimethyladamantane, cis 1,4 DMA (trans) 1,4-Dimethyladamantane, trans 1,MA 1-Methyladamantane 1,MD 1-Methyldiamantane 1E,3,5,DMA 1-Ethyl-3,5-dimethyladamantane 1E,3,MA 1-Ethyl-3-methyladamantane 2 EA 2-Ethyladamantane 2, MA 2-Methyladamantane 20R 20R: 20R 24-ethyl 14α, 17α cholestane, C29 20S 20S 24-ethyl 14α, 17α cholestane, C29 22S/(22S+22R) 22S 17α,21β homohopane/(22S 17α,21β homohopane+22R
17α,21β homohopane) 3,4 DMD 3,4_Dimethyldiamantane 3,MD 3-Methyldiamantane 4 MD 4-Methyldiamantane 4,8 DMD 4,8-Dimethyldiamantane 4,9 DMD 4,9_Dimethyldiamantane 9,MT 9-Methyltriamantane A Adamantane API° American Petroleum Institute Gravity ARO Aromatics ASP Asphaltenes C/N Carbon to nitrogen ratio C27/C29 Cholestane/24 Ethylcholestane D Diamantane Diast/St Diasterane/Sterane
xxiii
ABBREVIATION DESCRIPTION DMT Dimethyltriamantane FID Flame Ionization Detector GC Gas Chromatography GP Genetic Potential GR Gamma Ray H/C Elemental hydrogen to carbon ratio HI Hydrogen Index Kg Kilogram Kg/t Kilogram Per Ton L Litter M Meter mD Millidarcy Mg Milligram Min Minute Mm Millimeter MS Mass Spectrometer MSD Mass selective detector mV Millivolt N Normal concentration of solution Ninorg Inorganic nitrogen Norg Organic nitrogen NSO Nitrogen, sulphur and oxygen O/C Elemental oxygen to carbon ratio OI Oxygen Index OM Organic Matter PDB Pee Dee Belemnite Ph Phytane Ph/n-C18 Phytane/Octadecane PI Production Index Ppm Parts per million Ppt Parts per trillion Pr Pristane Pr/n-C17 Pristane/ Heptadecane Pr/Ph Pristane/Phytane S Sulphure SAT Saturates Sec Second SIM Selective Ion Monitoring SOM Soluble Organic Matter SP Spontaneous Potential St/Hop 5α, 14α, 17α Cholestane/17α-Hopane T Triamantane
xxiv
ABBREVIATION DESCRIPTION TIC Total ion chromatogram Tm 17α 22,29,30-trisnorhopane Tmax Maximum Temperature TMD Trimethyldiamantane TOC Total Organic Carbon TPS Total Petroleum System Ts 18α 22,29,30-trisnorhopane Type-I Kerogen Type-I Type-II Kerogen Type-II Type-III Kerogen Type-III Wt Weight Α Alpha Β Beta ββ 20S 24-ethyl 5α, 14β, 17β cholestane, C29 γ Gamma δ Delta
1
Chapter-1
INTRODUCTION
1.1 PETROLEUM SYSTEM
The quantitative predictions on the hydrocarbon potential of an area comprise the
Total Petroleum System (TPS) of that area. It encompasses a pod of active source rock
and all genetically related oil and gas accumulations. A petroleum system exists wherever
all essential elements and processes are known to occur or are thought to have a
reasonable probability to occur. In other words, for oil or gas existence, all geological
elements and processes must be there so that the organic matter (OM) in a source rock
can be converted into a petroleum accumulation. The essential elements and process of a
petroleum system are shown in the following table.
Table-1.1: Essential elements and geological process for Total Petroleum System
(TPS)
Essential Elements Geological Process
Source rock
Reservoir rock
Seal /Overburden rock
Trap Formation
Generation and migration
Several petroleum systems have been recognized in previous studies (Jaswal et
al., 1997; Khan et al., 1986; Wandrey et al., 2004) in the Potwar Basin, Pakistan;
however, these have been combined into a single composite Eocambrian-Miocene TPS
(the Patala-Nammal TPS) owing to the scarcity of available in formation (Wandrey et al.,
2004). Furthermore, due to multiple stacked sources, reservoirs and extensive fault
systems in the area, further subdivision is difficult due to mixing of hydrocarbons from
different sources.
1.1.1. Source Rock
The term source rock (Table-1.2) describes fine grained sedimentary rocks having
capabilities to preserve sufficient quantity of right type of OM. The sedimentary OM
comprises of two general fractions; (i) bitumen, low molecular weight OM extractable by
common organic solvents and (ii) Kerogen, a high molecular weight component that is
2
insoluble in these solvents. Peters and Cassa, 1994 gave classification of source rock
based on quality, quantity and thermal maturity of OM.
Another terminology regarding different types of source rocks is given by Brooks
and Fleet in 1987. They divided source rock into three types: effective source rock,
possible source rock and potential source rock. Where Effective source rock is a
sedimentary rock that has already generated and expelled hydrocarbons and Possible
source rock is sedimentary rock whose source potential has not yet been evaluated, but it
may have generated and expelled hydrocarbons, while Potential source rock is immature
sedimentary rock known to have capabilities to generate hydrocarbons if it attains
requisite level of thermal maturity.
Source Rock of Potwar Basin
There are multiple source rocks for petroleum with different levels of maturity in
the Potwar Basin. The primary source for hydrocarbons appears to be the Paleocene
Patala Formation (Wandrey et al., 2004) but other potential source rocks may be
contributing in different parts of the basin. The details of source rocks are given below
(Table-1.2):
Table-1.2: Source Rocks Present in the Potwar Basin (OGDC, 1996; Quadri and
Quadri, 1996)
Source and Age Remarks
Clastic and
evaprites of Lower
Cambrian
Oldest potential source rock consists of a dominant clastic in
lower part while dominant in carbonate and evaporites in middle
part. Potential source rock intervals with TOC (upto 30%), HI
(upto 879) and GP (upto 250kg/t) are found in evaporite
sequence (Aamir and Siddiqui, 2006; Wandrey et al., 2004)
Marine and Deltaic
Shales of Jurassic,
Triassic and
Permian
Wargal Formation has a TOC (wt%) of 1% (Jaswal et al., 1997).
Datta Formation shows 06-2% TOC (wt%) although the main
component of this Formation is sand.
Sardhai Formation and Chhidru Formation have sufficiently high
TOC (wt %) values to have source-rock potential (Quadri and
3
Source and Age Remarks
Quadri, 1996).
Marine Shales of
Paleocene
Lockhart Formation has a TOC of 1.4% (Jaswal et al., 1997).
The marine shales of Patala Formation are probably predominant
oil source in the Potwar Basin (OGDC, 1996). It has TOC value
from 0.5% to >3.5% with an average of 1.4% (Wandrey et al.,
2004).
1.1.2. Reservoir Rock
Sedimentary rocks having sufficient porosity and permeability to accumulate
hydrocarbon are termed as reservoir rocks. Reservoir rocks are either clastic or
carbonates composition. Clastic rocks are composed of silicates and chemically stable
while carbonate are formed by biogenetically produced detritus and are susceptible to
alteration by the process of diagenesis (Frank et al., 1998).
Reservoir Rocks in Potwar Basin
The reservoirs in the Potwar Basin are both sandstones and carbonates and range
in age from Cambrian to Miocene. More than 60% producing reservoirs belong to Eocene
carbonates (Wandrey et al., 2004) (Figure-1.1). Sandstone porosities is 5-30% with an
average of 12-16% while permeability is 1-30mD within average of 4-17mD. The details
of reservoir rocks of Potwar Basin are given in Table-1.3.
1.1.3. Traps and Seals
Hydrocarbons are of low density than Formation water. If there is no mechanism
to stop their upward migration then they will seep to the surface. Seals and Traps are
fundamental elements for entrapment of hydrocarbons A trap is defined as “any rock that
permits significant accumulation of oil or gas, or both, in the subsurface” (North, 1985).
Traps and Seals in Potwar Basin
Overturned anticlinal faults pop up structures and fault traps are commonly found
in the Potwar Basin (Wandrey et al., 2004). Seals may be provided by shale units and
tightly packed carbonates. Several unconformities have sealing abilities to restrict
hydrocarbons. Numerous shaly units (pre-Neogene sequence) provide adequate seals for
various individual reservoirs.
4
Table-1.3: Geological Age, Reservoir type and oil/gas producing Formation
found in Potwar Basin, Pakistan (Jaswal et al., 1997; Khan et al.,
1986; Wandrey et al., 2004)
Age Reservoir Type Formation
Miocene Alluvial sandstone* Murree
Eocene Carbonates, Shale Bhadrar, Chorgali, Sakesar, Margala Hill
Limestone
Paleogene Carbonates Khairabad, Lockhart, Patala and Nammal
Cretaceous Sandstone Lumshiwal
Jurassic Continental sandstone* Datta
Permian Sandstone* Tobra, Amb and Wargal
Cambrian Alluvial and
Sandstone*
#Khewra, Kussak and Juttana
* Sandstone porosities range from <%5 to 30% with an average of 12%-16%. Sandstone
Permeability ranges from 1mD to > 300mD with an average of 4mD to 17mD (Khan et al., 1986).
# The oldest reservoir for oil, gas and condensates. Producing oil fields like Adhi, Missakeswal,
Rajian are producing from Khewra sanstone.
0
2
4
6
8
10
12
14
16
18
20
Miocene Eocene Paleocene Jurassic Permian Cambrain
Age
Nu
mb
er
of
Oil
Fie
lds
Figure-1.1: Distribution of producing reservoir based on number of field and
geological age (Wandrey et al., 2004).
5
Cambrian Khewra sandstone is sealed by shales and carbonates of Kussak
Formation in Adhi, Rajian and Kal oil and gas fields while in Missa Keswal field, three
Lower Cambrian oil bearing intervals are sealed by intra Formational shales. The seals
for hydrocarbons in the Potwar Basin are given below (Table-1.4);
Table-1.4: Various seals and reservoirs present in different oil fields of Potwar
Basin Pakistan (Quadri and Quadri, 1996).
Field/Well Reservoir Seal
Adhi Lower Permian Tobra Dandot Formation
Dhurnal Wargal Hangu Formation
Meyal Datta Tertiary unconformity and Hangu Formation
Meyal-2 Datta Shinwari Formation
Balkassar-4 Samana Suk Chichali Formation
Balkasar-1 Chorgali Marine marl of Chorgali Formation
The effectiveness of sealing capabilities of sediments of Potwar Basin is reflected
by the abnormally high pressures encountered by molasse sediments during drilling. In
the Kohat-Potwar fold and thrust belt, almost all the hydrocarbons producing structures
are either fault bounded or compartmentalized by high angle thrust faults, resulting in the
combination of older rocks against the overlying younger molasses sediments (Wandrey
et al., 2004). This kind of stratigraphic relationship provides a good and effective lateral
seal in most of the cases.
1.1.4. Generation and Migration
The organic debris is best preserved in fine-grained sediments deposited in the
absence of oxygen (Waples, 1983). Diagenesis converts organic matter with the help of
chemical and biological reactions. These reactions take place during early burial in the
depositional environment at low temperature and the products of these reactions are large
molecules, the largest being kerogen. These large molecules act as precursors for oil and
gas.
With increase in burial depth, porosity and permeability of sedimentary rocks
decreases and temperature increases. These changes terminate microbial activity and
bring Diagenesis to a halt. The OM changes through the process of Catagenesis, where
catagenesis is a thermal phase. Kerogen begins to disintegrate into smaller, more mobile
6
molecules called Bitumen which is further converted into gas molecules under the
influence of temperature by the process called Metagenesis. The heat mediated reactions
that convert sedimentary OM in to petroleum is termed as Maturation (Peters et al.,
2005b). Once formed, oil and gas molecules migrate from source rock into reservoir
rocks which are more porous and permeable than source rocks.
Migration involves upward movement of hydrocarbons through permeable strata.
Two stages have been recognized in the migration process;
i. Primary Migration
ii. Secondary Migration
Primary migration involves expulsion of petroleum from low permeability source
rocks into more permeable strata. In the secondary stage of migration the generated
petroleum moves freely to suitable reservoir structure.
Generation and Migration of Hydrocarbons in the Potwar Basin
Generation of hydrocarbons in the Potwar Basin most likely began in Late
Cretaceous time for Cambrian through Lower Cretaceous source rocks and again from
Pliocene time to the present for younger source rocks (OGDC, 1996). Wandrey et al.
(2004) suggested that the generation and migration in Potwar Basin start at about 30Ma
and therefore show only a late or second period of generation i.e. from 20-15Ma and still
continued.
1.2 ROCK-EVAL PYROLYSIS
Rock-Eval pyrolysis, initially given by Espitalié et al. (1977), is a widely
acceptable technique which utilize temperature programmed heating (in the range of 300
°C to 550 °C) of small amount of rock (50-70mg) or coal (30-50mg) in an inert
atmosphere (He or N2) in order to determine petroleum potential of rock samples. The
resulting pyrogram is shown in Figure-1.2. The parameters which are generated by Rock-
Eval are S1, S2, S3 and Tmax. These parameters are used to evaluate quantity, quality and
thermal maturity of OM. The S1 represents hydrocarbons present in free state that are
thermally distilled at 300 °C and S2 represents hydrocarbons cracked from the kerogen
during temperature range of 300 °C to 550 °C. Both S1 and S2 are measured in mg of
hydrocarbons/g of rock.
7
Figure-1.2: Schematic diagram showing output of Rock-Eval analysis and
application interpretation (Tissot and Welte, 1984).
8
The CO2 released during kerogen cracking is trapped and measured by a thermal
conductivity detector (TCD) as S3 in mg CO2/g rock. The fourth parameter Tmax is the
temperature at which maximum amount of hydrocarbons (S2) is generated from the
kerogen during Rock-Eval pyrolysis. The Rock-Eval data is interpreted in terms of
kerogen type, generation potential of source rock, thermal maturity and to delineate oil
and gas prone sediments.
1.2.1. Quantity of Organic Matter
The quantity of organic matter in the sediments is pre-requisite for a potential
source rock. Peters and Cassa (1994) suggested that there are minimum values of organic
carbon below which sediments are unable to produce oil/gas. Lewan (1987) found that
the minimum value of TOC (wt %) required to expel hydrocarbons is between 1.5 and
2%. Gas appears to have expelled at about 0.5% TOC. Peters and Cassa (1994) gave
guideline values for the petroleum potential source rock (Table-1.5).
Table-1.5: Geochemical parameters describing petroleum potential (quantity) of
a source rock (Peters and Cassa, 1994).
TOC (Wt %) Bitumen Petroleum
Potential Shale Carbonates*
S1
mg/g
S2
mg/g(wt %) (ppm)
Hydrocarbons
(ppm)
Poor 0-0.5 <0.2 0-0.5 0-2.5 0-0.05 0-500 0-300
Fair 0.5-1 0.2-0.5 0.5-1 2.5-5 0.05-0.1 500-1000 300-600
Good 1-2 0.5-1 1-2 5-10 0.1-0.2 1000-2000 600-1200
Very good 2-4 1-2 2-4 10-20 0.2-0.4 2000-4000 1200-2400
Excellent >4 >2 >4 >20 >0.4 >4000 >2400
1.2.2. Thermal Maturation
Thermal maturity refers to the extent of heat driven reactions that converts
Kerogen to bitumen and petroleum and then into gas and graphite. Kerogen breaks down
under the influence of increased temperature and pressure during deep burial of
sediments and produces petroleum (Hunt, 1979). The important and detectable
quantitative changes which allow researchers to judge the extent to which kerogen
maturation has proceeded is accessed by thermal maturation (Behar and Vandenbroucke,
1987). Cracking of kerogen in the presence of hydrogen will favor hydrocarbon
9
production (Durand, 1980). The Rock-Eval Tmax,21
1
SS
SPI and
TOC
Bitumen are
parameters for thermal maturity. The guidelines regarding thermal maturity proposed by
Peters and Cassa (1994) are given in Table-1.6. HI vs. Tmax plot is used to determine
different types of kerogen. However at latter stages of maturity, Type-I, II and III will
show similar chemical composition.
Table-1.6: Geochemical Parameters Describing Level of Thermal Maturation
(Peters and Cassa, 1994).
Stage of thermal maturity Tmax (ºC) Bitumen/TOC PI
Immature <435 <0.05 <0.1
Early 435-445 0.05-0.1 0.1-0.15
Peak 445-450 0.15-0.25 0.25-0.4
Mature
Late 450-470 <0.1 >0.4
Post mature >470 ------- -------
1.2.3. Kerogen Classification
There are different methods to classify different types of Kerogen. French
petroleum institute classifies Kerogen into three types i.e. Type-I, Type-II and Type-III
and a forth type (Type-IV) which is less studied. Analysis of immature Kerogen by H/C
and O/C ratios plot gives van Krevelen diagram (Figure-1.3) in which kerogen is
differentiated into three different types. This classification also indicates sources of
Kerogen along with oil and gas production ability/stage. Another classification of
kerogen was done using HI vs. OI plot (Figure-1.4). This plot is often relates with van
Krevelen diagrams and some time called as a modified or pseudo-van Krevelen diagram.
Peters and Cassa (1994) have given guideline values for the classification of kerogen type
and expeeled product based upon HI and S2/S3 (Table-1.7). Where
xTOCS
HIdexHydrogenIn100
)( 2
xTOCS
OIxOxygenInde100
)( 3
10
Figure-1.3: Atomic H/C vs. atomic O/C plot showing different types of kerogen
and oil/gas generation zone (Tissot and Welte, 1984).
Figure-1.4: Classification of Kerogen Types based on HI/OI diagram (Peters and
Cassa, 1994).
49
Table-1.7: Geochemical parameters describing kerogen type (Quality) and expelled
product at peak maturity (Peters and Cassa, 1994).
Kerogen HI (mg of HC/g of TOC) S2/S3 Expelled product
I >600 >15 Oil
II 300-600 10-15 Oil
II/III 200-300 5-10 Oil/Gas
III 50-200 1-5 Gas
IV <50 <1 None
Type-I kerogen is relatively rare. It is formed in organic rich rocks that are deposited
under anoxic environment and shallow water column. It contains highly oil prone OM having HI
>600mg HC/g TOC while H/C could be upto 1.9. It is formed from algal OM deposited.
Alginites are the maceral group in lacustrine settings, dominate amorphous liptinite macerals are
found in Type-I kerogen. It contains significant input from lipids derived from the selective
accumulation of algal and bacterial remains. Long chain n-alkanes are major components of the
Type-I kerogen, aromatic and NSO compounds are less compare to other types of kerogen
(Durand, 1980).
Type-II kerogen is derived from mixed (marine and terrigenous) OM deposited under
marine depositional conditions. It has potential to generate both oil and gas. Plant resins, pollens,
spores, maceral groups i.e. resinite, extinite and cutinite deposited in reducing environmental are
the source of Type-II kerogen (Fisher and Miles, 1983). Immature Type-II kerogen has high HI
values i.e. 300–600 mg HC/g TOC (Peters et al., 2005b). Type-II kerogen has poly aromatic
nuclei with ketonic and carboxylic acid groups. Aliphatic structures comprise abundant chains of
moderate length (up to C25) and ring systems (naphthenes) (Durand, 1980). Associated bitumens
contain abundant cyclic structures (aliphatic and aromatic hydrocarbons, and thiophenes) and
have higher sulphur content than other types (Staplin, 1969).Sulfur is typically higher in Type-II
compared with other kerogen types. Unusually high sulfur in certain Type-II kerogen (Baskin
and Peters, 1992; Lewan, 1986; Orr, 1974; Peters et al., 1990) may explain the tendency of this
kerogen to generate petroleum at lower levels of maturity. They contain mixed OM from
phytoplankton, zooplankton, bacterial remains and lipid rich remains of higher plants like spores,
pollen, cuticles, resins and waxes. Type-II kerogen contain high percentage of sulphur
compounds in the range of 8-14% is classified as Type-IIS kerogen. In Type-IIS, H/C is uptp 1.4,
50
atomic S/C 0.04 and begin to generate oil at lower level of thermal maturity than typical type II
kerogens with <6 % sulfur.
Type-III kerogen is gas prone. It is mainly from terrigenous OM deposition under deltaic
to paralic marine setting. Type-III kerogen has polyaromatic nuclei, ketone, and carboxylic acid
groups. Minor amounts of aliphatic compounds are present i.e. methyl and other short chain
compounds bound with oxygen containing functional groups. Some time long chain compounds
are present due to the contribution of higher plant waxes (liptinites) and cutin (exinites) (Durand,
1980).
1.3. GEOPHYSICAL WELL LOGS AND WIRELINE LOG
The procedure of making a detailed record (a well log) of the geological formations is
called well logging. It is based on physical measurements of rock properties made by instruments
that are lowered into the boreholes drilled for the oil and gas exploration. Wireline logging is
performed by lowering a 'logging tool' at the end of a wireline into an oil or gas well (or
borehole) and recording properties using a variety of sensors. Logging tools measure the
electrical, radioactive, electromagnetic, nuclear magnetic resonance, and other properties of the
rocks and entrapped fluids. In this study we have used gamma ray ( -ray) log and spontaneous
potential (SP) log to determine rock types.
Gamma Ray ( -ray) Log
A log of the natural radioactivity of the formation along the borehole, measured in API is
called gamma ray log. It is useful for distinguishing between sands and shales in a siliclastic
environment. This is because sandstones are usually nonradioactive quartz, whereas shales are
naturally radioactive because of potassium isotope (K-40) as the largest source of
natural radioactivity in clays, and adsorbed uranium and thorium (U, Th) which are daughter
products of the uranium and thorium decay series. Decay of radioactive elements produces high
energy gamma ray emissions. Gamma ray log records the amount of natural gamma radiation
emitted by the rocks surrounding the borehole using Geiger Muller counter.
Radioactive elements are normally concentrated in shaley rocks, therefore clay and shale
bearing rocks show high gamma ray log readings while most clay free sandstones and carbonates
51
are very weakly radioactive and have low gamma ray log readings. Shales are sufficiently high in
radioactivity while radioactivity of sandy shales is less therefore these stratigraphic units can be
easily distinguished from the other rocks on a gamma ray log (Figure-1.5). Other applications of
gamma ray logs include; location of radioactive ores, uranium in particular. It also helps to locate
lignite and coal beds.
Figure-1.5: Gamma ray log showing effect of various lithologies on gamma ray log
readings (Selley, 1985).
52
Spontaneous Potential (SP) Log
The spontaneous potential (SP) log measures the natural or spontaneous potential
difference that exists between the borehole and the surface, without any applied current. It is a
very simple log that requires only an electrode in the borehole and a reference electrode at the
surface. These spontaneous potentials arise from the different response that different formations
provide for charge carriers in the borehole and formation fluids, which lead to a spontaneous
current flow. The SP log gives the following main uses: detection of permeable beds,
identification of shale in a formation and correlation (Selley, 1985). It was one of the first
wire line logs developed, found when a single potential electrode was lowered into a well and a
potential was measured relative to a fixed reference electrode at the surface. The most useful
component of this potential difference is the electrochemical potential that causes a significant
deflection in the SP response opposite permeable beds. The magnitude of this deflection depends
mainly on the salinity contrast between the drilling mud and the formation water, and the clay
content of the permeable bed. Therefore the SP log is commonly used to detect permeable beds
and to estimate clay content and formation water salinity (Selley, 1985).
Figure-1.6: A typical SP tool arrangement (Selley, 1985).
53
Figure-1.7: A typical responses of the SP log showing variation of potential with
permeability (Selley, 1985).
1.4. BIOMARKERS IN SEDIMENTS AND PETROLEUM
The basic chemical constituents for all living organisms are: lipids, proteins and
carbohydrates, and lignins in higher plants. Each has very characteristic differences with respect
to the relative abundances and detailed chemical structure in different organisms and their end
products (Tissot and Welte, 1984). Organic geochemist studies the composition, fate and
distribution of organic matter in the geosphere (Rullkötter et al., 1988).
Under certain environmental conditions, biological precursor of certain organisms, leads
to the Formation of biomarkers (biological markers). Thus, biomarkers are indicators of those
prevailing conditions and organisms. Biomarkers are composed of complex structure of carbon,
hydrogen, and other elements i.e. sulphur, nitrogen, oxygen etc. Biomarkers found in oil,
petroleum and sediments extract show little or no change in structure from their parent organic
molecules in living organisms (Peters and Moldowan, 1993). Carbon skeleton of biomarkers
survive in the processes of diagenesis and catagenesis hence they are structurally similar but
54
diagenetically alteration products of specific natural products (Mackenzie et al., 1983). In
general, specific organic matter input and its environmental/depositional conditions are
responsible for the structure of biomarker. It can be traced back to the natural product precursors
in algae, plants, bacteria and other organism from which they were derived (Peters et al., 2005b).
Biomarker distributions, in oils and source rock bitumens, can provide a powerful
correlation tool, which can be used to interpret characteristics of the petroleum source rock i.e.
source rock lithology, age and extent of hydrocarbon biodegradation in case of crude oils (Peters
and Moldowan, 1993). It also provides information on the nature of organic matter, deposition
environment and thermal maturation. However, factors like source, maturity, depositional
environment and the extent of biodegradation are largely interrelated (Murray and Boreham,
1992). In other words, a single biomarker is less effective in defining organic matter type, source
rock lithology or depositional environment than a number of biomarkers (Arouri, 1996).
Biomarker parameters are best combined to provide the most reliable interpretations of source
rocks (Peters and Moldowan, 1993).
1.4.1. Hopanes
Pentacyclic triterpenoids, including precursors of the hopanes, are found in primitive
organisms and higher plants, but appear to be absent in algae (Peters and Moldowan, 1991).
Bacteria appear to be the major source for hopanoids in sediments, rocks, and petroleum. The
extended hopanes or "homohopanes" (C31-C35) are probably related to bacteriohopanetetrol
found in bacteria. Hopanes are abundant biomarkers in sedimentary rocks and petroleum because
their hopanoid precursors are widespread membrane components in living cells and are resistant
to degradation during diagenesis (Ourisson et al., 1979; Ourisson et al., 1984; Peters and
Moldowan, 1991). Other polyfunctional C35-hopanoids are also believed to act as precursors for
homohopanes (Peters and Moldowan, 1991; Rohmer, 2010). The hopanoids undergo a net
reduction to hopanes during diagenesis. It is calculated that hopanoids account for 5%–10% of
the soluble organic carbon in rocks and sediments (Peters and Moldowan 1991; Ourisson et al.
1979). Evidence shows that bacteriohopanetetrol can also be incorporated into kerogen and later
released during catagenesis (Mycke et al., 1987; Peters and Moldowan, 1991). The biological
17 (H), 21 (H)-22R configuration of hopanoids in organisms is thermally unstable compared to
other epimers (Kolaczkowska et al., 1990). During (Philp, 1983b)hopanes (Peters and
Moldowan, 1991) along a reaction scheme proposed by Seifert and Moldowan (1980).
55
Hopanes are commonly used to relate oils to source rocks which are shown on the m/z
191 mass chromatograms. They reflect source rock depositional environment and organic matter
input. Because bacteria are found abundantly in sediments, hopanes occur nearly in all oils, and
oils from different source rocks deposited under identical conditions may show similar hopane
fingerprints.
1.4.2. Steranes
Sterols, such as cholesterol, are essential lipids in all eukaryotic organisms. Recent
sediments contain an extensive variety of different functionalized sterols characterized by the
position and number of functional group. Steranes and diasteranes with 27 to 29 carbon atoms
are common in most oils and bitumens. During diagenesis and catagenesis the biological
stereospecificity of sterols, particularly at C-5, C-14, C-17, and C-20, is usually lost and a
diverse range of isomers is generated.
The use of sterane distribution patterns in crude oils and sediments extracts are numerous
e.g. correlation between crude oils and a source rock is now an established tools to the petroleum
explorationists (Connan et al., 1980; Grantham, 1986; Hufnagel et al., 1980; Peters and
Moldowan, 1991; Philp, 1983b; Seifert and Michael Moldowan, 1978, 1979; Seifert and
Moldowan, 1980; Volkman et al., 1983). Source of organic matter as marine, terrestrial or algal
is determine from the relative proportions of varying steranes particularly C27, C28 and C29 on
ternary diagram (Huang and Meinschein, 1979; Mackenzie et al., 1981; Mackenzie et al., 1983),
catalytic effect of clay is examined from the distribution and relative abundance of diasteranes
(Ensminger et al., 1978; Sieskind et al., 1979) and bacterial degradation of crude oils is studied
from degradation of steranes (Connan et al., 1980; Goodwin et al., 1981; Seifert et al., 1979).
Diasterane formation also indicates oxic environments. The typing of crude oils and source rock
extracts using sterane distribution patterns has found much application (Grantham, 1986).
The most common precursors of sedimentary steranes are sterols which are found in
eukaryotes (Mackenzie et al., 1983). Steranes in living organism show 14 (H), 17 (H) – 20R
configuration (biological configuration). During diagenesis and catagenesis this biological
configuration is changed to mixture of 20R and 20S. The RS
S
2020
20 ratio is the most
commonly used biomarker maturity parameter. At equilibrium its value is between 0.52-0.55 for
C29 sterane. The 14 (H), 17 (H) sterane is transformed into 14 (H), 17 (H) isomer in both
56
20R and 20S forms, resulting in an increase of ratio from non-zero to about 0.7 with
equilibrium from C29 sterane occurring between 0.67-0.71 (Seifert and Moldowan, 1986).
1.4.3. DIAMONDOIDS
Diamondoids are cage-like, ultra-stable, saturated hydrocarbons that have diamond like
fused ring structure consisting of a number of cyclohexane rings. They consist of repeating units
of ten carbon atoms forming a tetra-cyclic cage system. They are called "diamondoid" because
their carbon-carbon framework constitutes the fundamental repeating unit in the diamond lattice
structure. The first and simplest member of the group is adamantane followed by its polymantane
homologues i.e. diamantane, triamantane, tetramantane etc. The general chemical formula for
diamondoids is C4n+6H4n+12. It has been found that adamantane crystallizes in a face-centered
cubic lattice which is free from angle strain and torsional strain, making it a very stable
compound.
Diamondoids are constituents of crude oils and condensates. Adamantane was originally
discovered and isolated from petroleum fractions of the Hodonin oilfields in Czechoslovakia
(Landa and Machacek, 1933). Diamondoids in petroleum are believed to be formed
enzymatically from lipids with subsequent structural rearrangement during the process of source
rock maturation and oil generation. Because of this, the diamondoid content of petroleum is
applied to distinguish source rock facies. Due to particular structure of diamondoids, they could
be useful in making new biomarkers with more stability than the existing ones. New findings
indicate that diamondoids are the appropriate alternatives for analyzing reservoirs which could
not be assessed with conventional techniques. They appear to be resistant to biodegradation.
