Thesis 2009 Source Rock Evaluation

SOURCE ROCK EVALUATION OF

LOWER TERTIARY FORAMTIONS IN

NORTHEAST IRAQ

A THESIS

SUBMITTED TO THE COUNCIL OF THE COLLEGE OF SCIENCE, UNIVERSITY OF SULAIMANI, IN PARTIAL FULFILMENT OF THE REQUIRMENTS FOR THE DEGREE OF MASTER OF SCIENCE IN

GEOLOGY

BY

Kardo Sardar Mohammed Ranyayi B.Sc. University of Sulaimani.2002

SUPERVISED BY

Dr. Dler H. Baban Assistant Professor

October 2009 A.D Galarizan 2709 kurdi

@@

Dedicated to

My Father &mother

My kind brothers and sisters

My best friends

All those who love me

Love Science

Love our country KURDISTAN

With my respect@@

Kardo S. M. Ranyayi

2009

I

ACKNOWLEDGMENTS I thank God for always being with me and for everything He has done for me.

My thanks also for the Deanery of College of Science and the Department of

Geology for providing all the facilities required for this study.

I would like to express my deepest gratitude and appreciation to my supervisor

Dr. Dler H. Baban for suggesting the subject of this research and for his sincere help,

continuous guidance, and precious remarks throughout the work.

I also would like to express my thanks for the Northern Oil Company (Kirkuk) for

providing the rock samples used in this study in the wells KM-3, Ja-46, and Pu-7.

I am very grateful to Western Zagros Oil Company, especially Dr. George

Pinckney and Mr. William Matthews for funding and assisting me in analyzing rocks,

extracts, and oil samples by Rock Eval 6 and GC/MS instruments in Baseline

Resolution Inc. (Analytical Laboratories) Texas, USA.

My unlimited thanks should go to Genel Energy Oil Company (TTOPCO) for

providing me with rock samples for the well TT-04 and also for pyrolysing 10 samples

in TPAO Research Center, Ankara, Turkey.

I wish to thank, most gratefully, Dr. Fawzi M. Al-Bayati, Dr. Fadhil A. Lawa, Dr.

Ibrahim. M. J. Mohyaldin, and Dr.Thamer K. Al-Ameri for their help by offering me

some references and some requirements during the palynological preparations.

Special thanks are due to Dr. Polla A. Khanaqa, Kurdistan Technology and

Scientific Research Establishment (Sulaimani), for his cooperation in using the

florescent microscope.

I wish to express my recognition to Ms. Shadan M. Ahmed, Mr. Irafan O. Musa,

Ms. Divan O. Qadir, and Mr. Omed M. Mustafa from Geology Department for

supporting me and giving me references for enhancing my study and providing some

requirements during the Laboratory works.

I extend my thanks to Mr. Luqman Omer and Mr. Dlzar Dilshad from the

Chemistry Department for their assistance in Infrared Analysis and providing me with

some chemical solutions.

Kardo S. M. Ranyayi

II

ABSTRACT

The total 207 rock samples have been chosen from Aaliji, Kolosh, or

Aaliji/Kolosh, and Jaddala Formations in four wells of Taq Taq-04, Kor Mor-3,

Jambur-46, and Pulkhana-7 to be studied optically and analytically for their

hydrocarbon generation potential determination. Two oil samples from Tertiary

reservoirs of wells Ja-25 and Tq-2 have been chosen for source

oil and oil

oil

correlation studies.

Optically, three types of palynofacies were identified depending on the

difference in their organic matter components (AOM, Palynomorphs, Phytoclasts, and

Opaque materials). These three identified palynofacies indicated deposition in distal

suboxic-anoxic basin, and only part of the Palynofacies -2 appeared to be deposited

in proximal suboxic-anoxic shelf. The Thermal Alteration Index (TAI) of the contained

organic matters from the identified dinoflagellate species Operculodinium sp. showed

color change from orange (2 TAI) to light yellowish brown (3- TAI) which indicating

that the organic matters within the studied samples were not affected by the

Paleotemperatures higher than 96°C, and only the lower part of Aaliji/Kolosh beds in

TT-04 entered the maturity state.

The dominant type of AOM in the four studied sections is type A with some

contribution from types B, C, and D, and the infrared spectroscopy (IR) analysis for

the studied samples supported this result. The non-fluorescence of the AOM matters

within Aaliji/Kolosh, Aaliji, and Jaddala Formations under the ultraviolet light proved

the marine(autochthonous) origin of the organic matters that were derived from

degradation of phytoplanktons in the four studied sections ,with exception of the

upper part of the Aaliji/Kolosh and Kolosh Formations in TT-04 which appeared to be

of low-fluorescence to non-fluorescence indicating a mix of marine (autochthonous)

origin derived from degradation of phytoplanktons and also of continental

(allochthonous) origin derived from degradation of plant debris.

Early stages of maturity have been indicated from the Vitrinite Reflectance

measurements done for chosen samples from the lower part of Aaliji/Kolosh beds in

TT-04 (Ro between 0.62% and 0.64%), while all other studied samples from the rest

sections showed still thermally immature conditions of organic matters

From TOC content point of view; Jaddala Formation is generally good or very

good as source rock, while the other studied formations are generally poor. Most of

the organic matters within Aaliji/Kolosh beds and Kolosh Formations in TT-04 appear

to be of kerogen type III, while the organic matters that existed in the other sections

III

generally showed a mix of type II and III. Maturity parameters obtained from pyrolysis

analysis indicated that the lower part of Aaliji/Kolosh in TT-04 can be considered

relatively of higher maturity than the other studied successions (within oil window

generation), and expulsion already occurred in these beds, while in KM-3 and Ja-46

the studied successions are very close to maturity and they may generate some

hydrocarbons but not enough to initiate expulsion. Indigenous condition of

hydrocarbons was clear for the sections of TT-04, KM-3, and Ja-46 while in Pu-7

contamination state or migrated hydrocarbons were obvious.

The depositional environment related biomarkers indicate that the initial

organic matters for all the extracted and the two oil samples were deposited in anoxic

clay-poor carbonate environment with contribution from algal origin of organic

matters, except Aaliji/ Kolosh beds in TT-04 (at depth 1441m) in which the organic

matters seem to be of more terrestrial sources. No hypersaline condition of

deposition for the initial organic matters within the analyzed samples has been

detected. The maturity indicator biomarkers like steranes, Pr/Ph, and CPI indicate

that the oil from Tq-2 is more mature than the oil from Ja-25, while most of the

extracted samples appear to be immature except for those related to Aaliji/Kolosh

beds from TT-04. The oil sample of Ja-25 showed no biodegradation effects, while

the oil of Tq-2 appeared to be in slight to moderate level (2-3) of biodegradation.

Differences between the oil of the U. Eocene Pila Spi reservoir and the oil of U.

Cretaceous reservoirs in Taq Taq Oil Field have been observed and interpreted as

due to contribution of other sources (in addition to the Jurassic and Cretaceous beds)

like Paleocene beds in generating the accumulated oil in the U. Eocene Pila Spi

reservoir and due to the effect of some kinds of degradations.

IV

Table of Contents

Subjects

Page No.

Acknowledgments .. .. .. .

I

Abstract .. .. .. .. .

II

Table of contents .. .. .. ...

IV

List of figures .. .. .. ..

VI

List of tables .. .. .. .. X

Chapter One: Introduction

1.1 Preface. .. .. ..

1

1.2 Previous Studies. .. .. ..

1

1.3 Aims of the study .. .. ...

2

1.4.

Aaliji Formation

.. .. ..

3

1.5 Kolosh Formation .. .. .. 4

1.6 Jaddala Formation .. ..

5

1.7

The Study Area

.. .. .. .

7

1.7.1Taq Taq oil field. .. .. ..

7

1.7.2 Kor Mor oil field. .. .. ..

7

1.7.3 Jambur oil field. .. .. ..

7

1.7.4 Pulkhana oil field .. .. .. ..

8

1.8 Sampling. .. .. .. ..

8

1.9

Methodology .. .. ..

9

Chapter Two: Palynofacies Analysis

2.1 Preface .. .. ..

16

2.2 Palynofacies applications. .. .. ..

16

2.3 Classifications of Sedimentary Organic Matters .. ...

17

2.4 Palynofacies identification for

the studied samples .. ..

22

2.4.1 Palynofacies -1(PF.1) .. .. ...

22

2.4.2 Palynofacies-

2(PF.2) .. .. ...

22

2.4.3 Palynofacies -3 (PF.3)

.. .. .

23

2.5

Palynofacies analysis. .. .. ..

29

Chapter Three: Optical Observation

3.1 Preface. .. .. .. .

35

3.2 Maturation of Organic Matters. .. ..

35

3.2.1Thermal Alteration Index (TAI)

.. .. ..

36

3.2.2

Evaluating Maturity by TAI

.. .. .

38

V

Subjects

Page No.

3.3 Amorphous Kerogen .. .. .

40

3.4 Fluorescence microscopy .. .. .

46

3.5 Infrared Spectroscopy .. .. ..

48

3.6 Vitrinite Reflectance (RO)

.. .. .

54

3.7 Ternary kerogen plots. .. .. ..

60

Chapter Four: Pyrolysis analysis

4.1 Preface .. .. ..

62

4.2 Total Organic Carbon (TOC %)

.. ..

65

4.3 Extractable Organic Matter (EOM)

.. .. ..

69

4.4 Rock-Eval parameters .. .. .

71

4.4.1 Hydrogen Index (HI) and Oxygen Index (OI)

.. .

73

4.4.2 Genetic Potential (GP)

.. .. ..

83

4.4.3 Transformation Ratio (TR) .. ..

86

4.4.4 Bitumen Index (S1/TOC %)

.. ..

94

4.4.5 S2 and TOC (%)

.. .. ..

99

4.4.6 RC and TOC (%)

.. .. ..

106

Chapter Five: Biomarkers

5.1 Preface. .. .. .. .

109

5.2 Uses of Biomarkers

.. .. ..

109

5.3 Analyzed Samples

.. .. .. ..

110

5.4 Depositional Environment and Source related Biomarkers

110

5.4.1 Pristane and Phytane

.. ..

111

5.4.2 The Carbon Preference Index (CPI) .. .. .

113

5.4.3 Steranes and Diasteranes .. .. .

116

5.4.3.1 C27, C28, and C29

Steranes Ternary Plot. ..

116

5.4.3.2 Diasteranes / Steranes Ratio

.. ..

119

5.4.3.3 C30

Sterane Index [C30/ C27-C30) Steranes] ..

122

5.4.4 Gammacerane index .. .. .. .

122

5.4.5 Terpanes. .. .. ..

124

5.4.6 Ts/ (Ts+Tm) .. .. .. .

127

5.4.7 Oleanane. .. .. ..

128

5.4.8 Dibenzothiophene(DBT)/Phenantheren. .. .

129

5.5 Maturation Determination by Biomarkers

.. ..

130

5.5.1. Sterane and Diasterane

.. .. .

131

5.5.2

Ts / (Ts + Tm)

.. .. .. .

131

5.5.3

Hopanes. .. .. .. ..

131

5.6 Petroleum Biodegradation

.. .. ..

134

VI

List of Figures

Subjects

Page No.

5.6.1 Controls on Petroleum Biodegradation

.. ..

135

5.6.2

The Rate of Reservoir

Oil Compositional Degradation

135

5.6.3

Biodegradation effect on the analyzed oils of Tq-2 and Ja-25. .

136

5.7 Stable Carbon Isotope

.. .. .. .

144

5.8 Oil-Oil and Oil-Source Rock Correlations

.. .

145

5.8.1 Pr / nC17

versus Ph / nC18. .. .. ..

147

5.8.2 Steranes and Diasteranes Ternaries

.. .. 148

5.8.3 Carbon Isotope data .. .. .. ..

150

5.8.4 Reservoir Oil Fingerprinting (ROF)

.. .. .

151

5.8.5 Miscellaneous. .. .. .. ..

153

Chapter Six: Conclusions and Recommendations

6.1 Conclusions .. .. .. ..

156

6.2 Recommendations .. .. .. .

160

References .. .. .. ..

161

Subjects

Page No.

1.1 The location map of the studied area. .. ..

8

2.1 Palynofacies -1

.. .. ..

24

2.2 Palynofacies -2

.. .. ..

24

2.3 Palynofacies -3

.. .. ..

24

2.4

Percentages of different organic matter components .in TT.04....

25

2.5

Percentages of different organic matter components in KM-3...

26

2.6

Percentages of different organic matter components . in Ja-46

27

2.7

Percentages of different organic matter components in Pu-7.....

28

2.8 AAP ternary diagram . ...inTT-04

31

2.9 AAP Ternary diagram in Km-3

32

2.10 AAP Ternary diagram . . ..in Ja-46 .

32

2.11 AAP Ternary diagram . . . in Pu-7 .

33

2.12 A cross section show the correlation between . .

34

3.1 Dinoflagellate species

as an indicator for maturity (TAI 2) ...

39


as

an indicator for maturity (TAI +2)

39


as an indicator for maturity (TAI 3)

..

39

3.4 Amorphous Organic Matter Type (A)

.. ..

42

3.5 Amorphous Organic Matter Type (B)

.. ..

42

3.6 Amorphous Organic Matter Type(C)

..

42

3.7 Amorphous Organic Matter Type (D)

.. ...

42

VII

Subjects

Page No.

3.8 Classification of palynofacies constituents ..

47

3.9 The infrared analysis Graphs for.......................... .. .

49

3.10Typical Infra Red spectra of the four types of AOM

.

50

3.11 Kerogen and maturity level determined from A factor C factor...for TT.04.

52

3.12 Kerogen and maturity level determined from A factor C factor...for KM-3..

53

3.13 Kerogen and maturity level determined from A factor C factor...for Ja-46..

53

3.14 Kerogen and maturity level determined from A factor C factor...for Pu-7..

54

3.15 Vetrinite Reflectance Histograms.......................................... from TT-04...

56

3.16 Vetrinite Reflectance Histograms.......................................... from KM-3

57

3.17 Vetrinite Reflectance Histograms.......................................... from Ja-46

58

3.18 Vetrinite Reflectance Histograms.......................................... from Pu-7 .

59

3.19Ternary Liptinite -Vitrinite-

Inertinite LVI) kerogen plot. ..

61

4.1 Evaluation ..in TT-04 depending on variations TOC content

with depth. .. .. .. .

67

4.2 Evaluation ..in Km-3 depending on variations TOC content


68

4.3 Evaluation ..in Ja-46 depending on variations TOC content


68

4.4 Evaluation ..in Pu-7 depending on variations TOC content

with depth. .. .. ..

69

4.5 Source rock

potential rating based on TOC (%) and EOM (ppm) .. 70

4.6 HI versus OI cross plot .. in TT-04 ..

75

4.7 HI versus OI cross plot .. in KM-3 .. .

75

4.8HI versus OI cross plot .. in Ja-46 .. .

76

4.9 HI versus OI cross plot .. in Pu-7 .. .

76

4.10 HI versus Tmax cross plot .in TT-04 .. .

77

4.11HI versus Tmax cross plot .in KM-3 .. ..

77

4.12 HI versus Tmax cross plot ... in Ja-46 .. ..

78

4.13HI versus Tmax cross plot . in Pu-7 .. ..

78

4.14HI versus Tmax cross plot . in TT-04 .. .

79

4.15HI versus Tmax cross plot . in KM-3 .. .. 79

4.16HI versus Tmax cross plot . in Ja-46 .. .

80

4.17HI versus Tmax cross plot . in Pu-7 .. 80

4.18 Tmax versus depth . in TT-04 .. .

81

4.19 Tmax versus depth .in KM-3 ..

81

4.20Tmax versus depth . in Ja-46 ..

82

4.21 Tmax versus depth .In Pu-7 .. .

82

4.22 TOC (%) versus S1+ S2 (Genetic Potential) ..in TT-04 .

84

VIII

Subjects

Page No.

4.23 TOC (%) versus S1+ S2 (Genetic Potential) ..in KM-3

84

4.24 TOC (%) versus S1+ S2 (Genetic Potential) ..in Ja-46 ..

85

4.25 TOC (%) versus S1+ S2 (Genetic Potential) ..in Pu-7

85

4.26

PI versus depth .in TT-04 ..

88

4.27 PI

versus depth .in KM-3 ..

88

4.28 PI

versus depth

.inJa-46 ..

89

4.29 PI versus depth .in Pu-7 ..

89

4.30 Tmax versus TR ..in TT-

04

90

4.31

Tmax versus TR ..in KM-3 ..

90

4.32

Tmax versus TR ..in Ja-46

91

4.33

Tmax versus TR ..in Pu-7 ..

91

4.34 Tmax versus PI .. ....in TT-

04 ..

92

4.35 Tmax versus PI .. ....in KM-3 ..

92

4.36 Tmax versus PI .. ... in Ja-46 ..

93

4.37 Tmax versus PI .. ... in Pu-7 ..

93

4.38 S1/TOC versus Depth in TT-

04

95

4.39

S1/TOC versus Depth in KM-3 ..

95

4.40

S1/TOC versus Depth in Ja-46 ..

96

4.41 S1/TOC versus Depth in Pu-7 ..

96

4.42 S1/TOC versus Depth ..in TT-

04 .

97

4.43 S1/TOC versus Depth ..in KM-3 ..

97

4.44 S1/TOC versus Depth ..in Ja-46 ..

98

4.45 S1/TOC versus Depth ..in Pu-7 ..

98

4.46 TOC versus S2 cross plot . . in TT-04 ..

99

4.47 TOC versus S2 cross plot . . in KM-3 ..

100

4.48 TOC versus S2 cross plot . . in Ja-46 ..

100

4.49 TOC versus S2 cross plot . . in Pu-7

101

4.50 TOC versus S2 . in TT-04 .

102

4.51 TOC versus S2 . In KM-3 ..

102

4.52 TOC versus S2 . In Ja-46 ..

103

4.53 TOC versus S2

in Pu-7 ..

103

4.54 TOC versus S2 in TT-04

104

4.55 TOC versus S2 in KM-3 .

104

4.56 TOC versus S2 in Ja-46 .

105

4.57 TOC versus S2 in Pu-7 ..

105

4.58 TOC versus RC .. ..in TT-

04 ..

106

4.59 TOC versus RC .. ..in KM-3

107

4.60 TOC versus RC .. ..in Ja-46 .

107

4.61 TOC versus RC .. ..in Pu-7 ..

108

5.1 Pr/nC17 versus Ph/nC18 cross plot .

114

5.2 Pr/nC17

versus Ph/nC18 cross plot

115

5.3 Cross plot of Pr/Ph versus CPI .

115

5.4 Ternary plot ..C27, C28, and C29

steranes .

118

5.5Ternary plot C27, C28, and C29

steranes .

119

5.6

Pr/ (Pr+Ph)

versus C27

Diasteranes/ (Diasteranes+ regular Steranes)

121

IX

Subjects

Page No.

5.7 C27/C29

Diasteranes versus C27/C29

Steranes

121

5.8

Cross plot of Pr/ Ph

versus C29/

C27

sterane .

122

5.9 Gammacerane Index versus Pr / Ph ratio ..

124

5.10 Tricyclic terpanes C22/C21 versus Tricyclic terpanes C24/C23

ratio

126

5.11 C29H/C30H versus C35H/C34H ratios ...

126

5.12 Cross plot between Pr/Ph ratio and hopane/sterane ratio .

127

5.13

Cross plot of CPI versus Ts/ (Ts+Tm) ..

128

5.14 Cross plot between Pr/Ph ratio and DBT/Phenantheren

130

5.15 S/(S+R) C29ST ( )

versus S/ ( S+ R) C29ST

ratios .

132

5.16Ts/ (Ts+ Tm) versus C27Dia / (Dia+ Reg. Steranes) cross plot ..

133

5.17 cross plot of Terpane maturity parameters

133

5.18 A schematic diagram of physical and chemical changes occurring during

crude oil and natural gas biodegradation ..

137

5.19 The Cross plot of 1MP + 9MP versus 2MP + 3MP ..

139

5.20 P1, P2, and P3 ternary of Mango

139

5.21 Cross-plot of Ph/nC18 versus trimethylnaphthalene(TMN) .

140

5.22 GC of the oil from Tq-2 and oil from Ja-25 .

142

5.23 Gross composition of Ja-25 and Tq-2......................................................

143

5.24 13C saturate versus 13C aromatic cross plot. .

145

5.25

Ternary diagram of C27, C28, C29

steranes ....

149

5.26

Ternary diagram of C27, C28, C29

Diasteranes ...

149

5.27 Star diagram. ...

152

5.28

Cross plot of Ts/Tm versus C35H/C34H ...

154

5.29

Cross plot of C29H/C30H versus Diasterane/Sterane .

154

5.30

Cross plot of Sterane/Hopane versus C27

/ C29 ( S) .

155

5.31

Cross plot of Ts/Tm versus Diasterane/Sterane .

155

X

List of Tables

Subjects

Page No.

1.1 Optical and chemical analysis of the sedimentary organic matter content

in the Paleocene-Lower Eocene beds in N and part of middle Iraq

2

1.2

Locations of the studied sections .

7

1.3

The number of samples and type of testing .

in TT-04 .

10

1.4

The number of samples and type of test ...in KM-3

12

1.5

The number of samples and type of testing

in Ja.46

13

1.6

The number of samples and type of

testing .in Pu-7

14

2.1 Percentage of the different organic matter .in TT-

04

18

2.2 Percentage of the different organic matter .. .in KM-3 ..

19

2.3 Percentage of the different organic matter ... in Ja-46 ..

20

2.4 Percentage of the different organic matter in Pu-7 ...

21

2.5 The statistical analysis for palynofacies-1

22

2.7 The Statistical analysis for palynofacies-2 .

23

2.6 The statistical analysis . for palynofacies-3 .

23

3.1 Amorphous Kerogen Types as described optically by Thompson

and Dembicki, (1986) .

41

3.2 Types of AOM . in TT.04 well .

43

3.3 Types of AOM .. in KM-3 well. .

44

3.4 Types of AOM .. in Ja-46 well ..

45

3.5 Types of AOM .. in Pu-7 well. ..

46

3.6 Measured intensities from Infrared spectroscopy .....................in TT.04

51

3.7 Measured intensities from Infrared spectroscopy ............ .

in KM-3

51

3.8 Measured intensities from Infrared spectroscopy ........... ...in Ja-46

51

3.9

Measured intensities from Infrared spectroscopy ............ ...in Pu-7

52

3.10 The percentage of Liptinite, Vitrinite and Inertinite .

60

4.1 Rock-Eval data for the pyrolyzed samples in TT-04 ...

63

4.2 Rock-Eval data for the pyrolyzed samples .in KorMor-3 .

63

4.3 Rock-Eval data for the pyrolyzed samples .in Jambur-46 ..

64

4.4 Rock-Eval data for the pyrolyzed samples .in Pulkana-7 ...

64

4.5 The source rock classification according to TOC (%) content ...

66

4.6 Min,Max,and Mean of the TOC contents.......and their evaluation.

67

4.7

The TOC (%) and EOM (ppm) values .

70

4.8

Rock-Eval parameters and their abbreviations. .

72

4.9 Calculated Rock-Eval parameters and their abbreviations ..

72

4.10

Maturity stage as related to Vitrinite Reflectance and Tmax.

..

73

4.11

Maturity level as a function of production Index and Tmax ..

73

XI

Subjects

Page No.

4.12 Evaluation of source rocks .......genetic potential values

83

4.13 Immature organic matter and production index.

86

5.1 Ratios of Pr/Ph, Pr/ Pr+Ph), Pr/nC17and Ph/nC18 and CPI.

114

5.2 The

percentage of the C27, C28, and C29

Ster.and Dia. and Dia./Ster.

118

5.3 The ratios of different biomarkers which have been used in detecting the

source and depositional environment.

120

5.4 The ratio of Gammacerane Index .

123

5.5 The ratios of different Terpanes for

the analyzed two oil . extracts.

125

5.6 Ratios of Ts/ (Ts+Tm) and CPI ...

128

5.7The Pr/Ph ratio and DBT/Phenantheren.

129

5.8 The ratios of some maturity parameters

for the analyzed oil and extract. 132

5.9 (1PM+9PM) + (2PM+3PM) and TMN

138

5.10 P1, P2, and P3 values .

138

5.11 Diasterane/Sterane ratio and Sterane epimer

values .

141

5.12 Chemical composition...... (%SAR, %ARO, %NSO and %ASPH) .

141

5.13 13C Saturate and 13C Aromatic Isotopes data .

144

5.14 Pr/n17.Ph/n18 ratio and CPI........................Oil of Tq-1 .

148

5.15 13C Saturate and 13C Aromatic Isotopes data............... Oil of Tq-1.

150

5.16 The parameters used in the oil-oil correlation and fingerprinting.

152

5.17 Ratio of different biomarkers

used in oil-oil correlation and Oil-Source

rock correlation.

153

CHAPTER ONE ___________________________________________

Chapter one Introduction

1

1.1: Preface.

Most of the executed studies about the source rocks in Iraq concentrated on

studying the formations which are older than Tertiary (especially Jurassic) without

paying attention to some Tertiary Formations like Aaliji, Kolosh and Jaddala which

may have a role in generating hydrocarbons in the places in which they occur.

Studies about evaluation of some Tertiary beds have been done in Western

Iran and they discovered that Pabdeh Formation (Which is equivalent to Kolosh and

Aaliji Formations) contributed in generating oils in some Iranian Oil Fields (Bordenave

and Burwood, 1990; Rabbani and Kamali, 2005; and Alizadeh et al., 2007). There

are also a number of studies done by other authors in some other countries like

Turkey and Jordan (Sari and Aliyev, 2006; Sari et al., 2007and Abed and Arouri,

2006).

The Early Tertiary (Palaeocene-Lower Eocene) sediments in Iraq cover most

areas consists of clastic and carbonate sediments. These sediments were first

identified by Henson (1951: in Al-Ameri, 1996) and Dunnington (1958). They claimed

a regressive cycle with a discontinuous sedimentation in most parts of the basin (Al-

Ameri, 1996).The Aaliji, Kolosh and Sinjar Limestone Formations belong to the

Palaeocene-Lower Eocene Cycle and the Jaddala Formation belongs to the Late

Lower Eocene - Upper Eocene cycle of platform area in Iraq (Buday, 1980).

The Palaeocene-Lower Eocene cycle, as a whole is marked by the origin and

full development of the geosynclinal area on the territory of Iraq and by widespread

transgression on the shelf. The cycle starts with a widespread transgression, most

probably throughout the whole area of Iraq (ibid).

Bellen et al. (1959) introduced the lithostratigraphic terminology for the

Palaeocene-Lower Eocene sediments as Suwias red beds for the red beds, Kolosh

Formation for the flysch clastic, Aaliji Formation for the Baisnal marl, Sinjar Formation

for the reefal neritic limestone, Um El-Rdhuma Formation for the platform limestone

belt in the Western Iraqi Desert and Jaddala Formation for the offshore marly and

chalky limestone and marls.

1.2 Previous Studies:

There are no detailed studies about the source rock evaluation of Tertiary

beds in Iraq, except for the study done by Al-Ameri et al. (1991) about the

palynomorph maturation of Palaeocene-Lower Eocene at some exposures in north

and parts of middle Iraq as shown in Table (1.1).


2

Table (1.1): Optical and chemical analysis of the sedimentary organic matter content in

the Palaeocene-Lower Eocene beds at some exposures in north and parts

of middle Iraq (after Al-Ameri et al., 1991).

Key to the abbreviations: TAI=Thermal Alteration Index, AOM=Amorphous Organic Matter,

TOC=Total Organic Carbon.

1.3 Aims of the study:

The main objective of this study is to show the hydrocarbon potentiality of the

Lower Tertiary Formations (Aaliji, Kolosh, and Jaddala) in parts of northeastern Iraq

and their contribution in generating the oil accumulated in the reservoirs in northern

Iraqi Oil Fields, and that is done by determining the following:-

1- The type and quantity of organic matter contents within Lower Tertiary

Formations in the studied wells.

2- The origin and the paleodepositional environment of identified organic matter

contents.

3- The level of maturity of the existing organic matters in the studied formations

and their potential for hydrocarbon generation.

4- The origin, the properties, and the age of some selected oil samples from the

study area.

5- Correlation between the extracts from these formation rocks and some

accumulated oils within the reservoirs in the same or other nearby oil fields.

No.

Locality

Spore color

TAI

Paleogeothermy

?c

AOM

%

TOC

%

Facies

1. Tasluja Dark brown 3.0 180 2 ----- Metamorphosed

2. Choarta Brownish black 3.4 200 Nil ----- Metamorphosed

3. Dokan Brown 2.8 170 7 0.44 Transitional

4. Shaklawa Amber yellow 2.2 90 15 0.64 Mature

5. Aqra Light brown 2,5 120 6 0.05 Mature

6. Zakho Light brown 2.5 120 10 ----- Transitional

7. Tel-Hajar Amber yellow 2.2 90 10 ----- Mature

8. Akkashat Green yellow 1.2 30 Nil ----- Immature

9. Ethna yellow 1.8 60 Nil ----- Immature


3

1.4 Aaliji Formation:

The Aaliji Formation is one of the most widespread Palaeocene-Lower

Eocene units of the shelf area (Buday, 1980) which was first described by Bellen

(1950: in Buday, 1980) from the type locality in NW Syria (Lat. 36 29 25 N,

Long.44 18 55 E) (Bellen et al., 1959). A supplementary type section has been

chosen for Iraq by Iraqi Petroleum Company (IPC) in Kirkuk-109 well at 35 33 08

N. and 44 18 55

E.

The thickness of the formation in the type area is about 100m. Higher

thicknesses were recorded in the southeastern areas of the foot hill zone only, were

the thickness amount was about 350m. The thickness is, however, rapidly increasing

towards the northeast Iraq about 470m (Jassim and Buday, 2006), where the

formation passes into a more clastic facies and interfingers with the Kolosh

Formation (Buday, 1980).On the other hand, the formation thins out towards the west

and the southwest rapidly, being only some tens of meters thick around and to the

west of the Tigris.

The formation was deposited in an off-shore, open marine environment lying

between two belts of platform margin carbonate shoals in the southwest and

northeast (ibid).

Generally, the Aaliji Formation consists of gray and light brown argillaceous

marls, marly limestones and shales with occasional microscopic fragments of chert

and rarely scattered glauconite (Bellen et al., 1959).

Silty and sandy beds occur towards the north and northeast where the

formation gradually passes into the clastic Kolosh Formation. Towards the southeast

and the west the formation is predominantly composed of limy globigerinal mud.

Chalky and argillaceous limestone beds occur where the formation passes laterally

into the Umm Er Rhadhuma Formation (Jassim and Buday, 2006).

Fossils, especially the globorotalids are abundant. The fossil contents indicate

the age of Aaliji Formation of Palaeocene-Early Eocene age (Bellen et al., 1959).

The Upper Cretaceous Shiranish Formation underlies the Aaliji Formation

uncomformably. This unconformity is marked by a complete change of fauna and

lithology. The Middle Eocene Jaddala Formation overlies the Aaliji Formation

unconformably, here again a complete change of fauna and lithology mark the

unconformity (ibid).


4

The lower contact of the formation in the type area is unconformable except

where the Aaliji occurs as tongues within the Kolosh Formation (Jassim and Buday,

2006).

1.5 Kolosh Formation:

The Kolosh Formation was first described by Dunnington (1952: in Bellen et

al., 1959) who designated a section at Kolosh, north of Koi Sanjak in the High Folded

Zone as a type area of the formation (Buday ,1980).

The Kolosh Formation thickness in the type section is about 777m at

coordination approximately 36°

50

N. and 44°

45

E.

According to Ditmar and Iraqi-Soviet team (1971: in Jassim and Buday 2006)

the type section of the formation includes part of the Sinjar Limestone Formation.

The formation according to the original description consists of shales and

sandstones composed of green rock, chert and radiolarite. In the higher parts

interfingering with the Sinjar limestone Formation occurs (Buday, 1980).

The formation was deposited in a marginal marine depositional environment in

a narrow rapidly subsiding trough. Ditmar et al. (1971: in Jassim and Buday, 2006)

considered that the Kolosh clastics were flysch. However, Seilacher (1963: in Jassim

and Buday, 2006) considered that they have the characteristics of mollase.

