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Ministry of Higher Education And Scientific Research University of Baghdad College of Science
Crude Oil Characterization and Source Affinities of Missan Oil
Fields, Southeastern Iraq.
A Thesis Submitted to the College of Science University of Baghdad in Partial Fulfillment of the
Requirements for the Degree of Doctor of philosophy in Geology / (Petroleum Geology)
By
FURAT ATA SALEH AL-MUSAWI M. Sc. University of Baghdad, 1997
Mars 2010 1431
The Supervisor Certification I certify that this thesis (Crude Oil Characterization and Source Affinities of Missan Oil Fields, Southeastern Iraq) was prepared under my supervision at the Department of Geology, College of Science in the University of Baghdad, in partial fulfillment of requirements for the Degree of Doctor of philosophy in Geology (Petroleum Geology).
Signature: Signature: Name: Dr. Thamer K. Al-Amiri Name: Dr. Ameen I. Al-Yasi Scientific Degree: Professor Scientific Degree: Assistant Professor Address: University of Baghdad-College of Science- Dep. of Geology.
Address: University of Baghdad-College of Science- Dep. of Geology.
Date: / /2010 Date: / /2010
Recommendation of the Head of Committee of Postgraduate Studies in Geology Department
In view of the available recommendations, I forward this thesis for debate by the examining committee.
Signature:
Name: Dr. Ahmad Shehab Al - Banna Title: Professor Address: Head Geology Department, College of Science, University of Baghdad. Date: / /2010
Committee Certification
We, the members of the Examining Committee, certify that after reading this thesis and examining the student in its contents, we think it is adequate for the award of the Degree of Doctor of Philosophy in Geology (Petroleum).
Signature: Signature: Name: Dr. Ali D. Gayara Name: Dr. Fawzi M. Al-Beyati Title: Professor Title: Assistant Professor Address: University of Baghdad-College of Science- Dep. of Geology
Address: Technical Collage. Kirkuk
Date: Date: (Chairman) (Member) Signature: Signature: Name: Dr. Muafak F. Al-Shahwan Name: Dr. Madhat E. Nasser Title: Assistant Professor Title: Assistant Professor Address: University of Basra-College of Science- Dep. of Geology
Address: University of Baghdad-College of Science- Dep. of Geology
Date: Date: (Member) (Member) Signature: Signature: Name: Dr. Thamer K. Al-Amiri Name: Dr. Hayfa A. Najem Title: Professor Title: Assistant Professor Address: University of Baghdad-College of Science- Dep. of Geology
Address: University of Baghdad-College of Science- Dep. of Geology
Date: Date: (Supervisor Member) (Member) Signature: Name: Dr. Ameen I. Al-Yasi Title: Assistant Professor Address: University of Baghdad-College of Science- Dep. of Geology
Date: (Supervisor Member)
Approved by the Deanery of the College of Science. Signature: Name: Dr. Khalid S. Al-Mukhtar Title: Professor Address: Dean of the College of Science, University of Baghdad Date:
ACKNOWLEDGEMENT
Appreciation is given to all colleagues who did their best to assist me
to accomplish my thesis. I would like to thank the Ministry of Higher
Education and Scientific Research, University of Baghdad, college of
Science, for helping me to get the joint scholarship to Stanford University,
USA.
Also so many thanks to the Department of Earth Sciences for every
thing (Teaching, Training, Guiding and encouraging).
I am delighted to acknowledge with my debts to my advisor Prof.Dr.
Thamer. k. Al-Ameri, and to my co-adviser Assistant.Prof.Dr Ameen
Ibrahim, for advising me and supplying requirements to perform this work.
I am terribly grateful to Missan Oil Company, and south oil
company, for helping me with my project, and for collecting my crude oils
and rock samples.
I appreciate the role of the oil expert Mr. Mohamad .A. jabbar in
Missan oil company for his coordination and following through out the
project.
Admiration and respect to Prof.Dr. J.K.Moldowan, Stanford
University, School of Earth Science, USA, for helping me to conduct all
my Biomarker analysis at his molecular labs.
In addition, I wish to thank Dr.K.Peters, oil expert at Schlemperge
oil company, USA for his help to interpret my result data.
Thanks to Dr.J.Dahil, oil expert at Chevron oil company, USA, for
his helps at the labs.
Special thanks to the Iraq Geosurv , Geology expert Mr.V.Sissakian,
for helping me in the project.
Great thanks to all post graduate student, Baghdad University,
Geology Department for their cooperation.
TABLE OF CONTENTS Subject Page NoTable of contents List of figures List of tables Abstract CHAPTER ONE - Introduction 1.1. Introduction 1 1.2. Previous Studies 1 1.3. Aim of Study 2 1.4. Location of Study Area 2 1.5. Materials and Methodology 4 1.5.1. Geological investigation 5 1.5.2 Geochemical investigation 5 1.5.2.1. Pyrolysis analysis 5 1.5.2.2. Vitrinite reflectance (Ro %) 7 1.5.2.3. Bitumen extraction 9 1.5.2.4. Crude oil analysis 10 1.5.2.5. Gas chromatographic analyses 11 1.5.3. Organic facies and Palynofacies investigation 17 1.6. Geological Setting 18 CHAPTER TWO - PALYNOFACIES ANALYSIS 2.1. Palynofacies And Kerogen Types 22 2.1.1. Noor-1 Well 31 2.2. Paleoenvironmenta Interpretation 34 2.3. Organic Thermal Maturation 35 2.3.1. NO-1 Well 38
CHAPTER THREE - SOURCE ROCKS EVALUATION 47 3.1. Principles of evaluation 48 3.1.1. Organic richness 48 3.1.2. Genetic type of organic matter 50 3.1.3. Thermal maturation 54 3.2. Source Rock Characterization Using Rock-Eval Pyrolysis 56 3.2.1. Sulaiy Formation 56 3.3. Source Rock Characterization Using Biomarkers 61 3.3.1. Source and Age Related Biomarker Parameters 61 3.4. Nordiacholestane and 24-Norcholestane Ratios 68 3.5. Maturity-Related Biomarker/ Non-Biomarker Parameters 72 CHAPTER FOUR- Reservoir organic geochemistry 74 4.1. Crude oil geochemistry 78 4.1.1. API gravity 78 4.1.2. Sulfur content 79 4.1.3. Crude oil compositions 80 4.1.3.1. Gas chromatographic analysis (GC) and C15 +
hydrocarbon composition 82
4.1.4. Stable carbon isotope composition (δ13 C %o) 95 4.1.5. Alkanes and Acyclic Isoprenoids 98 4.1.5.1. Pristane/Phytane 98 4.1.5.2. Terpanes and Similar Compounds 99 4.2. Maturity-Related Biomarker/ Non-Biomarker Parameters 1 4 1 CHAPTER FIVE- ORGANIC GEOCHEMICAL CORRELATION 150
5.1. Oil - Oil correlation 150 5.2. Oil - Source rock correlation 150 5.2.1. Age and Oil-Source Correlation Relevant Parameters 153
154 5.2.2. Parameters related to maturity, lithology and depositional environment
CHAPTER SIX- SUMMARY and RECOMMENDATIONS 160 6.1. Summary 160 6.1.1. Source rock evaluation 160 6.1.2. Crude Oils 161 6.2. Recommendations 163 REFERENCES 164
LIST OF FIGURES
FIGURES Page No.1.1. Location map of study area 3 2.1. Tectonic map of Iraq (After Jassim and Goff, 2006) 20 3.2. Schematic key to assist identification of dispersed
palynological organic matter in thermally immature to marginally mature sediments (Tyson, 1995)
30
4.2. Percentage distribution of particulate organic matter groups within the defined Palynofacies of the (NO-1) well 33
5.2. AOM-Phytoclast-Palynomorph ternary plot of NO-1 well (Tyson, 1995) 35
6.2. Oil and gas generation as a function of increasing sediment burial (Modified after Oehler, 1983) 37
7.2. Pearson’s (1984) color chart compared with other organic thermal maturity, TAI and Vitrinite reflectance (Modified from Traverse, 1988)
37
8.3. Geochemical characteristics TOC, S2, Tmax and Ro versus depth of Sulaiy Formation 58
9.3. HI versus OI of Sulaiy Formation (Espitalie et al., 1977) 58 10.3. Geochemical log of the NO-1 well 60 11.3. Gas chromatographs of the C15+ saturated hydrocarbons in
rock extracts for AG-2 well 63
12.3. Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for HF-2 well 63
13.3. Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for R-167 well 64
14.3. Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for AM-3 well 64
15.3. Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for NO-1 well 65
16.3. Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for R-172 well 65
17.3. Pristane /nC17 versus phytane/nC18 for source rock extracts in the study area, can be used to infer oxicity and organic matter type in the source-rock depositional environment (Peters et al., 1999; Shanmugam, 1985)
67
18.3. Cross-plot of pristane/nC17 versus phytane/nC18, showing the genetic type of organic matter for crude oil samples (Obermajer et al., 1999)
68
19.3. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (R-167)
70
20.3. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (AM-3)
71
2 1 . 3 . Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (NO-1)
7 1
22.3. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (R-172)
72
23.4. Ternary diagram showing the gross composition of crude oil samples 82
24.4. Gas chromatograms for Crude oil sample from HF-2 well 85 25.4. Gas chromatograms for Crude oil sample from AG-1 well 85 26.4. Gas chromatograms for Crude oil sample from AG-10 well 86 27.4. Gas chromatograms for Crude oil sample from AG-11 well 86 28.4. Gas chromatograms for Crude oil sample from AG-7well 87 29.4. Gas chromatograms for Crude oil sample from FQ-8well 87 30.4. Gas chromatograms for Crude oil sample from FQ-11well 88 31.4. Gas chromatograms for Crude oil sample from FQ-2well 88 32.4. Gas chromatograms for Crude oil sample from NO-2well 89 33.4. Gas chromatograms for Crude oil sample from HF-1 well 89 34.4. Gas chromatograms for Crude oil sample from AM-30well 90 35.4. Gas chromatograms for Crude oil sample from BU-13well 90 36.4. Gas chromatograms for Crude oil sample from BU-20 well 91 37.4. Gas chromatograms for Crude oil sample from BU-11 well 91 38.4. Gas chromatograms for Crude oil sample from BU-17 well 92 39.4. Gas chromatograms for Crude oil sample from FQ-3 well 92 40.4. Gas chromatograms for Crude oil sample from FQ-4 well 93 41.4. Gas chromatograms for Crude oil sample from FQ-5 well 93 42.4. Plot of pristane/nC17 versus phytane/nC18, showing organic
matter type, source rock depositional and thermal maturity of crude oil samples (Shanmugam, 1985; Peters et al., 1999)
94
43.4. Relation between the stable isotope compositions of saturates and aromatics for crude oil samples for the study area. (After Sofer, 1984)
97
44.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (HF-2,AG-1) 101
45.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (AG-10,AG-11) 102
46.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (AG-7,FQ-8) 103
47.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (FQ-11,FQ-2) 104
48.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (NO-2,HF-1) 105
49.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (AM-3,BU-13) 106
50.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (BU-20,BU-11) 107
51.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (BU-17,FQ-3) 108
52.4. Example M/Z 191 GCMS mass chromatograms for crude oil in wells (FQ-4,FQ-5) 109
53.4. M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well (AM-3) 118
54.4. M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well (HF-2) 119
55.4. M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well (FQ-5) 120
56.4. M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well (BU-11) 121
57.4. Triangular plots showing the relative concentrations of C27, C28 and C29 regular steranes for Cretaceous-Tertiary crude oil. (Huang and Meinschein, 1979; Moldowan et al., 1985)
126
58.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( HF-2)
128
59.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( AG-10)
128
60.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( AG-11)
129
61.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-8)
129
62.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-2)
130
63.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( HF-1)
130
64.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( BU-13)
131
65.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( BU-20)
131
66.4. Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26
132
steranes for crude oil sample, well( FQ-3) 67.4. Metastable reaction monitoring/gas chromatography/mass
spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-4)
132
68.4. Example GCMS mass chromatograms for crude oil sample, well (AG-7) showing m/z 253 and m/z 231 134
69.4. Example GCMS mass chromatograms for crude oil sample, well (HF-1) showing m/z 253 and m/z 231 135
70.4. Example GCMS mass chromatograms for crude oil sample, well (HF-2) showing m/z 253 and m/z 231 136
71.4. Example GCMS mass chromatograms for crude oil sample, well (FQ-5) showing m/z 253 and m/z 231 137
72.4. Ternary diagram showing the relative abundance of C27-, C28-, and C29-monoaromatic (MA) steroids in the aromatic fractions of source rock extracts determined by gas chromatography/mass spectrometery (GCMS) (m/z 253)
140
73.4. Thermal maturity of the analyzed crude oil samples based on sterane isomerizaion. Vitrinite reflectance estimates after correlations in Waples and Machihara (1990); Peters and Moldowan (1993)
147
74.5. Selected MRM for rock extracts and crude oils 155 75.5. Selected MRM for rock extracts and crude oils 156 76.5. Selected gas chromatography for rock extracts and crude
oils 157
77.5. Selected gas chromatography for rock extracts and crude oils 158
78.5. Plot of pristane/nC17 versus phytane/nC18, showing organic matter type, source rock depositional and thermal maturity of crude oil and rock extract samples (Shanmugam, 1985; Peters et al., 1999)
159
List of tables
1-1: Representative rock sample in the study area 4 2-1: Representative crude oils in the study area 4 3a: Geochemical parameters describing the petroleum potential
(quantity) of an immature source rock 7
3b: Geochemical parameters describing kerogen type (quality) and the character of expelled products 7
3c: Geochemical parameters describing level of thermal maturation 7
4-2: Semi quantitative distribution of the various (POM) recorded from the (NO-1) well. 32
5-2: Batten’s (1980) scale for palynomorphs colors (reproduced from Traverse, 1988) 38
6-3: Organic richness, Pyrolysis data and Vitrinite reflectance for Sulaiy Fm in Noor Well, Missan Oil Field 57
7-3: Extracts gas chromatographic results for six wells in South Iraq 66
8-3: A summary of biomarker characteristics using MRM-GCMS technique for extract source rocks samples for the study area
70
8-4: Crude oil liquid chromatography results for wells in the Missan Province 80
9-4: Crude oil gas chromatography results for wells in the study area 94
10-4: Gas chromatography – mass spectrometry, triterpane report (m/z 191) 110
11-4: GC/MS Parameter 111 12-4: A summary of biomarker characteristics (terpanes) for
crude oil samples in the study area 112
13-4: Sterane (m/z217) peak identification report 122 14-4: A summary of biomarker characteristics (Steranes) for
crude oils, Missan Province, South Iraq 123
15-4: A summary of biomarker characteristics using MRM-GCMS technique for crude oil samples for the study area 127
16-4: Monoaromatic steroid and triaromatic steroid biomarkers (m/z 253 and m/z 231) peak identification report 138
17-4: A summary of biomarker characteristics (Monoaromatic and Triaromatic) for crude oil samples from Missan oil fields, South Iraq
139
18-4: A summary of maturity related none/biomarker for crude oil samples for Missan oil fields 143
ABSTRACT
Twenty five (25) rock samples collected from six (6) wells, (4) of them in Missan Province [ Noor (NO-1), Amara (AM-3), Abu Gharab(AG-2),Halfaya (HF-2)] for Sulaiy Formation and the other two (2) wells from Basra Province well [ North Rumalia (R-167)] for Sulaiy Formation and well [ North Rumalia (R-172) ] for Sargelu Formation, also eighteen (18) crude oils have been collected from Cretaceous – Tertiary reservoir in Missan oil fields. Sedimentary organic matters for the Sulaiy Formation are performed in well (NO-1) for twenty rock samples optical studies for these samples have conformed the kerogen type II that generate liquid hydrocarbons, with abundance of (AOM) and offshore marine environment for Sulaiy Formation. For source rock evaluation, Pyrolysis analysis, Percentages of (TOC %), (RO %), indicate their hydrocarbon generation from Kerogen type II of marine environment. Confirmations for marine environment are performed by the ratios of Pristine to Phytane (Pr/Ph) and carbon preference index (CPI). Crude oils characterizations are prepared on eighteen (18) samples of Cretaceous- Tertiary reservoirs in Missan Province. Gas Chromatography (GC) results indicate (Pr/Ph) ratio is less than one (1), and (CPI) is also one (1) , which indicate carbonate marine environment. Source maturation could be indicating by ratios of (Ts/Tm) of low to moderate maturation. Metastable Reaction (MRM) analyses have indicated oil source age of Jurassic period. Oil – oil correlation for all Cretaceous- Tertiary reservoirs indicate one source rock that could correlate to one source rock of the Jurassic Sargelu Formation.
المستخلص
نمـوذجـا صخريـا من سـتة آبـار مختلفة، اربعة آبار منهـا في محافظة ) 25(تم جمع . [No-1, Am-3, Ag-2, Hf-2]ميسان، بئر نور وبئر عماره وبئر ابو غراب وبئر حلفايه
-R(من تكوين السلي واثنان منها استخدمت للمقارنة في محافظة البصرة، بئر رميلة الشـمالي .لتكوين الساركلو )R-172(تكوين السلي، وبئر رميلة الشمالي ل ) 167
الثالثي في محافظة ميسان –نموذجا من النفط الخام من مكامن الكريتاسي) 18(كذلك تم جمع [No-2, Am3, Hf-1, Hf-2, Fq-2, Fq-3, Fq-5, Fq-8, Fq-11, Bz-11, Bz-13, Bz-
17, Bz-20, Ag-1, Ag-7, Ag-10, Ag-11] نموذجا صخريا لدراسة المواد العضوية الرسوبية لتكوين السلي في بئر ) 20(خدم وقد است
)NO-1( حيث دلت النتائج المجهرية على سيادة المواد العضوية عديمة الشكل التركيبي ،)AON(ذات القابلية على انتاج النفوط السائلة ،
قييم الصخور المصدرية لت) NO-1(نموذجا صخريا من تكوين السلى من بئر ) 15(تم اختيار ونسب كمية الكاربون ) Pyrolysis(المولدة للنفط، حيث اشارت نتائج التكسر الحراري
، )CPI(و) Pr/Ph(وكذلك نسب ) %RO(ونسب انعكاسية الفيترينايت ) %TOC(العضوي على نشوء النفوط السائلة مكونة الكيروجين من النوع الثاني الذي يعود الى البيئة البحرية
.الكاربونيةبئرا نفطيا ) 18(عينة من النفط الخام من ) 18(تم اجراء تحليالت مواصفات النفط الخام على
الدالئل الحياتية وذلك باستخدام تحليالت) الثالثي–الكريتاسي (في محافظة ميسان ذات االعمار )Biomarker( حيث اشارت تحليالت الغاز الكروماتغرافي ،)GC ( لنسب)Pr/Ph ( الى اقل
مما يؤكد البيئة الكاربوناتية البحرية للصخور المصدرية، وقد اشارت تحليالت ) 1(من الواحد )GC/MS ( الى نفس البيئة الكاربوناتية البحرية، كما أكدت نسبة)Ts/Tm (ئ الى نضوج واط
.معتدلفقد اشارت الى ان عائدية عمر الصخور المصدرية يعود للعصر ) MRM(اما تحليالت
.الجوراسي نفط لنماذج مكامن الكريتاسي والثالثي اشارت الى عائديتها الى صخور –ان مضاهاة نفط
.مصدرية واحدة من تكوين الساركلو ذي العمر الجوراسي
العاليم وزارة التعلي
والبحث العلمي جامعة بغداد العراق ـبغداد
مواصفات النفوط الخام وعائدياتها المصدرية في حقول نفط ميسان، جنوب شرق العراق
إلىرسالة مقدمة جامعة بغدادـكلية العلوم
في علم األرضدكتوراه فلسفة وهي جزء من متطلبات نيل درجة )جيولوجيا النفط(
فرات عطاء صالح الموسوي
١٩٩٧ جامعة بغداد –ماجستير
آذار 2010
Chapter One Introduction
١
1.1. Introduction
The importance of this study is coming from no documented
biomarker indicated of the crude oils from south east of Iraq, their source
rocks, depositional environment, and hydrocarbon potentiality, age and
maturity. This study is an effort intended to answer some of these
questions. Moreover, knowing source rock as a part of the petroleum
system may enhance the process of oil exploration in the promising part of
southern Iraq.
1.2. Previous Studies
Studies have been publish on stratigraphy, paleontology and sediment
logy of the study area; however, there is no information on their burial and
temperature histories, biomarker study on the crude oils, so the following is
some out standing studies concerning this project.
1. (Buday, 1980) studies the stratigraphy and palegeography of south Iraq.
2. (Beydoun, 1992) studying briefly the regional geology and petroleum
resources of south Iraq.
3. (Al-sharhan, 1997) studies the sedimentary basin and petroleum geology
of Iraq as one of the important petroleum country in the Middle East.
4. (Sadooni, 1997) studies the petroleum prospects of upper Jurassic in
South Iraq, Sulaiy Formation.
5. (Al-Ameri,Al-Musawi,and Batten.1999) they use palynofacies as an
indications to depositional environment ,source potential for
hydrocarbon and age determination of Sulaiy formation ,southern Iraq.
6. (Al-Shahwan, 2002) studies the thermal maturity, and Basin analysis of
Lower Cretaceous- Upper Jurassic, Southern Iraq.
7. (Pitman, 2004) study the petroleum generation and migration in the
Mesopotamian basin and zagros fold belt of Iraq.
Chapter One Introduction
٢
1.3. Aim of Study
The main objectives of this study are the following:
1. An assessment and characterization of the extent, nature, and source rock
quality in the southeastern of Iraq basin.
2. An identification of the Palynofacies and outlining the depositional
environmental conditions.
3. A determination of crude oil characterization.
4. An apply of the oil – oil and oil – source rock correlation using certain
biomarkers to figure out the origin of these oils.
1.4. Location of Study Area
The selected study area is located in south east of Iraq as depicted in
figure (1-1)
Chapter One Introduction
٣
Figure (1-1) Location map of study area
Chapter One Introduction
٤
1.5. MATERIALS AND METHODOLOGY
The underlying principle for the research is derived from the realization
that there is a heterogeneous distribution of the productive wells,
hydrocarbon phases (that include crude oils with different API and sulfur
contents, depths and rates of production) in the Missan Province,
Southeastern of Iraq.
The fundamental materials used in this work include composite logs
for “representative cutting &core samples (Table 1-1), eighteen (18) crude
oil samples recovered from the main producing fields dispersed in the
studied area (Table 2-1). The Missan Oil Company and South Oil
Company (Iraq) kindly provided the required materials of this study. The
detailed methodologies of the present work were described in the following
paragraphs: Table 1-1: Representative rock sample in the study area
Rock Sample No. Field Well Core Cutting
1 North Rumaila R – 172 - 1 2 North Rumaila R – 167 1 - 3 Amara AM-3 - 1 4 Abu Gharab AG – 2 1 - 5 Halfaya HF– 2 1 - 6 Noor NO – 1 - 20
TOTAL 25 Table 2-1: Representative crude oils in the study area
No. Field Well HF-1 1 Halfaya HF-2 AG-1 AG-7
AG-10 2 Abu Gharab AG-11
3 Amara AM-3 BU-11 BU-13 BU-17 4 Buzerkan BU-20 FQ-2 FQ-3 FQ-4 FQ-5
5 Faqa
FQ-8 6 Noor No-2
TOTAL 18
Chapter One Introduction
٥
1.5.1. Geological investigation
A through review of the general geologic setting and its relation to
the hydrocarbon potential is envisaged utilizing the subsurface data
gathered from deep drilling as well as isopach, and structural contour maps
with cross sections. This review will take advantage of previously
published literature on the studied area.
1.5.2. Geochemical investigation
This study is base on data of geochemical analyses of representative
cutting and core samples, collected from different oil fields. These samples
were prepared as possible to be available for further analysis. The samples
analyzed for their organic matter contents for investigating the rock quality,
generation capability and thermal maturation level. The analyses were
carried out in the Molecular Organic Geochemistry laboratory at Stanford
University, California-US; Baseline DGSI analytical laboratories,
Houston-US.
1.5.2.1. Pyrolysis analysis
These analyses were made using the Rock-Eval version VI technique
(Espitalie et al., 1985). The Rock-Eval 6 Pyroanalyzer is considered to be
the most valuable geochemical exploration tool used to evaluate the
prospective source rock by providing information on the organic richness
(TOC, wt%), the generation capability, type of organic matter and the
thermal maturity of source rocks.
The Rock-Eval 6 analyzer is designs to improve Rock - Eval 2
technology and to increase the domain of application of the method for
source rock characterization (improved kerogen analysis and kinetic
parameters) and reservoir studies. The instrument is a completely
automated device consisting of two micro-ovens which can be heated up to
Chapter One Introduction
٦
850°C controlled by a thermocouple located in contact with the sample. An
FID detector measures the HC gas released during the Pyrolysis while an
on-line infrared cell (IR) is use to measure the quantity of CO and CO2
generated during Pyrolysis and oxidation of samples. This complementary
stage allows determination of total organic carbon (TOC) and mineral
carbon content of samples. The generated thermo-vaporized free
hydrocarbons already in the rock "S1" are released at temperatures lower
than those needed to break down the kerogen. Hence monitoring of the
hydrocarbons released by steadily increasing the temperature provides a
way of increasing the amount of generated hydrocarbons relative to the
total potential. The "S2" peak represents the genetic potential of the sample
by measuring the hydrocarbons that would generate at optimum maturity.
The "S1" and "S2" are expressed in milligrams of hydrocarbon per gram of
rock (mg HC / g rock). The "S3" peak represents the quantity of evolved
CO2 expressed in milligrams of CO2 per gram of rock (mg CO2 / g rock).
The temperature (Tmax) at which the Pyrolysis peak S2 occurs has been used
as a measure of maturity, as it increases with increasing levels of maturity.
