hydrocarbon exploration and tectonic evolution of belayim marine oil field, gulf of suez, egypt

Faculty of Science Geology Department

HHYYDDRROOCCAARRBBOONN EEXXPPLLOORRAATTIIOONN AANNDD TTEECCTTOONNIICC EEVVOOLLUUTTIIOONN OOFF BBEELLAAYYIIMM

MMAARRIINNEE OOIILL FFIIEELLDD,, GGUULLFF OOFF SSUUEEZZ,, EEGGYYPPTT

A thesis submitted by

MM OOHHAAMM EEDD AABBDDAALL LL AAHH AABBUU AALL --AATTTTAA

B.Sc. Geology “Geology and Chemistry Degree” (2004)

Data Analyst

Geoservices - A Schlumberger Company

A dissertation submitted in partial fulfillment of the requirements for the

M.Sc. Degree in Petroleum Geology

SSUUPPEERRVVII SSEEDD BBYY ::

2015

AASSSSII SSTTAANNTT PPRROOFF.. DDRR.. GGHHAALL II BB II BBRRAAHHII MM II SSSSAA

Assistant Professor of Petroleum Geology, Geology Department

Mansoura University

DDRR.. MM OOHHAAMM MM EEDD AAWWAADD AAHHMM EEDD

Lecturer of Applied Geophysics

Geology Department

Mansoura University

DDRR.. MM OOHHAAMM EEDD MM OOUUSSTTAAFFAA AAFFII FFEE

Lecturer of Petroleum Geology

Geology Department

Benha University

Mohamed Abu Al-AttaHydrocarbon Exploration And Tectonic Evolution Of Belayim Marine Oil Field, Gulf Of Suez, Egypt2015

Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Author’s Declarationii

Faculty of Science Department of Geology

HHYYDDRROOCCAARRBBOONN EEXXPPLLOORRAATTIIOONN AANNDD TTEECCTTOONNIICC EEVVOOLLUUTTIIOONN OOFF BBEELLAAYYIIMM

MMAARRIINNEE OOIILL FFIIEELLDD,, GGUULLFF OOFF SSUUEEZZ,, EEGGYYPPTT

RREESSEEAARRCCHHEERR’’ SS NNAAMM EE:: MM OOHHAAMM EEDD AABBDDAALL LL AAHH AABBUU AALL --AATTTTAA

Supervisors

Signature Profession Name

Assistant Professor of Petroleum Geology

Geology Department

Mansoura University

Assistant Prof. Dr. Ghalib Ibrahim Issa


Geology Department

Mansoura University

Dr. Mohammed Awad Ahmed


Geology Department

Benha University

Dr. Mohamed Moustafa Afife

Chairperson of the Geology Vice-Dean for postgraduate Dean Department and research affairs Prof. Dr. Hosni H. Ghazala Prof. Dr. El-Sayed I. El-Desoky Prof. Dr. Azza I. Othman

Mansoura UniversityHydrocarbon Exploration And Tectonic Evolution Of Belayim Marine Oil Field, Gulf Of Suez, Egypt2015

Author’s Declarationiii

Faculty of Science Department of Geology

HHYYDDRROOCCAARRBBOONN EEXXPPLLOORRAATTIIOONN AANNDD TTEECCTTOONNIICC EEVVOOLLUUTTIIOONN OOFF BBEELLAAYYIIMM MMAARRIINNEE

OOIILL FFIIEELLDD,, GGUULLFF OOFF SSUUEEZZ,, EEGGYYPPTT

RREESSEEAARRCCHHEERR’’ SS NNAAMM EE:: MM OOHHAAMM EEDD AABBDDAALL LL AAHH AABBUU AALL --AATTTTAA

Supervisors: Signature Profession Name


Geology Department

Mansoura University



Geology Department

Mansoura University

Dr. Mohammed Awad Ahmed


Geology Department

Benha University

Dr. Mohamed Moustafa Afife

Referees: Signature Profession Name


Geology Department

Mansoura University


Professor of Petroleum Geology and Geochemistry

Geology Department

Alexandria University

Prof. Dr. Mohamed Abdel-Aziz Younes

Professor of Petroleum Geology

Geology Department

Azhar University

Prof. Dr. Essam Ahmed Abdel-Gawad

Chairperson of the Geology Vice-Dean for postgraduate Dean Department and research affairs Prof. Dr. Hosni H. Ghazala Prof. Dr. El-Sayed I. El-Desoky Prof. Dr. Azza I. Othman


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Author’s Declarationiv

AUTHOR’S DECLARATION

I hereby declare that I am the author of this thesis.

The experiments in this thesis constitute work carried out by the candidate unless otherwise stated.

The thesis's tables, figures, and bibliography have been complied with the stipulations set out for the

degree of Master by the Mansoura University.

I further authorize Mansoura University to reproduce this thesis by photocopying or by other means,

in total or in part, at the request of other institutions or individuals for the purpose of scholarly

research.