Following biodegradation the remaining oil is enriched with diamondoids. Then the level of
biodegradation will be estimated by determination of the ratio of diamondoids to their
derivatives, particularly when main part of hydrocarbons has been degraded. It is believed that
the diamondoids found in petroleum result from carbonium ion rearrangements of suitable
organic precursors (such as multi-ringed terpene hydrocarbons) on clay mineral from the same
source. In view of the Lewis acid catalyzed isomerization (rearrangement) of hydrocarbons, it is
speculated that diamondoids may have been formed via homologation of the lower
adamantologues at high pressure and temperature in the natural underground oil and gas
reservoirs. The lower adamantologues are believed to have been formed originally by the
57
catalytic rearrangement of tricycloalkanes during or after oil generation.
Methyl derivatives of diamondoids show variation in the thermal stability. This variation
of thermal stability of diamonds lead to the use of certain isomer ratios as maturity parameters
for crude oils and source rocks, especially at high and overmature stages of hydrocarbon
generation (Chen et al., 1996). For example, 1-methyl-adamantane (1-MA) is more stable than 2-
methyladamantane (2-MA), 4-methyldiamantane (4-MD) is more stable than 1-
methyldiamantane (1-MD) and 3-methyldiamantane (3-MD). Hence, the ratios 1-MA/(1-MA+2-
MA) and 4-MD/(1-MD+3-MD+4-MD) should increase with increasing thermal stress (or depth).
In other words the greater the ratio, the higher will be the thermal maturity of the oils and source
rocks.
1.5. STABLE ISOTOPES
Stable isotope compositions of carbon, sulfur, nitrogen, and hydrogen are used with
biomarkers to determine genetic relationships among oils and bitumens. Isotopes are atoms
whose nuclei contain the same number of protons but different numbers of neutrons. 12
C and 13
C
are called the light and heavy stable isotopes and account for 98.89% and 1.11% of all carbon.
Stable isotope data are presented as delta ( ) values representing the deviation in parts per
thousand (‰, permil, or ppt) from an accepted standard.
1000‰)(tan
tanx
R
RR
dards
dardssample
Where “R” represents the isotope abundance ratio, such as 13
C/12
C,18
O/16
O,34
S/32
S,
15N/
14N, and D/H (
2H/
1H). The isotopic abundance of some commonly used elements is given in
Table-1.8. The value for carbon, for example, is a convenient means to evaluate small
variations in the relative abundance of the 13
C in organic matter. A negative value implies that
the sample is depleted in the heavy isotope relative to the standard. A positive value means that
the sample is enriched in the heavy isotope relative to the standard. Sealed tube combustion is
the most popular method to convert organic matter to carbon dioxide for isotope analysis until
1990 because it yields reproducible results but is generally faster and less expensive than
dynamic combustion using a vacuum line (Peters et al., 2005b). Today, most analyses for stable
carbon isotope composition i.e. compound specific isotopic analysis (CSIA) and bulk isotopic
analysis are carried out using online combustion systems with a coupled elemental analyzer and
58
isotope ratio mass spectrometer (combustion/IRMS) (Hoefs, 1997). Bulk isotopic analysis is
used for the carbon, nitrogen, oxygen and sulphur etc. Small amounts of sample enclosed in tin
capsule is burned under oxygen stream with various catalysts to produce respective isotopes of
interest i.e. isotopes of nitrogen, carbon, oxygen etc. These isotopes are then quantified with
IRMS and results are reported relative to the Pee Dee Belemnite (PDB) for carbon and air for
nitrogen.
Table-1.8: Natural abundance of the most commonly used stable isotopes
Element Isotope Abundance
(%) 1H 99.94 Hydrogen
2H 0.016
12C 98.89 Carbon
13C 1.11
14N 99.64 Nitrogen
15N 0.36
16O 99.76 Oxygen
18O 0.20
32S 95.02 Sulphur
34S 4.21
1.5.1. Stable Carbon and Nitrogen Isotopes
All natural carbon of Earth exists as a mixture of two stable isotopes 12
C (98.9%) and 13
C
(1.1%). The carbon isotopic composition of living organic matter, in part, not only depends on
the species but also determined by a number of environmental properties e.g. the pathway of
photosynthesis, terrestrial and aquatic plants etc. Isotopic fractionation results in the relative
abundance of isotopes due to difference in their masses. Heavy isotopes usually form stronger
bonds compared to lighter isotopes. Hence lighter isotopes will react faster than the heavy
isotopes and product will be lighter than reactants (Hoefs, 1997). Stable isotopic data is
expressed by the (delta) notation in units of permil (‰) to report changes in the isotopic
abundance compare to standard.
1000‰)(tan
tanx
R
RR
dards
dardssample
59
Where Rsample and Rstandard are measured isotopic ratio for the sample and standard.
Because most carbon sources contain less 13
C than reference, the observed 13
C ‰ values are
usually negative.
Stable nitrogen ratios have been little used in the exploration for oil. The main problem
is, in addition to sample preparation and measurement, the petroleum has little organic nitrogen
usually of the order of 0.1‰ while 15
N has a wider range i.e. approximately 20‰ (Stahl, 1977).
This broad range may be useful in application of stable nitrogen isotopes in the distinguishing of
source of petroleum and furthermore as an indicator of organic pollution (Parker, 1971).
Table-1.9: Variation of carbon isotopic ratio in different types of OM
Organic matter Type 13
C content (PDB)
Hydrocarbon
source material
Organic carbon in recent sediments
i. Marine Plants
ii. Marine Plankton
iii. Non marine
iv. Land Plants
a) C3 Plant
b) C4 Plants
-18 to -8
-30
-32 to -22
-30 to -22
-15 to -10
Table-1.10: Table showing various types of organic matter along with their C13
, N15
and C/N values (Hamilton and Lewis Jr, 1992; Sarma et al., 2012).
Source of OM N15
C13
Source of OM C/N Ratio
Phytoplankton 3-4.2 -38 to -34 Terrigenous sediments 12.17-19.50
Algae on C3 plants 0-6.5 -38.8 to -26.2 Marine plants 11.27
C3 vascular plants -1.6 to 4 -29.8 to -26 Terrestrial plants (C3) 22.7-50.9
Algae on C4 grass 1.75-5.8 -30.2 to -22.5 Terrestrial plants (C4) 36.2-37.1
C4 grass 1.75-4.5 -13.2 to 10.2 Aquatic plants 10.4-14.6
It has been reported that the terrigenous detrital organic matter is generally characterized
by a low 15
N signature while the marine component has a relatively higher 15
N value (Mariotti
et al., 1984; Peterson et al., 1985; Thornton and McManus, 1994; Wu et al., 2002). In
comparison of stable carbon isotopes, nitrogen isotopic compositions had more complex
depositional fluctuations which indicate additional factors had the significant influences on the
distributions of 15
N in sedimentary organic matter i.e. a series of complex biogeochemical
processes (Wu et al., 2002).
60
Decomposition of organic matter increases the relative 15
N and result would create
isotopically enriched 15
N in sedimentary organic matter. Heavier 15
N values corresponded with
high C/N ratios, which suggested the latter are produced principally as a result of organic matter
diagenesis (Cifuentes et al., 1996; Thornton and McManus, 1994). Microbial mineralization also
reduced nitrogen percentage i.e. 14
N is preferentially lost and organic matter becomes
progressively enriched in 15
N. Consequently, higher decomposed organic matter will contain
little nitrogen but with enriched in 15
N.
6.1.3. C/N elemental ratios
The C/N elemental ratio has been used as an indicator of organic matter in aquatic
sediments because proteins, which are primary nitrogen compounds in phytoplankton and
zooplankton, have low C/N ratio in the range of 5-6 compared to plankton OM derived from
terrestrial OM in sediments which has C/N ratio 15 or higher while algae has C/N ratio 4-10
(Bordovskiy, 1965). It is due to that the higher plants mainly contain cellulose and lignin and few
nitrogen compounds.
The C/N ratio has been used as a representative proxy to reconstruct the depositional
environment of coastal lagoon and freshwater lake sediments (Sampei and Matsumoto, 2001).
Although the C/N ratios have been interpreted elsewhere to be nearly equal to the weight ratio of
Corg to organic nitrogen (i.e., C/Norg ratio), ignoring inorganic nitrogen (Ninorg) content, some
researchers have pointed out that a relatively high Ninorg could affect the C/N ratio. Müller (1977)
reported that C/N ratios in deep sea sediments were anomalously low (<4), attributing this
reduction to inorganic ammonia. This suggests that Ninorg introduces a degree of uncertainty in
using C/N ratio as an indicator of organic source.
1.6. AIMS AND SCOPE OF WORK
Sedimentary sequences of Eocene, Paleocene, Jurassic and older ages are reported source
rocks in the Potwar Basin. The main aim of this study is better understanding of the petroleum
systems of the Potwar Basin using wide range of samples and advanced analytical techniques
i.e., stable carbon and nitrogen isotopes, biomarkers, Rock-Eval and TOC study and different
well logs in following areas;
Evaluation of productive zone and permeability of Chorgali, Sakesar and Patala
formations with the help of spontaneous potential (SP) log and Gamma ray (GR) log
61
Source rock potential and thermal maturity of Eocene, Paleocene and Jurassic sediments
on the basis of Rock-Eval and TOC study
Evaluation of source and depositional environment of Chorgali, Sakesar and Patala
formations using stable isotopes of 13
C and 15
N and C/N ratios
Investigation of source, depositional environment and thermal maturation of Eocene,
Paleocene and Early Permian sediments using biomarkers
Evaluating potential of adamantane, diamantane and triamantane and their methyl and
ethyl derivatives as indicator of thermal cracking and microbial oxidation in crude oils
and condensates.
62
Chapter-2
GEOLOGY AND SAMPLE DESCRIPTION OF STUDY AREA
2.1. DESCRIPTION OF STUDY AREA (POTWAR BASIN)
Marine sedimentary rocks of Paleozoic, Mesozoic and Tertiary age are present in
Pakistan. Basinal set up is ideal for petroleum to have been formed. Shelf facies is predominant
(Wandrey et al., 2004). The shelf gives way to deeper trough and has been divided into
subsidiary basins by fundamental highs. Tectonism in the shelf areas has been modest. Indeed,
upto Tertiary times all the Earth movements were of non-orogenic type. Main orogenic
movements had been post marine sedimentation leading to the Formation of favourable structural
traps (Wandrey et al., 2004). The source-reservoir-cap rock combinations are present. The region
is nearby to the oil producing areas of Persian Gulf. Inspite of this entire favourable factor, the
scale of petroleum discoveries today has not been a substantial one. The reason above all, may be
that not enough drilling has been done.
The Potwar Basin where most of the exploration activity has taken place is more
prospective than other areas (Wandrey et al., 2004). Most prospects are in Tertiary and Mesozoic
rocks; they form traps in drillable depth and posses the combination of composite petroleum
system. The Potwar Basin was estimated to have a reservoir potential of 40 million barrels and a
yearly production of about 2.2 million barrels of oil. These oil reservoirs are all anticlines or
domal structures situated on two parallel E-W lines of foldings of Soan syncline which bounded
in the south by Salt Range and the north by Kala Chitta range. The quality of oil is highly
variable based on API° gravity ranging from 16° API and 50° API gravity. Along with the oil
substantial amount of gas is also produced in basin. The Jurassic and Eocene reservoirs are the
most important produces. Jurassic and Miocene production is mainly due to granular porosity
where as the Paleocene and Eocene are from limestone fracture porosity. Sealing caps has
invariably been provided by shales (Wandrey et al., 2004).
The Potwar Basin is located on a portion of the Indian Plate which was structurally
deformed during the Indo-Eurasian collision and by the overthrust of the Himalayas to the north
and NW. Overthrusting has resulted in intense deformation and the juxtaposition of strata of
widely varying ages (e.g. Precambrian and Tertiary) in close proximity. Precambrian rocks are
exposed in the Salt Range at the southern margin of the basin. Before the onset of plate collision
63
in the Eocene, the Precambrian interval was not buried sufficiently deeply for OM maturation to
occur and much of the Precambrian to Paleocene succession has remained thermally immature to
the present day (Grelaud et al., 2002; Khan et al., 1986). However, in local areas, abnormally
high Formation pressures resulting from regional compression and compaction disequilibrium,
together with deep burial by overburden rocks, have led to the generation and expulsion of
hydrocarbons from pre-Eocene source rocks (Grelaud et al., 2002; Law and Spencer, 1998).
2.1.1. Depositional History
Depositional history of study area is given in Chapter-5.
2.1.2. Stratigraphy of the Potwar Basin
A detailed description of the stratigraphy is provided by Wandrey et al. (2004 a, b) and
Fazeelat et al. (2010). The sedimentation in the area started in the late Precambrian and lasted
until Pleistocene (Figure-2.1). The significant unconformities are Ordovician-Carboniferous,
Late Permian-Mesozoic and Oligocene. The Precambrian Salt Range Formation, composed
largely of salt and gypsum with minor quantities of shale and claystone, is the basement unit. It
derives its name from the occurrence of huge deposits of rock salt. Above the Salt Range
evaporates, thick seams of shale and sandstone with minor carbonate representing Lower
Cambrian Jhelum group (Khewra, Kussak and Bhaganwala Formations). Lower Permian strata
comprising of Tobra Formation, overlain by the sandstones and claystones of the Dandot,
Warcha and Sardhai Formations and shales limestone and sandstones of Wargal and Chhidru
Formations overlie Precambrian and Cambrian strata in Potwar Foldbelt (Fazeelat et al., 2010).
The Jurassic strata embrace the Shinawari/Springwari and Datta Formations comprising of
nearshore siliciclastics & nonmarine-sandstone hiatus (Khan et al., 1986). Jurassic and Triassic
are poorly developed/absent in the Potwar area (Jaswal et al., 1997). The absence of Cretaceous
strata in the Potwar area is explained by the erosion rather than non-deposition; this applies also
to the eastern edge of the Basin where, to a certain extent, Cretaceous sequences might have been
formed but were eroded during Early Tertiary times (Raza et al., 1995).
64
Figure-2.1: Generalized stratigraphy of the Potwar area (Wandrey et al. 2004, and
references therein)
65
The Lower Cretaceous segment composed of Chichali Formation basinal shales and
massive cross-bedded sandstones of the Lumshiwal Formation. The Hangu Formation
siliciclastics were deposited initially on an erosional plane marking the pinnacle of the
Cretaceous Lumshiwal Formation (Fazeelat et al., 2010; Iqbal and Shah, 1980; Kemal et al.,
1992; Shah et al., 1977). The contact between the Lockhart and subordinate carbonates of the
Patala Formation is also transitional (Iqbal and Shah, 1980; Kemal et al., 1992; Shah et al.,
1977). The overlying Eocene Nammal Formation is shallow-marine to lagoonal shales and
interbedded limestones with a transitional contact between the Patala and the Nammal. The
Chharat Group includes marine shales and interbedded limestones of the lower Eocene Chorgali
Formation. Oligocene rocks are absent from the largest part of the basin. The upper part of the
stratigraphic section comprises Miocene Rawalpindi Group (Murree and Kamlial Formations).
The Murree Formation consists of fluvial sandstones and siltstones and the Kamlial Formation
fluvial sandstones and clays. Pliocene Pleistocene (Chinji, Nagri, Dhok Pathan and Soan
Formations) consists of fluvial sandstones and conglomerates of Siwalik Group mark the top of
the stratigraphic column.
2.2. SAMPLE DESCRIPTION
A total of 121 sediments and 12 crude oils/condensates are analyzed in this study. The
sediments belong to Eocene, Paleocene, Jurassic and Early Permian ages while crude
oils/condensates were obtained from reservoirs of Eocene to Jurassic ages. The location of
samples is given in Figure-2.2.
2.2.1. Crude Oils and Condensates
Crude oil/condensates have obtained from shallow as well as deep reservoir e.g. 1673m
(Khaur) to 5039m (Dhurnal) with API° gravity ranges from 19.37 (Balkasar Oxy) to 39.91
(Meyal). Mainly Eocene and Paleocene formations are acting as reservoir rocks in these
productive oil fields. Unconformities are responsible for the variation in depth of formation i.e.
Chorgali formation depth is around 2600m in Balkasar and Balkasar Oxy while same geological
formation is at 5039m depth for Dhurnal. Such variations in formation depth clearly support the
missing of geological formation or unconformities in the study area.
66
Well-A
Well-B
Kars
alK
hau
r
Dh
ulian
Well-C
Well-F
Well-D
Rata
na
Dh
akn
i
Fim
kasar
Well-E
33°
33.1
°
33.2
°
33.3
° 72°
72.1
°72.2
°72.3
°72.4
°72.5
°72.6
°72.7
°72.8
°
Mu
rree T
hru
st
Fau
lt
NO
RT
HE
RN
FO
LD
ED
ZO
NE
PO
TO
WA
R P
LA
TE
AU
SO
AN
RIV
ER
So
an
Syn
clin
e
010
20M
iles
Thru
st F
ault
Anticlin
e
Oil
Well
Fig
ure
-2.2
: L
oca
tio
n m
ap
of
wel
ls A
, B
, C
, D
, E
an
d F
on
ma
p o
f P
ak
ista
n
67
Ta
ble
-2.1
: D
escr
ipti
on
of
geo
log
ica
l a
ge
an
d r
eser
vo
ir f
orm
ati
on
of
sam
ple
s u
nd
er s
tud
y.
Th
e q
ua
nti
ty o
f v
ari
ou
s
cla
sses
of
com
po
un
ds
is d
eter
min
ed u
sin
g c
olu
mn
ch
rom
ato
gra
ph
y.
Sr.
#
Wel
l n
am
e T
ota
l
Dep
th (
m)
Res
erv
oir
G
eolo
gic
al
ag
e S
AT
(%)
AR
O
(%)
NS
O
(%)
AS
P
(%)
S %
AP
I°
Gra
vit
y
1
Bal
kas
ar
2528.9
2
Chorg
ali/
Sak
esar
E
oce
ne
37
42
11
10
0.1
19.9
1
2
Bal
kas
ar
oxy
2520
Chorg
ali/
Sak
esar
E
oce
ne
35
41
13
11
0.1
19.3
7
3
Dhak
ni
4591.0
7
Lock
har
t P
aleo
cene
59
30
6
5
0.1
35.8
3
4
Dhuli
an
2738.1
5
Lock
har
t P
aleo
cene
63
28
5
4
0.0
1
37.1
2
5
Dhurn
al
5039.6
9
Chorg
ali/
Sak
esar
/
Pat
ala
Eo
cen
e/
Pal
eoce
ne
63
28
5
4
0.0
1
35.6
3
6
Fim
kas
ar
3244.6
1
Chorg
ali/
Sak
esar
E
oce
ne
41
36
10
13
0.1
21.3
4
7
Kar
sal
3896.9
2
Chorg
ali/
Sak
esar
/
Lo
ckh
art
Eo
cen
e/
Pal
eoce
ne
34
40
15
11
0.0
1
20.1
2
8
Khau
r 1673.8
4
Sak
esar
E
oce
ne
63
25
6
6
0.0
1
35.2
3
9
Mey
al
4130.1
5
Dat
ta
Jura
ssic
67
23
5
5
0.0
1
39.9
1
10
Par
iwal
i 5024.3
0
Dhak
Pas
s P
aleo
cene
68
21
7
4
0.0
1
39.8
1
11
Pin
dori
4275.3
8
Chorg
ali/
Sak
esar
E
oce
ne
63
25
7
5
0.0
1
36.3
9
12
Rat
ana
4516.9
2
Chorg
ali/
Sak
esar
E
oce
ne
63
26
6
4
0.0
1
35.2
1
49
Eocene Chorgali and Sakesar formations are the commonly found reservoir rocks in the
Potwar Basin while Paleocene Patala and Jurassic Datta formations act both source rocks and
reservoir rocks (Table-2.1). The API° gravity varies from heavy oil to condensates. This
variation is reflected in relative compositions of classes of compounds (Table-2.1). Condensates
have high API° gravity and high concentration of saturate compounds (SAT) while heavy oils
have low API° gravity and low saturate compounds (Table-2.1).
2.2.2. Sediments
A total of 121 sediments from six wells are analyzed. Sediments belong to Eocene,
Paleocene, Jurassic and Early Permian ages. Sediments were selected randomly based upon TOC
and those having TOC 1% were analyzed. Oil wells are labeled as Well-A, Well-B, Well-C,
Well-D, Well-E and Well-F. Rock-Eval and TOC (wt%) analysis were performed on wells A, B
& C for quality, quantity and maturity of OM. Geophysical well logs i.e. Spontaneous potential
log (SP log) and Gamma Ray log (GR log) were performed on wells D, E, and F to interpret
lithology and productive zones. GC-MS analysis was used for source, depositional environment
and maturity in wells D, E and F. Table-2.2 enlist details of samples, while lithostratigraphy of
study of study area is presented in Figure-2.1.
50
Table-2.2: Table showing the geological formations, no of sediments samples and
Lithology of each formation of study area
Geological formation
Age/Name
No. of
Sample
Lithology
Well-A
Eocene Sakesar 10 Limestone with interbedded shale
Paleocene Patala 4 Shale with interbedded limestone
Paleocene Lockhart 9 Limestone with rare interbedded shale
Well-B
Paleocene Patala 22 Shale with interbedded limestone
Paleocene Dhak Pass 18 Limestone with rare interbedded shale
Well-C
Jurassic Datta 8 Sandstone with interbedded siltstone and shale
Well-D
Eocene Chorgali 5 Limestone with interbedded shale
Eocene Sakesar 4 Limestone with interbedded shale
Paleocene Patala 4 Shale with interbedded limestone
Well-E
Eocene Chorgali 5 Limestone with interbedded shale
Eocene Sakesar 5 Limestone with interbedded shale
Paleocene Patala 5 Shale with interbedded limestone
Early Permian Sardhai 5 Shale with rare interbedded limestone
Well-F
Eocene Chorgali 4 Limestone with interbedded shale
Eocene Sakesar 4 Limestone with interbedded shale
Paleocene Patala 4 Shale with interbedded limestone
Early Permian Sardhai 5 Shale with rare interbedded of limestone
51
Chapter-3
EXPERIMENTAL
A total of 12 crude oils/condensates and 121 sediments from six productive wells were
analyzed in this study. Crude oil/condensates belong to reservoir of Eocene, Paleocene and
Jurassic ages. Main reservoir formation and general information pertaining to crude
oils/condensates is given in Table-2.1. Sediments were obtained from following formations;
Chorgali and Sakesar (Eocene), Patala, Lockhart and Dhak Pass (Paleocene), Datta
Formation (Jurassic) and Sardhai Formations (Early Permian).
The experimental work including chromatographic separation, sample preparation,
extraction of SOM, liquid chromatography, gas chromatography (GC) and GC-MS was
performed in laboratories of chemistry department, U.E.T., Lahore. Accelerated Solvent
Extraction was performed at Geochemical and Environmental Research Group (GERG), College
Station, Texas, USA. GC-MS was performed at Department of Oceanography, Texas A&M,
College Station, Texas, USA. The elemental analysis and bulk isotope analysis was performed at
University of California’s DAVIS Stable Isotope Facility, USA. Total Organic Carbon (TOC)
and Rock-Eval analysis was performed at laboratory of Pakistan Petroleum Limited, Karachi.
Geophysical well logs i.e. SP log and GR log were provided by Ministry of Petroleum, Pakistan.
However, the work was repeated, wherever needed, in order to keep consistencies in the data.
3.1 Chemicals, Glassware and Apparatus
The analytical grade solvent and reagents; Deionized water, Dichloromethane (BDH),
Methanol (BDH), n-Hexane (Merck), cyclohexane (Merck), petroleum ether (Merck),
chloroform (BDH), Molecular Sieve 5A (Organics), Silica for TLC (60-200 mesh, BDH),
Silica for column (60-200mesh, BDH), alumina (neutral, 200mesh, BDH), copper strip, zinc
powder (BDH), magnesium sulphate (analytical grade), hydrofluoric acid (37%, BDH),
liquid nitrogen (commercial grade) were used without further purification.
Pasteur pipettes, liquid chromatography columns (10mL, 15mL capacity, Pyrex),
glass wool, cotton, soxhlet extraction assembly (250mL, Pyrex), quick fit distillation
assembly (250mL, Pyrex), ultrasonic bath, heating mental, hot plate, magnetic stirrer,
weighing balance (0.01g, 0.01mg, Sartorius), sample vials (3mL, 5mL, 10mL, Pyrex), Teflon
52
beakers (25mL). Glassware was soaked in chromic acid, washed with distilled water,
methanol and acetone. It was kept in oven at 110 °C prior to use.
Standardization/activation of reagents
i. Activated silica was used for column chromatography. The Silica is activated by
placing it in oven at 110°C for 8 hr prior to use.
ii. Precipitated copper powder was activated by rinsing with 3M HCl, distilled water,
methanol, acetone and hexane successively.
iii. Molecular Sieve 5A° was activated by heating it in oven at 110°C for overnight
before use.
iv. Soxhlet apparatus, after pre-extraction with (50:50) mixture of methanol and
dichloromethane for 8hrs, was used for extraction.
3.2. SAMPLE PREPARATION AND GEOCHEMICAL ANALYSIS
The sediments were washed thoroughly with distilled water to remove any dirt particle
and then dried in air. The dried samples were crushed and passed through 80 mm mesh sieve.
The powdered samples (10 g) were placed in an acid fume bath of 6N HCl (100 mL) overnight in
order to remove carbonates and bicarbonates. Then sample were repeatedly washed with
deionized water and placed in oven for drying. After drying, sediment samples were used for
bitumen extraction, TOC determination, Rock-Eval pyrolysis, Elemental and Stable isotopic
analysis. .
3.2.1. Extraction of soluble organic matter (SOM) from sediments
Soluble organic matter (SOM) was extracted using soxhlet extraction and accelerated
solvent extraction (ASE).
Soxhlet Extraction
The soxhlet apparatus was pre-extracted with a solvent mixture of (50:50 v/v
dichloromethane: methanol), before extraction. The apparatus was pre-extracted along with
thimble, cotton wool, activated copper turnings and anti-bumping granules for overnight. 1g of
powdered sediment was placed in a thimble which was then covered by cotton wool and was
started using mixture of dichloromethane and methanol (9:1, 250 mL). Whenever required,
freshly prepared extraction mixture was added. The extraction was continued till the solvent
53
became colorless. The SOM was recovered by removing solvent by a rotary evaporator followed
by complete removal of solvent under slow stream of nitrogen gas.
Accelerated Solvent Extraction (ASE)
A Dionex ASE 200 instrument, with 50 mL stainless steel extraction cells was used
for accelerated solvent extraction. A 50 mL extraction cell was prepared by placing a cellulose
filter in the capped end and then tightly packed with 5 g of Ottawa sand and 3 g of neutral silica
gel. 50 mL of mixture of DCM:MeOH (1:1) were passed over the column for conditioning. Then
the cell was packed with 1g of crushed sediment sample followed by 5 g sand and finally a
second cellulose filter before capping the cell. The ASE cell was placed into ASE carousel for
extraction process. During the extraction process, DCM:MeOH (1:1) was delivered into the
extraction cell, which was then brought to an elevated temperature (45 °C). Following extraction,
the extract containing the target analytes was purged from the cell using nitrogen (flow rate of 1
mL/min) into a collection vial for analysis (Ghani et al., 2007).
3.2.2. Removal of Free Elemental Sulphur from Crude Oils and Sediment Extracts
The freshly activated copper (0.5 g) was packed in a Pasteur pipette and 0.5 g sample
(SOM/crude oil) dissolved in 1 mL of n-hexane was introduced to the top of the column. The
free sulphur present in the sample chemically combined with copper forming CuS. The column
was washed with 3-bed volumes of n-hexane to extract sulphur free bitumen. The solvent was
carefully removed by heating on a sand bath to afford sulphur free crude oil and SOM.
3.2.3. Liquid Chromatography of Crude Oils and SOM
Small scale column chromatography
For small scale column chromatography, 2 mg of sample (SOM/crude oil) dissolved in
n-hexane (1 mL) was introduced from the top of a small column (5.5 x 0.5 cm, i.d.). This small
column was filled with activated silica. The aliphatic hydrocarbons (saturates) were eluted with
n-hexane (2 mL); the aromatics with a mixture of n-hexane and diethyl ether (2 mL, 50:50, n-
hexane: diethyl ether); NSO compounds with a mixture of dichloromethane and methanol (2 mL,
1:1) and asphaltenes with chloroform (2 mL).
Large scale column chromatography
For large scale chromatography, soluble organic matter (70 mg) and crude oil (100
mg) were used. A glass column (40 × 0.9 cm i.d.) with glass wool at bottom was rinsed with
methanol prior to use and then filled with activated silica (10 g). The SOM or crude oil was
54
introduced on the top of the column. The aliphatic hydrocarbons (saturates) were eluted with n-
hexane (40 mL); the aromatics with a mixture of n-hexane and diethyl ether (40 mL, 1:1, n-
hexane: diethyl ether); NSO compounds with a mixture of dichloromethane and methanol (40
mL, 1:1) and Asphaltenes with chloroform (40 mL) Each fraction was recovered by removal of
solvent on a sand bath by maintaining temperature up to maximum 50 °C.
3.2.4. Isolation of Branched and Cyclic Alkanes using 5A° molecular sieve
A saturated fraction obtained by liquid chromatography, was used to isolate branched
and cyclic alkanes from straight chain alkanes as suggested by Asif et al. 2010. The saturated
fraction (15 mg) in minimum volume of cyclohexane was added in to a 2 mL vial contain 1mL
cyclohexane and 2 g of activated 5A° molecular sieves. The vial was capped and placed into pre-
heated aluminum block (85 °C) for at least 8 hrs. The resulting mixture was filtered through a
small column of silica (5.5 × 0.5 cm, i.d.) and rinsed thoroughly with cyclohexane. The
cyclohexane containing branched/cyclic alkanes was collected in pre-weighed vial. The removal
of excess cyclohexane under a slow stream of nitrogen yielded branched and cyclic fraction.
3.3. ANALYTICAL TECHNIQUES
3.3.1. Total Organic Carbon (TOC wt %)
TOC values of source rock samples were determined using a Leco CR-12 carbon
determinator at Pakistan Petroleum Limited, Karachi. The crushed sample (100 mg) was treated
with 6N HCl acid bath to remove carbonates and bicarbonates. Then the sediments were dried
and combusted at 1200 °C in an O2 atmosphere. The amount of CO2 evolved was measured with
a Thermal Conductivity Detector.
3.3.2. Rock-Eval Pyrolysis
Acid treated samples were subjected to a Rock-Eval II (Delsi, Inc.) pyrolysis
according to method as described by Peters (1986) and Peters and Cassa (1994). Samples (100
mg) were pyrolyzed in a helium atmosphere at 300 °C for 4 mins, followed by programmed
pyrolysis at 25 °C/min from 300 to 550 °C. A flame ionization detector (FID) was used to
monitor the evolved hydrocarbons (Tissot and Welte, 1984). The first peak (S1) was obtained
from volatilization of free hydrocarbons during isothermal pyrolysis at 300 °C. The second peak
(S2) represents hydrocarbons generated by thermal cracking of kerogen during pyrolysis at 300
to 550 °C. The third peak (S3) represents the CO2 generated (mg) from one gram of rock during
55
pyrolysis and was analyzed using a thermal conductivity detector (TCD). The type and maturity
of OM in the source rocks was interpreted following Emeis and Kvenvolden (1986).