Bellen et al. (1959) gave the detailed succession in reverse stratigaraphical order in

the type section as follows:

1- Limestones and marls with Miscilanea miscilla (d Archaic and Haime),

ostracods ,miliolids and valvulinides about 144 meters.

2- Limestones with Dictyokathina simplex Smout, miliolids, rotalids, Lockhartia

sp. and valvulinids about 30 meters.

3- Limestones and shales, red shales and sandstone with the same fossils but

without Dictyokathina simplex smout about 133.5 meters.

4- Limestones with Saudia labyrithica Henson, Lockhartia sp., miliolids and

rotalids about 6 meters.

5- Blue shales and green sands with occasional fauna of dwarf foraminifera.

The sand grains in the Kolosh Formation are composed of green rock, chert

and radiolarite. Units (1) and (2) were reassigned by Ditmar and Iraqi-Soviet team

(1971: in Jassim and Buday, 2006) to the Sinjar limestone Formation. The

lithology of units (3) and (4) indicates that interdigitation of the Kolosh and Sinjar

Formations occurs. Interfingering of the Kolosh and Sinjar Formations has also


5

been observed in the Taq Taq wells by Ditmar and Iraqi-Soviet team (1971: in

Jassim and Buday, 2006), in the north part of Kirkuk structure by Bellen et

al.(1959),and in Darbendikhan area by Jassim et al. (1975: in Jassim and Buday,

2006).

In the upper part (Limestone interbedded) rotalides, miliolides, Daviasina sp.,

Sakesaria sp., Tabirana daviesi, valvulinerides, Miscellanea miscella, Saudia

labyrinthica, and ostracod were found (Buday, 1980).

According to the evidence of fossils the formation should be from the Palaeocene

age .The lower Eocene might be represented by the section marked by the limestone

interbeds (Buday, 1980), It is necessary, therefore, to agree with the opinion of

Ditmar et al. (1971: in Buday, 1980), that the formation is mostly Palaeocene in age

and it is bulk is older than the Sinjar Formation, Khurmala Formation, and perhaps

Aaliji Formation too.

The formation is heterogeneous and is rapidly change both horizontally and

vertically, intergrading into and interfingering with Sinjar limestone and Khurmala

Formation (Bellen et al., 1959).

The lower contact of the formation is clearly unconformable and transgressive. In

the type area the Tanjero Formation underlies the Kolosh, in other areas it is the

Shiranish Formation or some of the Upper Cretaceous limestone formations. The

clastics of the Kolosh indicate the erosion of the Tanjero-or some parts of the Qulqula

-and of other Cretaceous-Jurassic formations during the sedimentation of the Kolosh

Formation (Buday, 1980).

The upper contact of the formation is supposed to be unconformable too. This

was suggested by Bellen et al. (1959), but was, in some areas, not clearly proved.

However, there are cases where the Kolosh is covered by Palaeocene-Lower

Eocene limestone formations and the upper boundary is conformable and (as it is in

the type area) gradational too (Buday, 1980).

1.6 Jaddala Formation:

The formation represents the off-shore facies of the late Early Eocene late

Eocene sequence in the western and central areas of Iraq. It was first described by

Henson in 1940 from the type locality near Jaddala village in Jabal Sinjar of the

foothill zone at lat. 36? 18 20 N and long. 41? 41 28 E. (Jassim and Buday, 2006).


6

Bellen et al. (1959) stated that the formation in the type area comprises 350

meters of argillaceous and chalky limestones and marls, with occasional thin

intercalations of shoal Limestones (Avanah Limestones tongues). Higher thickness

might occur at the western continuation of the type area south of Jabal Sinjar.

(Buday, 1980).

The Jaddala Formation was deposited in a basin lying between two belts of

carbonate shoals on the southwest and northeast margins of the basin. The

northeast shoals were deposited on a ridge separating the basin from the platform in

which the Gercus Formation and Pila Spi Formation were deposited (Jassim and

Buday, 2006).

Bellen et al. (1959) considered that the formation is of Mid-Late Eocene age,

and that it contains reworked fossils of Early Eocene age (Jassim and Buday, 2006).

However, Poinikarov et al. (1967: in Jassim and Buday, 2006) considered that

the formation may be partly of latest Early Eocene age since it contains Globorotalia

aragonensis, which is the index fossil for the upper faunal zone of the Early Eocene.

The stratigraphic relations of the Jaddala Formation with the Dammam and

Avanah formations indicate a Late Early Eocene-Late Eocene age (Jassim and

Buday, 2006).

The Sinjar Formation underlies this formation unconformably. The

unconformity is marked by a concentration of glauconite (Bellen et al., 1959). The

formation often transgressively overlies pre-Tertiary formations, for example north of

the Euphrates river, were the Palaeocene-Early Eocene beds are either very thin (10-

20 m only) or absent (Jassim and Buday, 2006).

The Upper contact of the formation in the type area is unconformable ; the

overlying sediments are of Miocene age (Serikagni Formation) ,except in the narrow

belt passing through the Qara Chauq structure of the Foothill Zone where the

formation is overlying by the Oligocene sediments(Jassim and Buday, 2006).


7

1.7 The Study Area:

The study area includes four subsurface sections (wells) namely TT-04, KM-

3, Ja-46, and Pu-7 (Table1.2) from the four oil fields of Taq Taq, Kor Mor, Jambur,

and Pulkhana respectively in northeast Iraq (Fig. 1.1).

Table (1.2): Locations of the studied sections, number of samples, and thickness of the studied

formations in each section.

Studied

Section Locality Coordinate Formation

No. of

Samples

Thickness

m

TT-04 Taq Taq Oil

Field

35? 40' 33" N

44? 31' 30" E

Kolosh 14 183

Aaliji/Kolosh 53 525

KM-3 Kor Mor Oil

Field

35? 09' 15" N

44? 48' 15" E

Jaddala 17 218

Aaliji 14 140


Ja-46 Jambur Oil

Field

35? 09' 43" N

44? 32' 13" E

Jaddala 20 161.5

Aaliji 11 144.78

Pu-7 Pulkhana Oil

Field

34? 46' 53" N

44? 46' 15" E

Jaddala 42 336


The following is brief information about the mentioned oil fields:

1.7.1 Taq Taq Field:

Taq Taq oil field consists of a longitudinal, asymmetrical anticline of about

29km length and 11km width. The field is located 65Km north of Kirkuk City and 13

Km southwest of Koy-Sinjak Town. The structure has been discovered at the end of

1950s by IPC. Low pressure oil of about 24? API exists in the U. Eocene Pila Spi

reservoir, while light oil of about 47? API accumulates in the secondary porosities of

Shiranish, Kometan, and Qamchuqa reservoirs (IEOC, 1994).

1.7.2 Kor Mor Field:

Kor Mor Field is located about 35km southeast of Kirkuk City and consists of

an asymmetrical longitudinal anticline of about 33km length and 4km width with a

closure of 900m. The first exploration well in this field has been drilled in 1928. The

discovered gas in the field exists in the Tertiary reservoirs within the formations of

Jeribie, Euphrates, Azqand, and Ana (IEOC, 1994).

1.7.3 Jambur Field:

Jambur Field is located in the southeast of Kirkuk City on the same axis of Bai

Hassan and Khabbaz structures (Northwest-Southeast), and consists of an

asymmetrical longitudinal anticline of about 30km length and 4km width. The first


8

exploration well in this field has been drilled in 1927. Oil accumulates in the Tertiary

beds of the structure ( 39.6?API) within the formations of Jeribie (50m), Euphrates

(65m), and Jaddala (160m), and also within the Cretaceous beds of Qamchuqa

Formation (38?API, about 300m oil column and 425m gas column) (IEOC, 1994).

1.7.4 Pulkhana Field:

This field is located 50km southwest of Kirkuk City close to Jambur Field. The

structure consists of an asymmetrical longitudinal anticline of about 45km length and

8km width. The first well in this field has been drilled in 1927 (IEOC, 1994).

Accumulated oil that exists in the Euphrates/ Sarikagni reservoirs (35? API, 2.7%

sulphur) of Lower Miocene age, and within the fractures of the Upper Cretaceous

Shiranish Formation (28? API) (Beydoun, 1988).

Figure (1.1): Location map of the studied Wells.

1.8 Sampling:

A total of 207 oil well rock samples (cutting and core) from the Lower Tertiary

Formations (Aaliji, Kolosh, and Jaddala) were collected by random interval sampling

from TT-04, KM-3, Ja-46, and Pu-7 wells as shown in Table (1.2). The term Aaliji/

Kolosh Formation has been used arbitrarily in this study for those intervals which

show properties of both formations and no clear separation can be done between

them.

1 Tq-1 2 Tq-2 3 TT-04 4 KM-3 5 Ja- 25 6 Ja-46 7 Pu-7

6

7

4

5

3

1

1

2

-34?

-36?

-35?

|

41 |

43 |

44 |

42 |

45

°

°

°

°

°


9

Two oil samples have also been chosen from the two wells of Ja-25 (35? 09'

14" N, 44? 24' 53" E) at a depth of 1975m from the Lower Miocene Jeribi reservoir,

and from well Tq-2 (36? 00' 17" N, 44? 31' 14" E) at a depth of 533m-613m from the

Upper Eocene Pila Spi reservoir to be studied by GC/MS instrument.

1.9 Methodology:

Optical methods of this research included utilizing standard palynological

techniques to isolate the organic matter contents from the rock samples. The method

included treating with 10 % light HCl and concentrated HCl to dissolve carbonates

and after neutralization the residue was treated with concentrated HF acid to remove

silicates. Palynomorphs and other organic matter components were collected by

filtration using (20 µm) nylon mesh. The residue was mainly adhered on glass slides

and covered using cellosize and Canada balsam to be ready for transmitted light

microscope studies and also for Fluorescence testing which has been done in

Kurdistan Technology and Scientific Research Establishment (Sulaimani).

Part of the residual (kerogen) material which extracted during the palynological

preparation was used for Infrared (IR) test which was done in the Chemistry

department, College of Science, Sulamani University.

Some 12 polished sections were prepared from selected samples by Baseline

Resolution Inc. (Analytical Laboratories) Texas, USA, for petrographic studies, to

identify the vitrinite reflectance pattern in the studied sections. The polish sections

were examined in reflected light, measurements were made for the percentage of

incident light reflected from vitrinite particles in the samples by using a wave length of

546µm.

Analytical methods of this research included Rock-eval pyrolysis, including

Total Organic Carbon (TOC) determinations for 55 samples (core and cutting) to

ascertain the source richness, maturation and kerogen type determination in addition

to some other parameters.

The Medium Pressure Liquid Chromatography (MPLC) was done for 2 oil

samples. The isotopes carried out for 2 oil samples and 4 rock samples.

Gas-chromatography was done for 2 oil samples and 14 extracted rock

samples. The saturated and aromatic hydrocarbons were analyzed by GC/MS; data

were acquired in full-scan (m/z 191, 217, 218 and 259). The GC/MS for saturate


10

fraction made for 2 oil and 4 rock samples. The GC/MS for aromatic fraction made for

2 oil and 2 rock samples.

The above Pyrolysis and GC/MS analysis have been done in Baseline

Resolution Inc. (Analytical laboratories) Texas, USA, in addition to 10 rock samples

from TT-04 well which have been analyzed by Rock eval-6 Pyrolysis instrument

(including TOC determinations) in TPAO Research Center, Ankara, Turkey. Details

about the number of the samples and the types of testing are listed in tables (1.3

1.6).

Table (1.3): The number of samples and types of testing for Aliji/Kolosh and Kolosh

Formations in TT-4 well. Key of abbreviations: IR: Infrared, RO: Vitrinite Reflectance,

Fl.: Fluorescence, Pyro.: Pyrolysis, GC: Gas Chromatography, GC/MGas Chromatography/Mass

Spectroscopy, Satu.: Saturated, Arom.: Aromatic, EOM: Extracted Organic Matter, Iso: Isotope,

and (*): samples combined.

Formation

Depth(m)

Palynological

slide IR

RO

Fl.

Pyro.

GC

GC/MS

Satu.

GC/MS

Arom. EOM

Iso.

K

olo

sh

900 +

912 +

928 +

948 + +

956 + +

984 + +

992 + +

1008 +

1016 + +

+

1032 +

1044 +

1052 +

1064 +

1068 +

Aal

ij/K

olo

sh

1092 +

1104 +

1112 +

1120 +

1128 + +

+

1136 +

1148 +

1160 +

1178 +

1190 + +

1214 +

1218 +

1238 +

1242 +

1246 +(*)

+

+(*)

1258 + +

+

1262

+

1270 +

1282 + +

+

1290 +


11

Table 1.3 Continued

Formation Depth(m) Palyno.

slide

IR

RO

Fl.

Pyro.

GC

GC/MS

Satu.

GC/MS

Arom.

EOM

Iso.

A

aliji

/Ko

losh

1304 +

1312 +

1320 +

1324 +

1340 + +

+

1356 +

1368 +(*)

+

+(*)

1376 +

1384 +

1392 1396 +

1404 + +

1416 +

1428 +

1436 +

1392 1448 + +

+

+

+

1466 +

1478 +

1482 +

1490 +

1494

+

1498 + +

1502 +

1522 +

1546 + +

+

+

1558 +

1562 +

1566 +

1578 + +

1586 + +

+

1598

+

1606 +


12

Table (1.4): The number of samples and types of testing for Aliji/Kolosh, Aaliji,

and Jaddala Formations in KM-3 well.

Formation

Depth(m)

Palyno.

slide

IR RO Fl. Pyro.

GC

GC/MS

Satu.

GC/MS

Arom.

EOM Iso.

Ja

dd

ala

1850 +

1860 + +

1878 +

1889 + + +

1990 +

1892 +

1908 +

1940 + +

1942 +

1948 +

1969 +

1996 +

2004 + + + +

2017 +

2028 +

2037 + + +

2060 + + + + + + +

A

aliji

2064 +

2073 +

2080 +

2084 +

2089 +

2111 +

2124 +

2134 + + +

2136 +

2145 + + +

2158 +

2168 +

2172 + + +

2187 +

A

aliji

/Ko

losh

2191 +

2197 +

2201 +

2210 +

2222 +

2228 + + +

2237 +

2261 + +

2280 +

2298 +

2300 +

2303 +

2312 +

2314 +

2358 + +

2364 + + +

2370 +

2380 +

2393 + + +

2399 +


13

Table (1.5): The number of samples and type of testing for Aliji/Kolosh and

Jaddala Formations in Ja-46 well.

Formation

Depth(m)

Palyno.

slide

IR RO Fl. Pyro.

GC

GC/MS

Satu.

GC/MS

Arom.

EOM Iso. Ja

dd

ala

1620 +

1689 +

1695 + +

1714 +

1725 +

1736 + + + +

1744 +

1748 + +

1750 +

1777 +

1786 +

1793 + + +

1796 +

1804 +

1812 +

1818 + + +

1820 +

1846 + + + +

1862 + +

1864 +

Aal

iji/K

olo

sh

1870 + + +

1896 + + +

1910 + + +

1933 + + +

1961 +

1968 + + +

1982 +

1984 +

1994 +

1996 +

2017 + +


14

Table (1.6): The number of samples and the types of testing for Aliji/Kolosh and

Jaddala Formations in Pu-7 well.

Formation

Depth(m)

Palyno.

slide

IR RO Fl. Pyro.

GC

GC/MS

Satu.

GC/MS

Arom.

EOM Iso. Ja

dd

ala

1540 +

1565 +

1575 + +

+

1585 +

1590 +

1595 + +

+

1600 +

1605 +

1610 +

1615 + +

+

1620

+(*)

+

+(*)

+(*)

1625 +

1635 +

1645 +

+

1655 +

1660 +

1665 +

1680 +

1689

+(*)

+

+(*)

+(*)

1695 +

1704 +

1714

+

1721 +

1730 +

1737 +

+

1744

+

1750

+

1757 +

1758 +

1775 +

1777

+

1786 +

1792 + +

+

1796

+

1804

+

+

+ + +

1814 +

1820

+

+

+ + + +

1828 +

1840 +

1846

+

1848 +

1864 +

A

aliji

/Ko

losh

1881 +

1889 +

+

1904 +

1915 +

1928 +

1939 +

1958 +

1966 +

1971 +


15

Table 1.6 Continued

Formation

Depth(m)

Palyno.

slide

IR RO Fl. Pyro.

GC

GC/MS

Satu.

GC/MS

Arom.

EOM Iso. A

aliji

/Ko

losh

1984 + +

+

+

1989 + +

+

1992 +

1994 + +

+

1996

+

1999.60 +

2008 +

CHAPTER TWO ___________________________________________

Chapter Two Palynofacies Analysis

16

2.1 Preface:

The palynofacies concept was first introduced by Combaz (1964) to describe the

total assemblage of particulate organic matters recovered from sedimentary rocks by

palynological techniques. This practice was successfully applied to paleoenvironmental

depositional determinations and sequence stratigraphic interpretations in several sections

of the world, and particularly useful to hydrocarbon productive basins (Al- Ameri et al.,

1999; Ibrahim, 2002; Oboh-Ikuenobe and de Villiers, 2003; Dybkjaer, 2005; and Mart?nez

et al., 2005: all in Rodr?guez Brizuela et al., 2007).

Powell et al. (1990: in Tyson 1995) defined palynofacies as a distinctive

assemblage of HCl and HF insoluble particulate organic matter (palynoclast) where their

composition reflects a particular sedimentary environment. However, in many geological

studies the environment is not a known value (especially in fine-grained sediment) and it is

identification is inferred from the palynofacies data.

A relationship between palynofacies (kerogen) and genesis of hydrocarbons was

demonstrated by Staplin (1969) and Jones (1986: in Tyson 1995).

Tyson (1995) and Batten (1996b) considered that Palynofacies can help not only to

establish the depositional environment but also to determinate the hydrocarbon source

potential and assessment of thermal maturity of the host sediments.

Wood et al. (1996) mentioned that Palynofacies determinations rely on quantitative

and qualitative assessments of the textural and compositional characteristics of the total

organic assemblage.

2.2 Palynofacies applications:

Batten (1996a) used palynofacies as indicators of variations in the distance to the

shoreline. This ultimately can be related to changes in relative sea level. However,

stochastic events such as retransporting of organic matter by oceanic currents and storms,

pollen and spores transported by the wind, as well as changes in run-off and climate, can

also have an influence on the organic matter content of sediments .

Tyson (1993) applied the palynofacies technique for:-

Determination of the magnitude and location of terrigenous inputs (provenance and

proximal-distal relationships with respect to clastic sediment source).

Determining depositional polarity (onshore-offshore direction).


17

Identification of regressive transgressive trends in stratigraphic sequences and

thus depositional boundaries.

Characterization of the depositional environment in terms of: Salinity (normal or

saline lake waters, brackish "estuarine" or marine), Oxygenation and redox

conditions (strongly or moderately oxidizing oxic conditions, and strongly or

moderately reducing dysoxic to anoxic conditions), Productivity (normal or

upwelling), and Water column stability (permanently stratified, seasonally stratified,

or continuously mixed).

Characterization and empirical subdivision of sedimentologically "uniform" facies,

especially shales and other fine grained sediments.

Deriving correlations at levels below biostratigraphic resolution.

Preliminary qualitative or semi-quantitative determination of hydrocarbon source

rock potential, and qualification of bulk rock geochemical parameters.

Producing sophisticated and detailed organic facies models.

2.3 Classifications of Sedimentary Organic Matters:

Many authors, such as Staplin (1969) and Hart (1986) have classified the

sedimentary organic particles in various terms. In order to make palynofacies a cost

effective routine tool in paleoenvironmental and sequence stratigraphic investigations, a

sufficiently simple classification is required for observations in transmitted light microscopy.

Such a classification must take into account some important variables, such as the

biological origin of the constituents, their preservation state, and any significant variation in

size, morphology, or density which can affect the hydrodynamic behavior of particles

(Pittet and Gorin, 1997).

In this study, by using transmitted light microscope, the main organic matter

components, namely, Amorphous Organic Matter (AOM), Palynomorphs, Phytoclasts and

Opaque materials were recognized and classified. Identification of component groups was

made based on the classification of Pellaton and Gorin (2005). The percentage of each

component was determined to be used in Palynofacies analysis (Tables 2.1- 2.4).

The most dominated component was the Amorphous Organic Matter (AOM) with

minor amounts of Palynomorphs, Opaque Organic Matters, and Phytoclasts of different

percentages. It has been observed that most of the Palynomorphs were represented by


18

dinoflagellates and spores with some fungi and foraminiferal test lining (which is generally

of trochospiral shapes). Phytoclasts appeared to be of plant origin (cuticles and wood

debris). Most of the opaque materials were of different sizes and without domination of a

specific shape.

Table (2.1): Percentages of the different organic matter components for Aaliji/Kolosh and

Kolosh Formations in TT- 04 well.

Opaque Materials

%

Phytoclasts %

Palynomorphs%

AOM %

Depth of samples

(m) Formation

10 13 2 75 900

Ko

losh

10 25 3 63 912 10 29 3 58 928 9 32 5 54 948 10 32 2 56 956 10 31 2 57 968 8 21 2 69 984 12 14 3 71 992 10 18 5 67 1008 11 23 8 58 1016 12 15 3 70 1032 9 14 3 74 1044 10 13 4 73 1052 12 9 8 71 1068 8 22 2 68 1092

A

aliji

/Ko

losh

8 23 6 63 1112 9 35 2 54 1120 10 22 6 62 1128 10 17 5 68 1136 12 16 5 67 1148 12 12 2 74 1160 11 8 3 78 1190 10 7 5 78 1214 8 11 3 78 1218 12 10 3 75 1238 9 12 4 75 1242 12 12 0 76 1258 12 13 3 72 1270 12 10 6 72 1282 12 9 3 76 1290 10 8 5 77 1312 10 7 4 79 1324 10 5 6 79 1340 12 7 4 77 1356 9 8 2 81 1376 10 6 2 82 1384 12 7 3 78 1396 12 5 0 83 1404 12 6 2 80 1416 10 7 2 81 1428 11 4 2 83 1436 12 7 3 78 1448 10 6 6 78 1466


19

Table 2.1 Continued

Opaque Materials

%

Phytoclasts % Palynomorphs% AOM

%

Depth of samples(

m) Formation

12 6 8 74 1482

Aal

iji/K

olo

sh 10 9 3 78 1498

10 5 2 83 1502 11 5 6 78 1522 10 6 5 79 1546 11 5 8 76 1558 9 2 6 83 1566

11 7 7 75 1578 9 2 6 83 1586 9 4 9 78 1606

Table (2.2): Percentages of the different organic matter components for Aaliji/Kolosh, Aaliji

and Jaddala Formations in KM-3 well.

Opaque

Materials %


% Depth of

samples(m)

Formation

10 2 4 84 1850

Ja

dd

ala

12 1 2 85 1860 10 1 2 87 1878 9 1 4 86 1889 8 1 1 90 1892 10 2 6 82 1908 8 2 1 89 1940 8 2 1 89 1942 10 2 4 84 1969 8 1 1 90 1996 8 2 3 87 2017 10 2 0 88 2028 8 2 0 90 2037 9 3 1 87 2064

A

aliji

8 3 0 89 2073 10 3 3 84 2084 8 8 2 82 2124 8 4 5 83 2134 8 3 5 84 2136 8 4 10 78 2168 10 3 4 83 2172 10 3 2 85 2191

A

aliji

/Ko

losh

8 5 4 83 2197 8 8 3 81 2201 10 8 2 80 2210 10 6 3 81 2228 10 3 4 83 2237 12 5 2 81 2261 8 5 4 83 2298 8 6 3 83 2303 8 6 2 84 2312 8 8 3 81 2314 10 7 0 83 2358


20

Table 2.2 Continued

Table (2.3): Percentages of the different organic matter components for Aaliji and Jaddala

Formations in Ja-46 well.

Opaque Materials

%


% Depth of

samples(m)

Formation

10 8 2 80 2364 Aaliji/Kolosh

10 12 3 75 2380 10 12 3 75 2393

Opaque Materials

%


% Depth of

samples(m)

Formation

8 3 1 88 1695

Ja

dd

ala 8 1 1 90 1725

10 1 5 84 1748 8 1 1 90 1786

12 1 2 85 1793 12 1 3 84 1818 10 1 8 81 1864 10 4 5 81 1870

A

aliji

8 12 3 77 1896 8 6 3 83 1910 8 8 8 76 1933 8 5 3 84 1961 8 4 3 85 1968

10 11 3 76 1982 10 6 2 82 1994 12 2 3 83 2017


21

Table (2.4): Percentages of the different organic matter components for Aaliji/ Kolosh and

Jaddala Formations in Pu-7 well.

Opaque Materials

%


% Depth of

samples(m)

Formation

8 1 0 91 1540

Ja

dd

ala

8 1 1 90 1565 8 2 1 89 1575

10 1 2 87 1585 8 2 3 87 1590

10 2 4 84 1595 10 1 3 86 1600 10 3 8 79 1605 10 1 6 83 1610 8 1 2 89 1615 8 2 0 90 1625

10 2 2 86 1635 10 2 6 82 1645 10 1 1 88 1655 8 1 1 90 1660 8 2 5 85 1665 8 2 5 85 1695 7 2 3 88 1704

10 2 2 86 1721 10 2 2 86 1730 10 3 2 85 1737 8 3 5 84 1757

12 1 3 84 1775 9 2 6 83 1786

10 1 4 85 1792 10 8 5 77 1814 10 2 4 84 1828 10 2 5 83 1840 8 10 3 79 1848 8 10 4 78 1864

10 8 1 81 1881

A

aliji

/Ko

losh

10 5 1 84 1889 9 7 3 81 1904 8 5 4 83 1915

10 8 3 79 1928 10 7 4 79 1939 10 5 3 82 1958 10 8 5 77 1966 11 3 2 84 1971 10 2 12 76 1984 10 2 8 80 1989 8 3 9 80 1994 8 5 2 85 1999.60

10 8 0 82 2008


22

2.4 Palynofacies identification for the studied Sections:

After separating the main components of the sedimentary organic matters within

the studied samples (tables 2.5-2.8), they have been subdivided into three palynofacies

depending on the estimated percentages of the different identified components and the

lithology of the host sediments. The main properties of each palynofacies and their

distribution along the studied sections are as follows:

2.4.1 Palynofacies -1 (PF.1):

This palynofacies is characterized by a high percentage of AOM with a low

percentage of palynomorphs which is mainly comprised of dinoflagellates, few spores and

pollen with foraminiferal test lining, with a relatively high percentage of phytoclasts and

opaque materials (Table 2.5). Figure (2.1) illustrate the palynofacies-1 as they appear

under transmitted light microscope.

This palynofacies was observed in the Aaliji/Kolosh and Aaliji Formations in TT-04

between the depths (1148 m) and (1606 m), in KM-3 well from depth (2037m) to (2393 m),

in Ja-46 well from depth (1864 m) to (2017 m), and in Pu-7well between the depths (1864

m) and (2008 m) (Figs. 2.4-2.7). The lithology of Aaliji/Kolosh Formation composed of

shale, sandy shale and gray to light gray coarse grain sandstones with some pebbles.

Aaliji Formation is generally composed of gray and light brown argillaceous marls, marly

limestones and shales.

Table (2.5): The statistical analysis of the different organic matter components for palynofacies-1

2.4.2 Palynofacies- 2 (PF.2):

This palynofacies is characterized by a high percentage of AOM (but less than PF.1)

and a high percentage of phytoclasts (higher than PF.1) with a low percentage of

palynomorphs (which is mainly comprised of dinoflagellate, spore, pollen and foraminiferal

test lining), and a high percentage opaque material relative to the palynomorph content

Organic matter component

Minimum

%

Maximum

%

Mean

%

AOM 72 89 80.12

Palynomorphs 0.0 12 3.7

Phytoclasts 2 13 6.49

Opaque materials 8 12 9.83


23

(Table 2.7). Figure (2.2) illustrate the palynofacies-2 as they appear under transmitted light

microscope.

This palynofacies appears in the Kolosh Formation from the depth of (900m) to

(1092m) and in the upper part Aaliji/Kolosh Formation to the depth of (1148m) in TT-04

(Fig.2.4). The lithology of Kolosh Formation is generally composed of marly Limestones,

with blue shales and green sands.

Table (2.6): The Statistical analysis of the different organic matter components for palynofacies-2

2.4.3 Palynofacies -3 (PF.3):

This Palynofacies is characterized by high percentage of AOM, and a few

palynomorphs (comprised mainly of dinoflagellates, few spores, pollen and foraminiferal

test lining), with a low percentage of phytoclast and opaque materials (Table 2.7). Figure

(2.3) illustrate the palynofacies-3 as they appear under transmitted light microscope.

This palynofacies has been recorded within the whole Jaddala Formation in KM-3

well from the depth of (1850m) to (2037m), in Ja-46 well from the depth of (1695m) to

(1864m), and in Pu-7well between the depths (1540m) and (1864m) (Figs.2.5-2.7).The

lithology of Jaddala Formation is typically composed of argillaceous and chalky limestones

and marls, with occasional thin intercalations of limestones.

Table (2.7): The statistical analysis of the different organic matter components for palynofacies-3


Minimum

%

Maximum

%

Mean

%

AOM 77 91 85

Palynomorphs 0.0 8 2.69




Minimum

%

Maximum

%

Mean

%

AOM 54 75 65.31

Palynomorphs 2 8 4.05




24

Figure (2.3): Palynofacies-3, Jaddala Formation, Depth (1615m), Section

Pu-7, Slide No. (10), X. (100).

Figure (2.2): Palynofacies-2, Kolosh Formation, Depth (968 m), Section TT-04, Slide No. (6), X. (100).

Figure (2.1): Palynofacies-1, Aaliji Formation, Depth (2064 m), Section KM-3, Slide No. (14), X. (100).


25

Figure (2.4): Percentages of different organic matter components and the identified palynofacies

for Aaliji/Kolosh and Kolosh Formations in TT-04 well.

100.0 20 30 40 50 60 70 80 90 100%

Ep

och

Fo

rmat

ion

Lit

ho

log

y

Pal

yn

ofa

cies

Dep

th(m

)

900

925

950

975

1000

1025

1050

1075

1100

1125

1175

1200

1250

1275

1300

1150

1225

1325

Pal

aeo

cen

eA

aliji

/Ko

losh

1350

1375

1400

1425

1450

Ko

losh

AOMPalynomorphs

PhytoclastsOpaquematerials

1475

1500

1525

1550

1575

1600

Pal

ynof

acie

s.2

Pal

ynof

acie

s.1

MarlyLimestone

Sandstone

Intervening ofsand and

Limestone

Shale

Limestone


26


for Aaliji/Kolosh , Aaliji, and Jaddal Formations in KM-3 well.

Sandstone

Shale

Intervening of sandstone and

LimestoneMarly

Limestone

Limestone

Marl

ArgillaceousLimestone

100.0 20 30 40 50 60 70 80 90 100%

Ep

och

Fo

rmat

ion

Lit

ho

log

y

Pal

yno

faci

es

Dep

th(m

)

1850

1875

1900

1925

1950

1975

2000

2025

2050

2075

2125

2150

2200

2225

2250

2100

2175

2275

Pal

aeo

cen

eJa

dd

ala

Aal

iji/K

olo

sh

2300

2325

2350

2375

2400

2046

2186

Aal

iji

Pal

yno

faci

es.3

Pal

yno

faci

es.1

AOMPalynomorphs


Eo

cen

e


27


for Aaliji and Jaddala Formations in Ja-46 well.

100.0 20 30 40 50 60 70 80 90 100%

Ep

och

Fo

rmat

ion

Lit

ho

logy

Pal

yno

faci

es

Dep

th(m

)

1690

1710

1730

1750

1770

1790

1810

1830

1850

1870

1910

1930

1970

1990

2010

1890

1950

1864

Eo

cen

eP

alae

oce

ne

Jad

dal

aA

aliji

Pal

yno

faci

es.3

Pal

yno

faci

es.1

AOMPalynomorphs


Sandstone

Interveningof sand andLimestone

Shale

Marl

Argillaceouslimestone


28


for Aaliji/Kolosh and Jaddala Formations in Pu-7 well.