Title of Thesis/Dissertation:

Hydrocarbon Exploration and Tectonic Evolution of Belayim Marine Oil Field,

Gulf of Suez, Egypt

Signature

Author ___________________

Abu Al-Atta, Mohamed

Faculty of Science, Mansoura University

June, 2015


Thesis Abstractv

THESIS ABSTRACT

Integrated 1D basin modeling was applied to evaluate the thermal history of the sedimentary

sequence of the Belayim Marine Oil Field, with the thermal calibration to available maturation, data

from multiple wells drilled in the Belayim Marine Oil Field. In combination with the interpretation of

the wireline logs data and burial history of the sedimentary units this led to a maturity model for

deposits of source rocks, potential source rock. Integrated 1D basin modeling was applied to evaluate

the thermal history of the sedimentary sequence in the Belayim Marine Oil field. In all 1D models, the

present heat flow ranges from 52-64 mW/m2, with the higher values occurring in BM-57 well. Areas of

present heat flow maxima are generally coincident with distribution of basement relief and/or high

conductivity basement. This higher value occurring at BM-57 with thick highly thermal conductive

basin-fill sediment, i.e. South Gharib Formation, whereas the lower values modeled for the BM-24 well

are associated with thick lower thermal conductive basin-fill sediment, i.e. Post South Gharib

formations. The higher heat flow is explained by uplift followed by erosion, which provides an

additional 1-17 mW/m2 above background of 52-64 mW/m2. Heat is refracted away from regions of

thick sediment cover and preferentially channeled through areas of elevated basement. An additional

15 mW/m2 may be produced by conductivity contrasts in basement. High sedimentation rate can also

affect the temperature field due to the low heat conductivity of highly porous sediments. The results

of the 1D simulations show the differences in burial, thermal and maturity history. The burial history

of the study area is represented by time-depth history plots that show the burial of different horizons

traced through time, from deposition to present day. The subsurface temperature was specified for

every layer throughout its geologic history. The following thermal regime for Belayim Marine Oil Field

is proposed based on present-day corrected static bottom-hole temperatures.

1) Paleo-heat flow was highest at ~25-23 Mabp (the Oligocene rifting phase), with cooling caused by

a heat flow decline.

2) Paleo-heat flow has increased during the Miocene rifting phase. This thermal scheme has been

implemented in the 1D model, applying high heat flows from (~17.2 to 16.8 Mabp.) There was a

decline in geothermal gradient due to rapid sediment accumulation (as indicated during the deposition

of the South Gharib Formation) resulting in a subsurface temperature that was anomalously low.

3) Paleo-heat flow has increased during the Late Messinian Time Event from ~5.2-4 Mabp, and

declining to the background in the Neogene.

For the different source rock sequences, the content of organic matter (TOC) and quality Hydrogen

Index (HI) has to be defined together with reaction kinetic parameters for the thermal primary

cracking to light and heavier petroleum components. The limestone of Thebes Formation is shallow

marine depositional environment with a reported thickness in the range of 44 to 237m. It is

characterized by a relatively high total organic carbon (TOC) value of ~2.71wt% and by immature

Type II kerogen (BM-36 and BM-57 wells) and mature at wells (BM-70, BM-65, BM-23 and 113-M-27

well). For the numerical basin modeling, intervals with present-day TOC values below 0.5wt% for oil-

prone source rocks and 0.8wt% TOC for gas-prone source rocks were considered to have negligible

petroleum generation potential because the kerogen in such lean rocks is often highly oxidized. The

relatively high hydrogen index of 409 mgHC/gTOC and low oxygen index 47 mgCO2/gTOC, S2 value of


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Thesis Abstractvi

11.1 mg/g rock indicate that the kerogen is made up of an oxygen-lean organic material and confirm

the kerogen as type II that considered mainly as oil generative interval. Duwi Formation assigned to

pre-rift basin fill sediments of limestone organic rich interval that deposited in open marine

depositional environment which is characterized by type II kerogen with an excellent generation

potential for liquid hydrocarbons (oil prone type II-S kerogen). It is characterized by a high initial total

organic carbon (TOC) value of ~4.02wt% and by immature to early mature Type II kerogen at single

well (BM-57 well), whereas it is classified as thermally mature type II kerogen at (BM-23, 113-M-34,

and 113-M-27 wells). For the numerical basin modeling, intervals with present-day TOC values below

0.5wt% for oil-prone source rocks and 0.8wt% TOC for gas-prone source rocks were considered to

have negligible petroleum generation potential because the kerogen in such lean rocks is often highly

oxidized. Nubia-A Formation has organic-rich intervals, namely Nubia A-S1, Nubia A-S2 and Nubia A-

S3. The present-day depth to top ranges between 2931m (TVDss) at BM-36 and 3933m (TVDss) at

113-M-27 well with total thickness ranges between 45m at 113-M-27 well and 164m at BM-36 well. It

assigned to pre-rift sediments of shale organic rich interval that deposited in shallow marine

depositional environment and classified as a mixed type II-III kerogen with an excellent generation

potential for liquid hydrocarbons (oil prone type II-B – type III kerogen). It is characterized by fairly

total organic carbon (TOC) value of ~1.03wt% and by immature Type II-III kerogen at BM-57 well,

and an early-mature type II kerogen intervals at BM-36 and BM-65 wells), but mature at single well,