If an independent analysis is made of the organic carbon concentration
(TOC) in the rock, two other useful parameters are obtained; the hydrogen
index (HI = S2/TOC wt %, roughly equivalent to H/C ratio in the kerogen)
and the oxygen index (OI = S3/TOC wt %, roughly equivalent to O/C ratio
in the kerogen). Espitalie et al. (1977) used the Pyrolysis yield to
differentiate between the types of organic matter by plotting the hydrogen
index or H/C against the oxygen index or O/C on modified Van Krevelen
diagram as follows:
Type I: mainly oil – prone organic matter with minor gas.
Type II: mixed oil and gas – prone organic matter.
Type III: mainly gas – prone organic matter.
Chapter One Introduction
٧
Peters and Cassa (1994) rated interpretative guidelines of source rock
evaluation; the results are summarizing in Table (1a, 1b and 1c): Table 3a: Geochemical parameters describing the petroleum potential (quantity) of an
immature source rock Organic Matter
Rock Eval Pyrolysis Bitumen Petroleum Potential TOC
(Wt %) S1 S2 (Wt %) (ppm)
Hydrocarbons
(ppm) Poor Fair Good Very good Excellent
0.0 – 0.5 0.5 – 1.0 1.0 – 2.0 2.0 – 4.0 > 4.0
0.0 – 0.5 0.5 – 1.0 1.0 – 2.0 2.0 – 4.0 > 4.0
0.0 – 2.5 2.5 – 5.0 5.0 – 10.0 10.0 – 20.0 > 20.0
0 – 0.05 0.05 – 0.10 0.10 – 0.20 0.20 – 0.40 > 0.40
0 – 500 500 – 1000 1000 –2000 2000 –4000 > 4000
0 – 300 300 – 600 600 – 1200 1200 – 2400 > 2400
Table 3b: Geochemical parameters describing kerogen type (quality) and the character
of expelled products Kerogen type HI
(mg HC / g TOC) S2 / S3 Atomic H/C Main expelled at peak maturity
I II
II/III III IV
> 600 300 – 600 200 – 300 50 – 200 < 50
> 15 10 – 15 5 – 10 1 – 5 < 1
> 1.5 1.2 – 1.5 1.0 – 1.2 0.7 – 1.0 < 0.7
Oil Oil Mixed oil + gas Gas None
Table 3c: Geochemical parameters describing level of thermal maturation
Maturation Generation Stage of thermal maturation
Ro (%)
Tmax (oC)
TAI a
Bitumen / TOC b
Bitumen (mg/g rock)
PI c [S1/(S1+S2)]
Immature Mature Early Peak Late Postmature
0.2 – 0.6
0.60 – 0.65 0.65 – 0.90 0.90 – 1.35
> 1.35
< 435
435 – 445 445 – 450 450 – 470
> 470
1.5 – 2.6
2.6 – 2.7 2.7 – 2.9 2.9 – 3.3
> 3.3
< 0.05
0.05 – 0.10 0.15 – 0.25
___
___
< 50
50 – 100 100 – 250
___
___
< 0.10
0.10 – 0.15 0.25 – 40
___
___
a TAI thermal alteration index. b Mature oil-prone source rocks with type I or II kerogen commonly show bitumen/TOC ratios in the range 0.05 – 0.25. Caution should be applied when interpreting extract yields from coals. c PI Production index.
1.5.2.2. Vitrinite reflectance (Ro %)
Vitrinite Reflectance (VR) is the most commonly used organic
maturation indicator used in the petroleum industry. Vitrinite, because it is
not strongly prone to oil and gas formation, is common as a residue in
source rocks. As coal rank increases and the chemical composition of the
Vitrinite correspondingly changes, the Vitrinite macerals (elementary
microscopic constituents of coal) can recognized by their shape,
morphology, reflectance and fluorescence. The term, which is broadly
Chapter One Introduction
٨
equivalent to minerals in rocks, becomes increasingly reflective. Therefore,
the percentage reflection of a beam of normal incident white light from the
surface of polished Vitrinite is a function of the rank (maturity) of the
macerals. The reflectivity (R) may be recorded as either Rv max% or Ro%.
Both are measurements of the percentage of light reflected from the
sample, calibrated against a material which shows ~100% reflectance (i.e. a
mirror). Because Vitrinite is 'anisotropic', reflectance will be greatest on the
bedding parallel surfaces and least on surfaces cut orthogonal to the
bedding. Surfaces cut at angles between these two extremes will have
intermediate reflectance. Consequently, under (cross) polarized light, the
reflectance of the Vitrinite macerals observed will depend upon its position
relative to the plane of polarization of the light. In cross polar, the Vitrinite
will, in a 360° rotation of the stage, have two reflectance maxima and two
reflection minima. It is the average % reflection of the two-reflectance
maxima which provides analysts with the value Rv max%. This
methodology is that of choice in Australia. In the USA and Europe, Ro% is
measured. This is simply the reflection off macerals from a normal incident
beam of non-polarized light.
Samples are separated and washed, and then mounted in resin. These
resin blocks are then ground and polished to a high standard. Poor
polishing will lead to spurious reflection measurements. Sample
preparation takes 24 hours. The blocks will obviously contain particles of
vitrinite plus other macerals (i.e. liptinites and inertinites) which will need
to be recognized and discarded {NB reflectance of these macerals may be
recorded as RL% or RI %}.The number of individual reflection
measurements is dependent on the abundance of vitrinite in the sample, but
should be on the order of 30-100 vitrinite measurements. A skilled analyst
can make these measurements in, say, 30 minutes.
The data of vitrinite reflectance (Ro%) were provided by the Baseline
DGSI analytical laboratories, Houston-US.
Chapter One Introduction
٩
1.5.2.3. Bitumen extraction
Minor amounts of substances soluble in organic solvents are associated
with kerogen; these substances are collectively called "bitumen" by some
geochemists. The followed method of bitumen extraction and analysis as
described in Peters and Moldowan (1993) was completed in the Molecular
Organic Geochemistry lab, Geological &Environmental Sciences
Department (GES) -School of Earth Sciences - Stanford University; as
follows:
a. Bitumen is extracted by pulverizing the rock (about 10-50 gm) and then
soaking the pulverized rock for 12 to 36 hr in an organic solvent. The
most common organic solvents are: dichloromethane, chloroform,
benzene-methanol, carbon disulphide and carbon tetrachloride. The
organic solvent applied in this study was dichloromethane. The solvent is
removed from the extracted bitumen by evaporation (this method of
removal results in the loss of the lighter hydrocarbons, which have
similar evaporation rate as the solvent). In practice, only hydrocarbons
heavier than carbon number C15+ are retained for further analysis. The
extracted bitumen is expressed as weight percent to the whole rock
sample.
b. Removal of elementary sulfur from extracted bitumen by copper.
c. Asphaltene was separated from the extracted bitumen using n-hexane or
pentane. The precipitated asphaltenes were then filtered off and
expressed as weight percent of the whole extracted bitumen.
d. The extract was fractionated using open-column liquid chromatography
to separate saturates, aromatics and polar (NSO or resins plus
asphaltenes) compounds, according to the following procedures:
Plug the tapered end of the glass column (29 cm long, 0.9 cm inside
diameter) with glass fiber filter paper or glass wool to retain the silica
gel, but allow the solvents to pass through.
Chapter One Introduction
١٠
Fill the column with activated silica gel [activate the silica gel (40
micron) by placing a shallow (<40 cm) layer in an uncovered
crystallizing dish or large beaker and heating in an oven at 200-250o C,
but not over 250o C, for 16 hr and store in a tightly sealed container] to a
level 25 cm from the bottom by adding a few cm at a time and tapping or
vibrating the column to pack the silica gel tightly and uniformly. Place
the packed column in a clamp or rack to hold it vertical. Mark a tared 12
ml vial at the 11ml level and place it under the column.
Accurately weigh 10 to 25 mg of the extracted sample or crude oil
sample and place it on the top of the column.
Add hexane to the top of the column to chromatograph the sample. Do
not allow the level of solvent to drop below the top of the silica gel bed.
Continue adding hexane and eluting, by gravity, until 11ml of eluate has
been collected.
Change the eluting solvent to dichloromethane.
Rinse the outside tip of the column into the hexane collection vial with a
few drops of hexane, and wipe it with a tissue.
Mark a tared 32ml vial at the 20ml level and place it under the column.
Continue adding the dichloromethane to the top of the column and
continue eluting until at least 20 ml of elute have been collected. Use
gentle pressure to assist the elution.
Rinse and wipe the outside tip of the column as before.
Evaporate the solvents from both collection vials with a gentle nitrogen
stream at 40-50o C. Reweigh the vials to determine the weights of
saturate and aromatic fractions collected.
1.5.2.4. Crude oil analysis
Crude oil samples were topped to 200o C at atmospheric pressure and
the residue over 200o C was collected and weighted. The collected crude oil
Chapter One Introduction
١١
samples were analyzed for evaluating their geochemical characteristics and
identifying their origin.
The analyses of these crude oils were based on quantitative
separation of the various structural types and determination of molecular
distribution within each type. Asphaltenes are precipitated with hexane and
the soluble fraction is separated into saturates, aromatics and resins (NSO
compounds) on a silica-alumina column by successive elution with hexane,
benzene and benzene-methanol. The solvents were evaporated and the
weight percent of each compound was accurately determined.
1.5.2.5. Gas chromatographic analyses
The gas chromatography of the saturated hydrocarbon fractions of
the extracts and crude oils was performed using a Hewlett Packard 5890
gas chromatograph fitted with a Quadrex 30 m fused silica capillary
column and a flame ionization detector (FID). Oven temperature was
programmed from 40 to 340o C at 5o C/minute with a 2 minute hold at 40o
C and a 20 minute hold at 340oC.
Analytical data are processed with a Hewlett Packard chemstation
data acquisition system and DELL computer hardware. This software
system facilitates data processing and graphic display as well as electronic
data transmittal. All standard calculations are made including
pristane/phytane ratio (Pr/Ph) , carbon preference index ( CPI), and other
key parameters.
Analyses by gas chromatography of the saturated hydrocarbons are
useful in the identification of the geochemical fossils (biomarkers) which
can be used as indicators to the organisms from which the extracts and
crude oils were derived or the digenetic circumstances under which the
organisms were buried.
Chapter One Introduction
١٢
⎥⎥
⎦
⎤
⎢⎢
⎣
⎡+
++++++++
++++++++
3432302826
3331292725
3230282624
33312927252
1CCCCCCCCCC
CCCCCCCCCC
Normal alkane (n-alkanes)
Normal alkanes are important due to their high concentration in
bitumen and crude oil and their existence in plants and high lipids. Waples
(1985) recognized that, the n-alkanes in terrestrial plants have dominant
odd number of carbon atoms, especially C23, C25, C27, C29, and C31. Fatty
acids in marine algae on the other hand are largely even carbon numbered
and yield n-alkanes having a maximum in their distribution in the range of
C17 or C22 depending on the species present with no preference for either
odd or even carbon atoms. The carbon preference index (CPI) is the
strength of the odd carbon predominance in n-alkanes (Bray and Evans,
1961). The CPI value was calculated by dividing odd carbon atoms over
even carbon atoms:
CPI =
As the maturity precedes the n-alkane chains become shorter and
diluted with new n-alkanes during catagenesis. This may produce new
chains that have no preference for odd or even carbon and makes the
carbon preference index (CPI) approach to unity. Thus, the immature
sediments have high CPI value but may not be used as an absolute source
indicator. However, the n-alkanes derived from algae may show either odd
or even carbon number preference depending on the depositional
environment. In fact, the CPI values may originally approach unity.
Isoprenoids
Isoprenoids are good indicators for the biogenic origin of the
bitumen and oils, but they are of limited value in assessing the contribution
of particular organisms (Waples, 1985). Pristane (C17) and phytane (C18)
are the most common isoprenoids used in this work (pr and ph
respectively). Their occurrences are generally associated with specific
Chapter One Introduction
١٣
depositional environment and are believed to be sensitive to diagenetic
conditions (Illich, 1983). The ratio of pristane to phytane has been used as
an indicator to the oxygen level available during diagenesis.
Pristane over phytane ratio below unity is taken as an indicator of
high reducing depositional environment and high ratios between 1 and 3
indicate oxidizing environment often associated with terrestrial origin. As
maturity proceeds phytane is generated faster than pristane, leading to a
decrease in the pristane over phytane ratio. Combining the isoprenoid and
normal alkane distributions provides valuable information about the source
of organic matter, organic facies, biodegradation and maturation level. A
good way to display these data is by plotting pristane / n-C17 against
phytane / n-C18 (Shanmugam, 1985). In this figure the trend of pristane /
phytane ratios as oxygen content indicator is along the arrows labeled
oxidizing or reducing. As maturity increases n-alkanes are generated faster
than isoprenoids, resulting in a decrease in isoprenoid / n-alkane ratio and
regression along the line toward the origin. In contrast, biodegradation
removes n-alkanes faster. In that case, the isoprenoid / n-alkane ratio
increases away from the origin.
Gas chromatography / mass spectrometry analysis (GC / MS)
Subsamples of whole oil or bitumen and separated fractions are
always taken for auxiliary geochemical analyses, such as gas
chromatography, stable carbon isotope, sulfur content, and API gravity.
Internal standards added to the separated saturated and aromatic fractions
facilitate quantitation of chromatographic peaks and determine whether
further treatment is necessary before GCMS analysis (Peters et al., 2005).
Many laboratories add 5β-cholane to the saturate fraction as an
internal standard for sterane and terpane measurements before all GCMS
analyses (Seifert and Moldowan, 1979). 5β-cholane is not found in
significant abundance in crude oils, does not interfere with the indigenous
Chapter One Introduction
١٤
compounds, and fragments to give the same principal ion
(mass/charge=m/z 217 by the same mechanism as other steranes.
In this study, the saturate fractions were spiked with a known
quantity of 5β-cholane and treated with high Si/Al ZSM-5 zeolite
(silicalite) to remove all of the normal alkanes and increase the signal of
more diagnostic biomarkers; as follow:
Normal paraffins will be absorbed into the pores of silicalite which are
about 6 angstroms in diameter. The sample must be dissolved in a solvent
which is larger than the silicalite pore size. Isooctane is the preferred
solvent.
Small column procedure
Place a small piece of glass wool in the bottom of a 5 3/4 inch Pasteur
pipette and tamp it down. If it is tamped too loosely, silicalite will pass
through, too tight and solvent will flow very slowly.
Place about 200 mg of silicalite into the pipette to create a
chromatography column.
Heat the column at 500o C in an oven overnight 12-16 hr to oxidize any
carbon compounds.
Dissolve up to a maximum of 10 mg of saturate hydrocarbon fraction in
a small volume of solvent and load the sample on the top of the silicalite
such that it soaks in. The volume should be small enough so that only the
silicalite is wetted.
Let the column stand for 5-10 minutes (using a rack to hold the pipettes)
and then elute with 4 ml of solvent. The flow rate should be slow enough
that it takes a few minutes for the solvent to pass through. If pressure is
applied to the top of the column, silicalite may be forced through the
glass wool.
Chapter One Introduction
١٥
Evaporate the solvent with a gentle nitrogen stream at 40-50o C, dissolve
the remaining sample in hexane and then transfer to small vials for
GCMS analyses.
The saturated HC fractions of some source rock extract, and crude
oil samples were analyzed by selected ion monitoring (m/z 191), (m/z 205),
(m/z 177), (m/z 163), (m/z 217), (m/z 259), (m/z 238), (m/z 218) (m/z,
231) and (m/z 253) gas chromatography / mass spectrometry (GC / MS)
using a Hewlett Packard 5890 Series II gas chromatography for studying
triterpane and sterane distributions.
Biomarkers are ubiquitous in crude oils and petroleum source rocks,
where their structures are maintain with very few changes during
diagenesis and catagenesis. The high specificity of some biomarkers in
crude oils and source rocks allows the inference of paleoenvironmental
conditions at the time of sedimentation, thermal maturity of source rock
and oils, type of organic matter in the rocks, and genetic links among
different types of crude oils and oil-source rocks.
Triterpanes commonly found in crude oils and bitumens come
mainly from triterpenoids synthesized by microorganisms. They have
proven very valuable for correlation because they are sensitive to
diagenetic conditions, to biodegradation and in some cases, they reflect
type of organisms from which the organic matter is derived. The
distribution patterns and ratios of certain compounds of triterpanes as
hopane and C29 norhopane are important indicator to depositional
environment, where a predominance of C29 may indicate a carbonate source
rocks (Waples, 1985). The most studied land-plant diagnostic biomarker of
angiosperms is 18α(H)-oleanane which has been recorded in Cretaceous
and younger materials; thus, the detection of this compound in crude oils
sets age constraints on a petroleum system and the type of organic matter in
the source rock.
Chapter One Introduction
١٦
Steranes are a group of cycloalkane hydrocarbons with the four-ring
carbon skeleton of steroids. Sterols are a class of C26 to C30 four-ring
alcohols of which commonly occurring members are C27 cholesterol, C28
ergosterol, and C29 β-sitosterol. Sterols are biosynthesized by algae,
dinoflagellates and higher plants. These compounds are the precursors of
steranes found in petroleum and petroleum source rocks.
Gas chromatography/mass spectrometry / mass spectrometry analysis
(GCMS/MS):
GCMS/MS is base on the fact that complex organic molecules
(parents) ionized in the ion source of a mass spectrometer breakdown into
smaller charged fragments (daughters). Some of these daughters' ions are
characteristic of their parent molecules (e.g. m/z 217 is a daughter of most
steranes). GCMS/MS allows the operator to determine the parents of
selected daughter ions (Peters et al., 2005). GCMS/MS analysis of the
sterane parent ion transitions corresponding to m/z 372 217,
m/z 386 217, and m/z 400 217 allows separate mass chromatograms
for the C27, C28 and C29 steranes, respectively. GCMS/MS analysis can be
used to determine marine input to oil (C30 steranes) and for correlations
using triangular diagram of C27-C28-C29 steranes, diasteranes, triaromatic
steroids, and other compounds. Due to their sensitivity, reliability and their
use in biomarker applications, Metastable reaction monitoring
(MRM)/GCMS represents a significant refinement over routine GCMS. A
Hewlett-Packard 5890 Series II-Micromass Autospec Q® hybrid GCMS
system was use for further sterane analyses using MRM/GCMS.
A standard oil sample was analyzed to insure quality control and as a
reference index for compound identification and for absolute qualification
of steranes (Seifert and Moldowan, 1979).
Chapter One Introduction
١٧
1.5.3. Organic facies and palynofacies investigation:
The characterization and classification of organic facies and
Palynofacies has been obtained from organic petrographic (reflected light)
and palynological (transmitted light) methods. The present study is base on
twenty cuttings samples recovered from the Noor-1 well, south east Iraq.
They were prepared palynologically using standard palynological
maceration techniques (Traverse, 1988) adopted at the laboratory of
Palynology at the Geological& Environmental Sciences Department,
Stanford University, US. 20 grams of each sample were disaggregating by
crushing in a porcelain mortar to increase the surface of reaction with
chemicals in the next steps. To remove the carbonates, concentrated
hydrochloric acid (35 % HCl) was add until the reaction (effervescence)
stopped to ensure the complete removal of carbonates and to avoid the
formation of calcium fluoride when the HF is add in the removal of
silicates. Acid was removed by repeated decanting, and dilution with
distilled water, until the samples are completely neutral.
The residue was transferred to plastic pots and hydrofluoric acid
(40% HF) was added for 3-7 days and stirred every 24 hours. During this
time, the mixture was decanted once everyday and fresh hydrofluoric acid
added (if the sample is highly arenaceous), the samples are decanted daily
until the residues are absolutely neutral.
The unwanted rock particles were separated from the finer
disaggregated material using 125 µm brass sieve and 10 µm nylon sieve,
the residue was washed using distilled water for several times to get rid of
coarse and gel-like unwanted masses. No further oxidation or staining were
applied to the residues to enable the study of palynofacies and spore/pollen
coloration. A considerable amount of the residue was mounted on a glass
slide using Canada balsam as a mounting medium to prepare the kerogen
(un oxidized) slide to study the palynofacies groups. The microscope slides
Chapter One Introduction
١٨
were examined with a Nikon eclipse 80i optical microscope equipped with
a Nikon DXM 1200F digital camera at the Geological& Environmental
Sciences Department, Stanford University, US.
1.6. Geological Setting
The involved area is located, tectonically within the northern limits
of Arabian Plate that is colliding with the Persian Plate, Particularly within
the unstable shelf, represented by two Zones ; The Foothills Zones, along
the Iraqi-Iranian international boundaries and the Mesopotamian Zone.
(Figure.2-1). More precisely, the former is represented by Himreen Sub
zone, whereas the latter by Tikrt-Amarra Sub Zone (Al-kadhimi et al.,
1996). However, Jassim and Buday (in Jassim and Goff, 2006) considered
the involved area to be located within the Stable Shelf, since they
considered the Mesopotamian Zone to be part of it. Nevertheless, (Fouod,
2010) disagree with the last opinion of Jassim and Buday and is in
accordance with (Al-kadhimi et al., 1996).
From structural point of view, the involved area includes many
Anticlines, some of them are on surface (Abu Ghrab, Faka, and Bazergan),
others are subsurface. All of them have NW-SE trend, which is a
characteristic feature for the tectonic zones in which to they occur. They
are long and narrow, double plunging anticlines (Al-kadhimi et al., 1996).
Concerning the subsurface structural framework of the involved area, there
is a NW-SE trending main fault that is almost located along the
northeastern margin of Bazergan oil field. There main subsurface fault runs
in the involved area, also in NE-SW direction. Most probably, it forms the
boundary (subsurface) between two zones, where the structures change
their main trend from NW-SE to N-S. It is located almost north of
subsurface Huwaiza structure. The length of this fault is about 45 km and it
Chapter One Introduction
١٩
represents the southeastern limits of the Foothills Zone (Al-kadhimi et al.,
1996).
Concerning the surface geology of the involved area, the extreme
northeastern part is covered by Bia Hassan Formation (Sissakian, 2000).
The thickness of this formation with the common underlying formations
(Mukdadiyah, Injana,and Fatha formations) is about (2000-2500).This huge
thickness has a positive effect on the saturation of the hydrocarbons, as
their weight is concerned. Besides, the presence of evaporates within the
Fatha Formation (subsurface) that will serve as cap rocks for the tight
anticlines. Quaternary sediments, except parts of Bazergan structure
(Sissakian, 2000); cover the remaining (southwestern) parts. It is worth
mentioning that below these Quaternary sediments the same as
aforementioned stratigraphic sequence do exist, which means the same
positive factors, concerning hydrocarbon accumulation and maturation.
Chapter One Introduction
٢٠
Figure (2-1) Tectonic map of Iraq (After Jassim and Goff, 2006)
Concerning the new tectonic movement in the involved area, the
whole area is under influence of subsiding. The amount of subsidence
range from (1000-2000) m, ( Sissakian and Deikran, 1998 ), in form of a
local subsided basin, which shows more than 2000m, as being in wells of
Abu Ghrab and Fakkah ( 2035 and 2037m, respectively ). This local basin,
although trends more to N-S than to NW-SE, as it has to be, because the
Chapter One Introduction
٢١
latter is the main trend of the structures there, but this abnormal
trend could be attributed to the regional available data and not to defaulted
subsurface data ( Sissakian and Deikran,1998).
In interpreting the aforementioned new tectonic data, the recorded
amount of subsidence that represents the depth to the top of the Fatha
Formation, shows very good coincidence with mentioned thickness of the
stratigraphic sequence, as reworded to be within range of ( 2000-2500 ) m.
The rate of subsidence, as being measured from the constructed contours of
the new tectonic movements, ranges from (- 1.2 to – 1.6) cm / 100 years,
(Sissakian and Deikran, 1998).
Chapter Two Palynofacies Analysis
22
2. PALYNOFACIES ANALYSIS
The basic aim of the investigation presented in this chapter was to
determine the nature of the disseminated organic constituents,
sedimentation conditions and paleoenvironmental conditions prevailed
during the deposition of the source rocks encountered in the study area.
Application of such techniques gives new insight into problems concerning
the determination of the potential and efficiency of petroleum source rocks.
Palynofacies is probably the single discriminating technique for studying
and explaining organic facies patterns. This is simply no substitute for
direct visual observation of what is actually in the sediment.
Palynofacies data can generate for more numerous and diverse
parameters than bulk geochemical data, permitting the analysis of much
more detailed and suitable variations in sedimentary environment and
organic matter source or preservation state. Moreover, it provides direct
information on the origin and character of the bulk of the particulate
organic matter, rather than of the minor extractable components (only a few
percent of the TOC) whose characteristics may or may not be
representative of the whole, and whose origins are often unclear (Tyson,
1995). Palynofacies is an interface discipline. Perhaps its greatest virtue is
that it represents a highly efficient and effective means of integrating
playnological, sedimentological and organic geochemical data into a single
cohesive geological model. Such models can used to predict source rock
potential based upon more readily visualized geological (rather than
geochemical) arguments. Palynofacies is therefore: ‘a body of sediment
containing a distinctive assemblage of palynological organic matter though
to reflect a specific set of environmental conditions, or to be associated
with a characteristic range of hydrocarbon-generating potential (Tyson,
1995). This term was first introduced by Combaz (1964) to describe the
total microscopic image of the organic components. Then it became
Chapter Two Palynofacies Analysis
23
popular however, the definition varied between different authors. Some
authors named the organic components “organic matter”, others
“palynodebris” but still others “kerogen” (Carvalho, 2001). The term
kerogen is today the most commonly used term to describe the organic
components contained in sedimentary rocks (Tyson, 1993). Tyson (1993)
used the term kerogen in a purely palynological sense to describe the
dispersed particulate organic matter of sedimentary rocks that is insoluble
in hydrochloric (HCl) and hydrofluoric (HF) acids.
Practically, when examine the organic matter in thermally immature
sediments often consists largely of morphologically recognizable
biologically produced entities. Here is below some brief description of the
four major particulate organic matter categories (Fig. 3-2) identified by
Tyson (1993& 1995).
PHYTOCLAST GROUP
The majority of dispersed fossilized phytoclasts are deriving from
the lingo-celluloses tissues of terrestrial macrophytes. Most probably
represent fragments of strongly lignified mechanical support and vascular
tissues of the secondary xylem (‘wood’) of arborescent gymnosperms and
angiosperms (plus the analogous tissues in tree ferns and extinct vascular
plants that exhibited secondary growth).