Sandstone

Interveningof sand andlimestone

Shale

Marl

Argillaceouslimestone

100.0 20 30 40 50 60 70 80 90 100%Ep

och

For

mat

ion

Lit

ho

log

y

Pal

yno

faci

es

Dep

th(m

)

1540

Eo

cene

Pal

aeo

cen

e

Jad

dal

aA

aliji

/Ko

losh

1575

1600

1625

1650

1675

1700

1725

1750

1775

1825

1850

1900

1925

1950

1800

1875

1975

2000

1874

Pal

ynof

acie

s.1

Pal

ynof

acie

s.3

AOMPalynomorphs



29

2.5 Palynofacies analysis:

Tyson (1995) defined palynofacies analysis as a palynological study of

depositional environment and hydrocarbon source rock potential based upon the total

assemblage of particulate organic matter.

Palynofacies analysis evaluates the total microscopic particulate organic-matter

assemblage within a sedimentary rock following the chemical breakdown and removal of

any carbonate and siliciclastic mineral constituents. The remaining HF and HCl insoluble

organic matter provides valuable information about the sedimentary facies,

paleoenvironment, and source rock potential, including the relative importance and

distance from terrestrial source areas, depositional energy, and basin redox conditions.

Previous palynofacies studies have shown that palynofacies variations exhibit a marked

correlation with proximal-distal gradients in facies, and thus also with sequence

stratigraphy (Frank and Tyson, 1995; Tyson, 1996, and Tyson et al, 2000: all in Buckley

and Tyson, 2003).

Tyson (1993, 1995) provided a ternary diagram which is very effective and geologically

it is a familiar means of presenting percentage data for real populations or artificial

groupings with three components. The main advantage of this ternary diagram is that the

data plots with a spatial separation that is useful for grouping samples into empirically

defined associations and kerogen assemblages.

This plot can pick out the differences in relative proximity to terrestrial organic

matter sources 'kerogen transport path' and the redox status of the depositional sub

environments that control amorphous organic matter preservation. There are a lot of

ternaries comparable to that of Tyson (1993 and 1995) with similar or different organic

matter components. As an example; (The ternary of Microplankton, Spore- Pollen; and

Palynomorph plot by Federova, 1977; Duringer and Dubinger,1985 and Traverse ,1988:

all in Tyson ,1995) to indicate onshore-offshore depositional environments and

transgressive-regressive trends. There is also the ternary composed of Alginite +

Amorphous, Herbaceous + Pollen + Spores, and Woody- Coaly which proposed by

Shimazaki (1986: in Omura and Hoyanagi, 2004) from which the fluvial, estuarine,

prodeltaic, shelf, sub marine fan and basin floor sediments can be identified and

distinguished.


30

In this study, the APP ternary of Tyson (1995) has been chosen to determine the

paleodepositional environment of the identified palynofacies.

After plotting the organic matter components (AOM, Palynomorphs, and

Phytoclasts+ Opeque materials) from Tables (2.1-2.4) to Tyson s ternary as shown in the

figures (2.8- 2.11). The following results have been obtained:

1. The three identified palynofacies were located within the field IX of the ternary

which is known as distal suboxic-anoxic basin, and only part of the P.F2 extends

to the field VI which is known as proximal suboxic-anoxic shelf.

2. PF.3 represents the deepest environment of deposition among the three identified

palynofacies, then PF.1 and PF.2 respectively.

3. The depositional environment of the Aaliji/Kolosh, Aaliji, and Jaddala Formations

(PF.1 and PF.3) is characterized by dominated assemblages of AOM with low

abundance of palynomorphs partly due to masking and frequently alginite- rich.

And they were deposited in deep basin or stratified Shelf Sea and their sediments

may represent starved basins.

4. The upper studied part of Kolosh Formation in TT-04 (PF.2) is extended from

distal suboxic-anoxic basin towards proximal suboxic-anoxic shelf which is

characterized by high dominated AOM preservation due to reducing conditions

with characteristic phytoclast content may be moderate to high due to turbiditic

input and/or general proximity to source.

5. From Tyson (1993,1995) ternary diagram, the field of IX is characterized by low

Prasinophytes (of organic plankton) often dominant which can interpret that

Aaliji/Kolosh, Aaliji, and Jaddala Formations {according to Tyson (1995)s

standard kerogen and palynomorph parameters which commonly used in

paleodepositional environment} were deposited under the stable stratified water

masses with low in situ production of cyst-forming dinoflagellates, and low

redeposition of dinocysts from adjacent shelf areas, also the high percentage of

AOM show that these formations were deposited under reducing conditions (at

least temporarily dysoxic to anoxic) with high preservation of authochthonous

planktonic organic matter.

6. The field (VI) which is characterized by low to common dinocysts dominant

means that the Kolosh Formation is partly deposited at the area of productivity


31

(e.g. hydrographic estuarine or shelf fronts or coastal upwelling areas) also the large

magnitude and size of phytoclasts in the Kolosh Formation generally at close

proximity to, or redeposit from fluvio-daltaic source of terrestrial organic matter,

resulting in dilution of other components, or oxidizing environment in which other

components were destroyed, and usually low ,with high percents of small opaque

materials, especially during high sea level. Due to hydrodynamic equivalence

characterized by high sandy and silty sediments.

7. The existed kerogen in the three identified palynofacies were expected to be type

II and I (II>I) which is highly oil prone, but some samples of palynofacies-2 (field

VI) appeared to be containing only kerogen type II which is less oil prone.

Figure (2.12) shows a lateral correlation between the identified palynofacies in the studied

sections of TT-04, KM-3, Ja-46, and Pu-7.

Figure (2.8): APP ternary diagram of Tyson (1993) for determining the depositional environments of the studied samples from palynofacies-1(Aaliji/Kolosh Formation) and Palynofacies-2 (Kolosh Formation) in TT-04 well.

Proximity to fluvial sources plus sorting

Redox plus masking effectAOM 60 35

VIIIA

E

IXD

VII V

Palynomorphs

55

CB

40VI

IVb

IVa D

BIII E

65

IIC

Phytoclasts

10AB

I

Redo

x pl

us p

roxi

mity

to fl

uvia

l sou

rces

Palynofacies.1Palynofacies.2


32

Figure (2.9): APP ternary diagram of Tyson (1993) for determining the depositional environments of the studied samples from palynofacies-1(Aaliji/Kolosh and Aliji Formations) and palynofacies-3 (Jaddala Formation) in KM-3 well.

Figure (2.10): APP ternary diagram of Tyson (1993) for determining the depositional environments of the studied samples from Palynofacies-1(Aliji/Kolosh Formation) and palynofacies-3 (Jaddala Formation) in Ja-46 well.



VIIIA

E

IX DVII V

Palynomorphs

55

CB

40VI

IVb

IVa D

BIII E

65

IIC

Phytoclasts

10AB

I

Redo

x pl

us p

roxi

mity

to fl

uvia

l sou

rces



VIIIA

E

IX DVII V

Palynomorphs

55

CB

40VI

IVb

IVa D

BIII E

65

IIC

Phytoclasts

10AB

I

Redo

x pl

us p

roxi

mity

to fl

uvia

l sou

rces




33

Figure (2.11): APP ternary diagram of Tyson (1993) for determining the depositional environments of the studied samples from Palynofacies-1(Aliji/Kolosh Formation) and palynofacies-3 (Jaddala Formation) in Pu-7 well.



VIIIA

E

IX DVII V

Palynomorphs

55

CB

40VI

IVb

IVa D

BIII E

65

IIC

Phytoclasts

10AB

I

Redo

x pl

us p

roxi

mity

to fl

uvia

l sou

rces



34

NW SE

Figure (2.12): A cross section shows correlation between the identified palynofacies within the studied sections. (No horizontal scale)

Form

atio

n

Lith

olog

y

Paly

nofa

cies

Dep

th (m)

1690

1710

1730

1750

1770

1790

1810

1830

1850

1870

1910

1930

1970

1990

2010

1890

1950

1864

Jadd

ala

Aal

iji

Form

atio

n

Lith

olog

y

Paly

nofa

cies

Dep

th (m)

1540

Jadd

ala

Aal

iji/K

olos

h

1575

1600

1625

1650

1675

1700

1725

1750

1775

1825

1850

1900

1925

1950

1800

1875

1975

2000

1874

Form

atio

n

Lith

olog

y

Paly

nofa

cies

Dep

th (m)

900

925

950

975

1000

1025

1050

1075

1100

1125

1175

1200

1250

1275

1300

1150

1225

1325

Aal

iji/K

olos

h

1350

1375

1400

14251450

Kol

osh

1475

1500

1525

15501575

1600

Paly

nofa

cies

.3Pa

lyno

faci

es.1

Paly

nofa

cies

.1Pa

lyno

faci

es.3

Paly

nofa

cies

.2Pa

lyno

faci

es.1

Datum line(Shiranish-Aaliji/kolosh and Shiranish-Aaliji contacts)TT-04 Ja-46 Pu-7

Form

atio

n

Lith

olog

y

Paly

nofa

cies

Dep

th (m)

1850

1875

1900

1925

1950

1975

2000

2025

2050

2075

2125

2150

2200

2225

2250

2100

2175

2275

Jadd

ala

Aal

iji/K

olos

h

230023252350

23752400

2046

2186

Aaj

iji

Paly

nofa

cies

.3Pa

lyno

faci

es.1

KM-32024 2050

SandstoneInterveninigof sandandLimestone

ShaleMarl Argillaceouslimestone

MarlyLimestone

Limestone

CHAPTER THREE ___________________________________________

tionObservaOptical Chapter Three

3.1 Preface:

There is a tendency among the geologists and geochemists to rely more on

chemical and physical parameters which are more standardized than on current optical

descriptions. However, many of those scientists realize that only visual examinations of

the organic matter may help unravel the complex chemical properties or may provide

clues to the paleodepositional environment of the sediments (Thompson-Rizer, 1993).

Microscopic methods of kerogen typing have potential advantages over chemical

methods in being capable of providing semi-quantitative data on all the components

contributing to the organic matter (i.e., kerogen, solid bitumen) in a single sample

(Whelan and Thompson-Rizer, 1993).

One can observe from the organic matter that were incorporated into a rock, the

abundance of these kinds of organic matter, the level of maturation or thermal history of

the rock, and possibly some clues to the environment of deposition by visually studying

the kerogen(Staplin, 1969).

Visual kerogen analyses are commonly done by microscopically examining, in

transmitted light, strew, smear, or palynological slides. The visually determined

proportions of different kerogen types can be used in conjugation with geochemical

analyses (Total Organic Carbon, Pyrolysis-Gas Chromatography, Elemental Analysis,

Vitrinite Reflectance, etc.) to better interpret the generating potential of source rocks

(Thompson and Dembicki, 1986).

One of the reasons for a lack of standardized nomenclature in describing kerogen

visually is the fact that a variety of sample preparations and microscope lighting

conditions are being used for the optical study of kerogen. Often, workers are trying to

describe the same material, which looks vastly different in thin section in transmitted

light compared to the concentrated form in reflected white light (Whelan and Thompson-

Rizer, 1993).

3.2 Maturation of Organic Matters:

Maturation is a digenetic process during which organic matter undergoes two

types of change: mobile products (gas, liquid) are given off, and condensation of the

solid residual products takes place due to their aromatization. (Taylor et al., 1998)


Radke et al. (1997) defined the maturation as a technical term commonly used in

petroleum geochemistry to address thermally induced changes in the nature of organic

matter during catagenesis. It may refer to the entire source rock, which is said to gain

maturity when heated sufficiently. Maturation summarizes kerogen conversion

processes including petroleum generation.

Tissot and Welte (1984) in general terms described the organic matter maturity

as: immature, mature or post mature, depending on it is relation to the oil generative

window. Immature organic matter has been affected by diagenesis, including biological,

physical, and chemical alteration, but without a pronounced effect of temperature.

During thermal maturation or catagenesis, all kerogen types lose hydrogen as

well as oxygen including functional groups (Whelan and Thompson-Rizer, 1993).

It has been shown experimentally that all kerogen types initially expel hydrogen

and oxygen predominantly as water and carbon dioxide during the lower temperature

(diagenetic stage) of the maturation and via hydrocarbon loss (oil and gas generation)

during the higher temperature catagenetic maturation stages (Tissot and Welte, 1984).

Two types of thermal maturity parameters exist as mentioned by (Peters et al.,

2005):

1. Generation or conversion parameters used as indices of the stage of petroleum

generation (independent on the magnitude of thermal stress).

2. Thermal stress parameters used to describe relative effects of temperature/time.

For example, two rocks containing different types of kerogen might generate

equivalent amounts of oil at a given atomic hydrogen/carbon ratio, but the vitrinite

reflectance of the samples may differ.

Conventional geochemical methods used to assess source-rock maturity include

Rock-Eval pyrolysis, Vitrinite Reflectance (Ro), Thermal Alteration Index (TAI), Spore

Color Index (SCI), and Carbon Preference Index (CPI) (Peters et al., 2005).

3.2.1 Thermal Alteration Index (TAI):

As temperature represents a key parameter in hydrocarbon generation,

reconstructing the thermal history of sediments is a critical task in applied geosciences.

The color of certain types of organic matter changes predictably with increased

heat from almost colorless or yellow through brown to black. During this transformation

hydrocarbons are generated. These color changes, as observed under the microscope


using transmitted light, can be used to construct a Thermal Alteration Index (TAI), as

reported by Staplin (1969).

The analysis of Palynomorphs to determine thermal alteration has the advantage

that only a few grams of the sample material and a standard light microscope are

required.

Specific color changes in organic material consistently accompany the chemical

reactions leading to hydrocarbon generation (Bujak et al., 1977).

The chemical transformations are manifested optically as a color change in fossil

palynomorphs ranging from yellowish green for immature rocks, through yellow and

orange for more mature rocks, to various shades of brown for over mature rocks,

eventually becoming black and opaque, and unidentifiable at high thermal maturities

(Mao et al., 1994).

Pross et al. (2007) also mentioned the commonly used qualitative scales as follows:

(1) The Etat de Conservation Index of Correia (1967, 1971) and Correia and

Peniguel (1975).A 1 6 scale for different palynofacies constituents including

sporomorphs, dinoflagellate cysts, acritarchs, chitinozoans, and plant debris.

(2) The Thermal Alteration Index (TAI) of Staplin (1969, 1982), ranging from 1 to 5

and based on spores, cuticles, and amorphous sapropelic debris.

(3) The Spore Coloration Index of Robertson Research Group (Haseldonckx, 1979;

Barnard et al., 1980), ranging from 1 to 10.

(4) The Spore Coloration Index of Batten (1980, 1982), ranging from 1 to 7. To

increase the consistency and reproducibility of spore coloration data, Pearson

(1982, 1984) published a color chart based on ten defined colors with Munsell

reference numbers that related to the TAI scale of Staplin (1969).

In an effort to provide quantitative scales comparable in precision and reproducibility

to that of vitrinite reflectance, quantitative approaches based on the measurement of the

translucency of sporomorphs using a photometric unit, have been developed. (Pross et

al., 2007)


3.2.2 Evaluating Maturity by TAI:

The optical assessment of the studied samples was done by observing the color

change of the palynomorphs due to the effect of temperature and that for evaluating the

maturation stage of Aaliji/Kolosh, Aaliji, Kolosh, and Jaddala Formations in the studied

wells.

To assess the real TAI evaluating of the studied samples, a specified species of

dinoflagellate of longest range of appearance has been chosen to show the result of

temperature effect on its color changes. The chosen dinoflagellate species was

Operculodinium sp. due to it is longest appearance in addition to its existence in the four

studied sections (Figs.3.1- 3.3).

In this study, the TAI values for the studied slides have been determined using

transmitted light microscopy and according to the TAI scale proposed by Philips

Petroleum Company of Pearson (1990). A comparison has been done also with other

scales proposed by a number of authors like: Cardott and Lambert (1985: in Mao et al.,

1994) and Hao and Mao (1989: in Mao et al., 1994).

The results were as follows:

The color changes of the studied palynomorphs ranged from orange (2 TAI) (Fig.

3.1) to dark yellow (2+ TAI) (Fig. 3.2) to light yellowish brown (3- TAI) (Fig. 3.3)

indicating that the organic matters within the studied samples were not subjected

to paleotemperatures higher than 96°C (according to Mao et al.,1994

paleotemperature scale)

Aaliji / Kolosh Formation in TT-04 (from depth1112 to1466m) appeared to have

entered the maturity zone as they show dark yellow color palynomorphs (2+ TAI)

from the depth(1112 to 1242m) and light yellowish brown color palynomorphs (3-

TAI) in the deeper part of the section till the depth 1466m, while the rest of the

shallower studied part of the section (900 to less than 1112m) observed to be still

immature since the color of the used palynomorphs was orange (2 TAI).

Aaliji/Kolosh and Aaliji Formations in the other studied sections are generally still

thermally immature although they show indications to be very close to maturity.

Wherever Jaddala Formation appeared in the studied sections showed

palynomorphs of orange color (2 TAI) indicating immature source rocks especially

in Pu-7 section between depths 1540m and 1590m.


Figure (3.1): Dinoflagellate species

Operculodinium sp.

as an indicator of maturity (TAI 2), Aaliji Formation,

Depth (2136m), Well (KM-3), Slide No. (19), X. (400).


Operculodinium sp.

as an indicator of maturity (TAI 2+), Aaliji/Kolosh

Formation, Depth (1112m), Well (TT-04), Slide No. (16), X.

(400).


Operculodinium sp.

as an indicator of maturity (TAI 3-), Aaliji/Kolosh

Formation, Depth (1416m), Well (TT-04), Slide No. (39), X.

(400).


3.3 Amorphous Kerogen:

Two major groups of kerogen particles can be easily distinguished with an optical

microscope: those with definite shapes or structures, often very similar to modern plant

tissues; and those without distinct shapes or structures, which can not be related to

modern tissues or the structured kerogens. The shapeless particles have traditionally

been given the name amorphous kerogen (Thompson and Dembicki, 1986).

Amorphous organic matter is debris without recognizable shape or internal

structure. It consists mainly of fluffy masses of various colors and fluorescences and

usually comprises partially decomposed organic material mainly of marine

phytoplankton origin. It is usually rapidly degraded in oxic environments and therefore is

indicative of low oxygen conditions such as exist in distal, dysoxic to anoxic, and

eutropic settings and where there is little mixing of the water column (Waterhouse,

1996).

Pocock et al. (1988) divided amorphous organic martial into two types: (A)

Amorphous matter of pale yellow to deep amber color more or less translucent, resulting

from aerobic bacterial activity. (B) Materials of a natural gray to dark brown color,

generally somewhat less transparent, formed by the action of anaerobic (reducing)

bacteria.

Some workers have tried to understand the optical - chemical relationship of

amorphous kerogen. Powell et al. (1982: in Thompson and Dimbicki, 1986) attempted to

optically distinguish hydrogen - rich and hydrogen - poor amorphous kerogen in source

rock samples depending on geochemical analyses (extraction, pristine/ phytane, atomic

H/C). They were, however, unable to show a correlation because the genetic description

(algal/ microbial or terrestrial) and the quantity of the amorphous material did not

sufficiently distinguish the different kinds of amorphous kerogen.

In this study, the optical classification of AOM proposed by Thompson and

Dimbicki (1986) has been chosen to distinguish between the different types of AOM and

for evaluating the quality of the existed organic matters within the studied sections.

Thompson and Dimbicki (1986) optically distinguished four different types of

amorphous kerogen according to the textural differences using transmitted microscopy,

reflected, and fluorescence lights as clarified in table (3.1) in addition to the analysis by

Infrared instrument. They explained the appearance of those four types of AOM under


microscopes and clarified their ability to hydrocarbon generation in terms of oil-prone or

gas-prone amorphous kerogens.

Geochemically defined oil- prone samples are generally supposed to

contain types A and /or D separately or combined, while gas-prone samples are

supposed to contain type A, and vary in amounts of types B, C and /or D.

The figures 3.4 - 3.7 show four types of the AOM (A, B, C, and D) which

optically distinguished from the four studied sections under the transmitted light.

The results of the optically examined AOM in the four studied sections showed

dominant of type A with some contribution from types B, C, and D (Tables 3.2-3.5)

According to Thompson and Dembiki (1986) the existed organic matters within

Aaliji/Kolosh, Aaliji, and Jaddala Formations are generally mixed of oil and gas-prone in

KM-3, Ja-46 and Pu-7, while the Aaliji/Kolosh and Kolosh Formations in TT-04 appeared

to be more gas- prone rather than oil-prone.

Table (3.1): Amorphous Kerogen Types as described optically by Thompson and Dembicki (1986).

(*) Textural descriptions derived from viewing the sample with all three microscope lighting

conditions with 400x magnification, oil immersion.

(**) Transmitted light .

(***) Reflected light .

(****) Fluorescence light or incident blue light.

Type

Texture (*) TL(**) RL(***) FL(****)

A Chunky compact masses (approximately20-300 microns) with weak polygonal, Mottled, interconnected network textures

Red brown

Brown to grey

Patches or flecks of yellow to yellow grey

to none

B Small, dense, elongated, oval to rounded Individual grains (approximately 10-20 Microns)

Dark brown to

black

Brown to grey None

C Dense clumps (approximately 50 - 300 microns) with granular, fragmented or globular textures

Dark brown Grey None

D Thin , rectangular or platy individual Grains (approximately 10 microns) Light

brown Brownish-

grey

Some yellow patches or

Flecks to none


Figure (3.4): Amorphous Organic Matter (Type A), Aaliji/Kolosh Formation, Depth (1128m), (TT-04),

Slide No. (18), (400X).

Figure (3.5): Amorphous Organic Matter (Type B), Aaliji/Kolosh Formation, Depth (2364m), (KM-3),

Slide No. (34), X. (400).

Figure (3.6): Amorphous Organic Matter (Type C), Kolosh Formation, Depth (992m), (TT-04), Slide

No. (2), X. (400).

Figure (3.7): Amorphous Organic Matter (Type D), Jaddala Formation, Depth (1792m), (Pu-7),

Slide No. (25), X. (400).


Table (3.2): Types of AOM (according to Thompson and Dembicki, 1986) in TT-04 well.

Formation

Depth

m.

Type of

AOM

Formation

Depth

m.

Type of

AOM

Ko

losh

900 B+C

Aal

iji/K

olo

sh

1270 A

912 B+C 1282 A

928 A+B 1290 A

948 A 1312 A

956 A 1324 A

984 A 1340 A

992 B+C 1356 A

1008 A 1376 A+B

1016 A 1384 B

1032 B+C 1396 B

1044 B+C 1404 B

1052 A 1416 A

1068 A 1428 A

1092 A 1436 A

Aal

iji/K

olo

sh

1112 A 1448 A

1120 A 1466 A+B

1128 A 1482 A+B

1136 A+B 1498 A+B

1148 A+B 1502 A+B

1160 A+B 1522 A+B

1190 A 1546 B

1214 A 1558 B

1218 A 1566 A

1238 A 1578 A

1242 A 1586 B

1258 B 1606 A


Table (3.3): Types of AOM (according to Thompson and Dembicki, 1986) in KM-3 well.

Formation Depth

m.

Type of

AOM Formation

Depth

m.

Type of

AOM

Ja

dd

ala

1850 A+B

Aal

iji 2134 A+B

1860 A+B 2136 A 1878 A+B 2168 A+B

1889 A+B 2172 A

1892 A+B

Aal

iji/K

olo

sh

2191 A+B 1908 A+B 2197 A+B 1940 A+D 2201 A+B 1942 A+D 2210 A 1969 A+D 2228 A 1996 A+D 2237 A 2017 A+D 2261 A+B 2028 A+D 2298 A+B 2037 A+D 2303 A+B 2064 A 2312 A+B 2073 A 2314 A+B 2084 A 2358 A+B 2124 A+B 2364 B

2134 A+B 2380 B

1850 A+B 2393 B

1860 A+B 2191 A+B 1878 A+B 2197 A+B 1889 A+B 2201 A+B

1892 A+B 2210 A 1908 A+B 2228 A 1940 A+D 2237 A 1942 A+D 2261 A+B 1969 A+D 2298 A+B 1996 A+D 2303 A+B 2017 A+D 2312 A+B 2028 A+D 2314 A+B 2037 A+D 2358 A+B 2064 A 2364 B

2073 A 2380 B

Aaliji

2084 A 2393 B

2124 A+B


Table (3.4): Types of AOM (according to Thompson and Dembicki, 1986) in Ja-46 well.

Formation Depth

m.

Type of AOM

Jad

dal

a

1695 A+B

1725 A+B

1748 A+B

1786 A

1793 A

1818 A

1864 A+B

Aal

iji

1870 A

1896 A

1910 A+B

1933 A

1961 A+B

1968 B

1982 A+B

1994 A+B

2017 A+B


Table (3.5): Types of AOM (according to Thompson and Dembicki, 1986) in Pu-7 well.

3.4 Fluorescence microscopy:

The absorption of ultraviolet or visible light by organic matter causes the excitation

of an electron from its initial low energy orbital in the ground singlet state to a high-

energy orbital in the excited singlet state. The excited molecule is subject to collision

with surrounding molecules giving up a small fraction of energy via radiation less decay

to the vibration of molecules. The molecule, after the electron steps down to the lowest

vibration level of the excited singlet state, commonly undergoes spontaneous emission

and emit is it is excess energy as fluorescence. (Huang and Otten, 1998)

Fluorescence emission occurs at a lower frequency than the incident light. The

frequency difference, and therefore the spectrum, depend on the structural

Formation Depth

m.

Type of

AOM Formation

Depth

m.

Type of

AOM

Ja

dd

ala

1540 A+D

Jad

dal

a

1775 A+D

1565 A+D 1786 A+D

1575 D 1792 D

1585 D 1814 D

1590 A+D 1828 D

1595 D 1840 A+D

1600 A+D 1848 A+D

1605 A 1864 A+D

1610 A

Aal

iji/K

olo

sh

1881 A+B

1615 A 1889 A+B

1625 A+B 1904 A+B

1635 A+B 1915 A+B

1645 A+B 1928 A

1655 A+D 1939 A

1660 A+D 1958 A+B

1665 A+D 1966 A+B

1695 A+D 1971 A+B

1704 A+D 1984 A

1721 A 1989 A

1730 A 1994 A

1737 A 1999.60 A+B

1757 A+D 2008 A+B


O R I G I N G R O U P C O N S T I T U E N T

H ig h e rP la n t

D e b r isP h y to c la s t s

P o l le n & s p o r e s S p o r o m o r p h s

F r e s h w a te r a lg a eD e g r a d e d

P la n t d e b r i sD e g r a d e d

P h y to p la n k to n

A m o r p h o u sO r g a n ic

M a t t e r ( A O M )

M a r in e P h y to p la n k to n

F o r a m in i f e r a F o r a m in i f e r a lt e s t l i n in g

D in o f la g e l la t e c y c t s &a c r i ta c h s

O th e r m a r in e a lg a e

N o n - f lu o r e s c e n c tA O M

P e d ia s t r u m B o tr y c o c c u s

N o n - s a c c a te sB is a c c a te s

C u t i c u le ( P M 3 )

S e m i - O p a q u e ( P M 1 )T r a n s lu c e n t ( P M 2 )

O p a q u e( P M 4 )

E q u id im e n s .

L a th - s h p e d .

f lu o r e s c e n c tA O M

CO

NT

INE

NT

AL

( all

ocht

h on o

u s)

Mar

in

(aut

och t

h on o

us)

P R E S E R V A T I O N P O T E N T I A L

lo w h ig h

characteristics of the excited and lower electronic states of the molecule. Fluorescence

spectroscopy is a widely used method in the chemical analysis of molecular structure

and dynamics (Huang and Otten, 1998)

Whitker (1984); Tyson (1987); Steffen and Gorin (1993); Wood and Gorin (1998);

and Bombardiere and Gorin (2000): all in Pellaton and Gorin(2005) distinguished

fluorescent from non-fluorescent marine AOM and terrestrial non-fluorescent AOM.

According to the classification of Pellaton and Groin (2005) (Fig.3.8) all of the

AOM matters within Aaliji/Kolosh, Aaliji, and Jaddala Formations belong to marine

(autochthonous) which are derived from degradation of phytoplankton in the four studied

sections as they show non-fluorescent under the ultraviolet light, with the exception of

the upper part of the Aaliji/Kolosh and Kolosh Formations in TT-04 which appear to be of

low-fluorescent to non-fluorescent indicating that the AOM in the upper part of the

Aaliji/Kolosh and Kolosh Formations are of both marine (autochthonous) origin derived

from degradation of phytoplankton and also of continental (allochthonous) origin derived

from degradation of plant debris.

According to the Pellaton and Gorin (2005)s diagram the preservation potential of

the organic matters in Aaliji/Kolosh, Aaliji, and Jaddala Formations in TT-04, KM-3, Ja-

46, and Pu-7 were expected to be low to moderate as they mainly comprise of AOM and

marine phytoplankton (Dinoflagillates and other marine algae) and foraminiferal test

lining. The examined organic matters in the studied palynological slides appeared to be

relatively well preserved or non degraded which means that they did not subjected to

effective diagenetic processes.

Figure (3.8): Classification of palynofacies constituents, {after Pellaton and Gorin(2005) with

modification from Steffen and Gorin(1993)and preservation potential derived from

Bombardiere and Gorin(1998)}


3.5 Infrared Spectroscopy:

The infrared technique allows an evaluation of the relative importance of carbonyl

and/or carboxyl groups versus aliphatic chains plus saturated rings, providing

information about the occurrence and abundance of the various functional groups in

kerogen, and also paraffinicity or aromaticity; and in particular the absorption bands

provide a comparative evaluation of the petroleum potential of different source rocks.

This evaluation is based on the respective intensity of the absorption bands related to

aliphatic CH2, CH3 groups (source of hydrocarbons) and to polyaroamtic nuclei (inert

part of kerogen) (Tissot and Welte, 1984).

Both the aliphatic C H and carbonyl absorption intensities decrease with

increasing maturation (Whelan and Thompson-Rizer, 1993).

If atoms in molecules are considered to be tiny balls on the end of springs which

represent chemical bonds, then absorption of infrared (IR) radiation occurs as a result of

the discrete amounts of energy (corresponding to specific frequencies of light) required

to stretch or bend these bonds. Therefore, the absorption frequencies for specific

molecules obtained from infrared spectroscopy provide organic structural information

about the presence of specific bond types and functional groups (ibid).

The technique gives valuable information about both kerogen type and maturity

when used together with other data, and can provide a quantitative measure of specific

bond types and functional groups, especially those of aliphatic and aromatic C H

bonds (in the range of 3100-2900 cm-1), C=O groups (in the range of 1800-1650 cm-1),

and O H and N H groups (in the range of 3600-3200 cm-1) (ibid).

In this study an infrared spectroscopy analysis was done for 38 samples (Fig.3.9)

and their spectrographs were compared with typical infrared spectra of the four types of

AOM which proposed by Thompson and Dembicki, (1986) (Fig.3.10) for checking the

optically identified AOM types.

From the output spectrographs the intensity of distinct peaks at 2860 cm-1 and

2930 cm-1 (CH2 and CH3 aliphatic groups), at 1710 cm-1 (Carboxyl and Carbonyl

groups), and at 1630 cm-1 (aromatic C=C bonds) have been measured to calculate A

and C Factors proposed by Ganz and Kalkreuth (1987a) (Tables 3.6-3.9).


TT-04 Well

(Depth1016m)

KM-3 Well

(Depth 2393m)

Ja-46

Well

(Depth 1812m)

Pu-7 Well

(Depth 1575m)

Figure (3.9): The Infrared Analysis Graphs for analyzed samples from (TT-04, KM-3,

Ja-45 and Pu-7)


Figure (3.10):

Typical Infrared spectra of the four types

of AOM proposed by Thompson and Dembicki, (1986).

A Factor represents the ratio between the sum of the intensity of 2860 cm-1 +

2930 cm-1 peaks to the sum of intensity for 2860 cm-1+ 2930 cm-1 + 1630 cm-1 peaks,

while C Factor represents the ratio of the intensity of 1710 cm-1 peak to the sum of

intensity for the peaks of 1710 cm-1 + 1630 cm-1 (Ganz and Kalkreuth, 1987a).

Plotting A Factor versus C Factor in a diagram similar to that of Van-Kervelen as

proposed by Ganz and Kalkreuth (1987b) has been done for the studied sections to

detect the type of kerogen and maturity state of the organic matters (Figs. 3.11-3.14).