113-M-27 well, At BM-65 well, the analyzed source rock intervals with (TOC 1.27-1.43%) appear to

have fair potential for gas and oil generation, at the present level of thermal maturity (Pyrolysis S2

2.70-3.74 mg/g and HI 189-281). For the numerical basin modeling, intervals with present-day TOC

values below 0.5wt% for oil-prone source rocks and 0.8wt% TOC for gas-prone source rocks were

considered to have negligible petroleum generation potential because the kerogen in such lean rocks

is often highly oxidized. The relatively high hydrogen index of 167 mgHC/gTOC and low oxygen index

86 mgCO2/gTOC, S2 value of 1.72 mg/g rock indicate that the kerogen is made up of an oxygen-lean

organic material and confirm the kerogen as type II-type III that considered mainly as oil generative

interval. Nubia B Formation is characterized by early-mature source rocks that were deposited under

transitional environments, and with a tendency to produce mainly liquid oil with minor gas generation

capacities. It is considered as an active currently expelling effective source rock that has already

generated and expelled hydrocarbons. The organic-rich interval has been differentiated based on well

logging interpretation and confirmed by geochemical analysis, namely Nubia B-S. The organic rich

interval Nubia B-S is located at five wells 113-M-27, BM-36, BM-65, BM-57, and at BM-24 well. The

present-day depth to top ranges between 3036m (TVDss) at BM-24 and 4002m (TVDss) at 113-M-27

well with total thickness ranges between 45m at BM-65 well and 93m at BM-36 well for Nubia B-S.

Moreover, a second organic rich interval, namely Nubia B-S1, has been distinguished at shallower

depth of 3018m (TVDss) at BM-24 well. It assigned to pre-rift sediments of shale organic rich interval

that deposited in shallow marine depositional environment and classified as type II-III kerogen with

an excellent generation potential for liquid hydrocarbons (oil prone type II-B – type III kerogen). It is

characterized by a relatively remaining high total organic carbon (TOC) value of ~2.62wt% and by


Thesis Abstractvii

immature-early mature Type II-III kerogen at BM-57 well and an early-mature type II-III kerogen

intervals at BM-36 and BM-65 wells but mature at wells, BM-24 and 113-M-27 well.

The analyzed samples contain mixed marine and terrestrial sources with variable but nearly equal

proportions. The black shale of the Nubia-B is considered as the mature potential source rock of the

Nubia reservoir. The analyzed interval showed mixed types of organic matter, with the marine

component dominating in most samples and decreasing generally with depth.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Publications Arising from This Thesisviii

PUBLICATIONS ARISING FROM THIS THESIS

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Noteix


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Notex

NOTE

The present thesis is submitted to the Faculty of Science, Mansoura University in partial fulfillment of

the requirements for the degree of Master of Science in Petroleum Geology. Beside the research work

materialized in this thesis, the candidate has attended nine post-graduate courses for one academic

year in the following topics:

First semester Second semester

1- Petroleum Geology-1 1- Petroleum Geology-2

2- Hydrogeology-1 2- Hydrogeology-2

3- Well Logging 3- Organic Geochemistry

4- Reservoir Characterization 4- Static Geology

5- Statistics 5- Numerical Analysis

6- Computer Science 6- English Language

The candidate has been successfully passed the final examination in these courses.

Chairperson of Geology Department

Prof. Dr. Hosni H. Ghazala

Faculty of Science - Mansoura University


Acknowledgmentsxi

ACKNOWLEDGMENTS

Any success earned by this research deservedly belongs to almighty "Allah" Thanks God.

Perhaps the most significant contribution was by Prof Dr. Ghalib Issa, Assistant Professor of

Petroleum Geology, Mansoura University. His unflagging efforts to improve readability, assistance

with writing, and his suggestions concerning content were an incalculable asset. In addition, his

encouragement commitment to accuracy, with a difficult and often tedious task, does not pass

unnoticed. I have learned a great deal from him about how to express the concepts in a clear and

logical manner, and made a major contribution refining this work, so he deserves a special deep heart

thanks. Therefore, I affectionately dedicated my research to his amazing patience and tolerance.

I equally thank Dr. Mohamed Afife, Lecturer of Petroleum Geology, Benha University, who

introduced various aspects of organic geochemistry to me, a very exciting subject. Co-operation and

technical assistance from my fellow-colleagues at Geology Department-Mansoura University are

gratefully acknowledged. I was also helped by Geology Department-secretariat staff, to handle the

administrative subjects.

I would like to take this opportunity to express my grateful thanks to the managerial and technical IES

for their assistance and support throughout the research program described here. This work is a

testimony to their professionalism and technical excellence.

Gratitude is wished to extend the appreciation to the Egyptian General Petroleum Cooperation

(EGPC), and the Belayim Petroleum Company (PETROBEL) for their approval and permission to use

the material of study. This research and its preparation were influenced by the cumulative experience

of Dr. Mohammed Awad Ahmed, lecturer of Applied Geophysics, Mansoura University, who

pointed me in the right direction about this interesting subject. I am grateful to my father Mr.

Abdallah Abu Al-Atta, who taught me to cherish excellence. I would like to thank my family for

their patience with regard to the time I spent in writing and rewriting the material ultimately compiled

in this research.