The most conspicuous lignified structures seen in palynological
preparations are fragments of xylems elements, comprising tracheids and
vessels. Tracheids may be recognizing by their bordered, scalariform or
other types of pits, pores by which the elements communicate with adjacent
cells. Each tracheid may have 50-300 pits, mostly located on the radial
walls, and arranged in single or multiple rows (uniseriate, biseriate or
multiseriate). The pits may be outlined and separated from each other by
linear or crescentic thickenings termed crassulae. The vessels are analogous
Chapter Two Palynofacies Analysis
24
structures to tracheids but are longer and often somewhat greater diameter
(25-500 µm). The structured woody plant tissue be divided into three main
categories:
Gymnosperm tracheid tissue with circular uni- or biserial arrangement of
rows of pits; with concentric darker-thickened zone (non-fluorescing).
Angiosperm tracheid tissue with “cross-hatch” structure, and thickened
ribs (more translucent-less lignified; non-fluorescing).
Structured gelified tissue with massive and fibrous parallel structure and
sub-conchoid curved fracture surfaces (non-fluorescing).
The woody tissue as a category of phytoclasts is most typical of the
swamp facies and other sediments rich in terrestrial organic matter. The
cuticle layer is the outermost part of the epidermis of those tissues of the
aerial parts of higher plants that do not show secondary growth. Most
cuticles are derived from leaves, because these are also produced and shed
in great numbers and their surface area is very large. An abundance of
cuticle and suberinized tissues is of special significance because their waxy
or oily composition means that they have significant potential as a source
of liquid hydrocarbons, a unique property among phytoclasts. Three types
of cuticles: isodiametric rounded or undulate cuticles (Angiospermae);
rectangular dark brown cuticles (Gymnospermae; non-fluorescing with
partial oxidation before or during deposition): and epidermal tissues.
Cuticles are most typical of a fluvio-deltaic, prodelta, estuarine-mangrove
facies or proximal submarine fan facies (Tyson, 1987, 1995). Cuticles have
preserved either in low energy environments, having buried rapidly before
the onset of oxidation or in a Tertiary mangrove swamp. The content of this
category of organic matter is indicative of the vicinity of the source
(Plate1).
Chapter Two Palynofacies Analysis
25
PALYNOMORPH GROUP
Palynomorphs contain all dispersed organic material defined by a
recognizable organization at cellular level. Three major subgroups of
palynomorphs are distinguished; sporomorphs (spores, pollen and fungal
spores), (Plate 2). Phytoplankton (Dinoflagellate cysts, Prasinophyte
phycomata, Acritarchs, Cyanobacteria, chlorococcale colonial algae) and
zoomorphs (animal derived palynomorphs including foraminiferal linings,
Chitinozoa and scolecodonts), (Plate 3). This group contains fungal
unicellular and multicellular ,spores and fungal filaments (hyphen) without
fluorescence (secretinite). The dark-brown primary color of fungal spores
indicates melanization and influence of atmospheric oxygen (Tyson, 1995).
In an oxidizing environment, fungal attack on structured materials normally
precedes the formation of amorphous material by bacterial action. This
could be an explanation of the presence of fungal spores together with the
amorphous type kerogen of humic origin. Inshore-shallow water facies
yield acritarch assemblages characterized by low diversity and high
dominance of some taxons. The abundance of acritarch in marine
sediments depends on the lithology and sediment grain size. The fact that
acritarchs are primarily restricted to shelf environments strongly suggests
that they had a meroplanktonic lifestyle similar to that of modern cyst-
forming dinoflagellates.
The presence of foraminiferal test linings is a reliable indicator of
marine conditions (Tyson, 1995). In recent sediments, the abundance of
linings declines sharply at the head of estuaries, and their size decreases as
salinity falls (Tyson, 1995). The abundance of linings in recent sediments
also decreases with increasing water depth. The foraminiferal linings are
absent in most deltaic sediments and in the major part of the prodeltaic
sediments littoral zone; modern shallow-water shelf sediments contain a
high percentage (15-45% from all palynomorphs) of foraminiferal linings.
Chapter Two Palynofacies Analysis
26
AMORPHOUS GROUP
The amorphous group consists of all particulate organic components
that appear structureless at the scale of light microscopy, including
phytoplankton- or bacterially derived amorphous organic matter
(traditionally referred to as ‘AOM’, higher plant resins, and amorphous
products of the diagenesis of macrophyte tissue (Plate 4).
The major portion of organic matter in source rock sediments is in
the form of amorphous kerogen (amorphinite). Characterization of
amorphous organic matter (AOM) is a fundamental factor in source rock
evaluation through the microscope, and in the reconstruction of the
conditions of sedimentation. The high value of the AOM point to reducing
(dysoxic and anoxic) environments with high preservation potential of
planktonic organic matter or benthic microbial mat material. The AOM
comprise a large proportion of living or dead bacteria. Amorphous organic
matters often represent the intimate association with clay minerals.
The syn-sedimentary processes of “amorphization” took place in the
photic zone, where most of the consumption and re-mineralization of
biomass occurs at or near the sediment–water interface. Some authors have
interpreted this organo–mineral association as an early flocculation in the
water column of labile (partly dissolved) organic material with clay
particles from water suspension (Bishop and Philip, 1994 in Tyson, 1995).
The content of AOM increases in distal anoxic facies and by
upwelling systems influenced by dysoxic sediment facies (Demaison and
Moore, 1980; Powell et al., 1990). An abundance of AOM in recent marine
sediments appears to be especially diagnostic of dysoxic to anoxic facies
and is typical of most dysoxic–anoxic source rock facies. The oxygen
deficient bases are ideal for AOM preservation (Jones and Demaison, 1982;
Jones, 1983). Due to prolonged oxidation open ocean oxic pelagic
sediments often have little or no remaining AOM.
Chapter Two Palynofacies Analysis
27
OPAQUE GROUP
Once particulate organic matter particles have undergone sufficient
maturation or alteration they become opaque. Referred to all structured
brownish black-to-black color oxidized or carbonized particles. The
recycled and oxidized fractions usually show negligible hydrocarbon
potential and are less responsive to further changes in thermal maturation.
This category of grains appears as mostly homogeneous highly corroded
opaque fragments of an elongated shape with sharp angular outlines. The
presence or absence of the oxidized or carbonized woody tissue in
sediments is very important in environmental interpretation and source rock
evaluation. (Plate 5).
Inertinite is the product of oxidation of structured materials,
generated by the alteration of wood in an oxidizing environment at normal
or elevated temperature; sedimentary charcoal is widely accepted to be
primarily the product of Pyrolysis of mainly land plant matter during wild
fires. Wild fires are important biologically because they occur in abroad
range of terrestrial environments including swamps and bogs, where
accumulated peat may also burned most argillaceous deposits, regardless of
environment of deposition; contain at least a few minute oxidized and/or
reworked black particles (Batten, 1996). Fragment of woody material in
organic residues from semi-oxidizing environment range from dark brown
to black in color and from translucent at the edges to completely opaque in
aspect. Inertinite cannot, however, be produced by bacterial decay in a
reducing environment. Inertinite is chemically very stable and is frequently
preserved as a product of recycling. Being composed of carbon, it has no
source rock potential. Although Inertinite is chemically inert and not
potential for hydrocarbon (Pocock et al, 1987) in undertaken project is a
good parameter to indicate the pre-depositional environment recognized in
determination of palynofacies types.
Chapter Two Palynofacies Analysis
28
Kerogen, commonly defined as the insoluble macromolecular
organic matter (OM) dispersed in sedimentary rocks, is by far the most
abundant form of OM on Earth. This fossil material is of prime importance
as the source of oil and natural gas; moreover, kerogen can provide
essential information on major topics such as past environments, climates
and biota. Tyson (1993& 1995) primarily designed simple classification for
rapid assessment of hydrocarbon potential. This classification is relatively
simple and has a limited number of categories (usually four to six). The
principal concern is to identify the relative proportions of inert, gas-prone,
oil-prone and very oil-prone material within the total kerogen assemblage.
The key categories that must be identifying on source rock potential are:
• Essentially inert material (kerogen type-IV), non-fluorescent, opaque
black to dark brown semi-opaque particles, generally oxidized or
carbonized Phytoclasts (including charcoal).
• Gas-prone material (kerogen type-III), non-fluorescent, generally
orange or brown, translucent, structured Phytoclasts or structure less
materials.
• Oil-prone material (kerogen type-II), volumetrically, the most
important constituent is fluorescent amorphous organic matter, but
fluorescent (non-oxidized) non-alginate Palynomorphs, cuticle and
membranous debris are also included.
• Highly oil-prone material (kerogen type-I), this consists of very
strongly fluorescent organic matter including structured material
derived from chlorococcale and prasinophyte algae, and amorphous
materials derived from cyanobacteria and thiobacteria. Resins and
some cuticles are the only significant terrestrially derived
components belonging to this group.
Chapter Two Palynofacies Analysis
29
In the present study, twenty cutting samples rose from Well (N0-1),
samples were subject to palynological kerogen preparation slides. Each
sample has two-sets, so the total studied kerogen is forty slides. Each
sample was examined using the transmitted light microscope at 50 x 0.80
magnification in order to make a qualitative as well as quantitative analysis
of the particulate organic matter, determination of the Palynofacies and
kerogen types, determination of spore coloration and assessment of thermal
alteration index (TAI), Vitrinite reflectance (Ro%) and organic thermal
maturation. Each slide was counted for its particulate organic matter
content in terms of Abundant (>80%), Common (5-15%), and Rare (<5%).
Chapter Two Palynofacies Analysis
30
Structureless Structured
AMORPHOUS GROUP
Heterogeneous,+fluorescent,common inclu-sion,+diffuse edge
Homogeneous,non-fluorescent,rounded, sharp to diffuse outline
Haline, Homogeneous,fluorescent, sharpoutline + fracture or irregular surface
AOM Humic gel(intra/extra cellular)
Resin
Fragmentary particle = clast(angular broken outline, obviously not a whole discrete entity)
Diagnostic animalian features(spines, slits, hairs, joints) etc.
No diagnosticanimalian features
ZOOCLAST GROUPPHYTOCLAST GROUP
Opaque up to edge, non-fluorescent,+ biostructure (e.g. pits)
Definitive biostructure
Translucent(at least at edge of particle)
Cellular
2Dfluorescent sheet
3D mass
Pitting or spiralthickenings
Thin, narrowtubes, +septae,non-fluorescent.Pale or dark brown
Equidimensional (l : w < 3)
Lath - shaped (l : w > 3)
FluorescentNon-fluorescent
Cuticle Suberinizedphellem tissues (bark)
Cortex tissues(of roots?)
Wood tracheid or'nematoclast'
Melanized fungal hyphae
Oxidized or carbonizedwoody tissues including charcoal
Discrete individual or colonial entity
PALYNOMORPH GROUP
Sporomorph subgroup
Zoomorph subgroup
Phytoplankton subgroup
No definitive biostructure
Only residual trace of structure
Irregular,degraded or embayedappearance
Massive, angular homogeneous +concoidal fracture.Non-fluorescent
Square, elongate or lath-shaped (parallel-sided)
Non-cellular sheet (+ folds)
'Pseudo-amorphous' phytoclast
Degradedmacrophytetissue (espe- cially poorlylignified tissues)
Highly gelified woodytissue (cell walls and cell fillingindistinguishable)
Fibrousbundles
Non fibrous, 'solid',+ length-parallelstripes or bands, orcross-hatch pattern
Possibly marine macrophyte (seagrass/seaweed) tissue. Possibly dull fluorescence? Probably wood
tracheid tissuewithout visible pits
'Membranes'Fluorescent = cuticle? Non-fluorescent = zooclast?
UNKNOWN ORGANIC PARTICLE
Fig. (3-2): Schematic key to assist identification of dispersed palynological organic matter in thermally immature to marginally mature
sediments (Tyson, 1995).
Chapter Two Palynofacies Analysis
31
RESULTS AND DISCUSSION
2.1. PALYNOFACIES AND KEROGEN TYPES
2.1.1. NOOR-1 WELL
Kerogen composition data (Fig.4-2) shows that, organic matter in the
intervals analyzed from 4720m to 4930m primarily consists of abundant
Amorphous Organic Matter (AOM), (found to be up to 90%). Common to
Rare Palynomorphs, Rare opaque and Phytoclasts (Table 4-2).
The amorphous organic matter present consists mainly of moderately
to well preserve pale yellow to orange massive to grainy texture with a
rather dull matrix. Most of the recorded fragments showed diffused edges
but the granular varieties are also represente in minor amounts. The
Phytoclasts consist mainly of pale brown to brown, well to moderately
preserve structured terrestrial plant fragments (e.g., mostly tracheids,
cuticles and xylem ray tissues). Tracheids are the most common Phytoclast
constituent, mostly in the form of elongate lath-shaped and tabular particles
lacking any visible pitting, obvious perforated bordered pits showing a uni-
to biserial arrangement. One remarkable structure for tracheids is the
helical or spiral patterns of thickening. The dispersed cuticles with distinct
cellular outlines (mostly polygonal, rarely rectangular) picked out by the
cuticular flanges, orange-brown to brown in color. The opaques are dark
brown to black colored equidimensional (equant) to lath-shaped fragments
Palynomorphs are dominate showing yellow, yellowish orange in color.
Type II kerogen, Oil-Prone material is suggest for the analyzed
Sulaiy formation at (NO-1) well based on the presence of large amounts of
AOM derived mostly from degraded terrestrial Phytoclasts. This
interpretation is in accord with the Moderate HI values (mostly between
400-600 mg HC/g TOC) imply that the dominant component, AOM.
Chapter Two Palynofacies Analysis
32
Table (4-2): Semi quantitative distribution of the various (POM) recorded from the
(NO-1) well.
No. Depth (m) Formation AOM Phytoclasts Palynomorphs Opaques
1 4720 Yamamma A R R R 2 4730 Yamamma A R R R 3 4742 Sulaiy A R C R 4 4750 Sulaiy A R R R 5 4770 Sulaiy A R R R 6 4780 Sulaiy A R R R 7 4800 Sulaiy A R R R 8 4815 Sulaiy A R R R 9 4825 Sulaiy A R R R
10 4839 Sulaiy A R R R 11 4850 Sulaiy A R R R 12 4862 Sulaiy A R R R 13 4878 Sulaiy A R R R 14 4890 Sulaiy A R R R 15 4900 Sulaiy A R C R 16 4910 Sulaiy A R R R 17 4915 Sulaiy A R R R 18 4922 Sulaiy A R R R 19 4928 Sulaiy A R R R 20 4932 Sulaiy A R R R
A. Abundant, C. Common, R. Rare
Chapter Two Palynofacies Analysis
33
KEROGEN COMPOSITION %DEPTH (m)
FMLITHOLOGY20 40 60 80
4700
4720
4740
4760
4780
4800
4820
4840
4860
4880
4900
4920
4940
Yam
amm
aSu
laiy
LIMESTOME AOM
PALYNOMORPHSSHALE
PHYTOCLASTS
OPAQUSE
Fig. (4-2): Percentage distribution of particulate organic matter groups within the defined Palynofacies of the (NO-1) well.
OPAQUES
Chapter Two Palynofacies Analysis
34
2.2. PALEOENVIRONMENTAL INTERPRETATION
The use of palynology in geological studies has hitherto been
focused on determining the age of rocks (palynostratigraphy) and on giving
vegetational and climatic interpretations based on comparison of fossil
palynofloras with those of extant vegetation (paleoecology and
paleoclimatology). During the past two decades there has been increasing
attention paid to analyzing the total kerogen (acid-resistant organic matter)
component of sediments. The subdiscipline of palynofacies analysis has
enabled palynologists to provide detailed environmental interpretations that
have proven useful in coal and petroleum geology. Specifically, the pollen,
spores, dinoflagellates and other particulate organic matter, which can be
recognized and identified from a sequence of rocks, can be use effectively
to define precisely the different palaeoenvironmental parameters that
prevailed during the deposition of the rocks. These parameters include,
temperature, sea level changes, water depth, salinity and terrigenous influx.
In general, changes in palynofacies types and composition of
palynomorphs assemblage may provide information regarding the
interpretation of these parameters.
In the present study, the paleoenvironmental reconstruction is based
on the defined particulate organic matter groups and the composition of
palynofacies assemblages of the studied intervals within ( NO-1) well. The
paleoenvironmental deductions were derived mainly from the ternary
diagrams (cf. Tyson, 1993, 1995).
The AOM-Phytoclast-Palynomorph (“APP”) ternary plot (Fig.5-2) is use to
summarize the optical character of the kerogen assemblages for (NO-1)
well. It is clear shows that most of the samples plot in AOM dominated
field (IX-field) that are usually associated with distal suboxic-anoxic facies
(Tyson, 1995).
Chapter Two Palynofacies Analysis
35
Fig. (5-2): AOM-Phytoclast-Palynomorph ternary plot of NO-1 well (Tyson, 1995).
2.3. ORGANIC THERMAL MATURATION
Maturation is the process by which plant and algal material deposited
in sediment is thermally decomposed to yield oil, natural gas and other
products (chiefly CO2 and water). It is govern by both time and
temperature, in which the same degree of maturation can attained at a low
temperature for a long period as at a high temperature for a short period of
time (Oehler, 1983). As the organic matter matures, it breaks down to
generate oil and gas, the rate of oil and gas generation is slow at first, then
increases rapidly, then diminishes again (Fig.6-2). Initially, oil is the main
product, but at higher maturities oil generation declines and gas generation
increases (Oehler, 1983). The maturity range over which most of the oil is
generate is called the “oil window” and the rocks generating that oil are
said to be “mature”. Rocks that have not yet reached that stage are call
“immature” and rocks that have passed through that stage into the gas-
generating phase are call “overmature” (Oehler, 1983).
Sporopollenin is a very tough material, it is not indestructible and
post-depositional heating can cause chemical changes. These are of the
Chapter Two Palynofacies Analysis
36
same sort that can affect organic matter generally (e.g., in coal beds where
the coal series proceeds from peat to anthracite by grades, with loss of H
and O and concomitant enrichment of C and molecular condensation). The
same occurs with dispersed sporopollenin, through apparently not as fast as
it does with other organic substances (Traverse, 1988).
The main observed change in spore/pollen exines along the
carbonization-coalification process is the change of color in transmitted
light. Fresh exines are pale yellowish to almost colorless. If these exines
are heated, (e.g., by deep burial or proximity of the enclosing sediments to
a lava flow) their color intensifies from yellow to orange to brown, dark
brown and finally black (Traverse, 1988).
In the present work, simple thin-walled psilate palynomorphs were
chosen to investigate their exines color using Pearson’s (1984) color chart
(Fig.7-2) and Batten’s (1980) scale of palynomorph colors (Table 5-2) to
estimate approximately the numerical thermal alteration index (TAI),
Vitrinite reflectance (Ro %) and organic thermal maturity of the studied
intervals in the ( NO-1) well.
Chapter Two Palynofacies Analysis
37
Depth (m) Relative amount of petroelum formed
Temperature ( C)o
1000
2000
3000
4000
5000
50
100
150
200
Biogenic gas
OilThermal gas
Oil peak
Gas peak
Immature
Mature
Overm
ature
Fig. (6-2): Oil and gas generation as a function of increasing sediment burial
(Modified after Oehler, 1983).
Organicthermalmaturity
Spore / pollencolour
Correlation toother scales
TAI = 1 - 5 VitriniteReflectance
IMMATURE
MATUREMAIN PHASE OF LIQUID PETROLEUMGENERATION
DRY GAS ORBARREN
1
1+
2-
2
2+
3-
3
3+
4-
4
(5)
0.5 %
1.3 %
0.2 %
0.3 %
0.9 %
2.0 %
2.5 %
BLACK & DEFORMED Fig. (7-2): Pearson’s (1984) color chart compared with other organic thermal maturity,
TAI and Vitrinite reflectance (Modified from Traverse, 1988).
Chapter Two Palynofacies Analysis
38
Table (5-2): Batten’s (1980) scale for palynomorphs colors (reproduced from Traverse,
1988). Observed color of Palynomorphs Significance
1. colorless, pale yellow, yellowish orange Chemical change negligible; organic matter immature, having no source potential for hydrocarbon.
2. Yellow Some chemical change, but organic matter still immature.
3. Light brownish yellow, yellowish orange Some chemical change, marginally mature but not likely to have potential as a commercial source.
4. Light medium brown Mature, active volatilization, oil generation.
5. Dark brown Mature, production of wet gas and condensate, transition to dry gas phase.
6. Very dark brown-black Over mature; source potential for dry gas. 7. Black (opaque) Traces of dry gas only.
2.3.1 NO-1 well
The studied succession (4720 - 4932 m) in the (NO-1) well generally
shows marked increase in the color intensity with increasing depth. It is
characterized by generally mature palynomorphs with. Light brownish
yellow, yellowish orange to light medium brown Color. This corresponds
to 2+ to -3 TAI and 0.57 - 0.70 % Vitrinite reflectance.
The calculated maturity generally increases with depth and appears
to follow a maturity profile, which projects at ≈ 0.68 % Ro at 4900 m.
Chapter Three Source Rocks Evaluation
47
3. Source Rocks Evaluation
Although petroleum systems are generally composed of at least source,
a reservoir, and a trap (Dow, 1974; Magoon, 1988), the presence of a viable
source rock is perhaps the most important factor governing the nature
accumulation of hydrocarbons. As stated by Demaison and Huizinga (1991),
"if there is no petroleum generation in the subsurface, then all of the other
necessary requirements of a petroleum system (e.g., structure, reservoir, seal)
lose relevance".
It is generally, organic rich fine-grained sediment that is naturally
capable of generating and releasing hydrocarbons in amounts to form
commercial accumulations (Hunt, 1996). Waples (1985) distinguished the
petroleum source rocks into potential, possible and effective as follows:
a. Potential source rocks: are immature sedimentary rocks known to be
capable of generating and expelling hydrocarbons if their level of maturity
were higher.
b. Possible source rocks: are sedimentary rocks whose source potential has not
yet been evaluated, but which may have generated and expelled
hydrocarbons.
c. Effective source rocks: are sedimentary rocks that have already generated
and expelled hydrocarbons.
However, the present geochemical study aims to define the potential
source rocks of the subsurface Creteaous in the area of Missan Oil Field and
the definition of the main zones of oil generation. This done through a detailed
geochemical study on representative of (15) cutting samples from (Noor-1)
well, these samples and some other basic data are kindly offered from Missan
and South Oil Companies.
Chapter Three Source Rocks Evaluation
48
3.1. Principles of evaluation
The identification and categorization of rocks, active or potential
petroleum source beds, are as important in an exploration well as
identification of potential reservoirs (Waples, 1985).
The hydrocarbon source evaluation is generally based on the organic
quantity (organic richness), quality (kerogen type), generation capability and
the thermal maturation of the organic matter disseminated in the rock (Hunt,
1979; Tissot and Welte, 1984; Waples, 1985). The hand available
programmed analyses applied in the present study, the organic richness based
on total organic carbon determination using Leco Carbon Analyzer, the
organic quality and generation capability were determined utilizing Rock-Eval
II and IV Pyroanalyzer. Furthermore, the methods used for determining the
stages of maturation are the common Vitrinite reflectance measurements (Ro)
and the maximum temperature of Pyrolytic hydrocarbons (Tmax).
3.1.1. Organic richness
Total organic carbon (TOC), also called organic carbon (Corg), measures
the quantity but not the quality of organic carbon in the rock or sediment
samples. Total organic matter (TOM) can be calculated by multiplying TOC
by 1.2, assuming that the organic matter is 83 wt% carbon (Peters et al.,
2005).TOC can be measured by various methods, each with limitations and
potentially different results, as discussed below.
Direct combustion is the most common method, which requires
acidification of the ground rock sample with 6 N HCL in a filtering crucible to
remove carbonate, removal of the filtrate by washing /aspiration, and drying at
~ 55o C. Using a typical Leco Carbon Analyzer, the dried sample is combusted
with metallic oxide accelerator at ~ 1000o C. The CO2 generated during
Chapter Three Source Rocks Evaluation
49
combustion is analyzed using either infrared (IR) or thermal conductivity
detectors (TCDs). IR detectors are specified for CO2, while TCDs respond to
other compounds, such as sulfur dioxide and water, if they are not removed.
The indirect TOC method is usually applied to organic-poor, carbonate-
rich rocks. Total carbon (including carbonate carbon) is determined on one
aliquot of the sample, while carbonate carbon is determined on another aliquot
by coulometric measurements of the CO2 generated by acid treatment. Organic
carbon is the difference between total carbon and carbonate carbon. This
method is more time-consuming than the direct method and requires two
separate analyses of the sample.
The Rock-Eval II plus TOC determines TOC by summing the carbon in
the pyrolyzate with that obtained by oxidizing the residual organic matter at
600o C. For small samples (100 g), this method provides more reliable TOC
data than the methods discussed above, which require ~1-2 g of ground rock.
However, mature samples, where Vitrinite reflectance is more than ~1 %,
yield poor TOC data when determined by this method because the temperature
is insufficient for complete combustion.
The Rock-Eval VI Pyrolysis and oxidation reaches 850o C, which
results in more reliable Tmax and TOC data, especially for highly mature
samples (Lafargue et al., 1998). Hunt (1962) pointed out that, the organic
matter content in "Viking shale" differs with grain size of the sediments as:
Grain size organic matter %
> 4 µ (silt) 1.79
4 – 2 µ 2.08
< 2 µ 6.50
Vassaeovich et al., (1967) reported that, the weight percent of organic
carbon in particular source rocks could correlate with the enrichment of
Chapter Three Source Rocks Evaluation
50
terrigenous materials in the rock. Therefore, the terrigenous sediments, which
are rich in carbonates or coarser materials, have low concentration of organic
matter, but when shale content increases, the organic matter content increases.