3.3.3. Geophysical Well Logs
Spontaneous Potential Log (SP Log) and Gamma Ray Log (GR Log)
Spontaneous potential and Gamma ray logs were provided by Pakistan Petroleum
Limited (PPL), Karachi. The SP and GR log were measured with the help of equipments
installed at the drilling site. A truck mounted with logging unit was placed in front of catwalk of
the rig. Then the logging tool i.e. Sonde was lowered down. The sonde was lowered to the
desired depth and data was collected while the sonde was pulled up.
In case of SP log sonde was connected with an electrode and that electrode was
connected to another electrode at the surface. The potential difference created due to different
anions and cations present in geological formation were measure and recorded in the form of a
graph.
In case of GR log, sonde is equipped with a device which only record total gamma ray
signals which were due to gamma ray emission due to different energy level from radioactive
elements. The signals of gamma ray were recorded using Geiger Muller counter.
3.3.4. Elemental and Stable Isotopic Analysis for Carbon and Nitrogen
After removing carbonates and bicarbonates by acid treatment, samples were analyzed
for elemental as well as stable isotopic analysis of carbon and nitrogen. Elemental analyzer
(Model PDZ Europa ANCA-GSL) interfaced with mass spectrometer (Model PDZ Europa 20-
20, Sercon Ltd., Cheshire, UK) was used for this purpose at UC-Davis facility, University of
California, USA.
Pre-weighted samples were placed inside tin capsules. Tin capsules were introduced in
combustion furnace having temperature of 1000 °C. Pure oxygen was supplied in the combustion
furnace which helped in oxide formation. Tin capsule produced a flash combustion which
increases the temperature upto 1700 °C. This increase in temperature further helped the
combustion process where Cr2O3 was used as combustion catalyst. The product of combustions
was in gaseous state, which was then swept in a helium stream. Then the resultant gases i.e. N2,
NOx, H2O, O2, and CO2 were then swept through a reduction stage of pure copper wires held at
600 °C. This removes any remaining oxygen and converts NOx gases to N2. Water vapours
(produced due to combustions) were removed by a magnesium perchlorate trap.
56
Packed column gas chromatograph was used to separate nitrogen and carbon dioxide
at an isothermal temperature. Ion source of IRMS sequentially ionized and accelerate these
chromatographic peaks produced by GC. Gas species of different mass were separated in a
magnetic field and simultaneously measured by a Faraday cup universal collector array.
Standards, similar to the samples being analyzed, were also combusted under same
conditions. These standards were previously calibrated against NIST Standard Reference
Materials (IAEA-N1, IAEA-N2, IAEA-N3, IAEA-CH7, and NBS-22). Every sample’s
preliminary isotope ratio was measured relative to reference gases analyzed with each sample.
Those preliminary values were finalized by adjusting the values for the entire batch based on the
known values of the included laboratory standards. The final delta values were expressed relative
to international standards PDB (PeeDee Belemnite) and Air for carbon and nitrogen,
respectively.
3.3.5. Gas Chromatography (GC-FID)
Gas chromatography (GC) analysis of the saturated fractions of crude oils/condensates
and SOM were carried out using (Shimadzu 14B series Gas Chromatograph, equipped with FID
and 30 m x 0.25 mm (i.d) film thickness 0.25 m fused silica capillary column, coated with
methyl silicone (OV-1). The sample (1 L of 10 mg/1 mL) was injected in splitless mode by
means of syringe through a rubber septum on to the column. Detector (FID) and injector
temperatures were kept at 250 °C and 290 °C, respectively. The oven temperature was
programmed from 60 °C to 290 °C at 4 °C/min. Nitrogen at a linear velocity of 2 mL/min was
used as carrier gas. The data was collected from retention time 0-70 minutes.
3.3.6. Gas Chromatography-Mass Spectrometry (GC-MS)
Full scan mode for compound identification
GC-MS analysis was performed using a Hewlett-Packard (HP) 5973 Mass Selective
Detector (MSD) interfaced to a HP 6890N gas chromatograph (GC). A 30 m × 0.25 mm ID
capillary column coated with a 0.25 µm 5% phenyl 95% methyl polysiloxane stationary phase
(DB-5 MS, J & W scientific) was used for the analysis. 1 µL of the saturated fraction (1 mg/mL
in n-hexane) was introduced into the split/splitless injector using the HP 6890N auto-sampler.
The injector was operated at 280 °C in pulsed splitless mode. Helium maintained at a constant
flow rate of 1.1 mL/min was used as carrier gas. The GC oven was programmed from 40 °C to
310 °C at 3 °C/min with initial and final hold times of 1 and 30 minutes, respectively. The
57
transfer line between the GC and the MSD was held at 310 °C. The MS source and quadrupole
temperatures were at 230 °C and 106 °C, respectively. Data was acquired in full scan mode from
50 to 550 a.m.u., with the MS ionization energy 70 eV and the electron multiplier voltage 1800
V.
Selected ion monitoring (SIM) mode for biomarkers
Aliphatic hydrocarbons, after sieving, were analyzed by GC-MS in selected ion
monitoring mode for better resolutions of compound classes. Similarly, to increase the resolution
between individual isomers of steranes and hopanes was obtained by running GC-MS in SIM
mode using 30 m × 0.25 mm ID capillary column coated with a 0.25 µm 5% phenyl 95% methyl
polysiloxane stationary phase (DB-5 MS, J & W scientific). In these analyses GC-MS conditions
were kept same as described in full scan mode except MSD was operated in SIM mode.
Selected ion monitoring (SIM) mode for diamondoids
Diamondoids analysis was carried out using a Hewlett-Packard (HP) 5973 Mass
Selective Detector (MSD) interfaced to a HP 6890N gas chromatograph (GC). A 30 m × 0.25
mm ID capillary column coated with a 0.25 µm 5% phenyl 95% methyl polysiloxane stationary
phase (DB-5 MS, J & W scientific) was used for the analysis. 1 µL of the saturated fraction (1
mg/mL in n-hexane) was introduced into the split/splitless injector using the HP 6890N auto-
sampler. The oven temperature was programmed to increase from 20 to 294 °C at a rate of 4
°C/min and was held at the final temperature for about 30mins. The mass spectrometer generated
positive ions by electron impact at 70 eV. The ion source was maintained at 200 °C. Ion
chromatograms were obtained by selective ion monitoring (SIM), using 20 masses and a 70ms
dwell time for each mass. The transfer line between the GC and the MSD was held at 294 °C.
The MS source and quadrupole temperatures were at 210 °C and 106 °C, respectively. Mass
spectra were obtained by scanning from 30 to 450µ at a rate of about 1.2 s per scan.
58
Chapter-4
INTERPRETATION OF PRODUCTIVE ZONES USING SPONTANEOUS POTENTIAL
(SP) LOG AND GAMMA RAY (GR) LOG
ABSTRACT
In this chapter, Spontaneous Potential (SP) and Gamma ray (GR) logs have been used for
identification of productive zones within the sedimentary sequences of Eocene (Chorgali and
Sakesar) and Paleocene (Patala) ages. The study encompasses samples from three wells D, E &
F. These formations mainly consist of limestone, sandstone and interbedded shale. The order of
permeability (reservoir property) from SP log was Chorgali > Sakesar > Patala. Shale contents
and organic matter i.e. source rock properties, increased with depth. Chorgali and Sakesar
showed permeable limestone with interbedded shale with some organic matter deposition. It was
shown to have reservoir properties. While Patala showed the presence of shale with interbedded
limestone and organic matter, it was shown to be source rock.
59
4.1. INTRODUCTION
The continuous recording of a geophysical parameter along a borehole produces a
geophysical well log. The value of the measurement is plotted continuously against depth in the
well. Various logs are used for different purposes e.g. SP log measures the difference in
electrical potential due to preferential diffusion and absorption of cations and anions in formation
fluid (Selley, 1985). Cations (small size) have high mobility than anions and creates charge
imbalance. The SP log is a measure of permeability. Limestones are low in permeability unless
they are porous or fractured. Sandstone usually shows a large deflection toward the negative pole
because of their permeability. If the sonde encounters a fluid that is a better conductor than the
drilling mud (such as salt water), the curve will deflect to the left and if the fluid is a poor
conductor (such as fresh water or oil), it will deflect to the right (Selley, 1985).
The gamma ray log is an extremely simple and useful technique that is used in all
petrophysical interpretations. The gamma ray log measures the total natural gamma radiation
emanating from a formation which originates from potassium-40 and the isotopes of the
Uranium, Radium and Thorium series. The gamma ray is measures by gamma ray tool i.e.
Geiger Muller counter. The total gamma ray log is expressed in API° scale goes from 0 to 200
API° but it is more common to see 0 to 100 API and 0 to 150 API° in log presentations. Organic
rich shales and volcanic ash show the highest gamma ray values, and halite, anhydrite, coal,
clean sandstones, dolomite and limestone have low gamma ray values (Selley, 1985). Care must
be taken not to generalize these rules too much.
4.2. INTERPRETATION OF PRODUCTIVE ZONES
In this chapter, SP and GR logs have been used for identification of productive zone
where productive zone is permeable and shale rich rocks within the study area.
4.2.1 Productive Zones Using Spontaneous Potential (SP) Log
Differences in salinity between the Formation water and the borehole fluid give rise to
spontaneous potential (SP). The SP log measures the spontaneous potential difference that exists
between the borehole fluid with conducting fluid electrode and a reference electrode at the
surface. SP response of shale and clay is same while opposite response is obtained for sandstone.
The difference of response is due to flow of ions i.e. sodium and chloride ions. Presence of these
natural occurring ions is related to permeability of the Formation (Selley, 1985). Deflection of
log from an arbitrarily determined shale base line indicates permeable and therefore porous
60
sandstones and carbonates. Deflection to left of the baseline is termed as normal or negative SP
and it is an indication of permeable sand and carbonates while deflection to right side of baseline
is reversed or positive SP (impermeable shale) while poor or absent SP deflection occurs in case
of uniformly impermeable Formation. In general, SP log is used to differentiate between
interbedded impermeable shale and permeable sandstone or carbonates (Selley, 1985).
Spontaneous potential (SP) log for Eocene (Chorgali and Sakesar) and Paleocene (Patala)
ages from wells D, E and F is shown in Figure-4.1 i. In Well-D, SP log response was normal in
the range of -68 to -54 mV on the left side of the baseline in linear manner showing occasional
fluctuations between -68 to -54 mV in Eocene Sakesar Formation and almost linear in Eocene
Chorgali and Paleocene Patala Formation as SP log was in the range of -61 to -57 mV and -65 to
-63 mV, respectively. This type of variations in SP response is associated with the permeability
of the Formation. More negative response means more permeability and less negative response
means less permeability (Selley, 1985). Permeability is the property of good reservoir rock.
More the permeability, good is the reservoir quality (Selley, 1985). So the SP response suggests
that the reservoir properties of Eocene Chorgali Formation are better than Eocene Sakesar
Formation which was in turn better than Paleocene Patala Formation.
The spontaneous potential (SP) log of three formation i.e. Chorgali and Sakesar (Eocene)
and Patala (Paleocene) from Well-E is shown in Figure-4.1 ii. SP log response at early depth of
Chorgali was between -60 to -55 mV showing good reservoir character but with increasing
depth, Chorgali gave a sudden increase in SP response and value shifted towards the base line
i.e. -40 mV. This sudden increase indicates the presence of some impermeable shale. The
presence of shale was also indicated by variation of SP log in Sakesar formation. The upper part
of Sakesar showed decreased SP response which increased with depth. Such a variation in SP
response indicated impermeable shale intervals although high overburden pressure contributes
compactness and decreases in permeability (Selley, 1985). The upper part of Paleocene Patala
formation showed impermeable formation (-5 mV) which continued till middle of formation
depth (-10 mV) while the lower part showed high negative response as compare to upper and
middle part i.e. -20 mV. This trend is different from SP log response of same formation in Well-
D which is due to the different burial depths. As Paleocene Patala Formation is considered as a
potential source rock in Potwar Basin so such behavior is not so much astonishing.
61
Table-4.1: Description of geological information and total organic carbon in sediment
samples taken from different wells under study.
Sediment
I.D.*
Upper Depth
(m)
Geological
Age
Formation Ray
Log
SP
Log
Well-D
S-1 3756 Eocene Chorgali 50 -61
S-2 3772 Eocene Chorgali 30 -57
S-3 3787 Eocene Chorgali 28 -60
S-4 3796 Eocene Chorgali 30 -58
S-5 3798 Eocene Chorgali 28 -59
S-6 3821 Eocene Sakesar 18 -63
S-7 3826 Eocene Sakesar 50 -68
S-8 3835 Eocene Sakesar 20 -60
S-9 3969 Eocene Sakesar 27 -54
S-10 4062 Paleocene Patala 30 -63
S-11 4065 Paleocene Patala 20 -63
S-12 4067 Paleocene Patala 18 -63
S-13 4069 Paleocene Patala 75 -65
Well-E
S-14 4655 Eocene Chorgali 38 -55
S-15 4662 Eocene Chorgali 35 -60
S-16 4672 Eocene Chorgali 25 -55
S-17 4685 Eocene Chorgali 37 -60
S-18 4688 Eocene Chorgali 42 -40
S-19 4697 Eocene Sakesar 38 -50
S-20 4704 Eocene Sakesar 15 -52
S-21 4716 Eocene Sakesar 40 -62
S-22 4720 Eocene Sakesar 20 -40
S-23 4728 Eocene Sakesar 30 -73
S-24 4820 Paleocene Patala 20 -5
S-25 4828 Paleocene Patala 30 -10
S-26 4860 Paleocene Patala 40 -22
S-27 4884 Paleocene Patala 67 -20
Well-F
S-34 4029 Eocene Chorgali 40 -25
S-35 4033 Eocene Chorgali 35 -28
S-36 4041 Eocene Chorgali 38 -25
S-37 4046 Eocene Chorgali 40 -23
62
Sediment
I.D.*
Upper Depth
(m)
Geological
Age
Formation Ray
Log
SP
Log
S-38 4070 Eocene Sakesar 23 -35
S-39 4073 Eocene Sakesar 20 -28
S-40 4123 Eocene Sakesar 26 -35
S-41 4130 Eocene Sakesar 50 -34
S-42 4168 Paleocene Patala 25 -32
S-43 4173 Paleocene Patala 26 -23
*Sediments numbering is same used in chapter-6 & 7. Few sediments are missing as data is not
available
In Well-F, upper portion of Eocene Chorgali Formation showed almost a linear SP
response i.e. from -28 to -23 mV (Figure-4.1, iii). This behavior of Chorgali formation in Well-F
is different from same formation in wells D & E where this formation showed high negative
response. Perhaps this is due to the compactness of the Chorgali formation in Well-F. Sakesar
Formation has SP log value from -35 to -28 mV which is also a different trend than the SP log
values in wells D & E. Paleocene Patala Formation also showed SP log values within -32 to -23
mV which is similar to SP log response of same formation in Well-E but differs from Well-D.
49
20
20
Ch
org
ali
Sakesar
Pata
la
4650
4700
4750
4800
4850
-80
-60
-40
-20
0
ii
Ch
org
ali
Sakesar
Pata
la
4025
4045
4065
4085
4105
4125
4145
4165
-80
-60
-40
-20
020
iii
3750
3800
3850
3900
3950
4000
4050
-80
-60
-40
-20
0
i
Ch
org
ali
Sakesar
Pata
la
Well-D
Well-E
Well-F
Fig
ure
-4.1
: R
esp
on
se o
f S
P l
og
wit
h d
epth
fo
r C
ho
rga
li, S
ak
esa
r a
nd
Pa
tala
fo
rma
tio
ns
wit
hin
i)
Wel
l-D
, ii
) W
ell-
E
a
nd
iii
) W
ell-
F. R
efer
to
Fig
ure
-2.1
fo
r li
tho
log
y o
f fo
rmati
on
s
49
4.2.2. Identification of Lithology from Gamma Ray (GR) Log
Three types of logs that measure radioactivity are commonly used for formation
evaluation in oil or gas well drilling i.e. gamma ray log, neutron log and density log. The gamma
ray log uses a scintillatation counter to measure the natural radioactivity of Formation as the
sonde is drawn up the borehole. The main radioactive element in the rocks is potassium (K-40)
which is commonly found in illitic clay and to a lesser extent in feldspars, mica and glauconite.
Organic matter commonly scavenges uranium and thorium and thus oil source rock, oil shale,
sapropetlites and algal coals are radioactive. The gamma ray is measured in APIº units and
generally plotted on the scale of 0-100 or 0-120 APIº (Selley, 1985). Conventionally, the natural
gamma ray log reading is presented on the left hand column of the log in a manner similar to S.P.
log. A shale baseline is drawn and deflection from base line gives idea about rocks. Deflection to
left from baseline means clean lithology i.e. sandstone or carbonates. In general, limestone and
sandstones have a range of 0-75 APIº while organic shale and oil have a range of 50-120 APIº
and 110-200 APIº, respectively. So with the help of gamma ray log formation can be evaluated
(Selley, 1985).
In Well-D, Chorgali and Sakesar (Eocene) and Patala (Paleocene) were evaluated by
gamma ray log (Figure-4.2, i). The values of GR log for Chorgali Formation was in the range of
28-50 API° which is a typical value for Limestone and sandstone lithology (Selley, 1985). At the
start of Formation GR values was high i.e. 50 API° which was due to the presence of organic
shale (Selley, 1985). With increase in burial depth the GR values decreased which indicate
interbedded shale with limestone formation. Sakesar formation showed gamma ray response
from 18-50 API° (Table-4.1). the lower and upper part of formation have low API° values but
the middle part of formation showed high GR value i.e. 50 API° due to interbedded shale. Patala
formation being a potential source rock of Potwar Basin showed high value of gamma ray
response i.e. upto 75 API°. Such high value indicates shale having organic matter and oil
expulsion tendency is typical of potential source rock which Patala formation exhibits.
In Well-E, Eocene (Chorgali and Sakesar) and Paleocene (Patala) were analyzed by
gamma ray (Figure-4.2, ii). With increase in burial depth, a gradual decrease in gamma ray
response was observed in Chorgali formation (Table-4.1). The decrease continued till the lower
part of formation where GR log value increased upto 42 API° which indicates the presence of
interbedded shale content.
49
37
50
38
00
38
50
39
00
39
50
40
00
40
50
02
55
07
51
00
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49
Sakesar formation showed gamma ray response in a range of 15 to 40 API°. At the start of
formation depth, response decreased to its minimum value i.e. 15 API°, a clear indication of
presence of limestone and sandstone (Selley, 1985). At the middle of formation GR log reached
upto 40 API° which indicated the presence of organic shale (Selley, 1985). Patala formation
again showed behavior of a potential source rock. GR log response of Patala formation was in a
range of 20 to 67 API°. The GR log values continuously increased throughout formation depth
indicated the presence of organic shale with increasing burial depth in Patala formation. Such
response supported the concept of Patala formation as a potential source rock of the study area.
In Well-F, Chorgali and Sakesar (Eocene) and Patala (Paleocene) were analyzed by
gamma ray (Figure-4.2, iii). Chorgali formation showed almost a linear response having GR
values between 35-40 API°. These values indicated the presence of both shale and limestone but
shale was not a source rock rather act as reservoir rock. Sakesar formation also showed nearly
linear response except at the end of formation where GR log value reached upto 50 API°. This
behavior is similar to upper laying Chorgali formation indicated the presence of interbedded
shale with limestone. Patala formation showed GR log values (25-26 API°) which indicated the
presence of limestone.
4.3. CONCLUSIONS
Geophysical well logs showed the presence of limestone, sandstone and interbedded
shale in geological formations of study area. Permeability decreased with depth in order of
Chorgali > Sakesar > Patala while reverse order was observed for source rock property i.e. shale
contents and organic matter was maximum for Patala and minimum for Chorgali. Reservoir
characteristics of Chorgali formation were most and least for Patala formation.
50
SOURCE ROCK POTENTIAL OF EOCENE, PALEOCENE AND JURASSIC
DEPOSITS IN THE SUBSURFACE OF THE POTWAR BASIN, NORTHERN
PAKISTAN
ABSTRACT
The hydrocarbon source rock potential of five formations in the Potwar Basin of northern
Pakistan, the Sakesar Formation (Eocene); the Patala, Lockhart and Dhak-Pass Formations
(Paleocene); and the Datta Formation (Jurassic) was investigated using Rock-Eval pyrolysis and
total organic carbon (TOC) measurement. Samples were obtained from three producing wells
referred to as Well-A, Well-B and Well-C. In Well-A, the upper ca. 100 m of the Eocene Sakesar
Formation contained abundant Type III gas-prone organic matter (OM) and the interval appeared
to be within the hydrocarbon generation window. The underlying part of the Sakesar Formation
contained mostly weathered and immature OM with little hydrocarbon potential. The Sakesar
Formation passes down into the Paleocene Patala Formation. Tmax was variable because of facies
variations which were also reflected in variations in hydrogen index (HI), TOC and S2/S3
values. In Well-A, the middle portion of the Patala Formation had sufficient maturity (Tmax 430
to 444°C) and organic richness to act as a minor source for gas. The underlying Lockhart
Formation in general contained little OM, although basal sediments showed a major contribution
of Type II/III OM and were sufficiently mature for hydrocarbon generation.
In Well-B, rocks in the upper 120 m of the Paleocene Patala Formation contained little
OM. However, some Type II/III OM was present at the base of the formation, although these
sediments were not sufficiently mature for oil generation. The Dhak Pass Formation was in
general thermally immature and contained minor amounts of gas-prone OM.
In Well-C, the Jurassic Datta Formation contained oil-prone OM. Tmax data indicated that
the formation was marginally mature despite sample depths of > 5000 m. The lack of increase in
Tmax with depth was attributed to low heat flows during burial. However, burial to depths of
more than 5000 m resulted in the generation of moderate quantities of oil from this formation.
51
5.1. INTRODUCTION
Previous studies of the Potwar Basin in northern Pakistan have identified a number of
potential source rocks including the Precambrian Salt Range; the Permian Dandot, Sardhai and
Chhidru Formations; and the Paleocene Lockhart and Patala Formations (Quadri and Quadri,
1996; Raza et al., 1995). TOC contents range from 0.5 to > 3.5 %. Oil and gas is believed to have
been produced from source rocks with Types II and III kerogen (OGDC, 1996; Shah et al., 1977;
Wandrey et al., 2004). Thermal maturity ranges from vitrinite reflectance (VRr) 0.65 to 0.95%
for the Permian, 0.5 to 0.9% for the Jurassic and 0.6 to 1.1% for the Cretaceous; dry gas
generation begins near 1.3% VRr (Jaswal et al., 1997; Tobin and Claxton, 2000).
Structural traps in the Potwar Basin include faulted anticlines, pop-up structures and fault
blocks Reservoirs include sandstones of Cambrian, Permian and Jurassic ages, and fractured
carbonates of Paleocene and early Eocene ages, the Miocene Muree Formation being the
youngest oil-producing unit. About 60% of producing reservoirs are carbonates. The Paleocene
Dhak-Pass Formation has been recognized as a potential reservoir rock in wells in the central
basin (Wandrey et al., 2004).
The objective of this study was to characterize potential source rocks of Eocene,
Paleocene and Jurassic ages in the Potwar Basin using Rock-Eval pyrolysis and TOC
measurements.
5.2. BACKGROUND GEOLOGY
The Potwar Basin is located on a portion of the Indian Plate which was structurally
deformed during the Indo-Eurasian collision and by the overthrust of the Himalayas to the north
and NW. Overthrusting has resulted in intense deformation and the juxtaposition of strata of
widely varying ages (e.g. Precambrian and Tertiary) in close proximity. Precambrian rocks are
exposed in the Salt Range at the southern margin of the basin. Before the onset of plate collision
in the Eocene, the Precambrian interval was not buried sufficiently deeply for OM maturation to
occur and much of the Precambrian to Paleocene succession has remained thermally immature to
the present day (Grelaud et al., 2002; Khan et al., 1986). However, in local areas, abnormally
high formation pressures resulting from regional compression and compaction disequilibrium,
together with deep burial by overburden rocks, have led to the generation and expulsion of
hydrocarbons from pre-Eocene source rocks (Grelaud et al., 2002; Law and Spencer, 1998).
52
Fig. 1. General location map of the Potwar Basin, northern Pakistan, showing major
structural elements and locations of Wells A, B and C referred to in this paper.
5.3. DEPOSITIONAL HISTORY
The sedimentary succession in the Potwar Basin ranges in age from Precambrian to
Recent (Fig. 2). Three major unconformities are present (Ordovician-Carboniferous, Late
Permian–Mesozoic and Oligocene). The Precambrian Salt Range Formation is composed of a
clastic-dominated lower section, a carbonate-dominated middle section and a halitedominated
upper section in which potential source beds have been identified (Iqbal and Shah, 1980; Shah et
al., 1977). The evaporite sequence is overlain by Cambrian sandstones and shales (Khewra
Formation) and sandstones, siltstones and carbonates of the Kussak, Jutana and Baghanwala
Formations. Lower Permian strata are restricted to the eastern Potwar Basin and include the
Tobra Formation, deposited in glacial conditions, overlain by the sandstones and claystones of
the Dandot, Warcha and Sardhai Formations. Late Permian marine sediments of the Wargal and
Chhidru Formations include shales, limestone and sandstones, and are restricted to the western
and north-central parts of the Potwar Basin. These sediments may have sufficiently high TOC
values to have source rock potential (Quadri and Quadri, 1996). Jurassic and Triassic strata are
poorly developed or absent in the Potwar Basin. The Datta Formation (Jurassic) is mainly of
continental origin and is composed of shales and non-marine sandstones with paralic intervals. It
has both reservoir and source rock potential. Shallow-marine foraminiferal limestones and dark
53
Fig. 2. Stratigraphic column for the Potwar Basin. #: source rocks; * reservoir rocks
(OGDC, 1996; Wandrey et al., 2004).
54
grey shales were deposited during the Paleocene to Eocene. The Paleocene section includes (i)
the Hangu/Dhak Pass Formation which is dominated by sandstones with minor carbonaceous
shales, coals and limestones; (ii) the Lockhart Limestone; and (iii) the Patala Formation,
composed of dark-grey fossiliferous shales and limestones. In the eastern Potwar Basin, the
upper part of the formation includes coal beds. The calcareous claystones of the overlying
Nammal Formation mark the beginning of the lower Eocene, and are followed by the massive
limestones of the Sakesar Formation, overlain by dolomitic limestones and calcareous claystones
of the Chorgali Formation. Marine deposition in the area ended as a result of continental
collision in the middle Eocene. Post-Eocene units include alluvial deltaic sediments of the
Siwalik Group (Nagri and Chinji Formations) and the fluvial and fluvio-deltaic deposits of the
Rawalpindi Group (Kamlial, Murree and Kohat Formations). These non-marine units represent
the erosional products of southward-advancing Himalayan thrust sheets (Pennock et al., 1989).
5.4. PETROLEUM SYSTEM
Previous studies have recognized several different petroleum systems in the Potwar
Basin, but they have been combined into a single composite Eocambrian-Miocene TPS (the
Patala-Nammal TPS) owing to the scarcity of available information and analyses (Wandrey et
al., 2004). Stacked source and reservoir intervals and extensive fault systems have led to mixing
of hydrocarbons from multiple sources Potential source rocks have been identified in
Precambrian, Permian, Paleocene and Eocene successions, but the Paleocene Patala Formation
(20- 180 m thick) appears to be the primary source of most of the oils (Quadri and Quadri, 1996;
Raza et al., 1995).
The average TOC of the Patala Formation is 1.4 %, and kerogen is Type II and III. An
exception to this is at Dhurnal field, where the Patala has a low TOC, whereas the Permian
Wargal and Paleocene Lockhart Formations have TOC values of 1.0 % and 1.4 %, respectively
(Jaswal et al., 1997). In addition, oil samples from the Dhurnal, Pindori, Bhangali and Adhi
oilfields have sulphur contents less than 0.2%, different from oils known to be sourced from the
Patala, indicating the presence of other petroleum systems in the basin (Khan et al., 1986). In the
productive part of the Potwar Basin, thermal maturities equivalent to vitrinite reflectance (VRr)
range from 0.62 to 1.0 % for Tertiary rocks, 0.6 to 1.6 % for the Cretaceous, 0.5 to 0.9 % for the
Jurassic and 0.65 to 0.95 % for the Permian (Tobin and Claxton, 2000). Oil or gas has been
produced from the following formations: Cambrian-Kherwa, Kussak and Jutana; Permian-Tobra,
55
Amb and Wargal; Jurassic-Datta; Paleocene-Lockhart, Patala and Nammal; Eocene-Bhadrar,
Chorgali and Margala Hill; and Miocene-Murree (Khan et al., 1986). Average reservoir
porosities are 12-16 % and permeability ranges from 4 to 17 mD (Jaswal et al., 1997; Khan et al.,
1986). Generation of hydrocarbons most likely began in the Late Cretaceous for Cambrian
through Lower Cretaceous source rocks, and from the Pliocene onwards for younger source
rocks (OGDC, 1996). Although there are probably two distinct periods of hydrocarbon
generation for the two different groups of source rocks, sufficient source correlation data are not
available to define separate petroleum systems. Migration is primarily over short distances updip
and vertically into adjacent reservoir units through faults and fractures. Seals include fault
truncations, interbedded shales and the thick shales and clays of the Miocene and Pliocene
Siwalik Group (Jaswal et al., 1997).
5.5. MATERIALS AND METHODS
A total of 71 core samples of Eocene, Paleocene and Jurassic rocks were obtained at 10
to 15 m intervals from three wells (A, B and C) in the Potwar Basin (Fig. 1). Details of each
sample are provided in Appendix 1. These sedimentary units have not been studied formally
before. Samples were washed thoroughly with water, air dried, crushed, and passed through an
80 mm mesh sieve. Crushed samples were then subjected to TOC combustion and Rock-Eval
pyrolysis using a Rock-Eval II (Delsi, Inc.) apparatus following Peters (1986) and Peters and
Cassa (1994). Samples (100 mg) were pyrolyzed in a helium atmosphere at 300°C for 4 min,
followed by programmed pyrolysis at 25°C/min from 300 to 550°C. A flame ionization detector
(FID) was used to monitor the evolved hydrocarbons (Tissot and Welte, 1984). The first peak
(S1) was obtained from volatilization of free hydrocarbons during isothermal pyrolysis at 300°C.