I express explicitly my appreciation to a special person, my spouse Dr. N. Sherief, who alternatively

threatened me with dire consequences to make me complete this research. Without her affectionate

support, completion of this work would not have been possible.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Dedicationxii

DEDICATION

GGRRAATTEEFFUULLLLYY DDEEDDIICCAATTEEDD

TTOO MMYY PPAARREENNTT AANNDD MMYY WWIIFFEE

WWHHOOSSEE EENNCCOOUURRAAGGEEMMEENNTTSS IINNSSPPIIRREEDD MMEE!!


Contentsxiii

CONTENTS

AUTHOR’S DECLARATION ......................................................................................................................................III

THESIS ABSTRACT .................................................................................................................................................V

PUBLICATIONS ARISING FROM THIS THESIS.........................................................................................................VIII

AABBUU AALL--AATTTTAA,, AA..MM..,, IISSSSAA,, II..GG..,, AAHHMMEEDD,, AA..MM..,, AANNDD AAFFIIFFEE,, MM..MM.. ((22001144)).. SSOOUURRCCEE RROOCCKK EEVVAALLUUAATTIIOONN AANNDD

OORRGGAANNIICC GGEEOOCCHHEEMMIISSTTRRYY OOFF BBEELLAAYYIIMM MMAARRIINNEE OOIILL FFIIEELLDD,, GGUULLFF OOFF SSUUEEZZ,, EEGGYYPPTT.. ''RREEVVIIEEWW EEGGYYPPTTIIAANN

PPEETTRROOLLEEUUMM RREESSEEAARRCCHH IINNSSTTIITTUUTTEE;; EEGGYYPPTTIIAANN JJOOUURRNNAALL OOFF PPEETTRROOLLEEUUMM ((EEGGYYJJPP)),, 2233((33)),, ((PPPP.. 228855--330022)). .........VIII

NOTE ...................................................................................................................................................................IX

NOTE ....................................................................................................................................................................X

ACKNOWLEDGMENTS.............................................................................................................................................XI

DEDICATION........................................................................................................................................................XII

CONTENTS..........................................................................................................................................................XIII

LIST OF TABLES .................................................................................................................................................XVI

LIST OF FIGURES .............................................................................................................................................XVIII

LIST OF FIGURES .............................................................................................................................................XVIII

LIST OF EQUATIONS.........................................................................................................................................XXXI

LIST OF EQUATIONS.........................................................................................................................................XXXI

1. INTRODUCTION .....................................................................................................................................1-1

1.1 General ............................................................................................................................................1-1

1.2 Exploration history of belayim marine oil field ...........................................................................1-1

1.3 Aim of study ....................................................................................................................................1-1

1.4 Proposed investigation ..................................................................................................................1-3

1.4.1 GEOLOGICAL INVESTIGATIONS .......................................................................................................... 1-3 1.4.2 GEOCHEMICAL INVESTIGATIONS ....................................................................................................... 1-3 1.4.3 GEOPHYSICAL INVESTIGATIONS ........................................................................................................ 1-3 1.4.4 NUMERICAL BASIN MODELING............................................................................................................ 1-4

1.5 Approach and methods .................................................................................................................1-4

1.5.1 CONCEPTUAL FRAMEWORK ................................................................................................................. 1-4 1.5.2 EXPLORATION GEOCHEMICAL MODELING ........................................................................................ 1-4 1.5.3 RISK MANAGEMENT SYSTEM ............................................................................................................... 1-5

1.6 Data base ........................................................................................................................................1-5

1.6.1 SUBSURFACE DATA ............................................................................................................................... 1-5 1.6.2 TECHNICAL FACILITIES ........................................................................................................................ 1-5

2. GEOLOGIC SETTING AND TECTONIC FRAMEWORK ..................................................................2-1

2.1 General ............................................................................................................................................2-1

2.2 Geological overview .......................................................................................................................2-1

2.3 Tectonic evolution of the Gulf of Suez. .......................................................................................2-6

2.4 Structural setting of the Gulf of Suez ........................................................................................2-11

2.5 Lithostratigraphy ..........................................................................................................................2-12


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Contentsxiv

2.5.1 Pre-rift succession ................................................................................................................................2-13 2.5.2 Syn-rift succession................................................................................................................................2-17 2.5.3 Post-rift succession ..............................................................................................................................2-19

A - Baba Member...............................................................................................................................................2-20 B - Sidri Clastic Member ...................................................................................................................................2-20 C - Feiran Member.............................................................................................................................................2-20 D - Hammam Faraun Member .........................................................................................................................2-20

2.6 Petroleum system ........................................................................................................................ 2-24

2.6.1 Source rocks..........................................................................................................................................2-24 2.6.2 Geothermal gradients ..........................................................................................................................2-29 2.6.3 Reservoir rocks .....................................................................................................................................2-31 2.6.4 Seals .......................................................................................................................................................2-34 2.6.5 Traps ......................................................................................................................................................2-35 2.6.6 Oil types.................................................................................................................................................2-36

2.7 Belayim Marine Oil Field reserves by play................................................................................ 2-37