Mcauliffe (1977) considered the range 0.5 – 1.0 % by weight organic carbon
is the lower limit for shale to be source rock. Dow (1978) mentioned that,
most acknowledged source rock must contain (0.2 – 0.8 %) organic carbon.
Hedberg et al., (1979) pointed out that, the organic carbon content of 0.5 %
represents the minimum limit for potential source rock. Thomas (1979)
classified the potentiality of source rocks based on their weight percentage of
organic carbon; into poor source (<0.5 wt %), fair source (0.5 – 1.0 wt %),
good source (1.0 – 2.0 wt %) and excellent source (>2.0 wt %). Tissot and
Welte (1984) stated that clastic rocks, which are considered a source for
petroleum, contain a minimum of 0.5 wt % of total organic carbon (TOC)
while good source rocks contain an average of about 2.0 wt % of TOC.
The type of the organic matter has important influence on the nature of
the generated hydrocarbons. Espitalie et al., (1985) found that, organic
richness alone may not suffice to evaluate source rocks, where the organic
matter is mainly inertinite i.e. oxidized or biodegraded and not capable of
generating hydrocarbons even at high concentrations. Peters (1986) presented
a scale for assessment of source rocks used in a wide scale and is applied in
this work; a content of 0.5 wt % TOC as a poor source, 0.5 – 1.0 wt % as a fair
source, 1.0 – 2.0 wt % as a good source and more than 2.0 wt % TOC as very
good source rock.
3.1.2. Genetic type of organic matter
The recognition of the initial genetic organic matter of a particular
source rock is essential for the prediction of oil and gas potential. The type of
Chapter Three Source Rocks Evaluation
51
organic matter completes the organic richness in evaluating the generating
potential of a source rock. The most common methods used to identify the
type of organic matter include: 1) optical methods (reflected light –
transmitted light – fluorescence light), 2) bitumen extract method, and 3)
Pyrolysis method. As the organic material is more deeply buried, biochemical
processes ceases, and further changes result from purely chemical processes.
Bacterial degradation as the most important biochemical process becomes
nonexistent below a sediment depth of about one meter, in mud’s having an
anaerobic environment. At this point, complex intermediate substances are
formed by a chemical process, followed by a much slower chemical process
which converts the intermediate substance into a single stable substance
known as "kerogen" (Tissot and Welte, 1978). The kerogen consists of
heterogeneous, finely disseminate organic matter, and resembles its immediate
precursors. It is composed mainly of complex molecules, relatively inert. It
could not be dissolved in acids or alkalis, resistant to bacterial attack, but
easily oxidized by certain chemicals or long exposure to air. Minor amounts of
substances soluble in organic solvents are associated with kerogen at this stage
and are collectively called "bitumen". The kerogen type can be differentiated
by optical microscopic or physicochemical methods. The differences among
them are chemical and are related to the nature of the original organic matter.
Accordingly, Waples (1985) classified the sedimentary organic matter
petrographically into three main components:
1. Oil-prone component equivalent to exinite-liptinite (also sapropelic),
containing algal fragments, pollens, spores, cuticles, resins, algal
sapropel (marine origin) and waxy sapropel (from land plants).
Chapter Three Source Rocks Evaluation
52
2. Gas-prone component equivalent to Vitrinite derived mainly from lignin,
cellulose walls of cells from high land plants e.g. terrestrial origin.
3. Inertinite component which has undergone oxidation (prior to deposition)
by forest fires, bacterial or sub-aerial oxidation. This component may count
as organic content but will not yield hydrocarbons at any maturation level.
The organic matter in potential source rocks must be of the type that is
capable of generating petroleum (Korchagina and Chetverekova, 1980; Tissot
and Welte, 1984; Waples, 1985). It has been establish that, the organic matter
is classified into three classes:
1. Sapropelic type equivalent (type I and II by Tissot et al., 1974).
2. Humic type equivalent (type III by Tissot et al., 1974).
3. Mixed type from the two other types equivalent (II / III or III / II).
Bitumen extracts, petroleum generation from a particular source rock,
depend on temperature, modified time and type of organic matter. The
increase in temperature with depth cause distinct changes in the physical and
chemical characteristics of the organic matter. Bitumen is the amenable
organic matter, which can be extracted by organic solvents such as chloroform
from source rocks. Larskaya and Zhabrev (1964), Louis (1964), Philippi
(1965) observed that, there is an increase of bitumen ratio and hydrocarbon
ratio with increasing depth of burial reaching a maximum value at the peak of
oil generation and are reduced to the minimum value at the end of the
catagenesis stage. The data of analyses of extracted bitumen and geochemical
parameters of the subsurface Creteous-Tertiary rock units in concern were
estimated and tabulated in tables given later.
Cerchez and Anton (1972) suggested the following characterizing
values for bitumen content for source rock quality:
Chapter Three Source Rocks Evaluation
53
% Free bitumen Source rock quality 0.015 0.015 - 0.020 0.02 - 0.10 0.10 - 1.50 1.50
weak weak to favorable favorable to good good very good
The percent bitumen extraction ratio is calculated by dividing the
weight percent of chloroform soluble organic matter by the weight percent of
organic carbon (TOC Wt %) in the sediments and multiplying by 100. The
values of extraction ratio [(extract / TOC), (4 – 8%)] indicate the presence of
autochthonous (insitu) bitumen, while the moderate value (more than 8%)
indicates the presence of allochthonous bitumen (Korchagina and
Chetverekova, 1976).
The mode of distribution of n-alkanes also sheds light on the genetic
origin of organic matter (Calvin, 1971; Tissot and Pelet, 1971; Tissot and
Welte, 1984; Vassaeovich et al., 1976; Korchagina, 1983; Korchagina and
Chetverekova, 1980). It is known that sapropelic organic matter (type-II) is
characterized by a maximum peak concentration of n-alkanes from C15-17-19
(Clark and Blumer, 1967; Hunt, 1968). The (type- III) kerogen has the
maximum concentration of n-alkanes from C27-29-31. Whereas, the mixed type
of organic matter (type II/III) derived from remains of higher vascular plants
has the maximum concentration of n-alkanes from C 21-23-25 (Hunt, 1968;
Albercht and Ourisson, 1969; Calvin, 1971; Tissot and Welte, 1984).
Pyrolysis is almost the best routine tool for determining the kerogen
type (Espitalie et al., 1977). In the present study, the kerogen types were
determined using the Pyrolysis (Rock-Eval 6) data, by plotting the hydrogen
index (HI = S2 / TOC), (note; the Rock-Eval 6 model automatically estimate
the HI without the routine equation) versus the oxygen index (OI = S3 / TOC)
on a modified Van Krevelen type diagram as well as HI versus Tmax. Because
Chapter Three Source Rocks Evaluation
54
of the importance of the hydrogen content as a convenient tool to differentiate
the types of organic material, Waples (1985) used the hydrogen index values
(HI) for immature kerogen to differentiate the types of organic matter.
Hydrogen indices below about 150 mg/g indicate a potential source to
generate gas (mainly type-III kerogen). On the other hand, hydrogen indices
between 150 and 300 mg/g contain more type-III kerogen than type-II and
therefore are capable for generating mixed gas and oil, but mainly gas.
Furthermore, kerogen with hydrogen index above 300 mg/g contain
substantial amounts of type-II macerals, and thus are considered to have good
source potential for generating oil and minor gas. Kerogen with hydrogen
index above about 600 mg/g evaluated as a pure type-I (rarely found) or type-
II, has been rated as excellent potential to generate oil (Peters, 1986).
3.1.3. Thermal maturation
As a rock containing kerogen is progressively buried in a subsiding
basin, it is subjected to increasing temperature and pressure. A source rock is
defined as mature when it generates a great amount of hydrocarbons. A rock
that does not reach this level of generation is defined as an immature source,
and that which passed the time of significant generation is considered as over-
mature source rock. Generally, various parameters have used for estimating
source rock maturation. These parameters include Vitrinite reflectance (Ro),
the temperature at which the kerogen yields maximum hydrocarbons (Tmax) by
Pyrolysis, carbon preference index (CPI), spore co. The most common method
used for determining the stage of maturation is Vitrinite reflectance (Ro) which
was discussed by several workers. Hood et al., (1975) noted that one of the
most useful measures of organic metamorphism is the reflectance of Vitrinite.
Tissot and Welte (1978) considered Vitrinite reflectance as the most powerful
Chapter Three Source Rocks Evaluation
55
tool. Waples (1985) considered a Vitrinite reflectance (Ro %) of 0.6% to mark
the early stage of oil generation, while the peak of oil generation is at Ro ≈
0.8%, and the late stage or the end of oil generation is marked at Ro ≈ 1.35%.
Carbon preference index (CPI) has received the greatest attraction among
methods using the chemical composition of saturates, for the determination of
both the type and maturity of organic matter. Bray and Evans (1961), based on
the progressive change of distribution of long chain n – alkanes during
maturation noticed that, in recent immature sediments the presence of long
chain normal alkanes of odd carbon number are predominant as a result of the
contribution of higher plants in most marine or terrestrial organic matter and
so carbon preference index (CPI) is high. Thermal degradation of kerogen
during catagenesis subsequently generates new alkanes without predominance.
Thus, the preference of odd – numbered molecules progressively disappears.
The original equation by Bray and Evans (1961) adopted in this study as the
following:
Bray and Evans (1961) pointed out that, high values of carbon
preference index (more than 2) refers to immature sediments and the low
values (around unity) indicate mature sediments. Most of the geochemical
data show coincident results on the evaluation of level of thermal maturation
of organic matter, except Tmax of the bulk rock parameter. The reason why the
Tmax value of the bulk rock sample is a little bit higher compared to other
parameters is that it could be increase due to the mineral matrix effect (Liu
and Lee, 2004). In the present study, the maturity of the analyzed samples has
been estimate utilizing the maximum temperature (Tmax) of Rock Eval
Pyrolysis, Vitrinite reflectance, study of normal alkanes of extracts, and
content of bitumen extraction.
Chapter Three Source Rocks Evaluation
56
This chapter focuses on source rock evaluation using extensive organic
geochemical program carried on a data set of rock samples. These samples
subjected to well defined, proven and efficient methods for source rock
characterization. These methods of source rock characterization arranged in
order are: (1) source rock characterization using Rock-Eval Pyrolysis, and (2)
source rock characterization using biomarkers. These techniques were used to
obtain independent parameters on organic matter composition, thermal
maturity and environment of deposition.
3.2. SOURCE ROCK CHARACTERIZATION USING ROCK-EVAL
PYROLYSIS
3.2.1. Sulaiy Formation
In the NO-1well, total organic carbon (TOC wt %), Vitrinite reflectance
(Ro) and Pyrolysis analyses were conducted on a total of 15 cutting samples
(Table 6-3) in order to measure the generation capability, organic matter type
and state of maturity of Sulaiy Formation within the study area. Total organic
carbon (TOC, wt%) content is generally used as an indicator of the kerogen
and bitumen amount (as weight percent) in a source rock. The TOC content of
Sulaiy Formation is between 0.73 - 3.84 wt% (Table 6-3, Fig.8-3A) indicating
good to very good source rock potentials.
S1 hydrocarbons in the whole rock are found in Free State, and they can
be disintegrated under heat. S1 hydrocarbon peak values indicate poor to good
generating potential (Table 6-3). The relatively low S1 values may suggest that
hydrocarbons are not yet produced from source rocks because of the low
thermal maturity.
Pyrolysis S2 yields indicate Good generating potential (Fig.8-3B). The
ratio of S2 to the TOC of the rock is the hydrogen index (HI). HI is a key
Chapter Three Source Rocks Evaluation
57
source rock parameter used in quantitative modeling of the phase and volume
of expelled hydrocarbons and the classification of kerogen type. In the present
work, the HI values (Table 6-3) comprised type-III and/or type III/II kerogen;
HI are typically range from 244 - 436 mg HC/g TOC (Figs.9-3).
The temperature at maximum hydrocarbon generation is the Tmax.
Tmax together with the vitrinite reflectance (Ro) indicate mature source rocks,
since the values range from 441 - 450o C and 0.66 - 0.78, respectively (Fig.8-3
C& D). Table (6-3): Organic richness, Pyrolysis data and Vitrinite reflectance for Sulaiy Fm
in Noor Well, Missan Oil Field
№ Depth (m)
TOC (wt%) (analyzed samples)
S1 S2 S3 Tmax HI OI Ro
1 4780 2.04 0.11 5.74 0.78 442 284.16 38.61 0.78 2 4800 1.88 0.18 5.42 0.96 443 288.30 51.06 0.71 3 4815 1.25 0.14 4.24 0.61 441 339.20 48.80 0.65 4 4825 0.9 0.36 2.20 0.79 443 244.44 87.78 0.71 5 4839 2.32 0.23 10.12 0.63 444 436.21 27.15 0.66 6 4850 0.87 0.16 2.82 0.59 443 324.14 67.82 0.71 7 4862 1.08 0.15 4.41 0.62 445 408.33 57.41 0.71 8 4878 0.73 0.15 1.76 0.52 446 241.09 71.23 0.68 9 4890 3.02 0.16 9.41 0.61 445 311.59 20.20 0.69 10 4900 2.35 0.23 10.12 0.79 444 430.63 33.62 0.66 11 4910 1.69 0.18 7.12 0.96 443 420.12 56.80 0.71 12 4915 3.12 0.11 12.74 0.78 445 408.33 25.00 0.69 13 4922 2.01 0.41 8.02 1.66 448 399.00 82.59 0.72 14 4928 3.84 0.14 11.24 0.61 448 292.71 15.88 0.72 15 4932 2.68 0.10 9.33 1.11 450 348.13 41.42 0.73
Chapter Three Source Rocks Evaluation
58
1 2 3 4
4950
4900
4850
4800
4750
4700
2 4 6 8 10 300 350 400 450
A. TOC (wt %) B. S (mg HC/g rock)2 C. Tmax
DE
PTH
(m)
D. Ro(%)
0.1 1.0
Poor
Poor
Fair
Fair
Goo
d
Goo
d
V. G
ood
V. G
ood
Imm
atur
e
Imm
atur
e
Oil
zone
Oil
Gen
erat
ion
Gas
Gen
erat
ion
Fig.(8-3): Geochemical characteristics TOC, S2, Tmax and Ro versus depth of Sulaiy
Formation.
Type I
Oxygen Index (mg Co / g TOC)2
0 50 100 150 200 250
100
200
300
400
500
600
600
800
900
1000
Type II
Type III
Hyd
roge
n In
dex
(mg
HC
/g T
OC
)
Fig. (9-3): HI versus OI of Sulaiy Formation (Espitalie et al., 1977).
HI.
OI.
Chapter Three Source Rocks Evaluation
59
To sum up, based on Rock-Eval Pyrolysis data, and Vitrinite
reflectance analysis of Sulaiy Formation in the studied well (No-1) is mature
to generate hydrocarbons and has capability to produce oil (type II kerogen),
generally the lower part of Sulaiy Formation lies within the oil window.
Moreover, in order to concise the various analyses have taken place for
the studied well, here is below a geochemical log (Figs.10-3) to make easy to
show the various geochemical parameters.
Chapter Three Source Rocks Evaluation
60
3.3 SOURCE ROCK CHARACTERIZATION USING BIOMARKERS
3.3.1 SOURCE AND AGE RELATED BIOMARKER PARAMETERS
This part of this chapter explains and helps to identify the
characteristics of the source rock (e.g. lithology, geologic age, type of organic
matter, redox conditions). Biological marker (biomarker, molecular fossil) can
be define as; complex organic compounds composed of carbon, hydrogen, and
other elements that are found in petroleum, rocks, and sediments and show
little or no change in structure from their parent organic molecules in living
organisms. These compounds are typically analyzed using gas
chromatography/ mass spectrometry. Most, but not all, biomarkers are
isopentenoids, composed of isoprene subunits. Biomarkers include pristane,
Phytane, steranes, triterpanes, and porphyrins (Peters et al., 2005).
ALKANES AND ACYCLIC ISOPRENOIDS
Pristane/Phytane
The most abundant source of Pristane (C19) and Phytane (C20) is the
Phytyl side chain of chlorophyll (a) in phototrophic organisms and
bacteriochlorophyll (a) and (b) in purple sulfur bacteria (e.g. Brooks et al.,
1969; Powell and McKirdy, 1973). Reducing or anoxic conditions in
sediments cleavage of the Phytyl side chain to yield Phytol, which undergoes
reduction to dihydrophytol and then phytane. Oxic conditions promote the
competing conversion of Phytol to Pristane by oxidation of Phytol to Phytenic
acid, decarboxylation to Pristane, and then reduction to Pristane. For rock and
oil samples within the oil-generative window, pristane/phytane correlates
weakly with the depositional redox conditions. High Pr/Ph (>3.0) indicates
terrigenous organic matter input under oxic conditions, while low values
(<0.8) typify anoxic, commonly hyper saline or carbonate environments
% ° C
Chapter Three Source Rocks Evaluation
61
(Peters et al., 2005). Phytane dominates over pristine in all the samples
analyzed, and Pr/Ph values range from 0.52 to 1.16 (Table 7-3). The higher
phytane content compared to that of pristane (in most cases) is probably due to
reducing conditions at the time of source rock deposition (Welte and Waples,
1973; Ten Haven et al., 1985, 1987), and/or to contributions by marine source
rocks during oil formation. Ten Haven et al. (1987) recommend against
drawing conclusions on the oxicity of the environment of deposition from
Pr/Ph alone. Consequently, inferences from Pr/Ph on the redox potential of the
source sediments should always be supported by other geochemical and
geologic data. Typically, conditions of source-rock deposition inferred from
Pr/Ph of oils agree with other indicators, such as sulfur content or the C35
homohopane index. Gas chromatograms of the six extracts (Figs. 11-3 to 16-
3) are vary notable and are characterized by a smooth n-alkane distribution
with a predominance of low-molecular weight compounds, and almost no
quantities of terrestrially derived waxy n-alkanes. This distribution, together
with Pr/Ph ratios close to 1.0 (Table 7-3), suggest dominant marine-source
input with no terrestrial contribution.
It is recognized that the low abundance of TOC suggests that a relative
oxicity of the depositional environment; this affects the amount and elemental
composition of the stored organic matter, In contrast, the less oxic
environment promoted better organic preservation in the depositional
environment (Tissot and Welte, 1984).
Chapter Three Source Rocks Evaluation
62
Fig. (11-3): Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for ( AG-2) well.
Fig. (12-3): Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for
(HF-2) well.
Retention time
Retention time
Res
pons
e R
espo
nse
Chapter Three Source Rocks Evaluation
63
Fig. (13-3): Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for
(R-167) well.
Fig. (14-3): Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for (AM-3) well.
Retention time
Res
pons
e R
espo
nse
Retention time
Chapter Three Source Rocks Evaluation
64
Fig. (15-3): Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for
(NO-1) well.
Fig. (16-3): Gas chromatographs of the C15+ saturated hydrocarbons in rock extracts for
(R-172) well.
Retention time
Res
pons
e R
espo
nse
Retention time
Chapter Three Source Rocks Evaluation
65
⎥⎥
⎦
⎤
⎢⎢
⎣
⎡+
++++++++
++++++++
3432302826
3331292725
3230282624
33312927252
1CCCCCCCCCC
CCCCCCCCCC
Table (7-3): Extracts gas chromatographic results for six wells in South Iraq.
№ Well Name
Depth (m) Formation Sample
type Lithology TOC Pr / Ph
Pr / nC17
Ph / nC18
CPI OEP
1 AG-2 3320 Jaddala Cutting Calc. marl 0.32 1.04 0.20 0.34 1.12 1.08 2 HF-2 4002 Rumila Cutting Calc. shale 0.45 0.84 0.16 0.29 1.10 1.01 3 R-167 4498 Sulaiy Core Carbonate 1.88 1.16 0.36 0.47 1.25 1.15 4 AM-3 4518 Sulaiy Core Carbonate 0.82 0.52 0.25 0.40 1.02 0.99 5 NO-1 4901 Sulaiy Core Carbonate 1.67 0.57 0.17 0.32 0.99 0.95 6 R-172 4800 Sargelu Cutting Carbonate 3.23 0.52 0.24 0.40 1.04 1.01
Pr: Pristane
Ph: Phytane
CPI: Carbon preference index
CPI = …… Bray and Evans, 1961
OEP: Odd-even predominance
OEP = (C25 + 6 C27 + C29) / (4C26 + 4C28) ……………………..……. Scalan and Smith, 1970
Pristane/n-C17 and phytane/n-C18 are sometimes used in petroleum
correlations studies. For example, Lijmbach (1975) noted that oils from rocks
deposited under open-water conditions showed=Pr/n-C17 <0.5, while those
from inland peat swamps had ratios greater than one (1). Alexander et al.
(1981) suggested use of the ratio (Pr+nC17) / (Ph+nC18) because it is less
affected by variation in thermal maturity than Pr/n-C17 or Ph/n-C18.
Biodegradation increases these ratios because aerobic bacteria generally attack
n-alkanes before the isoprenoids. A plot of pristane/n-C17 versus phytane/n-C18
ratios indicates that the source rock extracts originated from type II organic
matter (Figs.17-3 & 18-3) deposited under marine algal type conditions.
MRM-GCMS RESULTS
The parent-mode metastable reaction monitoring (MRM/GCMS) offers
advantage in selectivity and signal-to-noise ratio that are similar to parent
mode GCMS-MS using a tandem instrument.The uses a double-focusing
magnetic instrument, may be more readily available than a tandem instrument.
Chapter Three Source Rocks Evaluation
66
May be quantitatively more reproducible than GCMS/MS because of fewer
variables to control (e.g. collision cell or Q3) (Peters et al., 2005). Of the
extract source rocks samples, six samples were chosen to run on the Stanford
Autospec in the metastable reaction monitoring GC-mass spectrometry
(MRM/GCMS) mode to be able to calculate 24-Nordiacholestane (NDR) and
24-norcholestane (NCR) ratios, as defined by Holba et al. (2000). A well-
characterized standard routinely employed in the lab was run with samples in
this study, thus allowing compound determinations by comparing the results
to the standard. All calculated biomarker ratios are base on peak area
measurements (Fig. 19-3 to 22-3).
0.1
10
1.0
Oxida
tion
Reduction
TerrigenousType III
Mixed Type II/III
Ph / nC18
Pr/ n
C17
0.1 1.0 10
100
Marine Algal Type II
Biodegradation
Maturation
Extract rocks Fig. (17-3): Pristane /nC17 versus phytane/nC18 for source rock extracts in the study area,
can be used to infer oxicity and organic matter type in the source-rock depositional environment (Peters et al., 1999; Shanmugam, 1985).
Chapter Three Source Rocks Evaluation
67
Fig. (18-3): Cross-plot of pristane/nC17 versus phytane/nC18, showing the genetic type of
organic matter for crude oil samples (Obermajer et al., 1999).
3.4. Nordiacholestane and 24-norcholestane ratios
Information on C26 steranes in petroleum is seldom accessible using
conventional SIM/GCMS because concentrations of C26 steranes are typically
an order of magnitude lower than the C27 - C29 steranes. Furthermore, their gas
chromatographic retention times coincide with the early eluting C27 - C29
sterane and diasteranes, resulting in interference (Peters et al., 2005).
Three series of C26 steranes are known, including 21-, 24-, and 27-
norcholestanes (Moldowan et al., 1991). The 21- and 27-norcholestanes
appear to have no direct sterol precursors but may originate through bacterial
oxidation or thermally induced cleavage and loss of a methyl group from
larger steroids (>C26). On the other hand, traces of 24-norcholestanes occur in
living marine algae and invertebrates, suggesting an origin in eukaryotes
(Goad and Withers, 1982). However, all three series of C26 steranes occur in
both marine and non-marine crude oils.
The ratio of C24/(C24 + C27)-norcholestanes is an effective source-
correlation parameter as it was used to distinguish marine from non-marine
Chapter Three Source Rocks Evaluation
68
crude oils from Upper and Lower Cretaceous rocks, respectively in Angola
(Moldowan et al., 1991).
Nordiacholestanes help to distinguish Tertiary from Cretaceous and
Cretaceous from older oils.
Two ratios, 24-nordiacholestane ratio (NDR) and 24-norcholestane ratio
(NCR), may defined respectively by equations (1) and (2) using peaks
designated by the numbers in figure ().
NDR = ]4321[
]21[+++
+ ……….. 1 &
NCR = ]131211108765[
]8765[+++++++
+++ ………..2
For both ratios, the initial elevation of the ratios occurs in the Jurassic
(NDR>0.20, NCR>0.30) when the first preserved diatom fossils were
recognized (Lipps, 1993; Tappan, 1980). A second, more significant increase
in 24-norcholestane abundance occurs in the Cretaceous (NDR>0.25,
NCR>0.40) when diatoms experienced a rapid expansion and associated
species diversification (Tappan, 1980; Lipps, 1993; Stewart and Rothwell,
1993). The next major increase in the ratio profiles with age occurs in oils
derived from Oligocene and younger sources i.e. generally Neogene
(NDR>0.50, NCR>0.60), which represent deposition of siliceous
(diatomaceous) source rocks. Table (8-3) lists the NCR and NDR ratios for a
suite of source rock extracts for the study area. Source rock extracts
formations have medium values of both NCR and NDR (up to 0.44 and 0.30,
respectively) consistent with their Cretaceous age for three samples( R-167,
Am-3, No-1).For the forth extract source rock ( R-172) has NCR=0.29 and
NDR=0.18, consistent with their Jurassic age.
Chapter Three Source Rocks Evaluation
69
12
3
4
5 6
7
8
9
10
11
1213
Fig. (19-3): Metastable reaction monitoring/gas chromatography/mass spectrometry
(MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (R-167).