The second peak (S2) represents hydrocarbons generated by thermal cracking of kerogen during
pyrolysis at 300 to 550°C. The third peak (S3) represents the CO2 generated (mg) from one gram
of rock during pyrolysis and was analyzed using a thermal conductivity detector (TCD). The
type and maturity of OM in the source rocks was interpreted following Emeis and Kvenvolden
(1986).
TOC values of source rock samples were determined using a Leco CR-12 carbon
determinator at the Hydrocarbon Development Institute of Pakistan (Islamabad). The crushed
sample (100 mg) was treated with 6N HCl to remove carbonate and combusted at 1200°C in an
O2 atmosphere. The amount of CO2 evolved was measured with a TCD.
56
5.6. RESULTS AND DISCUSSION
The source rock potential of the Eocene Sakesar Formation, the Paleocene Patala,
Lockhart and Dhak Pass Formations, and the Jurassic Datta Formation at wells A, B and C was
assessed. Other formations penetrated by these wells were not analyzed because samples were
not available.
5.6.1. Well-A
(i) The Eocene Sakesar Formation
The upper 100 m of the formation contained abundant TOC, up to 13 wt %. S1 and S2
were 0.5-4 and 1.5-36 mg HC/g rock, respectively (Figs. 3a i-iii). Deeper sediments were
comparatively organic-lean as suggested by TOC (1-3 wt %) and S1 and S2 of <0.5 and 2-6 mg
HC/g rock, respectively. The nature of the OM was assessed using a plot of OI versus HI
(Bordenave, 1993; Tissot and Welte, 1984) (Fig. 4). Most samples from the Sakesar Formation
had HI values in the range 100 to 200 mg HC/g TOC and low OI values (Figs. 3a vi, vii)
indicating Type III kerogen as the main component of the OM (Table-1). The S2/S3 ratios were
> 5 for most of the samples, supporting the presence of Type III gas-prone OM. A number of
previous studies have identified the Paleocene Patala Shale as the primary source rock for
hydrocarbons in the Potwar Basin (Aamir and Siddiqui, 2006; Khan et al., 1986; Raza et al.,
1995). Based on comparatively high TOC and HI values as well as maturity indicators, this study
suggests that marine limestones in the Sakesar Formation may also include source rock intervals.
The level of thermal maturity was evaluated from a plot of Tmax versus depth (Fig. 3a v). Tmax
values were comparatively high for the upper 100 m of the Sakesar Formation, mostly falling
within a narrow range (440-448 °C), with the exception of one sample with Tmax 430°C,
indicating a similar general level of maturation. Deeper sediments, which contained smaller
quantities of OM, had variable thermal maturities. Anomalies in maturity and relative abundance
of OM can be due to unconformities or other local variations (Peters, 1986), but the observed
variations in organic richness and Tmax in the Sakesar Formation were attributed to facies
changes. A plot of production index (PI) versus depth showed values from 0.1 to 0.3 and Tmax
from 440 to 448 °C for the top 100 m of the formation, and PI < 0.1 and Tmax < 435°C for the
underlying sediments (Figs. 3a v, viii). The PI and Tmax versus depth trends suggest that the top
of the Sakesar Formation is mature and at the onset of hydrocarbon generation, while lack of
increase in Tmax
57
Fig. 3. Geochemical logs based on Rock-Eval / TOC parameters for Eocene,
Paleocene and Jurassic sediments from wells A, B and C in the Potwar Basin.
58
and PI with depth for the underlying section is attributed to a facies change. The presence of inert
kerogen was indicated on a plot of TOC versus S2 (Fig. 5), based on the assumption that only
labile kerogen generates hydrocarbons recorded in the Rock-Eval S2 peak; thus, the intercept
where S2 = 0 indicates inert carbon. The minimum value of S2 for the Sakesar Formation was
1.57 g HC/g rock; the TOC and HI for this sample were 1.2 wt % and 131 mg HC/g TOC,
respectively, suggesting the presence of gas-prone OM (based on Tmax = 444 °C). Other studies
have interpreted the presence of inert kerogen on the basis of a plot of TOC versus S2 (Dahl et
al., 2004). However, this plot (Fig. 5) did not suggest that the Sakesar Formation contained
significant amounts of inert kerogen. The possibility that migrated hydrocarbons were present
was assessed from the S1/TOC ratio, where values of 0.1 to 0.2 indicate oil expulsion and those
> 1 are characteristic of migrated hydrocarbons (Smith and Perez-Arlucea, 1994). The highest
value for the Sakesar Formation was 0.7 with other samples at < 0.3 (Fig. 3a x).
Fig. 4. Plot of HI versus OI, showing type of OM in Eocene, Paleocene and Jurassic samples
Moreover, the S2/S3 ratio was < 1 for the above sample which indicated the presence of
reworked OM (Fig. 3a ix). Hence, the presence of migrated and inert hydrocarbons
cannot be ruled out. Based on its organic richness and thermal maturity, the Sakesar
Formation is within the zone of hydrocarbon formation, and most likely contains gas
prone OM. Comparatively lower values of TOC and Tmax for the underlying sediments
(2550-2625 m) were related to facies change. The extremely high S3 and OI peaks
indicated the presence of resedimented organic matter or Type III kerogen.
Fig. 5. Plot of TOC versus S2. The expanded section indicates the presence of
inertinite in samples from the Patala and Dhak Pass Formations; however,
other samples show very good to excellent potential
(ii) The Paleocene Patala Formation
Some 45 m of the Patala Formation were penetrated by Well A. Only the middle
portion of the formation (depth 2650 m) showed significant source rock potential in terms
of TOC (10 wt %), S1 and S2 (3 and 19 mg HC/g rock, respectively) and thermal
maturity (Tmax up to 444°C) (Figs. 3a i-iii, v). OM in these sediments was predominantly
gas-prone as shown by a plot of OI versus HI (Figure-4), and HI values in the range 100
to 200 mg HC/g TOC (Fig. 3a vi). The depth profiles of S3 and OI (Figs. 3a iv, vii) and
comparison of S1 and TOC suggested no significant contribution of migrated or
resedimented OM to the TOC. Although Tmax of the Patala Formation was in the range of
maturation and expulsion (430-444°C), the formation may act as a minor source of gas in
Well A.
(iii) The Paleocene Lockhart Formation
Geochemical logs showed that almost 80% of Lockhart Formation samples were
low in OM (Figs. 3a i-iii). The lower section of the formation (2750-2800 m) contained
considerable amounts of inert kerogen, as reflected in the unusually high OI response
(330 mg CO2/g TOC) and in S2/S3 <1 (Figs. 3a vii, ix). A plot of S2 versus TOC also
indicated the presence of inert kerogen (Fig. 5). Some marginally mature sediments
containing Type II/III OM were present in the lower section of the Lockhart Formation,
as reflected by HI values > 250 mg HC/g TOC and the position of samples on the HI
versus OI diagram (Figs. 3a vi, & 4). These sediments are currently in the marginally
mature zone; with adequate maturity, they may have the potential to generate oil and gas.
5.6.2. Well-B
(i) The Paleocene Patala Formation
The majority of samples in the upper 120 m of the Patala Formation were low in
OM (TOC 1-2 wt %). S1 and S2 plots indicated little potential in terms of both generated
and residual hydrocarbons (S1 0.1- 0.5 and S2 1-2 mg HC/g rock) (Figs. 3b ii-iii). This
portion of the formation had no potential for either liquid or gaseous hydrocarbons
Organic-rich sediments were present within the interval 2960 to 3050 m as reflected in
TOC values of 2 to 8 wt %. These samples showed relatively high S2 and S2/S3 values
(1.5-20 mg HC/g rock and 1.5-15; Figs. 3b i, iii-ix). This part of the formation appeared
to have a mixed OM content, as reflected in HI of < 150 to 300 mg HC/g TOC with
minor oil and gas potential. Most of the samples from the Patala Formation plotted in the
Type III region on the plot of HI versus OI. A few samples had HI values >250 mg HC/g
TOC, which indicated some contribution from Type II/III OM.
Although the potential of the Patala Formation as a source rock has been
recognized in previous studies (Jaswal et al., 1997; Khan et al., 1986; Raza et al., 1995;
Tobin and Claxton, 2000; Wandrey et al., 2004), most of the samples analyzed in this
study had low OM content and low thermal maturity (Figs. 3b i-iii, v), with Tmax less than
430°C. Analysis of the 210 m sequence of the Patala Formation from Well B suggested
that the OM was not adequate for an effective source rock. Sediments within the interval
2960 to 3050 m contained marginal amounts of gas prone OM.
(ii) The Paleocene Dhak Pass Formation
Samples of the Dhak Pass Formation generally contained little OM, although
TOC (up to 6 wt %) was higher than expected. However, S1 and S2 suggested little
potential in terms of both generated and residual hydrocarbons (S1 0.1-0.5 and S2 1-2 mg
HC/g rock), and HI was < 100 mg HC/g TOC. Tmax did not increase with depth and
values ranged between 380 and 439°C (Fig. 3b v). Over 90% of the samples had not
reached a Tmax of 430°C, indicating that the OM from this formation was immature or
early mature. On a plot of OI versus HI, most of the samples plotted in the field of Type
III kerogen, with a few samples plotting as Type II/III. Because of the low S1 and S2
values, meaningful results could not be obtained from HI and PI plots (Figs. 3b vi, viii)
The deeper sediments may have minor hydrocarbon potential, as shown by S3
values of 2 to 5 mg CO2/g rock as well as an HI < 150 mg HC/g TOC. In summary,
samples of the Dhak-Pass Formation lacked both the quantity of OM and thermal
maturity required for hydrocarbon generation.
5.6.3. Well-C
(i) The Jurassic Datta Formation
Samples of the Jurassic Datta Formation contained substantial amounts of OM
(TOC 1-7.5 wt%; Figs. 3c i). Rock-Eval data included an S1 of 0.5 to 5, and an S2 of 4 to
33 mg HC/g rock (Figs. 3c ii-iii). The possibility of migrated or inert hydrocarbons was
minor, on the grounds described above for the Paleocene sediments (Fig. 5). HI values
>350 mg HC/g TOC further indicated that most of the samples from this formation were
free from inert OM (Fig. 3c vi). The total genetic potential (GP) of the Datta Formation
showed good potential for hydrocarbon generation (average S1+S2 of 10). On an HI
versus OI plot, the Datta Formation samples appeared to contain Type II oil-prone OM
(HI 250 to 500 mg HC/g TOC; Figs. 3c vi & 4). About 60% of the samples showed HI
values in the range 340 to 500 mg HC/g TOC; however, 40% of the samples had
comparatively low HI values in the range 250 to 290 mg HC/g TOC and plot in the Type
II/III area of the diagram, indicating some contribution from mixed OM. Tmax values were
in the range 424 to 436°C. The average Tmax of 430°C indicated marginally mature OM
(Fig. 3c v; Table 1). The Jurassic Datta Formation had probably experienced insufficient
temperatures for maturation of OM to occur at these depths. The PI (0.1-0.2) indicated
that the sediments were at the beginning of the oil window (Fig. 3c viii). A rise in Tmax
with depth was not observed for the sediments analyzed. On the basis of Tmax, the
samples were in the range of marginally mature OM, despite a depth of >5000 m. The
lack of an increase of Tmax with depth is attributed to the Datta Formation sediments
experiencing low heat flows and to convective cooling by meteoric waters, and also to
the variability in kerogen type. However, burial to more than 5000 m was sufficient for
the formation to have generated a moderate quantity of oil. The potential occurrence of
inert kerogen, determined from the TOC versus S2 plot (Fig. 5), in both Paleocene and
Jurassic sediments was minor. The Datta Formation mainly contained Type II oil-prone
OM. The catagenic product from the Datta Formation, based on the plot of HI versus OI
and other results, was oil (Figs. 3c vi, ix & 4).
5.7. CONCLUSIONS
Analysis of 71 samples of Eocene, Paleocene and Jurassic ages from three wells
in the Potwar Basin, northern Pakistan, allowed the following conclusions to be drawn:
In Well-A, the upper ca. 100 m interval of the Eocene Sakesar Formation
contained thermally mature (Tmax 440-448°C), Type III OM. The Paleocene
Patala Formation encountered in Well A is about 45 m thick. Its middle portion
has adequate maturity and organic richness to act as a minor source of gas. In
Well-B, the upper 120 m of the Patala Formation has poor source rock potential;
although some marginal sediments containing Type II/III OM are present at the
base of the formation, they are not mature enough for hydrocarbon generation.
Most of the Lockhart Formation sediments are organic lean and thermally early
mature in terms of hydrocarbon generation.
Samples of the Dhak Pass Formation from Well-B have poor source rock
potential, and lacked the quantity and quality of organic matter and the thermal
maturity necessary for hydrocarbon generation.
Samples of the Jurassic Datta Formation from Well-C contained Type II OM with
minor Type II/III OM.
Chapter-6
STABLE CARBON AND NITROGEN ISOTOPES: SOURCE AND
DEPOSITIONAL ENVIRONMENT INTERPRETATION OF POTWAR BASIN,
PAKISTAN
ABSTRACT
In this study we have used stable carbon and nitrogen isotopes along with
composition of elemental carbon & nitrogen and TOC to evaluate the source and
paleoenvironment of OM and relative contribution of marine and terrigenous OM in
sediments. The study was conducted on selected samples from four geological
formations: Chorgali, Sakesar (Eocene), Patala (Paleocene) and Sardhai (Early Permian)
collected from wells D, E and F in the northern Potwar Basin. High values TCC and
extremely low TNC reflect an enhanced amount of terrestrial OM in these sediments.
Low values of Pr/Ph (<1) and diasteranes/steranes (~ 0.2; chapter 7) and high TOC
suggest anoxic environments and marine carbonate depositional setting for OM. Carbon
isotope ratios of OM generally range from –25.8 to –24.2‰ with lower values occurring
in the some samples of Sakesar formation. The values are 2.8‰ greater than 27‰, the
mean value of C3 plants and suggest that OM was derived from C3 plants with significant
input from land plants and marine planktons. The plot of C/N vs. 13
C demonstrates that
OM in Chorgali and Sakesar samples is from a similar source such as vascular C3 plant as
primary producers. The trend toward low C/N values within the Chorgali and Sakesar
formations is associated with inclusion of marine planktonic OM into the source.
Similarly low C/N values (< 20) observed for Patala and Sardhai samples imply
significant carbon input from marine planktons in mixed OM.
15N data show two trends, low values in the range of 2.3 to 3.8‰ observed for
Chorgali, Sakesar and some Patala sediments indicate mixed land plant and marine
planktonic OM, while slightly higher values 3.1 to 5.9‰ for Sardhai and Patala (Well-F)
Formations illustrate that mixed OM in these sediments contains higher planktonic input.
The15
N versus 13
C diagram demonstrates the nature and origin of OM. It is likely to be
composed of land plants mainly derived from C3 plants having variable proportions of
marine planktonic input.
Key words: Sediments, C3 plants, OM, C/N ratio, 13
C,15
N, Potwar Basin.
6.1. INTRODUCTION
Stable carbon and nitrogen isotopes (13
C and 15
N) and their elemental ratios
(C/N) are powerful proxies to identify the contribution and fate of organic matter (OM) in
sediments. It can also show the mixing trend between terrestrial and aquatic source of
OM (Huon et al., 2002; Meyers, 1997; Müller, 1977; Muzuka and Hillaire-Marcel, 1999;
Ohkouchi et al., 1997). The 13C and 15N are measured relative to Vienna Pee Dee
Belemnite (PDB) and N2-Air respectively. A classic example of the use of bulk carbon
isotopes is the work of Kvenvolden et al. (1995). Tar ball residues from the beaches of
Prince William Sound were collected several years after the Exxon Valdez accident and
characterized on the basis of bulk carbon isotope ratios (Kvenvolden et al., 1995). Based
on the bulk isotope values, two distinct sources were identified; one resembled closely to
the Exxon Valdez oil with 13
C around 29‰, while second group was isotopic ally
heavier with values close to 24‰. Based on these values and biomarker data, it was
concluded that origin of tar balls is from Californian crude oils derived from the
Monterey Formation.
The carbon isotopic composition varies with the source of OM, depositional
environment and photosynthetic pathway. Terrestrial plants follow C3 and C4 pathway for
photosynthesis. C3 plants fix CO2 to 3 carbon compound (glyceraldehyde-3-phosphate) as
an intermediate for glycolysis, analogously C4 plants fix CO2 to oxaloacetate (4 carbon
compound). Figure-6.1 shows variations in 13
C of some terrestrial plants. The 13
C
values of the OM vary from 35‰ to 22‰ in C3 plants and from 16‰ to 10‰ in
C4 plants. Terrestrial plants acquire their carbon from atmospheric CO2 (13
C 7‰),
while carbon source of aquatic plants like marine algae is from dissolved bicarbonate
(13
C 0) (Philp, 2007). The majority of recent plants use the C3 pathway (Reinfelder et
al., 2000). Warmer and more arid climates favor C4 plants (like maize, sorghum, and
sugarcane etc.; isotopically heavy), while C3 plants are generally associated with cooler
and wetter climates and have low isotopic values. The OM from marine source is
isotopically heavier than the terrestrial plants; e.g., marine algae generally have 13
C
value of about 20‰, it acquires carbon from dissolved bicarbonate (13
C 0). The 13
C
values for terrestrial OM in the Cretaceous is about –27‰. However there is often an
overlap between the 13
C values of marine and terrestrial sediments (Figure-6.1),
therefore, carbon isotope ratios should be evaluated in conjunction with C/N ratios, which
acts as an indicator to determine the predominant sources of organic matter (Andrews et
al., 1998; Graham et al., 2001; Matson and Brinson, 1990; Thornton and McManus,
1994). This is because terrestrial plants have cellulose and lignin as a key structural
component, which is absent in algae. As a result, terrestrial plants show C/N ratio 20 or
greater while algae being protein rich have low C/N ratios between 4 and 10 (Ertel and
Hedges, 1985; Meyers, 1994, 1997). High C/N ratios are associated with high values of
15N and low
13C because of diagenesis and mineralization (Wu et al., 2002).
Figure-6.1: The variations in 13
C of some terrestrial plants.
Stable nitrogen isotopes have little been used in the exploration study due to
minor quantity of organic nitrogen, usually of the order of 0.1‰, in petroleum; while
15N has a broader range of approximately 20‰ (Stahl, 1977). This broad range may be
useful in application of stable nitrogen isotopes in distinguishing the source of petroleum
(Parker, 1971). The terrigenous OM is generally characterized by a low 15
N signature
while the marine OM has a relatively higher 15
N values (Mariotti et al., 1984; Peterson
et al., 1985; Thornton and McManus, 1994; Wu et al., 2002). Compared to stable carbon
isotopes, nitrogen isotopes have more complex depositional fluctuations due to influence
of additional factors on the distributions of 15
N in sedimentary OM (Wu et al., 2002).
For example, decomposition of OM under diagenetic conditions results in loss of 14
N and
enrichment of 15
N in sedimentary OM. Higher 15
N corresponds to high C/N ratios,
since nitrogen is labile compared to carbon under diagenetic conditions (Cifuentes et al.,
1996; Thornton and McManus, 1994). Microbial mineralization results in preferential
loss of 14
N and concurrent enrichment of 15
N in OM; consequently, highly decomposed
OM will contain little nitrogen but higher values of 15
N.
Although nitrogen isotopes have been used to elucidate the source and
depositional history of OM within sediments; but is more commonly used to understand
mineralization, denitrification and nitrogen deposition in aquatic systems (Altabet and
Francois, 1994). Mineralized nitrogen within seawater has 15
N value of about +5‰
while the atmosphere, from which terrestrial plants acquire their nitrogen, has a 15
N
value of 0‰. Based on these OM from terrestrial and aquatic sources can be
distinguished (Altabet and Francois, 1994; Meyers, 2006; Sigman et al., 2001). Nitrogen
isotopes can be used in conjunction with carbon isotopes and C/N ratios. A cross plot
between13
C and 15
N gives an idea about the nature of plant source (Peters et al.,
2005b). Similarly 15
N vs. C/N diagram provides good insight into the source of OM and
the paleoenvironmental conditions in which it was deposited. In this study we have used
TOC, elemental and isotopic composition of sediments, in order to evaluate the source
and paleoenvironment of OM and to determine relative contribution of marine and
terrigenous OM in sediments of Eocene, Paleocene and Early Permian ages.
6.2. GEOLOGY AND STUDY AREA
Sediments from three oil wells D, E and F were analyzed for stable isotope and
elemental content of carbon and nitrogen (Figure-6.2). These oil wells were encompasses
the Potwar Basin, Pakistan. The Potwar Plateau is located in the western foothills of the
Himalayas in northern Pakistan. Potwar basin is an active exploration area due to its
substantial reservoir potential. These reservoirs contained many commercial oil fields
which are produced from the Eocene rocks (Jaswal et al., 1997). The major source rocks
in the basin occur in Cambrian, Permian, Paleocene and Eocene sediments (Khan et al.,
1986; Shah et al., 1977; Wandrey et al., 2004).
The geology of the Potwar Basin is very complex. This part of the Indian plate
was deformed during collision with the Eurasian plate and overthrust of the Himalaya
Mountains on the N and NW. The collision began in the Late Eocene and resulted in a
2000 km convergence (Law and Spencer, 1998). Moreover, extensive tectonic activity
caused intense deformation of the rocks; formations of significantly different ages (e.g.
Precambrian and Tertiary) are juxtaposed. As a result, correlating oils and source rocks
(particularly for biodegraded oils) is very difficult. For generalized stratigraphy and
details of geology of the Potwar Basin, see chapter-2, 5 & 8.
Figure-6.2: Map of Pakistan showing the location of wells D, E & F.
6.3 EXPERIMENTAL
The sediments were washed thoroughly with distilled water to remove any dirt
particle and then dried in air. The dried samples were crushed and passed through 80 mm
mesh sieve. The powdered samples (10 g) were placed in an acid fume bath of 6N HCl
(100 mL) overnight in order to remove carbonates and bicarbonates.
After removing carbonates and bicarbonates by acid treatment, samples were
analyzed for elemental as well as stable isotopic analysis of carbon and nitrogen.
Elemental analyzer (Model PDZ Europa ANCA-GSL) interfaced with mass spectrometer
(Model PDZ Europa 20-20, Sercon Ltd., Cheshire, UK) was used for this purpose at UC-
Davis facility, University of California, USA.
50mg samples were placed inside tin capsules. Tin capsules were introduced in
combustion furnace having temperature of 1000 °C. Pure oxygen was supplied in the
combustion furnace which helped in oxide formation. Tin capsule produced a flash
combustion which increases the temperature upto 1700 °C. This increase in temperature
further helped the combustion process where Cr2O3 was used as combustion catalyst. The
product of combustions was in gaseous state, which was then swept in a helium stream.
Then the resultant gases i.e. N2, NOx, H2O, O2, and CO2 were then swept through a
reduction stage of pure copper wires held at 600 °C. This removes any remaining oxygen
and converts NOx gases to N2. Water vapours (produced due to combustions) were
removed by a magnesium perchlorate trap.
Packed column gas chromatograph was used to separate nitrogen and carbon
dioxide at an isothermal temperature. Ion source of IRMS sequentially ionized and
accelerate these chromatographic peaks produced by GC. Gas species of different mass
were separated in a magnetic field and simultaneously measured by a Faraday cup
universal collector array.
Standards, similar to the samples being analyzed, were also combusted under
same conditions. These standards were previously calibrated against NIST Standard
Reference Materials (IAEA-N1, IAEA-N2, IAEA-N3, IAEA-CH7, and NBS-22). Every
sample’s preliminary isotope ratio was measured relative to reference gases analyzed
with each sample. Those preliminary values were finalized by adjusting the values for the
entire batch based on the known values of the included laboratory standards. The final
delta values were expressed relative to international standards PDB (PeeDee Belemnite)
and Air for carbon and nitrogen, respectively.
6.4. RESULTS AND DISCUSSION
In order to distinguish sources of OM and to reconstruct the paleoenvironment of
deposition, total organic carbon (TOC), total elemental carbon and nitrogen, C/N ratios
and isotope composition (13
C and 15
N) were measured for sediments of Eocene,
Paleocene and Early Permian ages collected from wells D, E and F drilled within an area
of 60 km in the northern Potwar Basin. Table-6.1 enlists elemental and stable isotope data
of carbon & nitrogen of sediments.
6.4.1. Elemental Carbon and Nitrogen
The sediments of Chorgali Formation were characterized by high total carbon
contents (TCC) and show a similar trend within wells D, E and F (Figure-6.3; Table-6.1).
Most of the values were between 8.88 and 11.4 %. In a few samples, lower values of 1.2-
3.2% were measured. The values of elemental nitrogen were extremely low and vary
between 0.04 and 0.28% (Figure-6.3; Table-6.1). The uppermost sediment of Sakesar
shows high TCC of 8.34-9.98%, whereas the remaining samples of this interval show low
values in the range of 4.8-6.06%. A distinct increase in TCC is recognized for S-23
sediment, with a maximum value of 9.07%.
Table-6.1: The elemental and stable isotope data of Carbon and Nitrogen for
wells D, E and F.
Depth (m) Sediment
I.D.
Total
N%
Total
C%
15N
13C TOC
%
Pr/Ph C/N
Well-D
Eocene Chorgali
3756 S-1 0.21 8.88 2.38 -24.73 2.83 0.4 42.39
3772 S-2 0.15 3.14 3.48 -24.43 2.81 0.33 21.41
3787 S-3 0.07 1.34 2.6 -24.46 3.01 0.62 20.29
3796 S-4 0.28 11.6 2.59 -25.05 3.17 0.33 40.8
3798 S-5 0.29 11.71 2.35 -24.52 3.16 0.45 39.99
Eocene Sakesar
3821 S-6 0.36 9.99 2.8 -26.17 3.21 0.26 28.09
3826 S-7 0.11 4.88 3.44 -24.27 2.87 0.21 45.74
3835 S-8 0.15 6.06 3.66 -24.72 2.84 1.01 39.94
3969 S-9 0.15 5.76 3.3 -24.52 2.46 0.45 38.66
Paleocene Patala
4062 S-10 0.12 2.74 3.22 -24.36 3.46 0.38 23.6
4065 S-11 0.18 7.09 3.5 -24.78 3.61 0.81 38.61
4067 S-12 0.26 8.04 2.73 -24.71 3.32 0.44 30.9
4069 S-13 0.13 1.88 2.69 -24.2 3.63 0.81 14.24
Well-E
Eocene Chorgali
4655 S-14 0.17 7.42 2.62 -25.55 3.17 0.39 42.39
4662 S-15 0.12 2.62 3.83 -25.24 3.1 0.33 21.41
4672 S-16 0.06 1.12 2.86 -25.27 3.21 0.6 20.29
4685 S-17 0.24 9.69 2.85 -25.88 2.87 0.33 40.8
4688 S-18 0.24 9.78 2.58 -25.34 2.8 0.43 39.99
Depth (m) Sediment
I.D.
Total
N%
Total
C%
15N
13C TOC
%
Pr/Ph C/N
Eocene Sakesar
4697 S-19 0.3 8.34 3.09 -27.04 2.46 0.26 28.09
4704 S-20 0.09 4.07 3.78 -25.07 3.4 0.21 45.74
4716 S-21 0.13 5.06 4.03 -25.54 3.61 0.99 39.94
4720 S-22 0.12 4.81 3.63 -25.33 3.32 0.43 38.66
4728 S-23 0.22 9.07 3.46 -25.73 3.63 0.21 40.43
Paleocene Patala
4820 S-24 0.1 2.29 3.54 -25.16 3.07 0.38 23.6
4828 S-25 0.15 5.92 3.86 -25.6 2.92 0.79 38.61
4860 S-26 0.22 6.72 3.01 -25.53 3.21 0.42 30.9
4884 S-27 0.11 1.57 2.96 -25 3.22 0.38 14.24
4887 S-28 0.13 2.33 3.56 -25.31 3.28 0.79 17.76
Early Permian Sardhai
5300 S-29 0.12 2.33 5.96 -25.12 3.25 0.42 18.98
5305 S-30 0.18 2.87 4.64 -24.98 1.89 0.38 16.39
5310 S-31 0.15 2.59 4.51 -25.16 2.11 0.79 17.51
5312 S-32 0.14 3.77 4.89 -25.52 2.8 0.42 26.74
5316 S-33 0.17 2.86 4.54 -25.43 2.81 0.38 16.81
Well-F
Eocene Chorgali
4029 S-34 0.21 8.82 2.37 -24.27 3.07 0.41 42.39
4033 S-35 0.15 3.12 3.46 -24.3 2.92 0.33 21.41
4041 S-36 0.07 1.33 2.58 -24.89 3.21 0.62 20.29
4046 S-37 0.28 11.52 2.57 -24.36 3.22 0.33 40.8
Eocene Sakesar
4070 S-38 0.35 9.92 2.78 -24.56 3.28 0.45 28.09
4073 S-39 0.11 4.85 3.41 -24.36 3.25 0.26 45.74
4123 S-40 0.15 6.02 3.64 -24.75 1.89 0.21 39.94
4130 S-41 0.15 5.72 3.28 -26 2.11 1.01 38.66
Paleocene Patala
4168 S-42 0.27 10.79 3.12 -24.11 2.82 0.45 40.43
4173 S-43 0.15 2.77 5.38 -24.15 2.81 0.81 18.98
4176 S-44 0.21 3.42 4.18 -24.02 3.01 0.44 16.39
4180 S-45 0.18 3.08 4.07 -24.2 3.17 0.21 17.51
Early Permian Sardhai
4215 S-46 0.17 4.49 4.41 -24.54 3.13 1.01 26.74
4227 S-47 0.2 3.4 4.1 -24.46 3.21 0.45 16.81
Depth (m) Sediment
I.D.
Total
N%
Total
C%
15N
13C TOC
%
Pr/Ph C/N
4233 S-48 0.12 2.31 5.91 -24.9 2.87 0.39 18.98
4238 S-49 0.17 2.85 4.6 -24.77 2.83 0.81 16.39
4243 S-50 0.15 2.57 4.47 -24.95 2.46 0.44 17.51
Well-D
FormationTNC (%) TCC (%)
15NC
13Depth(m)
3740
3840
3940
4040
-27 -26 -25 -24
Chorgali
Sakesar
Patala
2 4 6 0.1 0.2 0.3 0.4 4 8 12 16
4650
4750
4850
4950
5050
5150
5250
-27.5 -26.5 -25.5 -24.5 0 2 4 6 0.1 0.2 0.3 0.4 4 8 12 16
4020
4070
4120
4170
4220
-27 -26 -25 -24 2 4 6 0.1 0.2 0.3 0.4 4 8 12 16
Well-E
Well-F
Chorgali
Sakesar
Patala
Dhak Pass
Chhidru
Wargal/
Amb
Sardhai
Chorgali
Sakesar
Patala
Sardhai
Figure-6.3: Depth profile showing variations in stable carbon and nitrogen
isotopes, and total carbon and nitrogen contents of OM in wells D, E
and F.