As seen from the cross plots, maturity levels appear to be higher as the values of A and

C Factors decrease, accordingly, all the analyzed samples were located within the

immature zone (Ro<0.3%), and all the organic matters appeared to be mostly of type II

kerogen.


Table (3.6): Measured intensities from Infrared spectroscopy with A and C Factors

and type of AOM in TT-04


and type of AOM in KM-3.


and type of AOM in Ja-46.

Formation Depth m.

2930 C-1

2860 C-1

1710 C-1

1630 C-1

A factor

C

factor Type of

AOM Kolosh 1016 89.24

91.65 88.09 81.63 0.69 0.52 A

Aal

iji/K

olo

sh

1128 83.42

85.21 86.19 81.6 0.67 0.51 A

1178 88.25

88.63 88.2 86 0.67 0.51 A

1258 92.38

93.29 88.35 85.17 0.69 0.51 A

1282 85.76

87.87 86.45 83.93 0.67 0.51 A

1340

95.67

96.83

91.69

88.39

0.69

0.51

B

1444 97.41

97.37 89.72 86.88 0.69 0.51 B

1490 74.8 76.68 71.48 64.06 0.7 0.53 B

1562 94.94

96.28 86.8 84.16 0.69 0.51 B

1586 69.42

73.05 71.05 64.59 0.69 0.52 A

Formation Depth m.

2930 C-1

2860 C-1

1710 C-1

1630 C-1

A factor

C factor

Type of AOM

Jaddala 1889 63.08 65.7 68.07 63.76 0.67 0.52 A

1946 60.45 64.16 68.91 16.29 0.88 0.81 A

2037 47.62 51.87 58.65 53.73 0.65 0.52 D

Aaliji

2089 46.67 52.55 59.51 52.77 0.65 0.53 A

2134 59.88 62.91 67.75 63.94 0.66 0.51 A

2158 57.28 60.72 63.44 59.62 0.66 0.52 A

2172 58.58 61.91 65.99 60.15 0.67 0.52 A

Aaliji/Kolosh

2228 56.91 59.35 64.34 59.11 0.66 0.52 A

2364 50.08 52.76 57.55 50.99 0.67 0.53 B

2393 43.77 47.04 51.32 44.06 0.67 0.54 B

Formation Depth

m.

2930

C-1

2860

C-1

1710

C-1

1630

C-1

A

factor

C

factor

Type of

AOM

Jaddala

1793

62.64

65.15

68.64

65.4

0.66

0.51

A

1812

48.69

53.64

59.97

56.45

0.64

0.52

A

1818

67.68

69.4

72.9

69.79

0.66

0.51

A

Aaliji

1870

45.95

48.14

52.87

46.26

0.67

0.53

A

1896

52.89

56.49

61.95

57.46

0.66

0.52

A

1910

34.03

36.64

49.32

40.74

0.63

0.55

A

1933

57.95

59.99

63.69

58.79

0.67

0.52

A

1968

60.41

62.32

66.96

62.27

0.66

0.52

B


52

● Kolosh Formation, ●Aaliji/Kolosh Formation.

Table (3.9): Measured intensities from Infrared spectroscopy with A and C Factors and type of AOM in Pu-7.

Figure (3.11): Kerogen type and maturity levels as determined from A Factor and C Factor relationship for TT-04 (the diagram is after Ganz and Kalkreuth, 1987b).

Formation Depth m.

2930 C-1

2860 C-1

1710 C-1

1630 C-1

A factor

C factor

Type of AOM

1575 47.7 53.54 65.42 62.01 0.62 0.51 D 1595 39.85 47.11 58.16 56.11 0.61 0.51 D 1695 51.73 51.73 61.63 57.66 0.64 0.52 A 1680 52.74 59.1 67.06 63.53 0.64 0.51 A 1758 23.4 31.02 49.25 47.16 0.54 0.51 D

Aaliji

1792 41.34 50.25 56.59 53.28 0.63 0.52 D 1984 55.03 57.93 64.73 59.37 0.66 0.52 A 1989 39.29 46.44 51.52 45.74 0.65 0.53 A 1992 57.97 60.14 65.28 59.56 0.66 0.52 A

Aaliji/Kolosh

1994 48.9 51.95 55.95 49.61 0.67 0.53 A

Vitrinitebreflectanceequivalent grid

evolution pathof type III

Type IV

evolution pathof type II

evolution pathof type I

A-f

acto

r

0.0 0.1 0.2 0.3 0.4 0.5 0.7 0.8 0.9 10.6C-factor

0.30.40.6 0.5

0.70.8

0.9

1.0

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1


53

● Jaddala Formation ● Aaliji Formation ●Aaliji/Kolosh Formation

● Jaddala Formation ● Aaliji Formation

Figure (3.12): Kerogen type and maturity levels as determined from A Factor and C Factor relationship for KM-3 (the diagram is after Ganz and Kalkreuth, 1987b).

Figure (3.13): Kerogen type and maturity levels as determined from A Factor and C Factor relationship for Ja-46 (the diagram is after Ganz and Kalkreuth, 1987b).



Type IV



0.30.40.6 0.5

0.70.8

0.9

1.0

A-f

acto

r

0.0 0.1 0.2 0.3 0.4 0.5 0.7 0.8 0.9 10.6C-factor

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1



Type IV



0.30.40.6 0.5

0.70.8

0.9

1.0

A-f

acto

r

0.0 0.1 0.2 0.3 0.4 0.5 0.7 0.8 0.9 10.6C-factor

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1


54

● Jaddala Formation●Aaliji/Kolosh Formation

Figure (3.14): Kerogen type and maturity levels as determined from A Factor and C Factor relationship for Pu-7 (the diagram is after Ganz and Kalkreuth, 1987b).

3.6 Vitrinite Reflectance (Ro): The reflectance of maceral particles can be readily measured using conventional

reflectance microscope initially developed by coal petrologists and later applied to

organic matter dispersed in sediments; an international standard provides an accurate

scale relating thermal maturation and the reflectance of vitrinite. The technology for

measuring RO (reflectance in oil) is well known and because the reflectance is a

measured variable rather than an estimated variable, it is a useful statistical estimator in

data analysis (Hart, 1986).

Vitrinite is the term applied to a group of maceral / kerogens with certain definite,

variable optical and chemical properties (Carr, 2000: in Othman, 2003), and most often

used to reflectance measurements, because its optical properties alter more uniformly

during rank advance than do those of the other macerals( Dow,1997: in Othman,2003).

The reflectance of vitrinite in coal and Disseminated Organic Matter (DOM)

increases during thermal maturation due to complex irreversible aromatization reactions

(Petres and Cassa, 1994: in Othman, 2003).



Type IV



0.30.40.6 0.5

0.70.8

0.9

1.0

A-f

acto

r

0.0 0.1 0.2 0.3 0.4 0.5 0.7 0.8 0.9 10.6C-factor

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1


Hunt (1996) mentioned that the irreversible chemical reactions, in which the rate

rises exponentially with temperature, are responsible for the changes in molecular

structure. Consequently the reflectance associated with these maturation changes also

increases exponentially with a linear rise in temperature.

There are problems associated with the RO method, the most critical of which is

the reliability of the vitrinite sample as a statistical estimator of the true population. In

cutting samples, caving and recycling are the principle causes of error in RO

measurements, assuming instrument-and operator-error are controlled. An occasional

problem in obtained an accurate estimate of the RO is that sufficient vitrinite is often

difficult to find in a sample; true vitrinite is absent from all pre-middle Silurian rocks (Hart,

1986).

In this study, Vitrinite Reflectance technique was also used to estimate the

maturity level of the organic matters for twelve selected samples from the four studied

sections.

In TT-04 the three selected samples from Aaliji/Kolosh beds at depths 1368,

1448, and 1546m showed appreciable numbers of vitrinite particles which were used to

measure the reflection intensity as shown in figure (3.15). The mean of reflectance

percentages for the samples were between 0.62 and 0.64% indicating early stages of

maturity for the studied samples.

The examined samples related to Jaddala Formation in KM-3 section at depths

2004 and 2060m showed close conditions to maturity (mean reflectance 0.48 and 0.44%

respectively) (Fig.3.16), although the measured points in the sample of 2060m were not

sufficient. Unfortunately the third chosen sample at depth 2145m from Aaliji Formation in

the same section showed no vitrinite particles for their reflectance to be measured.

The three samples of Jaddala Formation at depths 1736, 1846, and 1862m from

Ja-46 section also had no sufficient vitrinites, but the measured few points showed a

mean reflectance between 0.43 and 0.59% which means that their organic matters are

still within the realm of immaturity (Fig.3.17).

The problem of lack in vitrinite continued with the samples chosen from Jaddala

Formation in Pu-7, but the measured points showed a relatively higher maturation level

than the two sections of KM-3 and Ja-46 with a reflectance mean ranged between 0.47

and 0.51% (Fig.3.18).


Reflectance @ 546nm

Reflectance @ 546nm

0

5

10

15

20

25

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

Taq Taq-

4

1448

0

5

10

15

20

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

1368

2.00

Reflectance @ 546nm

20

15

0

5

00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

1546

10

Figure (3.15): Vitrinite Reflectance Histograms and the statistical details of the three selected

samples from TT-04 well.

Mean

Std. Dev.

Points

Max.

Min.

Depth m.

0.62

0.06

36

0.75

0.53

1368

0.62

0.04

48

0.72

0.55

0.64

0.05

29

0.72

0.53

1546


Reflectance @

546nm

0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2060

2.00

Reflectance @ 546nm

0

5

10

15

20

25

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2004

2.00

Reflectance @ 546nm

0

5

10

15

20

25

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2145

2.00

No vitrinite


samples from KM-3 well.

Mean

Std. Dev.

Points

Max.

Min.

Depth m.

0.48

0.04

40

0.56

0.42

2004

0.44

0.03

7

0.50

0.41

2060

0

0

0

0

0

2145


0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

1846

Reflectance @ 546nm

0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

1862

0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

1736

Reflectance @ 546nm

Reflectance @ 546nm


samples from Ja-46 well.

Mean

Std. Dev.

Points

Max.

Min.

Depth m.

0.59

0

1

0.59

0.59

1736

0.43

0.01

2

0.44

0.42

1846

0.43

0.03

5

0.47

0.41

1862


0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

1804

2.00

0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

1820

0

5

10

15

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

1689

Reflectance @ 546nm Reflectance @ 546nm

Reflectance @ 546nm


samples from Pu-7 well.

Mean

Std. Dev.

Points

Max.

Min.

Depth m.

0.51

0.8

2

0.57

0.45

1689

0.47

0.03

10

0.50

0.40

1804

0.49

0.03

3

0.55

0.44

1820


3.7 Ternary kerogen plots:

Many authors used ternaries of different organic matter components to show

either hydrocarbon potentiality, type of kerogen, or depositional environments of the

source rocks. Each ternary may have special circumstances depending on the existed

and measured ratios of the organic matter components which in turn depend on the

nature and depositional environment of the studied samples.

Law et al. (1980: in Tyson, 1995) used a Liptinite

Vitrinite

Inertinite (LVI) plot

in order to characterize kerogen assemblages and indicate the probable hydrocarbons

that may be generated from them (i.e. oil, wet gas, and dry gas).

By plotting the values listed in table (3.10) for the studied samples on the (LVI)

ternary of Law et al. (1980) (Fig.3.19), the samples of Aaliji/Kolosh taken from TT-04

section appeared to be gas prone while all other samples taken from KM-3, Ja-46, and

Pu-7 showed tendency to be oil-prone.

Table (3.10): Percentages of Liptinite, Vitrinite and Inertinite for the studied samples of TT-04,

KM-3, Ja-46, and Pu-7 wells.

No. Section Depth m. Liptinite % Vitrinite % Inertinite %

1 TT-4 1368 10 75 15

2 TT-4 1448 20 60 20

3 TT-4 1546 20 65 15

4 KM-3 2004 95 5 0

5 KM-3 2060 95 5 0

6 KM-3 2145 100 0 0

7 Ja-46 1736 95 5 0

8 Ja-46 1846 95 5 0

9 Ja-46 1862 95 5 0

10 Pu-7 1689 95 5 0

11 Pu-7 1804 95 5 0

12 Pu-7 1820 95 5 0


61

Figure (3.19): Locations of the studied samples on Liptinite -Vitrinite- Inertinite (LVI) ternary of Law et al. (1982: in Tyson, 1995).

Inertinite100%

Vetrinite100%

AOM+Liptinite

100%

35

65

65

35

65

Oil

Wet Gas+

Condensate

Dry Gas

Barren

Ja-46, 1846m Ja-46, 1862mKM-3, 2145mTT-04, 1546m

Pu-7, 1620-1689m Pu-7, 1804mJa-46, 1736mKM-3, 2004m KM-3, 2060mTT-04, 1248-1368m TT-04, 1448m

Pu-7, 1804m

CHAPTER FOUR ___________________________________________

Chapter Four

Pyrolysis Analysis

4.1 Preface:

Pyrolysis is a widely used degradation technique that allows breaking a complex

substance into fragments, by heating it under an inert gas atmosphere. The small

compounds thus obtained are building blocks of the complex substance, but they can

often be analyzed more easily, eventually up to a molecular level, and quantified.

Applying this technique to hydrocarbon generation from kerogen thermal cracking also

means that geological conditions with long time intervals at low temperature can be

replaced by laboratory conditions with short experiment duration at high temperature, of

course in a defined domain where cracking reactions are similar (Vandenbroucke,

2003).

The method consists of estimating petroleum potential of rock samples by

pyrolysis according to a programmed temperature pattern. The temperature programs

are defined in order to distinguish, by a Flame Ionization Detector (FID), thermo-

vaporized free hydrocarbons and /or fragments from thermolabile compounds at 300

centigrade (peak S1), and potential hydrocarbons that can be released during thermo

destruction of Organic Matter (OM) within the range 300-650 centigrade (peak S2). In

addition, Carbon monoxide (CO) and Carbon dioxide (CO2) released during pyrolysis

are monitored by means of an IR cell, providing information on the oxidation state of the

organic matter. The method is completed by oxidation of the rock sample according to a

programmed temperature pattern. This complimentary stage allows determination of

Total Organic Carbon and Mineral Carbon Content of the samples (Johannes et al.,

2006).

In this study Rock-eval pyrolysis including Total Organic Carbon (TOC)

determination for 55 core and cutting samples have been done in samples by Baseline

Resolution Inc. (Analytical Laboratories) Texas, USA to ascertain the hydrocarbon

potentiality of Aaliji/Kolosh, Aaliji, Kolosh and Jaddala Formations in the studied wells.

The values of the different pyrolysis parameters for the selected samples are shown in

tables 4.1- 4.4.

Chapter Four Pyrolysis Analysis

Table (4.1): Rock-Eval data for the pyrolyzed samples from Aaliji/Kolosh and Kolosh Formations in TT-04 well.

Key of abbreviations: OI: Oxygen Index, HI: Hydrogen Index, PC: Pyrolysable Organic Carbon, RC: Residual Carbon.

Table (4.2): Rock-Eval data for the pyrolyzed samples from Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3 well.

Formation Depth

m. TOC

Wt. %

S1 mg/g

S2

mg/g

S3

mg/g

S1+S2 (GP)

S1/ S1+S2

(PI)

S1/ TOC

%

Tmax

Co HI OI

PC Wt. %

RC Wt. %

Kolosh 984 0.62 0.08 0.29 0.61 0.37 0.22 0.13 424 47 98 0.06 0.56 1064 0.33 0.1 0.43 0.64 0.53 0.19 0.3 428 130 194 0.06 0.27

Aaliji/Kolosh

1104 0.51 0.08 0.36 0.35 0.44 0.18 0.16 429 71 69 0.04 0.47 1190 0.49 0.18 0.39 0.6 0.57 0.32 0.37 429 80 122 0.06 0.43 1246 0.49 0.09 0.25 0.32 0.34 0.26 0.18 424 51 66 0.03 0.46 1262 0.71 0.08 0.37 1.61 0.45 0.18 0.11 430 52 227 0.15 0.56 1304 0.38 0.10 0.15 0.34 0.25 0.4 0.26 427 39 89 0.03 0.35 1320 0.56 0.06 0.22 1.03 0.28 0.21 0.11 426 39 184 0.1 0.46 1368 0.47 0.10 0.17 0.41 0.27 0.37 0.21 448 36 87 0.04 0.43 1392 0.56 0.03 0.16 0.44 0.19 0.16 0.05 237 29 79 0.04 0.52 1404 0.34 0.08 0.15 0.37 0.23 0.35 0.24 436 44 109 0.04 0.3 1448 0.65 0.14 0.35 0.36 0.49 0.29 0.22 442 54 55 0.04 0.61 1478 0.56 0.1 0.19 1.71 0.29 0.34 0.18 419 34 305 0.16 0.4 1494 0.56 0.07 0.25 1.35 0.32 0.22 0.13 427 45 241 0.13 0.43 1546 0.44 0.06 0.10 0.23 0.16 0.38 0.14 442 23 53 0.02 0.42 1578 0.66 0.06 0.42 0.49 0.48 0.13 0.09 433 64 74 0.05 0.61 1598 0.39 0.09 0.30 0.35 0.39 0.23 0.23 434 77 90 0.04 0.35

Formation Depth m.

TOC Wt. %

S1 mg/g

S2 mg/g

S3 mg/g

S1+S2 (GP)

S1/ S1+S2

(PI)

S1/ TOC

%

Tmax

Co HI OI

PC Wt. %

RC Wt. %

Jaddala 1990 0.76 0.27 2.16 0.68 2.43 0.11 0.36 430 285 90 0.08 0.68 2004 2.17 0.46 4.48 1.61 4.94 0.09 0.21 428 206 74 0.19 1.98

Aaliji

2060 2.66 2.04 14.36 1.14 16.4 0.12 0.77 426 540 43 0.24 2.42 2080 3.21 3.43 20.52 1.28 23.95 0.14 1.07 425 638 40 0.32 2.89 2111 2.31 0.60 8.61 1.52 9.21 0.07 0.26 423 373 66 0.22 2.09 2145 1.33 1.07 5.59 0.90 6.66 0.16 0.8 427 422 68 0.14 1.19 2187 3.69 1.63 22.73 1.54 24.36 0.07 0.44 427 616 42 0.34 3.35 2222 0.37 0.26 0.71 0.42 0.97 0.27 0.7 428 192 114 0.05 0.32 2254 0.61 0.31 0.85 0.74 1.16 0.27 0.51 434 140 122 0.08 0.53 2280 0.85 0.23 1.24 0.58 1.47 0.16 0.27 431 145 68 0.07 0.78

Aaliji/Kolosh

2300 0.32 0.17 0.36 0.77 0.53 0.32 0.53 451 113 241 0.07 0.25 2358 0.43 0.23 0.28 0.61 0.51 0.45 0.53 425 66 144 0.06 0.37 2370 0.64 0.18 0.65 0.46 0.83 0.22 0.28 431 101 72 0.05 0.59 2399 0.35 0.30 0.58 0.32 0.88 0.34 0.86 427 164 90 0.04 0.31

Chapter Four Pyrolysis Analysis

Table (4.3): Rock-Eval data for the pyrolyzed samples from Aaliji and Jaddala Formations in Ja-46 well.

Table (4.4): Rock-Eval data for the pyrolyzed samples from Aaliji/Kolosh and Jaddala Formations in Pu-7 well.

Formation Depth m.

TOC Wt. %

S1 mg/g

S2

mg/g

S3

mg/g

S1+S2 (GP)

S1/ S1+S2

(PI)

S1/ TOC

%

Tmax

Co HI OI

PC Wt. %

RC Wt. %

Jaddala

1736 0.98 0.26 1.79 2.01 2.05 0.13 0.27 428 184 206 0.2 0.78 1774 0.13 0.08 0.31 0.81 0.39 0.21 0.62 422 235 614 0.08 0.05 1804 1.36 0.38 5.38 1.15 5.76 0.07 0.28 427 395 84 0.15 1.21 1846 1.68 0.42 6.75 1.46 7.17 0.06 0.25 425 401 87 0.19 1.49 1862 1.03 0.28 3.86 1.41 4.14 0.07 0.27 426 374 137 0.16 0.87

Aaliji

1893 1.77 0.29 3.74 1.68 4.03 0.07 0.16 428 211 95 0.19 1.58 1921 0.67 0.16 1.50 0.90 1.66 0.1 0.24 431 224 134 0.1 0.57 1943 0.15 0.13 0.32 0.32 0.45 0.29 0.87 425 221 221 0.03 0.12 1982 0.14 0.06 0.16 1.02 0.22 0.27 0.43 428 112 713 0.1 0.04 1994 0.12 0.07 0.23 0.60 0.3 0.23 0.58 431 192 500 0.06 0.06 2003 0.10 0.07 0.11 0.87 0.18 0.39 0.7 451 109 861 0.08 0.02 2017 0.18 0.06 0.08 0.87 0.14 0.43 0.33 341 44 478 0.08 0.1

Formation Depth m.

TOC Wt. %

S1 mg/g

S2 mg/g

S3 mg/g

S1+S2 (GP)

S1/ S1+S2

(PI)

S1/ TOC

%

Tmax

Co HI OI PC Wt. %

RC Wt. %

1620 1.86 27.70 4.55 1.43 32.25 0.86 14.9 424 245 77 0.4 1.46 1689 2.15 29.70 5.08 1.41 34.78 0.85 13.8 425 236 65 0.42 1.73 1714 2.59 20.24 7.38 1.55 20.24 0.73 7.8 417 285 60 0.37 2.22 1744 3.35 44.93 9.63 1.17 54.56 0.82 13.4 431 288 35 0.56 2.79 1750 3.91 44.04 19.88 1.27 63.92 0.69 11.3 424 508 32 0.65 3.26 1777 2.85 15.96 15.23 1.01 31.19 0.51 5.61 425 535 36 0.35 2.5 1796 4.00 15.69 24.70 1.20 40.39 0.39 3.93 429 618 30 0.45 3.55 1804 3.03 9.52 16.91 0.98 26.43 0.36 3.14 425 558 32 0.31 2.72 1820 2.69 8.56 16.38 1.01 24.94 0.34 3.19 430 609 38 0.3 2.39 1846 1.96 4.72 10.01 1.10 14.73 0.32 2.41 426 511 56 0.22 1.74

Aaliji/Kolosh

1984 0.63 0.33 0.83 0.61 1.16 0.28 0.53 432 132 97 0.07 0.56 1996 1.53 4.04 6.70 0.92 10.74 0.38 2.64 425 438 60 0.17 1.36

Jaddala

alysisAnPyrolysis

Chapter Four

4.2 Total Organic Carbon (TOC):

The organic matter richness of source rocks is estimated usually using the Total

Organic Carbon content (TOC wt%), although the TOC is a residual TOC when dealing

with the mature source rocks, as the overall converting efficiency of organic carbon is

generally less than 1.5 w% (Hunt, 1979: in Maky and Ramadan,2008).

The color of a rock is a rough, but not always reliable, indicator of its TOC

content. Most sandstones and red beds have very low TOC because the organic matter

has been destroyed by oxidation. TOC generally increases in shale as the color goes

from red to variegate, to green, gray and finally to black (the use of colors as a rough

TOC indicator should always be supported by analytical data) (Hunt, 1996).

Currently, TOC is best determined by direct combustion. Approximately 0.2

grams of the sample is carefully weighed, treated with concentrated hydrochloric acid to

remove carbonates, and vacuum filtered on glass fiber paper. The residue and paper is

places in a ceramic crucible, dried, combusted with pure oxygen in a LECO EC-12

carbon analyzer at about 1000 centigrade. A laboratory slandered is run every five

minutes. "Total carbonate" can be determined from differences in weight of the original

sample and residue that remained after acid treatment or by LECO combustion (%TOC)

differences before and after the acid digestion (Mukhopadhyay, 2004).

Tissot and Welte (1984) considered the 0.3% for carbonates and 0.5% for shales as

the minimum required TOC value for source rock facies.

According to Peter (1986: in Gogoi et al., 2008) commonly accepted minimum

TOC content for a potential source rock is 0.5%. Rocks containing less than 0.5% TOC

are considered to have negligible hydrocarbon source potential. Between 0.5 and 1.0%

TOC indicates marginal and more than 1% TOC often has substantial source potential.

TOC values between 1 and 2% are associated with depositional environments

intermediate between oxidizing and reducing, where preservation of lipid-rich organic

matter with source potential for oil can occur. TOC values above 2% often indicate

highly reducing environment with excellent source potential.

Leckie et al. (1988) in their classification of qualification of source rocks also

suggested the existence of more than 0.5% TOC for not considering a bed as a poor

source rock. While Barker (1996: in Maky and Ramadan, 2008) considered a TOC value

alysisAnPyrolysis

Chapter Four

of 1.0% as the lower limit for an effective source rock, because a source rock with less

than 1.0% will never generate enough oil to initiate primary migration.

Table (4.5) show the classification of source rock potentiality according to their

TOC (%) which proposed by Bacon et al. (2000).

From the results of TOC analysis for the studied samples, and using statistic

analysis for the values (table 4.6) the following have been concluded:

Among the studied formations, Jaddala is the richest with TOC then what is

known as Aaliji/ Kolosh, Aaliji Formation, and Kolosh Formation respectively.

As location, Pulkhana seemed to be the richest area, then Kor Mor, Jambur,

and Taq Taq respectively.

The highest TOC value (4%) has been recorded in Jaddala Formation at depth

1796m in Pu-7 section.

The lower part of Aaliji Formation in Ja-46 showed continues lowest TOC

content among the studied sections.

According to the classification of Bacon et al. (2000), Jaddala is generally good

or very good as source rock (from TOC content point of view), while the other

studied formations are generally poor.

Table (4.5): The Source rock classification according to TOC content (after Bacon et al., 2000)

Figures (4.1-4.4) show the evaluation of the studied successions in the four selected

sections depending on variations in TOC content as a function of depth.

TOC(%) content Source rock quality

<0.5 Poor

0.5-1 Fair

1-2 Good

> 2 Very good

alysisAnPyrolysis

Chapter Four

Table (4.6): Minimum, Maximum, and Mean of the TOC content for the studied formations

and their evaluation in the studied sections.

Figure (4.1): Evaluation of Aaliji/Kolosh and Kolosh Formations in TT-04 well depending on

variations in TOC content with their depths(the diagram from Maky and Ramadan,

2008).

No.

Section

Formation

No. of Sample Min.

TOC%

Max.

TOC%

Mean

TOC% Evaluation

1 TT-04 Kolosh 2 0.33 0.62 0.47 Poor

2 TT-04 Aaliji/Kolosh 15 0.34 0.71 0.51 Fair

3 KM-3 Jaddala 2 0.76 3.21 2.2 Very good

4 KM-3 Aaliji 6 0.37 3.69 1.52 Good

5 KM-3 Aaliji/Kolosh 4 0.32 0.64 0.43 Poor

6 Ja-46 Jaddala 5 1.63 0.13 1.03 Good

7 Ja-46 Aaliji 7 0.1 1.77 0.44 Poor

8 Pu-7 Jaddala 10 0.86 4 2.83 Very good

9 Pu-7 Aaliji/Kolosh 2 1.53 0.63 1.08 Good

Kolosh

Fn.

Aaliji/Kolosh Fn.

1600

1500

1400

1300

1200

1100

1000

900

Dep

th (

m)

0 0.5 1 2TOC(WT%)

Poo

r so

urce

Fai

r so

urce

Goo

d so

urce

Ver

y go

od s

ourc

e

alysisAnPyrolysis r Four Chapte

68

Figure (4.2): Evaluation of Aaliji/Kolosh, Aaliji, and Jaddal Formations in KM-3 well depending on variations in TOC content with their depths(the diagram from Maky and Ramadan, 2008).

Figure (4.3): Evaluation of Aaliji and Jaddala Formations in Ja-46 well depending on variations in TOC content with their depths (the diagram from Maky and Ramadan, 2008)

● Jaddala Fn.

● Aaliji Fn.

● Aaliji/Kolosh Fn.

● Jaddala Fn.

● Aaliji Fn.

Dep

th (m

)

2000

1900

1800

1700

TOC(WT%)0 0.5 1 2

Poor

sour

ce

Fair

sour

ce

Goo

d so

urce

Ver

y go

od so

urce

0TOC(WT%)

Dep

th (m

)

2400

2300

2200

2100

2000

0.5 1 2 3 4

Poor

sour

ceFa

ir so

urce

Goo

d so

urce

Ver

y go

od so

urce

alysisAnPyrolysis

Chapter Four

Figure (4.4): Evaluation of Aaliji/ Kolosh and Jaddala Formations in Pu-7 well depending on

variations in TOC content with their depths(the diagram from Maky and Ramadan,

2008).

4.3 Extractable Organic Matter (EOM):

The bitumen extracted from the sediments is often referred to as Extractable

Organic Matter (EOM). It usually represents 5 to 10% of the total organic matter in fine

grained sedimentary rocks. Though there are many other factors, but the detail

compositional analysis of EOM in conjunction with kerogen yields the necessary

information to make at least semi-quantitative predictions about the amount of petroleum

which has been or will be generated by a given amount of source rock (Ahmed et al.,

2004).

Bacon et al. (2000) classified the potentiality of source rocks depending on their

EOM (wt %) content to Poor, Fair, Good, and Very good when they contain <0.05, 0.05-

0.1, 0.1-0.2, and >0.2 respectively.

The potential of hydrocarbon generation in a source rock can be estimated from

TOC (%) versus EOM (ppm) data (Othman, 2003). Using the obtained values of EOM

for selected samples in the studied sections versus their TOC values (Table 4.7) in a

cross plot (Fig. 4.5) it was found out that Aaliji/Kolosh Formation in TT-04 and the

sample from Jaddala Formation at depth 2004m in KM-3 showed a good quality source

Jaddala Fn.

Aaliji/Kolosh Fn.

2000

1900

1800

1700

1600

Dep

th (

m)

TOC(WT%)0 0.5 1 2 3 4

Poo

r so

urce

Fai

r so

urce

Goo

d so

urce

Ver

y go

od s

ourc

e

alysisAnPyrolysis

Chapter Four

10

1000100100.1

1

EOM(ppm)

TO

C %

100

10000 100000

Gas Source

Poor Source

Very Poor Source

Poor

FairGood

Very

Good

Excellent

Bitumen20% of O

rganic Carbone

Bitumen10% of O

rganic Carbone

Oil staining orContamination

rock and the other one sample in KM-3 from the upper part of Aaliji Formation at depth

2060 appeared to be of 10% extractable bitumen from the existed organic carbon. The

lower part of Jaddala Formation in Ja-46 at depth 1846m also showed nearly a good

source rock regarding the existence of extractable bitumen, while the samples from Pu-7

may affected by contamination from migrated oils and this will be approved using proper

procedures later in this chapter.

Table (4.7): TOC (%) and EOM (ppm) values for selected samples in the studied sections.

Figure (4.5): Source rock potential rating based on TOC and EOM for selected samples

from the studied sections (the diagram from Othman, 2003).

Section Depth m.

TOC %

EOM (ppm)

TT-04 1448 0.65 2043 K M-3 2004 2.17 1927 K M-3 2060 2.66 3644 Ja-46 1846 1.68 2185 Pu-7 1620 1.86 28160 Pu-7 1689 2.15 28160 Pu-7 1804 3.03 19443 Pu-7 1820 2.69 15068

Pu-7,1620m Pu-7,1689m Pu-7,1804m Pu-7,1820m

KM-3,2004m KM-3,2060m Ja-46,1846mTT-04,1448m

alysisAnPyrolysis

Chapter Four

4.4 Rock-Eval Parameters:

This technique uses temperature programmed heating of a small amount of rock

(70 mg) or coal (30-50 mg) in an inert atmosphere (helium or nitrogen) in order to

determine the quantity of free hydrocarbons present in the sample (S1 peak) and of

those that can be potentially released after maturation (S2 peak). The Tmax value is a

standardized parameter, calculated from the temperature at which the S2 peak reaches

its maximum: this parameter is used as a maturity parameter for fossil organic matter.

These parameters describe the quality of organic matter in the rock sample for

exploration purpose. For a more complete diagnosis, total organic content (TOC) has to

be determined together with the Mineral Carbon content (MinC) (Behar et al., 2001).