Res
pons
e
Retention time
Chapter Three Source Rocks Evaluation
70
1
2
3 4
5
67 8
9
10
11
1213
Fig. (20-3): Metastable reaction monitoring/gas chromatography/mass spectrometry
(MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (AM-3)
1
2
34
5 6
7 8
9
10
11
1213
Fig. (21-3): Metastable reaction monitoring/gas chromatography/mass spectrometry
(MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (NO-1)
Res
pons
e
Retention time
Res
pons
e
Retention time
Chapter Three Source Rocks Evaluation
71
12
3
4
5
67 8
9
10
11
12
13
Fig. (22-3): Metastable reaction monitoring/gas chromatography/mass spectrometry
(MRM-GCMS) m/z 358 →217 analyses of C26 steranes for extract source rock sample well (R-172)
3.5. MATURITY-RELATED BIOMARKER/ NON-BIOMARKER
PARAMETERS
ALKANES AND ISOPRENOIDS
Isoprenoids/n-alkane ratios
Pristane/nC17 and phytane/nC18 decrease with thermal maturity as more
n-alkanes are generate from kerogen by cracking (Tissot et al., 1971). These
isoprenoids/n-alkanes ratios can be used to assist in ranking the thermal
maturity of related, non-biodegraded oils and bitumens (Table 7-3).
Carbon preference index & odd-even predominance
The relative abundance of odd versus even carbon-numbered n-alkanes
can be use to obtain a crude estimate of thermal maturity of petroleum. These
Chapter Three Source Rocks Evaluation
72
⎥⎥
⎦
⎤
⎢⎢
⎣
⎡+
++++++++
++++++++
3432302826
3331292725
3230282624
33312927252
1CCCCCCCCCC
CCCCCCCCCC
measurements include the carbon preference index (CPI) (Bray and Evans,
1961) and the improved odd-to-even predominance (OEP) (Scalan and Smith,
1970) are shown below. CPI = …………………………..1 OEP = (C25 + 6 C27 + C29) / (4C26 + 4C28)……………………………………………….2 OEP = (C21 + 6 C23 + C25) / (4C22 + 4C24)……………………………………………….3
CPI or OEP values significantly above (odd preference) or below (even
preference) 1.0 indicates low thermal maturity. Values of 1.0 suggest, but do
not prove, that an oil or rock extract is thermally mature. CPI or OEP values
below 1.0 are unusual and typify low-maturity oils or bitumen’s from
carbonate or hyper saline environments (Peters et al., 2005).
Table (7-3) suggests a considerable odd versus even-predominance for
the extracts source rocks. All the source rock extracts are mature in the in the
study area , where CPI or OEP ratios more or less approach 1.0.
C26 21/(21 + 27)-norcholestane ratio
Analysis by GCMS/MS (m/z 358 → 217) of four Phosphoria sourced
Wyoming oils shows a progressive relative increase in 21-norcholestanes and
to a lesser extent 27-norcholestanes compared to other C26 steranes, with
increasing thermal maturity (Moldowan et al., 1991).
Judging from the results on oil sets 21/ (21+24+27)-norcholestanes may
be an effective maturity parameter for the middle to late part of the oil
window. Thus, it appears that the 21-norcholestanes are more stable at higher
temperatures and/or are generated later than 24- and 27-norcholestanes. The
ratio 21/ (21+24+27)-norcholestanes has potential for maturity assessment as
shown by its systematic increase for the source rock extracts. The 21-
norcholestanes ratio gradually increases.
Chapter Four Reservoir organic geochemistry
74
4.1. Crude Oil Characterization
Originally, petroleum was defined as a liquid substance referred to as
"crude oil" or simply "oil" occurred in underground natural reservoirs, but the
definition has been broadened to include hydrocarbon gases referred to as
"natural gases" occurring in similar reservoirs. Oil is a complex mixture
containing a large number of closely related compounds (Tissot and Welte,
1984). The compounds present and their relative amounts are controlle
initially by the nature of the organic matter in the source rock. With more
specific words, the relative amounts of normal alkanes, isoprenoids, aromatics
and sulfur compounds, are characteristic of the source and should be
essentially the same for all oil derived from a particular source rock. The fact
that, variations in crude oil composition are to a certain extent inherited from
different source rocks. For instance, coaly material in general yields more
gaseous compounds, while high-wax crude oils are commonly associated with
source material containing high proportions of lipids of terrestrial higher
plants and of microbial organisms (Hunt, 1996). High-sulfur crude oils
frequently related to carbonate-type source rock. A side from the influence of
source rock facies, the state of maturity of the source material is also of
importance. However, much larger variations in composition could cause
processes operating in the reservoir. In other words, crude oil alteration
processes (thermal alteration, deasphalting, biodegradation and water
washing) tend to obscure the original character of the oil, and therefore affects
crude oil correlation, furthermore influence the quality and economic value of
petroleum (Tissot and Welte, 1984). Therefore, the carefully studying of the
chemical compositions of the rock extracts, seeps and produced oil can
minimize the risk associated with finding petroleum accumulations.
Consequently, the present author constitutes this chapter to throw more light
Chapter Four Reservoir organic geochemistry
75
on the composition, classification and the geochemical characterization of
crude oil samples, through several routine and advanced geochemical analyses
from productive fields within the study area. In order to scrutinize these
analyses, about eighteen (18) representative crude oil samples have been
collected from different eighteen (18) productive wells from different (6) Oil
fields within the study area. The results of routine geochemical analyses of oil
samples are summarized in Table (8-4).
4.2. Group composition of crude oils
The gross composition of crude oil can be defined by the following
main groups:
• Saturate hydrocarbons: saturated hydrocarbons in which each carbon
atom is bonded four other atoms, either carbon or hydrogen, comprising
normal, branched alkanes (paraffins) and cycloalkanes (naphthenes).
• Aromatic hydrocarbons: unsaturated hydrocarbons are unsaturated with
respect to hydrogen, including pure aromatics, cycloalkanoaromatic
(naphthenoaromatic) molecules, and usually cyclic sulfur compounds.
• Resins and asphaltenes: made of the high molecular weight polycyclic
fraction of crude oil comprising N, S and O atoms. Asphaltenes are
insoluble in light alkanes and thus precipitate with n-hexane. Resins are
more soluble, but are likewise very polar and are strongly retained on silica
gel when performing liquid chromatography, unless a polar solvent is used
as the mobile phase.
These parameters are not independent, as all crude oils consist of these
four groups of components. If one of these groups is missing, the other three
groups of course, amount to 100%, as saturates plus aromatics plus resins and
Chapter Four Reservoir organic geochemistry
76
asphaltenes are unity. This fact automatically introduces a certain degree of
correlation between these groups and their subdivisions.
4.3. Classification of crude oils
Various crude oil classifications have been proposed by geochemists
and petroleum refiners. The purpose of these is very different, and also the
physical or chemical parameters which have been used in the classification.
Petroleum refiners are mostly interested in the amount of the successive
distillation fractions (e.g. gasoline, naphtha, kerosene, gas oil, lubricating
distillate) and the chemical composition or physical properties of these
fractions (viscosity, cloud test, etc.); (Tissot and Welte,1984). However,
geologists and geochemists are more interested in identifying and
characterizing the crude oils, to relate them to source rocks and to measure
their grade of evolution. Therefore, they rely on the chemical and structural
information of crude oil constituents, especially on molecules which are
supposed to convey genetic information. A well known used classification of
crude oils based on distillation and specific gravities of two key fractions of
distillation. Other classifications have been proposed based on refractive
index, density and molecular weight. The newly proposed classification is
based on the content of the various structural types in crude oils (alkanes,
cycloalkanes, aromatics) plus NSO compounds (resins and asphaltenes) and
the distribution of the molecules within each type. It also takes into account
the sulfur content (Tissot and Welte, 1984).
According to Tissot and Welte (1984), the main classes of crude oils
are:
Chapter Four Reservoir organic geochemistry
77
a. Paraffinic class: crude oils will be considered as paraffinic, if the total
content of saturated hydrocarbons is over 50% of a particular crude oil,
paraffins content is more than 40%, naphthenes is less than 50%. The
amount of asphaltenes plus resins is below 10%, and sulfur content is less
than 1%.
b. Paraffinic – naphthenic class: the class paraffinic – naphthenic oils has a
moderate resins plus asphaltenes content (usually 5 to 15%) and a low
sulfur content (0 to 1%). Aromatics amount to 25 to 40% of the
hydrocarbons.
c. Naphthenic class: the naphthenic oil includes mainly degraded oils, they
originates from biochemical alteration of paraffinic – naphthenic oils and
usually have more than 40% naphthenes and they usually have a low
sulfur content (below 1% although they are degraded).
d. Aromatic – intermediate class: is comprised of crude oils which are
often heavy. Resins and asphaltenes amount to ca. 10 – 30 % and
sometimes more, and the sulfur content is above 1%. This oil class the
aromatics amount to 40 – 70 %.
e. Aromatic – naphthenic and aromatic asphaltic class: are mostly
represented by altered crude oils. Therefore, most aromatic – naphthenic
and aromatic – asphaltic oils are heavy, viscous oil resulting originally
from degradation of paraffinic – naphthenic, or aromatic intermediate oils.
The resin plus asphaltene content is usually above 25% and may reach
60%. However, the relative content of resins and asphaltenes, and the
amount of sulfur, may vary according to the type of the original crude oils.
This type can be subdivided into:
Chapter Four Reservoir organic geochemistry
78
1. Aromatic – naphthenic class: is mainly derived from paraffinic or
paraffinic naphthenic oils. The resins to asphaltenes ratio of 2% or more,
with a sulfur content below 1%.
2. Aromatic – asphaltic class: includes a few true aromatic oils, apparently
non-degraded. However, it is mainly comprise of heavy, viscous, or even
solid oils, resulting from alteration of aromatic – intermediate (particularly
high sulfur) crude oils.
4.4. Crude oil geochemistry
Adequate sampling of crude oils is essential for their characterization.
Geochemical characterizations of crude oils increase the efficiency of
petroleum exploration and exploitation programmes. According to Tissot and
Welte (1984), the common methods for geochemical characterization of crude
oils are the measurement:
• API gravity
• Sulfur content
• Crude oil compositions
• Stable carbon isotope compositions (δ 13C ‰)
• Biological markers
4.4.1. API gravity
API gravity is a measure of the density or specific gravity of crude oils,
and is report in degrees (oAPI). According to Waples (1985), the API gravity
could be calculated as the following equation:
API =( 141/Specific gravity) – 131.5
Chapter Four Reservoir organic geochemistry
79
Waples (1985) reported that, oils have API gravities ranging from 20o
to 45o regarded mostly as normal crude oils, where those of less than 20o are
usually biodegraded, and above 45o are rated as condensate oils. The oil
samples recovered from the Kirkuk Group,Sadi, Nahr Umr,and Mishrif
reservoirs within the study area have oAPI gravities ranging from 17.5o to
30.20o (Table 8-4).
4.4.2. Sulfur content
Sulfur is the third most abundant atomic constituents of crude oils,
following carbon, hydrogen and expressed as weight percent. Tissot and Welte
(1984) suggested that, oils with low sulfur content less than unity classified as
paraffinic, paraffinic – naphthenic or naphthenic classes, while oils of high
sulfur (more than unity) belongs to the aromatic intermediate class. They also
added that, there is inverse relation between maturation and sulfur content in
crude oils, where the sulfur content decreases with increasing maturity.
This conclusion was confirmed by Waples (1985) who considered the
sulfur content as a maturity influenced parameter. On the other hand,
Moldowan et al. (1985) used the sulfur content as an indicator of the source
origin; as oils of marine origin has more than 0.5 % sulfur.
Chapter Four Reservoir organic geochemistry
80
Table (8-4): Crude oil liquid chromatography results for wells in the Missan Province.
Liquid chromatography wt% Stable carbon isotopes No Well Name
Depth (M) API S % Sat. Arom. Resins Asphalt. Sat. ‰ Arom. ‰ CV *
1 HF-2 2768-2803 22.4 4.85 22.5 45.7 16.7 15.1 -27.59 -27.74 -3.43 2 AG-1 2886-2994 21.0 4.64 21.2 48.0 16.0 14.8 -27.72 -27.50 -2.57 3 AG-10 2920-2930 19.8 4.12 23.5 49.0 14.6 12.9 -27.52 -27.62 -3.34 4 AG-11 2946-3018 20.4 4.23 23.4 48.1 15.7 12.8 -27.60 -27.51 -3.15 5 AG-7 3010-3045 22.4 4.24 23.0 48.3 15.5 13.2 -27.64 -27.62 -3.04 6 FQ-8 3043-3049 21.5 3.89 24.4 51.6 13.5 10.5 -27.52 -27.63 -3.36 7 FQ-11 3058-3064 17.4 4.01 19.6 49.2 18.2 13.1 -27.36 -27.73 -3.99 8 FQ-2 3081-3084 20.2 3.90 22.5 52.7 12.2 12.6 -27.51 -27.53 -3.17 9 NO-2 3366-3383 **NA **NA 31.5 40.0 14.7 13.8 **NA **NA **NA 10 HF-1 3681-3706 30.1 2.74 35.5 39.9 13.0 11.6 -28.12 -27.65 -1.89 11 AM-3 3741-3745 27.8 2.85 34.4 40.4 14.7 10.5 -28.07 -27.92 -2.62 12 BU-13 3794-3808 22.6 **NA 22.5 48.4 14.1 15.0 -27.65 -27.77 -3.43 13 BU-20 3810-3820 18.9 2.56 21.4 41.1 14.8 22.7 -27.68 -27.64 -2.98 14 BU-11 3825-3835 25.7 5.12 24.0 49.6 13.2 13.2 -27.67 -27.87 -3.52 15 BU-17 3849-3863 21.8 **NA 22.0 47.5 15.7 14.8 -27.70 -27.80 -3.05 16 FQ-3 3930-3940 20.6 3.67 26.2 42.1 14.2 17.5 -27.81 -27.68 -2.74 17 FQ-4 4000-4015 19.5 3.85 20.6 53.3 15.6 10.5 -27.46 -27.60 -3.45 18 FQ-5 4023-4038 22.7 4.19 23.9 48.2 15.2 12.7 -27.62 -27.69 -3.24
* CV = Canonical variable **NA = No analysis (no data)
In the respective area, all the studied reservoired oils have high sulfur
content ranging from 2.56 % to 5.12 % (Table 8-4). According to Moldowan
et al. (1985), all the oil samples recovered from the area under consideration
seem to be originate from a marine source as they contain more than 0.5 %
sulfur content. Most primary sulfur in petroleum originates from early
diagenetic reactions between the deposited organic matter and aqueous sulfide
species. Sulfides are produced by sulfate-reducing bacteria, primarily in
highly reducing anoxic depositional environments (Peters and Moldowan,
1991).
4.4.3. Crude oil compositions
In the present study, the saturate and aromatic hydrocarbons together
with the non – hydrocarbon fractions (resins and asphaltenes) are separated
from the crude oil samples using liquid chromatography on an
Chapter Four Reservoir organic geochemistry
81
alumina silica gel column. These fractions are expresses as weight percent of
the whole sample and listed in Table (8-4) to show the compositional data of
eighteen (18) crude oil samples recovered from the study area. The gross
composition ternary diagram proposed by Tissot and Welte (1984) indicates
that all the studied oil samples are located in the region of normal oils (Fig.23-
4). Thoroughly, the samples recovered from the study area, regardless to their
depths, contains more than 20 % resins plus asphaltenes, more than 2.0%
sulfur content and less than 50 % aromatic compounds of the total
hydrocarbons. Moreover, the abundance of paraffins over naphthenes and
NSO compounds suggests that, all the oil samples are mainly mature.
Generally, the average of saturated hydrocarbon fraction increase with depth.
The aromatic hydrocarbons are about 40 % as abundant as the saturate
hydrocarbons (Table 8-4). Furthermore, the total hydrocarbons increase with
increasing depth, inversely, the percentage of non – hydrocarbon fraction
(resins + asphaltenes) showed an observable decrease in its amounts as the
depth increases.
Barton (1934) first reported the change of composition with depth on
the crude oils of the Gulf coast. He noted a progressive decrease of density
and an increase in paraffinic content with increasing depth of the producing
interval. Hunt (1953) from the Tensleep oils of Wyoming observed the same
phenomenon, as the depth effect does not obliterate major differences
resulting from different source rocks and does not account for variations of
geothermal data. Since then, the change of composition with depth results
mainly from progressive cracking of carbon chains that causes the content of
light hydrocarbons to increase.
Chapter Four Reservoir organic geochemistry
82
Aromatic HC
NSO Compounds(Resins+Asphaltenes)
Saturated HC
NORMAL OILS
MOSTLY HEAVY, DEGRADED OILS
20
40
60
80
20406080
20
40
60
80
Isofrequency contours (percent)
Crude Oil Sample Fig. (23-4): Ternary diagram showing the gross composition of crude oil samples
4.4.3.1. Gas chromatographic analysis (GC) and C15+ hydrocarbon
composition
The C15+ hydrocarbon composition and the distribution of specific
compounds within the hydrocarbon fractions provide considerable information
on both source rock depositional environment and degree of thermal maturity
of crude oil samples.
Gas chromatograms of the saturated hydrocarbons are most useful in the
identification of biomarkers which can be used as indicators to the organisms
from which the organic matter was derived (Waples, 1985). Waxy oils are
generally considered to originate from kerogen of a non – marine (terrigenous)
land-derived origin, deposited in lacustrine, paralic or deltaic environment.
Non – waxy oils are generally derive from kerogen deposited in open marine
environment where the contribution of land derived organic matter is limited
to physiographic, climatic or other reasons (Tissot and Welte, 1984).
Chapter Four Reservoir organic geochemistry
83
The terrestrial oils are differentiated from marine oils by their high Pristane /
Phytane ratio (routinely determined by GC), in most cases more than 3, also
the wax content is high (more than 10 %). This content is normally calculate
by the relative abundance of the C22 to C29 n-alkane versus C17 to C21 n-alkane
(Waples, 1985). However, the ratio of Pristane / Phytane should be use with
caution in interpreting oil source bed environment (Waples, 1985; Hunt,
1996). This is because as maturity proceeds, phytane is generate faster than
Pristane, leading to a decrease in pristane / phytane ratio. Powell and McKirdy
(1973) pointed out that, high pristane / phytane ratio more than unity
suggested oxidizing environment and less than unity indicate reducing
environment. Chung et al. (1992 and 1994) distinguished three groups of
marine petroleum, informally named carbonate oils, deltaic oils, and marine
shale oils, based on the composition of organic matter in the source rocks from
which the oils be derived. Source rocks that give rise to carbonate oil contain
only marine organic matter and are characterized by low pristane / phytane
ratio (less than unity), while source rocks that give rise to deltaic oils, show
more contribution from terrestrial organic matter and detrital sediments, and
characterized by predominance of high pristane / phytane ratio \(more than
unity). Marine shale oils are mainly derived from source rocks contain marine
organic matter with mostly detrital sediments, and marked by high pristane /
phytane ratio (more than 3). On the other hand, carbonate oils are
differentiated from deltaic oils by their high sulfur content (≥ 0.5) and low
pristane / phytane ratio (≤ 1.0), (Palacas et al., 1984; Sofer, 1988; Claypool
and Mancini, 1989 and Peters et al., 1993 and 1994). The results of gas
chromatograms of the saturated hydrocarbons (C15+) of the study area are
shown in figures (24-4 to 41-4). The whole oil gas chromatograms samples
results, are highly similar appearance, they indicate a moderate concentration
Chapter Four Reservoir organic geochemistry
84
of most of the n-alkanes. n-C15 seems to be the most abundant n-alkane; the
isoprenoids Pristane and Phytane are detected.
It is clear noticed that, the crude oils have low pristane (pr)/ Phytane
(ph) ratios of 0.52 – 0.64 together with a moderately low pristane/nC17 and
phytane/nC18 ratios of ( 0.11 – 0.16) and (0.22 – 0.31) respectively. Such
values suggest that they are generated from a source rock containing mainly
marine organic matter of algal type II kerogen, (Shanmugam, 1985; Peters et
al., 1999) (Fig. 42-4). The carbon preference index (CPI) of the studied oils
and up to 1.10 (Table 9-4) shows an odd carbon preference; indicating mature
samples (Waples, 1985).
Chapter Four Reservoir organic geochemistry
85
Fig. (24.4): Gas chromatograms for Crude oil sample from HF-2 well.
Fig. (25-4): Gas chromatograms for Crude oil sample from AG-1 well.
Retention time
Res
pons
e
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Res
pons
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Chapter Four Reservoir organic geochemistry
86
Fig. (26-4): Gas chromatograms for Crude oil sample from AG-10 well.
Fig. (27-4): Gas chromatograms for Crude oil sample from AG-11 well.
Retention time
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pons
e
Retention time
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pons
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Chapter Four Reservoir organic geochemistry
87
Fig. (28-4): Gas chromatograms for Crude oil sample from AG-7well.
Fig. (29-4): Gas chromatograms for Crude oil sample from FQ-8well.
Retention time
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pons
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pons
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Chapter Four Reservoir organic geochemistry
88
Fig. (30-4): Gas chromatograms for Crude oil sample from FQ-11well.
Fig. (31-4): Gas chromatograms for Crude oil sample from FQ-2well.
Retention time
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pons
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pons
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Chapter Four Reservoir organic geochemistry
89
Fig. (32-4): Gas chromatograms for Crude oil sample from NO-2well.
Fig. (33-4): Gas chromatograms for Crude oil sample from HF-1 well.
Retention time
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pons
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pons
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Chapter Four Reservoir organic geochemistry
90
Fig. (34-4): Gas chromatograms for Crude oil sample from AM-30well.
Fig.(35-4): Gas chromatograms for Crude oil sample from BU-13well.
Retention time
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pons
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pons
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Chapter Four Reservoir organic geochemistry
91
Fig. (36-4): Gas chromatograms for Crude oil sample from BU-20 well.
Fig. (37-4): Gas chromatograms for Crude oil sample from BU-11 well.
Retention time
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pons
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pons
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Chapter Four Reservoir organic geochemistry
92
Fig. (38-4): Gas chromatograms for Crude oil sample from BU-17 well.
Fig. (39-4): Gas chromatograms for Crude oil sample from FQ-3 well.
Retention time
Res
pons
e
Retention time
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pons
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Chapter Four Reservoir organic geochemistry
93
Fig.(40-4): Gas chromatograms for Crude oil sample from FQ-4 well.
Fig. (41-4): Gas chromatograms for Crude oil sample from FQ-5 well.
Retention time
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pons
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Chapter Four Reservoir organic geochemistry
94
Table (9-4): Crude oil gas chromatography results for wells in the study area. Sample
No. Well
Name Interval (m) Producing Unit Pr / Ph Pr / n C17 Ph / n C18 CPI OEP
1 HF-2 2768-2803 Sadi ٠٫٩٢ ١٫٠٥ ٠٫٢٤ ٠٫١٢ ٠٫٥٨ 2 AG-1 2886-2994 Jeribe-Euphrates ٠٫٩٦ ١٫٠٨ ٠٫٢٨ ٠٫١٤ ٠٫٦١ 3 AG-10 2920-2930 Jeribe-Euphrates ٠٫٩٦ ١٫٠٦ ٠٫٢٨ ٠٫١٤ ٠٫٦٠ 4 AG-11 2946-3018 Jeribe-Euphrates ٠٫٩٧ ٠٫٩٥ ٠٫٣١ ٠٫١٤ ٠٫٥٢ 5 AG-7 3010-3045 Upper.Kirkuk ٠٫٩١ ١٫٠٥ ٠٫٢٥ ٠٫١١ ٠٫٥٢ 6 FQ-8 3043-3049 Upper.Kirkuk ١٫٠٣ ١٫١٢ ٠٫٢٧ ٠٫١٢ ٠٫٦٢ 7 FQ-11 3058-3064 Upper.Kirkuk ٠٫٩٦ ١٫١٠ ٠٫٢٥ ٠٫١١ ٠٫٥٤ 8 FQ-2 3081-3084 Jeribe-Euphrates ٠٫٩٤ ١٫١٤ ٠٫٢٩ ٠٫١٣ ٠٫٥٥ 9 NO-2 3366-3383 Mishrif ٠٫٩٧ ١٫٠٨ ٠٫٢٢ ٠٫١٦ ٠٫٦٤
10 HF-1 3681-3706 Nahr Omr ٠٫٩٣ ٠٫٩٨ ٠٫٢٣ ٠٫١٢ ٠٫٦٢ 11 AM-3 3741-3745 Nahr Omr ٠٫٩٥ ٠٫٩٨ ٠٫٢٢ ٠٫١٢ ٠٫٥٩ 12 BU-13 3794-3808 Mishrif ٠٫٩١ ١٫٠٣ ٠٫٢٦ ٠٫١٢ ٠٫٥٤ 13 BU-20 3810-3820 Mishrif ٠٫٩٣ ١٫٠٤ ٠٫٢٦ ٠٫١٢ ٠٫٥٧ 14 BU-11 3825-3835 Mishrif ٠٫٩٣ ١٫٠٤ ٠٫٢٥ ٠٫١١ ٠٫٥٤ 15 BU-17 3849-3863 Mishrif ٠٫٩٤ ١٫٠٧ ٠٫٢٤ ٠٫١١ ٠٫٥٣ 16 FQ-3 3930-3940 Mishrif ٠٫٩٦ ١٫٠٤ ٠٫٢٧ ٠٫١٤ ٠٫٦١ ١٧ FQ-4 4000-4015 Mishrif ٠٫٩٣ ٠٫٩٧ ٠٫٣١ ٠٫١٣ ٠٫٥٤ ١٨ FQ-5 4023-4038 Mishrif ٠٫٩٥ ١٫١٠ ٠٫٢٧ ٠٫١٤ ٠٫٦١
0.1
10
1.0
Oxidation
Reduction
Terrigenous Type III
Mixed Type II/III
Ph / nC18
Pr /
nC17
0.1 1.0 10
100
Marine Algal Type II
Biodegradation
Maturation
1011311 1426121 51617 97
43 581819
Fig. (42-4): Plot of pristane/nC17 versus phytane/nC18, showing organic matter type, source
rock depositional and thermal maturity of crude oil samples (Shanmugam, 1985; Peters et al., 1999).