The values of total nitrogen contents (TNC) are slightly greater than the Chorgali
Formation (0.1 to 0.35%), however TNC show trend similar to TCC throughout the
sequences (Figure-6.3). The Paleocene Patala sediments do not show uniformity in TCC,
the values are generally low in the range of 1.57-3.42% for top and lowermost samples,
whereas middle samples from wells D & E show higher values between 5.9 and 8.04%.
This interval also includes a single spike, with value 10.8% for topmost sample in Well-
F. The nitrogen signal is low in the range of 0.09-0.26% either for the Patala Formation.
The Early Permian Sardhai Formation was penetrated in wells E & F. This interval
generally shows low TCC and TNC in the range of 2.3 to 4.48% and 0.12 to 0.2%
respectively.
For paleoenvironmental interpretations, the information about marine and
terrigenous proportions of the OM is extremely necessary. OM from terrigenous source
mainly contains cellulose and lignin whereas marine OM from animal source is nitrogen
rich and cellulose poor. High TCC and extremely low amounts of TNC are probably the
result of an enhanced content of terrestrial OM in these sediments. In most of the Eocene-
Permian samples, the total nitrogen content is not more than 0.35%, indicating a
terrigenous organic matter as main source. The inconsistency in TCC coincides with
variable amount of OM accumulation and preservation during this time interval.
6.4.2. Total Organic Carbon (TOC)
High values of TOC, 2.8 – 3.2%; 1.9 – 3.6%; 2.8 – 3.6% and 1.9 – 3.2% indicate
high productivity and high preservation rate of OM under anoxic conditions in Chorgali,
Sakesar (Eocene), Patala (Paleocene) and Sardhai (Early Permian) Formations (Table-
6.1). The OM in marine sediments originates from marine and terrestrial sources (Goni et
al., 2005). It is estimated that over 80% of the global organic carbon (OC) burial occurs
in shallow marine systems (Tesi et al., 2007). The samples show low values of Pr/Ph (<1)
and diasteranes/steranes (~ 0.2; chapter 7), we assume marine carbonate depositional
setting for OM in the study area.
6.4.3. Stable Carbon and Nitrogen Isotopes (13
C and 15
N)
Stable carbon isotopic composition (13
C) of OM is broadly used as an indicator
for carbon sources, productivity and photosynthetic pathways in plants (Schubert and
Calvert, 2001). The values for land plants range from 10 to 35‰ (Meyers, 1997;
Sharpe, 2007; Tyson, 1995), which could be differentiated between C3 and C4
plants. The 13
C for C3 plants range from 35 to 22‰ (average 27‰), while for the C4
plants it is from 16 to 10‰, with a mean value of 13‰ (Meyers, 1997; Meyers,
2003; Sharpe, 2007; Smith and Epstein, 1971). Organic carbon from marine primary
productivity is usually enriched in 13
C relative to C3 vascular plant carbon. Marine OM
typically has 13
C values ranging from 21 to 19‰. Marine and freshwater
phytoplankton sources for the OM are indicated by 13
C ( 28.1 to 19.7‰, mean=
23.0‰),15
N (+14.8 to +4.7‰, mean= +9.2‰) and C/N (14.5 to 1.5, mean= 7.9) (Fry
and Sherr, 1989).
The values of 13
C for Chorgali, Sakesar and Patala samples within Well-D are in
close proximity of 24.8‰ to 24.2‰ with lower values occurring for some samples
(e.g., S-4 and S-6, 25 and 26.2‰; Table-1; Figure-2). The overall 13
C for Chorgali,
Sakesar, Patala and Sardhai samples within Well-E are also close ( 25 to 25.8‰) with
the exception of top sample of Sakesar Formation ( 27‰; Table-6.1). The same
formations penetrated in Well-F show a similar trend, i.e., 13
C 24 to 24.9‰ with the
exception of S-41, which is isotopically lighter with 13
C 26‰ (Table-6.1).
Carbon isotope ratios of most samples range from –25.8 to –24.2‰ with lower
values (–26 and –27 ‰) occurring in the some samples of Sakesar Formation. These
values are 2.8‰ greater than 27‰, the mean value of C3 plants. Keeping in view the
influence of anoxic environments and non-clasic/marine carbonate depositional settings
for OM, 13
C data suggest a similar type of OM predominantly derived from C3 plants;
while those with lighter isotopic signatures could have more contribution of land plant
input.
6.4.4. C/N Ratios: Source Identification
C/N ratios are widely used as an indicator of OM origin. Vascular plants biomass
is mainly comprised of cellulose and lignin and depleted in nitrogen, compared to marine
phytoplankton (protein-rich). C/N less than10 is interpreted as aquatic source. Most
microorganisms have C/N ratios between 4 and 9; while terrestrial plants have a wide
C/N range of 10 to 40, although values as high as 90 are not uncommon. Values 10 to
20 may suggest admix of aquatics and terrestrial sources, while >20 is for dominant
terrestrial biomass. However, inorganic nitrogen bound to clays decrease the ratio, while
diagenetic conditions increase the ratio, as proteins are relatively labile (Hedges et al.,
1986; Meybeck, 1982; Meyers, 1997; Sharpe, 2007; Tyson, 1995). The guidelines by
these authors will be used to identify origin of OM in this study.
The C/N ratios range from 20 42, 28 45, 14 40 and 16 26 for Chorgali,
Sakesar, Patala and Sardhai Formations, a similar trend within these formations suggest a
similar type of OM deposition irrespective of the location of well and depth of sample,
although Patala samples in Well-F show some variations (Table-6.1). Chorgali Formation
shows C/N ratios 39 42 for the top and bottom samples corresponding to strong
terrestrial input, while the lower values of 20 21 for the middle samples suggest admix
of aquatics (probably marine algae) and land plant sources (Figure-6.3). The values are
generally higher in the range of 38 45 for the Sakesar samples with the exception of
topmost sample of the formation, which indicate C/N close to 28. These data indicate
strong land plants input (Table-6.1). Patala shows inconsistent trend, the C/N values
between 14 and 18 suggest mixed marine algal and land plant sources for the deeper
samples of the formation which continue up to the Early Permian Sardhai Formation as
reflected from C/N ratios 16 18; while higher values, 23 and 38 to 40 for Patala and 26
for Sardhai correspond to variable input from land plants derived OM (Fontugne and
Jouanneau, 1987; Wada et al., 1987). Our results generally show high values of C/N
ratios for the Chorgali and Sakesar Formations and fall within the range of a strong
terrestrial input (38 45) with occasional low values (20 21) within the range of some
algal input into the source. Alternatively low C/N ratios (< 20) observed for Patala and
Sardhai Formations imply carbon input from mixed sources (marine algal and land
plants), which supports marine depositional environment and improved preservation of
OM in marine carbonate sediments.
The plot of C/N vs. 13
C (Figure-6.4) demonstrates that 13
C is almost consistent
while high C/N ratios e.g., for Chorgali and Sakesar samples indicate that OM is from a
common source such as vascular C3 plant as primary producers. The trend toward low
C/N values within the Chorgali and Sakesar formations is associated with inclusion of
marine planktonic OM into the source (Figure-6.4). Similarly low C/N values (< 20)
observed for Patala and Sardhai samples imply mixed OM having significant input from
marine planktons.
-30
-25
-20
-15
-10
Chorgali
Sakesar
Patala
Sardhai
0 10 20 30 40 50 60
C/N
70 80
-35
C3 Land Plants
Mixed (Marine Planktons & Land Plants)
C13
Figure-6.4: C/N versus 13
C diagram showing a variation of bulk organic matter
in sediments of Chorgali, Sakesar, Patala and Sardhai Formation
(Modified from Meyers 1997).
-2
0
2
4
6
8
-42 -38 -34 -30 -26 -22 -18 -14 -10 -6
Chorgali
Sakesar
Patala
Sardhai
C13
N15
Marine
Algae
Land Plants
C3 Plants
Marine OM
LandPlants Mixed:
&Marine Planktons
Figure-6.5:13
C versus 15
N diagram showing origin and variability of OM in
sediments.
Nitrogen isotope ratio ( 15N) has also been used to identify the origin of OM in
sediments (Hu et al., 2006; Meyers, 1997; Thornton and McManus, 1994), which
depends on where the different organisms acquire their nitrogen from. The ultimate
source of nitrogen on Earth is the atmospheric nitrogen which exists as N2 gas (15
N
=~0‰), however, molecular nitrogen is inert and cannot be utilized by plant and animal
life as such. The bio-active forms of nitrogen for plants and animals uptake are
ammonium and nitrate formed by ammonification and nitrification during nitrogen
fixation process (Hoefs, 1997; Leng and Barker, 2006).
Dissolved nitrogen within seawater in the form of nitrates has 15
N value of about
+5‰ while the atmosphere (from which terrestrial plants acquire their nitrogen) has a
15N value of 0‰. Marine plankton follow
15N value of dissolved nitrate (~5‰), while
C3 land plants reflect 15
N value of atmospheric N2 (0 to 1‰; Meyers 2006, Sigman et
al. 2000, Altabet and Francois 1994). The 15
N in the range of 2–5‰, and C/N ratio >10
up to 40 are used as the terrestrial end member (Schoeninger and DeNiro, 1984).
The results of 15
N do not show significant variation among the samples of three
wells.15
N data show two trends, low values in the range of 2.3 to 3.8‰ have been
observed for Chorgali, Sakesar and some Patala sediments and indicate mixed land plant
and marine planktonic OM, while slightly higher values 3.1 to 5.9‰ for Sardhai and
Patala (Well-F) Formations illustrate that mixed OM in these sediments contains higher
planktonic input. The 15
N versus 13
C diagram demonstrated the nature and origin of
OM on the basis of 15
N, is likely to be composed of land plants mainly derived from C3
plants plus variable proportions of marine planktonic input.
6.5. CONCLUSIONS
Enhanced amount of terrestrial OM was indicated by high values TCC and
extremely low TNC.
Anoxic environment with marine carbonate depositional setting for OM was
indicated by high TOC and low values of Pr/Ph (<1) and diasteranes/steranes.
Carbon isotope ratios of OM generally range from –25.8 to –24.2‰ with some
lower values found in Eocene Sakesar formation. These values suggest that OM
was derived from C3 plants with significant input from land plants and marine
planktons.
The plot of C/N vs. 13
C demonstrates that OM in Chorgali and Sakesar samples
is from a similar source such as vascular C3 plant as primary producers.
The trend toward low C/N values within the Chorgali and Sakesar formations is
associated with inclusion of marine planktonic OM into the source. Similarly low
C/N values (< 20) observed for Patala and Sardhai samples imply significant
carbon input from marine planktons in mixed OM.
Two trends were found in 15
N data i.e. low values (2.3-3.8‰) observed for
Chorgali, Sakesar and some Patala sediments indicate mixed land plant and
marine planktonic OM, while slightly higher values (3.1-5.9‰) for Sardhai and
Patala (Well-F) Formations illustrate that mixed OM in these sediments contains
higher planktonic input.
The15
N versus 13
C diagram demonstrates that the OM is likely to be composed
of land plants mainly derived from C3 plants having variable proportions of
marine planktonic input.
Chapter-7
SOURCE, DEPOSITIONAL ENVIRONMENT AND MATURITY OF
EOCENE, PALEOCENE AND EARLY PERMIAN SEDIMENTS: BIOMARKERS
AND ROCK-EVAL STUDY
ABSTRACT
Further to stable isotopes and well log study (chapters 4 & 6), GC, GC-MS,
Rock-Eval, TOC analysis on sedimentary sequences of Eocene (Chorgali & Sakesar),
Paleocene (Patala) and Early Permian (Sardhai) is reported in this chapter. The main
aim of study is to characterize the OM quantity and quality, and to interpret the
depositional environment and thermal maturity of OM in these sediments in order to
evaluate source rock potential and petroleum prospects in the Potwar Basin.
Rock-Eval pyrolysis data indicate that Chorgali and Sakesar Formations have
good to very good quantity of type II/III OM with potential mainly for gas generation.
The samples have Hydrogen Index (HI) 275-374 mg HC/g TOC and S2/S3 mostly 4.5-5.5.
Most of the Paleocene sediments show HI values in the range of 300-445 mg HC/g TOC
and suggest major contribution of type II kerogen in these samples; S2/S3 ratios in the
range of 5.5-16 indicate both oil and gas prone sediments, while lower values (< 5)
reflect gas prone OM. The Early Permian, Sardhai samples have HI 218-354 mg HC/g
TOC and S2/S3 up to 6.8 and represent mostly gas prone type II/III OM. All the samples
show TOC about 2-3.6% and Tmax 440 – 442°C which is consistent with good to very
good organic richness and thermal maturity of sediments in the peak oil window.
The commonly used biomarker parameters have further been used to
interpret the source material, thermal maturity and depositional environment of samples.
The organic source was assessed from the composition of C27–C29 steranes. The relative
distributions of steranes in order of C27>C29>C28, and C27/C29 steranes >1 suggest OM
input of mixed nature, most likely of marine planktonic and terrestrial origin. Low values
of diasterane/sterane and Ts/ (Ts+Tm) for most samples (0.2-0.4 and 0.5-0.6) as well as
Pr/Ph ratios up to 0.2-0.8 suggest anoxic clay-poor/carbonates having high pH and low
Eh. The values of maturity parameters, / ( + ) and 20S/ (20S+20R) C29 sterane, are
lower than the equilibrium values and represent early generation stage of samples;
however, keeping in view Tmax values 440 – 442°C, and that sediments under study are
anoxic carbonates, wherein generation stage is reached before the equilibrium, we
propose that all samples have reached the peak of the oil window. The variations in
biomarker and Rock-Eval parameters in some samples suggest regional variations of
organic facies in their source rocks.
7.1. INTRODUCTION
Characterizing the organic matter from sedimentary rocks is one of the main
objectives of organic geochemistry and is now widely recognized as a critical step in the
evaluation of the hydrocarbon potential of a prospect. The characteristics of potential
source rocks or oils can be evaluated by a number of geochemical methods such as Rock-
Eval and Gas Chromatography-Mass Spectrometry (GC-MS) technique through
biomarker studies. Rock-Eval pyrolysis has been widely used in the industry as a
standard method in petroleum exploration. This technique uses temperature programmed
heating of a small amount of rock (100 mg) in an inert atmosphere (helium or nitrogen)
so as to determine: the quantity of free hydrocarbons present in the sample and the
amount of hydrocarbons and compounds containing oxygen that are produced during the
thermal cracking of the insoluble organic matter in the rock. Furthermore, the Total
Organic Carbon (TOC) content of the rock is determined by oxidation under air, in a
second oven, of the residual organic carbon after pyrolysis (For details of Rock-Eval, see
Chapter-1 & 5).
Biomarkers have been used as molecular indicators of the organic source
materials, depositional environmental, thermal maturity experienced OM and
geochemical correlation study (Curiale et al., 1983; El-Gayar et al., 2002; Holba et al.,
2003; Larter and Douglas, 1982; Peters et al., 2005b; Sosrowidjojo et al., 1994). Some
specific source and depositional conditions may increase or decrease the relative
proportion of some compounds class. Concentration of these compounds, in petroleum
and sediments, can be used to get information on source and depositional environment of
crdue oils and sediments. Variation in relative concentrations of biomarker isomeric
ratios reflects thermal maturity of OM. Thermal maturity describes the extent of heat
driven reactions that convert sedimentary organic matter into petroleum (Peters et al.,
2005b). Petroleum is a complex mixture of hydrocarbons having compounds that move
toward thermal stability with maturation. Based upon level of thermal maturity, organic
matter is termed as immature, mature and post mature with respect to oil generation
window (Tissot and Welte, 1984). Geochemical correlations involve comparison of
biomarker data of crude oils and SOM of source rocks in an attempt to find
compositional similarity and its application by petroleum industry in exploration study
(Killops and Killops, 2009; Philp, 1983b). Since these compounds are present in minute
quantities (ppm or ppb) in sedimentary OM, therefore sophisticated analytical techniques
like Gas chromatography-mass spectrometry (GC-MS) provides a useful mean for
analysis of biomarkers (Peters and Moldowan, 1993).
7.2. SOURCE, DEPOSITIONAL ENVIRONMENT AND
MATURATION PARAMETERS
This section contained description of some Rock-Eval and biomarker
parameters which were used to access the source, maturity and depositional environment
of samples. A brief description of each parameter is given in following paragraphs and
listed in Table-7.1.
S1: S1 is the amount of hydrocarbons which are already expelled from source
rock at 300 °C. It is expressed in mg of hydrocarbons/g of rock. The values of S1
describe quality of source rock (Peters and Cassa, 1994).
S2: S2 is the quantity of hydrocarbons which are produced during heating at 350-
550 °C. It is expressed in terms of mg of hydrocarbons/g of rock. It is also used for the
quality of organic matter (OM) in sediments.
S3: This parameter represents the amount of CO2 produced during kerogen
cracking. It is expressed as mg of CO2/g of rock.
Hydrogen Index (HI): Hydrogen index is calculated by dividing S2 with TOC. It
is expressed as mg of hydrocarbons/ g of TOC. HI corresponds to the quantity of
pyrolysable OM/hydrocarbons relative to the TOC in sample.
Oxygen Index (OI): Oxygen index is measured by dividing S3 with TOC. It is
expressed as mg of CO2/g of TOC. OI represents the quantity of carbon dioxide relative
to TOC. The cross plot of HI vs. OI is used for the classification of the kerogen type and
nature of hydrocarbon expulsion i.e. oil or gas prone.
Tmax: It the temperature at which maximum hydrocarbons are expelled from the
source rock. This temperature is used for the assessment of thermal maturity of the
sediments. A cross plot of HI vs. Tmax is used to determine the thermal maturity and type
of kerogen in OM.
SPI: Source Potential Index is the maximum amount of hydrocarbons (kg HC/ton
Rock) that were generated under any 1m2 of surface area of the source rock (Demaison
and Huizinga, 1991).
S2/S3: S2/S3 is ratio of generated hydrocarbons at Tmax vs. amount of CO2
produced. This is used for the type of hydrocarbons i.e. oil or gas prone.
Production Index (PI): Production index can be defined as S1/(S1+S2) i.e.
proportion of free hydrocarbons in relation to total amount of hydrocarbons obtained after
pyrolysis. PI is also used for the thermal maturity evaluation.
Pristane/Phytane: Pristane and Phytane are branched acyclic iso-prenoids eluted
just after nC-17 and nC-18. Didyk et al. (1978) proposed Pr/Ph<1 is the indication of
anoxic source rock deposition while Pr/Ph>1 indicate oxic conditions. High Pr/Ph i.e. >3,
indicates terrigenous organic matter under oxic conditions (Didyk et al., 1978).
Pr/(Pr+Ph) vs. C27 Diasterane/(Diasterane + Sterane) ratio: This ratio can be
used to identify the presence of carbonate or shale lithology (Moldowan et al., 1994).
Iso-prenoids/n-alkane Ratio: Oils from rocks deposited under open-water
conditions showed Pr/nC17 <0.5, while those from inland peat swamps had ratios greater
than 1.00. Both Pr/nC17 and Ph/nC18 decrease with thermal maturity. Biodegradation
increases these ratios because aerobic bacteria generally attack the n-alkanes prior to
isoprenoids. Values less than 1.0 are indicative of non-biodegraded oils (Connan et al.,
1980).
Diasterane/Sterane: Diasterane/Sterane ratio is commonly used to distinguish
between carbonates and clastic source rocks (Mello et al., 1988; Rubinstein et al., 1975).
High diasterane/sterane ratio indicates the presence of oxic clay rich source rocks while
low values indicate clay poor carbonate rich sediments.
22S/(22S+22R) Homohopane Isomerization: The ratio rises from 0.00 to ~0.6
and can be used for maturity assessment (Seifert and Moldowan, 1980). Oils and bitumen
extracts which are near oil generation window have 22S/(22S+22R) homohopane ratio in
the range of 0.50-0.54 while values in the range of 0.57-0.62 indicate that main phase of
oil generation has reached or near to surpassed.
Ts/(Ts+Tm): C27 17 (H) tris-norhopane (Tm) is thermally less stable than C27
18 (H) tris-neohopane (Ts) (Seifert and Michael Moldowan, 1978). This ratio ranges
between 0.4-0.5 for immature oils and bitumen, from 0.5-0.6 for early oil generation
while 0.6-0.8 is for peak oil generation. This value keeps on increasing till Ts
concentration becomes maximum (Seifert and Michael Moldowan, 1978).
20S/(20S+20R) Sterane Isomerization: The relative concentration of “S” and “R”
configuration for maturity. 20S/(20S+20R) ratio increases from 0.00 to 0.5 and reaches to
equilibrium at 0.52-0.55. The equilibrium value corresponds to peak oil generation
window while value between 0.4-0.5 represents early oil generation window (Seifert and
Moldowan, 1986).
/( + ) Sterane Isomerization: 14 , 17 (H) configuration in C29 sterane is
thermally more stable than 14 , 17 (H) configuration. This stability factor causes high
relative concentration of isomers compared to isomers with increasing maturity.
Seifert and Moldowan (1986) proposed /( + ) ratio between 0.25-0.45 for early oil
generation window and for peak oil generation, this ratio is 0.61-0.71 (equilibrium
concentration).
Table-7.1: Rock-Eval and Biomarker parameters to evaluate source,
maturity and depositional conditions of OM.
Parameter Indicators Reference
S1 0-0.5 (Poor), 0.5-1 (Fair), 1-2
(good), 2-4 (very good), >4 (excellent)
S2 0-2.5 (Poor), 2.5-5 (Fair), 5-10
(good), 10-20 (very good), >20 (excellent)
Tmax <435 °C (immature), 435-445 °C
(early mature), 445-450 °C (peak mature),
450-470 °C (late mature), >470 °C (post
mature)
HI >600 (Type-I), 300-600 (Type-II),
200-300 (Type-II/III), 50-200 (Type-III),
<50 (Type-IV)
SPI Petroleum Potential of Source Rock;
<0.2 (low), 2 to <7 (moderate), 7 (high)
S2/S3 >15 (oil), 10-15 (oil), 5-10 (oil and
gas), 1-5 (gas), <1 (none)
PI <0.1 (immature), 0.1-0.15 (early
mature), 0.25-0.4 (peak mature), > 0.4 (late
mature)
(Peters and
Cassa, 1994)
Pr/Ph <0.8 (anoxic conditions with
hypersaline or marine carbonates), >3 (oxic
conditions with terrigenous OM), 1
(shale), 1 (Carbonates)
(Peters et al.,
2005b)
(Connan, 1981)
(Moldowan et
al., 1985)
Ph/n-C18 0.3 (shale), 0.3 (carbonates) (Connan, 1981;
Palacas et al., 1984)
Diasterane/Sterane Low values indicates anoxic clay-
poor or carbonate source rock with high pH
and low Eh
High values indicates clay-rich
source rock with low pH and high Eh
(Moldowan et
al., 1985; Peters et al.,
2005b)
22S/(22S+22R)
Hopane
0.57-0.62 (peak oil generation),
0.50-0.54 (barely entered oil generation),
<0.5 (low maturity)
(Philp, 1983a;
Seifert and Moldowan,
1980)
Ts/(Ts+Tm) 0.4-0.5 (immature), 0.5-0.6 (early
mature), 0.6-0.8 (peak oil generation)
(Seifert and
Moldowan, 1980)
20S/(20S+20R) 0.4-0.5 (early oil generation), 0.52-
0.55 (peak oil generation i.e. equilibrium)
(Peters et al.,
2005b)
/( + )
Sterane
<0.25 (immature), 0.61-0.71
(equilibrium)
(Peters et al.,
2005b)
7.3. RESULTS AND DISCUSSION
In this chapter, sediment samples of Eocene, Paleocene and Early Permian
ages from three wells were analyzed using Rock-Eval, GC and GCMS. The Rock-Eval
parameters and biomarkers were examined in detail in order to interpret the source of
OM, depositional environment and thermal maturity.
7.3.1. WELL-D
(i) Eocene Chorgali Formation
Eocene Chorgali formation, having limestone (carbonate) lithology, has good
quantity of organic matter (OM) (TOC 2.81-3.17). Slight increase in TOC (wt %) was
observed with depth. OM richness was supported by the S1 (2.12 to 3.24mg/g) and S2
(7.79 to 9.63mg/g) (Table-7.2, Figure-7.1 i-iii). Source Potential Index (SPI) (1.58-2.05)
suggested low source rock potential of this unit (Table-7.1). These low values indicated
the oil expulsion (Peters and Cassa, 1994). Quality of organic matter was assessed by
using HI and S2/S3 values (Figure-7.1, v-vi). S2/S3 values (2.56-5.1) and HI values (275-
316 mg of HC/g of TOC) indicate the presence of Kerogen Type-II/III. Presence of Type-
II/III was also confirmed by plotting HI vs. OI plot (Figure-7.2) (Bordenave, 1993; Tissot
and Welte, 1984). All sediments were within the Type II/III area of the diagram,
indicating contribution from mixed OM, while S2/S3 ratio indicated both oil and gas
potential. Thermally maturity was assessed using Tmax and Production Index (PI).
Sediments have values within thermally mature zone i.e. >435 °C (Peters and Cassa,
1994). Tmax values falls within a narrow range of 440-442 °C which indicate the
sediments were within mature stage. This narrow range was due to low heat exchange
and variability in kerogen type. PI values (0.19-0.25) also supported that the sediments
were within mature zone (Peters and Cassa, 1994). A combine assessment of thermal
maturity and nature of organic matter was done by plotting Tmax vs. HI data (Figure-7.3).
This figure showed that the all sediments were within mature window with type-II/III
OM as major source input. Based on comparatively high TOC and HI values as well as
maturity indicators, this study suggests that marine limestone in the Chorgali formation,
particularly those having SPI > 2, may contain some source rock intervals. The plot
between TOC vs. S2 suggested that inert carbon was absent and sediments were in very
good to excellent category.
Table-7.2: Rock-Eval, TOC data based on various parameters to access quality,
quantity and thermal maturity of organic matter in Eocene and
Paleocene Sediments from Well-D.
Depth
(m)
Sediment
I.D.
TOC
(%)
S1a S2
a S3
b S1+S2
a SPI
cS2/S3 HI
dOI
e Tmax
(°C)
PI S1/TOC
Eocene Chorgali Formation
3756 S-1 2.83 2.12 7.79 2.77 9.91 1.58 2.81 275 98 442 0.21 0.75
3772 S-2 2.81 2.53 8.20 2.16 10.73 1.71 3.80 292 77 440 0.24 0.90
3787 S-3 3.01 3.14 9.51 3.72 12.65 2.02 2.56 316 124 440 0.25 1.04
3796 S-4 3.17 2.15 9.32 2.32 11.47 1.82 4.02 294 73 441 0.19 0.68
3798 S-5 3.16 3.24 9.63 1.89 12.87 2.05 5.10 305 60 440 0.25 1.03
Eocene Sakesar Formation
3821 S-6 3.21 3.34 10.62 1.91 13.96 4.27 5.56 331 60 440 0.24 1.04
3826 S-7 2.87 2.89 8.92 1.93 11.81 3.63 4.62 311 67 442 0.24 1.01
3835 S-8 2.84 2.67 8.63 1.87 11.30 3.47 4.61 304 66 442 0.24 0.94
3969 S-9 2.46 1.88 6.74 2.71 8.62 2.64 2.49 274 110 442 0.22 0.76
Paleocene Patala Formation
4062 S-10 3.46 4.13 13.61 0.85 17.74 2.61 16.01 393 25 439 0.23 1.19
4065 S-11 3.61 4.19 15.32 1.33 19.51 2.88 11.52 424 37 439 0.21 1.16
4067 S-12 3.32 4.16 13.01 1.73 17.17 2.52 7.52 392 52 440 0.24 1.25
4069 S-13 3.63 4.08 16.15 1.81 20.23 2.97 8.92 445 50 441 0.20 1.12
a = mg HC/g rock, b = mg CO2 /g rock, c = kg HC/ton rock, d = mg HC/ g TOC,
e = mg CO2/g TOC
420
430
440
450
460
470
3750
3850
3950
4050
12
31
23
45
24
68
10
12
14
16
18
510
15
20
0200
400
600
510
15
0.2
0.4
0.6
iT
OC
iiii
iiv
vv
iv
iiv
iii
S1
S2
S1
+S
2H
IS
2/S
3T
ma
xP
I
Qu
ali
tyQ
ua
nti
tyT
her
ma
l M
atu
rity
Fig
ure
-7.1
: G
eoch
emic
al
Wel
l L
og
s fo
r W
ell-
D,
sho
win
g q
ua
lity
, q
ua
nti
ty a
nd
th
erm
al
ma
turi
ty o
f o
rga
nic
ma
tter
in
Eo
cen
e a
nd
Pale
oce
ne
Fo
rma
tio
ns.
Sym
bol
is f
or
Eoce
ne
Ch
org
ali
Frm
ati
on
is f
or
Eoce
ne
Sak
esar
Form
ati
on
wh
ile
rep
rese
nts
Pale
oce
ne
Pata
la f
orm
ati
on
.
0
100
200
300
400
500
600
700
0 50 100 150 200
Type-I
Type-II
Type-III
OI
HI
Chorgali
Sakesar
Patala
Figure-7.2: Modified Van Krevelan diagram for classification of kerogen type in
Well-D sediments.
0
100
200
300
400
500
600
700
800
900
1000
400 420 440 460 480 500
Type-I
Type-II
Type-III
0.5% Ro
1.35% Ro
HI
OI
A B C
Patala
Chorgali
SakesarOil Window
Condensate
Wet gas
Dry gas
Figure-7.3: Tmax vs. HI plot showing the classification and thermal maturity of OM
0
10
20
30
40
04
812
16
Excellen
t
02468
10
01
23
4
Po
orF
air
Go
od
Very
Go
od
No
Po
ten
tial
Ch
org
ali
Sakesar
Pata
la
Fig
ure
-7.4
: T
ota
l O
rgan
ic C
arb
on
(w
t%)
vs. S
2 (
mg
/g)
plo
t fo
r th
e q
uality
of
org
an
ic m
att
er
in E
ocen
e a
nd
Pale
ocen
e F
orm
ati
on
in
Well-D
S2
TO
C
Biomarker based depositional environment ratios for Eocene Chorgali formation such as
Pr/Ph is in the range of 0.33-0.62 indicated anoxic to hypersaline depositional conditions
of OM (Table 7.3, Figure 7.5 i). Iso-prenoids vs. sterane plot suggested that OM in
carbonates sediments was probably deposited under anoxic conditions (Figure 7.6).