2.7.1 Belayim Stratigraphic-Structural Play ................................................................................................2-37 2.7.2 Kareem-Upper Rudeis Stratigraphic-Structural-Unconformity Play ...............................................2-37 2.7.3 Nubia Structural-Unconformity Play...................................................................................................2-38

2.7.4 Upper Cretaceous Stratigraphic-Structural Play ...............................................................................2-39

2.7.5 Upper Cretaceous Structural Play ......................................................................................................2-39

3. THEORETICAL ASPECTS...................................................................................................................... 3-1

PART I: BOREHOLE GEOPHYSICS: TECHNIQUES USED AND DATA PROCESSING......................................................3-1

3.1 Procedures of Formation Evaluation........................................................................................... 3-1

3.1.1 Formation temperature and Rw determination ..................................................................................3-1 3.1.2 Clay volume analysis ..............................................................................................................................3-1 3.1.3 Porosity analysis .....................................................................................................................................3-3 3.1.4 Water saturation analysis ......................................................................................................................3-6 3.1.5 Cutoffs and summation reports ............................................................................................................3-8

3.2 Source Rock Analysis .................................................................................................................... 3-8

3.2.1 ∆T log R Technique................................................................................................................................3-9

PART II: NUMERICAL BASIN MODELING.............................................................................................................3-11

3.3 Introduction.................................................................................................................................. 3-11

3.3.1 Construction of The New Geometry...................................................................................................3-11 3.3.2 Heat Flow Analysis ...............................................................................................................................3-13 3.3.3 Kinetics of Calibration Parameters .....................................................................................................3-16 3.3.4 Petroleum Generation Kinetics ...........................................................................................................3-18 3.3.5 Adsorption Models ................................................................................................................................3-22 3.3.6 PVT Analysis ..........................................................................................................................................3-23 3.3.7 Reservoir Characterization ..................................................................................................................3-23 3.3.8 Risk and Uncertainty ............................................................................................................................3-23

4. RESULTS AND DISCUSSIONS ........................................................................................................... 4-1


Contentsxv

4.1 Formation Evaluation .....................................................................................................................4-1

4.2 Basin Modeling Procedure .............................................................................................................4-2

4.3 Geohistory .....................................................................................................................................4-23

4.3.1 Burial history......................................................................................................................................... 4-23 4.3.2 Thermal history .................................................................................................................................... 4-24

4.4 Thermal Maturity and Hydrocarbon Generation ......................................................................4-29

4.4.1 Thebes Formation ................................................................................................................................ 4-37 4.4.2 Duwi Formation .................................................................................................................................... 4-47 4.4.3 Nubia A Formation ............................................................................................................................... 4-54 4.4.4 Nubia B Formation ............................................................................................................................... 4-61

4.5 Reservoir Characterization and Hydrocarbon Stability............................................................4-98

4.5.1 Belayim Formation (Hammam Faraun) ............................................................................................. 4-98 4.5.2 Rudeis oil-bearing zone ..................................................................................................................... 4-100 4.5.3 Thebes Formation .............................................................................................................................. 4-105 4.5.4 Matulla Formation .............................................................................................................................. 4-106 4.5.5 Wata Formation.................................................................................................................................. 4-109 4.5.6 Raha Formation .................................................................................................................................. 4-110 4.5.7 Nubia A Formation ............................................................................................................................. 4-112

4.6 1D Numerical MODELING Analysis ..........................................................................................4-119

5. SUMMARY AND CONCLUSIONS ........................................................................................................5-1

5.1 Conclusions .....................................................................................................................................5-3

Migration ................................................................................................................................................................... 5-8

5.2 Recommendations ..........................................................................................................................5-8

6. REFERENCES ............................................................................................................................................6-1

ا ا ...........................................................................................................................................................


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Tablesxvi

LIST OF TABLES

TABLE 3.1: WEIGHTED FACTORS AND ACTIVATION ENERGIES USED IN EASY %RO. ......................................... 3-18

TABLE 3.2: RESULTS OF OPTIMIZATION OF KINETIC PARAMETERS AND TEMPERATURE LIMITS OF THE OIL AND GAS

WINDOWS FOR THE FIVE KEROGEN ORGANO FACIES (COMPILED AFTER (PEPPER AND CORVI, 1995)). .......... 3-22

TABLE 4.1: CHRONOSTRATIGRAPHIC CONCEPTUAL MODEL OF THE BASIN FILL IN TERMS OF GEOLOGIC PROCESSES

OPERATING AT A SPECIFIC TIME FOR WELL BM-57. ................................................................................. 4-3












OPERATING AT A SPECIFIC TIME FOR WELL 113-M-27. ............................................................................ 4-9


OPERATING AT A SPECIFIC TIME FOR WELL 113-M-34. .......................................................................... 4-10

TABLE 4.9: SUMMARY OF SOME ESTABLISHED CHARACTERISTIC PARAMETERS OF LITHOSTRATIGRAPHIC UNIT IN BELAYIM

MARINE OIL FIELD USED FOR MODELING. ............................................................................................ 4-12