Chapter Four Reservoir organic geochemistry
95
4.4.4. Stable carbon isotope composition (δ13C ‰)
The geochemical significance and range of carbon isotopic composition
of crude oil and crude oil fractions has been the subject of many studies, as an
indicator of the depositional environment, and as a tool in oil-oil and oil-
source correlations (Alexander et al., 1981 and Sofer, 1984). Carbon isotope
values are obtaine by converting the sample to CO2 in an atmosphere of
oxygen at 860o C, then using mass spectrometers to measure the relative
amount of 13C and 12C in the sample compared with those in the Peedee
Belemnite standard (PDB limestone). The results are expresses as per- mil
deviation from the standard and are calculated using the following equation
(Waples, 1985):
δ13C = [(13C/12C Sample) / (13C/12C Standard) – 1] х 1000
Silverman (1963) used the stable carbon isotope to show the genetic
relationship between lipids in living organisms in both marine and non –
marine environments and crude oils. Degens (1969), has reported the results
of 600 isotope analyses of a crude oil and showed that the average of those
measurements is identical to the average composition of lipid fraction
obtained from present – day marine planktons. He also added that the average
carbon isotope composition of crude oils from various geologic ages changes
from -30 ‰ for pre-Devonian oils to -27 ‰ for Pennsylvanian oils, then back
to -31 ‰ for Tertiary oils. Hunt (1970); Tissot and Welte (1978) and Rogers
(1980) concluded that, oils derived from terrigenous organic matter (waxy oil)
are isotopically lighter (more negative) than marine oils. Sofer (1984)
suggested that the isotope composition of oils could change owing to
maturation and possibly migration effects and due to minor in-homogeneities
in the source material. He also recognized that, the isotope composition of oil
Chapter Four Reservoir organic geochemistry
96
fractions (saturates and aromatics), excluding the biodegraded oils, by a
mathematical relation known as canonical variable (CV). The relation between
the canonical variable (CV) and the isotope composition of the saturate and
aromatic hydrocarbons be given by the following equation (Sofer, 1984):
CV = -2.53 δ 13Csaturate + 2.22 δ 13Caromatic – 11.65
The oil sample with a canonical variable (CV) value larger than 0.47 is
classified as waxy (terrigenous) oil and the sample with a canonical variable
(CV) less than 0.47 is classified as non – waxy (marine) oil. However, this
value (0.47) is arbitrary in a way, because it is obtained mostly from statistical
considerations and very little from geochemical consideration (Sofer, 1984).
Hence, the classification based on the canonical variable (CV) have to be
correlated and supported by other geochemical parameters such as n-alkane
distribution.
Pristane / Phytane ratios show some kind of correlation with the
canonical variable (CV). Sofer (1984) suggested that, terrigenous oils with
high Pristane / Phytane ratio (> 1.0) are usually associated with high values of
CV, and marine oils with low pristane / phytane ratio (< 1.0) are associated
with low values of CV. However, many terrigenous oils show low pristane /
phytane ratios and marine oils show high pristane / phytane ratios, this is due
to the effect of maturity (Sofer, 1984). The isotopic values of the investigated
oil samples were done in the Molecular Organic Geochemistry lab, Geological
&Environmental Sciences Department (GES) -School of Earth Sciences -
Stanford University. Table (8-4) shows that there is no variation among the
carbon isotopes of the oil fractions of the eighteen crude oil samples,
indicating that, these samples are isotopically similar and genetically related.
The carbon
Chapter Four Reservoir organic geochemistry
97
isotope value of saturate fraction ranges from -28.12 to -27.36 ‰ and for
aromatic fraction ranges from -27.92 to -27.50 ‰ (Table 8-4), suggesting a
mature, marine oil samples [Denison et al., 1990; Hunt, 1970; Tissot and
Welte, 1978 and Rogers, 1980]. The calculated canonical variable (CV) values
of the Tertariary and Cretaceous oil samples ranges from (-3.99 to -1.89)
indicating non waxy oils derived from marine sources, as described by Sofer
(1984) (Fig. 43-4). Zumberge (1993) used the relation between the carbon
isotopes of the saturate fractions and those of aromatic to differentiate
between marine and non-marine oils. It is clear obvious from figure (43-4)
that, the oils samples within the study area are derived mainly from marine
source rocks.
C13Saturates
C13
Aro
mat
ics
-32 -30 -28 -26 -24 -22 -20 -18-32
-30
-28
-26
-24
-22
-20
-18
-16
NON MARINE OILS
MARINE OILS
Transiti
onal zone
3124614
121711 18879 1319
Fig. (43-4): Relation between the stable isotope compositions of saturates and aromatics for
crude oil samples for the study area. (After Sofer, 1984).
Chapter Four Reservoir organic geochemistry
98
Biomarkers (or geochemical fossils) are molecules inherited from the
organisms living at the time of sediment deposition, which have preserved
without subsequent alteration, or with only minor changes, so that they keep
the main features of their chemical structures (Tissot and Welte, 1984).
4.1.5. ALKANES AND ACYCLIC ISOPRENOIDS
4.1.5.1. Pristane/Phytane
The most abundant source of pristane (C19) and phytane (C20) is the
phytyl side chain of chlorophyll (a) in phototrophic organisms and
bacteriochlorophyll (a) and (b) in purple sulfur bacteria (e.g. Brooks et al.,
1969; Powell and McKirdy, 1973). Reducing or anoxic conditions in
sediments cleavage of the phytyl side chain to yield phytol, which undergoes
reduction to dihydrophytol and then phytane. Oxic conditions promote the
competing conversion of phytol to pristane by oxidation of phytol to phytenic
acid, decarboxylation to pristane, and then reduction to pristane.
For rock and oil samples within the oil-generative window,
pristane/phytane correlates weakly with the depositional redox conditions.
High Pr/Ph (>3.0) indicates terrigenous organic matter input under oxic
conditions, while low values (<0.8) typify anoxic, commonly hypersaline or
carbonate environments (Peters et al., 2005). Ten Haven et al. (1987)
recommend against drawing conclusions on the oxicity of the environment of
deposition from Pr/Ph alone. Consequently, inferences from Pr/Ph on the
redox potential of the source sediments should always supported by other
geochemical and geologic data. Typically, conditions of source-rock
deposition inferred from Pr/Ph of oils agree with other indicators, such as
sulfur content or the C35 homohopane index.
Chapter Four Reservoir organic geochemistry
99
Pristane/n-C17 and phytane/n-C18 are sometimes use in petroleum
correlations studies. For example, Lijmbach (1975) noted that oils from rocks
deposited under open-water conditions showed Pr/n-C17 <0.5, while those
from inland peat swamps had ratios greater than one (1). Alexander et al.
(1981) suggested use of the ratio (Pr+nC17) / (Ph+nC18) because it is less affect
by variation in thermal maturity than Pr/n-C17 or Ph/n-C18. Biodegradation
increases these ratios because aerobic bacteria generally attack n-alkanes
before the isoprenoids.
4.4.5.2. TERPANES AND SIMILAR COMPOUNDS
Many terpanes in petroleum originate from bacterial (prokaryotic)
membrane lipids (Ourisson et al., 1982). These bacterial terpanes include
several homologous series, including acyclic, bicyclic (drimanes), tricyclic,
tetracyclic and pentacyclic compounds. The following is a brief overview of
more detailed discussions of these compounds (Table 10-4)
Tricyclic terpanes
These are widespread in oils and bitumens; measured by using m/z 191
fragmentogram, derived from lacustrine and marine source rocks. Tricyclic
terpanes are used to correlate crude oils and source-rock extracts, to predict
source rock characteristics, and to evaluate the extent the thermal maturity and
biodegradation (Seifert and Moldowan, 1981; Zumberge, 1987; Peters and
Moldowan, 1993). Because of their extreme resistance to biodegradation,
tricyclic terpanes permit correlation of intensely biodegraded oils (Seifert and
Moldowan, 1979; Palacas et al., 1986). They are also more resistant to thermal
maturation than hopanes, although the lower-carbon-number homologs are
Chapter Four Reservoir organic geochemistry
100
favored at high thermal maturity (Peters et al., 1990). Ratios of various
tricyclic terpanes by carbon number can be useful in order to distinguish
marine, carbonate, lacustrine, paralic, coal/resin, and evaporitic oils. The
C19/C23, C22/C21, C23/C24, C26/C25 and (C28+C29) / Ts (Table 11-4) tricyclic
terpane ratios help to identify extracts and crude oils depositional
environments. In West Africa, Burwood et al. (1992) found out that marine
oils have C25/C26 tricyclic terpanes ratio > 1, while nonmarine oils have a ratio
less than one. In this study, all the crude oils samples have C25/C26 tricyclic
terpane ratios more than (1) (Figs. 44-4 to 52-4), consistent with marine
origin, which is corroborated by a high C23/C19, C22/C21, C23/C24, tricyclic
terpanes/hopanes, and (C28+C29) / Ts ratios, signifying higher marine algal
input (Table 11-4). Identifacton of Gas chromatography – mass spectrometry,
triterpane report (m/z 191) can be shown in (Table 10-4).
Ts/Tm ratio
The ratio of C27 18α(H)-22, 29, 30-trisnorneohopane (Ts) relative to C27
17α(H)-22, 29, 30-trisnorhopane (Tm), Ts/Tm, was first proposed as a
maturity parameter by Seifert and Moldowan ( 1981), but the Ts/Tm can also
serve as facies parameter for related oils. Mello et al. (1988) have shown that
Ts/Tm values below 1 imply a lacustrine/saline, marine evaporitic or marine
carbonate depositional environment, whereas values above (1) indicate
lacustrine fresh-water or marine deltaic environments. From the Ts/Tm data in
Table (12-4) the Tertairy-Creteasous appear to be related from a marine
carbonate depositional environment. Seifert and Moldowan (1986) proposed
the ratio Ts / Tm ratio as a maturity indicator. Waples and Machihara (1992)
Chapter Four Reservoir organic geochemistry
101
stated that, Ts / Tm ratio does not used for quantitative estimation of
maturation but as a correlation parameter.
Fig. (44-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(HF-2,AG-1), Peaks identifications are specified in Table (3).
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GC-MS m/z 191 Well AG-1
Chapter Four Reservoir organic geochemistry
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Fig.(45-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(AG-10,AG-11), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well AG-10
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Chapter Four Reservoir organic geochemistry
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Fig.(46-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(AG-7,FQ-8), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well AG-7
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Chapter Four Reservoir organic geochemistry
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Fig.(47-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(FQ-11,FQ-2), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well FQ-11
GC-MS m/z 191 Well FQ-2
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Fig.(48-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(NO-2,HF-1), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well NO-2
GC-MS m/z 191 Well HF-1
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Fig.(49-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(AM-3,BU-13), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well AM-3
GC-MS m/z 191 Well BU-13
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Fig. (50-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(BU-20,BU-11), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well BU-20
GC-MS m/z 191 Well BU-11
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Fig.(51-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells (BU-
17,FQ-3), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well BU-17
GC-MS m/z 191 Well FQ-3
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Chapter Four Reservoir organic geochemistry
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Fig.(52-4): Example M/Z 191 GCMS mass chromatograms for crude oil in wells
(FQ-4,FQ-5), Peaks identifications are specified in Table (3).
GC-MS m/z 191 Well FQ-4
GC-MS m/z 191 Well FQ-5
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Table (12-4): A summary of biomarker characteristics (terpanes) for crude oil samples in the study area.
№ Well Name
Depth interval A B C D E F G H I J K L M N O P Q R S
1 HF-2 2768-2803 0.00 0.08 1.67 0.00 0.01 0.06 0.06 0.01 0.17 0.15 0.04 0.57 1.27 0.15 7.04 4.34 0.14 0.88 0.79 2 AG-1 2886-2994 0.00 0.08 1.66 0.00 0.01 0.07 0.07 0.02 0.22 0.18 0.05 0.57 1.18 0.16 6.15 3.89 0.14 0.85 0.72 3 AG-10 2920-2930 0.00 0.09 1.72 0.00 0.01 0.07 0.07 0.01 0.21 0.17 0.05 0.57 1.15 0.17 6.23 3.93 0.16 0.95 0.73 4 AG-11 2946-3018 0.00 0.07 1.67 0.00 0.01 0.06 0.06 0.01 0.22 0.18 0.05 0.57 1.19 0.17 6.13 3.73 0.15 1.02 0.78 5 AG-7 3010-3045 0.00 0.09 1.72 0.00 0.01 0.07 0.06 0.02 0.22 0.18 0.06 0.57 1.22 0.17 5.82 4.12 0.15 0.97 0.67 6 FQ-8 3043-3049 0.00 0.09 1.78 0.00 0.01 0.06 0.06 0.02 0.23 0.19 0.05 0.57 1.30 0.17 5.13 3.90 0.16 1.09 0.70 7 FQ-11 3058-3064 0.00 0.11 1.98 0.00 0.00 0.07 0.06 0.01 0.22 0.18 0.03 0.56 1.19 0.19 6.63 4.01 0.17 1.03 0.74 8 FQ-2 3081-3084 0.00 0.10 1.83 0.01 0.02 0.06 0.05 0.02 0.22 0.18 0.06 0.54 1.22 0.18 6.37 3.95 0.16 1.05 0.71 9 NO-2 3366-3383 0.00 0.08 1.55 0.00 0.01 0.05 0.05 0.01 0.14 0.12 0.04 0.57 1.27 0.13 6.03 4.22 0.12 0.99 0.92
10 HF-1 3681-3706 0.00 0.05 1.36 0.01 0.01 0.07 0.07 0.02 0.21 0.18 0.06 0.56 1.27 0.15 5.93 3.73 0.37 1.02 0.79 11 AM-3 3741-3745 0.00 0.07 1.34 0.01 0.02 0.08 0.07 0.01 0.23 0.19 0.06 0.57 1.19 0.15 6.70 3.57 0.22 0.93 0.70 12 BU-13 3794-3808 0.00 0.09 1.62 0.00 0.00 0.05 0.06 0.01 0.21 0.17 0.07 0.57 1.28 0.15 6.40 4.09 0.16 0.90 0.70 13 BU-20 3810-3820 0.00 0.10 1.63 0.00 0.01 0.06 0.06 0.01 0.21 0.17 0.07 0.58 1.24 0.15 6.47 4.00 0.15 0.85 0.71 14 BU-11 3825-3835 0.00 0.08 1.67 0.00 0.01 0.06 0.06 0.01 0.19 0.16 0.05 0.56 1.19 0.16 6.72 3.77 0.14 0.79 0.70 15 BU-17 3849-3863 0.00 0.10 1.76 0.00 0.00 0.06 0.05 0.01 0.18 0.15 0.05 0.57 1.22 0.17 7.12 4.34 0.15 0.81 0.73 16 FQ-3 3930-3940 0.00 0.09 1.49 0.01 0.01 0.06 0.06 0.02 0.22 0.18 0.06 0.58 1.21 0.14 6.66 3.78 0.14 0.85 0.77 17 FQ-4 4000-4015 0.00 0.11 1.97 0.00 0.01 0.06 0.06 0.02 0.22 0.19 0.06 0.56 1.17 0.20 5.92 4.30 0.15 0.83 0.70 18 FQ-5 4023-4038 0.00 0.09 1.68 0.00 0.00 0.05 0.05 0.02 0.20 0.17 0.06 0.58 1.19 0.16 5.09 3.93 0.15 1.14 0.76
Chapter Four Reservoir organic geochemistry
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C24 tetracyclic terpane ratio
Ratios of tetracyclic terpanes to hopanes increase in more mature source
rocks and oils, indicating greater stability of the tetracyclic terpanes.
Tetracyclic terpanes also are more resistant to biodegradation than the hopanes
(Aquino Neto et al., 1983). The C24 tetracyclic terpane / hopane, C24
tetracyclic / C23 tricyclic terpane, and C24 tetracyclic / C26 tricyclic terpane
ratios are common source parameters. The C24 tetracyclic terpane has the most
widespread occurrence, followed by C25-C27 homologs. Abundant C24
tetracyclic terpane in petroleum appears to indicate carbonate and evaporite
source-rock settings (Palacas et al., 1984; Connan et al., 1986; Mann et al.,
1987; Clark and Philp, 1989). However, this compound is also believed to
originate from terrigenous organic matter (Philp and Gilbert, 1986) and is
common in most marine oils generated from mudstone to carbonate source
rocks. The C24 tetracyclic/C26 tricyclic terpanes ratios range from 5.09 to
16.21. In general, these ratios are much higher than 1. According to Mello et
al. (1988) and Philp and Gilbert (1986), the relative abundance of the C24
tetracyclic terpanes could be a marker of higher plants (Table 12-4).
C35 homohopane index
The C30 hopane is the largest component in a series of C27 to C33
hopanes and is an abundant in organic material usually encountered in saline
and hyper-saline environment. The presence of hopanes has been interpreted
as the product of strongly reducing conditions affecting the evidence of
bacterial types and blue green algae (Ten Haven et al., 1985). The
homohopanes (C31- C35) originate from bacteriohopanetetrol and other
polyfunctional C35 hopanoids common in prokaryotic microorganisms
(Ourisson et al., 1984; Rohmer 1987).
Chapter Four Reservoir organic geochemistry
112
The relative distribution of C31- C35 17α 22S and 22R homohopanes in marine
petroleum is used as an indicator of redox potential (Eh) during and
immediately after deposition of the source sediments. High C35 homohopanes
are commonly associated with highly reducing (low Eh) marine conditions
during deposition (Peters and Moldowan, 1991; Ten Haven et al., 1988; Mello
et al., 1988). The C35 homohopanes index is the ratio C35 / (C31 - C35)
homohopanes. Also expressed as C35/ C34 and C35S/ C34S hopanes (Table10-
4). The C29/C30 and C35/C34 hopane ratios can be used in tandem to define the
source facies of oils and source rock extracts. The C35/ C34 hopane ratio in this
plot uses the 22S epimer rather than both 22S and 22R to avoid interference.
All crude oil samples show higher C35/ C34 hopanes (>0.80), indicate marine,
carbonate marine source rocks, consistent with more anoxic depositional
conditions. The unusually large amount of C35 extended hopane seems to be
associated with marine carbonate and evaporates (Philip, 1985; Riediger et al.,
1990). However, Peters and Moldowan (1991) prefer to correlate high C35 /
C34 ratios in marine environment with low redox potential rather than with
lithology as not all carbonate rocks have high C35 concentration
30-Norhopane/hopane
High 30-norhopane/hopane is typical of anoxic carbonate or marl
source rocks and oils. Measured using m/z 191 chromatograms, expressed as
C29 / C30 hopane. The C29 17α-norhopane rivals hopane as the major peak on
m/z 191 mass chromatograms of saturate fractions of many oils and bitumens.
C29/C3017α hopane is greater than 1.0 for many anoxic carbonate or marl
source rocks and related oils but generally is less than 1.0 for most of the
studied samples (Table 12-4). However, Brooks (1986) noted that high
Chapter Four Reservoir organic geochemistry
113
C29 norhopane contents can occur in samples containing oleanane which is
considered to be a terrestrial indicator. The plotting of C29 / C30 hopane and
C35 / C34 hopane suggest a positive relationship between them, where crude
oils generated from many marine carbonate and marl source rocks have high
norhopane/hopane and C35/C34 22S hopane, consistent with anoxia during
deposition of the source rock (Zumberge, 2000).
Oleanane / C30 hopane (Oleanane index)
Oleananes are well-known biomarkers arising from geological
transformation of pentacyclic triterpenoids typical of higher plants. Oleanane
in crude oils and rock extracts is a marker for both source input and geologic
age. This compound originates from betulins (Grantham et al., 1983), and
other pentacyclic triterpenoids that are produced by angiosperm (flowering
land plants). Crude oils from the Tertiary Niger Delta contain abundant
oleananes (Ekweozor et al., 1979), and there is a correlation between the
abundance of higher-plant macerals (e.g. vitrinite and resinite) and the
oleanane index (Udo and Ekweozor, 1979). Absence of oleanane does not
prove that crude oil was generated from Cretaceous or older rocks. Small
amounts of oleanane occur in Jurassic crude oil (Peters et al., 1999) and rock
extracts (Moldowan et al., 1994) and extracts of megafossils from older rocks
(Taylor et al., 2004). Oleanane normally elutes immediately before the C30
hopane. The oleananes have two isomers (18α and 18β), both of the two
isomers are found in the analyzed source rock extracts, the latter is thermally
less stable (Riva et al., 1988). Thus the sum of 18α and 18β isomers should be
used in oleanane/C30 hopane for purposes of correlation. The calculated
oleanane index (Table 12-4), is nearly zero as evidenced by GCMS suggests
that contribution from organic matter related to angiosperms was very low,
Chapter Four Reservoir organic geochemistry
114
also the absence of oleanane could be good indicator for carbonate marine
environment.
Gammacerane index
Gammacerane usually measured using m/z 191. Seifert and Moldowan
(1986) suggested that gammacerane is best measured using the m/z 412
(molecular ion) mass chromatogram because it reduces interference from
other terpanes with the gammacerane peak that occur on the m/z 191
chromatogram.
Gammacerane, a C30 triterpane represent an unusual organic input to the
sediment and is abundant in many crude oils generated from lacustrine source
rocks, often associated with hyper-saline environment (Zumberge, 1987).
High gammacerane concentrations were originally considered to be markers
for lacustrine facies (Pool and Claypool, 1984). Waples and Machihara (1992)
stated that gammacerane can also occur in major and minor concentrations in
many rocks that are definitely not of lacustrine origin as they are dominated in
marine rocks, and evaporites of the Gulf of Suez (Mello et al., 1988). Brassel
et al. (1988) suggested that lacustrine environment in which gammacerane is
abundant, are not fresh water lakes. Therefore, gammacerane is considered
also as a salinity marker (Damste et al., 1988). Gammacerane is also abundant
in certain marine crude oils from carbonate – evaporate source rocks
(Moldowan et al., 1985; Mello et al., 1988; Moldowan et al., 1991), as shown
in the present study.
Chapter Four Reservoir organic geochemistry
115
STERANES AND DIASTERANES
Diasterane/Regular sterane
Acidic sites on clays, such as montmorillonite or illite, catalyze the
conversion of sterols to diasteranes during diagenesis (Rubinstein et al., 1975).
Alternatively, acidic (low Ph) and oxic (high Eh) conditions facilitate
diasterane formation during diagenesis (Moldowan et al., 1986).
The diasteranes/steranes ratio identification (Table 13-4) is based on
[13β, 17α(H) 20S+20R] / {[5α ,14α, 17α(H) 20S+20R] + [5α,14β, 17β(H)
20S+20R]} for the C27, C28, and C29 steranes obtained from GCMS (Tables
14-4, Figs 53-4 to 56-4). Occasionally, only one carbon number is used, for
example C27, as specified. Oils from the hypersaline lacustrine family have
very low amounts of diasteranes, which commonly suggests a source rock that
has low content of catalytic clays, consistent with carbonate or evaporate
source rocks (Mello et al., 1988; Peters and Moldowan, 1993). . Low
diasteranes /steranes ratios in oils indicate anoxic clay-poor or carbonate
source rock.
During diagenesis of these carbonate sediments, bacterial activity
provides bicarbonate and ammonium ions (Berner et al., 1970), resulting in
increased water alkalinity. Under these conditions of high pH and low Eh,
calcite tends to precipitate and organic matter preservation is improved.
Although low diasterane relative concentrations commonly reflect a shale-
poor source rock, the amount of diasteranes in oils is also influenced by the
level of thermal maturity (i.e., diasteranes increase with increasing maturity).
Diasteranes/steranes ratios are commonly used to distinguish petroleum
from carbonate versus clastic source rocks, from the calculated disteranes/
steranes ratios in the present study, we have low ratios (<0.1) which indicate
that the crude oil samples related to carbonate marine environment.
Chapter Four Reservoir organic geochemistry
116
Fig.(53-4): M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well
(AM-3). Peaks identifications are specific in Table (6).
GC-MS m/z 217 Well AM-3
GC-MS m/z 218 Well AM-3
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Fig.(54-4): M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well
(HF-2). Peaks identifications are specified in Table (6).
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GC-MS m/z 218 Well HF-2
Chapter Four Reservoir organic geochemistry
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Fig.(55-4): M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well
(FQ-5). Peaks identifications are specified in Table (6).
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Chapter Four Reservoir organic geochemistry
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Fig.(56-4): M/Z 217, and M/Z 218 mass fragmentograms for crude oil sample from well
(BU-11). Peaks identifications are specified in Table (6).
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GC-MS m/z 218 Well BU-11
Chapter Four Reservoir organic geochemistry
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Table (14-4): A summary of biomarker characteristics (Steranes) for crude oils, Missan Province, South Iraq.