Carbonate sediments have also been indicated by SP and GR logs (Chapter-4). Further to
modified Van Krevelan diagram (Figure-7.2), the cross plot of Pr/n-C17 vs. Ph/n-C18
indicated that sediments of Chorgali formation have mixed OM deposited under anoxic
conditions (Figure 7.7). The steranes to hopane ratios reflect eukaryotes (mainly algae
and vascular plants) vs. prokaryotes (bacteria) input to source rock. Low
steranes/hopanes ratio < 1 indicated the dominance of bacterial input (Figure-7.5, ii). The
relative distribution of C27-C29 steranes (Table-7.3) indicated mixed OM input which
was also supported by C27/C29 sterane ratio ( 1). Low values of diasterane/sterane ratio
up to 0.25 indicated anoxic clay-poor probably carbonates sediments as source rocks of
OM (Peters et al., 2005b). Maturity of samples was assessed using ratios based upon
steranes and hopanes isomerization ratios. 22S/(22S+22R) ratios (0.48-0.57) were close
to equilibrium values (0.57-0.65) (Figure-7.1, iv, Table-7.3). Ts and Tm values (0.48-
0.59) indicated early mature nature of sediments (Fgure-7.5, v, Table-7.3). In carbonate
source rocks expulsion is reached before the equilibrium compared to shale source rock
therefore these sediments have equilibrium before the onset of significant. The samples
showed 20S/(20S+20R) ratio (0.45-0.53) and /( + ) values in the range of 0.58-0.6.
The equilibrium values for these parameters are 0.52-0.55 and 0.61-0.71, respectively
(Figure-7.5 vi & vii). These parameters indicated that OM in these sediments is at early
oil generation zone.
Ta
ble
-7.3
: B
iom
ark
ers
da
ta b
ase
d o
n v
ari
ou
s p
ara
met
ers
to a
cces
s q
ua
lity
, q
ua
nti
ty a
nd
th
erm
al
ma
turi
ty o
f o
rga
nic
ma
tter
in
Eo
cen
e a
nd
Pa
leo
cen
e S
edim
ents
of
Wel
l-D
.
Rel
ativ
e %
D
epth
(m)
Sed
imen
t
I.D
.
Pr/
Ph
P
r/
nC
17
Ph
/
nC
18
Pr/
(Pr+
Ph
)
St/
Ho
pD
ia
/St
C27
C28
C29
C27/
C29
22
S/
(22S
+22R
)
Ts/
(Ts+
Tm
)
20
S/
(20
S+
20
R)
/(+
)
Eo
cen
e C
ho
rgal
i F
orm
atio
n
3756
S-1
0.4
0.5
6
0.3
6
0.2
9
0.7
7
0.2
5
39.2
22.9
537.8
51.0
4
0.5
3
0.5
9
0.5
0.5
8
3772
S-2
0.3
3
0.5
1
0.3
3
0.2
5
0.7
8
0.1
9
39.2
25.6
535.1
51.1
2
0.5
2
0.5
2
0.5
3
0.5
9
3787
S-3
0.6
2
0.5
5
0.2
4
0.3
8
0.8
0.2
2
38.5
24.3
37.2
1.0
3
0.5
7
0.5
2
0.5
0.5
8
3796
S-4
0.3
3
0.5
3
0.2
1
0.2
5
0.8
7
0.2
3
39.9
22.9
537.1
51.0
7
0.4
8
0.4
8
0.4
5
0.6
3798
S-5
0.4
5
0.5
1
0.3
1
0.3
1
0.8
0.2
5
39.2
22.9
537.8
51.0
4
0.5
7
0.5
2
0.5
0.5
8
Eo
cen
e S
akes
ar F
orm
atio
n
3821
S-6
0.2
6
0.4
2
0.4
7
0.2
1
0.4
6
0.3
1
43.4
24.3
32.3
1.3
4
0.5
6
0.5
2
0.5
5
0.6
1
3826
S-7
0.2
1
0.7
6
0.3
3
0.1
8
0.5
5
0.2
8
44.8
20.2
534.9
51.2
8
0.5
3
0.5
3
0.5
1
0.6
1
3835
S-8
0.7
1
0.5
9
0.2
5
0.5
1
0.4
9
0.3
9
40.6
21.6
37.8
1.0
7
0.5
4
0.4
7
0.4
9
0.6
3969
S-9
0.4
5
0.5
7
0.2
6
0.3
1
2.8
8
0.1
2
38.5
24.3
37.2
1.0
3
0.5
4
0.5
0.4
8
0.5
7
Pal
eoce
ne
Pat
ala
Fo
rmat
ion
4062
S-1
0
0.3
8
0.5
7
0.3
1
0.2
7
1.1
8
0.1
4
43.4
20.2
536.3
51.1
9
0.5
3
0.5
3
0.4
8
0.5
6
4065
S-1
1
0.6
2
0.5
0.2
4
0.4
5
1.1
5
0.2
1
37.1
28.3
534.5
51.0
7
0.5
4
0.4
7
0.5
1
0.6
1
4067
S-1
2
0.4
4
0.5
7
0.1
8
0.3
1.1
4
0.2
6
37.8
25.6
536.5
51.0
3
0.5
2
0.6
5
0.4
9
0.5
8
4069
S-1
3
0.6
4
0.5
5
0.2
4
0.4
5
0.7
7
0.4
6
35.7
22.9
541.3
50.8
6
0.5
2
0.6
2
0.4
5
0.5
9
Pr/
Ph:
Pri
stane/
Phyt
ane
C27/C
29 S
t: C
hole
stane/
24 E
thyl
chole
stane
20R
: 2
0R
24-e
thyl 14
, 17
chole
sta
ne, C
29
Pr/
n-C
17
: P
rist
an
e/ H
epta
dec
an
e 2
2S
/(2
2S
+2
2R
): 2
2S
17
,21
ho
mo
ho
pa
ne/
(22S 1
7,2
1 h
om
ohopane+
22R
17
,21
hom
ohopane)
: 20S
24-e
thyl 5
, 14
, 17
chole
sta
ne, C
29
Ph
/n-C
18
: P
hyt
an
e/O
cta
dec
an
e 2
0S
: 20S
24-e
thyl 14
, 17
chole
sta
ne, C
29
St/
Ho
p:
5, 14
, 17
Chole
sta
ne/1
7-H
opa
ne
Ts:
18
22
,29
,30
-trisno
rho
pa
ne
Dia
st/S
t: D
iast
era
ne/
Ste
ran
e T
m:
17
22
,29
,30
-trisno
rho
pa
ne
Dep
th(m
)
iP
r/P
hii
St/
Ho
pii
iD
ia/S
t
iv2
2S
/(2
2S
+2
2R
)v
Ts/
(Ts+
Tm
)
vi
20
S/(
20
S+
20
R)
vii
/(
+)
C2
9 S
t
So
urc
e a
nd
Dep
osi
tio
na
l E
nv
iro
nm
ent
Th
erm
al
Ma
turi
ty
Fig
ure
-7.5
: B
iom
ark
er D
epth
Pro
file
s fo
r W
ell-
D,
ind
ica
tin
g v
ari
ou
s p
ara
met
ers
reg
ard
ing
so
urc
e, m
atu
rity
an
d d
epo
siti
on
al
env
iro
nm
ent
in E
oce
ne
an
d P
ale
oce
ne
Fo
rma
tio
ns.
Sy
mb
ol
is f
or
Eo
cen
e C
ho
rga
li F
rma
tio
nis
fo
r E
oce
ne
Sa
kes
ar
Fo
rma
tio
n w
hil
e re
pre
sen
ts P
ale
oce
ne
Pa
tala
fo
rma
tio
n.
37
50
38
50
39
50
40
50
00
.20
.40
.60
.81
23
40
.20
.40
.60
.81
0.5
0.6
0.7
0.8
0.5
0.6
0.7
0.8
0.5
0.6
0.6
0.7
0.8
Figure-7.6: Isoprenoids vs. Sterane plot for Well-D indicting input from
carbonates and shale in Eocene, Paleocene and Early Permian
Sediments
0.1
1
10
100
0.1 1 10
Chorgali
Sakesar
Patala
A
B
C
D
A = Terrigenous OM
B = Peat Coal
C = Mixed OM
D = Aquatic OM
Maturation
Biodegradation
Oxidizing
Reducing
Prn-C17
Phn-C18
Figure-7.7: Pristane/n-C17 vs. Phytane/n-C18 plot for Eocene and Paleocene
Sediments for Oxicity and OM for Well-D
Ts
Tm
C29
C30
C31
C32
C33
C34
C35
S
S
S
S
S
R
R
R
R
R
90.980.5 81.8 83.1 84.4 85.7 87.0 88.3 89.6
Retention Time (mins)
m/z 191
8170.6 71.9 73.2 74.5 75.8 77.1 78.4 79.7
1716
15
14
1
23
4
5
6
7
13
12
11
10
8
9
Retention Time (mins)
m/z 217
Figure-7.8: Representation of mass fragmentograms m/z 191 and m/z 217for
hopanes and steranes, respectively. The details of peaks are given in
Table-7.4.
Table-7.4: Identification of hopanes and steranes using m/z 191 and m/z 217,
respectively.
Peak # Peak Name
Ts 18 (H)-22,29,30-trisnorneohopane, C27
Tm 17 (H)-22,29,30-trisnorhopane, C27,
29 17 (H),21 (H)-30-norhopane, C29
30 17 (H),21 (H)-Hopane, C30,
31S 22S 17 (H),21 (H)-homohopane,C31,
31R 22R 17 (H),21 (H)-homohopane,C31,
32S 22S 17 (H),21 (H)-bishomohopane,C32,
32R 22R 17 (H),21 (H)-bishomohopane,C32,
33S 22S 17 (H),21 (H)-trishomohopane,C33,
33R 22R 17 (H),21 (H)-trishomohopane,C33,
34S 22S 17 (H),21 (H)-tetrakishomohopane,C34,
34R 22R 17 (H),21 (H)-tetrakishomohopane,C34,
35S 22S 17 (H),18 (H)-pentakishomohopane,C35,
35R 22R 17 (H),21 (H)-pentakishomohopane,C35
1 20S 13 ,17 -diacholestane, C27,
2 20R 13 ,17 -diacholestane, C27,
3 20S 24-methyl-13 ,17 -diacholestane, C28, (24 (S+R))
4 20R 24-methyl-13 ,17 -diacholestane, C28, (24 (S+R)
5 20S 5 , 14 ,17 -cholestane, C27,
6 20R 5 ,14 ,17 -cholestane, C27,
7 20S 5 ,14 ,17 -cholestane, C27,
8 20R 5 ,14 ,17 -cholestane, C27,
9 20R 24-ethyl-13 ,17 -diacholestane, C29,
10 20S 24-methyl-5 ,14 ,17 -Cholestane, C28,
11 20R 24-methyl-5 ,14 ,17 -cholestane, C28,
12 20S 24-methyl-5 ,14 ,17 -cholestane, C28,
13 20R 24-methyl-5 ,14 ,17 -cholestane, C28,
14 20S 24-ethyl-5 14 ,17 -cholestane, C29,
15 20R 24-ethyl-5 ,14 ,17 -cholestane, C29,
16 20S 24-ethyl-5 ,14 ,17 -cholestane, C29,
17 20R 24-ethyl-5 ,14 ,17 -cholestane, C29,
(ii) Eocene Sakesar Formation
Limestone Eocene Sakesar formation showed good quantity of OM as shown by
TOC (2.46- 3.21 wt %), S1 (1.88-3.34mg/g) and S2 (6.74-10.62mg/g) (Figure-7.1, i-iii,
Table-7.2). SPI values (2.64-4.27) indicated moderate potential for oil expulsion (Peters
and Cassa, 1994). OM quality and expelled product was assessed with help of HI and
S2/S3 values. HI values (331-274 mg HC/TOC) showed contribution of mixed type-II
and type-III Kerogen. S2/S3 ratio (2.49-5.56) supported mainly gas production of
sediments. Presence of Type-II/III OM was also confirmed by plotting HI vs. OI data
(Bordenave, 1993; Tissot and Welte, 1984) (Figure-7.2). Thermal maturity was assessed
using the Tmax and PI data. Most of sediments have same level of thermal maturity i.e.
Tmax is 442°C which showed that the sediments were at early mature stage (Figure-7.1,
vii). PI data (Figure-7.1, viii) also support this early maturity as PI values were below
0.25 (Peters and Cassa, 1994). A plot between Tmax and HI gave clear picture about the
nature and maturity of OM (Figure-7.3). Figure-7.3 showed that the sediments were
within the early mature region having mixed OM i.e. type-II/III. Presence of inert
Kerogen was analyzed by plotting TOC vs. S2 data (Figure-7.4). It can be seen from
Figure-7.4 that all sediments were within very good to excellent category. Inert Kerogen
was absent in most of the samples however traces of migrated hydrocarbons were
detected in samples having S1/TOC values very close to 1.00 (Smith and Perez-Arlucea,
1994).
Biomarker parameters of Eocene Sakesar formation were not very much different
from the Eocene Chorgali formation. Pr/Ph values within the range of 0.21-0.71 (Figure-
7.5, i, Table-7.3) indicating anoxic depositional environment of sediments (Peters et al.,
2005b). Sterane vs. Iso-prenoids plot (Figure-7.6) showed lithology of sediments as
anoxic carbonates except in S-8 which was at the boarder line of shale and carbonates.
Pr/n-C17 vs. Ph/n-C18 cross plot (Figure-7.7) indicated that most of sediments contained
mixed OM deposited under reducing conditions although S-6 may have some aquatic
OM. Steranes vs. hopanes ratios were low (<0.6) except in S-9 which had high value
(2.88) indicating poor prokaryotic input in OM (Figure-7.5, ii, Table-7.3).
Diasterane/sterane values were low which suggested anoxic clay-poor/carbonates
sediments as source rock of OM having high pH and low Eh (Figure-7.5, iii). C27/C29
sterane ratios indicated mixed OM in most of the sediments. Thermal maturity based on
22S/(22S+22R) ratio (0.53-0.56) and Ts/(Ts+Tm) ratio (0.47-0.53) suggested that
samples were at early oil generation stage. /( + ) ratio (0.57-0.61) and
20S/(20S+20R) values (0.48-0.55) showed that the most of sediment are within the early
oil generation window. In carbonate source rocks expulsion is reached before the
equilibrium compared to shale source rock therefore these sediments have equilibrium
before the onset of significant.
(iii) Paleocene Patala Formation
Patala Formation showed significant source rock potential i.e. TOC (3.32-3.63
wt%), S1 (4.08-4.19mg/g) and S2 (13.01-16.15mg/g) values were within very good to
excellent range (Peters and Cassa, 1994). SPI values suggested the Paleocene Patala
formation has moderate potential for hydrocarbon expulsion (Peters and Cassa, 1994).
HI values (392-445 mg HC/g TOC) indicated good quality of OM i.e. Type-II/III with
dominance of Type-II as values of HI were high. Plot of HI vs. OI (Figure-7.2) showed
that most of sediments fall in upper portion of type-II Kerogen region indicated the
dominance of type-II which is oil prone where S2/S3 (7.52-16.01) confirmed the oil
generation potential of Paleocene Patala formation. As Paleocene Patala formation is a
potential source rock in upper Indus Basin so this type of dominance was expected. Tmax
values were within a narrow range and above the onset of generation i.e. 439-441°C and
PI values (0.2-0.24) also indicate mature sediments (Figure-7.1 vii-viii, Table-7.2). A plot
of Tmax vs. HI further supported mature nature of OM (Figure-7.3). It can be seen from
Figure-7.3, that all sediments were within mature region and contained OM derived from
type-II/III Kerogen. A plot of TOC vs. S2 indicated the absence inertinite (Figure-7.4) as
all sediments fall within excellent category (Peters and Cassa, 1994). Migrated
hydrocarbons were indicated as S1/TOC values were above 1.00.
Biomarker parameters e.g. Pr/Ph values were low (0.38-0.64) as generally in
marine carbonate source rocks (Figure-7.5, i, Table-7.3). The cross plot of Pr/(Pr+Ph) vs.
Diasterane/(Diasterane+Sterane) supported that anoxic carbonates were present (Figure-
7.6). Sterane/hopane ratio ( 1) indicated the mixed contribution of OM (Table-7.3). The
ratio of C27/C29 steranes (0.86-1.19) and relative distribution of C27-C29 steranes also
showed the mixed (marine and land plant) OM in sediments. Diasterane/sterane ratios
were in the range of 0.14-0.46, which indicated the absence of clay rich sediments
necessary for the conversion of steranes or their precursors to diasteranes. The sediments
were clay poor/carbonates under high pH and low Eh conditions (Figure-7.5, iii). Various
parameters based on isomerization ratios of hopane and sterane were used to access the
maturity of sediment of Paleocene Patala sediments. 22S/(22S+22R) values (0.52-0.54)
and Ts/(Ts+Tm) ratio (0.47-0.65) indicated that the sediments were at oil generation
window (Figure-7.5, vii, Table-7.3). In carbonate source rocks expulsion is reached
before the equilibrium compared to shale source rock therefore these sediments have
equilibrium before the onset of significant. 20S/(20S+20R) values (0.45-0.51) and
/( + ) values (0.56-0.61) and respective plots suggested that oil generation stage
had reached. These values together with Tmax (439-441°C) suggested that these source
rocks have begin to generate hydrocarbons.
7.3.2. WELL-E
(i) Eocene Chorgali Formation
Carbonate sediments of Eocene Chorgali Formation showed excellent quantity of
OM as indicated by TOC (2.80-3.21 wt %), S1 (2.11-3.32mg/g) and S2 (8.62-10.62mg/g)
values (Figure-7.9, i-iii, Table-7.5). SPI values (1.24-1.53) indicted that the sediments
have moderate potential for generation of hydrocarbons (Peters and Cassa, 1994). HI
(294-331 mg HC/ g TOC) and S2/S3 (4.03-5.62) values indicated mixed organic matter
i.e. Type-II/III (Table-7.5, Figure-7.9, v-vi). The cross plot of HI vs. OI (Figure-7.10)
further supported that the sediment contained OM derived from mixed sources.
Sediments have a narrow range of Tmax values i.e. 440-442°C which indicated maturity of
sediments. PI values (0.18-0.25) also supported maturity stage. To get the better view of
nature and maturity of OM, a plot of HI vs. Tmax was used (Figure-7.11). Sediments fall
within a region of mature stage with having oil generation ability in mixed OM, as shown
in Figure-7.11. TOC vs. S2 plot indicted that the sediments were in very good to
excellent category (Figure-7.12). Inert OM was absent but traces of migrated
hydrocarbon were indicated as S1/TOC values were nearly to 1.00 in the middle of
formation.
Table-7.5: Rock-Eval and TOC data based on various parameters to access
quality, quantity and thermal maturity of organic matter in Eocene,
Paleocene Sediments of Well-E.
Depth Sediment
I.D.
TOC
(%)
S1a S2
a S3
b S1+S2
a SPI
c S2/S3 HI
d OI
e Tmax
(°C)
PI S1/TOC
Eocene Chorgali Formation
4655 S-14 3.17 2.11 9.32 2.31 11.43 1.25 4.03 294 73 441 0.18 0.67
4662 S-15 3.10 3.21 9.61 1.92 12.82 1.41 5.01 310 62 440 0.25 1.04
4672 S-16 3.21 3.32 10.62 1.89 13.94 1.53 5.62 331 59 440 0.24 1.03
4685 S-17 2.87 2.89 8.89 1.91 11.78 1.30 4.65 310 67 442 0.25 1.01
4688 S-18 2.80 2.72 8.62 1.87 11.34 1.24 4.61 308 67 442 0.24 0.97
Eocene Sakesar Formation
4697 S-19 2.46 1.93 6.72 2.71 8.65 2.04 2.48 273 110 442 0.22 0.78
4704 S-20 3.40 4.11 13.59 0.85 17.70 4.20 15.99 400 25 439 0.23 1.21
4716 S-21 3.61 4.19 15.31 1.32 19.50 4.63 11.60 424 37 439 0.21 1.16
4720 S-22 3.32 4.11 13.01 1.73 17.12 4.06 7.52 392 52 440 0.24 1.24
4728 S-23 3.63 4.02 16.15 1.81 20.17 4.79 8.92 445 50 441 0.20 1.11
Paleocene Patala Formation
4820 S-24 3.07 3.12 9.62 1.72 12.74 6.41 5.59 313 56 442 0.24 1.02
4828 S-25 2.92 3.33 10.92 1.37 14.25 7.17 7.97 374 47 442 0.23 1.14
4860 S-26 3.21 3.31 10.89 2.53 14.20 7.17 4.30 339 79 445 0.23 1.03
4884 S-27 3.22 3.7 11.12 2.35 14.82 7.47 4.73 345 73 442 0.25 1.15
4887 S-28 3.28 3.93 12.63 2.02 16.56 1.65 6.25 385 62 441 0.24 1.20
Early Permian Sardhai Formation
5300 S-29 3.25 3.61 11.52 1.79 15.13 1.51 6.44 354 55 440 0.24 1.11
5305 S-30 1.89 1.12 4.12 2.08 5.24 0.52 1.98 218 110 440 0.21 0.59
5310 S-31 2.11 1.9 6.12 2.13 8.02 0.80 2.87 290 101 441 0.24 0.90
5312 S-32 2.80 2.12 7.82 2.77 9.94 0.99 2.82 279 99 442 0.21 0.76
5316 S-33 2.81 2.51 8.19 2.16 10.70 1.07 3.79 291 77 440 0.23 0.89
a = mg HC/g rock, b = mg CO2 /g rock, c = kg HC/ton rock, d = mg HC/ g TOC,
e = mg CO2/g TOC
4650
4750
4850
4950
5050
5150
5250
5350
12
34
12
34
52
46
810
12
14
16
18
510
15
20
200
400
600
510
15
20
430
440
450
460
470
00.2
0.4
0.6
iT
OC
iiii
iiv
vv
iv
iiv
iii
S1
S2
S1
+S
2H
IS
2/S
3T
ma
xP
I
Qu
ali
tyQ
uan
tity
Th
erm
al
Matu
rity
Fig
ure
-7.9
: G
eoch
emic
al
Wel
l L
ogs
for
Wel
l-E
, sh
ow
ing q
uali
ty, q
uan
tity
an
d t
her
mal
matu
rity
of
org
an
ic m
att
er i
n E
oce
ne,
Pale
oce
n a
nd
Earl
y P
erm
ian
Form
ati
on
s.
Sy
mb
ol
is f
or
Eo
cen
e C
ho
rga
li F
rma
tio
nis
fo
r E
oce
ne
Sa
kes
ar
Fo
rma
tio
n
rep
rese
nts
Pa
leo
cen
e P
ata
la f
orm
ati
on
wh
ile
.
is f
or
Ealr
y P
erm
ian
Sard
hai
Form
ati
on
Ch
org
ali
Sakesar
Pata
la
Sard
hai
0
100
200
300
400
500
600
700
0 50 100 150 200
Type-I
Type-II
Type-III
OI
HI
Chorgali
Sakesar
Patala
Sardhai
Figure-7.10: Modified Van Krevelan diagram for classification of kerogen type in
Well-E sediments.
Chorgali
Sakesar
Patala
Sardhai
0
100
200
300
400
500
600
700
800
900
1000
400 420 440 460 480 500
Type-I
Type-II
Type-III
0.5% Ro
1.35% Ro
HI
OI
Oil Window
Condensate
Wet gas
Dry gas
Figure-7.11: Tmax vs. HI plot showing the classification and thermal maturity of OM
0
10
20
30
40
04
81
21
6
Ex
ce
lle
nt
Po
or
Fa
ir
Go
od
Ve
ry G
oo
d
02468
10
01
23
4
Ch
org
ali
Sa
ke
sa
r
Pa
tala
Sa
rdh
ai
Fig
ure
-7.1
2:
To
tal O
rgan
ic C
arb
on
(w
t%)
vs. S
2 (
mg
/g)
plo
t fo
r th
e q
uality
of
org
an
ic m
att
er
in E
ocen
e, P
ale
ocen
e a
nd
Earl
y P
erm
ian
Fo
rmati
on
in
Well-E
TO
C
S2
Ta
ble
-7.6
: B
iom
ark
ers
da
ta b
ase
d o
n v
ari
ou
s p
ara
met
ers
to a
cces
s q
ua
lity
, q
ua
nti
ty a
nd
th
erm
al
ma
turi
ty o
f o
rga
nic
ma
tter
in
Eoce
ne,
Pa
leo
cen
e a
nd
Ea
rly
Per
mia
n
Sed
imen
ts o
f W
ell-
E.
Rel
ativ
e %
D
epth
(m)
Sed
imen
t
I.D
.
Pr/
Ph
P
r/
nC
17
Ph
/
nC
18
Pr/
(Pr+
Ph
)
St/
Ho
p
Dia
/St
C27
C28
C29
C27/
C29
22
S/
(22S
+22R
)
Ts/
(Ts+
Tm
)
20
S/
(20
S+
20
R)
/(+
)
Eo
cen
e C
ho
rgal
i F
orm
atio
n
4655
S-1
4
0.3
9
0.5
4
0.3
6
0.2
9
0.7
5
0.2
5
37.8
25.5
36.7
1.0
3
0.5
1
0.5
8
0.4
8
0.5
4
4662
S-1
5
0.3
3
0.4
9
0.3
3
0.2
5
0.7
6
0.1
9
37.8
28.5
33.7
1.1
2
0.5
0.5
0.5
1
0.5
5
4672
S-1
6
0.6
0.4
3
0.2
4
0.3
8
0.7
8
0.2
2
37.1
27
35.9
1.0
3
0.5
5
0.5
0.4
8
0.5
4
4685
S-1
7
0.3
3
0.2
9
0.2
1
0.2
5
0.8
5
0.2
3
38.5
25.5
36
1.0
7
0.4
7
0.4
7
0.4
3
0.5
6
4688
S-1
8
0.4
3
0.4
9
0.3
1
0.3
1
0.5
9
0.2
5
37.8
25.5
36.7
1.0
3
0.5
1
0.5
1
0.4
8
0.5
4
Eo
cen
e S
akes
ar F
orm
atio
n
4697
S-1
9
0.2
6
0.4
0.4
5
0.2
1
0.7
8
0.2
3
39.9
25.5
34.6
1.1
5
0.5
0.5
4
0.5
3
0.5
5
4704
S-2
0
0.2
1
0.7
4
0.3
3
0.1
8
0.9
7
0.2
1
39.2
28.5
32.3
1.2
1
0.5
4
0.5
0.4
7
0.5
7
4716
S-2
1
0.9
9
0.3
9
0.2
5
0.4
9
0.8
3
0.2
1
41.3
28.5
30.2
1.3
7
0.5
1
0.5
1
0.5
2
0.5
8
4720
S-2
2
0.4
3
0.3
9
0.2
6
0.3
1
0.9
0.1
9
40.6
27
32.4
1.2
5
0.5
3
0.4
5
0.4
9
0.5
3
4728
S-2
3
0.2
1
0.7
4
0.3
3
0.1
8
2.2
6
0.2
1
39.2
28.5
32.3
1.2
1
0.5
2
0.4
8
0.4
7
0.5
7
Pal
eoce
ne
Pat
ala
Fo
rmat
ion
4820
S-2
4
0.3
8
0.4
5
0.3
1
0.2
7
0.8
5
0.2
2
39.9
28.5
31.6
1.2
6
0.5
3
0.5
0.5
1
0.5
5
4828
S-2
5
0.7
9
0.3
9
0.2
4
0.4
3
1.1
5
0.1
4
42
22.5
35.5
1.1
8
0.5
1
0.5
1
0.4
6
0.5
2
4860
S-2
6
0.4
2
0.2
7
0.1
8
0.3
1.1
2
0.2
1
35.7
31.5
32.8
1.0
9
0.5
3
0.4
6
0.4
9
0.5
7
4884
S-2
7
0.3
8
0.4
5
0.3
1
0.2
7
1.1
1
0.2
6
36.4
28.5
35.1
1.0
4
0.5
0.6
3
0.4
7
0.5
4
4887
S-2
8
0.7
9
0.3
9
0.2
4
0.4
3
0.7
5
0.4
4
34.3
25.5
40.2
0.8
5
0.5
0.6
0.4
3
0.5
5
Ear
ly P
erm
ian
Sar
dh
ai F
orm
atio
n
5300
S-2
9
0.4
2
0.2
7
0.1
8
0.3
0.8
0.1
9
37.8
28.5
33.7
1.1
2
0.5
2
0.4
8
0.5
1
0.5
5
5305
S-3
0
0.3
8
0.4
5
0.3
1
0.2
7
0.6
4
0.2
2
37.1
27
35.9
1.0
3
0.5
3
0.5
0.4
8
0.5
4
5310
S-3
1
0.7
9
0.3
9
0.2
4
0.4
3
0.7
2
0.2
3
38.5
25.5
36
1.0
7
0.5
1
0.5
1
0.4
3
0.5
6
5312
S-3
2
0.4
2
0.2
7
0.1
8
0.3
0.8
8
0.2
2
35
31.5
33.5
1.0
4
0.5
1
0.4
9
0.4
7
0.5
4
5316
S-3
3
0.3
8
0.4
5
0.3
1
0.2
7
0.9
2
0.2
1
39.2
30
30.8
1.2
7
0.5
4
0.5
0.5
4
0.5
6
Pr/
Ph:
Pri
stane/
Phyt
ane
C27/C
29 S
t: C
hole
stane/
24 E
thyl
chole
stane
20R
: 2
0R
24-e
thyl 14
, 17
chole
sta
ne, C
29
Pr/
n-C
17
: P
rist
an
e/
22
S/(
22
S+
22
R):
22
S 1
7,2
1 h
om
oh
op
an
e/
: 20S
24-e
thyl 5
, 14
, 17
chole
sta
ne, C
29
Ph
/n-C
18
: P
hyt
an
e/O
cta
dec
an
e 2
0S
: 20S
24-e
thyl 14
, 17
chole
sta
ne, C
29
Dia
st/S
t: D
iast
era
ne/
Ste
ran
e
T
s: 1
8 2
2,2
9,3
0-t
risno
rho
pa
ne
Tm
: 1
7 2
2,2
9,3
0-t
risno
rho
pa
ne
Dep
th(m
)i
iii
iiiv
vvi
vii
Pr/
Ph
St/
Hop
Dia
/St
22S
/(22S
+22R
)T
s/(T
s+T
m)
20S
/(20S
+20R
)/(
+)
C29 S
t
Fig
ure
-7.1
3:
Bio
mark
er D
epth
Pro
file
s fo
r W
ell-
E, in
dic
ati
ng v
ari
ou
s p
ara
met
ers
regard
ing s
ou
rce,
matu
rity
an
d d
eposi
tion
al
envir
on
men
t in
Eoce
ne,
Pale
oce
ne
an
d E
arl
y P
erm
ian
Form
ati
on
s.