TABLE 4.10: THE THERMAL BOUNDARY CONDITIONS FOR WELL BM-57 INCLUDING THE SEDIMENT-WATER INTERFACE

TEMPERATURE AT THE TOP OF THE MODEL AND THE PALEO-HEAT FLOW AT THE BOTTOM. SEDIMENT–WATER

INTERFACE TEMPERATURE DEPENDS ON WATER DEPTH AND PALEOLATITUDE, SYNTHESIZED AFTER (WYGRALA,

1989). THE BASAL HEAT FLOW VALUES ARE SPECIFIED FOR EACH GEOLOGIC EVENT USING THE KNOWN PLATE

TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN, 1990). .............................. 4-13












List of Figuresxvii
















TABLE 4.16: THE THERMAL BOUNDARY CONDITIONS FOR WELL 113-M-27 INCLUDING THE SEDIMENT-WATER

INTERFACE TEMPERATURE AT THE TOP OF THE MODEL AND THE PALEO-HEAT FLOW AT THE BOTTOM. SEDIMENT–

WATER INTERFACE TEMPERATURE DEPENDS ON WATER DEPTH AND PALEOLATITUDE, SYNTHESIZED AFTER

(WYGRALA, 1989). THE BASAL HEAT FLOW VALUES ARE SPECIFIED FOR EACH GEOLOGIC EVENT USING THE KNOWN

PLATE TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN, 1990). ..................... 4-19

TABLE 4.17: THE THERMAL BOUNDARY CONDITIONS FOR WELL 113-M-34 INCLUDING THE SEDIMENT-WATER

INTERFACE TEMPERATURE AT THE TOP OF THE MODEL AND THE PALEO-HEAT FLOW AT THE BOTTOM. SEDIMENT–


(WYGRALA, 1989). THE BASAL HEAT FLOW VALUES ARE SPECIFIED FOR EACH GEOLOGIC EVENT USING THE KNOWN

PLATE TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN, 1990). ..................... 4-20

TABLE 4.18: SOURCE ROCK INTERVALS AND PROPERTIES USED FOR MODELING OF HYDROCARBON GENERATION IN THE

BELAYIM MARINE OILFIELD, BM-57 WELL, BM-65 WELL AND BM-70 WELL, GULF OF SUEZ. ...................... 4-30

TABLE 4.19: FINAL CALCULATED PETROPHYSICAL PARAMETERS FOR EACH INDIVIDUAL BOREHOLE ADDRESSED. IT

INCLUDES DEPTHS AND THICKNESS AND IP-INTERACTIVE PETROPHYSICS® SOFTWARE DEUCED PARAMETERS AS

FOLLOW; RESERVOIR AND PAY CHARACTERIZATION PARAMETERS (INCLUDES NET THICKNESS, EFFECTIVE POROSITY,

WATER SATURATION AND SHALE VOLUME)............................................................................................ 4-98

TABLE 4.20: SUMMARY OF HYDROCARBON POTENTIALITY OF SOURCE ROCK INTERVALS. .................................. 4-120


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Figuresxviii

LIST OF FIGURES

FIGURE 1.1: MAP SHOWING THE STUDY AREA AND LOCATION OF THE STUDIED WELLS, BELAYIM MARINE OIL FIELD,

CENTRAL GULF OF SUEZ, EGYPT (MODIFIED AFTER (MOHAMED AND BAKER, 2002)). ENLARGED LOCATION MAP

OF THE STUDY AREA, BELAYIM MARINE OIL FIELD AND SPATIAL DISTRIBUTION OF THE AVAILABLE WELLS, WHICH

LOCATED BETWEEN LATITUDES 28° 38.5' AND 28° 51.5' AND BETWEEN LONGITUDES 32° 44' AND 33° 13' IN

THE WESTERN PART OF BELAYIM PAY IN THE GULF OF SUEZ. THIS DATASET BELONGS TO BELAYIM PETROLEUM

COMPANY “PETROBEL” CONCESSIONS (BELAYIM MARINE OIL FIELD). THE STUDY AREA INCLUDES 8 WELLS, TWO

OF THEM ARE WATER INJECTION (113-M-27,113-M- 34), WELL BM-65 IS DRY WELL, AND (BM-57, BM-70,

BM-36, BM-24, BM-23) ARE OIL PRODUCING WELLS. ........................................................................... 1-2

FIGURE 2.1: STRUCTURAL MAP OF GULF OF SUEZ RIFT WITH LOCATION OF OIL FIELDS AND MAIN DISCOVERIES, INSET:

LOCATION OF SUB BASINS (GEOLOGY BASED ON (COLLETTA ET AL., 1988; MESHREF, 1990). ....................... 2-2

FIGURE 2.2: TECTONIC SETTING AND STRUCTURAL FRAMEWORK MAP (IHS, 2006) SHOWING MAJOR TECTONIC

DEVELOPMENTS. SUCCESSIVE GROUP OF TILT BLOCKS WITH REGIONAL DIPS. THE HOMOGENEOUS TILT PROVINCES

ARE SEPARATED BY TECTONIC BOUNDARIES (TRANSFORM FAULTS), WHICH ARE THE EFFECTS OF AQABA FAULTS

THAT ACTED AS STRIKE-SLIP FAULTS DURING THE EARLY STAGE OF RIFT STRUCTURATION (ALSHARHAN, 2003).