Ghori (1998) defined the main peaks which are read from Rock-Eval as follows:

S1:- (Free hydrocarbons) already generated hydrocarbons in nature and expressed as

mg/g rock.

S2:- (Oil potential) remaining hydrocarbon potential of rock and expressed as mg/g rock.

S3:- Carbon dioxide (CO2) released during pyrolysis up to 390°C and expressed as

mg/g rock. This is proportional to oxygen present in the kerogen and may be unreliable

in carbonate rocks because there is a possibility of contamination from inorganic carbon.

The Rock-Eval parameters and their abbreviations are shown in table (4.8)

which is summarized by Behar et al. (2001), while table (4.9) is the Rock Eval

parameters calculated according to Johannes et al. (2006).

Kerogen maturation, as reflected by Tmax, is observed not to be very sensitive to

time (unlike vitrinite reflectance), so that temperature is more important than time in the

overall kinetics of kerogen breakdown and the associated oil and gas generation (Wood,

1988; Hunt, 1991: both in Whelan and Thompson-Rizer, 1993). Maturity stages as

related to Vitrinite Reflectance and Tmax which proposed by Ibrahimbas and Reidiger

(2004) shown in table (4.10).

Tissot et al. (1987: in Whelan and Thompson-Rizer, 1993) maintain the chemical

nature of a particular kerogen is intimately related to the observed Tmax. . It would be

expected that different kerogen types would show different responses of Tmax to the

maturation process, which summarized Tmax data for kerogen types I, II, III, and

concluded that Tmax is a good maturation indicator for kerogen types II and III, but not for

alysisAnPyrolysis

Chapter Four

the type I because the Tmax values remain very constant as a function of maturity for the

type I.

The values in table (4.11) which proposed by Bacon, et al. (2000) show that

maturity levels for the oil window

depend on the type of organic matter, and

encompass a vitrinite reflectance range of Ro 0.5 1.3% and pyrolysis Tmax temperatures

(temperature at maximum rate of hydrocarbon generation during S2 evolution) of 435

470°C. The pyrolysis Production Index (PI=S1/ (S1+S2)) is another measure of maturity,

with values ranging from 0.15 to 0.4 normally associated with oil generation.

Table (4.8): Rock-Eval parameters and their abbreviations (after Behar et al., 2001).

Table (4.9): Calculated Rock-Eval parameters and their abbreviations (after Johannes et al., 2006)

Acquisition parameters Detector/Oven Unit Name

Name

S1 FID/Pyrolysis mg HC/g rock Free hydrocarbons

S2 FID/Pyrolysis mg HC/g rock Oil potential TpS2 - C° Temperature of peak S2 maximum

S3 Insoluble Residual(IR)/Pyrolysis mg CO/g rock CO2 organic source

S3

Insoluble Residual(IR)/Pyrolysis mg CO/g rock CO2 mineral source

TpS3

- C° Temperature of peak S3 maximum

S3CO Insoluble Residual(IR)/Pyrolysis mg CO/g rock CO2 organic source

TpS3CO - C° Temperature of peak S3CO maximum

S3 CO Insoluble Residual(IR)/Pyrolysis mg CO/g rock CO organic and mineral source

S4CO2 Insoluble Residual(IR)/Oxidation mg CO/g rock CO2 organic source

S5 Insoluble Residual(IR)/Oxidation mg CO/g rock CO2 mineral source

TpS5 - C° Temperature of peak S5 maximum

S4CO Insoluble Residual(IR)/Oxidation mg CO/g rock CO organic source

Abbreviation

Unit

Formula

Name

GP S1+S2 Genetic Potential

PI

S1/(S1+S2)

Production Index

PC wt% 0.1[0.83(S1+S2)+0.273S3+

0.429(S3CO+0.5S3CO)] Pyrolysable Organic Carbon

TOC wt% PC+RC Total Organic Carbon

BI

100S1/TOC

Bitumen Index

HI Mg HC/g TOC 100S2/TOC Hydrogen Index

OI Mg CO2/g TOC 100S3/TOC Oxygen Index

RC CO wt% 0.0428 S4 CO Residual Carbon Organic(CO)

RC CO2 wt% 0.0273 S4CO2 Residual Carbon Organic(CO2)

RC wt% RC CO+RC CO2 = TOC-PC Residual Carbon Organic

alysisAnPyrolysis

Chapter Four

Table (4.10): Maturity stages as related to Vitrinite Reflectance and Tmax. (after Ibrahimbas

and Reidiger, 2004)

Stage of the thermal

maturity for oil

Vitrinite Reflectance

Ro (%)

Rock-Eval Tmax.

(Centigrade)

Immature

Mature

Early

Peak

Late

Post mature

0.2-0.6

0.6-0.65

0.65-0.9

0.9-1.35

1.35

435

435-445

445-450

450-470

470

Table (4.11): Maturation level as a function of Production Index and Tmax for different types of Kerogen ( after Bacon, et al., 2000)

Maturation

Level

Production

Index

(PI)

Tmax

for

Type I

Tmax

for

Type II

Tmax

for

Type III

Immature

Mature

Over mature

0.15

0.15-0.4

0.4

445

445-455

455

435

435-460

460

440

440-470

470

4.4.1 Hydrogen Index (HI) and Oxygen Index (OI):

The Hydrogen Index is a measure of hydrogen richness in kerogen and has a

direct relationship with elemental hydrogen to carbon ratios. The index is used to define

the type of kerogen and approximate level of maturation. The OI is the measure of

oxygen richness in kerogen and has a direct relationship with elemental oxygen to

carbon ratios. This index was used in conjunction with HI to define the type of kerogen

and approximate level of maturation (Ghori, 1998).

Tissot and Welte(1978: in Pitman et al., 1987) clarified the relation between thermal

maturity of source rock with HI that is at low level of thermal maturity (vitrinite reflectance

less than 0.5%) oil-prone (type I and type II) source rocks generally are characterized by

a high hydrogen index (more than 400 milligram HC/g TOC) relative to the oxygen index

(less than 50 milligram CO2/g TOC ), whereas gas-prone (type III) source rocks

commonly display a wide range in oxygen index (5-100 milligram CO2/g TOC) with a

low hydrogen index (less than 200 milligram HC/g TOC). Hydrogen index for any type of

alysisAnPyrolysis

Chapter Four

kerogen that is thermally mature (vitrinite reflectance more than 0.75%) typically are less

than 300 milligram HC/g TOC).

By plotting the HI and OI values for the analyzed selected samples on the Van-

Kerevlen diagram (Figs. 4.6 - 4.9) to obtain the type of kerogen; it was clear that most of

the organic matters within Aaliji/Kolosh and Kolosh Formations in TT-04 are of kerogen

type III, while the existed organic matters in the other sections generally showed a mix

of type II and III for most of studied samples.

It is important to mention that a number of anomalously high OI values have been

observed in some depths especially in the lower part of Ja-46 section (Aaliji Formation).

Such a condition can be referred to the released CO2 which may come mainly from the

carbonate minerals instead of the organic matters particularly when the TOC content

becomes less than 1%. Some times carbonates appear to break down at temperatures

lower than 400°C (Hunt, 1996).

In order to determine the maturity stage of the organic matters, the values of HI have

been plotted against Tmax values in a number of cross plots (Figs. 4.10

4.17) which

showed that the lower part of Aaliji/Kolosh in TT- 04 entered the zone of maturation,

while most of the organic matters in the rest formations within the other studied sections

appeared to be still immature and some times very close to maturity. As it was expected,

the older and deeper formations are the closer to the maturity in all the studied sections.

Figures (4.18-4.21) show the increasing of maturity with depth depending on the

measured Tmax values for the studied samples.

alysisAnPyrolysis

Chapter Four

Figure (4.6): HI versus OI cross plot for Aaliji/Kolosh and Kolosh Formations in TT-04

section. The diagram from Espitalie et al. (1977: in Tissot and Welte, 1984).

Figure (4.7): HI versus OI cross plot for Aaliji/Kolosh, Aaliji, and Jaddala Formations in

KM-3 section. The diagram from Espitalie et al. (1977: in Tissot and Welte, 1984)

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0 50 100 1500

100

200

300

400

500

600

700

800

900

1000

II

III

I

OI(mgCO2/g TOC)

HI(

mgH

C/g

TO

C)

200 250

305

II

III

I

0 50 100 150 2000

100

200

300

400

500

600

700

800

900

1000

OI(mgCO2/g TOC)

HI(

mgH

C/g

TO

C)

alysisAnPyrolysis

Chapter Four

Figure (4.8): HI versus OI cross plot for Aaliji and Jaddala Formations in Ja-46 Section.

The diagram from Espitalie et al. (1977: in Tissot and Welte, 1984).

Figure (4.9): HI versus OI cross plot for Aaliji/Kolosh and Jaddala Formations in Pu-7

section. The diagram from Espitalie et al. (1977: in Tissot and Welte ,1984)

Jaddala Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

II

III

I

0 50 100 1500

100

200

300

400

500

600

700

800

900

1000

OI(mgCO2/g TOC)

HI(

mgH

C/g

TO

C)

220 500610

710860470210

200

II

III

I

0 50 100 1500

100

200

300

400

500

600

700

800

900

1000

OI(mgCO2/g TOC)

HI(

mgH

C/g

TO

C)

alysisAnPyrolysis

Chapter Four

Figure (4.10): HI versus Tmax cross plot for Aaliji/Kolosh and Kolosh Formations in TT-04

section. (The diagram from Hunt, 1996)

Figure (4.11): HI versus Tmax cross plot for Aaliji/Kolosh, Aaliji, and Jaddala Formations in

KM-3 Section. (The diagram from Hunt, 1996)

900

800

700

600

500

400

300

200

100

0500480460440420400

Type III

Type II

Type I

0.5% Ro

1.3% Ro

HI(

mgH

C/g

TO

C)

Tmax (°C)Immature mature Post mature

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

900

800

700

600

500

400

300

200

100

0500480460440420400

Type III

Type II

Type I0.5% Ro

1.3% Ro


HI(

mgH

C/g

TO

C)

alysisAnPyrolysis

Chapter Four

Figure (4.12): HI versus Tmax cross plot for Aaliji and Jaddala Formations in Ja-46 section.

(The diagram from Hunt, 1996)

Figure (4.13): HI versus Tmax cross plot for Aaliji/Kolosh and Jaddala Formations in Pu-7

section. (The diagram from Hunt, 1996)

410341

900

800

700

600

500

400

300

200

100

0500480460440420

Type III

Type II

Type I

0.5% Ro

1.3% Ro


HI(

mgH

C/g

TO

C)

Jaddala Fn.

Aaliji Fn.

Tmax (°C)

1.3% Ro

0.5% Ro

Type I

Type II

Type III

500480460440420400

900

800

700

600

500

400

300

200

100

0

Immature mature Post mature

HI(

mgH

C/g

TO

C

Jaddala Fn.

Aaliji/Kolosh Fn.

alysisAnPyrolysis

Chapter Four

Figure (4.14): HI versus Tmax cross plot for Aaliji/Kolosh and Kolosh Formations in TT-04

section. The diagram from English et al. (2004).

Figure (4.15): HI versus Tmax cross plot for Aaliji/Kolosh, Aaliji, and Jaddala Formations in

KM-3 Section .The diagram from English et al. (2004).

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0

900

800

700

600

500

400

300

200

100

HI(

mgH

C/g

TO

C)

Tmax (°C)500480460440420400

Imm

atur

e

Mat

ure

Pos

t Mat

ure

0

900

800

700

600

500

400

300

200

100

HI(

mgH

C/g

TO

C)

Tmax (°C)500480460440420400

Imm

atur

e

Mat

ure

Pos

t Mat

ure

alysisAnPyrolysis

Chapter Four

Figure (4.16): HI versus Tmax cross plot for Aaliji and Jaddala Formations in Ja-46 section.

The diagram from English et al. (2004).

Figure (4.17): HI versus Tmax cross plot for Aaliji/Kolosh and Jaddala Formations in Pu-7

section .The diagram from English et al. (2004).

Jaddala Fn.

Aaliji/Kolosh

Jaddala Fn.

Aaliji Fn.

Tmax (°C)500480460440420400

0

900

800

700

600

500

400

300

200

100

HI(

mgH

C/g

TO

C)

Imm

atur

e

Mat

ure

Post

Mat

ure

410341 500480460440420Tmax (°C)

0

900

800

700

600

500

400

300

200

100

HI(

mgH

C/g

TO

C)

Imm

atur

e

Mat

ure

Post

Mat

ure

alysisAnPyrolysis

Chapter Four

Figure (4.18): Tmax versus depth for Aaliji/Kolosh and Kolosh Formations in TT-04 section.

Figure (4.19): Tmax versus depth for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3

section.

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh

1600

1500

1400

1300

1200

1100

1000

900

400 450 500Tmax (°C)

Dep

th (

m)

Imm

atur

e

Mat

ure

Pos

t Mat

ure

400Tmax (°C)

Dep

th (

m)

2400

2300

450 500

2200

2100

2000

Imm

atur

e

Mat

ure

Pos

t Mat

ure

alysisAnPyrolysis

Chapter Four

Figure (4.20): Tmax versus depth for Aaliji and Jaddala Formations in Ja-46 section.

Figure (4.21): Tmax versus depth for Aaliji/Kolosh and Jaddala Formations in Pu-7 Section.

Jaddala Fn.

Aaliji Fn.

Jaddala Fn.

Aaliji/Kolosh

Fn.

341 450 500Tmax (°C)

Dep

th (

m)

2000

1900

1800

1700

Imm

atur

e

Mat

ure

Pos

t Mat

ure

2000

1900

1800

1700

1600

400 450 500Tmax (°C)

Dep

th (

m)

Imm

atur

e

Mat

ure

Pos

t Mat

ure

alysisAnPyrolysis

Chapter Four

4.4.2 Genetic Potential (GP):

Tissot and Welte (1984) defined the Genetic Potential (S1+S2) of a given

formation as the amount of petroleum (oil and gas) that kerogen is able to generate, if it

is subjected to an adequate temperature during a sufficient interval of time. This

potential depends on the nature and abundance of kerogen, which in turn are related to

the original organic input at the time of sediment deposition, and to the conditions of

microbial degradation, and the rearrangement of organic matter in the sediments.

The Genetic Potential gives a qualitative estimate of hydrocarbon resource

potential; however, it can not be used to predict the type of hydrocarbons (gaseous or

liquid) produced during pyrolysis.

Tissot and Welte (1978: in Pitman et al., 1987) predicted the source rock quality

according to the genetic potential as shown in table (4.12).

Table (4 .12): Evaluation of source rocks according to their genetic potential values.

after Tissot and Welte (1978: in Pitman et al., 1987)

The potentiality of the studied successions were attempted to be determined from

the relationship between the TOC contain and the genetic potential values obtained for

the analyzed samples. The results as appear in figures (4.22

4.25) indicate different

potentiality for generating hydrocarbons. The whole studied succession in TT-04 was

observed to have a poor potentiality, while the section of KM-3 showed a wide range of

potentiality from poor in Aaliji/ Kolosh till excellent especially in Aaliji Formation. In Ja-

46; Aaliji Formation appeared to be poor to fair while Jaddala generally showed fair to

good potentiality. The organic matters within the studied samples in Pu-7 section were

observed to be of higher potentiality for hydrocarbon generation ranged mostly between

very good to excellent particularly Jaddala formation.

Genetic Potential

(milligram HC /g. Rock)

Source rock evaluation

> 6

2-6

< 2

Good

Moderate

Poor

alysisAnPyrolysis

Chapter Four

Figure (4.22): TOC versus S1+ S2 (Genetic Potential) for Aaliji/Kolosh and Kolosh

Formations in TT-04 Section (The diagram from Ghori, 2002).

Figure (4.23): TOC versus S1+ S2 (Genetic Potential) for Aaliji/Kolosh, Aaliji, and Jaddala

Formations in KM-3 Section (The diagram from Ghori, 2002).

TOC (%)0.1 0.2 0.5 1.0 2.0 5.0 10

0.1

1

10

5

S1+S

2(m

g/g

rock

)Fair

Good

Very Good

Excellent

Poor

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh

Fn.

0.1 0.2 0.5 1.0 2.0 5.0 10

0.1

1

10

5

S1+S

2(m

g/g

rock

)

TOC (%)

Fair

Good

Very Good

Excellent

Poor

alysisAnPyrolysis

Chapter Four

Figure (4.24): TOC versus S1+ S2 (Genetic Potential) for Aaliji and Jaddala Formations in

Ja-46 Section (The diagram from Ghori, 2002)

Figure (4.25): TOC versus S1+ S2 (Genetic Potential) for Aaliji/Kolosh and Jaddala

Formations in Pu-7 Section (The diagram from Ghori, 2002)

Jaddala Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

0.1 0.2 0.5 1.0 2.0 5.0 10

0.1

1

10

5

S1+S

2(m

g/g

rock

)

TOC (%)

Fair

Good

Very Good

Excellent

Poor

0.1 0.2 0.5 1.0 2.0 5.0 10

0.1

1

10

5

S1+S

2(m

g/g

rock

)

Fair

Good

Very Good

Excellent

Poor

TOC (%)

100

50

alysisAnPyrolysis

Chapter Four

4.4.3 Transformation Ratio (TR):

The Transformation Ratio or Production Index (S1/S1+S2) is the proportion of

free hydrocarbons in relation to the total amount of hydrocarbon compounds obtained by

the sample analysis (Espitaliè, 1986: in Othman, 2003).

The transformation ratio depends on the nature of the organic material and on the

subsequent geological history (temperature versus time history) (Tissot and Welte,

1984). Production Index is often used to assess the relative thermal maturity of organic

matter, and the presence of migrated hydrocarbons.

Type I and II organic matters that are thermally immature typically display

transformation ratios less than 0.1 (Table 4.13). These ratios increase gradually to 0.4

during catagenesis and are greater than 0.4 when the main stage of hydrocarbon

generation has been exceeded (Tissot and Welte, 1978: in Pitman et al., 1987).

Type III organic matter in the catagenesis zone commonly has production index that

ranges from 0.1-0.2 (Durand and Paratte, 1983: in Pitman et al., 1987).

Table (4.13): Immature organic matter types and Production Index (After Tissot and Welte, 1978: in Pitman et al., 1987).

Production Index has been used to show how far petroleum generation has

progressed in the studied sediments or in other words how far catagenesis stage has

been realized considering maturity stage is generally of PI higher than 0.2 (Ghori, 2002).

The lower part of the studied sections (Aaliji/ Kolosh and Aaliji Formations) in TT-04,

KM-3, and Ja-46 were observed to be mature (Figs. 4.26-4.29), while the upper part of

Aaliji and Jaddala Formations remained immature as also approved by the previous

methods of maturity determinations. The maturity condition of Jaddala Formation in Pu-7

(Fig. 4.29) seems to have no reality due to contamination of the analyzed samples by

migrated hydrocarbon leading to an increase of the bitumen ratio in the samples as

observed from the relatively high values of the EOM in the studied samples from this

Organic matter type Production Index

Type I

Type II

Type III

<0.1

<0.1

0.1-0.2

alysisAnPyrolysis

Chapter Four

section (Fig. 4.5). Such a conclusion can be supported by observing the unusual case of

decreasing PI values with increasing depth of burial in Pu-7 section.

Production Index (Transformation Ratio) values and the obtained Tmax values

from the pyrolysis process are used together as two maturity indicator factors in two

different cross plots (Figs. 4.30

4.37) to determine the maturity and potentiality of the

studied samples. According to the diagram suggested by Espitalli et al. (1977) which

has been brought from Katz (2001), less samples fall in the realm of maturity, as they

consider the range of Tmax between 440°C and 460°C and PI between 0.2 and 0.4

representative of maturity state of organic matters (Figs. 4.30-4.33). While the cross plot

suggested by Ghori (2000) between the same two parameters included more mature

samples, as he suggested a wider limits for maturity interval ranged between 430°C and

460°C for Tmax and between 0.1 and 0.4 for PI (Figs. 4.34-4.37).

Accordingly, still the lower part of Aaliji/Kolosh in TT-04 can be considered to

have relatively higher maturity (showing a maturity level within the oil window

generation) than the other studied successions. The contaminated state of the analyzed

samples from Pu-7 also approved clearly in the figure (4.33).

alysisAnPyrolysis

Chapter Four

Figure (4.26): PI versus depth for Aaliji/Kolosh and Kolosh Formations in TT-04 Section.

(The diagram from Ghori, 2002)

Figure (4.27): PI versus depth for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3

section. (The diagram from Ghori, 2002)

Dep

th (

m)

1600

1500

1400

1300

1200

1100

1000

900

0.0 0 .2 0.4

Production Index

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0.0

Dep

th (

m)

2400

2300

2200

2100

2000

0.2 0.4Production Index

alysisAnPyrolysis

Chapter Four

Figure (4.28): PI versus depth for Aaliji and Jaddala Formations in Ja-46 section.


Figure (4.29): PI versus depth for Aaliji/Kolosh and Jaddala Formations in Pu-7 Section.


Jaddala Fn.

Aaliji Fn.

Dep

th (

m)

2000

1900

1800

1700

1600

Production Index0.0 0.2 0.4 0.6 0.8

Jaddala Fn.

Aaliji/Kolosh Fn.

Production Index

Dep

th (

m)

2000

1900

1800

1700

0.0 0.2 0.4

alysisAnPyrolysis

Chapter Four

Figure (4.30): Tmax versus TR for Aaliji/Kolosh and Kolosh Formations in TT- 04 section.

(The diagram from Espitalli et al., 1977: in Katz, 2001)

Figure (4.31): Tmax versus TR for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3

section. (The diagram from Espitalli et al., 1977: in Katz, 2001)

Transformation Ratio

Tm

ax (

°C) IN

ERT MATERIA

L PRESENT

IMM

AT

UR

E

OVERMATURE

STAINED OR CONTAMINATED

MATURE

380

400

420

440

460

500

0 0.2 0.4 0.6 0.8 1.0

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0 0.2 0.4 0.6 0.8 1.0380

400

420

440

460

500


Tm

ax (

°C)

INERT M

ATERIAL P

RESENT

IMM

AT

UR

E

OVERMATURE


MATURE

alysisAnPyrolysis

Chapter Four

Figure (4.32): Tmax versus TR for Aaliji and Jaddala Formations in Ja-46 section.


Figure (4.33): Tmax versus TR for Aaliji/Kolosh and Jaddala Formations in Pu-7 section.



Tm

ax (

°C) IN

ERT MATERIA

L PRESENT

IMM

AT

UR

E

OVERMATURE


MATURE

0 0.2 0.4 0.6 0.8 1.0380

400

420

440

460

500

Jaddala Fn.

Aaliji/Kolosh Fn.

0 0.2 0.4 0.6 0.8 1.0

380

400

420

440

460

500


Tm

ax (

°C)

INERT M

ATERIAL P

RESENT

IMM

AT

UR

E

OVERMATURE


MATURE

360

340

Jaddala Fn.

Aaliji Fn.

alysisAnPyrolysis

Chapter Four

Figure (4.34): Tmax versus PI for Aaliji/Kolosh and Kolosh Formations in TT- 04 section.


Figure (4.35): Tmax versus PI for Aaliji/Kolosh, Aaliji and Jaddala Formations in KM-3

section (The diagram from Ghori, 2000)

0 0.2 0.3 0.4 0.5 0.60.1 0.7Production index

410

420

430

440

450

460

470

Tm

ax (

°C)

Immature

Oil- window

Gas-window

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0 0.2 0.3 0.4 0.5 0.60.1 0.7Production index

410

420

430

440

450

460

470

Tm

ax (

°C)

Immature

Oil- window

Gas-window

alysisAnPyrolysis

Chapter Four

Figure (4.36): Tmax versus PI for Aaliji and Jaddala Formations in Ja-46 section.


Figure (4.37): Tmax versus PI for Aaliji/Kolosh and Jaddala Formations in Pu-7 Section.


0.8 0.90 0.2 0.3 0.4 0.5 0.60.1 0.7Production index

410

420

430

440

450

460

470

Tm

ax (

°C)

Immature

Oil- window

Gas-window

Jaddala Fn.

Aaliji/Kolosh Fn.

345

3400 0.2 0.3 0.4 0.5 0.60.1 0.7

Production index

420

430

440

450

460

470

Tm

ax (

°C)

Immature

Oil- window

Gas-window

Jaddala Fn.

Aaliji Fn.

alysisAnPyrolysis

Chapter Four

4.4.4 Bitumen Index (S1/TOC %):

The main use of S1/TOC, which is some times called Migration Index (Hunt,

1996), is to determine the depth at which a source rock begins to expel oil. Generally S1

increases with depth as oil is being generated. According to Smith (1994: in Hunt, 1996)

the ratio of S1 to TOC% should be between 0.1 and 0.2 for oil expulsion to start in the

source rock. When S1 is high and the TOC is low, migrated hydrocarbons are indicated.

Plotting the S1/TOC values of the analyzed samples versus depth of the studied

sections (Figs. 4.38-4.41) showed that expulsion occurred at the lower part of Aaliji/

Kolosh in TT-04 (from the depth 1368) as the S1/TOC% values within the expected

range of 0.1 to 0.2 and this is comparable with the concluded maturity state of this zone.

Other parts of the studied successions in the other sections were observed to be of

higher S1/TOC values (greater than 0.2) indicating the probability of existing migrated

oils, therefore, it is important to sure from the indigenous condition of the hydrocarbons

in the analyzed samples to avoid any confusions.

The cross plot of S1 versus TOC% is commonly used to distinguish migrated

hydrocarbons and contaminants from indigenous hydrocarbons (Hunt, 1996). Figures

(4.42-4.45) represent the plot of S1 versus TOC for the analyzed samples in this study.

Values above the slanted line suggest nonindigenous hydrocarbons, and values below it

are indigenous. It is clear from the plots that the hydrocarbons in the studied samples

are all indigenous except the samples of the Pu-7 section which appeared to be

nonindigenous as concluded before also.

Accordingly, the studied samples within KM-3 and Ja-46 can be considered very

close to maturity and they may generate some hydrocarbons (as they have a relatively

high S1 values) but they are not enough to initiate expulsion.

alysisAnPyrolysis

Chapter Four

Figure (4.38): S1/TOC versus Depth for Aaliji/Kolosh and Kolosh Formations in TT- 04 section (The diagram after Smith, 1994 :in Hunt, 1996)

Figure (4.39): S1/TOC versus depth for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3 section (The diagram after Smith, 1994: in Hunt, 1996)

S1/TOC

Dep

th (

m)

1500

1400

1300

0

1200

16000.1 0.20 0.30

1100

1000

0.40

Kolosh Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

S1/TOC

Dep

th (

m)

0 0.1 0.2 0.3 0.4 0.5 0.7 0.8 0.9 1.00.6

2300

2200

2100

2000

2400 1.1

alysisAnPyrolysis

Chapter Four

Figure (4.40): S1/TOC versus Depth for Aaliji and Jaddala Formations in Ja-46 section. (The diagram after Smith, 1994: in Hunt, 1996)

Figure (4.41): S1/TOC versus Depth for Aaliji/Kolosh and Jaddala Formations in Pu-7 Section (The diagram after Smith, 1994: in Hunt, 1996)

S1/TOC

Dep

th (

m)

2000

1900

1800

1700

0 0.1 0.2 0.50.62.412.64

3.143.19

1620

0.3 0.4 3.95.61

7.811.2

13.413.8

14.9

Jaddala Fn.

Aaliji/Kolosh Fn.

Dep

th (

m)

2000

1900

1800

1700

S1/TOC0 0.1 0.2 0.3 0.4 0.5 0.7 0.8 0.9 1.00.6

Jaddala Fn.

Aaliji Fn.

alysisAnPyrolysis

Chapter Four

Figure (4.42): S1/TOC versus Depth for Aaliji/Kolosh and Kolosh Formations in TT- 04 section (The diagram after Hunt, 1996)

Figure (4.43): S1/TOC versus Depth for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3 section (The diagram after Hunt, 1996)

0.1 0.2 0.5 1.0 2.0 5.0 10

0.01

0.1

1.0

S1 (

mg/

g ro

ck)

TOC (%)

Nonin

digenou

s

Hydro

carb

ons

prese

nt

Indige

nous

Hydro

carb

ons

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0.1 0.2 0.5 1.0 2.0 5.0 10

0.01

0.1

1.0

S1 (

mg/

g ro

ck)

TOC (%)

Nonin

digenou

s

Hydro

carb

ons

prese

ntIn

digenou

s

Hydro

carb

ons

alysisAnPyrolysis

Chapter Four

0.1 0.2 0.5 1.0 2.0 5.0 10

0.01

0.1

1.0

S1 (

mg/

g ro

ck)

TOC (%)

Indige

nous

Hydro

carb

ons

Nonin

digenou

s

Hydro

carb

ons p

rese

nt

Jaddala Fn.

Aaliji Fn.

Figure (4.44): S1/TOC versus Depth for Aaliji and Jaddala Formations in Ja-46 section. (The diagram after Hunt, 1996)

Figure (4.45): S1/TOC versus Depth for Aaliji/Kolosh and Jaddala Formations in Pu-7 section (The diagram after Hunt, 1996).

TOC (%)

0.1 0.2 0.5 1.0 2.0 5.0 100.1

1

10

S1 (

mg/

g ro

ck)

Nonin

dige

nous

Hydro

carb

ons

pres

ent

Indi

geno

us

Hydro

carb

ons

Jaddala Fn.

Aaliji/Kolosh Fn.

alysisAnPyrolysis

Chapter Four

4.4.5 S2 and TOC%:

The values of S2 and TOC% can be used in more than one way to evaluate

source rocks regarding their ability in generating hydrocarbons or to detect the type of

hydrocarbons that they may generate.

Figures 4.46-4.49 are cross plots between S2 and TOC values as a function of HI

which show the types of hydrocarbons that were expected to be generating by the

analyzed samples. Bacon et al. (2000), in their interpretation for the type of petroleum

generated from immature sediments (Ro<0.6%), mentioned that HI of 50-200, 200-300,

and >300mgHC/gTOC indicate source rocks of ability to generate gas, oil and gas, and

oil respectively. Accordingly, gas is mainly the future product of the thermally

transformed organic matters within the samples studied from the upper part of

Aaliji/Kolosh and Kolosh Formations in TT-04 section. While the other studied

successions have an ability to generate oil in addition to the gas especially Jaddala

Formation in Pu-7 section.

Figure (4.46): TOC versus S2 cross plot for the analyzed samples from Aaliji/Kolosh and

Kolosh Formations in TT-04 section. (The diagram after Akinlua et al., 2005)

Kolosh

Fn.

Aaliji/Kolosh Fn.

0

0.5

1.0

S2 m

gHC

/gT

OC

Total Organic Carbon (%)0

1.5

0.5 1.0 1.5 2.0

HI (200)

Type IVDry Gas Prone

Type III Gas Prone

Type II / III Oil / Gas Prone

HI (50)

alysisAnPyrolysis

Chapter Four

Figure (4.47): TOC versus S2 cross plot for the analyzed samples from Aaliji/Kolosh, Aaliji,

and Jaddala Formations in KM-3 section(The diagram after Akinlua et al., 2005)

Figure (4. 48): TOC versus S2 cross plot for the analyzed samples from Aaliji and Jaddala

Formations in Ja-46 section (The diagram after Akinlua et al., 2005)

Jaddala Fn.

Aaliji Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0

S2m

gHC

/gT

OC

5

10

15

20

30

25

0 1.0 2.0 4.03.0Total Organic Carbon (%)


Type III Gas Prone


HI (200)

HI (400)

Type I Oil Prone

Type II Oil Prone

HI (700)

HI (50)

0 1.0 2.00

S2m

gHC

/gT

OC

4.03.0

5

10

15

20

30

25

Total Organic Carbon (%)


Type III Gas Prone


HI (200)

HI (400)

Type I Oil Prone

Type II Oil Prone

HI (700)

HI (50)

alysisAnPyrolysis

Chapter Four

Figure (4.49): TOC versus S2 cross plot for the analyzed samples from Aaliji/Kolosh and

Jaddala Formations in Pu-7 section (The diagram after Akinlua et al., 2005).

In another way to evaluate the studied sections depending on the relation

between S2 and TOC values, the plots shown in the figures 4.50-4.53 and also in the

figures 4.54-4.57 have been drawn to qualify the analyzed samples from their

potentiality point of view. Such potentiality (as it depends on values of S2) can be

considered as a future ability of the studied immature samples when they are subjected

to higher degrees of temperature and start entering stages of maturity.