№ Well Name
Depth interval A B C D E F G H I J K L M N O P 1 2 3
1 HF-2 2768-2803 29.69 26.77 43.53 36.27 20.29 43.44 0.72 0.42 0.49 0.54 0.95 0.11 0.68 0.61 1.47 0.12 0.10 0.10 0.84 2 AG-1 2886-2994 31.37 27.63 41 34.89 25.80 39.31 0.56 0.38 0.42 0.45 0.62 0.13 0.77 0.67 1.31 0.1 0.14 0.10 0.71 3 AG-10 2920-2930 30.97 26.63 42.4 34.17 27.81 38.02 0.62 0.36 0.38 0.47 0.72 0.14 0.73 0.63 1.37 0.13 0.14 0.10 0.70 4 AG-11 2946-3018 30.81 26.67 42.52 32.93 25.54 41.53 0.55 0.36 0.40 0.47 0.67 0.13 0.72 0.63 1.38 0.12 0.14 0.10 0.74 5 AG-7 3010-3045 30.77 25.64 43.6 35.61 27.21 37.18 0.61 0.38 0.43 0.49 0.75 0.13 0.71 0.59 1.42 0.12 0.14 0.10 0.72 6 FQ-8 3043-3049 30.56 26.74 42.7 33.32 24.03 42.66 0.58 0.37 0.41 0.49 0.71 0.09 0.72 0.63 1.40 0.13 0.13 0.11 0.82 7 FQ-11 3058-3064 30.04 26.48 43.47 37.21 24.89 37.90 0.62 0.38 0.47 0.53 0.89 0.12 0.69 0.61 0.1.45 0.10 0.13 0.11 0.88 8 FQ-2 3081-3084 29.8 26.41 43.79 33.74 22.88 43.39 0.51 0.34 0.41 0.49 0.70 0.13 0.68 0.60 1.47 0.11 0.14 0.11 0.79 9 NO-2 3366-3383 30.78 27.15 42.07 37.78 22.82 39.40 0.79 0.44 0.53 0.57 1.12 0.11 0.73 0.65 1.37 0.08 0.12 0.10 0.71 10 HF-1 3681-3706 30.36 26.98 42.67 35.95 21.31 42.74 0.86 0.46 0.51 0.53 1.05 0.12 0.71 0.63 0.141 0.15 0.18 0.10 0.53 11 AM-3 3741-3745 30.01 26.7 43.29 35.37 22.13 42.50 0.82 0.45 0.51 0.54 1.03 0.13 0.69 0.62 1.44 0.14 0.17 0.10 0.51 12 BU-13 3794-3808 30.98 26.81 42.21 36.15 22.18 41.67 0.75 0.43 0.51 0.55 1.02 0.11 0.73 0.64 0.1.36 0.16 0.12 0.10 0.81 13 BU-20 3810-3820 30.71 27.22 42.07 35.26 20.84 43.90 0.73 0.42 0.48 0.52 0.91 0.12 0.73 0.65 1.37 0.17 0.12 0.10 0.79 14 BU-11 3825-3835 31.95 26.15 41.9 37.08 20.65 42.27 0.75 0.43 0.51 0.55 1.03 0.11 0.76 0.62 1.31 0.13 0.12 0.10 0.85 15 BU-17 3849-3863 30.46 26.24 43.3 36.58 19.46 43.95 0.73 0.42 0.50 0.54 0.99 0.10 0.70 0.61 1.42 0.10 0.11 0.10 0.95 16 FQ-3 3930-3940 31.43 27.1 41.47 33.99 22.16 43.84 0.85 0.46 0.54 0.54 1.06 0.12 0.76 0.65 1.32 0.18 0.12 0.10 0.70 17 FQ-4 4000-4015 30.68 25.66 43.66 33.93 23.43 42.64 0.51 0.34 0.41 0.49 0.71 0.10 0.70 0.59 1.42 0.08 0.13 0.12 0.93 18 FQ-5 4023-4038 30.91 26.6 42.49 36.36 22.22 41.42 0.80 0.44 0.51 0.54 1.03 0.11 0.73 0.63 1.37 0.13 0.13 0.10 0.77
Chapter Four Reservoir organic geochemistry
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Regular steranes/17α-hopanes
In steranes/17α-hopanes, the regular steranes consist of the C27, C28, and
C29 ααα (20S+20R) and αββ (20S+20R) compounds and the 17α-hopanes
consist of the C29 – C33 pseudohomologs, including 22S and 22R epimers for
C31 - C33 homologs (Moldowan et al., 1985). Regular steranes/17α-hopanes
reflects input of eukaryotic (mainly algae and higher plants) versus
prokaryotic (bacteria) organisms to the source rock. Because organisms vary
widely in their steroid and hopanoid contents, differences in this ratio allow
only qualitative assessment of eukaryote versus prokaryote input. Maturity
may increase this ratio (Seifert and Moldowan, 1978). In general, high
concentrations of steranes and high steranes /hopanes (≥1) typify marine
organic matter with major contributions from planktonic and/or benthic algae
(Moldowan et al., 1985). Conversely, low steranes and low steranes/hopanes
are more indicative of terrigenous and/or microbially reworked organic matter
(e.g. Tissot and Welte, 1984).
Some workers use steranes/triterpanes as an indicator of organic matter
input, assuming that steranes originate from algae and higher plants while
triterpanes come mainly from bacteria. Here, we prefer to use
steranes/hopanes rather than steranes/triterpanes. Both ratios are of limited use
because the variety of organisms that contribute to steranes, and especially
triterpanes.
C27-C28-C29 steranes
In most cases, accuracy of the measurements by GCMS/MS or MRM-
GCMS is far superior to that from GCMS. Based on a study of recent marine
and terrigenous sediments, Huang and Meinschein (1979) showed that the
ratio of cholest-5-en-3β-ol to 24-ethylcholest-5-en-3β-ol is a source parameter
Chapter Four Reservoir organic geochemistry
122
that be able to be used to differentiate depositional settings. They proposed
that the distributions of C27, C28, and C29 sterol homologs on a ternary diagram
might be used to differentiate ecosystems.
Moldowan et al. (1985) proposed C27, C28, and C29 steranes ternary
diagram that represents a composite of data for oils from various source-rock
depositional environments. There is so much overlap on this figure that the
analysis is seldom used to differentiate depositional environments of the
source rocks for crude oil, with the possible exception of certain samples
containing predominantly higher-plant organic matter (e.g. non-marine
shales). The distribution of C27, C28, and C29 steranes (based on GCMS output
data) for each of crude oil samples in Tables (14-4 ) have been plotted in
triangular graphs according to Huang and Meinschein (1979) and Moldowan
et al. (1985). It is clear from figure (57-4) the elevated amounts of C27 steranes
(33-37 %) suggest a significant contribution to the organic matter from algae
and marine carbonate source rock facies .
Chapter Four Reservoir organic geochemistry
123
C28
C29C27
Marine >350 M.Y
Nonmarine shale
Marine shale
Marine carbonate
1
3 546
8910 7
13
14111215
16172
1819
Fig.(57-4): Triangular plots showing the relative concentrations of C27, C28 and C29 regular
steranes for Cretaceous-Tertiary crude oil. (Huang and Meinschein, 1979; Moldowan et al., 1985).
The marine carbonate oil of Huqf Formation (in Oman) and of Mulessa
Formation (in Syria) (Grantham and Wakefield, 1988) are anomalously high
in C29 steranes, possibly because of sterol precursor from marine brown and
green algae or bacteria (Peters and Moldowan, 1993; Hunt, 1996; Huang,
2000). Therefore, the high relative amount of C29 steranes in some samples
(Table14-4) can be attributed to marine algal precursors.
24-Nordiacholestane and 24-norcholestane ratios
Observation of elevated 24-nordiacholestanes and 24-norcholestanes in
Cretaceous or younger oils and sediments relative to their 27-norcholestane
analogs (Figs.58-4 to 67-4) indicated that the ratio of 24-nor to
Chapter Four Reservoir organic geochemistry
124
27-norcholestanes may be related to geologic age. Two ratios,
24-nordiacholestane ratio (NDR) and 24-norcholestane ratio (NCR), may be
defined respectively by equations (1) and (2) (refer to chapter 2) using peaks
designated by the numbers in Fig.()
Table (15-4) lists the NDR and NCR ratios for a suite of crude oils from
the Missan oil fields. Crude oil samples have low values of both NCR and
NDR (up to 0.29 and 0.30, respectively) consistent with their Cretaceous age
for three samples( R-167, Am-3, No-1).For the forth extract source rock ( Hf-
5) has NCR=0.29 and NDR=0.18, consistent with their Jurassic age.
Chapter Four Reservoir organic geochemistry
125
131211
10
9
87
6
5
4321
Fig(58-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( HF-2).
1 23 4
56 7
8
9
10
11 12 13
Fig.(59-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( AG-10).
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e
Chapter Four Reservoir organic geochemistry
126
131211
10
9
8
76
5
43
21
Fig.(60-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( AG-11).
131211
10
9
87
6
5
3 4
21
Fig.(61-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-8).
Retention time
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pons
e
Retention time
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pons
e
Chapter Four Reservoir organic geochemistry
127
131211
10
9
87
6
5
4321
Fig.(62-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-2).
1312
1110
9
1 23 4
5
67
8
Fig.(63-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( HF-1).
Retention time
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pons
e
Chapter Four Reservoir organic geochemistry
128
131211
10
9
1 23 4
5
67
8
Fig.(64-4): Metastable reaction monitoring/gas chromatography/mass spectrometry
(MRM-GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( BU-13).
13121110
9
87
6
5
4321
Fig.(65-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( BU-20).
Retention time
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pons
e
Retention time
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pons
e
Chapter Four Reservoir organic geochemistry
129
1312
1110
9
876
5
4321
Fig.(66-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-3).
131211
10
9
87
6
5
3 4
21
Fig.(67-4): Metastable reaction monitoring/gas chromatography/mass spectrometry (MRM-
GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-4).
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pons
e
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pons
e
Chapter Four Reservoir organic geochemistry
130
AROMATIC BIOMARKERS
Aromatic biomarkers can provide valuable information on organic
matter input. For example, aromatic hopanoids originate from bacterial
precursors, while tetra- and pentacyclic aromatics with oleanane, lupane, or
ursane skeletons indicate higher plants (Garrigues et al., 1986; Loureiro and
Cardoso, 1990), (Figs. 68-4 to 71-4 ).
C27- C28- C29 C-ring monoaromatic steroids (MA)
Plot locations of C-ring monoaromatic steroids on C27- C28- C29 ternary
diagrams (Fig.72) were related to various types of source input in a manner
similar to the early work of Huang and Meinschein (1979). C-ring
monoaromatic steroids may be derived exclusively from sterols with a side-
chain double bond during diagenesis (Moldowan and Fago, 1986). In this
respect, C-ring monoaromatic steroids may be more precursor-specific than
steranes.
Monoaromatic steroid triangular diagrams commonly distinguish oil
samples derived from non-marine versus marine shale source rocks. Oils
generated from marine shale generally contain less C29 monoaromatic steroids
than non-marine oils (Moldowan et al., 1985). Typically, more terrigenous
organic matter be deposited in non-marine than in marine source rocks, and
the non-marine rocks thus contain more C29 sterols. Ternary diagrams are
based on ratios of C27/(C27-C29), C28/(C27-C29), and C29/(C27-C29) mono-
aromatic steroids. For each carbon number, six isomeric compounds are used
in these ratios, including 5α (20S+20R), 5β (20S+20R) and 10β→5β methyl-
rearranged 20R and 20S isomers. C28/( C28+ C29) ratios <0.5, typically of
marine shale-carbonate derived source rocks (Table 16,17-4).
Chapter Four Reservoir organic geochemistry
131
1 2
3
4
5
6
7
8
9
1011
12
13
14
15
16
1718
19
20
21
22
2324 25
26
Fig.(68-4) : Example GCMS mass chromatograms for crude oil sample, well (AG-7)
showing m/z 253 and m/z 231.
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GC-MS M/z 253 Well (AG-7)
GC-MS M/z 231 Well (AG-7)
Chapter Four Reservoir organic geochemistry
132
1
23
4
5
6
7
8
9
10
15
11
1213
14
16
1718
19
20
21
22
2423 25
26
Fig.(69-4) : Example GCMS mass chromatograms for crude oil sample, well (HF-1)
showing m/z 253 and m/z 231.
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pons
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GC-MS M/z 253 Well (HF-1)
GC-MS M/z 231 Well (HF-1)
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pons
e
Chapter Four Reservoir organic geochemistry
133
1 2
3
4
5
7
68
9
10
11
12
13
14
15
16
17 18
19
20
21
22
2324 25
26
Fig.(70-4) : Example GCMS mass chromatograms for crude oil sample, well (HF-2)
showing m/z 253 and m/z 231.
GC –MS M/z253 Well (HF-2)
GC-MS M/z 231 Well (HF-2)
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pons
e
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pons
e
Chapter Four Reservoir organic geochemistry
134
12
4
3
5
6
7
8
9
10
11
12
13
14
15
16
17 18
19
20
21
22
2324
26
25
Fig.(71-4) : Example GCMS mass chromatograms for crude oil sample, well (FQ-5)
showing m/z 253 and m/z 231.
GC-MS M/z 253 Well (FQ-5)
GC-MS M/z 231 Well (FQ-5)
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Chapter Four Reservoir organic geochemistry
135
Table (17-4): A summary of biomarker characteristics (Monoaromatic and
Triaromatic) for crude oil samples from Missan oil fields, South east Iraq.
№ Well Name
Depth interval D E F G H I J K L N O P
1 ٢-HF ٢٨٠٣ – ٢٧٦٨
١٫١٩ ٠٫٢٦ ٠٫٢٥ ٠٫٤٩ ٤٠٫١٥ ٤٧٫٧٤ ١٢٫١١ ٠٫٣٠ ٠٫٧٨ ٠٫٥٠ ٠٫٩٩ ٠٫١٣
2 ١-AG ٢٩٩٤ – ٢٨٨٦
١٫٠١ ٠٫٢٢ ٠٫٢٦ ٠٫٥١ ٤٤٫٣٩ ٤٠٫٠٥ ١٠٫٥٦ ٠٫٢٦ ٠٫٧٨ ٠٫٤٩ ٠٫٩٦ ٠٫١٢
3 ١٠-AG
٢٩٣٠ – ٢٩٢٠
١٫١٢ ٠٫٢١ ٠٫٢٦ ٠٫٥٠ ٤٢٫٤٠ ٤٧٫٥ ١٠٫١٠ ٠٫٣٦ ٠٫٧٩ ٠٫٥٢ ١٫٠٧ ٠٫١٣
4 ١١-AG
٣٠١٨ – ٢٩٤٦
١٫١٧ ٠٫٢٠ ٠٫٢٧ ٠٫٥١ ٤١٫٦٤ ٤٨٫٥٩ ٩٫٧٧ ٠٫٣٥ ٠٫٨٠ ٠٫٥٣ ١٫١٤ ٠٫١٤
5 ٧-AG ٣٠٤٥ – ٣٠١٠
١٫١٣ ٠٫٢١ ٠٫٢٦ ٠٫٥٠ ٤٢٫٣٢ ٤٧٫٨٥ ٩٫٨٣ ٠٫٣١ ٠٫٨١ ٠٫٥٢ ١٫٠٨ ٠٫١٣
6 ٨-FQ ٣٠٤٩ – ٣٠٤٣
١٫٠٦ ٠٫١٩ ٠٫٢٧ ٠٫٥٣ ٤٣٫٨٩ ٤٦٫٤٧ ٩٫٦٤ ٠٫٣٠ ٠٫٨١ ٠٫٥١ ١٫٠٥ ٠٫١٤
7 ١١-FQ ٣٠٦٤ – ٣٠٥٨
٠٫٩٨ ٠٫٢١ ٠٫٣١ ٠٫٥٩ ٤٥٫٢٨ ٤٤٫٤٥ ١٠٫٢٧ ٠٫٣٣ ٠٫٧٦ ٠٫٤٨ ٠٫٩١ ٠٫١٤
8 ٢-FQ ٣٠٨٤ – ٣٠٨١
١٫٠٤ ٠٫٢٠ ٠٫٢٨ ٠٫٥٤ ٤٤٫١١ ٤٥٫٩٦ ٩٫٩٣ ٠٫٢٩ ٠٫٧٨ ٠٫٥٠ ١٫٠١ ٠٫١٤
9 ٢-NO ٣٣٨٣ – ٣٣٦٦
١٫١٥ ٠٫٢٦ ٠٫٢٣ ٠٫٤٥ ٤١٫٠٨ ٤٧٫٢٩ ١١٫٦٣ ٠٫٢٠ ٠٫٧٥ ٠٫٤٤ ٠٫٨٠ ٠٫١٣
10 ١-HF ٣٧٠٦ – ٣٦٨١
١٫٠٧ ٠٫٢١ ٠٫٢٣ ٠٫٤٤ ٤٣٫٥٠ ٤٦٫٧٠ ٩٫٨٠ ٠٫٦٥ ٠٫٩٤ ٠٫٧٦ ٣٫١٠ ٠٫١٥
11 ٣-AM ٣٧٤٥ – ٣٧٤١
١٫٠٩ ٠٫١٥ ٠٫٢٤ ٠٫٤٥ ٤٤٫٥٠ ٤٨٫٠٥ ٧٫٤٥ ١٫٠ ٠٫٩٣ ٠٫٧٩ ٣٫٨١ ٠٫١٦
12 ١٣-BU ٣٨٠٨ – ٣٧٩٤
١٫١٥ ٠٫٢٠ ٠٫٢٥ ٠٫٤٧ ٤٢٫٠٦ ٤٨٫٣٥ ٩٫٥٩ ٠٫٣٢ ٠٫٨٣ ٠٫٥٥ ١٫٢٤ ٠٫١٥
13 ٢٠-BU ٣٨٢٠ – ٣٨١٠
١٫٠٩ ٠٫١٨ ٠٫٢٤ ٠٫٤٧ ٤٣٫٤٨ ٤٧٫٥٩ ٨٫٩٣ ٠٫٣٢ ٠٫٨٣ ٠٫٥٦ ١٫٢٩ ٠٫١٤
14 ١١-BU ٣٨٣٥ – ٣٨٢٥
١٫٠٥ ٠٫٢١ ٠٫٢٥ ٠٫٤٩ ٤٣٫٩١ ٤٦٫١٠ ٩٫٩٩ ٠٫٣٣ ٠٫٨٣ ٠٫٥٥ ١٫٢٥ ٠٫١٤
15 ١٧-BU ٣٨٦٣ – ٣٨٤٩
١٫٠٦ ٠٫٢١ ٠٫٢٧ ٠٫٥١ ٤٣٫٥٣ ٤٦٫١٥ ١٠٫٣٢ ٠٫٣٠ ٠٫٨٠ ٠٫٥٣ ١٫١٤ ٠٫١٤
16 ٣-FQ ٣٩٤٠ – ٣٩٠٠
١٫١٤ ٠٫١٨ ٠٫٢٣ ٠٫٤٥ ٤٢٫٤٤ ٤٨٫٥٣ ٩٫٠٣ ٠٫٣٨ ٠٫٨٩ ٠٫٦٥ ١٫٨٨ ٠٫١٥
17 ٤-FQ ٣٠٦٤ – ٤٠٠٠
٠٫٩٥ ٠٫٢١ ٠٫٣٢ ٠٫٦١ ٤٥٫٨٠ ٤٣٫٤٢ ١٠٫٧٨ ٠٫٢٨ ٠٫٧٤ ٠٫٤٦ ٠٫٨٤ ٠٫١٤
٥ ١٨-FQ ٤٠٣٨ - ٤٠٢٣
١٫١٣ ٠٫٢٢ ٠٫٢٤ ٠٫٤٧ ٤٢٫٢٧ ٤٧٫٦١ ١٠٫١٢ ٠٫٣٢ ٠٫٨٢ ٠٫٥٤ ١٫١٨ ٠٫١٤
Chapter Four Reservoir organic geochemistry
136
Marine >350 M.Y.
Marine carbonate
Marine shale
C27 C29
C28
Nonmarine shale
Fig.(72-4): Ternary diagram showing the relative abundance of C27-, C28-, and C29-
monoaromatic (MA) steroids in the aromatic fractions of source rock extracts determined by gas chromatography/mass spectrometery (GCMS) (m/z 253).
Chapter Four Reservoir organic geochemistry
137
C26- C27- C28 triaromatic steroids (TA)
Triaromatic steroids can originate by aromatization and loss of a methyl
group (-CH3) from monoaromatic steroids. For example the C29 monoaromatic
steroid can be converted to the C28 triaromatic steroid. Ratios of C26/(C26- C28),
C27/(C26- C28) and C28/(C26- C28) triaromatic steroids are potentially effective
source parameters similar to those described for the C27, C28, and C29
monoaromatic steroids (Peters et a., 2005).
The triaromatic steroid ratios (Table 17-4) should be more sensitive to
thermal maturation than those for monoaromatic steroids or steranes because
the triaromatic steroids appear to be maturation products from aromatization
of monoaromatic steroids (Mackenize et al., 1982). As aromatization proceeds
in the early part of the oil window, there may be changes in the triaromatic
steroid ratios reflecting the relative case of aromatization of various
monoaromatic precursors and possible additional precursors other than
monoaromatic steroids. For example, the ratio of C27/C29 monoaromatic
steroids does not correlate with the ratio of C26/C28 20S triaromatic steroids in
a study of early mature to mature oils and seeps from Greece (Seifert et al.,
1984).
4.5. MATURITY-RELATED BIOMARKER/ NON-BIOMARKER
PARAMETERS
This part explains how biomarker analyses are used to assess thermal
maturity. The parameters are arranged by groups of related compounds in the
order (1) alkanes and isoprenoids, (2) terpanes, (3) polcadinanes and related
products, (4) steranes, and (5) aromatic steroids.
ALKANES AND ISOPRENOIDS
Chapter Four Reservoir organic geochemistry
138
Isoprenoids/n-alkane ratios
Pristane/nC17 and phytane/nC18 decrease with thermal maturity as more
n-alkanes are generated from kerogen by cracking (Tissot et al., 1971). These
isoprenoids/n-alkanes ratios can be use to assist in ranking the thermal
maturity of related, non-biodegraded oils and bitumens (Table 9-4).
Carbon preference index & odd-even predominance
Table (9-4) suggests a considerable odd versus even-predominance for
the crude oil samples are mature in the in the study area, where CPI or OEP
ratios more or less approach 1.0.
TERPANES
22S/(22S+22R) homohopane isomerization
The proportions of 22R and 22S can calculated for any or all of the C31-
C35 compounds. These 22R and 22S doublets in the range C31-C35 on the m/z
191 mass chromatogram are call homohopanes (Figs 44 – 52-4; peaks 30, 31,
33, 34, 35, 36, 37, 38, 39, 40). Typically, C31- or C32-homohopanes results are
used to calculate the 22S/(22S+22R) ratio. The 22S/(22S+22R) ratio rises
from 0.0 to ~ 0.6 (0.57 – 0.61 = equilibrium) (Seifert and Moldowan, 1980)
during maturation. Samples showing 22S/(22S+22R) ratios in the range 0.50-
0.54 have barely entered oil generation, while ratios in the range 0.57-0.62
indicate that the main phase of oil generation has been reached or surpassed.
The C32 17α(H)-homohopane 22S/(22S+ 22R) values of the analyzed
source rock extracts vary considerably from 0.54 to 0.58% (Table 12-4 )
formations have at least entered the oil window .
Chapter Four Reservoir organic geochemistry
139
Chapter Four Reservoir organic geochemistry
140
Table (18-4): A summary of maturity related none/biomarker for crude oil samples for Missan oil fields. № Well
Name Depth interval A B C D E F H I J L M N O P
1 HF-2 2768 – 2803 1.05 0.92 1.27 0.06 0.10 0.15 0.42 0.49 0.12 ٠٫٢٥ ٠٫١٣ ٠٫٥٠ ٠٫٩٩ ٠٫٧٨ 2 AG-1 2886 – 2994 10.08 0.96 1.18 0.07 0.10 0.18 0.38 0.42 0.1 ٠٫٢٦ ٠٫١٢ ٠٫٤٩ ٠٫٩٦ ٠٫٧٨ 3 AG-10 2920 – 2930 1.06 0.96 1.15 0.07 0.10 0.17 0.36 0.38 0.13 ٠٫٢٦ ٠٫١٣ ٠٫٥٢ ١٫٠٧ ٠٫٧٩ 4 AG-11 2946 – 3018 0.95 0.97 1.19 0.06 0.10 0.18 0.36 0.40 0.12 ٠٫٢٧ ٠٫١٤ ٠٫٥٣ ١٫١٤ ٠٫٨٠ 5 AG-7 3010 – 3045 1.05 0.91 1.22 0.07 0.10 0.18 0.38 0.43 0.12 ٠٫٢٦ ٠٫١٣ ٠٫٥٢ ١٫٠٨ ٠٫٨١ 6 FQ-8 3043 – 3049 1.12 1.03 1.30 0.06 0.11 0.19 0.37 0.41 0.13 ٠٫٢٧ ٠٫١٤ ٠٫٥١ ١٫٠٥ ٠٫٨١ 7 FQ-11 3058 – 3064 1.10 0.96 1.19 0.07 0.11 0.18 0.38 0.47 0.10 ٠٫٣١ ٠٫١٤ ٠٫٤٨ ٠٫٩١ ٠٫٧٦ 8 FQ-2 3081 – 3084 1.14 0.94 1.22 0.06 0.11 0.18 0.34 0.41 0.11 ٠٫٢٨ ٠٫١٤ ٠٫٥٠ ١٫٠١ ٠٫٧٨ 9 NO-2 3366 – 3383 1.08 0.97 1.27 0.05 0.10 0.12 0.44 0.53 0.08 ٠٫٢٣ ٠٫١٣ ٠٫٤٤ ٠٫٨٠ ٠٫٧٥
10 HF-1 3681 – 3706 0.98 0.93 1.27 0.07 0.10 0.18 0.46 0.51 0.15 ٠٫٢٣ ٠٫١٥ ٠٫٧٦ ٣٫١٠ ٠٫٩٤ 11 AM-3 3741 – 3745 0.98 0.95 1.19 0.08 0.10 0.19 0.45 0.51 0.14 ٠٫٢٤ ٠٫١٦ ٠٫٧٩ ٣٫٨١ ٠٫٩٣ 12 BU-13 3794 – 3808 1.03 0.91 1.28 0.05 0.10 0.17 0.43 0.51 0.16 ٠٫٢٥ ٠٫١٥ ٠٫٥٥ ١٫٢٤ ٠٫٨٣ 13 BU-20 3810 – 3820 1.04 0.93 1.24 0.06 0.10 0.17 0.42 0.48 0.17 ٠٫٢٤ ٠٫١٤ ٠٫٥٦ ١٫٢٩ ٠٫٨٣ 14 BU-11 3825 – 3835 1.04 0.93 1.19 0.06 0.10 0.16 0.43 0.51 0.13 ٠٫٢٥ ٠٫١٤ ٠٫٥٥ ١٫٢٥ ٠٫٨٣ 15 BU-17 3849 – 3863 1.04 0.94 1.22 0.06 0.10 0.15 0.42 0.50 0.10 ٠٫٢٧ ٠٫١٤ ٠٫٥٣ ١٫١٤ ٠٫٨٠ 16 FQ-3 3900 – 3940 1.04 0.96 1.21 0.06 0.10 0.18 0.46 0.54 0.18 ٠٫٢٣ ٠٫١٥ ٠٫٦٥ ١٫٨٨ ٠٫٨٩ 17 FQ-4 4000 – 4015 0.97 0.93 1.17 0.06 0.12 0.19 0.34 0.41 0.08 ٠٫٣٢ ٠٫١٤ ٠٫٤٦ ٠٫٨٤ ٠٫٧٤ 18 FQ-5 4023 - 4038 1.10 0.95 1.19 0.05 0.10 0.17 0.44 0.51 0.13 ٠٫٢٤ ٠٫١٤ ٠٫٥٤ ١٫١٨ ٠٫٨٢
Chapter Four Reservoir organic geochemistry
141
Moretanes/hopanes
The 17β,21α(H)-moretanes are thermally less stable than the
17α,21β(H)-hopanes, and abundances of the C29 and C30 moretanes decrease
relative to the corresponding hopanes with thermal maturity. The ratio of
17β,21α(H)-moretanes to their corresponding 17α,21β(H)-hopanes decreases
with thermal maturity from ~0.8 in immature bitumens to <0.15 in mature
source rocks and oils to a minimum 0.05 (Mackenzie et al., 1980; Seifert and
Moldowan, 1980). Based on 234 crude oils, Grantham (1966) concluded that
oils from Tertiary source rocks show higher moretane/hopane (0.10-0.30,)
than those from older rocks (generally ≤ 0.1).