CROSS-SECTIONS A-A', B-B', AND C-C' ILLUSTRATED IN (FIGURE 2.3). .................................................... 2-3

FIGURE 2.3: REGIONAL GEOLOGICAL CROSS-SECTIONS (IHS, 2006). (MESHREF AND KHALIL, 1990) CALCULATED

5.1 AND 14 KM OF WIDENING IN THE NORTHERN AND CENTRAL PROVINCES OF THE GULF OF SUEZ, RESPECTIVELY,

REPRESENTING AN INCREASE OF 11 AND 17%, RESPECTIVELY, IN THE INITIAL BASIN WIDTH......................... 2-4

FIGURE 2.4: STRUCTURAL CROSS-SECTION ALONG THE CENTRAL RIFT SEGMENT (YOUSSEF, 2000). THE ROLLOVER

ANTICLINE STRUCTURE TRENDING NW IS THE STRUCTURAL STYLE OF THE SYN-RIFT SEQUENCES WHEREAS THE

FAULTED NE DIPPING BLOCKS (FAULTED MONOCLINE) ARE THE STRUCTURAL STYLE OF THE PRE-RIFT SEQUENCES.

THIS REFLECTS THE ROLE OF THE SYN-RIFT LISTRIC FAULTS AND THE PRE-RIFT PLANAR FAULTS ON THE

STRUCTURAL MODEL OF THE BELAYIM AREA. DURING THE EARLY MIOCENE, THE BELAYIM AREA WAS SUBSIDED TO

FORM THE HANGING WALL OF THE EKMA-NEZZAZAT CLYSMIC FAULT ZONE. THIS WAS FOLLOWED BY THE

FORMATION OF TWO SUB-BASINS THAT ARE CONTROLLED BY TWO SETS OF MAJOR NW SYNTHETIC LISTRIC FAN

CLYSMIC FAULT ZONES THROWING SW AND CREATED A SYSTEM OF DOWN STEP BLOCKS TOWARDS THE NE. THE

BELAYIM OFFSHORE AND BELAYIM ONSHORE OIL FIELDS ARE LOCATED ON THE UPLIFT FOOTWALLS OF THOSE

LISTRIC FAN FAULT ZONES (HAMMAD, 2009). ........................................................................................ 2-5

FIGURE 2.5: THE RELATIONSHIP BETWEEN TECTONIC SUBSIDENCE RATES, TYPES, PERIODS, CLIMATE AND SEA LEVEL

CHANGES DURING THE NEOGENE IN THE GULF OF SUEZ (COMPILED AND MODIFIED FROM (BOSWORTH ET AL.,

1998) AND (GRIFFIN, 1999). SMALLER V SYMBOLS REPRESENT PERIODS OF RAPID BASIN SUBSIDENCE, FOR

EXAMPLE, THE BURDIGALIAN; LARGER V SYMBOLS REPRESENT MODEST RATES OF BASIN SUBSIDENCE, FOR

EXAMPLE, IN THE SERRAVALLIAN. ......................................................................................................... 2-9

FIGURE 2.6: DEVELOPMENT STAGES OF THE GULF OF SUEZ, AS AN EXAMPLE OF A TYPICAL INTERIOR FRACTURE RIFT

BASIN AFTER (ALSHARHAN, 2003). .................................................................................................... 2-11

FIGURE 2.7: LITHO-STRATIGRAPHIC COLUMN OF GULF OF SUEZ, (IHS, 2006). ............................................. 2-21

FIGURE 2.8: MAJOR SOURCE KITCHENS AND MIGRATION PATHWAYS OF HYDROCARBONS IN THE GULF OF SUEZ, (IHS,

2006). .......................................................................................................................................... 2-28


List of Figuresxix

FIGURE 2.9: GEOTHERMAL GRADIENT AND HOT SPOT AREAS IN THE GULF OF SUEZ, (IHS, 2006) . ................... 2-30

FIGURE 2.10: SCHEMATIC PLAY TYPES IN THE GULF OF SUEZ, (IHS, 2006) . ................................................ 2-38

FIGURE 3.1: NEUTRON / DENSITY CROSS PLOT THAT USED AS A DOUBLE SHALE INDICATOR (PGL, 2000) . ............ 3-2

FIGURE 3.2: SCHEMATIC REPRESENTATION OF SONIC AND RESISTIVITY-LOG RESPONSES IN SOURCE. NON-SOURCE AND

RESERVOIR INTERVALS USING A DELTA LOG R OVERLAY (MODIFIED FROM (PASSEY ET AL., 1990)). .............. 3-10

FIGURE 3.3: THE GENERAL WORK-FLOW OF PETROLEUM SYSTEM MODELING BASED ON THE FUNDAMENTAL CONCEPT OF

(WELTE AND YÜKLER, 1981). ........................................................................................................... 3-11

FIGURE 3.4: ESTIMATION OF EROSION OF OVERBURDEN BASED ON EXTRAPOLATION OF SONIC INTERVAL TRANSIT TIMES

VS. DEPTH TO AN UNCOMPACTED SHALE VALUE OF 656µS/M (MAGARA, 1986) . ....................................... 3-13

FIGURE 3.5: BOUNDARY VALUE PROBLEM OF THE HEAT FLOW ANALYSIS.......................................................... 3-15