According to both styles of cross plot in the mentioned figures which are from

Ghori (2000) and Othman (2003), the studied samples from Aaliji/Kolosh observed to be

mainly poor, while Aaliji samples showed a wide range of potentiality from poor to

excellent especially in KM-3 section. Jaddala appears to be more promising in Pu-7 as it

showed good to excellent potentiality and that in contrary to the fair or poor to good

potentiality which was shown in KM-3 and Ja-46 respectively.

Jaddala Fn.

Aaliji/Kolosh Fn.

0

S2m

gHC

/gT

OC

5

10

15

20

30

25

0 1.0 2.0 4.03.0Total Organic Carbon (%)


Type III Gas Prone

Mixed Type II / III Oil / Gas Prone

HI (200)

HI (400)

Type I Oil Prone

Type II Oil Prone

HI (700)

HI (50)

alysisAnPyrolysis

Chapter Four

Figure (4.50): TOC versus S2 for Aaliji/Kolosh and Kolosh Formations in TT-04 section.

(The diagram from Ghori, 2000).

Figure (4.51): TOC versus S2 for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3

section. (The diagram from Ghori, 2000)

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0.1 0.2 0.5 1.0 2.0 5.0 10

0.1

1

10

5

TOC (%)

S2 (

mg/

g ro

ck) Good

Very Good

Excellent

Poor

Fair

TOC (%)

S2 (

mg/

g ro

ck) Good

Very Good

Excellent

Poor

Fair

0.1 0.2 0.5 1.0 2.0 5.0 100.1

1

10

5

alysisAnPyrolysis

Chapter Four

Figure (4.52): TOC versus S2 for Aaliji and Jaddala Formations in Ja-46 section.


Figure (4.53): TOC versus S2 for Aaliji/Kolosh and Jaddala Formations in Pu-7 section.


Jaddala Fn.

Aaliji Fn.

Jaddala Fn.

Aaliji/Kolosh Fn.

0.1 0.2 0.5 1.0 2.0 5.0 100.1

1

10

5

TOC (%)

S2 (

mg/

g ro

ck) Good

Very Good

Excellent

Poor

Fair

0.1 0.2 0.5 1.0 2.0 5.0 100.1

1

10

5

TOC (%)

S2 (

mg/

g ro

ck) Good

Very Good

Excellent

Poor

Fair

alysisAnPyrolysis

Chapter Four

Figure (4.54): TOC versus S2 for Aaliji/Kolosh and Kolosh Formations in TT-04 section.

(The diagram from Othman, 2003)

Figure (4.55): TOC versus S2 for Aaliji/Kolosh, Aaliji, and Jaddala Formations in KM-3

section. (The diagram from Othman, 2003)

0.1 10.01

TOC (wt.%)

S2 (

Kg

hydr

ocar

bons

/ton

rock

)

Poor

FairGood

Excellent100

10

1

0.1

0.01

Very Good

Kolosh

Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

0.1 10.01

TOC (wt.%)

S2

(Kg

hydr

ocar

bons

/ton

rock

)

Fair

Good

Excellent100

10

1

0.1

0.01

Poor

Very Good

alysisAnPyrolysis

Chapter Four

Figure (4.56): TOC versus S2 for Aaliji and Jaddala Formations in Ja-46 section.


Figure (4.57): TOC versus S2 for Aaliji/Kolosh and Jaddala Formations in Pu-7 section


0.1 10.01

TOC (wt.%)

S2

(Kg

hydr

ocar

bons

/ton

rock

)Fair

Excellent100

10

1

0.1

0.01

GoodVery Good

Poor

Jaddala Fn.

Aaliji Fn.

0.1 10.01

TOC (wt.%)

S2 (

Kg

hydr

ocar

bons

/ton

rock

)

FairGood

Excellent100

10

1

0.1

0.01

Very Good

Poor

Jaddala Fn.

Aaliji/Kolosh Fn.

alysisAnPyrolysis

Chapter Four

4.4.6 RC and TOC%:

Residual Carbon (RC) represents the sum of the organic carbon (by wt %) which

is obtained from the CO and CO2 during the pyrolysis operation. It can be defined also

as the portion of the TOC which represents the non-pyrolysable organic carbon

(Johannes et al., 2006)

The cross plots of the TOC% versus Residual Carbon (RC) for the analyzed

samples (Figs. 4.58

4.61) show that there is a little generative potential left in the

Aaliji/Kolosh beds in TT-04, KM-3, and Pu-7 sections and the same in lower part of Aaliji

Formation in KM-3 and Ja-46 sections as most of the TOC% contents are very close to

the RC values. While, the upper part of Aaliji and Jaddala Formations still slightly have

the potentiality to generate hydrocarbons when they enter the realm of maturity.

Figure (4.58): TOC versus RC for Aaliji/Kolosh and Kolosh Formations in TT- 04section

(The diagram after English et al., 2004).

Kolosh

Fn.

Aaliji/Kolosh Fn.

1

2

3

4

5

6

7

8

02 4 6 80

Total Organic Carbon (wt%)

Res

idua

l Car

bon

(wt%

)

TOC =RC

alysisAnPyrolysis

Chapter Four

Figure (4.59): TOC versus RC for, Aaliji/Kolosh, Aaliji and Jaddala Formations in KM-3

section (The diagram after English et al., 2004).

Figure (4.60): TOC versus RC for Aaliji and Jaddala Formations in Ja-46 section


Jaddala Fn.

Aaliji Fn.

Aaliji/Kolosh Fn.

Jaddala Fn.

Aaliji Fn.

1

2

3

4

5

6

7

8

02 4 6 80


Res

idua

l Car

bon

(wt%

)

TOC =RC

1

2

3

4

5

6

7

8

02 4 6 80


Res

idua

l Car

bon

(wt%

)

TOC =RC

alysisAnPyrolysis

Chapter Four

Figure (4.61): TOC versus RC for Aaliji/Kolosh and Jaddala Formations in Pu-7 section.


Jaddala Fn.

Aaliji/Kolosh Fn.

2 4 6 8

1

2

3

4

5

6

7

8

00


Res

idua

l Car

bon

(wt%

)

TOC =RC

CHAPTER FIVE ___________________________________________

Chapter Five Biomarkers

5.1: Preface:

Biomarkers are specific organic compounds used in assessing the genetic

sources of bituminous organic matter derived from biochemical precursors by mainly

reductive but also oxidative alteration processes with chemical structures which can

be related back to their precursor compounds in contemporary or extinct biota

(Simoneit, 2004: in Idris et al., 2008). They are originating from formerly living

organisms, and are complex organic compounds composed of carbon, hydrogen,

and other elements. They occur in sediments, rocks, and crude oils and show little or

no change in structure from their parent organic molecules in living organisms

(Peters et al., 2005).

These organic compounds which are unequivocally related to their natural

product precursors originated from chemical and geological transformation of

biomolecules of organisms that were deposited during sedimentary processes (Osuji

and Antia, 2005)

Peters et al. (2005) mentioned three characteristics that distinguish biomarkers

from many other organic compounds which are:

1. Biomarkers have structures composed of repeating subunits, indicating that

their precursors were component in living organisms.

2. Each parent biomarker is common in certain organisms. These organisms can

be abundant and widespread.

3. The principle identifying structural characteristics of the biomarkers are

chemically stable during sedimentation and early burial.

5.2: Uses of Biomarkers:

Biological markers are normally analyzed by Gas Chromatography (GC) and

Gas Chromatography-Mass Spectrometry (GC-MS).

Tissot and Welte (1984) give the most common uses of geochemical fossils as

follows:-

1. As correlation parameters (oil-oil and oil-source rock).

2. For the reconstruction of depositional environment.

3. For the elucidation of chemical transformations during diagenesis and

catagenesis.

4. For the detection of contamination with foreign material in marine or fresh

water recent sediments.


In addition, biomarkers can provide information on the organic source materials,

environmental conditions during it is deposition, the thermal maturity experienced by

a rock or oil, and the degree of biodegradation (El-gayar et al., 2002: in Idris et al.,

2008), they also give valuable information about lithology and age determination


5.3 Analyzed Samples:

A number of samples from Aaliji/Kolosh, Aaliji, and Jaddala Formations have

been chosen from TT-04, KM-3, Ja-46 and Pu-7 sections, in addition to two oil

samples from Ja-25 and Tq-2 wells to be analyzed using GC and GC/MS

instruments. The selection of the actually analyzed samples depended highly on

whether the quantity of the bitumen extracted from each sample satisfactory or not

which in turn depends on firstly, the richness of the samples from organic materials

and secondly, on the obtained quantity of the rock samples itself.

5.4 Depositional Environment and Source related Biomarkers:

The composition and distribution (fingerprint) of certain diagnostic chemical

fossil can indicate the dominant source of sedimentary organic matter (marine or

non-marine), the physicochemical conditions prevalent and the paleoenvironment

(oxicity/anoxicity and salinity status) as well as the maximum thermal stress

experienced by the rocks or petroleum in which the compounds are found (Ekweozor

and Strauz, 1982: in Osuji and Antia, 2005). Within the stable carbon-carbon

skeleton of such compounds there are embodied essential information about the

habitat, nature and fate of the ancestral flora and fauna which can facilitate the

reconstruction of environment of deposition of ancient sediments and petroleum

(Ekweozor and Strauz, 1983; Kleme, 1989; Peters and Moldowan, 1993; Peters and

Cassa, 1994: all in Osuji and Antia, 2005).

Tissot and Welte (1984) mentioned that there are three factors that have effects

on the quality of information provided by geochemical fossils in terms of depositional

environment.

1- Their state of conservation, which may or may not allow one to link them to

their biochemical precursor molecule.

2- The distribution of the biochemical precursor (parent molecule) in the present

animal and /or plant kingdom.


3- The assumption that the distribution was comparable in ancient organisms.

The utility of biomarkers as indicators of depositional environments arises from the

fact that certain types of compounds are associated with organisms or plants that

grow in specific types of depositional environments (Philp, 2003a).

There are many biomarkers that are related to a specific source rock

depositional environment such as:

5.4.1 Pristane and Phytane:

These substances are formed at the time of sedimentary deposition by

degradation of the phytyl side-chain of chlorophyll. It has been postulated that phytol

degradation leads to the preferential formation of phytane versus pristane under

anaerobic sedimentary conditions. Thus, the pristane/phytane ratios can be applied

to evaluate the redox palaeoconditions. Here, sludge Pr/Ph values of ~ 1.2 indicate

that the fossil fuel pollution had been formed during geological times by deposition of

sediment under rather aerobic water column conditions, e.g. ocean or open sea

(Payet et al., 1999).

The abundant source of pristane (C19) and phytane (C20) is the phytal side

chain of chlorophyll (a) in phototrophic organisms and bacteriochlorophyll (a) and (b)

in purple sulphur bacteria (Mc Kirdy, 1973: in Peters et al., 2005). Anoxic conditions

or reducing in sediments promote cleavage of the phytal side chain to yield phytol,

which undergoes reduction to dehydrophytal and phytane. Oxic conditions promote

the competing conversion of phytol to pristine by oxidation of phytol to phytenic acid,

decarboxylation to pristene and then reduction to pristane (ibid).

The Pr/Ph ratio evolved as an indicator of the oxicity of the depositional

environment. An environment thought to be aerobic has microenvironments which

are anaerobic (Rowland, 1990: in Philp, 2003a). An organism containing an

alternative source for phytane may thrive in an oxic environment, producing Pr/Ph

ratio that is very low for an oxic environment. In brief, a great deal of caution needs to

be exercised when using the Pr/Ph ratio as an indicator of depositional environment

(Philp, 2003a).

Peters et al., (2005) mentioned that the Pr/Ph ratios in the range of 0.8-3.0 are

interpreted to indicate specific paleoenvironmental conditions without corroborating

data. Pr/Ph more than 3.0 indicates terrigenous plant input deposited under oxic to

suboxic conditions, while Pr/Ph less than 0.8 indicates saline to hypersaline

conditions associated with evaporate and carbonate deposition.


Pr/Ph is commonly applied because Pr and Ph are measured easily using gas

chromatography (Didyk et al., 1978: in Peters et al., 2005).

Marine organic matters usually have Pr/Ph less than 1.5 while terrestrial

organic matters have ratios of greater than 3.0. The ratio Pr/nC17 is useful for

differentiating organic matter from swamp environment (more than 1.0).Those

organic matters formed under marine environment (less than 0.5), but this ratio is

affect by maturity and biodegradation (Osuji and Antia, 2005).

The ratios of the Pr/Ph for the all extracts and the two oil samples of this study

were generally low and ranged between 0.58 and 1.29 indicating anoxic, reduced

marine carbonate depositional environment (Table 5.1). The only sample which had

Pr/Ph ratio greater than 3.0 was from TT-04(Aaliji/ Kolosh Formation) at depth 1441m

indicating terrestrial source of organic matter.

The ratio of Pr / nC17 for the studied extracts and oil samples ranged between

0.33 and 0.80 indicating depositional environments varied in there reduction or

oxidizing conditions. The samples related to Aaliji/ Kolosh Formation in TT-04 had Pr

/ nC17 higher than 0.5 (between 0.61 and 0.68) indicating depositional environments

suffered slightly from oxidizing condition. The samples of KM-3 that belonged to Aaliji

Formation (at depths 2060 and 2145m) also appeared to suffer from oxidizing

condition but to a less extend, while the sample at the depth 2004m which belongs to

Jaddala Formation represents deposition in a reduction condition although it is Pr /

nC17 is higher than 0.5 and that is because of it is relatively high Ph / nC18. The

same is true with the samples of Jaddala Formation from Ja-46 section. On the other

hand, the samples of Pu-7 which are related to Jaddala Formation also showed

clearly that they deposited in a reduced marine environment (their Pr / nC17 ratios

were less than 0.5). Regarding the two oil samples, both appeared to be originated

from marine organic matter sources.

The above conclusions regarding the paleodepositional environments of the

organic matters and oil samples depending on Pr / nC17 and Ph / nC18 ratios can be

seen in figure 5.1. The cross plot also shows that the organic matters in TT-04 are

relatively of higher maturity than the other studied sections.

Figure 5.2 shows the advantage of Pr / nC17 and Ph / nC18 ratios in

determining the types of kerogen. From the plot the same conclusions about the

types of kerogen that obtained using pyrolysis technique has been found out. The

kerogen type of the samples related to TT-04 seemed to be of more terrestrial source


)(

)(

)(

)(

2

1

3432302826

3331292725

3230282624

3331292725

CCCCC

CCCCC

CCCCC

CCCCCCPI

(type III) while the other samples including the oils appeared to be of more type II or

mixed between types II and III.

5.4.2 Carbon Preference Index (CPI):

Carbon Preference Index (CPI) is the ratio between the proportion of long chain

n-alkanes with an odd carbon number and the proportion of long chain n-alkanes with

an even number, measured in solvent extracts (Taylor et al., 1998), and generally is

presented by the following equation:

The CPI values decrease with increasing maturity down to about 1.5-1.0 in the

mature stage, but only for extracts of type II and III organic matters. Source rocks

with much algal and bacterial input (type I) behave differently because these

organisms do not generate a predominance of odd- numbered long chain n-alkanes

such as that occur in vascular plant waxes. In immature carbonates the CPI value

may be lower than 1.0 (Tissot and Wilte, 1984).

Moldowan et al. (1985: in Burgan and Ali, 2009) concluded that an odd carbon

preference is a characteristic of oil derived from source rocks deposited in non-

marine depositional environments. In contrast, the predominance of an even

numbered n-alkane preference is commonly observed in bitumens and oils derived

from carbonate or evaporite rocks (Palacas et al; 1984: in Burgan and Ali, 2009).

Oils and source rocks with CPI around 1.0 may arise from a predominance of

marine input and /or thermal maturation, while high CPI indicates low maturity (Taylor,

1998)

The CPI values of the two oil samples (Ja-25 and Tq-2) are less than 1.0 as

well as their Pr/Ph ratios indicating a mature condition, while most of the extracted

samples showed CPI above 1.0 (except one sample from TT-04at depth 1246-1368m

from Aaliji/Kolosh). The kerogen type of the studied samples being generally of a mix

origin (II and III) with mostly a marginal condition of maturation may be the reason

which caused the CPI values being not so interpretable regarding determining the

maturity of the studied samples.

The cross plot of Pr/Ph versus CPI (Fig.5.3) shows that the two oils and most

of the extracts fall into the field of more reducing condition. The cross plot also shows

some effects of oxidizing on few samples from KM-3. Anomalous high oxidizing effect


on one sample from TT-04 at depth 1448m can be observed reflecting it is

paleodepositional environment which shows a high Pristane input (Pr/Ph = 3.58).

Table (5.1): Ratios of Pr/Ph, Pr/ (Pr+Ph), Pr/nC17and Ph/nC18 and CPI (Carbon

Preference Index) for the analyzed extracts and oil samples.

Figure (5.1): Pr/nC17 versus Ph/nC18 cross plot, from which a mature, marine

source organic matter can be detected for the analyzed samples except

TT- 04 samples. (The plot after Shanmugam, 1985: in Younes and Philip,

2005)

Samples Depth (m) Pr/Ph Pr/ (Pr+Ph)

Pr/n-C17

Ph/n-C18

CPI

Ja-25, oil

1975

0.85

0.51

0.33

0.45

0.97

Tq-2, oil

600

0.79

0.46

0.44

0.63

0.97

TT-04

1246-1368

0.66

0.42

0.68

0.46

0.99

TT-04

1448

3.58

0.64

0.63

0.30

1.26

TT-04

1546

0.80

0.3

0.61

0.25

1.09

KM-3

2004

1.16

0.56

0.54

0.73

1.05

KM-3

2060

1.0

0.51

0.50

0.52

1.01

KM-3

2145

1.29

0.58

0.57

0.68

1.06

Ja-46

1736

0.61

0.4

0.66

0.91

1.23

Ja-46

1846

1.05

0.57

0.78

1.24

1.17

Ja-46

1862

0.58

0.38

0.80

0.87

1.10

Pu-7

1620-1689

0.80

0.45

0.45

0.47

1.05

Pu-7

1804

1.04

0.47

0.53

0.53

1.02

Pu-7

1820

0.91

0.48

0.44

0.47

1.02

10

1010.10.1

1

A Terrestrial SourceB Peat-Coal SourceC Mixed SourceD Marine Source

A

Oxidation

Reduction

Maturation BiodegradationBC

D

Ph / nC18

Pr

/ nC

17

Oil, Ja-25 Oil, Tq-2Ja-46, 1846m Ja-46, 1862mKM-3, 2145m

TT-04, 1546mPu-7, 1620-1689m Pu-7, 1804mJa-46, 1736m

KM-3, 2004m KM-3, 2060mTT-04, 1248-1368m TT-04, 1448m

Pu-7, 1820m


Figure (5.2): Pr/nC17 versus Ph/nC18 cross plot, from which kerogen type and

depositional environment can be detected for the analyzed samples.

(The plot after Ghori, 2000)

Figure (5.3): Cross plot of Pr/Ph versus CPI, from which the depositional environment

can be detected for the analyzed samples (The plot after Akinlua et

al.,2007b)

Ph

/nC18

0.1 0.2 0.5 1 2.0 5.0 10

0.1

1.0

10

5.0

Pr

/nC

17

Type I

IITyp

e II/I

IITyp

e II

ReducingOxidizing

0.2

0.3

0.5

2.0

3.0P

r/P

h

CPI10.90.8 1.1 1.2 1.3 1.4

1

2

3

4

MORE REDUCING

MORE OXIDIZING

0


TT-04, 1546mPu-7, 1620-1689m Pu-7, 1804mJa-46, 1736m

KM-3, 2004m KM-3, 2060mTT-04, 1248-1368m TT-04, 1448m

Pu-7, 1820m


TT-04, 1546mPu-7, 1620-1689m Pu-7, 1804mJa-46, 1736m

KM-3, 2004m KM-3, 2060mTT-04, 1248-1368m TT-04, 1448m

Pu-7, 1820m


5.4.3 Steranes and Diasteranes:

Steranes are a class of tetracyclic, saturated biomarkers constructed from six

isoprene subunits (nearly C30). They originate from sterols, which are important

membrane and hormone components in eukaryotic organisms. Most commonly used

steranes are in the range of C26-C30 and are detected using mass/charge 217 mass

chromatograms (Peters et al., 2005).

Diasterane (rearranged sterane) is the rearrangement product from sterol

precursors through diasteranes. The rearrangement involves migration of C-10 and

C-13 methyl groups to C-5 and C-14 and it is favored by acidic conditions, clay

catalysis, and/or high temperatures (Peters et al., 2005).

The presence of diasteranes provides information on both the lithology of the

source rocks responsible for generation of the crude oil, and nature of the

depositional environment. Another important factor to remember is that these

molecules are not planar, but very specific 3D conformations. What makes them

particularly useful from a geochemical perspective is the fact that the shape of the

molecules will vary as a result of maturity (Philp, 2003b).

The distribution of 4-methyl steranes can provide clear evidence for the

importance of algal-derived organic matter. The presence of the four major isomers

of dinosterane as well as 24-ethyl-4-methyl C30 steranes is usually associated with

marine depositional environments. High diasterane abundance is often taken as

evidence that the oil was derived from clastic source rocks containing clay which

catalyses the steroid backbone re-arrangement (Ensminger et al., 1978: in Bacon et

al., 2000).

5.4.3.1 C27, C28, and C29 Regular Steranes Ternary Plot:

An example of organic matter input is the distribution of C27, C28, and C29

steroles from eukaryotic organisms that reaches the sediment from an overlying

water column. This initial distribution of sterols might be altered by many diagenetic

factors during and after sedimentation, but ternary plots of the relative amounts of

C27, C28, and C29 steranes largely reflect original source input (Peters et al., 2005).

The ternary diagram of C27-C28-C29 sterane compounds from the oils and

sources are frequently used to identify the type or origin of the initial organic matters.

The main sources of C27 steranes are marine origin and that of C29 steranes which

are mostly the inputs from advanced plants. C28 steranes consist of a mix of

advanced plant and algae (Bachir et al., 2006).


High C29 sterane abundances are usually associated with source rocks

containing primarily higher plant organic matters (Huang and Meinschein, 1979;

Volkman, 1988b: both in Bacon et al., 2000). A predominance of C27 steranes and

only slightly lower abundances of C28 steranes and C29 steranes is typical of oil

derived from marine algal source rocks (Bacon et al., 2000).

The high value of C27 steranes (40.0%-45.6%) relative to C28 steranes(25.5%-

20.5%) and C29 steranes(34.5%-33.9%) for the analyzed two oil samples of Ja-25

and Tq-2 respectively (table 5.2), indicated that both oils are derived from marine

algal source rocks. The same is true with the extract sample from the depth 1736m in

Ja-46, while other samples from KM-3 and Pu-7 show a clear mixed origin of organic

matters.

The suggested ternary plot of Moldowan et al. (1985: in Peters et al., 2005)

shows that the relative amounts of C27, C28, and C29 steranes for any analyzed oil

and extract samples can be helpful in determining the marine or non-marine,

carbonate or shale source environments (Fig.5.4).

Using the mentioned ternary in this study approved that most of the analyzed

samples are from a marine origin.

According to the ternary of Huang and Meinschein (1979: in Wan Hasiah and

Abolins, 1998) the analyzed oil and extract samples are generally from open marine

depositional environment (Fig.5.5).


Table (5.2): The percentage of the C27, C28, and C29 Sterane C27, C28, and C29 Diasterane

and Diasterane/Sterane ratio for the analyzed oil and extract samples.

Figure (5.4): Ternary plot of the relative amounts of C27, C28, and C29 steranes for the

analyzed oil and extract samples. (The ternary from Moldowan et al., 1985

: in Peters et al., 2005).

oil and

Sterane

(217 m/z)

Diasterane (217 m/z)

Diasterane/ Sterane (217m/z)

Samples Depth (m) C27 % C28% C29 % C27% C28% C29 %

Ja-25,oil 1975 40.0 25.5 34.5 32.6 53.7 13.7 0.30 Tq-2,oil

600

45.6

20.5

33.9

26.7

57.4

15.9

0.34

KM-3

2060

32.3

34.3

33.5

36.3

49.4

14.3

0.23

Ja-46

1736

41.7

23.6

34.7

39.4

45.3

15.4

0.33

Pu-7

1804

35.5

28.7

35.8

24.5

59

16.5

0.09

Pu-7

1820

35.9

28.7

35.5

24.3

60.1

15.6

0.08

100

70

60

40

30

20

10

90

60

30

20

10

10203050

60

708090 100

C28

Marine shale

Non-marine shale

Marine carbonatesMarine > 350 M.Y.

C2940

40

50

70

80

100%

50

C27

80

90

Oil, Ja-25 Oil, Tq-2 Pu-7, 1804m Pu-7, 1820mJa-46, 1736mKM-3, 2060m


Figure (5.5): Ternary plot of the relative amounts of C27, C28, and C29 steranes from

which the source input and depositional environment can be detected

for the analyzed samples (The ternary from Huang and Meinschein,

1979: in Wan Hasiah and Abolins, 1998).

5.4.3.2 Diasteranes / Steranes Ratio:

The diasterane/sterane ratio indicates a clay-rich environment (Hughes, 1984: in

Fildani et al., 2005). It has recently been shown that the diasterane/sterane ratio is

determined by the ratio of clay to TOC, rather than to clay content (van Kaam-Peters

et al., 1998: in Bacon et al., 2000). This provides an explanation for the high

diasterane content found in some carbonate rocks.

The diasteranes/steranes ratios are commonly used to distinguish petroleum

from carbonate versus clastic source rocks and can be used to differentiate mature

from highly mature oils (Youns and Philip, 2005).

High diasteranes / steranes ratios are typical of petroleum derived from clay-

rich source rocks and in some crude oils can result from high thermal maturity

(Seifert and Moldowan, 1979) and/or heavy biodegradation (Peters et al., 2005).

The low diasteranes / steranes ratio in oils indicate anoxic clay-poor carbonate

source rock (Eglinton et al., 2006: in Muhayldin, 2008).

C29

C28

10080 70 60 50 40 30 20 10

10

20

30

40

50

60

70

80

90

100%

10

20

30

40

50

60

C27

70

80

90

100 90

Plankton

OpenMarinee

HigherPlant

Lacustrine

Estuarialor

bayTerrestrial



In this study, the low ratios of diasteranes / steranes for the two oil samples

(0.30

0.34) and the extracts (0.08-0.23) (Table 5.2) indicated that they were derived

from anoxic clay-poor carbonate source rocks.

According to Moldowan et al. (1994a: in Peters et al., 2005) Pr/ (Pr+Ph) and

C27 diasteranes/ (diasteranes+steranes) show a positive relationship which is

controlled by the depositional environments. Pr/ (Pr+Ph) increases with clay content,

as measured by increasing diasteranes, which parallels oxidative strength (Eh) of the

water column during deposition of rocks. By using values listed in table (5.3) for

different biomarker ratios, a cross plot between Pr/ (Pr+Ph) and C27

diasteranes/(diasteranes+ regular steranes) has been drawn (Fig. 5.6) to determine

the source of the organic matters for the extracts and the two oil samples which

appeared to be deposited under anoxic condition in a carbonate dominant

environment.

Cross plot of C27 / C29 diasterane versus C27 / C29 sterane on the other hand

also indicated the marine to mix origin of the analyzed samples (Fig. 5.7).

Pr/Ph versus C29 / C27 cross plot (Fig. 5.8) provided another indication about

the anoxic condition of deposition for the analyzed oils and extracts with a

contribution from algal origin of organic matters.

Table (5.3): Ratios of different biomarkers which have been used in detecting the

source and depositional environment for the analyzed oil and extract

samples.

Samples Depth (m)

C27/C29

Ster. (217) m/z)

C27/C29

Dias. (217 m/z)

C29/C27

Ster. (217 m/z)

C27

Dias./ (Dias. + Ster.)

(217 m/z)

Ster./

Hop.

Ts/ (Ts+Tm) (191m/z)

Ster. Index

(218m/z)

Ja-25, oil

1975

1.16

2.4

0.86

0.11

0.60

0.24

3.42

Tq-2, oil

600

1.3

1.7

0.77

0.09

0.31

0.32

3.85

KM-3

2060

0.96

2.5

1.04

0.07

1.02

0.21

4.45

Ja-46

1736

1.2

2.6

0.83

0.12

0.45

0.24

3.86

Pu-7

1804

0.99

1.5

1.01

0.04

0.28

0.17

3.68

Pu-7

1820

1.0

1.6

1

0.03

0.25

0.17

3.69


Figure (5.6): Pr/ (Pr+Ph) versus C27 Diasteranes/ (Diasteranes+ regular Steranes) cross

plot, from which anoxic carbonate environment has been detected for the

analyzed samples.(The cross plot is from Peters et al., 2005).

Figure (5.7): C27/C29 Diasteranes versus C27/C29 Steranes cross plot shows a marine

to mix depositional environment for the analyzed oil and extract samples

(The cross plot is from Ghori, 2000).

2.0

Terrestrial

Mixed

Marine

C27 / C29 Steranes

C27

/ C

29 D

iast

eran

es

0.0 0.5 1.0 1.5

0.5

1.0

1.5

2.0

2.5

0.0



0.2 0.3 0.4 0.5 0.6 0.7

0.55

Pr

(Pr

+ P

h)

C27 Dia./(Dia.+Reg. Ster.)

0.50

0.65

0.60

0.75

0.70 AnoxicShales

AnoxicCarbonates

Suboxicstrata

0.45

0.400.0 0.1


Figure (5.8): Cross plot of Pr/ Ph versus C29/ C27 sterane showing the anoxic condition

of deposition for the analyzed samples (The cross plot from Othman

et al.,2001).

5.4.3.3 C30 Sterane Index [C30/ (C27-C30) Steranes]:

The presence of C30 steranes (identified as 24-n-propylcholestanes) is a good

indication of a marine contribution, but their absence may not always be source

related (Moldowan et al., 1990), however, Holba et al., (2000) corresponded values

of zero for C30 Sterane ratio to non-marine oils.

The C30 sterane ratios generally increase with marine versus terrigenous

organic matter input to the source rock (Peters et al., 2005), and it is presence in

crude oil is the most powerful means in order to identify the input of marine organic

matter to the source rock (Peters et al., 1986: in Peters et al., 2005).

As 3.42 to 4.45 is the range of C30 sterane index for the analyzed extracts and

oil samples, accordingly they must be sourced mostly from marine origin organic

matters.

5.4.4 Gammacerane Index:

The Gammacerane index is expressed as the ratio of gammacerane/

gammacerane+17 (H), 21 (H)-hopane (Peters and Moldowan, 1991: in Abboud et

al., 2005). Source rock deposited in stratified anoxic water columns ''commonly

hypersaline'' and related crude oils commonly have high gammacerane indices

(gammacerane / hopane) (Abboud et al., 2005).

10.001.000.10

C29/C27 Sterane

Pr/

Ph

0.0

2

4

6

8

10

100.00

Anoxic

Oxic

Land Plant

Algal



Hypersaline lakes and ponds often develop anoxic conditions if saline deep

water is covered with water of lower density. Sedimentary rocks that were deposited

under these conditions often contain high relative concentrations of gammacerane,

which is a biomarker generally associated with water column stratification (Sinninghe

Damste et al., 1995: in Broock and Summons, 2004). However, as water column

stratification occurs under other conditions as well, gammacerane is also often

abundant in fresh water sediments (Grice et al., 1998: in Broock and Summons,

2004).

Gammacerane is generally associated with increasing salinity of the

depositional environment, both marine and lacustrine environments (Peters and

Moldowan, 1993: in Abboud et al., 2005).

No hypersaline condition of deposition for the initial organic matters within the

analyzed samples has been detected as their gammacerane index values were

generally low (between 0.07 and 0.14) (Table 5.4).

Higher salinity is typically accompanied by density stratification and reduced

oxygen content in bottom waters (i.e. lower Eh), which results in lower Pr / Ph (Peters

et al., 2005).

The cross plot of gammacerane index versus Pr / Ph ratio (Fig. 5.9) shows

that all extracts and the two oil samples were deposited under marine depositional

environment and that depending on the comparison of the results with the diagrams

of peters et al., (2005).