Sym
bol
is f
or
Eoce
ne
Ch
org
ali
Frm
ati
on
is f
or
Eoce
ne
Sak
esar
Form
ati
on
re
pre
sen
ts P
ale
oce
ne
Pata
la f
orm
ati
on
Sou
rce
an
d D
eposi
tion
al
En
vir
on
men
tT
her
mal
Matu
rity
is f
or
Earl
y P
erm
ian
Sard
hai
Form
ati
on
46
50
47
50
48
50
49
50
50
50
51
50
52
50
00
.20
.40
.60
.81
1.2
0.5
11
.52
2.5
0.1
0.2
0.3
0.4
0.5
0.5
0.6
0.7
0.8
0.5
0.6
0.7
0.8
0.4
0.5
0.6
0.7
0.8
0.5
0.6
0.7
0.8
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7
Anoxic Carbonates
Anoxic Shale
Suboxic Strata
PrPr+Ph
Dia(Dia+Reg)
Chorgali
Sakesar
Patala
Sardhai
Figure-7.14: Isoprenoids vs. Sterane plot for Well-E indicting input from
carbonates and shale in Eocene, Paleocene and Early Permian
Sediments
0.1
1
10
100
0.1 1 10
Chorgali
Sakesar
Patala
A
B
C
D
A = Terrigenous OM
B = Peat Coal Environm
C = Mixed OM
D = Aquatic OM
Maturation
Biodegradation
Oxidizing
Reducing
Prn-C17
Phn-C18
Sardhai
Figure-7.15: Pristane/n-C17 vs. Phytane/n-C18 plot for Eocene and Paleocene
Sediments for Oxicity and OM for Well-E
Biomarker parameters of Eocene Chorgali formation i.e. Pr/Ph (0.33-0.62)
indicated that the OM was probably deposited under anoxic depositional conditions
(Table 7.5, Figure 7.13 i) which was also supported by Iso-prenoids vs. sterane plot
(Figure 7.7). Carbonate sediments have also been indicated by SP and GR logs (Chapter-
4). Pr/n-C17 vs. Ph/n-C18 cross plot (Figure-7.14) indicated that sediments have mixed
OM deposited under anoxic conditions while diasterane/sterane ratio (0.19-0.25)
indicated anoxic clay-poor probably carbonates sediments as source rocks of OM (Peters
et al., 2005b). The steranes to hopanes ratios reflects eukaryotes (mainly algae and
vascular plants) vs. prokaryotes (bacteria) input to source rock. Steranes/hopanes ratio
(0.59-0.85) showed the presence of mixed OM (Figure-7.2, ii). The relative distribution
of C27-C29 and C27/C29 sterane ratio (1.03-1.12) also supported the mixed OM in
samples. 22S/(22S+22R) values (0.47-0.55) were lesser than the equilibrium value (0.57-
0.62) which showed early maturity within sediments (Figure-7.13, iv) which was also
supported by Ts/(Ts+Tm) ratio where values were ranging from 0.47-0.58. In carbonate
source rocks expulsion is reached before the equilibrium compared to shale source rock
therefore these sediments have equilibrium before the onset of significant.
20S/(20S+20R) ratio (0.43-0.51) showed early oil generation (Figure-7.13, vi, Table-7.6).
/( + ) ratio (0.54-0.56) supported the early oil generation in sediments of formation
(Figure-7.13, vii, Table-7.6).
(ii) Eocene Sakesar Formation
Eocene Sakesar formation, being a carbonate reservoir, contained good quantity
of OM as reflected by TOC (2.46-3.63 wt %), S1 (1.93-4.19 mg/g) and S2 (6.72-
16.15mg/g) values (Table-7.5, Figure-7.9, i-iii). SPI values (2.04-4.79) indicated
moderate potential for hydrocarbon generation and oil expulsion (Peters and Cassa,
1994). HI values (273-445 mg HC/ g TOC) indicated mixed OM i.e. type-II/III where
S2/S3 (2.48-15.99) also supported mixed OM (Table-7.5). HI vs. OI cross plot (Figure-
7.10) showed that most of the sediments have type-II although type-III was also
indicated. Tmax values were in oil expulsion zone and PI values (0.2-0.24) also supported
the maturity stage in sediments (Figure-7.9, vii-viii, Table-7.5). Tmax vs. HI plot (Figure-
7.11) indicated the dominance of type-II over type-III with oil expulsion stage of OM.
The cross plot of TOC vs. S2 (Figure-7.12) indicated the sediments were in very good to
excellent category. No inert OM was observed but the presence of migrated hydrocarbon
was indicated (Table-7.5).
Biomarker parameters of Sakesar formation i.e. Pr/Ph (0.21-0.99), Pr/n-C17
(0.40-0.74) and Ph/n-C18 (0.26-0.45) indicated anoxic carbonates may be present in
sediments (Table-7.6). The cross plots of diasterane/(diasterane+sterane) vs. Pr/(Pr+Ph)
(Figure-7.14) and Pr/n-C17 vs. Ph/n-C18 (Figure-7.15) indicated that mixed OM was
present under anoxic carbonate depositional environment except in S-19 which showed
aquatic OM. Steranes/hopanes ratios (0.78-2.26) also indicated mixed OM (Figure-7.13,
ii, Table-7.6) while diasterane/sterane values (0.19-0.23) indicated anoxic clay-
poor/carbonates with high pH and low Eh (Figure-7.13, iii). Relative distribution of C27-
C29 and C27/C29 ratio (1.21-1.37) supported the presence of mixed OM with carbonate
lithology (Figure-7.13, iv). 22S/(22S+22R) ratio (0.5-0.54) and Ts/(Ts+Tm) ratio (0.45-
0.54) indicated that the sediments have reached the early oil generation stage (Figure-
7.13, v, vii, Table-7.6). In carbonate source rocks expulsion is reached before the
equilibrium compared to shale source rock therefore these sediments have equilibrium
before the onset of significant. /( + ) ratio (0.53-0.58) and 20S/(20S+20R) values
(0.47-0.53) indicated early oil generation in the sediments (Figure-7.13, viii, Table-7.6).
(iii) Paleocene Patala Formation
Paleocene Patala Formation showed good quantity of OM as suggested by TOC
(2.92-3.28 wt %), S1 (3.12-3.93 mg/g) and S2 (9.62-12.63 mg/g) values (Figure-7.9 i-iii,
Table-7.5). SPI values showed moderate to high potential for hydrocarbon generation and
sediments were at oil expulsion. Such high OM and hydrocarbon potential was a feature
of Paleocene Patala formation as being potential source rock of Potwar Basin. HI values
(313-385 mg HC/g TOC) indicated the dominance of type-II Kerogen while S2/S3 also
supported the dominance of type-II (Figure-7.9, v-vi, Table-7.5). The cross plot of HI vs.
OI (Figure-7.10) confirmed the dominance of type-II over type-III Kerogen. Type-II is oil
prone OM and its presence in Paleocene Patala formation, is the characteristic of
potential source rock of Potwar Basin. Tmax values were close to each other and fall in oil
expulsion zone except in S-26 where Tmax value was at the borderline of early to peak
mature zone i.e. 445°C. PI values (0.23-0.25) indicated the maturity sage of sediments
(Peters and Cassa, 1994). The cross plot of Tmax vs. Hi (Figure-7.11) showed that the
sediments fall under oil expulsion zone and contain type-II OM as major contributor to
hydrocarbons. A cross plot of TOC vs. S2 (Figure-7.12) indicated that the sediments were
form very good to excellent in category. Inert Kerogen was absent but migrated
hydrocarbons were indicated.
Biomarkers parameters of Paleocene Patala formation i.e. Pr/Ph (0.38-0.79), Pr/n-
C17 ratio (0.27-0.45) and Ph/n-C18 ratio (0.17-0.31) indicated anoxic carbonates may be
present (Table-7.6) Carbonates were also indicated by SP log and GR log.
Diasterane/(diasteran+sterane) vs. Pr/(Pr+Ph) and Pr/n-C17 vs. Ph/n-C18 cross plots
indicated that dominance of mixed OM under reduced carbonate depositional
environment (Figure-714 & 15). Relative abundance of C27-C29 and C27/C29 ratio
(0.85-1.26) indicated predominance of mixed OM (Figure-7.13, iv-v). 22S/(22S+22R)
ratio (0.5-0.53) and Ts/(Ts+Tm) ratio (0.46-0.63) indicated that most of sediments were
at early oil generation stage (Figure-7.13, vi-vii). In carbonate source rocks expulsion is
reached before the equilibrium compared to shale source rock therefore these sediments
have equilibrium before the onset of significant. 20S/(20S+20R) ratio (0.43-0.51) and
/( + ) values (0.52-0.57) ratios supported the early oil generation in sediments of
formation.
(iv) Early Permian Sardhai Formation
Early Permian Sardhai Formation has good to very good category of OM (Peters
and Cassa, 1994) as indicated by TOC (1.89-3.25 wt %), S1 (1.12-3.61 mg/g) and S2
(4.12-11.52 mg/g) values (Figure-7.9, i-iii, Table-7.5). SPI values (0.52-1.51) indicate
low potential for hydrocarbon generation (Peters and Cassa, 1994). Quality of OM was
analyzed by using HI and S2/S3 data. HI values (218-354 mg HC/ g TOC) indicated the
presence of mixed OM i.e. type-II/III. S2/S3 values (1.98-6.44) indicated that both oil
and gas potential of sediments. The cross plot of HI vs. OI (Figure-7.10) also suggested
the dominance of type-III. Tmax values (440-442°C) were close to each other and fall in
oil expulsion zone similarly PI values (0.21-0.24) also supported the maturity in
sediments. A cross plot of Tmax vs. HI (Figure-7.11) were used to get a clear idea of
maturity and nature of OM. it can be seen from Figure-7.11, that the sediments were
within early maturity zone with dominance of type-III OM. TOC vs. S2 plot (Figure-
7.12) indicated that the sediments were in good to very good category. Inert Kerogen was
absent and no migrated hydrocarbon was present except S-29 which showed some traces
of migrated hydrocarbon.
The biomarker data for samples of Ealy Permian Sardhai formation was in
confirmation with Rokc-Eval data. Pr/Ph values (0.38-0.79) indicated anoxic depositional
environment of sediments (Figure-7.13, 1, Table-7.6). The cross plot of
diasterane/(diasterane+sterane) vs. Pr/(Pr+Ph) ratios (Figure-7.14) supported the anoxic
carbonate in this unit. Pr/n-C17 ratios (0.27-0.45), Ph/n-C18 ratios (0.17-0.30) and their
cross plot (Figure-7.15) indicated mixed OM under reducing marine carbonates
depositional environment. Diasterane/sterane ratios (0.19-0.23) showed sediments were
clay-poor/carbonate rich with high pH and low Eh conditions (Figure-7.13, iii). The
relative distribution of C27-C29 steranes and C27/C29 ratios (1.03-1.27) indicated the
presence of mixed OM within carbonates (Figure-7.13, iv, Table-7.6). Thermal maturity
assessed based on isomers of sterane and hopanes. 22S/(22S+22R) (0.51-0.54),
Ts/(Ts+Tm) ratios (0.48-0.51), 20S/(20S+20R) ratios (0.43-0.51) and /( + ) ratios
(0.54-0.56) supported that the sediments were within the zone of hydrocarbon (both oil
and gas) generation (Table-7.6). In carbonate source rocks expulsion is reached before
the equilibrium compared to shale source rock therefore these sediments have
equilibrium before the onset of significant. In carbonate source rocks expulsion is
reached before the equilibrium compared to shale source rock therefore these sediments
have equilibrium before the onset of significant.
7.3.3. WELL-F
(i) Eocene Chorgali formation
Eocene Chorgali Formation contained good amounts of OM indicated by TOC
(2.92-3.22 wt %), S1 (3.12-3.72 mg/g), and S2 (9.61-11.13mg/g) values (Figure-7.16, i-
iii, Table-7.7). SPI values (1.3-1.46) suggested the low potential for hydrocarbons
generation. HI (313-374 mg HC/g TOC) and S2/S3 (4.33-7.97) values suggested the
presence of mixed OM i.e. type-II/III. HI vs. OI plot (Figure-7.17) indicated that the
sediments have dominance of type-II Kerogen which is oil prone nature. Thermal
maturity of sediments was analyzed using Tmax and PI data. Tmax (442-445°C) values
were close to each other and within the oil expulsion zone (Figure-7.16, vii). PI data
(0.23-0.25) also supported oil expulsion and maturity of sediments. A cross plot of Tmax
vs. HI (Figure-7.18) clearly indicated the presence of type-II/III Kerogen and with
sediments at maturity region. Inert Kerogen was absent (Figure-7.19) and sediments were
in very good to excellent category (Peters and Cassa, 1994). Migrated hydrocarbons were
present as S/TOC values were above 1.00 in sediment samples (Table-7.7).
Biomarker parameters of Eocene Chorgali formation had Pr/Ph (0.33-0.62), Pr/n-
C17 (0.29-0.56) and Ph/n-C18 (0.24-0.36) ratios indicated mixed OM deposited under
anoxic carbonate depositional environment (Figure-7.20, i, Table-7.8).
Diasterane/(diasterane+staerane) vs. Pr/(Pr+Ph) plot also supported the predominance of
anoxic carbonates in sediments (Figure-7.21). Prokaryotic and eukaryotic OM input was
assessed using steranes/hopanes ratio (0.77-0.87) which indicated presence of mixed OM
input (Figure-7.20, ii, Table-7.8) while diasteranes/steranes ratios were low (0.22-0.25)
which suggested the anoxic clay-poor/carbonates with high pH and low Eh (Table-7.8).
Relative distribution of C27-C29 steranes and C27/C29 ratios (1.06-1.15) also supported
mixed OM input (Figure-7.20, iv, Table-7.8). 22S/(22S+22R) (0.48-0.57), Ts/(Ts+Tm)
(0.48-0.52), 20S/(20S+20R) (0.45-0.53) and /( + ) (0.58-0.6) ratios indicated early
maturity and expulsion of hydrocarbon in sediments. In carbonate source rocks expulsion
is reached before the equilibrium compared to shale source rock therefore these
sediments have equilibrium before the onset of significant.
Table-7.7: Rock-Eval and TOC data based on various parameters to access
quality, quantity and thermal maturity of organic matter in Eocene,
Paleocene and Early Permian Sediments of Well-F.
Depth Sediment
I.D.
TOC
(%)
S1a S2
a S3
b S1+S2
aSPI
cS2/S3 HI
dOI
e Tmax
(°C)
PI S1/TOC
Eocene Chorgali Formation
4029 S-34 3.07 3.12 9.61 1.72 12.73 1.30 5.59 313 56 442 0.25 1.02
4033 S-35 2.92 3.34 10.92 1.37 14.26 1.46 7.97 374 47 442 0.23 1.14
4041 S-36 3.21 3.33 10.91 2.52 14.24 1.46 4.33 340 79 445 0.23 1.04
4046 S-37 3.22 3.72 11.13 2.35 14.85 1.52 4.74 346 73 442 0.25 1.16
Eocene Sakesar Formation
4070 S-38 3.28 3.89 12.62 2.03 16.51 3.38 6.22 385 62 441 0.24 1.19
4073 S-39 3.25 3.61 11.49 1.79 15.1 3.10 6.42 354 55 440 0.24 1.11
4123 S-40 1.89 1.13 4.09 2.08 5.22 1.07 1.97 216 110 440 0.22 0.60
4130 S-41 2.11 1.89 6.12 2.13 8.01 1.64 2.87 290 101 441 0.24 0.90
Paleocene Patala Formation
4168 S-42 2.82 2.13 7.82 2.77 9.95 0.59 2.82 277 98 442 0.21 0.76
4173 S-43 2.81 2.53 8.23 2.16 10.76 0.64 3.81 293 77 440 0.24 0.90
4176 S-44 3.01 3.12 9.52 3.73 12.64 0.76 2.55 316 124 440 0.25 1.04
4180 S-45 3.17 2.14 9.33 2.32 11.47 0.68 4.02 294 73 441 0.19 0.68
Early Permian Sardhai Formation
4215 S-46 3.13 3.21 9.62 1.92 12.83 0.96 5.01 307 61 440 0.25 1.03
4227 S-47 3.21 3.34 10.62 1.93 13.96 1.04 5.50 331 60 440 0.24 1.04
4233 S-48 2.87 2.89 8.92 1.91 11.81 0.89 4.67 311 67 442 0.24 1.01
4238 S-49 2.83 2.69 8.61 1.87 11.3 0.85 4.60 304 66 442 0.24 0.95
4243 S-50 2.46 1.92 6.73 2.71 8.65 0.65 2.48 274 110 442 0.22 0.78
a = mg HC/g rock, b = mg CO2 /g rock, c = kg HC/ton rock, d = mg HC/ g TOC,
e = mg CO2/g TOC
40
20
41
20
42
200
12
34
12
34
52
46
81
01
21
41
61
85
10
15
20
20
04
00
60
05
10
15
43
04
40
45
04
60
47
00
0.2
0.4
0.6
iT
OC
iiii
iiv
vv
iv
iiv
iii
S1
S2
S1
+S
2H
IS
2/S
3T
ma
xP
I
Qu
ali
tyQ
ua
nti
tyT
her
ma
l M
atu
rity
Fig
ure
-7.1
6:
Geo
chem
ica
l W
ell
Lo
gs
for
Wel
l-F
, sh
ow
ing
qu
ali
ty,
qu
an
tity
an
d t
her
ma
l m
atu
rity
of
org
an
ic m
att
er i
n E
oce
ne,
Pa
leo
cen
an
d E
arl
y P
erm
ian
Fo
rma
tio
ns.
Sy
mb
ol
is f
or
Eo
cen
e C
ho
rga
li F
rma
tio
nis
fo
r E
oce
ne
Sa
kes
ar
Fo
rma
tio
n
rep
rese
nts
Pa
leo
cen
e P
ata
la f
orm
ati
on
wh
ile
. is
fo
r E
alr
y P
erm
ian
Sa
rdh
ai
Fo
rma
tio
n
Ch
org
ali
Sakesar
Pata
la
Sard
hai
OI
0
100
200
300
400
500
600
700
0 50 100 150 200
Type-III
HI
Chorgali
Sakesar
Patala
Sardhai
Type-I
TYpe-II
Figure-7.17: Modified Van Krevelan diagram for the classification of kerogen in
Well-F sediments
Chorgali
Sakesar
Patala
Sardhai
0
100
200
300
400
500
600
700
800
900
1000
400 420 440 460 480 500
Type-I
Type-II
Type-III
0.5% Ro
1.35% Ro
HI
OI
Oil Window
Condensate
Wet gas
Dry gas
Figure-7.18: Tmax vs. HI plot showing the classification and thermal maturity of OM
0
10
20
30
40
04
812
16
Ex
ce
lle
nt
Po
orF
air
Go
od
Ve
ry G
oo
d
8
10
01
23
4
Fig
ure
-7.1
9:
To
tal O
rgan
ic C
arb
on
(w
t%)
vs. S
2 (
mg
/g)
plo
t fo
r th
e q
uality
of
org
an
ic m
att
er
in E
ocen
e, P
ale
ocen
e a
nd
Pale
ocen
e F
orm
ati
on
in
Well-F
Ch
org
ali
Sa
ke
sa
riP
ata
laS
ard
ha
i
TO
C
S2
Ta
ble
-7.8
: B
iom
ark
ers
da
ta b
ase
d o
n v
ari
ou
s p
ara
met
ers
to a
cces
s q
ua
lity
, q
ua
nti
ty a
nd
th
erm
al
ma
turi
ty o
f o
rga
nic
ma
tter
in
Eoce
ne,
Pa
leo
cen
e a
nd
Ea
rly
Per
mia
n
Sed
imen
ts o
f W
ell-
F.
Rel
ativ
e %
D
epth
(m)
Sed
imen
t
I.D
.
Pr/
Ph
P
r/
nC
17
Ph
/
nC
18
Pr/
(Pr+
Ph
)
St/
Ho
p
Dia
/St
C27
C28
C29
C27/
C29
22
S/
(22S
+22R
)
Ts/
(Ts+
Tm
)
20
S/
(20
S+
20
R)
/(+
)
Eo
cen
e C
ho
rgal
i F
orm
atio
n
4029
S-3
4
0.4
1
0.5
6
0.3
6
0.2
9
0.7
7
0.2
5
39.2
23.8
37
1.0
6
0.5
3
0.5
9
0.5
0.5
8
4033
S-3
5
0.3
3
0.5
1
0.3
3
0.2
5
0.7
8
0.1
9
39.2
26.6
34.2
1.1
5
0.5
2
0.5
2
0.5
3
0.5
9
4041
S-3
6
0.6
2
0.4
5
0.2
4
0.3
9
0.8
0.2
2
38.5
25.2
36.3
1.0
6
0.5
7
0.5
2
0.5
0.5
8
4046
S-3
7
0.3
3
0.2
9
0.2
1
0.2
5
0.8
7
0.2
3
39.9
23.8
36.3
1.1
0.4
8
0.4
8
0.4
5
0.6
Eo
cen
e S
akes
ar F
orm
atio
n
4070
S-3
8
0.4
5
0.5
1
0.3
1
0.3
1
1.0
7
0.3
1
43.4
25.2
31.4
1.3
8
0.5
7
0.6
2
0.5
5
0.6
1
4073
S-3
9
0.2
6
0.4
2
0.4
7
0.2
1
0.8
7
0.2
8
44.8
21
34.2
1.3
1
0.5
5
0.5
3
0.5
1
0.6
1
4123
S-4
0
0.2
1
0.7
6
0.3
3
0.1
8
0.7
8
0.4
40.6
22.4
37
1.1
0.5
4
0.6
0.4
9
0.6
4130
S-4
1
1.0
1
0.4
0.2
5
0.5
1
2.8
0.1
2
38.5
25.2
36.3
1.0
6
0.5
8
0.6
0.4
8
0.5
7
Pal
eoce
ne
Pat
ala
Fo
rmat
ion
4168
S-4
2
0.4
5
0.4
1
0.2
6
0.3
1
0.9
3
0.1
4
43.4
21
35.6
1.2
2
0.5
4
0.5
2
0.4
8
0.5
6
4173
S-4
3
0.8
1
0.4
1
0.2
4
0.4
5
1.1
1
0.2
1
37.1
29.4
33.5
1.1
1
0.5
3
0.5
3
0.5
1
0.6
1
4176
S-4
4
0.4
4
0.2
7
0.1
8
0.3
1.1
7
0.2
6
37.8
26.6
35.6
1.0
6
0.5
4
0.4
7
0.4
9
0.5
8
4180
S-4
5
0.2
1
0.7
6
0.3
3
0.1
8
0.7
7
0.4
6
35.7
23.8
40.5
0.8
8
0.5
2
0.6
5
0.4
5
0.5
9
Ear
ly P
erm
ian
Sar
dh
ai F
orm
atio
n
4215
S-4
6
1.0
1
0.4
0.2
5
0.5
1
0.7
5
0.1
9
39.2
26.6
34.2
1.1
5
0.5
7
0.5
2
0.5
3
0.5
9
4227
S-4
7
0.4
5
0.4
1
0.2
6
0.3
1p
0.9
7
0.2
2
38.5
25.2
36.3
1.0
6
0.4
8
0.4
8
0.5
0.5
8
4233
S-4
8
0.3
9
0.4
7
0.3
1
0.2
7
0.7
9
0.2
3
39.9
23.8
36.3
1.1
0.5
7
0.6
2
0.4
5
0.6
4238
S-4
9
0.8
1
0.4
1
0.2
4
0.4
5
1.3
6
0.1
4
43.4
21
35.6
1.2
2
0.5
5
0.5
3
0.4
8
0.5
6
4243
S-5
0
0.4
4
0.2
7
0.1
8
0.3
1.2
1
0.2
1
37.1
29.4
33.5
1.1
1
0.5
4
0.6
0.5
1
0.6
1
Pr/
Ph:
Pri
stane/
Phyt
ane
C27/C
29 S
t: C
hole
stane/
24 E
thyl
chole
stane
20R
: 2
0R
24-e
thyl 14
, 17
chole
sta
ne, C
29
Pr/
n-C
17
: P
rist
an
e/ H
epta
dec
an
e 2
2S
/(2
2S
+2
2R
): 2
2S
17
,21
ho
mo
ho
pa
ne/
(22S 1
7,2
1 h
om
ohopane+
22R
17
,21
hom
ohopane)
: 20S
24-e
thyl 5
, 14
, 17
chole
sta
ne, C
29
Ph
/n-C
18
: P
hyt
an
e/O
cta
dec
an
e 2
0S
: 20S
24-e
thyl 14
, 17
chole
sta
ne, C
29
St/
Ho
p:
5, 14
, 17
Chole
sta
ne/1
7-H
opa
ne
Ts:
18
22
,29
,30
-trisno
rho
pa
ne
Dia
st/S
t: D
iast
era
ne/
Ste
ran
e T
m:
17
22
,29
,30
-trisno
rho
pa
ne
Dep
th(m
)i
iii
iiiv
vvi
vii
Pr/
Ph
St/
Hop
Dia
/St
22S
/(22S
+22R
)T
s/(T
s+T
m)
20S
/(20S
+20R
)/(
+)
C29 S
t
Fig
ure
-7.2
0:
Bio
mark
er D
epth
Pro
file
s fo
r W
ell-
F, in
dic
ati
ng v
ari
ou
s p
ara
met
ers
regard
ing s
ou
rce,
matu
rity
an
d d
eposi
tion
al
envir
on
men
t in
Eoce
ne,
Pale
oce
ne
an
d E
arl
y P
erm
ian
Form
ati
on
s.
Sym
bol
is f
or
Eoce
ne
Ch
org
ali
Frm
ati
on
is f
or
Eoce
ne
Sak
esar
Form
ati
on
re
pre
sen
ts P
ale
oce
ne
Pata
la f
orm
ati
on
is
for
Earl
y P
erm
ian
Sard
hai
Form
ati
on
Sou
rce
an
d D
eposi
tion
al
En
vir
on
men
tT
her
mal
Matu
rity
40
20
40
70
41
20
41
70
42
20
00
.51
1.5
12
30
.20
.40
.60
.20
.40
.60
.80
.20
.40
.60
.80
.20
.40
.60
.56
0.5
80
.60
.62
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7
Anoxic Carbonates
Anoxic Shale
Suboxic Strata
PrPr+Ph
Dia(Dia+Reg)
Chorgali
Sakesar
Patala
Sardhai
Figure-7.21: Isoprenoids vs. Sterane plot for Well-F indicting input from
carbonates and shale in Eocene, Paleocene and Early Permian
Sediments
0.1
1
10
100
0.1 1 10
Chorgali
Sakesar
Patala
A
B
C
D
A = Terrigenous OM
B = Peat Coal Environm
C = Mixed OM
D = Aquatic OM
Maturation
Biodegradation
Oxidizing
Reducing
Prn-C17
Phn-C18
Sardhai
Figure-7.22: Pristane/n-C17 vs. Phytane/n-C18 plot for Eocene and Paleocene
Sediments for Oxicity and OM for Well-F
(ii) Eocene Sakesar Formation
Eocene Sakesar formation showed good quantity of OM as reflected by TOC
(1.89-3.28 wt %), S1 (1.13-3.89 mg/g), S2 (4.09-12.62 mg/g) (Table-7.7, Figure-7.16, i-
iii). SPI values (1.07-3.38) indicated moderate potential for hydrocarbons generation. HI
(216-385 mg HC/g TOC) values indicated mixed OM i.e. type-II/III. S2/S3 (1.97-6.42)
also supported presence of mixed OM (Figure-7.16, v-vi, Table-7.7). HI vs. OI plot
(Figure-7.17) showed variation in OM input i.e. type-II and type-III are present.
Sediments were mature in nature as indicated by Tmax (440-441 °C) and PI data (0.22-
0.24) i.e. values were well within the maturity and oil expulsion stage (Peters and Cassa,
1994). A cross plot of Tmax vs. HI (Figure-7.18) indicated Type-II/III OM with maturity
in sediments. TOC vs. S2 plot (Figure-7.19) showed good to excellent category of OM
while inert Kerogen, which was absent. S1/TOC ratio indicated the presence of traces of
migrated hydrocarbons (Table-7.7).
Biomarker parameters of Eocene Sakesar formation i.e. Pr/Ph values (0.21-1.01),
Pr/n-C17 (0.4-0.76) and Ph/n-C18 (0.25-0.47) ratios indicated mixed OM which is
deposited under anoxic carbonate depositional environment (Figure-7.20, i, Table-7.8).
Diasterane/(diasterane+sterane) vs. Pr/(Pr+Ph) ratio (Figure-7.21) indicated that anoxic
carbonates were present in sediments while the cross plot of Pr/n-C17 vs. Ph/n-C18
supported the mixed OM under anoxic condition although S-39 showed aquatic OM.
Eukaryotic and prokaryotic OM input was assessed using sterane/hopane ratio (0.78-2.8)
which supported the mixed OM input (Figure-7.20, ii, Table-7.8). Relative concentration
of C27-C29 steranes and C27/C29 ratios (1.06-1.38) indicated that mixed OM was
dominant in sediment except in S-38 which showed marine OM input. 22S/(22S+22R)
(0.57-0.58), Ts/(Ts+Tm) (0.0.53-0.62), 20S/(20S+20R) (0.48-0.55) and /( + )
(0.57-0.61) ratio indicated early maturity of sediments which is due to carbonated
Lithology. In carbonate source rocks expulsion is reached before the equilibrium
compared to shale source rock therefore these sediments have equilibrium before the
onset of significant.
(iii) Paleocene Patala Formation
Paleocene Patala formation showed good quality of OM as reflected by TOC
(2.82-3.17 wt%), S1 (2.13-3.12 mg/g) and S2 (7.82-9.52 mg/g) values (Figure-7.16, i-iii,
Table-7.7). Although this formation is potential source rock of upper Indus basin but the
SPI values (0.59-0.76) were very low indicating low potential for hydrocarbons. Low SPI
and good TOC values were due to lateral drain system (Peters and Cassa, 1994). HI (277-
316 mg HC/g TOC) values (Table-7.7) showed the presence of mixed OM i.e. type-II/III
Kerogen which was also indicated by the S2/S3 values (2.55-4.02). HI vs. OI plot
(Figure-7.17) indicated the presence of mixed OM. Tmax and PI were used for the thermal
maturity assessment of sediments (Figure-7.16, vii-viii, Table-7.7). Tmax values were very
close to each other (440-442 °C) and indicated the maturity for sediments (Peters and
Cassa, 1994). PI values (0.19-0.25) also supported maturity in sediments. Tmax vs. HI plot
(Figure-7.18) indicated the maturity with mixed OM i.e. type-II/III. TOC vs. S2 plot
(Figure-7.19) indicated that the sediments were very good in quality and no inert Kerogen
was indicated. Some traces of migrated hydrocarbons were indicated by S1/TOC ratio
(Table-7.7).
Biomarker parameters of Paleocene Patala formation i.e. Pr/Ph (0.22-0.81), Pr/n-
C17 (0.27-0.76) and Ph/n-C18 (0.18-0.33) ratios indicated mixed OM deposited under
anoxic carbonate depositional environment (Figure-7.20, i, Table-7.7).
Diasterane/(diasterane+sterane) vs. Pr/(Pr+Ph) plot (Figure-7.21) also supported the
anoxic carbonate presence in formation. Prokaryotic vs. eukaryotic input of OM was
analyzed using steranes/hopanes ratio (0.77-1.17) which indicated presence of mixed OM
(Figure-7.20, ii, Table-7.7) while diasterane/sterane ratios (0.14-0.46) indicated the
contribution from clay lithology which was also indicated by the SP and GR logs.
