Crude Oil Characterization and Source Affinities of Missan

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

الثلاثي 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 تحليلات مواصفات النفط الخام على

الدلائل الحياتية وذلك باستخدام تحليلات) الثلاثي–الكريتاسي (في محافظة ميسان ذات الاعمار )Biomarker( حيث اشارت تحليلات الغاز الكروماتغرافي ،)GC ( لنسب)Pr/Ph ( الى اقل

مما يؤكد البيئة الكاربوناتية البحرية للصخور المصدرية، وقد اشارت تحليلات ) 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 تحليلات

.الجوراسي نفط لنماذج مكامن الكريتاسي والثلاثي 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 الأرضدكتوراه 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.


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)


٣

Figure (1-1) Location map of study area


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


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


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.


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


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.


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.


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


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.


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


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


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.


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.


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).


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


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


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.


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


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


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


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).


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.


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.


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.


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.


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%).


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 (especially 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).


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.


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


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


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).


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


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.


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).


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.


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


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


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


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).


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:


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


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


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.


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


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


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.


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.


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


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).


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


63


(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


64


(NO-1) well.


(R-172) well.

Retention time

Res

pons

e R

espo

nse

Retention time


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.


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).


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


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.


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


70

1

2

3 4

5

67 8

9

10

11

1213


(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


(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


71

12

3

4

5

67 8

9

10

11

12

13


(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


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


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


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:


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:


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


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.


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


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.


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).


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


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).


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

Retention time

Res

pons

e


86



Retention time

Res

pons

e

Retention time

Res

pons

e


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

Res

pons

e

Retention time

Res

pons

e


88



Retention time

Res

pons

e

Retention time

Res

pons

e


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

Res

pons

e

Retention time

Res

pons

e


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

Res

pons

e

Retention time

Res

pons

e


91

Fig. (36-4): Gas chromatograms for Crude oil sample from BU-20 well.


Retention time

Res

pons

e

Retention time

Res

pons

e


92


Fig. (39-4): Gas chromatograms for Crude oil sample from FQ-3 well.

Retention time

Res

pons

e

Retention time

Res

pons

e


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

Res

pons

e

Retention time

Res

pons

e


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


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).


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


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


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).


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.


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


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)


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 HF-2

GC-MS m/z 191 Well AG-1


102

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).


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(AG-7,FQ-8), Peaks identifications are specified in Table (3).


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(FQ-11,FQ-2), Peaks identifications are specified in Table (3).

GC-MS m/z 191 Well FQ-11


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(NO-2,HF-1), Peaks identifications are specified in Table (3).

GC-MS m/z 191 Well NO-2


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(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).



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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).



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(FQ-4,FQ-5), Peaks identifications are specified in Table (3).



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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


111

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).


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


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,


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.


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.


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).



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(HF-2). Peaks identifications are specified in Table (6).

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(FQ-5). Peaks identifications are specified in Table (6).

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(BU-11). Peaks identifications are specified in Table (6).

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120

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


121

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


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 .


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


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.


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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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


GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( FQ-8).

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131211

10

9

87

6

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4321



1312

1110

9

1 23 4

5

67

8


GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( HF-1).

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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


GCMS) m/z 358 →217 analyses of C26 steranes for crude oil sample, well( BU-20).

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1312

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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).


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.

Retention time

Res

pons

e

Retention time

Res

pons

e

GC-MS M/z 253 Well (AG-7)

GC-MS M/z 231 Well (AG-7)


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)


Retention time

Res

pons

e

GC-MS M/z 253 Well (HF-1)


Retention time

Res

pons

e


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)


GC –MS M/z253 Well (HF-2)


Retention time

Res

pons

e

Retention time

Res

pons

e


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)


GC-MS M/z 253 Well (FQ-5)

GC-MS M/z 231 Well (FQ-5)

Retention time

Res

pons

e

Retention time

Res

pons

e


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


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).


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


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 .


139


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


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.


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


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


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).


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


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


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


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.


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)


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.


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


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


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


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


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


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


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


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.


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.


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.


40

1

3

3

4


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


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.


43

1 2

11

3 4

5 6 7 8

9 10

12 13


44

Plate 1: Amorphous organic matter (AOM)

Fig.1: Slide 3b, 4742 m.

Fig.2: Slide 6a, 4750 m.






Fig.8: Slide 19b, 4862m.


Fig.10: Slide 37a, 4910 m.

Fig.11: Slide 37a, 4922 m.

Fig.12: Slide 37b, 4932 m.


45

1

4 56

7 8 9

10 11 12

2 3


46

Plate 5: Opaques


Fig. 2: Slide 25b, 4825 m.

1 2

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Crude Oil Characterization and Source Affinities of Missan

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