Table (5.4): The ratios of Gammcerane Index of the analyzed two oil samples and extracts.

Samples Depth (m)

Gammcerane

Index (191m/z)

Ja-25,oil

1975

0.14

Tq-2,oil

600

0.14

KM-3

2060

0.07

Ja-46

1736

0.12

Pu-7

1804

0.10

Pu-7

1820

0.11


5.4.5 Terpanes:

The m/z 191 mass chromatogram illustrates terpanes, which are primarily

derived from bacteriohopanetetrol, a cell wall rigidified in prokaryotic organisms

(Peters and Moldowan, 1993: in Osadetz et al., 2004).

Mukhopadhyay (2004) mentioned that those biomarker compounds that refer

to the terpanes are mainly derived from bacterial (prokaryotic) membrane lipids.

Philp and Gilbert (1986: in Osuji and Antia, 2005) indicated that extended

tricyclic terpanes were abundant in marine sourced oils but generally absent in

terrigenous oils.

Carbonate dominated sediments tend to be deposited in low latitude

environments and therefore the biomarkers for organisms that preferentially colonize

warm water tend to be important signatures in these sediments. Cyanobacteria 2a-

methylhopanes (Summons et al, 1999: in Bocks and Summons, 2004) and 30-

norhopanes (Subroto et al., 1991: in Broock and Summons, 2004) are generally

elevated in bitumen from carbonates and marl.

Hopanoide appears to be similarly affected so that diahopanes and

neohopanes are relatively more prominent in bitumen and oils derived from shales as

opposed carbonates (Peters and Moldowan, 1993: in Broock and Summons, 2004).

The ratios of C22/C21 can help to identify extracts and crude oils derived from

different source rocks. Generally, oils from carbonate source rocks can be

Figure (5.9): Gammacerane Index versus Pr / Ph ratio for

the analyzed oil and

extract samples. (The cross plot is from Peters et al., 2005).

0.0

Pr/ Ph

Gammacerane Index %

0.85

0.90

0.95

1.00

1.05

0.80

0.75

0.70

0.65

0.05 0.2 0.25 0.3

0.150.1 0.35



distinguished by high C22/C21 tricyclic terpane with low of C24/23 tricyclic terpane


As shown in table 5.5 the C22/C21 tricyclic terpane of the studied samples (oils

and extracts) are generally high (0.50 to 0.86) in comparison to their ratios from

C24/23 tricyclic terpane 0.3 to 0.43 indicating carbonate origin source rocks for all of

them.

The C25/C26 tricyclic terpane ratio is used to distinguish the marine and non-

marine environments (Burwood et al., 1992 and Hanson et al., 2000: both in Gulbay

and Korkmaz, 2008). The values higher than 1.0 indicate marine environment,

whereas the low values a non-marine environment. In this study, the C25/C26 tricyclic

terpane ratios of the two oils and all extracted samples are higher than 1.0 (Table 5.5)

indicating that the deposition occurred in marine environments.

Table (5.5): The ratios of different Terpanes for the analyzed two oil samples and

extracts.

From the cross plot of tricyclic terpanes C22/C21 ratios versus tricyclic terpanes

C24/C23 ratios for the analyzed extracts and oil samples (Fig. 5.10), a great similarity

can be observed with the analyzed extracts and oil samples of carbonate origin

worldwide by Geo Mark Research Inc. (2000: in Peters et al., 2005).

Norhopane / hopane (C29H/C30H) versus C35 / C34 hopane ratio for the

analyzed extracts and oil samples shows deposition in the carbonate dominant

environment under anoxic condition (Fig. 5.11).

Sletten (2003) mentioned that a high hopane/sterane ratio indicates terrestrial

input, while low ratios are typical for marine derived petroleum. According to his cross

plot (Pr/Ph ratio versus hopane/ sterane ratio) all the analyzed samples appeared to

be of marine source organic matters (Fig.5.12).

Samples Depth (m)

Hop./ Ster.

C29H/ C30H

(191m/z)

C35H/ C34H

(191m/z)

Tricyclic Terpanes (191 m/z)

C22/

C21

C24/

C23

C25/

C26

Ja-25,oil

1975

1.67

1.44

1.07

0.52

0.41

1.25

Tq-2,oil 600 3.23 1.51 1.04 0.7 0.36 1.35 KM-3

2060

0.98

1.15

1.16

0.5

0.43

1.32

Ja-46

1736

2.22

0.89

0.90

0.58

0.39

1.2

Pu-7

1804

3.57

1.55

1.07

0.86

0.3

1.39

Pu-7

1820

4

1.51

1.11

0.84

0.3

1.47


0 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.2 1.4Tricyclic Terpane C22 /C21

Tri

cycl

ic T

erpa

ne C

24 /C

23

0.10

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Figure (5.10): Tricyclic terpanes C22/C21 versus Tricyclic terpanes C24/C23 ratios for the

analyzed oil and extract samples. Such a relationship indicates a marine

carbonate source. (The cross plot is from Peters et al., 2005)

Figure (5.11): C29H/C30H versus C35H/C34H ratios shows the influence of anoxicity and high carbonate content in the marine environment for the analyzed oils

and extract samples.


0

0.4

0.8

1.2

1.6

2.0

C35H / C34H

C29

H /

C30

H

0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

Car

bona

te c

onte

nt

Anoxic condition



0 0.2 0.4 0.6

Pristane / Phytane

Hop

ane/

Ster

ane

0.8 1.0 1.05

Marine

Terrestrial

0

2

4

6

8

Figure (5.12): Cross plot between Pr/Ph ratio and hopane/sterane ratio indicating a

marine source of the analyzed extracts and oil samples.

(The diagram from Sletten, 2003)

5.4.6 Ts/ (Ts+Tm):

Ts (18 (H) 22, 29, 30 trisnorneohopane) and Tm (17 (H) 22, 29, 30

trisnorhopane) are specific types of trisnorneohopanes (Peters et al., 2005).

The Ts/ (Ts+Tm) is commonly used as a maturity parameter for oils of very

homogenous sources (Seifert and Moldowan, 1978) as well as oil samples

representing the same facies (Jones and Philp, 1990: in Lehne, 2008).

Bakr and Wilkes (2002: in Lehne, 2008) mentioned that the biomarker

parameter Ts/(Ts+Tm) is controlled by variations of facies and the depositional

environment, but not by maturity.

The source rock lithology may influence the variability of Ts/ (Ts+Tm) (Bakr

and Wilkes, 2002: in Lehne, 2008). Riva et al. (1989: in Lehne, 2008) have

demonstrated that the Ts/ (Ts+Tm) ratio decreases as the proportion of shale in

calcareous facies decreases, this leads to very low Ts/ (Ts+Tm) ratios in carbonate

source rocks.

Ts/ (Ts+Tm) ratio for the four extracts and the two oil samples are generally

low and less than 1.0 (Table 5.6) indicating sources derived from carbonates rather

than shales or clastics.



The cross plot of Ts/ (Ts+Tm) ratio versus CPI (Fig.5.13) show no clear

negative or positive proportionate between the two parameters indicating that not

only the source of organic matters may affect the ratios but also other factors like

maturity.

Table (5.6): Ratios of Ts/ (Ts+Tm) and CPI for the analyzed oil and extract samples.

Figure (5.13): Cross plot of CPI versus Ts/ (Ts+Tm) (The cross plot from Mello et al.,

1988: in Mohyldin, 2008)

5.4.7 Oleanane:

Oleananes are diagenetic alteration products of oleanane and taraxerene

precursors (Haven and Rulkotter, 1988: in Moldowan, 1994b), which is concentrated

among the angiosperm (flowering plants) (Das and Mahato, 1983 in Moldowan,

Samples Depth (m) Ts/ (Ts+Tm)

(191m/z) CPI

Ja-25, oil 1975 0.24 1.02

Tq-2, oil 600 0.32 0.97

KM-3 2060 0.21 1.01

Ja-46 1736 0.24 1.23

Pu-7 1804 0.17 1.02

Pu-7 1820 0.17 0.97

0.40 0.60 0.80 1.00 1.20 1.40

0.25

Ts/

(Ts+

Tm

)

CPI

0.20

0.35

0.30

0.45

0.40

0.15

0.100.0 0.20



1994b), in rock extracts and petroleum are also though to derive from angiosperm

(Whitehead, 1970: in Moldowan, 1994b).

Oleanane generally does not occur in rocks or oils prior to the angiosperm

diversification on land that occurred during the Late Cretaceous. Oleanane/hopane

ratios over 20% are characteristics of Tertiary source rocks and oils. On the other

hand, oleanane can be absent in source rocks deposited far from angiosperm input

(Burgan and Ali, 2009).

In this study, the analyzed oil sample was of no oleanane content. Such a

condition is always interpreted as either the oil is from sources older than the

Cretaceous, or it is from a source with no angiosperm content.

5.4.8 Dibenzothiophene(DBT)/Phenantheren:

A broad distinction between fresh water and marine environments can be

obtained from the relative abundance of S-containing compounds; the greater

abundance of these compounds in marine sediments being related to the sulphate

content of sea water and the activity of sulphate reducing(Killops and Killops, 2005).

Pr/Ph ratio versus DBT/Phenantheren values (table.5.7) can help to distinguish

between some marine and fresh water environments (Hughes et al., 1995: in Killops

and Killops, 2005).

Plotting the Pr/Ph ratio versus DBT/Phenantheren (Fig.5.14) showed that the

two oil samples are of mixed marine and lacustrine sulphate-rich environments, while

the organic matters within the two rock samples from KM-3 at depth (2060m) and Pu-

7 at depth (1804m) appear to be deposited in mixed marine and lacustrine, sulphate

poor environment.

Table (5.7): The Pr/Ph ratio and DBT/Phenantheren for the analyzed oil samples

and two extracts from KM-3 and Pu-7.

Samples Depth (m) Pr/Ph DBT/Phenanthrene

Ja-25, oil 1975 0.85 2.17

Tq-2, oil 600 0.79 1.95

KM-3 2060 1.0 0.31

Pu-7 1804 1.04 0.79


Figure (5.14): Cross plot between Pr/Ph ratio and DBT/Phenantheren marine source of

the analyzed extracts and oil samples (The diagram after Hughes et al.,

1995: in Killops and Killops, 2005).

5.5 Maturation Determination using Biomarkers:

In the same way that certain biomarkers have been used to characterize

source materials and depositional environments, selected biomarkers have been

used to evaluate the relative maturity of suspected source rocks and the oils that may

have generated.

The biomarker ratios can be particularly important in samples that may not

contain vitrinite, preventing the determination of vitrinite reflectance value. In addition,

these parameters permit measurements of relative maturity for oils as well as rocks,

something not possible with Vitrinite Reflectance, Thermal Alteration Index (TAI), or

Spore Color Index (SCI) (Philp, 2003a). The thermal break-down of kerogen to form

oil during catagenesis results in significant changes in the biomarkers that enable

them to be used for source-rock evaluation. (Osuji and Antia, 2005)

The role of Pristane/nC17 and phytane/nC18 ratios (Fig.5.1) and CPI as

maturation indicators has been discussed previously; therefore, they will not be

repeated in this section.

DB

T/P

hena

nthr

ene

Pr/Ph210 3 4 5 6

1

2

3

4

5

Zon

e 1A

Zon

e 1B

Zone 2 Zone 3 Zone 4

Zone(1A) marine(carbonate)Zone(1B) marine+sulphate-rich lacustrine carbonate+mixed)

Zone(3) marine+lacustrine (shale)Zone(2) sulphate poor lacustrine (variable)

Zone(4) fluvio-deltice(organic -rich shale+coal)

Oil, Ja-25 Oil,Tq-2 KM-3, 2060m Pu-7,1804m


5.5.1 Sterane and Diasterane:

At high levels of thermal maturity, rearrangement of steroids to diasterane

precursors may become possible, even without clays, due to hydrogen-exchange

reactions, which are enhanced by the presence of water (Van Kaam-Peters et al.,

1998: in Peters et al., 2005). Alternatively, diasteranes simply may be more stable

and survive thermal degradation better than steranes.

The ratio of 5 (H),14 (H),17 (H) to 5 (H),14 (H),17 (H)-steranes

(abbreviated to / ) is often used as an index of thermal maturity, but most

crude oils have similar proportions of these isomers which limit the use of this ratio in

environmental studies. A ratio of 20S and 20R isomers of about 1.0 is considered

typical of mature crude oils. A high abundance of C21 and C22 steranes relative to

C27

C29 steranes is typical of oil generated at high thermal maturities (Bacon et al.,

2000).

The ratios of S/(S+R) C29 Sterane ( ), and S/ ( + R) C29 ST for the

analyzed extracts and two oil samples from Ja-25 and Tq-2 are all less than 1.0

(Table 5.8) indicating low mature stage of the organic matters, but by observing the

mentioned ratios it is clear that the oil of Tq-2 has the higher ratio among them which

means that it is relatively of the highest maturity between the analyzed samples.

The cross plot of S/(S+R) C29 ST ( ) versus S/( S+ R) C29 ST, (Fig.

5.15) also shows a higher maturity of the oil sample from Tq-2 in comparison to the

oil of Ja-25 and the extract samples.

5.5.2 Ts / (Ts + Tm):

The cross plot of Ts / (Ts +Tm) versus C27 Dia. / (Dia. + Reg. Sterane) (Fig. 5.16)

(the used values are listed in tables 5.3 and 5.6) reflects the effect of thermal maturity

on the analyzed samples especially the oil sample of Tq-2. As it is appears from the

cross plot, the C27 Dia. / (Dia. + Reg. Sterane) ratio do not show a significant

increase as maturity increases and that may be due to it is less sensitivity to

maturation in comparison to Ts / (Ts +Tm), or due to the sources of organic matters

which have their own effect on the initial ratio of C27 Dia. / (Dia. + Reg. Sterane).

5.5.3 Hopanes:

Shen and Huang (2007) observed that the ratio of normoretane to norhopane

decreases with increasing maturity (from 0.85 at maturity around 0.4% to 0.1 at

0.78% Ro).The cross plot from Jonson et al. (2003) between Ts/(Ts+Tm) and C29


S /( S+ R)% C29ST

moretane index (Fig.5.17) indicates the slight maturity of the extracts from KM-3, Pu-

7, and Ja-46 especially from their Ts / (Ts +Tm) content, while the oil sample from

Ja-25 shows a higher maturity stage, but the highest maturity level has been shown

by the oil sample from Tq-2.

The ratios of H32 22S/ (22S+22R) homohopane for the analyzed extract

samples ranged between 0.48 and 0.60 indicating a main phase of oil generation,

with a slight increase of maturity for the oil sample from Tq-2 in comparison to

sample of Ja-25.

Table (5.8): The ratios of some maturity parameters for the analyzed oil and extract.

Figure (5.15): S/(S+R) C29ST ( )

versus S/ ( S+ R) C29ST ratios as indication of

maturity for the analyzed samples. (The cross plot is from Sletten, 2003)

Samples Depth (m)

S/(S+R) C29ST ( )

(217m/z)

S/( S+R)

C29ST (217m/z)

H32 S/(S+R) Homohopane

(191m/z)

C29

Moretane Index

Ja-25,oil 1975 0.37 0.40 0.58 0.11

Tq-2,oil 600 0.46 0.54 0.59 0.09

KM-3 2060 0.20 0.17 0.55 0.15 Ja-46 1736 0.22 0.26 0.48 0.28

Pu-7 1804 0.40 0.34 0.60 0.09

Pu-7 1820 0.37 0.33 0.60 0.09

0.3 0.4 0.5 0.60.25

Maturity

S/(S

+R)%

C29

ST

0.20.15 0.35 0.45 0.550.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5



Figure (5.16): Ts/ (Ts+ Tm) versus C27Dia / (Dia+ Reg. Steranes) cross plot for the

analyzed oil and extract samples. (The cross plot is from Peters et al.,

2005).

Figure (5.17): cross plot of Terpane maturity parameters (After Johnson et al.,

2003) indicating different stages of maturity of the studied samples.

0.1

C29Moretane Index

Incr

easin

gM

atur

ity

Ts/

(Ts+

Tm

)

0.2

0.3

0.4

01 0.8 0.6 0.4 0.2 0



0.2 0.3 0.4 0.5 0.6 0.7

0.25

Ts/

(Ts+

Tm

)

C27 Dia/(Dia+Reg. Steranes)

0.20

0.35

0.30

0.45

0.40

0.15

0.10

0.0 0.1

Matu

rity


5.6 Petroleum Biodegradation:

The quality of petroleum is mainly influenced by its gravity and viscosity which

depend greatly on maturity and biodegradation of oil. Biodegradation modifies oil

properties and its chemical composition inducing the diminution of it is API gravity

which is used as oil quality factor in petroleum industry. A strong deterioration of

petroleum quality occurs from slight to moderate biodegradation (Wenger and Davis,

2001: in Abbas et al., 2008).

The biodegradation increases the relative content of resins and asphaltenes,

metals (like vanadium and nickel) and sulfur by selectively removing saturate and

aromatic hydrocarbons (Abbas et al., 2008).

Biodegradation may be caused by aerobic bacteria when there is an access

to surface recharge waters containing oxygen in a temperature range below 65?C

75?C. In deep reservoirs, in which meteoric recharge appeared infeasible, anaerobic

bacteria are considered of prime importance (Peters and Moldowan, 1993: in Abbas

et al., 2008). However, not all low-temperature reservoirs contain degraded

petroleum. This may be because they have either been recently charged with fresh

oil or they have been uplifted from deeper, hotter subsurface regions (Head et al.,

2003).

Petroleum oil biodegradation by bacteria can occur under both oxic and anoxic

conditions (Zengler et al., 1999: in Okoh, 2006), even though by the action of

different consortia of organisms. In the subsurface, oil biodegradation occurs

primarily under anoxic conditions, mediated by sulfate reducing bacteria (Holba et al.,

1996: in Okoh, 2006).

Many genera of microbes are able to completely oxidize alkanes and to a

lesser extent, aromatic hydrocarbons (Jackson, 1996: in Enock, 1998). Based on

previous studies and reviews on biodegradation of petroleum hydrocarbons in the

marine environment, several generalizations can be made (Atlas, 1988; Jackson,

1996; Harayama et al., 1999: all in Enock, 2002):

Straight chain aliphatic hydrocarbons are easier to be degraded than branched

chain aliphatic hydrocarbons.

Aliphatic hydrocarbons are degraded more easily than aromatic hydrocarbons.

Saturated hydrocarbons are more easily degraded than unsaturated hydrocarbons.

Long chain aliphatic hydrocarbons are more easily degraded than short chain

(<C10) hydrocarbons, with few exceptions, since the latter are essentially toxic to

microorganisms.


Asphaltenes (and resins) are the most recalcitrant fractions in the crude oil.

5.6.1 Controls on Petroleum Biodegradation:

The biodegradation of petroleum and other hydrocarbons in the environment is

a complex process, whose quantitative and qualitative aspects depend on the type,

the nature, and amount of the oil or hydrocarbon present; in addition to the ambient

seasonal environmental conditions [such as temperature, oxygen, nutrient, water

activity, salinity, and acidity (pH)], and the composition of the allochthonous microbial

community (Wang et al., 2006).

The aerobic and anaerobic biodegradation mechanisms are still not fully

understood. The following conditions appear to be necessary for biodegradation of

large volumes of oil at the pool or field scale (Connan, 1984; Palmer, 1993; Blanc

and Connan, 1994: all in Peters and Fowler, 2002):

1. The reservoir temperature must be less than about 60 80°C, which corresponds to

depths shallower than about 2000m under typical geothermal gradients.

Biodegradation occurs at higher temperatures, but the rate decreases significantly.

2. There must be sufficient access to nutrients and electron acceptors (e.g. molecular

oxygen, nitrates, and phosphates) most likely through circulation of meteoric water

into deeper portions of the basin.

3. The reservoir must lack H2S for aerobic microbes or contain no more than about

5% H2S for anaerobic sulfate reducers to be active.

4. Salinity of the formation water must be less than about 100 150 parts per

thousand.

5.6.2 The Rate of Reservoir Oil Compositional Degradation:

The rate of biodegradation is not well known. Empirical evidence from surface

or near-surface oil spills suggests that biodegradation occurs relatively quickly in

environments that are at least partially aerobic with plentiful nutrients (Jobson et al.,

1972: in Peters and. Fowler, 2002); while degradation of oil in deep reservoirs is very

slow (Larter et al., 2000: in Peters and Fowler, 2002).

There is an extensive literature on the effects of biodegradation on crude oils

in reservoirs. Most works on hydrocarbons have focused on the C12+ fraction of oils,

which are known to have differing susceptibilities to biodegradation (Peters and

Moldowan, 1993: in George et al., 2002)

The composition of crude oils can be radically altered as a result of physical,

chemical and microbiological influences within the reservoir. In low temperature <

90°C environments, meteoric water influx can result in the selective removal of


gasoline range components and alkanes relative to asphaltenese and

heterocompounds through the agencies of biodegradation and water washing

(Connan, 1984: in Horsfield et al., 1992).

In general, the oxidation of oil during subsurface biodegradation leads to a

decrease in API gravity, saturated hydrocarbon and, to a lesser extent, aromatic

hydrocarbon content, whereas oil density, sulfur content, oil acidity, viscosity, and

metal content increase (Evans et al., 1971; Meredith et al., 2000; Wenger et al.,

2001: all in Larter et al., 2006). This alteration has a negative impact on oil production

(reduced well flow rates); refining operations "acidity" (Tomczyk et al., 2001: in Larter

et al., 2006) and oil value (lower API gravity, higher sulfur and metal content etc.).

Diasteranes are particularly resistant to biodegradation. Evidence suggests

that the C27-C29 steranes are destroyed completely before diasterane alteration

(Requejo et al., 1989: in Peters et al., 2005). As diasteranes are more resistant to

biodegradation than most other common saturated biomarkers, they have been used

as internal standard to measure the comparative loss of less resistant biomarkers.

(Seifert and Moldowan, 1979)

Many biodegraded oils contain abundant 25-norhopanes, and high abundance

is evidence for severe biodegradation (rank equal or more than 6) (Trendel et al.,

1990: in Peters et al., 2005). On the other hand, hopanes can be biodegraded after

steranes. Typically, such oils lack 25-norhopanes.

Heavy biodegradation can result in selective destruction of steranes relative to

diasteranes. However, it is possible for non-biodegraded oil to mix with heavily

biodegraded oil showing a much higher diasteranes/steranes ratio. In such cases,

only careful quantitative assessment of each biodegradation-sensitive parameter can

lead to the correct interpretation (Peters et al., 2005).

The relative level of degradation is based partially on changes in bulk

chemical and physical properties and partially on the principle of sequential

catabolism (Peters et al., 2005). The effects of various levels of biodegradation on

the composition of typical oil which ranked from 1 to 10 was proposed by Wenger et

al. ( 2001) which was modified by Head et al. (2003) (Fig.5.18).

5.6.3 Biodegradation effect on the analyzed oils of Tq-2 and Ja-25:

From the results of the GC and GC/MS analysis for the two oil samples of Tq-

2 and Ja-25 an attempt has been made to follow the effects of biodegradation on the

two oils, especially the oil of Tq-2 from the U. Eocene Pila Spi reservoir which is

known to be relatively a heavy oil (nearly 24 API).


Figure (5.18): A schematic diagram of physical and chemical changes occurring

during crude oil and natural gas biodegradation (Arrows indicate

where compound classes are first altered (dash lines), substantially

depleted(solid grey), and completely eliminated (black).

(The diagram from Wenger et al., 2001: in Head et al., 2003)


The values of the parameters which indicate the effects of biodegradation on

oils show different results about the actual effect of biodegradation on the oil of Tq-2.

The following is a summary of the parameters and cross plots which were

depended on to show whether biodegradation occurred or not for the analyzed oil

samples:

1. Akinula et al. (2007a) observed, during their geochemical study of oil samples

from an onshore field in the Niger Delta, that the degraded and non degraded

oils show differences in their methylphenanthrene (MP) ratios, as values of

(1MP + 9MP) versus (2MP + 3MP) within a cross plot discriminated the two

groups of oil obviously. Values of (1MP + 9MP) and (2MP + 3MP), shown in

table (5.19), have been used in figure 5.19 in which the oils of Tq-2 and Ja-25

located within the degraded oil area of Akinula et al s plot.

Table (5.9): (1MP + 9MP), (2MP + 3MP), and Trimethylnaphthalene (TMN) values

of the two oil samples of Ja-25 and Tq-2.

2. The ratio of Pr/nC17 and Ph/nC18 also can help in determining the effect of

biodegradation, as generally the high ratio of these two parameters in any oil

indicates the effect of biodegradation with low maturity state. Figure (5.1)

(cross plot Pr/nC17 versus Ph/nC18) showed no obvious effect of

biodegradation on the two studied oil samples.

3. Mango (1994) proposed a ternary between P1, P2, and P3 based on C7 data

to show the effect of biodegradation on the oils or extracts. In this ternary P1

represents the straight chain C7 n-alkane; P2 represents mono-branched C7s;

while P3 includes the poly-branched C7s. Plotting the triple P values of Tq-2

and Ja-25s oil values (Table 5.10) in Mangos ternary (Fig. 5.20) a slight

biodegradation has been observed for the oil of Tq-2.

Table (5.10): P1, P2, and P3 values of the two oil samples of Ja-25 and Tq-2

Oil sample Depth/m 1MP+ 9MP

(ppm) 2MP+ 3MP

(ppm) TMN

(ppm) Ja-25,oil 1975 828.5 797.9 4463.4 Tq-2,oil 600 470.4 385.4 1787

Oil sample Depth/m. P1 P2 P3 P1 % P2% P3%

Ja-25,oil 1975 33.56 22.67 6.67 53.4 36 10.6

Tq-2,oil 600 34.55 20.89 9.97 52.8 32 15.2


Oil, Ja-25,1975m.

Oil, Tq-2,600m.

Oil, Ja-25,1975m.

Oil, Tq-2,600m.

Figure (5.19): The Cross plot of 1MP + 9MP versus 2MP + 3MP showing degradation

state of the studied oil samples (The diagram is after Akinlua et al., 2007a).

Figure (5.20): P1, P2, and P3 ternary of Mango (1994) in which the oil sample of Tq-2 .

shows slight effect of biodegradations.

P2

00

500

1000

1500

2000

2500

200 400 600 800 1000 1200 1400 16002MP+3MP(ppm)

1MP

+9M

P(p

pm)

Non-Degraded oil

Degraded oil

100%

90

80

70

60

50

40

30

20

10

100%

90

80

70

60

50

40

30

20

10

102030

40

506070

8090 100% P1

Biodegradation

Trend

Original oil

P3


4. According to Akinula et al. (2007b) degraded oils may show characteristic

relationship between Ph/nC18 ratio and Trimethylnaphthalene (TMN) content.

As shown in figure (5.21) also a slight degradation effect can be observed on

the oil of Tq-2, but what is not common is the high degradation which

appeared to have affected the oil of Ja-25. The TMN content in the oil of Ja-25

may have interpreted in other ways rather than being an effect of

biodegradation, for example due to the type of the precursor organic matters.

5. The higher value of sterane than diasterane and the higher steranes 20R

epimers than 20S epimers in the studied oils (Table 5.11) approve that the

occurred biodegradation is not intense or severe but it is just moderate to

slight biodegradation which affected the oil of Tq-2.

6. The GC chromatogram of the two studied oils (Fig. 5.22) shows an obvious

loss in the lighter compounds (especially <C8) of the oil from Tq-2, while the

oil of Ja-25 still contains a characteristic quantity of the light hydrocarbon

compounds (even to less than 4 atomic carbons). Such a condition supports

the idea that the oil of Tq-2 suffered from some kind of degradation which

caused partial loss of the lighter and weakest side from the hydrocarbon

spectra.

Figure (5.21): Cross-plot of Ph/nC18 versus TMN illustrating the effect of

degradation on the studied oil samples

(The diagram is after Akinlua et al., 2007b)

Oil, Ja-25,1975m.

Oil, Tq-2,600m.

TM

N(p

pm)

phytane/nC18

Normal Oils

Degraded Oils

5000

3000

3500

4000

2500

2000

1500

1000

0.25 0.40 0.45 0.500.350.30 0.55 0.60 0.650.20


Table (5.11): Diasterane/Sterane ratio and sterane epimer values used in

the evaluation of the biodegradation degree of the two oil

samples of Ja-25 and Tq-2.

7. The accumulated oil in Pila Spi reservoir in Taq Taq oil field at relatively

shallow burial depth (less than 750m) with a geothermal gradient in the area

expected to be around 2.1?C/100m (Shaban,2008) (Formation temperature

around 40?C), in addition to the movable condition of the associated water in

different parts of the reservoir (Qadir, 2008), with existence of outcrop areas of

Pila Spi Formation in relatively higher and nearby areas to the field (like Haibat

Sultan Mountain) which may act as a charging water area. All of these

conditions make the expectation of any degradation having occurred to the oil

in the Pila Spi reservoir a common sense.

8. Tissot and Welte (1978: in Allen and Allen ,1990) observed from the gross

composition of 636 crude oil ( in terms of the three main groups of compounds

found in petroleum

Saturates, Aromatics and NSO compounds) that normal

(non-degraded) crude oil typically contains 60-80% saturates, and less than

20% NSO compounds. Accordingly, the oil of Pila Spi reservoir in Tq-2 may be

moderately degraded as it contains 43.5% saturates, 25.22% aromatics, and

31.27% NSO and asphalts (Table 5.12), while the accumulated oil in Jeribie

reservoir of Ja-25 shows properties of normal oil (Fig.5.23).

It can be concluded that the oil existed in the Pila Spi reservoir in Tq-2 well may

have suffered from a moderate to slight biodegradation or may be water washing

since biodegradation and water-washing effects are sometimes not clearly

distinguishable as mentioned also by Tissot and Welte (1984).

Table (5.12): Chemical composition of the studied two oil samples (%SAT., %ARO., %NSO and %ASPH)

Oil sample

Diaster./Ster.

(217m/z)

C27 S (217m/z)

C27R

(217m/z)

C28 S

(217m/z)

C28 R

(217m/z)

C29 S

(217m/z)

C29R

(217m/z)

Ja-25

0.30

61.1

126

45.9

80.3

64.7

109

Tq-2

0.26

55.2

94.1

33

42.3

58.4

70

Samples Depth SAT. ARO. NSO ASPH

m % % % % Ja-25,oil 1975 59.3 23.91 16.1 0.69 Tq-2,oil 600 43.5 25.22 18.47 12.8


142

Inte

nsity

In

tens

ity

IC

4N

C4

IC

5N

C5

22

DM

B CP 2

3D

MB

2M

P3

MP

NC

62

2D

MP

MC

P2

4D

MP

22

3T

MB

BZ

33

DM

PC

H2

MH

23

DM

P1

1D

MC

P3

MH

1C

3D

MC

P1

T3

DM

CP

3E

P1

T2

DM

CP

NC

7I

ST

DM

CH

11

3T

MC

PE

CP

12

4T

MC

P1

23

TM

CP

TO

L

NC

8I

P9

MX

YL

PX

YL

OX

YL

NC

9I

P1

0

NC

10

IP

11

NC

11

NC

12

IP

13

IP

14

NC

13

IP

15

NC

14

IP

16

NC

15

NC

16

IP

18

NC

17

IP

19

PH

EN

NC

18

IP

20

NC

19

NC

20

NC

21

C2

5H

BI

NC

22

NC

23

NC

24

NC

25

NC

26

NC

27

NC

28

NC

29

NC

30

NC

31

NC

32

NC

33

NC

34

NC

35

NC

36

NC

37

NC

38

NC

39

NC

40

NC

41

N

C4

IC

5N

C5

22

DM

B2

3D

MB

2M

P3

MP

NC

62

2D

MP

MC

P2

4D

MP

22

3T

MB

BZ 33

DM

PC

H 2M

H2

3D

MP

11

DM

CP

3M

H1

C3

DM

CP

1T

3D

MC

P3

EP

1T

2D

MC

PN

C7

IS

TD

MC

H1

13

TM

CP

EC

P1

24

TM

CP

12

3T

MC

PT

OL

NC

8I

P9

MX

YL

PX

YL

OX

YL

NC

9I

P1

0

NC

10

IP

11

NC

11

NC

12

IP

13

IP

14

NC

13

IP

15

NC

14

IP

16

NC

15

NC

16

IP

18

NC

17

IP

19

PH

EN

NC

18

IP

20

NC

19

NC

20

NC

21

C2

5H

BI

NC

22

NC

23

NC

24

NC

25

NC

26

NC

27

NC

28

NC

29

NC

30

NC

31

NC

32

NC

33

NC

34

NC

35

NC

36

NC

37

NC

38

NC

39

NC

40

NC

41

Figure (5.22): (A) GC chromatogram of the oil from Tq-2, (B) GC chromatogram of the oil from Ja-25.

