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

 

 

 

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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

 

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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

 

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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

 

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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

 

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DEDICATED

To

My Family

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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.

 

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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)

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

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4650

4700

4750

4800

4850

-80

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Ch

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4045

4065

4085

4105

4125

4145

4165

-80

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020

iii

3750

3800

3850

3900

3950

4000

4050

-80

-60

-40

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Ch

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Sakesar

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Well-D

Well-E

Well-F

Fig

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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

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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

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7

0.5

1

0.5

1

0.5

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0.5

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4720

S-2

2

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3

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6

0.3

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0.9

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9

40.6

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32.4

1.2

5

0.5

3

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9

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3

4728

S-2

3

0.2

1

0.7

4

0.3

3

0.1

8

2.2

6

0.2

1

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1

0.5

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Pal

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7

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5

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2

39.9

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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

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5

0.5

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3

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9

37.8

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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

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3

0.5

3

0.5

0.4

8

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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

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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

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24-e

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, 17

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sta

ne, C

29

Pr/

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17

: P

rist

an

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22

S/(

22

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22

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22

S 1

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oh

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an

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: 20S

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Dep

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vii

Pr/

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22S

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)T

s/(T

s+T

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+20R

)/(

+)

C29 S

t

Fig

ure

-7.1

3:

Bio

mark

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Pro

file

s fo

r W

ell-

E, in

dic

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46

50

47

50

48

50

49

50

50

50

51

50

52

50

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1.2

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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

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iT

OC

iiii

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iv

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0

100

200

300

400

500

600

700

0 50 100 150 200

Type-III

HI

Chorgali

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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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