The C30 compounds used most commonly for moretane/hopane,
although this ratio is also quantified using C29 compounds (e.g. Seifert and
Moldowan, 1980). Others have used both C29 and C30 compounds for their
moretane/hopane ratio (Mackenzie et al., 1980). The C30 compounds are use
for moretane/hopane in this study (Table 12-4). The crude oil samples show
moretane/hopane ranges from 0.05-0.07, with that range, we have mature
crude oil.
Tricyclics/17α-hopanes
The tricyclics/17α-hopanes ratio increases for related oils of increasing
thermal maturity (Seifert and Moldowan, 1978). The ratio increases because
proportionally more tricyclic terpanes than hopanes are released from the
kerogen at higher levels of maturity (Aquino Neto et al., 1983).
Because tricyclic terpanes and hopanes originate by diagenesis of
different biological precursors (Ourisson et al., 1982), the tricyclics/17α-
hopanes ratio can differ considerably between crude oils from different source
rocks or different facies of the same source rock.
Chapter Four Reservoir organic geochemistry
142
Ts/(Ts+Tm)
During catagenesis C27 17α-trisnorhopane (Tm) is less stable than C27
18α-trisnorneohopane (Ts) (Seifert and Moldowan, 1978). The Ts/(Ts+Tm)
ratio, sometimes reported as Ts/Tm, depends on both source and maturity
(Moldowan et al., 1986). The Ts/(Ts+Tm) ratio is most reliable as a maturity
indicator when evaluating oils from a common source of consistent organic
facies. The relative importance of lithology and oxicity of the depositional
environment in controlling this ratio remains unclear, although some results
suggest substantial effects. Ts/(Ts+Tm) appears to be sensitive to clay-
catalyzed reactions. For example, oils from carbonate source rocks appear to
have usually low Ts/(Ts+Tm) ratios compared with those from shales
(McKirdy et al., 1983; Mckirdy et al., 1984; Price et al., 1987). Table (12-4)
shows that Ts/(Ts+Tm) ratios for the crude oil samples systematically increase
with depth.
STERANES
20S/(20S+20R) & ββ/(ββ+αα) isomerization
Stereochemical information is included in the names of biomarkers. For
example, both 5α- and 5ß-steranes and R & S configurations occur in
petroleum, but they differ in physical characteristics. A clear understanding of
these stereochemical designations is needed to apply various biomarker
parameters, especially those for thermal maturity assessment (Peters et al.,
2005). Alpha "α" and "ß" designations refer to the orientation of carbon-
hydrogen bonds in the ring system: "α" refers to orientation above the plane of
the ring, whereas "ß" is below the plane. The S and R designations are
chemical conventions for designating molecular chiral centers in the
Chapter Four Reservoir organic geochemistry
143
hydrocarbon chains: R designates clockwise and S the counter-clockwise
orientation in these sequencing rules.
Isomerization at C-20 in the C29 5α,14α,17α(H)-steranes causes
20S/(20S+20R) to rise from 0.0 to ~0.5 (0.52 – 0.55 = equilibrium) with
increasing thermal maturity (Seifert and Moldowan, 1986).
The sterane isomerization ratios are reported most often for the C29-
ethylcholestanes or stigmastanes) due to the ease of analysis using m/z 217
mass chromatograms. Isomerization ratios based on the C27 and C28 steranes
commonly show interference by coeluting peaks. However, GCMS/ MS
measurements allow reasonably good accuracy for C27, C28 and C29
20S/(20S+20R), all of which have equivalent potential as maturity parameters
when measured by this method.
Isomerization at C-14 and C-17 in the C29 20S and 20R regular steranes
causes in increase in ββ/(ββ+αα) from near 0.0 to ~0.7 (0.67 – 0.71 =
equilibrium) with increasing maturity (Seifert and Moldowan, 1986). This
ratio appears to be independent of source organic matter input and somewhat
slower to reach equilibrium than 20S/(20S+20R), thus making it effective at
higher levels of maturity.
Plot of ββ/(ββ+αα) versus 20S/(20S+20R) for the C29 steranes (Fig.73-
4) is particularly effective in order to describe the thermal maturity of the
analyzed crude oil samples (Peters et al., 1994).
Diasteranes/steranes
Thermal maturity, lithology and the redox potential of the source rock
depositional environment affect diasteranes/steranes. As a result, this ratio is
useful for maturity determination only when oils or bitumens being compared
are from the same source rock organic facies. Catalysis by acidic clays has
Chapter Four Reservoir organic geochemistry
144
been proposed as the mechanism that accounts for diasteranes in sediments
(Rubinstein et al., 1975). Diasteranes/steranes are typically low in carbonate
source rocks and oils. However, because diasteranes occur in certain highly
calcareous rocks from the Adriatic Sea area that are clay-poor (Moldowan et
al., 1991), other acid mechanisms may be effective. High Eh during the
deposition of these sediments may account for the diasteranes.
C Sterane aßß / (aßß + aaa)40 50 60 70
C S
tera
ne 2
0S /
(S+R
)29
30
29
20
30
40
50
60
Ro = 0.6 %
Ear
ly O
il
Ro = 0.8 %
Pea
k O
il
Equilibrium (0.52 - 0.55)
Equi
libriu
m (0
.67
- 0.7
1)
1 2
3
4 5
6
978
101211
13
14 16
1715
18
19
Mat
urity
tren
d lin
e
Fig. (73-4): Thermal maturity of the analyzed crude oil samples based on sterane
isomerizaion. Vitrinite reflectance estimates after correlations in Waples and Machihara (1990); Peters and Moldowan (1993).
Chapter Four Reservoir organic geochemistry
145
Once formed, diasteranes are more stable than regular steranes.
Diasteranes/steranes increase dramatically past peak oil generation (Peters et
al., 1990). At these high levels of maturity, rearrangement of steranes to
diasteranes may be possible even without clays, probably due to hydrogen
exchange reactions that be enhanced by water (Rullkotter et al., 1984).
AROMATIC STEROIDS
TA/ (TA + MA), monoaromatic steroid aromatization
Maturation of monoaromatic steroids yields triaromatic steroids with
one less carbon. TA/(TA + MA) ratio increases from 0.0 to 100 % during
thermal maturation. The ratio has applied to calibrations of basin models
(Mackenzie, 1984). Evidence suggests that this ratio can affected by expulsion
(Peters et al., 1990). The more polar triaromatic steroids are retain
preferentially in the bitumen compared with the expelled oil. In this study, the
TA/(TA + MA) ratio uses the sum of all known C27 – C29 C-ring
monoaromatic steroid peaks (m/z 253) for MA and the sum of all C26 – C28
triaromatic steroid peaks (m/z 231) for TA in the expression TA/(TA + MA)
(Table 18-4).
MA (I)/MA (I + II)
Apparent side-chain scission (carbon-carbon cracking) with increasing
thermal maturity has been documented for aromatic steroids in oils (Seifert
and Moldowan, 1978) and rocks (Mackenzie et al., 1981). MA (I)/MA (I + II)
increases from 0.0 to 100 % during thermal maturation.
It is not known whether this increase is the result of (1) conversion of
long-chain to short-chain monoaromatic steroids by carbon-carbon cracking,
(2) preferential thermal degradation of the long-versus short-chain series, or
Chapter Four Reservoir organic geochemistry
146
(3) both. Moldowan et al. (1986) showed that this parameter is influenced by
diagenetic conditions, particularly Eh, in the source sediment. Mackenzie et al.
(1981) used the C28 monoaromatic steroid (mainly 5β20R isomer) (Moldowan
and Fago, 1986) as MA (II) and the C21 as the monoaromatic steroid MA (I).
The objection to this ratio is that the concentration of C28 relative to C27
through C29 monoaromatic steroids depends partly on source input and the fact
that the C21 monoaromatic steroid may be derived from any or all of the C27 -
C29 monoaromatic steroids. In this study we use the sum of all major C27 - C29
monoaromatic steroids as MA (II) and C21 plus C22 as MA (I) in order to
reduce the source input effect (Table 18-4). Table (18-4) shows systematic
increase of the MA (I)/MA (I + II) ratio with increasing depth in response to
increasing thermal maturity.
Chapter Five Organic geochemical correlation
150
Preface: Organic geochemical correlation
The geochemical correlation procedures can be used to establish
petroleum system to improve exploration success, define reservoir component
to enhance production, and to identify the origin of petroleum contaminating
the deposition environment. Biomarker ratios can be used in geochemical
correlation (i.e. oil-oil or oil-source rock correlation), (Peters et al., 2005).
5.1 Oil – Oil correlation
The biomarker analysis of the studied crude oil samples (Chapter 4)
indicating almost similarity in composition for these oils. One of the early
parameters used in correlation was Pr/Ph ratio; the values of this ratios in the
studied samples are ranging from 0.52 to 0.64 (i.e. <1), indicating anoxic,
marine carbonate depositional environment (Peters et al., 2005).
The biomarker parameter and ratios for the study crude oil samples are
correlated, such as the most characterize one as shown in (Table14-4&18-4),
all of them show strong relationship.
The general crude oil composition of analyzed samples, as indicate
from biomarkers, shows no major geochemical differences, this support the
contention that these crude oils were generate from one source rock or similar
source rocks.
5.2 Oil – Source rock correlation
Correlation of a crude oil to one or more source rocks is a common
industrial application of petroleum geochemistry. Confirmation that oil has
been generated in the target sedimentary basin is the most critical piece of
knowledge a petroleum exploration’s can derive; second in importance is the
determination of the sources of that oil. For this reason, an extensive arsenal
Chapter Five Organic geochemical correlation
151
of analytical methods is utilized to collect primary data on the organic matter
in crude oils and possible source rocks, and various components of these data
are used to relate oils causally to their prospective sources. Oil-source rock
correlations at various confidence levels have established for the petroleum
systems of all major sedimentary basins.
Any successful oil-source rock correlation must include three attributes:
(a) requirement of causality; (b) comparable chemical data for all samples;
and (c) geological support (Curiale, 2008). An oil-source rock correlation is a
causal relationship, established between a crude oil and an oil-prone
petroleum source rock, which is consistent with all known chemical,
geochemical and geological information (Curiale, 1993). List the three key
points of this definition below.
• The relationship must be causal. That is, the oil must arise (at least in part)
from the specified source rock.
• Chemical data used in the correlation must be comparable. That is, the
elemental, molecular and isotopic data derived from the source rock must
be of the same type as that derived from the oil.
• All available geological data must be supportive. That is, clear geological
evidence must exist which allows the proposed source rock to have sourced
the oil.
The absence of any of these three key points necessarily negates the
validity of a proposed oil-source rock correlation. That be the presence of all
three points is required, at a minimum, before declaring a correlation
successful. The importance of both the chemical and geological character of
these three definitional points cannot be overemphasized. Establishing
chemical similarities between the organic matter in a source rock and that in
Chapter Five Organic geochemical correlation
152
an oil, even if these similarities involve ‘genetic’ (i.e., source-derived)
molecular and isotopic characteristics, is necessary but insufficient. Such a
result has to be also supplemented by supporting geological data establishing
that the source was capable – in all spatial and temporal dimensions – of
having generated specific oil. These geological data, including the details of
depositional history and structural configuration through time, are provided as
input to a robust basin model which is used to support the correlation
conclusion in the spatial (i.e., fluid flow configuration) and temporal (i.e.,
timing of generation and expulsion) dimensions. Only when this be confirmed
can a bona fide oil-source rock correlation be concluded with confidence.
Geochemical identification of oil types and their source rocks represents an
important tool in the search for petroleum, especially in areas with complex
depositional and structural histories. Biological markers or biomarkers are
powerful tools to identify petroleum systems. Biomarkers are structurally
complex molecular fossils from once-living organisms that are ubiquitous in
crude oils and source-rock extracts (Peters and Moldowan, 1993). Because
they are, inherited from the source rock, biomarkers in migrated crude oils and
source-rock extracts can be compared like fingerprints to infer genetic
relationships. In many basins, the source rocks are unknown to be deeply
buried to include sampled by drilling. When samples of proposed source rocks
are unavailable, biomarkers in oils can still be used to constrain the identity of
the source. For example, different biomarkers provide information about the
age of the source rock, the composition of the deposited organic matter, and
the oxicity and mineralogy of the depositional environment.
Chapter Five Organic geochemical correlation
153
RESULTS AND DISCUSSION
Biomarkers analyses of the selected source rock extract from well in
Missan oil field samples were compared to the crude oils in an attempt to
establish oil-source rock correlation.
5.2.1 Age and oil-source correlation relevant parameters
Several biomarkers have been shown to be relate to specific modern
taxa, and molecular paleontological studies have revealed correlations, which
allow for the use of certain biomarkers as indicators of geologic age
(Moldowan et al., 1996; Holba et al., 1998). Age diagnostic biomarkers
employed in this study include 24-norcholestanes and 24-nordiacholestanes.
The crude oils show relative amounts of C26 steranes (24-
norcholestanes) and related C26 diasteranes (24-nordiacholestane) are possibly
derived from a diatomaceous precursor (Holba et al., 1998). Their ratios to the
nontaxon-specific C26 steranes, 27-norcholestane and 27-nordiacholestane
(NCR and NDR, respectively; Holba et al., 1998) are in the low to medium
range of values reported for Jurassic-Cretaceous source rocks. The values of
NCR and NDR are relatively medium for the analyzed source rock extracts
(0.23-0.30 and 0.39-0.44, respectively). These medium values (Three extract
rock samples) consistent with their Cretaceous age, and the value of NCR and
NDR for the forth extract source rock sample is (0.18, 0.29, respectively), the
low value consistent with their Jurassic age.
For the crude oils, the ratios pinpoint almost the Jurassic age where the
(NCR) and (NDR) values (0.13-0.19, 0.23-0.29, respectively).For the Jurassic
source rock where values of NCR and NDR are expected (Holba et al., 1998),
(fig.74-5& 75-5)
Chapter Five Organic geochemical correlation
154
5.2.2. Parameters related to maturity, lithology and depositional
environment
Some gas chromatography fingerprints are indicative of particular
organic matter input (Fig.76-5&77-5). For example, bimodal n-alkane
distributions with a second mode in the n-C23 to n-C30 range are usually
associated with terrestrial higher plant waxes (Tissot and Welte, 1984).
Based on the GC data, Pr/Ph ratios for the crude oils are same than that
of the source rock extracts (sample NO-1, AM-3, R-172), indicating same
depositional conditions. Moreover, the plotting of Pr/n-C17 against Pr/n-C18
(Fig.78-5) clearly shows the crude oils and source rock extracts are clustered
in the zone of marine algal with suboxic to anoxic depositional environment.
In summary, the analyzed crude oil samples suggests derivation from
marine organic matter influence, deposited under suboxic to anoxic
conditions, low to middle mature type II kerogen . In addition, the source rock
extracts confirms the dominant marine influxes, deposited under suboxic to
anoxic environments, low to middle mature type II kerogen.
Chapter Five Organic geochemical correlation
155
1
2
3 4
5
67 8
9
10
11
1213
Retention time
131211
10
9
87
6
5
4321
Retention time
Fig. (74-5): Selected MRM for rock extracts and crude oils.
Rock Xtract Well (AM-3)
Crude Oil Well (HF2)
Res
pons
e R
espo
nse
Chapter Five Organic geochemical correlation
156
12
3
4
5
67 8
9
10
11
12
13
Retention time
131211
10
9
87
6
5
4321
Retention time
Fig. (75-5): Selected MRM for rock extracts and crude oils.
Rock Xtract Well R-172
Crude Oil Well FQ-2
Res
pons
e R
espo
nse
Chapter Five Organic geochemical correlation
157
Retention time
Retention time
Fig. (76-5): Selected gas chromatography for rock extracts and crude oils.
Crude Oil Well (AM-3)
Rock Extract Well (AM-3)
Res
pons
e R
espo
nse
Chapter Five Organic geochemical correlation
158
Retention time
Retention time
Fig. (77-5): Selected gas chromatography for rock extracts and crude oils.
Rock Extract Well (NO-1)
Crude Oil Well (NO-2)
Res
pons
e R
espo
nse
Chapter Five Organic geochemical correlation
159
0.1
10
1.0O
xidation
Reduction
TerrigenousType III
Mixed Type II/III
Ph / nC18
Pr/ n
C17
0.1 1.0 10
100
Marine Algal Type II
Biodegradation
Maturation
1
Crude oils Extract rocks Fig. (78-5): Plot of pristane/nC17 versus phytane/nC18, showing organic matter type, source
rock depositional and thermal maturity of crude oil and rock extract samples (Shanmugam, 1985; Peters et al., 1999).
Chapter Six Summary and Recommendation
160
6. Summary and Recommendations
6.1. Summary
The aim of this study was to evaluate the potential source rock of Sulaiy
Formation, also identify the depositional environment by classifying the
Palynofacies, then determine the characterization of crude oil from (18 wells
of 6 oil fields ) in Missan Province, the crude oils were collected from
different pay zone ( Cretaous- Tertiary ), finally make a geochemical
correlation. This study is base on organic geochemical analysis.
6.1.1. Source rock evaluation
Although petroleum systems include source, reservoir, and trap, the
presence of a source rock is the most important factor governing the
accumulation of hydrocarbons. Lower cretaceous Sulaiy Formation in Noor-1
well was investigated as potential for oil, the Sulaiy Formation contain oil
prone (Type II Kerogen), predominantly carbonate marine organic matter to
be consider as potential source rock. The organic geochemical data (Rock
Eval) indicate the distribution of TOC % in the study area varying from Fair to
V.Good potentiality. The Tmax together with the vitrinite reflectance (Ro)
indicating mature source rocks, since the values range from 441 - 450o C and
0.66 - 0.78, respectively. Based on Rock-Eval Pyrolysis data analysis of
Sulaiy Formation in the studied well (No-1) is mature to generate
hydrocarbons and has capability to produce oil (type II kerogen), Sulaiy
Formation lies within the oil window. From biomarker analysis, a plot of
pristane/n-C17 versus phytane/n-C18 ratios indicates that the source rock
extracts originated from type II organic matter deposited under marine algal
type conditions. The ratios of (NCR) and (NDR) consistent with their
Cretaceous age for three samples (R-167, Am-3, and No-1). For the forth
Chapter Six Summary and Recommendation
161
extract source rock (R-172) has, consistent with their Jurassic age. All the
source rock extracts are mature in the in the study area, where (CPI) and
(OEP) ratios more or less approach (1) .From the paleonofacies analysis, the
(AOM) is the most dominant facies in Sulaiy Formation in (NO-1) well. Also
all the Sulaiy Formation samples are mature, the AOM-Phytoclast-
Palynomorph (“APP”) ternary plot shows that most of the samples plot in
AOM dominated field (IX-field) that are usually associated with distal
suboxic-anoxic facies.
6.1.2. Crude Oils
A- Bulk parameters and carbon isotopes of the samples strongly suggest
that the crude oils found in marine depositional envirnment reservoirs of the
study area are derived from a very similar source, crude oils were generated
from a carbonate source rock that contained predominantly algal and bacterial
organic matter These oils show no characteristic of any terrestrial organic
matter input.
Oils submitted to study were generated from organic facies that present
slightly different characteristics that may be due to sediment logical and/or
chemical effects of their respective depositional environment. This small
change of organic facies may be due either to the deposition of the source rock
under more slightly restricted conditions (anoxic) than the other organic
facies, or alternatively to a sediment biological effect. In terms of the thermal
maturity, crude oils are the mature of all the analyzed samples, whereas oils
entrapped in Cretaceous reservoir are the most mature though with no clear
distinction of maturity differences, with Tertiary reservoir. Finally, oils of the
study area have similar isotopic characteristics, Their physical and chemical
Chapter Six Summary and Recommendation
162
differences can be explained through small changes in the organic facies and
thermal maturity of their source rock.
B- Molecular Parameters:
The sterane (m/z 217) distribution in these oils supported the
conclusions reached by those of terpane (m/z 191) analyses. Crudeoils have a
marine planktonic (algae) source of from a source rock deposited under anoxic
and environmental conditions. These oils were generated when their source
rock reached an early stage of maturity, the sterane fingerprint of these oils
has similarities with that of the other oils that may point to their positive
correlation, Molecular parameters of oils support conclusions outlined by bulk
parameters and allow more detail oil characterization and correlation. Both are
sets of geochemical. The oils are marine origin and were generated of from
carbonate. source rock.
The crude oils are possibly derived from anoxic, carbonate, type II
kerogen, Early to middle stage of maturity based on; low Pr/Ph, low
diasteranes, dominance of norhopane over hopane, high relative abundance of
homohopanes and high C29 over C27 sterane (algae).
Finally,
• All the analyzed crude oils are related to the same family,
nonbiodegraded oils.
• Based on age diagnostic biomarkers, the Jurassic seems to be the main
candidate source rock for the oils: absence or scarce oleanane, low
norcholestane ratios.
Chapter Six Summary and Recommendation
163
6.2. Recommendations
The recommendation for future work involves the geochemical analyses
of potential source rock and crude oils from Cretaceous-Tertiary Formations
in Euphrates zone that are more mature with either oil samples from this
study, and to use seismic maps for basin modeling .
The main advantage of pyrolysis method is the procurement of the data
during drilling operations, thus the current study suggests being use Rock-
Eval (pyrolysis method) on the drilling site and allowing the information to be
obtained at an early stage.
Chapter Two Palynofacies Analysis
39
EXPLANATION OF PLATES
Most illustrations are photograph from the prepared slides of the NO-1 well.
The sample number, depth and corresponding formation are specified
respectively for each illustrated specimen. All magnifications are
50X / 0.80 A. Plate 1: Phytoclasts Fig.1: Slide 13b, 4770 m, Resin particle.
Fig.2: Slide 22b, 4850 m, Resin particle.
Fig.3: Slide 24b, 4900 m, Resin particle.
Fig.4: Slide 10a, 4915 m, Cuticles particle.
Chapter Two Palynofacies Analysis
40
1
3
3
4
Chapter Two Palynofacies Analysis
41
Plate 2: Palynomorphs (Terrestrial spores and pollen) Fig.1: Slide 3b, 4750 m. Cyathidites sp.
Fig.2: Slide 4b, 4780 m. Cyathidites sp.
Fig.3: Slide 5a, 4815 m. Pelfoidospore sp.
Fig.4: Slide 8a, 4862 m. Trilobosporite sp.
Fig.5: Slide 6a, 4910 m. Tasmanites sp.
Fig.6: Slide 6b, 4910 m. Perotrilets sp.
1 2
3 4
5 6
Chapter Two Palynofacies Analysis
42
Plate 3: Palynomorphs (Dinoflagellates - foraminifera)
Fig.1: Slide 10b, 4750 m, Dinoflagellate cyst. Cyclonephelium sp.
Fig.2: Slide 13a, 4780m, Dinoflagellate cyst. Gonyaulacysta sp.
Fig.3: Slide 13b, 4780 m, Dinoflagellate cyst. Oligosphaeridium sp.
Fig.4: Slide 15b, 4815 m, Dinoflagellate cyst. Dingodinium jurassi
Fig.5: Slide 18b, 4839 m, Dinoflagellate cyst. Ellispoidinum cinctum.
Fig.6: Slide 17b, 1961 m, Dinoflagellate cyst. Gonyaulacysta sp.
Fig.7: Slide 20a, 4862 m, Dinoflagellate cyst. Spiniferites sp.
Fig.8: Slide 20b, 4862 m, Dinoflagellate cyst. Cyclonephelium sp.
Fig.9: Slide 12a, 4900 m, Tectinous foraminiferal test linings.
Fig.10: Slide 14a, 4915m, Uniserial tectinous foraminiferal test linings.
Fig.11: Slide 11b, 4922 m, Tectinous foraminiferal test linings.
Fig.12: Slide 16a, 4928 m, Tectinous foraminiferal test linings.
Fig.13: Slide 24b, 4932 m, Tectinous foraminiferal test linings.
Chapter Two Palynofacies Analysis
43
1 2
11
3 4
5 6 7 8
9 10
12 13
Chapter Two Palynofacies Analysis
44
Plate 1: Amorphous organic matter (AOM)
Fig.1: Slide 3b, 4742 m.
Fig.2: Slide 6a, 4750 m.
Fig.3: Slide 8b, 4770 m.
Fig.4: Slide 11b, 4780 m.
Fig.5: Slide 13a, 4800 m.
Fig.6: Slide 13a, 4825 m.
Fig.7: Slide 15b, 4850 m.
Fig.8: Slide 19b, 4862m.
Fig.9: Slide 34b, 4890 m.
Fig.10: Slide 37a, 4910 m.
Fig.11: Slide 37a, 4922 m.
Fig.12: Slide 37b, 4932 m.
Chapter Two Palynofacies Analysis
45
1
4 56
7 8 9
10 11 12
2 3
Chapter Two Palynofacies Analysis
46
Plate 5: Opaques
Fig.1: Slide 25a, 4770 m.
Fig. 2: Slide 25b, 4825 m.
1 2
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