A

B

Retention time

Retention time


Figure (5.23): Gross composition of Ja-25 and Tq-2 oil samples {from Tissot and Welte(1978) which was modified by Allen and Allen(1990) in term of three main groups in compounds found in petroleum (Saturates, Aromatics, and NOS) compounds .Normal (Non-degraded) Crude typically contains 60-80% saturates, and less than20%NOS compounds}

Represent the crude oil samples which plotted in Tissot and Welte (1978) ternary diagram by Allen and Allen (1990).

To rank the degradation which have affected the oil of Tq-2 well according to

Wenger et al. (2001: in Head et al. 2003) (Fig.5.18) the following points are focused

on:

A) The API gravity of the oil which is about 23.74 (Karim, 2003).

B) The sulfur content of the oil which is 2.08 %wt (Karim, 2003).

C) The salinity of the formation water which is about 30 ppt. {(The salinity

value calculated by plotting the formation temperature 54.3°C and

formation water resistivity (RW) 0.15 ohm.m from Qader (2008) on the

Schlumberger equivalent converting chart (1996: in Asquith and

Krygowski, 2004)}

D) Existence of normal and iso alkanes (C15+).

E) The ratio of the saturated compounds which is 43.5%.

F) The low ratios of the condensates and wet gases (C2-C5)

Accordingly, a slight to moderate level (2-3) of biodegradation is expected to

be the case of the oil in Pila Spi reservoir in Tq-2 well.

No clear evidences about the biodegradation of the oil in the Lower Miocene

Jeribi reservoir of Ja-25 have been observed; therefore it is expected to be

undegraded oil.

Oil, Ja-25,1975m.

Oil, Tq-2,600m.

%SaturatedHC

%NSOCompounds

(Resins and Asphaltenes)

%Aromatic HC

1

Isofrequencycontours(%)

Normal crudeoils

Mostly heavydegraded oils

20

40

60

80

2080 4060

20

40

60

80


5.7 Stable Carbon Isotope:

The bulk isotopic compositions of the saturated and aromatic fractions of

crude oils have long been used for correlation purposes (Fyex, 1977: in Abbuod et

al., 2005).The stable carbon isotopic composition of organic matter is an important

tool to differentiate algal and land plant source materials and marine from continental

depositional environments (Meyers, 2003: in Youns and Philp 2005) .The carbon

isotopic signature of bitumen is relatively heavy for predominantly higher plant

sourced oils (Killops et al., 1997).

The stable carbon isotope values of crude oils are dependent mainly on the

depositional environment of the source rock and the degree of thermal maturity at

which the oil was expelled (Zein El-Din and Shaltout, 1987: in Youns and Philp,

2005). As thermal maturity level increases (higher API gravity), the isotopic ratio

increases to less (-) negative values (Rohrback, 1983) and 13C enrichment increases

with increasing maturity (Hill et al., 2007).

In this study, four extracts and two oil samples have been analyzed to measure

their saturate and aromatic carbon isotopes as shown in table (5.13).

Generally, the analysis indicates that the extracts showed higher negative

values for the 13C saturate (between -27.7

PDB and -27.1

PDB) and also for

the 13C aromatic (between -27.3

PDB and -27.0

PDB) than the two analyzed

oil samples. The less negative values of the two oil samples indicate their expulsion

from more mature source rocks than the maturity level of the beds from which the

extracts obtained. .

Table (5.13): 13C Saturate and 13C Aromatic Isotope data for the analyzed oils and extracts.

A cross plot of 13C values from saturates and aromatics are frequently used

for correlations of oils and bitumens (Fuex 1977: in Killops and Killops, 2005). It has

been suggested that marine and terrestrial origins can be distinguished by such plots

(Sofer, 1984 and 1988: in Killops and Killops, 2005), although the differentiation is

not always reliable (Peters et al., 1986: in Killops and Killops, 2005). 13C saturated

Samples Depth (m) 13C

Saturate

13C

Aromatic Ja-25

1975

-27.0

-26.8

Tq-2

600

-27.0

-26.9

KM-3

2060

-27.3

-27.1

Ja-46

1736

-27.7

-27.0

Pu-7 1804 -27.6 -27.2 Pu-7

1820

-27.1

-27.3


13C Sturates

(PDB)

and 13C aromatic fractions of the selected source rock samples plotted on the

diagram proposed by Sofer (1984: in Wang and Philp, 2001) to differentiate marine

and non-marine oils (waxy versus non-waxy in the plot) (Fig.5.24). From the plot a

non-waxy marine to slightly mixed origin of organic matter can be concluded for the

original organic matters within the analyzed samples.

However, statistical studies have shown that there are many exceptions to the

broad generalization (Peters et al., 1986: in Wang and Philp, 2001). It has been

suggested that this approach can be used for oil-source rock correlation (Schoell,

1983; Moldowan et al., 1985: both in Wang and Philp 2001). The good oil

oil, and

oil - source correlations can be observed in the cross plot.

Also the data of all the extracts and the two oil samples fall in the Non-waxy

region, and are 13C rich, which means that there is no evidence of gas generation to

cause the deplete of 13C, which causes the remaining hydrocarbons left in the source

rock to be of rich 13C, and all the extracted samples and the two oil samples appear

to be of marine origin.

Figure (5.24): 13C saturate versus 13C aromatic cross plot for the analyzed extracts

and oil samples (The diagram from Sofer ,1984: in Wang and Philp, 2001).

5.8 Oil-Oil and Oil-Source Rock Correlations:

Correlations are geochemical comparisons among oils or between oils and

extracts from prospective source rocks, and are used to determine whether a genetic

13C

Aro

mat

ics

(PD

B)

-34-32

OILS OF TERRIGENOUS ORIGIN

MIX

ED ORIG

IN O

ILS

OILS OF MARINE ORIGIN

-30

-28

-26

-24

-22

-20

-18

-16

-32 -30 -28 -26 -24 -22 -20 -18

Waxy

Non-Waxy



relationship exists or not (Peters and Moldowan, 1993; Waples and Curiale, 1999:

both in Peters and Fowler, 2002). Oil source rock correlation is based on the concept

that certain compositional parameters of migrated oil do not differ significantly from

those of bitumen remaining in the source rock. In this multi-parameter approach,

independent measurements of biomarker, stable carbon isotope, and other genetic

parameters support the inferred correlation (Peters and Fowler, 2002).

Oil-Oil correlations require the use of parameters that distinguish oil from

different sources and are resistant to secondary processes such as biodegradation

and thermal maturation (Peters and Moldowan, 1993: in Abboud et al., 2005). In

many cases, oil-oil correlation can be accomplished using a few simple parameters

such as gas chromatographic fingerprints, carbon or stable isotope ratios, or V/Ni

content (Abboud et al., 2005).

Gas chromatograms or fragmentograms have been widely used for correlating

oils and source rocks since the pioneering work of Seifert (1977), who differentiated

oils produced from San Joaquin Basin of California on the basis of sterane and

terpane fingerprints (Osuji and Antia, 2005). Recognizing such source fingerprints of

the hydrocarbon molecule enables one to know whether they have the same

biomarkers or similar geohistory of origin and migration. Thus, genetically related oils

can be differentiated from unrelated oils on the assumption that the same source

material and environment of deposition produce the same oils in which case a

chemical fossil compound in the source rock would be expected to appear in the oils

it generated. Obtaining a whole oil GC fingerprint requires analyzing entire oil for the

C2

C45 hydrocarbon range on a gas chromatograph (Osuji and Antia, 2005).

Ahmed et al. (2004) mentioned that the oil-source rock correlation studies are

carried out in any basin in which reservoired oil has been found, and the basic

objectives of correlation are:

a) Establish the geochemical character of the oil.

b) Determine the number of genetically related crude oil families within that area.

c) Carry out genetic correlation of potential and effective source rocks.

d) Define the control governing the generation, migration and accumulation of oil

within reservoir facies.

Peters et al. (2005) mentioned that biomarker correlations of crude oils with each

other, and with there source rocks, improve:

a) Understanding of reservoir relationships, petroleum migration path ways and

possible new exploration plays.


b) Biomarkers can be used to identify sources of petroliferous contamination in

the environment and the progress of remediation.

c) They can be used to evaluate thermal maturity and/or biodegradation, thus,

providing information needed to evaluate the distribution and producibility of

petroleum in the basin.

d) Provide information on regional variations in the character of oil and source

rocks as controlled by organic matter input and characteristics of the

depositional environment.

In this study an attempt has been made to find out any correlation between the

analyzed oil samples and the extracts from the source rocks depending on the data

obtained from the GC and GC/MS analysis. The main objective of the correlation

was to find out any relationship between the accumulated oil in the Upper Eocene

Pila Spi reservoir in Taq Taq Oil Field and Paleocene Aaliji/ Kolosh source rocks

which were expected to be effective and mature, and also to find out any correlation

between the mentioned oil with the reservoired oil the Upper Cretaceous beds in the

same oil field which is believed to be sourced mainly from beds of Jurassic age (Al-

Haba and Abdulla, 1989; Ahmed, 2007).

However, it is very difficult to find a reasonable relationship between severely

biodegraded oil and it is source because bacteria have destroyed some of the

biomarkers in this kind of oil, meanwhile; the oil characteristics have been changed.

Therefore, the correlation between biodegraded oils and their sources is one of the

tough problems in the study of oil-source tracing (Tissot and Welte, 1984). But as

found out above, the oil of Pila Spi reservoir in Tq-2 didn t suffer from severe

biodegradation, therefore, correlation between this oil and the extracts or other oils

still may show an acceptable reality.

The following tools have been used to follow the positive or negative

correlations between the studied samples:

5.8.1 Pr / nC17 versus Ph / nC18:

From figure (5.1) of this chapter no quite clear correlation can observed

between the studied extracts and oil samples, especially the extracts related to TT-04

as they show somehow different sources of organic matters. On the other hand,

differences also can be observed between the Pr / nC17 and Ph / nC18 ratios of the

Upper Cretaceous oil of Tq-1 with the oils of Tq-2 and Ja-25 although they show the

same values of CPI (Table 5.14). Such differences can be interpreted as differences

in the origin of organic matter and not mainly in maturity effects or biodegradation.


Table (5.14): Pr/nC17, Ph/nC18 ratios and CPI values of the studied samples and the

oil of Tq-1.

(*)Data from Ahmed (2007)

5.8.2 Steranes and Diasteranes Ternaries:

The ratio of adjacent homologs or compounds with similar structures, such as the

source dependant biomarker ratios, do not changes from bitumen in the source rock

to the migrated oil. For example, the ratio C27/ (C27-C29) steranes used in C27-C28-C29

ternary diagrams do not differ significantly between extracts from source rocks and

genetically related oils throughout the oil-generative window (Peters et al., 2005).

Peters et al.( 2005) also mentioned that the C27, C28 and C29 diasterane plots

are most important than C27, C28 and C29 sterane plots for oil-oil and oil-source rock

correlations, because the heavily biodegraded oils where sterane are altered, but

diasteranes remain intact, and also some highly mature oils and condensates show

low sterane but more abundant diasteranes. However, some oils from clay-poor

source rocks show high steranes, but the diasteranes are not useful for correlation

because of low concentration.

Sterane and diasterane ternaries for C27, C28, and C29 used to show the

correlation between the analyzed two oil samples of Ja-25 and Tq-2 with the bitumen

extracts from KM-3, Ja-46, and Pu-7 and the oil from the U. Cretaceous reservoir of

Tq-1 (Figs. 5.25 and 5.26). The sterane ternary showed clear genetically related

sources organic matters for all samples (oils and extracts) as they were located quite

close to each others, while in the diasterane ternary the oil of the U. Cretaceous

reservoir of Tq-1 separated obviously from the group indicating different sources of

organic matters.

Samples Depth (m) Pr/n-C17

Ph/n-C18

CPI

Ja-25, oil

1975

0.33

0.45

0.97

Tq-2, oil

600

0.44

0.63

0.97

Tq-1, oil * 1620-

1651 0.18 0.25 0.97

TT-04

1246-1368

0.68

0.46

0.99

TT-04

1448

0.63

0.30

1.26

TT-04

1546

0.61

0.25

1.09

KM-3

2004

0.54

0.73

1.05

KM-3

2060

0.50

0.52

1.01

KM-3

2145

0.57

0.68

1.06

Ja-46

1736

0.66

0.91

1.23

Ja-46

1846

0.78

1.24

1.17

Ja-46

1862

0.80

0.87

1.10

Pu-7

1620-1689

0.45

0.47

1.05

Pu-7

1804

0.53

0.53

1.02

Pu-7

1820

0.44

0.47

1.02


Figure (5.25): Ternary diagram showing the relative abundance of C27, C28 and C29

regular steranes for the analyzed extracts and oil samples and indicating the genetically relation of the extracts and the oils (The diagram is from Peters et al., 2005).

Figure (5.26): Ternary diagram shows the relative abundance of C27, C28 and C29 diasteranes for the analyzed extracts and oil samples and indicating the genetically relation of the extracts and the oils. (The diagram is from Peters et al., 2005).

C29C27

C28

100

90

80 70 60 50 40 30 20

10

10

20

30

40

5060

70

8090

100%

1020

30

40

5060

7080

90

100

C29

C28

10080

70

60 50

40 30 20 10

10

20

30

40

50

60

70

80

90

100%

10

2030

40

50

60

C27

70

8090

100

90

Oil, Ja-25 Oil, Tq-2

Pu-7, 1804m Pu-7, 1820mJa-46, 1736mKM-3, 2060mOil, Tq-1

Oil, Ja-25 Oil, Tq-2

Pu-7, 1804m Pu-7, 1820mJa-46, 1736mKM-3, 2060mOil, Tq-1


5.8.3 Carbon Isotope Data:

Carbon isotopic values are typically applied both in understanding depositional

environment and also as a tool in oil-oil and oil-source rock correlations (Sofer, 1984:

in Abbuod et al., 2005)

A positive correlation is usually established when the equivalent fractions of

oils differ by less than 1%. The difference between the isotopic composition of the

aromatic and saturated hydrocarbon fractions ranges up to 3.5%, with the aromatic

fraction typically being isotopically heavier.

Oil is only isotopically related to the oil generating fraction of kerogen; there

are maturity related changes in isotopic composition; and migrated oil often

comprises only a proportion of the generated bitumen and is comparatively depleted

in heavier and more polar compounds. For a given maturity, a bitumen is often lighter

than its source kerogen (0.5-1.5%), and the related oil is (0.0-1.5%) lighter again

(Peters and Moldowan, 1993: in Killops and Killops, 2005). Oils of similar maturity

that differ by more than 2% are usually not genetically related.

The bulk isotopic compositions of the saturate and aromatic fractions showed

a good correlation between the analyzed extract samples of the Aaliji/Kolosh, Aaliji,

and Jaddala Formations from KM-3, Ja-46 and Pu-7 and the two reservoired oil

samples in Tertiary beds of the Ja-25 and Tq-2 (Figure 5.24). Genetically related

organic matters indicated from the values of the saturated and aromatic 13C as they

were quite close to each other.

What is important to mention is the differences between the values of

saturated and aromatic 13C (especially the saturated) of the oil from Tq-2 and of the

extracts from the Jurassic beds which comprise part of the source beds for the

accumulated oil in the U. Cretaceous reservoirs in Taq Taq Oil Field (Table 5.15).

Although the differences in the saturated fractions are less than 1% but still some

variations can be observed.

Table (5.15): 13C Saturate and 13C Aromatic Isotope data for the analyzed oil of Tq-2 and the oil of Tq-1 with Jurassic extracts.

(*)Data from Ahmed (2007)

Samples Depth (m) 13C

Saturate 13C Aromatic

Tq-2, oil

600

-27.0

-26.9

Tq-1, oil *

1620-1651

-27.1

-26.3

Tq-1 *

3143

-27.9

-27.1

Tq-1 *

3165

-27.9

-26.9

Tq-1 * 3200 -27.8 -26.9


5.8.4 Reservoir Oil Fingerprinting (ROF):

For recognizing differences in the gas chromatograms of oils Kaufman et al.

(1990) developed a sensitive method, called Reservoir Oil Fingerprinting (ROF). The

ROF procedure consists of first numbering all the small measurable peaks

sequentially through n-C20. Then they visually select fewer than 25 pairs of peaks

(usually 12 or so) and calculate the ratios of their peak heights or areas. Peaks are

mainly selected in the C9

C20 range where there is a good distribution of

naphthenes and aromatics without too much overlap. The next step is to construct a

star diagram (polygon plot) by plotting each peak ratio on a different axis of a polar

plot. Alizadeh et al. (2007) modified Kaufman et al s. Star diagram using a number of

other biomarkers like Pr/C17, Ph/C18 and C17 to C36 to correlate oil fingerprinting of the

reservoirs and evaluate their origin.

In this study, a star diagram has been drawn for the two studied Tertiary oil

samples of Tq-2 and Ja-25 and correlation done with other oils from the U.

Cretaceous reservoir of Taq Taq Oil Field (Tq-1 well), the Main Limestone of Kirkuk

Oil Field (K-156 well), and the oil of Tertiary reservoir in the Bai Hassan Oil Field (BH-

22 well) using the values listed in table (5.16). The collective star diagram (Fig.5.27)

showed differences in the ratios of the lighter hydrocarbons which are positively

proportion with the API degrees of the oils. Such cases can be interpreted as

differences in maturity level of the oils, or differences in G/O ratio, or variety in the

initial precursor organic matters, or due to degradations or other reasons.

The great difference between the oil of the Pila Spi reservoir and the oil of U.

Cretaceous reservoir in Taq Taq Oil Field indicates two expected points:

1) Contribution of other sources (in addition to the Jurassic and Cretaceous beds)

in generating the accumulated oil in the U. Eocene Pila Spi reservoir in Taq

Taq Oil Field which is believed to be the Paleocene Aaliji/ Kolosh beds.

2) The oil in the Pila Spi reservoir in Taq Taq Oil Field subjected to some kinds of

degradations caused partial depletion of the lighter normal alkanes which are

of no long carbon chains (The effect of biodegradation and water washing is

proportional with the length and complexity of the atomic carbons) .


Table (5.16): The parameters used in the oil-oil correlation and fingerprinting of the oil

samples from Ja- 25, Tq-2, Tq-1, K-109, and BH-22 wells.

Oil

samples nC9 nC10 nC11 nC12 nC13 nC14 nC15 nC16

nC17

nC18

nC19

nC20

Ja-25

11.97

1023

9.20

7.74 6.81 5.94 5.13 4.47 3.91 3.4 2.9 2.46

Tq-2

1.69

2.30

2.72

2.73

2.83

2.86 2.84 2.78 2.60 2.28 1.90 1.73

Tq-1*

16.45

13.74

12.38

10.39

8.99

7.61

6.58

5.53

4.84

4.14

3.47

2.97

K-156*

6.51 6.74 6.40 5.61 5.07 4.60 4.18 4.00 3.62 3.34 2.91 2.63

BH-22**

8.12 8.63 9.03 8.36 8.07 7.34 7.19 6.08 5.44 4.75 4.11 3.79 *The data from Ahmed (2007).

** The data from Baban (2008).

Figure (5.27): Star diagram for the oil samples from Ja-25, Tq-2, Tq-1, K-156, and

BH-22 wells using C9

C20 peak values.

Tq-2Ja-25

BH-22

Tq-1K-156


5.8.5 Miscellaneous:

Figures 5.28-5.31 represent cross plots between different biomarkers to show

the correlation between the analyzed oils and oils with the extracts.

C35H/C34H versus Ts/Tm cross plot (Fig. 5-28) shows departure of the U.

Cretaceous reservoir oil of Tq-1 from the rest analyzed oils and extracts because of

the higher Ts/Tm ratio in the oil of Tq-1. C29H/C30H versus Diasterane/Sterane ratio

(Fig. 5-29) showed less correlation between the oils and extracts although all were

located within the same carbonate rich environment of source rocks.

Steranes/Hopanes versus C27/C29ST ( S) diagram (Fig. 5.30) collected the oils

and extracts within a single group except the extract from the depth 2060m of KM-3

which showed characteristic increase in the Steranes/Hopanes ratio making it not

correlatable with the rest of oils and extracts. Finally, the cross plot of

Diasterane/Sterane versus Ts/Tm again (Fig. 5.31) showed the oil of Tq-1 as an oil

generated from a source of organic matter differs from those which are responsible

for generating the oils accumulated in the Tertiary beds of Ja-25, Tq-2, and K-156

wells. The used values in plotting the figures (5.28-5.31) are listed in table (5.17).

Table (5.17): Ratios of different biomarkers used in oil

oil correlation and oil

source

rock correlation

* The data from Ahmed (2007).

Samples Depth (m)

Ster./

Hop.

C29H/

C30H (191m/z)

C35H/

C34H (191m/z)

Diasterane/ Sterane (217m/z)

C27

/ C29

( S)

(218m/z)

Ts/Tm (191m/z)

Ja-25,oil

1975

0.60

1.44

1.07

0.30

0.78

0.24

Tq-2,oil 600 0.31 1.51 1.04 0.34 0.73 0.32

Tq-1,oil* 1620-

1651 0.25 1.12 1.01 0.53 0.76

K-156,oil* 64 0.52 1.31 1.19 0.27 0.34 KM-3

2060

1.02

1.15

1.16

0.23

0.79

0.21

Ja-46

1736

0.45

0.89

0.90

0.33

0.66

0.24

Pu-7

1804

0.28

1.55

1.07

0.09

0.69

0.17

Pu-7 1820 0.25 1.51 1.11 0.08 0.69 0.17


Figure (5.28): Cross plot of Ts/Tm versus C35H/C34H, a clear variation can be observed

between the oil of Tq-1 and oils of Tq-2 and Ja-25, and with the extracts.

Figure (5.29): Cross plot of C29H/C30H versus Diasterane/Sterane, a clear variation can

be observed between oil of Tq-1 and Tq-2.

C35

H/C

34H

Ts / Tm0 0.4 0.8 1.2 1.6 2.0

0.4

1.6

1.2

0.8

2.0

0.4

0

1.6

1.2

0.8

DIA

ST./S

T.

2.0

0.4 0.8

C29H / C30H1.2

Carbonate content

1.6 2.0

Shal

e co

nten

t

Oil, Ja-25 Oil, Tq-2Pu-7, 1804m Pu-7, 1820mJa-46, 1736m

KM-3, 2060mOil, K-156 Oil, Tq-1


KM-3, 2060mOil, K-156 Oil, Tq-1


0.4

0 0.2

1.6

1.2

0.8

2.0

0.4 0.6 0.8

Ts / Tm1.0 1.2 1.4 1.6 1.8 2.0

DIA

ST. /

ST

.C

27/C

29 (

S)

Figure (5.30): Cross plot of Sterane/Hopane versus C27 / C29 ( S), a minor variation can be observed between Tq-1, Tq-2, Ja-25, and K-156 oils with the extracts (Except KM-3 at depth 2060m)

Figure (5.31): Cross plot of Ts/Tm versus Diasterane/Sterane, a clear variation can be observed between the oil of Tq-1 with Tq-2, Ja-25, and K-156 oils with the extracts.

Sterane/Hopane0 0.4 0.8 1.2 1.6 2.0

0.4

1.6

1.2

0.8

2.0


KM-3, 2060mOil, K-156 Oil, Tq-1


KM-3, 2060mOil, K-156 Oil, Tq-1

CHAPTER SIX ___________________________________________

Chapter Six Conclusions and Recommendations

156

6.1 Conclusions:

The following is a summery of the conclusions that can be drawn from the results

of the optical and analytical studies done in this study:

1. AOM comprises the higher percentage of organic matter components in

Aliji/Kolosh, Aaliji, Kolosh, and Jaddala Formations in the studied sections

followed by opaque materials and palynomorphs.

2. Three types of palynofacies can be distinguished from the difference in ratios of

the organic matter components in the studied successions. The identified

palynofacies indicated deposition in distal suboxic-anoxic basin with a slight

change in the environment towards proximal suboxic-anoxic shelf as in the

upper part of the studied succession in TT-04 (PF-2).

3. The TAI values of the studied sections ranged between (2) to (3-) indicating

that the organic matters within the studied samples were not subject to

paleotemperatures higher than 96°C, and only Aaliji / Kolosh beds in TT-04

(from depth1112 to1466m) appeared to have entered the maturity zone.

4. The results of the optically examined AOM in the four studied sections showed

dominant of type A with some contribution from types B, C, and D. The IR

analysis of the studied samples supported the optically identified types of AOM.

Accordingly, the existed organic matters within Aaliji/Kolosh, Aaliji, and Jaddala

Formations are generally mix of oil-prone and gas-prone in KM-3, Ja-46 and

Pu-7, while Aaliji/Kolosh beds and Kolosh Formation in TT-04 appeared to be

more gas-prone rather than being oil-prone.

5. As the AOM within Aaliji/Kolosh, Aaliji, and Jaddala Formations were generally

of non-fluorescence nature under the ultraviolet light, therefore, they can be

thought to be of marine (autochthonous) origin derived from degradation of

phytoplankton. The upper part of the studied Aaliji/Kolosh beds and Kolosh

Formation in TT-04 showed low-fluorescent to non-fluorescent nature indicating


157

that the existed AOM may be mix of marine (autochthonous) origin derived

from degradation of phytoplankton and of continental (allochthonous) origin

derived from degradation of plant debris.

6. According to the Vitrinite Reflectance measurement, Aaliji/Kolosh in TT-04

appeared to be at early stages of maturity, while Jaddala Formation in KM-3

section at depths 2004 and 2060m showed close conditions to maturity but still

immature. The Aaliji Formation in the KM-3 and Jaddala Formation in Ja-46

section had no sufficient vitrinites, but the measured few points showed that

their organic matters are still within the realm of immaturity. The Jaddala

Formation in Pu-7 showed a relatively higher maturation level than the two

sections of KM-3 and Ja-46.

7. The Jaddala Formation is the richest with TOC content, then Aaliji/ Kolosh, Aaliji,

and Kolosh Formation respectively. Jaddala Formation is generally good or very

good as source rock (from TOC content point of view), while the other studied

formations are generally poor. As sections and area; the TOC content in

Pulkhana-7 showed to be the richest area, then Kor Mor-3, Jambur-46, and Taq

Taq-04 respectively.

8. According to the pyrolysis data:

A. The organic matters within Aaliji/Kolosh and Kolosh Formations in TT-04 are

generally of kerogen type III, while the existed organic matters in the other

sections showed a mix of type II and III for most of studied samples, which

proved slight differences in the paleodepositional environments and differences

in the initial sources of organic matters.

B. The lower part of Aaliji/Kolosh in TT- 04 entered the zone of maturation, while

most of the organic matters in the Aaliji/Kolosh, Aaliji, and Jaddala Formations

in the other studied sections appeared to be still immature. The older and

deeper parts of the studied formations are the closer to maturity in all the

studied sections.


158

C. The whole studied succession in TT-04 was observed to have a poor

hydrocarbon potentiality, while the section of KM-3 showed a wide range of

potentiality from poor in Aaliji/ Kolosh to excellent especially in Aaliji Formation.

In Ja-46; Aaliji appeared to be poor to fair while Jaddala generally showed fair

to good potentiality. The organic matters within the studied samples in Pu-7

section (particularly Jaddala Formation) were observed to have higher

potentiality for hydrocarbon generation than the other studied sections.

D. Hydrocarbon expulsion seems to have occurred from the lower part of Aaliji/

Kolosh in TT-04, while the generated hydrocarbons in the other studied

sections are still not enough to initiate expulsion.

E. The hydrocarbons in the Aaliji/Kolosh, Aaliji, Kolosh, and Jaddala Formations in

TT-04, KM-3, and Ja-46 appeared to be indigenous, while in Pu-7 section the

existed hydrocarbons in Aaliji/Kolosh and Jaddala Formations appeared to be

non indigenous hydrocarbons.

F. There is a little generative potential left in the Aaliji/Kolosh beds in TT-04, KM-3,

and Pu-7 sections as most of the TOC contents are very close to the RC values.

While, a parts of Aaliji and Jaddala Formations still have the potentiality to

generate hydrocarbons when they enter the realm of maturity.

9. The GC/MS analysis for all extracts and the two oil samples taken from the

reservoirs of Tertiary in Ja-25 and Tq-2 wells indicated that:

A. Sources of organic matters that deposited in anoxic, reduced marine carbonate

environments, Sources of terrestrial organic matters of oxidizing condition have

been observed only in depth 1441m in TT-04 section within Aaliji/Kolosh beds.

B. The low ratio of Gammacerane Index indicated that no hypersaline condition of

deposition for the initial organic matters within the analyzed samples has

occurred.


159

C. The analyzed oil samples showed no Oleanane content, indicating that the oils

are generated from sources older than the Cretaceous or from sources with no

angiosperm content.

D. The Aromatic content within the two oil samples; a mixed marine and lacustrine

sulphate-rich environments for their sources has been detected.

E. The Isotopic data of the extracts and the two oil samples showed marine (to mix)

non-waxy origin of hydrocarbons.

F. Maturity related biomarkers indicated an immature state of organic matters in

KM-3, Ja-46, and Pu-7, and show that the oil of Tq-2 is more mature than the oil

of Ja-25.

G. Biodegradation affected the properties of the reservoired oil in the U. Eocene

Pila Spi. The expected level of biodegradation is slight to moderate (2-3). No

clear evidences of biodegradation have been observed in the oil of the Lower

Miocene Jeribi reservoir in Ja-25.

H. A good source

oil and oil

oil correlation was noted from the used diagrams

and plots showing genetically related source of organic matters for the analyzed

samples (oils and extracts).

I. Obvious differences were observed between the oil in the U. Eocene Pila Spi

reservoir in Tq-2 well and the oil in U. Cretaceous reservoirs in Tq-1 well in Taq

Taq Oil Field. Contribution in generating the oil in Pila Spi is expected from

other sources (in addition to the Jurassic and Cretaceous beds) like the

Paleocene Aaliji/ Kolosh beds. The differences also can be due to the effect of

some kinds of degradation of the oil in Pila Spi reservoir.


160

6.2 Recommendations:

As the Lower Tertiary beds extends to different parts of Iraq and generally show

variations in their properties, their evaluation from hydrocarbon potentiality point of view

needs more detail works. The following recommendations for future works may assist in

better understanding the role of the Lower Tertiary beds as source rocks and may

answer the questionable points that exist in the current research:

1. Evaluating the hydrocarbon potentiality of the basinal Lower Tertiary beds in

other localities of Northern Iraq in order to get a complete imagination about their

contribution in generation of the accumulated oils within the Tertiary reservoirs of

the whole northern Iraqi Oil Fields. Pyrolysis analysis and biomarker studies for

acceptable average sampling will enhance executing such evaluations.

2. Detailed studies about the burial history of the beds in Taq Taq and nearby areas

that show a relatively higher geothermal gradient and more thermally mature

source rocks.

3. Paying attention to the Lower Tertiary source rocks as an additional element

during any study that may be done about the Petroleum System of the region.

4. Classification and finger printing of the oils that exist in the Iraqi Oil Fields using

different parameters that are affected by geological situations such as

geographical locations, depths of reservoirs, lithology of host rocks, degradation

effects, types of sources, maturations, reservoir pressure, etc.

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sp.

Operculodinum

2 TAITAI -3

A

D,C,B

III

III,II

0

suboxic

anoxic

suboxic anoxic

Thermal Alteration Index

sp.

Operculodinum2 TAITAI -3

?

A

C,BD

IR

Vitrinite Reflectance

TOC

IIIIII, II

Pyrolysis

anoxic clay-poor carbonate environment

algal

Sterane, Pr/Ph

CPI

(Bitumen Extraction)

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Thesis 2009 Source Rock Evaluation