C27/C29 (0.88-1.22) ratio indicated presence of mixed OM while relative distribution of
C27-C29 steranes also supported mixed OM input in sediments. 22S/(22S+22R) (0.0.52-
0.54) and Ts/(Ts+Tm) ratio (0.47-0.65) indicated that sediments have reached early oil
generation stage (Table-7.8). In carbonate source rocks expulsion is reached before the
equilibrium compared to shale source rock therefore these sediments have equilibrium
before the onset of significant. 20S/(20S+20R) (0.45-0.51) and /( + ) ration (0.59-
0.61) indicated that sediments showed early oil generation (Figure-7.20, viii, Table-7.8).
(iv) Early Permian Sardhai Formation
Early Permian Sardhai formation showed good quantity of OM as indicated by
TOC (2.46-3.21 wt %), S1 (1.92-3.34 mg/g) and S2 (6.73-10.62mg/g) values (Figure-
7.16, i-iii, Table-7.7). SPI values were low (0.65-1.04) indicating low potential for
hydrocarbons generation. High TOC and low SPI indicate lateral drain system (Peters
and Cassa, 1994). HI (271-331 mg HC/g TOC) and S2/S3 (2.49-5.5) showed the presence
of mixed OM with dominance of type-II Kerogen (Table-7.7). A cross plot of HI vs. OI
(Figure-7.17) showed that the sediments contain mixed OM. Thermal maturity of
sediments was analyzed using Tmax and PI data (Figure-7.16, vii-viii, Table-7.7). Tmax
values (440-442 °C) were within a narrow range and indicate maturity and oil expulsion
in sediments while PI values (0.22-0.25) also supported maturity in sediments. A cross
plot of Tmax vs. HI (Figure-7.18) indicated that all sediments were mature and have ability
to expel hydrocarbons (both liquid and gas). Inert Kerogen was absent as shown in cross
plot of TOC vs. S2 (Figure-7.19). This plot further added that the sediments were in very
good category. Traces of migrated hydrocarbon were present in the upper portion of
formation as suggested by S1/TOC (Table-7.7).
Biomarker parameters of Early Permian Sardhai formation i.e. Pr/Ph (0.39-1.01),
Pr/n-C17 (0.27-0.47) and Ph/n-C18 (0.18-0.31) ratio indicated mixed OM deposited
under anoxic carbonate depositional environment (Figure-7.20, i, Table-7.8). The cross
plots of Diasterane/(Diasterane+Sterane) vs. Pr/(Pr+Ph) and Pr/n-C17 vs. Ph/n-C18
supported the mixed OM with carbonate environment under reducing conditions (Figure-
7.21 & 22). Steranes/hopanes (0.75-1.36) ratios showed the presence of mixed OM while
diasterane/sterane ratio was low (0.14-0.23) which indicated anoxic clay-poor/carbonates
with high pH and low Eh values (Figure-7.20, iii, Table-7.8). C27/C29 ratios (1.06-1.22)
and relative abundance of C27-C29 steranes indicated the presence of mixed OM.
22S/(22S+22R) (0.48-0.57) and Ts/(Ts+Tm) (0.48-0.62) indicated that the sediments
were early mature while 20S/(20S+20R) (0.45-0.53) and /( + ) (0.56-0.61) ratios
also supported early oil generation stage in sediments under study. In carbonate source
rocks expulsion is reached before the equilibrium compared to shale source rock
therefore these sediments have equilibrium before the onset of significant.
7.4. CONCLUSIONS
The sedimentary sequences comprising of Eocene Chorgali, Eocene Sakesar,
Paleocene Patala and Early Permian Sardhai formation were analyzed geochemically
using TOC, Rock-Eval and Biomarker parameters. Both biomarker and Rock-Eval data
supplement each other. The following conclusions were drawn;
The sediments of marine carbonates of Eocene Chorgali formation were organic
rich (TOC: 2.81-3.22 wt %) and good to very good in terms of expelled and remaining
hydrocarbon potential (S1: 2.11-3.72 mg/g; S2: 7.79+10.92 mg/g). The OM derived from
type-II/III kerogen was deposited under anoxic conditions. The sequence has sufficient
quantity of high quality OM and adequate thermal maturity to expel both liquid and
gaseous hydrocarbons.
The carbonates of Eocene Sakesar formation also showed good quantity of mixed
(Type-II/III) OM derived from land plants and marine planktons. The depositional
conditions were highly anoxic. The sediments have maturity about the same as in Eocene
Chorgali formation and have expelled moderate quantity of both liquid and gaseous
hydrocarbons.
The sedimentary sequence of Paleocene Patala formation is proven source rocks
in the study area. These sediments are good to very good in terms of organic richness and
genetic potential. The type, quantity of OM and thermal maturity is not much different
from Eocene Chorgali and Sakesar formations. However, these sediments have more
potential for liquid hydrocarbons.
The sediments of Early Permian Sardhai formation possess very good quantity of
type-II/III OM. The OM is thermally mature and showed moderate potential for both
liquid and gaseous hydrocarbons.
Chapter-8
DIAMONDOIDS AND BIOMARKERS: AS A TOOL TO BETTER DEFINE THE
EFFECTS OF THERMAL CRACKING AND MICROBIAL OXIDATION ON
OILS/CONDENSATES FROM RESERVOIRS OF THE UPPER INDUS BASIN,
PAKISTAN
ABSTRACT
The present study examined crude oils and condensates from 12 productive oil
field zones present in the Upper Indus Basin, Pakistan, located at 33°11 00 N to
33°56 00 N and 73°10 00 to 73°56 00 E. These crude oils and condensates belonged to
Eocene, Paleocene, and Jurassic ages. GC and GC-MS parameters revealed that these
samples were mature and contained marine and algal/ bacterial organic matter sources
from an oxidizing environmental/ dysoxic environment. The total methyladamantanes/
admantane ratio varied from 4.05 to 15.25 and showed increasing levels of microbial
oxidation. The diamantane/adamantane ratio varied from 1.14 to 3.06, and total
methyldiamantanes/diamantane ratio also supports the results. The degree and
classification of microbial oxidation in different crude oils and condensates were best
defined by plotting American Petroleum Institute gravity versus diamondoid
concentrations. Diamondoid parameters indicated a maturity of samples but the levels of
maturity were different based on the particular diamondoid maturity parameter used,
which varied considerably. This study further demonstrated that utilization of both
biomarkers and diamondoids provided the best approach for determining the maturity
level of crude oils and condensates.
Keywords: Diamondoids, Biomarker, Microbial oxidation, Thermal maturity, Upper
Indus Basin, Pakistan
8.1. INTRODUCTION
In petroleum, compounds exhibit differences in their resistance to microbial
oxidation. More specifically, it is the relative susceptibility of different compound classes
(e.g., n-alkanes, branched alkanes, alkylated monocyclic alkanes, bicyclic terpanes,
steranes, diasteranes, hopanes, alkylated benzenes, alkylated biphenyls, polycyclic
aromatic hydrocarbons) to microbial oxidation that in part, collectively determines such
differences in bulk petroleum stability ((Alexander et al., 1983; Armanios et al., 1992;
Bennett et al., 2006; Connan, 1984; Gough and Rowland, 1990; Illich et al., 1977; Peters
and Moldowan, 1991; Seifert et al., 1979; Trolio et al., 1999). Diamondoids are of
particular importance in petroleum geochemistry since they can provide valuable
information toward achieving a better understanding of petroleum systems in sedimentary
basins. Unfortunately, little information is available about the implications of diamondoid
signatures in petroleum reservoirs (Grice et al., 2000; Trolio et al., 1999; Wei et al., 2007;
Williams et al., 1986). Diamondoids are cage hydrocarbons occurring naturally in
petroleum in varying abundance with a substituted and unsubstituted homologous series
of lower diamondoids, including adamantanes, diamantanes and triamantanes (Grice et
al., 2000). They are rigid, fused-ring alkanes with diamond-like structures and unique
thermal stabilities (Wei et al., 2007). Diamondoids are more stable than most
hydrocarbons and once formed, are resistant to thermal and biological destruction
(Wingert, 1992). Their formation from polycyclic hydrocarbon precursors, probably
catalyzed by a strong Lewis acid catalyst, is driven by accompanying increases in their
thermodynamic stability (Wingert, 1992). Although the concentrations of these
compounds are often very low, they are widely distributed in crude oils and source rocks.
Diamondoid concentrations increase under conditions that cause thermal
degradation of most other compounds in crude oil; or chemical oxidation, such as
thermochemical sulphate reduction, is also responsible for losses of these non-
diamondoid compounds (Dahl et al., 1999). However, some work has suggested that
some diamondoids, such as adamantane (A), is also subject to microbial oxidation (Dahl
et al., 1999; Grice et al., 2000). Nevertheless, most ‘‘normal’’ oils with low maturity and
no cracking typically have high concentrations of biomarkers and extremely low
concentrations of diamondoids (Wei et al., 2007). Conversely, in highly cracked oils,
concentrations of diamondoids are generally very high and biomarkers are extremely low
or in some cases totally absent (Trolio et al., 1999). This suggests that any oil with high
abundances of both diamondoids and biomarkers should reflect a mixture of low maturity
oil and highly cracked sources (Wei et al., 2007). However, alteration of diamondoid
moieties in advanced stages of oil microbial oxidation in some reservoirs have been
reported (Grice et al., 2000). Thus, microbial oxidation could eventually reduce
diamondoid concentrations in highly biodegraded oils, while selective microbial
oxidation of biomarkers could increase their concentrations. Variations in the thermal
stability of methyl-substituted diamondoids have lead to the use of certain isomer ratios
as maturity parameters for crude oils and source rocks, especially at high overmature
stages of hydrocarbon generation (Chen et al., 1996). For example, 1-methyl-
adamantane (1-MA) is more stable than 2-methyl-adamantane (2-MA) and 4-
methyldiamantane (4-MD) is more stable than 1-methyldiamantane (1-MD) and 3-
methyl-diamantane (3-MD). Hence, the ratios 1-MA/(1-MA + 2-MA) and 4-MD/(1-MD
+ 3-MD + 4-MD) should increase with increasing thermal stress (or depth). In other
words, the higher the ratio, the higher the maturity of the oils and source rocks.
Consequently, it has been proposed that diamondoid hydrocarbon ratios can be used as
maturity indices for overmature crude oils and source rocks (Chen et al., 1996). Based on
the aforementioned chemical indices, the primary goal of this study was for the first time
to use diamondoids and biomarkers to examine crude oils and condensates, collected
from 12 productive oil field zones in the Upper Indus Basin, Pakistan.
8.2. GEOLOGY AND STUDY AREA
The study area is located to the southeast of Islamabad in Potwar Plateau, Upper
Indus Basin, Pakistan. The oil fields are located between latitude33°11 00 N to
33°56 00 N and 73°10 00 to 73°56 00 E (Fig. 1; Table 1). This depression has several
features that make it a favorable site for hydrocarbon accumulations. Located on a
continental margin, the depression is filled with thick deposits of sedimentary rocks,
including potential source reservoir and cap rock. It contains a thick overburden (about
3,000 m) of fluvial sediments, which provides the burial depth and optimum geothermal
gradient for seeps found in this area (Khan et al., 1986). The details on the geology of this
area have been reported in other studies (Ahmad et al., 2003; Benchilla et al., 2002;
Fazeelat et al., 1999; Fazeelat et al., 1994, 1995; Fazeelat et al., 2010; Fazeelat and
Yousaf, 2004; Grelaud et al., 2002; Robison et al., 1999; Wandrey et al., 2004; Wasim,
2004). More specifically, further details on these particular study sites along with the
geological setting can be found in Fazeelat et al. (2010) and Jalees et al. (2010).
8.3. EXPERIMENTAL
Twelve different samples of crude oils and condensates were selected for
chemical analyses. These oils are from Eocene, Paleocene and Jurassic reservoirs; details
about geological ages and formation are provided in Table 1. Column chromatography
Elemental sulphur was removed (Blumer, 1957) before fractionating samples. Sulphur
free samples were dissolved in n-hexane and fractionated into saturates (alkanes),
aromatics, and NSO (nitrogen, sulphur, and oxygen) fractions, using a glass column (40 9
0.9 cm i.d.) with activated silica gel (Fazeelat and Yousaf, 2004). The fractions were
recovered by careful evaporation of the solvent on a sand bath, followed by removal of
residual solvent with nitrogen gas. The samples were collected in pre-weighed vials and
quantified; the results are shown in Table 1.
8.3.1. Gas Chromatography
The saturated fractions (mg of sample/10 µL of solvent) obtained by liquid
chromatography were then analyzed using capillary gas chromatography (GC) with a
flame ionization detector (FID). GC-FID analyses of the saturated fractions were carried
out using a Shimadzu 14B series Gas Chromatograph, equipped with FID, and a 30 m x
0.25 mm (i.d.) film thickness 0.25 µm fused silica capillary column, coated with methyl
silicone (OV-1). Each sample (1 µL) was injected in splitless mode using a glass syringe
through a rubber septum into the column. The FID detector and injector temperatures
were maintained at 300 and 280 °C, respectively. The oven temperature was programmed
to ramp from 60 to 300 °C at 4 °C/min, with a 5 min hold time. Nitrogen was used as
carrier gas with a linear velocity of 2 mL/min. Further details on data collection, where
peak retention times occurred between 0 and 66 min are provided by (Asif, 2010).
8.3.2. Gas Chromatography–Mass Spectrometry
GC–MS analysis was performed using a Hewlett–Packard (HP) 5973 mass
selective detector (MSD) interfaced to a HP 6890 N gas chromatograph. The column
used was a 30 m x 0.25 mm ID capillary column coated with a 0.25 µm 5% phenyl 95%
methyl polysiloxane stationary phase (DB-5 MS, J&W scientific). 1 µL sample of the
saturated fraction (1 mg/ mL in n-hexane) was introduced into the split/splitless injector
using the HP 6890 N auto sampler. The injector was operated at 280 in pulsed splitless
mode. Helium maintained at a constant flow rate of 1.1 mL/ min was used as carrier gas.
The GC oven was programmed from 40 to 310 °C at 3 °C/min with an initial and final
hold time of 1 and 30 min, respectively. The transfer line between the GC and the MSD
was held at 310 °C. The MS source and quadrupole temperatures were at 230 and 106 °C,
respectively. Data were acquired in full scan mode from 50 to 550 amu, with the MS
ionization energy 70 eV and the electron multiplier voltage 1,800 V. The identification of
compounds peaks are shown in Fig. 2. The details of method can be found in (Asif et al.,
2009).
8.3.3. Isolation of Branched and Cyclic Alkanes
A saturated fraction obtained by liquid chromatography separation was used to
isolate branched and cyclic alkanes from straight chain alkanes. The saturated fraction
(up to 15 mg) in cyclohexane (1–2 mL) was added to a 2 mL auto sampler vial quarter
filled (2 g) with activated 5A° molecular sieves. The auto sampler vial was capped and
placed into pre-heated aluminum block (85 °C) for at least 8 h. The resulting mixture was
filtered through a small column of silica (5.5 x 0.5 cm i.d.) and rinsed thoroughly with
cyclohexane. The cyclohexane containing branched/cyclic alkanes were collected in pre-
weighed vials. The removal of excess cyclohexane under a slow stream of nitrogen
yielded the branched and cyclic fractions (Asif et al., 2009).
8.3.4. Recovery of Straight Chain Alkanes from Molecular Sieves
The molecular sieve containing n-alkanes were air dried and transferred to a 20
mL Teflon tube. n-Hexane (2–3 mL) was then added to cover the sieves along with 1 mL
of milli-Q water. The mixture was homogenized with a magnetic stirrer while being
placed in an ice bath. Hydrofluoric acid (50%, 20–30 drops) was added drop wise while
stirring until the sieve had dissolved (45–50 min). The excess HF was neutralized by
adding saturated solution of sodium bicarbonate while stirring. The n-alkanes from sieves
were dissolved in n-hexane and separated by passing through a small column of
anhydrous magnesium sulfate. The aqueous mixture was further extracted with pentane
(ca. 3 x 1 mL). Excess pentane was removed carefully using sand bath (50 °C) (Asif,
2010).
Fig. 2 TIC of Balkasar, Balkasar Oxy and Dhakni oil well sample
8.3.5. Diamondoid Analyses Using Selected Ion Monitoring Mode
Diamondoid analyses were carried out using a Hewlett-Packard (HP) 5973 mass
selective detector (MSD) interfaced to a HP 6890 N gas chromatograph (GC). A 30 m x
0.25 mm ID capillary column coated with a 0.25 µm 5% phenyl 95% methyl
polysiloxane stationary phase (DB-5 MS, J & W scientific) was used for the analysis.
1µL of the saturated fraction (1 mg/mL in n-hexane) was introduced into the
split/splitless injector using the HP 6890 N auto-sampler. The oven temperature was
programmed to increase from 20 to 294 °C at a rate of 4 °C/min and was held at the final
temperature for about 30 min. The mass spectrometer generated positive ions by electron
impact at 70 eV. The ion source was maintained at 200 °C. Ion chromatograms were
obtained by selective ion monitoring (SIM), using 20 masses and a 70 ms dwell time for
each mass. The transfer line between the GC and the MSD was held at 294 °C. The MS
source and quadrupole temperatures were at 210 and 106 °C, respectively. Mass spectra
were obtained by scanning from 30 to 450 amu at a rate of about 1.2 s per scan.
Identification of different derivatives of diamondoids is provided in Fig. 3 and Table 2.
8.4. RESULTS AND DISCUSSION
The samples represent a suite of different types of oils and condensates with
different levels of biodegradation. The general characterizations of these crude oils from
the Indus Basin Pakistan are shown in Table 1. These assigned categories were made on
the basis of API° gravity, GC-FID analysis and UCM (unresolved complex mixture) of
aliphatic hydrocarbon fractions along with diamondoid and biomarker analysis.
8.4.1. Depositional Environment and Organic Matter
The major factors largely responsible for the alteration of petroleum composition
are source, maturation, migration and microbial oxidation. The ratios of iso-prenoids to
n-paraffins are often used to determine oil-to-source correlation, maturation, and levels of
microbial oxidation (Connan et al., 1980). Pristane (Pr)/n-C17 and phytane (Ph)/n-C18
ratios were used for analyzing organic matter, depositional environment and maturation.
Values less than 1.0 are an indication of non-biodegraded oils (Connan et al., 1980). Both
Pr/n-C17 and Ph/n-C18 decrease with maturation due to the increasing prevalence of n-
paraffins (Hunt, 1979). The ratios of the sample for all the oils/condensates were less than
1.0 and which revealed a generally mature character (Table 3). Pr/Ph ratios used to assess
paleoredox conditions of this depositional environment (Connan et al., 1980) indicated
ratios greater than 1.0 for all crude oils/ condensates indicative of oxidizing conditions or
this depositional environment.
Fig. 3 The base ion peak chromatogram of the adamantanes (m/z 136 and CnH2n-5
series), diamantanes (m/z 188 and CnH2n-9 series) and triamantanes (m/z 240
and CnH2n-13 series). The peaks are identified in Table 3
Table-8.2: Diamondoids identified in crude oil/condensate samples
Peak
No.
Tentative Assignment of Peaks Abbreviation M+ Base Peak
1 Adamantane A 136 136
2 1-Methyladamantane 1,MA 150 135
3 2-Methyladamantane 2, MA 150 135
4 1-Ethyladamantane 1 EA 164 135
5 2-Ethyladamantane 2 EA 164 135
6 1,3_Dimethyladamantane 1,3 DMA 164 149
7 1,4-Dimethyladamantane, cis 1,4 DMA (cis) 164 149
8 1,4-Dimethyladamantane, trans 1,4 DMA (trans) 164 149
9 1,2-Dimethyladamantane 1,2 DMA 164 149
10 1-Ethyl-3-methyladamantane 1E,3,MA 178 149
11 1,3,5Trimethyladamantane 1,3,5 TMA 178 163
12 1,3,6_Trimethyladamantane 1,,3,6, TEA 178 163
13 1,3,4_Trimethyladamantane, cis 1,3,4, TEA (cis) 178 163
14 1,3,4-Trimethyladamantane, trans 1,3,4, TEA (trans) 178 163
15 1-Ethyl-3,5-dimethyladamantane 1E,3,5,DMA 192 163
16 1,3,5,7-Tetramethyladamantane 1,3,,5,7 TtMA 192 177
17 1,2,5,7-Tetramethyladamantane 1,2,5,7 TtMA 192 177
18 Diamantane D 188 188
19 4-Methyldiamantane 4 MD 202 187
20 1-Methyldiamantane 1,MD 202 187
21 3-Methyldiamantane 3,MD 202 187
22 4,9_Dimethyldiamantane 4,9 DMD 216 201
23 1,4 and 2,4_Dimethyldiamantane 1,4 & 2,4 DMD 216 201
24 4,8-Dimethyldiamantane 4,8 DMD 216 201
25 3,4_Dimethyldiamantane 3,4 DMD 216 201
26 Trimethyldiamantane TMD 230 215
27 Triamantane T 240 240
28 9-Methyltriamantane 9,MT 254 239
29 Dimethyltriamantane DMT 268 253
A plot of Pr/n-C17 versus Ph/n-C18 provided further information about past
organic matter inputs to this system, which appeared to be mainly derived from aquatic
algal and bacterial sources in a marine environment/dysoxic conditions (Figs. 4, 5). The
ratio of 30-nor-hopane/hopane (30Nor-Hop/Hop) (Peters et al., 2005a) also supported
that organic matter inputs were dominated from inputs from algal and bacterial sources
(Table 3). Figure 2 shows representative total ion chromatogram (TIC) of three samples;
total abundance of the diamondoids in each sample is shown in Table 3. Unresolved
complex mixtures (UCM) were present in all oils and condensates; low molecular weight
alkanes were absent.
8.4.2. Diamondoids
Diamondoids were analyzed and identified by GC–MS. All diamondoids were
identified by comparison of their mass spectra and relative retention time with reported
literature values (Chen et al., 1996; Wingert, 1992). Adamantanes, diamantanes, and
triamantanes, which were present in all the crude oils, were examined using m/z 135,
136, 149, 163, and 177 ions (adamantanes); m/z 187, 188, and 201 ions (diamantanes);
m/z 240, 239, and 253 ions (triamantantes) (Fig. 3 and Table 3). The plot between
diamondoids versus API° gravity (Fig. 6) showed that the Balkasar Oxy, Balkasar and
Fimkasar sites had high concentrations of diamondoids, likely due to cracking of high
molecular compounds (HMC) and decreases in API° gravity. In the Ratana, Khaur,
Karsal and Dhulian sites, the reverse trend was observed with less cracking which
resulted in fewer diamondoids and a higher API° gravity. Finally, the Meyal, Pariwali,
Pindori and Dhurnal sites showed a different trend with high API° values and
diamondoid concentrations which suggested that these samples were mixed.
Diamondoids are some of the most abundant resolved components present in the
saturated hydrocarbon fraction in biodegraded oils and heavy oils (Grice et al., 2000).
However, diamondoids are also formed by the cracking of polycyclic compounds present
in the crude oils/condensates (Wei et al., 2007). This cracking generally decreases the
American Petroleum Institute (API°) gravity of the oils and increases the diamondoid
concentrations. Therefore, it seems that any normal oils with high API° gravity and no
cracking have a low abundance of diamondoids and those with low API° gravity and high
cracking have a high abundance of diamondoids (Wei et al., 2007). The situation
becomes complex when considering maturity, which is also based on cracking (e.g.,
cracking of kerogen and HMC).
Fig. 4 Base ion chromatogram of hopanes (m/z 191 and CnH2n-8 series)
Fig. 5 Organic matter classification of sample analyzed (modified after Hunt 1979)
Fig. 6 Plot between API° gravity and total diamondoids concentration showing
effect of cracking
8.4.3. Maturity
The thermal maturity of the admantane (A) is different from its methyl
derivatives, methyladamantane (1-MA) and 2-methyladamantane (2-MA) (Grice et al.,
2000). Since the thermal stability of 1-MA is greater than 2-MA, the ratio of 1-MA/(1-
MA + 2-MA) increases with maturity (Grice et al., 2000). A similar trend is observed
with diamantane and its methyl derivatives, 1-methyldiamantane (1-MD), 3-
methyldiamantane (3-MD) and 4-methyldiamantane (4-MD), where 4-MD is more stable
than the other two derivatives (Grice et al., 2000). A plot between 1-MA/(1-MA + 2-MA)
versus 4-MD/(1-, + 2-, + 3- MD), showed that most samples had a high maturity level
(Fig. 7). The Balkasr Oxy, Ratana and Dhulian sites showed minimum levels of maturity,
while Khaur, Balkasar were at the highest level of maturity. Dhurnal, Karsal, Meyal,
Pindori, Fimkasar and Dhakni showed very complex trends and maturity levels could not
be determined. All are formations considered to be mature show values of 4-MD/ (1-, +
3-, + 4-MD) that ranged from 38 to 75%, with 1-MA(1-, + 2-MA) values similar, but
generally less than 40%. This suggested that while the 1-MA and 4-MD were thermally
stable, their relative stabilities were different. Such a comparison between two maturity
indices is complex and requires the use of biomarkers for a valid interpretation.
Fig. 7 Plot between maturity parameters i.e. 1-4MD/(1-, + 3-, + 4MD) x 100 versus
1-MA/ (1-, + 2-MA) x 100, showing relative thermal stability of the
methylated diamondoid derivatives
Ts and Tm are tris-norhopanes whereby, Ts is more thermally stable than Tm; this
allows the Ts/(Ts + Tm) ratio to be used as another index of maturity. The maturity range
for this index starts from about 0.5, which is very close to 1-MA/(1-, + 2-MA) maturity
value of 40%. A plot between Ts/(Ts + Tm) versus 1-MA/(1-, + 2-MA) provided a more
clear picture of the maturity level. The Ratana, Dhulian, Khaur, Dhurna, Pariwali, Meyal,
Fimkasar, Dhakni sites were all mature oils, while Balkasar Oxy, Balkasar, Karsal and
Pindori were only near the mature oil window (Fig. 8). These results suggested that the
1-MA/(1-, + 2-MA) ratio alone should not be used as a maturity parameter in the absence
of additional biomarker information. For example, the 22S/(22S + 22R) values ranged
from 0.49 to 0.52 indicative of a moderate maturity level, while the 30 Nor-hopane/hop
and 31 homohopane/hopane both indicated the same level of maturity and showed a
range of 1.57–1.79 and 0.93–0.97, respectively (Table 3).
Fig. 8 Plot between biomarker parameters and diamondoid maturity parameter
index for the relative thermal stability of the sample analyzed
8.4.4. Microbial Oxidation
Methyl derivatives of diamondoids showed more resistance microbial oxidation
than the diamondoids (Grice et al., 2000). This was evidenced by the ratio of
methyladamantanes (MA) (relatively low susceptibility) to the n-C11 alkane (relatively
high susceptibility) (Table 3). Increasing microbial oxidation was reflected by increases
in the ratio of MA/n-C11 alkanes. For example, the range of ratios increased from 0.12
(Balkasar Oxy) to 0.47 (Balkasar). As might be expected, mixed oils, multiple oil
accumulations, and microbial oxidation events were probably components of this ratio.
Also, changes in relative abundances of MA to adamantine (A) and methyldiamantanes
(MD) to diamantine (D) occurred with microbial oxidation; the MA/A ratios of samples
are shown in Table 3. This ratio varied from 4.05 to 15.25, with two exceptions for
Ratana and Dhulian which had values of 84.65 and 27.65, respectively. This exception in
Ratana and Dhulian was likely due to removal of adamantane from oil and condensates.
Many factors were associated with the removal of the admantane but the most important
were biodegradation and oxidation. Adamantane is easily oxidized and biodegraded,
while its derivatives are much stable (Chen et al., 1996; Grice et al., 2000). Diamantanes
and triamantanes were also more stable than adamantane due to an increase in the number
of carbon rings. Therefore, here we suggest that variations in MA/A ratios were directly
affected by changes in the concentrations of the adamantane. Since adamantanes were
most susceptible to microbial oxidation in all diamondoids, only a minor amount of
microbial oxidation can result in significant variation in the MA/A ratios. The ratio of
MA/A clearly increased with microbial oxidation, while the ratio between diamantane
and its methyl derivative did not vary much (from 2.14 to 8.34). Since diamantane is
more stable than adamantine, even Ratana showed a value of 8.34 which was more
biodegraded with a MA/A value of 84.65. Diamantane/adamantane ratio can also be used
as an index of microbial oxidation (Wei et al., 2007). As adamantane is more susceptible
than diamantine, so their ratio increases with increasing levels of microbial oxidation.
These oils and condensates in this study varied from 1.14 to 3.06 with exception for
Ratana with 41.5, Dhulian with 14.55 and Balkasar Oxy with 14.37. Dhulian and
Balkasar Oxy values were not as high as compared with Ratana, but microbial oxidation
levels were higher than in other samples; Ratana had the highest level of microbial
oxidation. Alkyladamantane and alkyldiamantane were more stable than the adamantane
and diamantane, respectively. The ratio between adamantane and its methyl derivatives
indicated the extent of the microbial oxidation. In these samples, this ratio ranged from
17 to 40.76, with exception for Ratana (176.56) and Dhulian (70.34), which likely had
high levels of microbial oxidation. The ratio between diamantane and its methyl
derivatives in these samples did not vary much (5.88–18.68) due to the stability of
diamantane.
8.5. CONCLUSIONS
Iso-prenoids and iso-prenoids to n-alkane ratios showed that all the samples were
mature and have oxidizing depositional environment. Marine organic matter, under
marine/dysoxic conditions, was the major source. UCM was present in all the samples
and low molecular weight alkanes were also absent. Cracking of high molecular
weight compounds and high concentration of diamondoids were present in Balkasar
Oxy, Balkasar and Fimkasar. Conversely, Ratana, Khaur, Karsal and Dhulian had the
reverse trend.
Balkasr Oxy, Ratana and Dhulian had minimum levels of maturity, while Khaur,
Balkasar were at high level of maturity. A plot between Ts/(Ts ? Tm) versus 1-
MA/(1-, + 2-MA) showed that Ratana, Dhulian, Khaur, Dhurna, Pariwali, Meyal,
Fimkasar, Dhakni were all in mature oil window, while Balkasar Oxy, Balkasar,
Karsal and Pindori were only near the mature oil window.
With increasing microbial oxidation, the ratio of MA/ n-C11 alkane increases from
0.12 (Balkasar Oxy) to 0.47 (Balkasar). The lower the ratio, the lower will be
microbial oxidation and vice versa.
Removal of adamantine from samples made MA/A ratio of samples highly variable
so need of alternative parameter is required.
The results suggest that cracked, uncracked and mixed oils and condensates are
present in this region of Pakistan.
References
141
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