FIGURE 3.6: GEOLOGIC AGE-LATITUDE PLOT OF AVERAGE OCEAN SURFACE TEMPERATURE THAT SHOWS THE EFFECT OF

CLIMATE MODEL AND LATITUDE ON VARIATIONS IN MEAN ANNUAL SEA SURFACE TEMPERATURES. THE INFLECTED

LINES REPRESENT THE ISOTHERMS THROUGH GEOLOGIC TIME AT THE CORRESPONDING LATITUDE. THE LINES

LABELED BY TEMPERATURE IN °C. THE DOTTED LINE INDICATES THE EVOLUTION OF THE SWI TEMPERATURE FOR

AN EXAMPLE (WYGRALA, 1989) ........................................................................................................ 3-16

FIGURE 3.7: EXAMPLE OF HORNER PLOT EXTRAPOLATION METHOD TO CORRECT BHT FOR COOLING DURING DRILLING

AND CIRCULATION. THE CORRECTED STEADY STATE TEMPERATURE FOR THE FORMATION IS 79°C (POELCHAU ET

AL., 1997)..................................................................................................................................... 3-17

FIGURE 3.8: CONCEPT OF MULTIPLE SOURCE TRACING (MANN ET AL., 1997). ................................................. 3-21

FIGURE 3.9: KEROGEN KINETIC CLASSIFICATION: DEFINITION OF FIVE GLOBAL ORGANO FACIES (PEPPER AND CORVI,

1995) . ......................................................................................................................................... 3-21

FIGURE 3.10: ADSORPTION AND MIGRATION PROCESSES. ............................................................................ 3-22

FIGURE 3.11: FLOWCHARTS OF (A) DARCY FLOW AND (B) FLOW PATH MODELING........................................... 3-23

FIGURE 4.1: THE SEDIMENT-WATER INTERFACE TEMPERATURE AT THE TOP OF THE MODEL AND THE PALEO-HEAT FLOW

AT THE BOTTOM. SEDIMENT–WATER INTERFACE TEMPERATURE DEPENDS ON WATER DEPTH AND PALEOLATITUDE,

SYNTHESIZED AFTER (WYGRALA, 1989). THE BASAL HEAT FLOW VALUES ARE SPECIFIED FOR EACH GEOLOGIC

EVENT USING THE KNOWN PLATE TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN,

1990). .......................................................................................................................................... 4-21

FIGURE 4.2: PLOT OF PALEOTEMPERATURE CALIBRATED WITH MEASURED CORRECTED STATIC BOTTOM HOLE

TEMPERATURE IN A REFERENCE WELLS (BM-57 AND BM-70) AGAINST DEPTH. THE CROSS-PLOT OF OBSERVED

AND COMPUTED REFLECTANCE SHOWS A GOOD FIT. ............................................................................... 4-21








Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Figuresxx


TEMPERATURE IN A REFERENCE WELLS (113-M-27 AND 113-M-34) AGAINST DEPTH. THE CROSS-PLOT OF

OBSERVED AND COMPUTED REFLECTANCE SHOWS A GOOD FIT. ................................................................ 4-23

FIGURE 4.6: THE BOUNDARY CONDITIONS ASSESSMENTS FOR WELL BM-57 INCLUDING THE PALEO WATER DEPTH AT

THE TOP, THE SEDIMENT-WATER INTERFACE TEMPERATURE AT MIDDLE (TOP OF THE MODEL) AND THE PALEO-HEAT

FLOW AT THE BOTTOM MUST BE ESTABLISHED TO DETERMINE THE INTERIOR TEMPERATURE FIELD. SEDIMENT–


(WYGRALA, 1989). THE BASAL HEAT FLOW VALUES WERE SPECIFIED FOR EACH GEOLOGIC EVENT USING THE

KNOWN PLATE TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN, 1990). .......... 4-24
































List of Figuresxxi

FIGURE 4.12: THE BOUNDARY CONDITIONS ASSESSMENTS FOR WELL 113-M-27 INCLUDING THE PALEO WATER DEPTH

AT THE TOP, THE SEDIMENT-WATER INTERFACE TEMPERATURE AT MIDDLE (TOP OF THE MODEL) AND THE PALEO-

HEAT FLOW AT THE BOTTOM MUST BE ESTABLISHED TO DETERMINE THE INTERIOR TEMPERATURE FIELD.

SEDIMENT–WATER INTERFACE TEMPERATURE DEPENDS ON WATER DEPTH AND PALEOLATITUDE, SYNTHESIZED

AFTER (WYGRALA, 1989). THE BASAL HEAT FLOW VALUES WERE SPECIFIED FOR EACH GEOLOGIC EVENT USING

THE KNOWN PLATE TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN, 1990)..... 4-27

FIGURE 4.13: THE BOUNDARY CONDITIONS ASSESSMENTS FOR WELL 113-M-34 INCLUDING THE PALEO WATER DEPTH

AT THE TOP, THE SEDIMENT-WATER INTERFACE TEMPERATURE AT MIDDLE (TOP OF THE MODEL) AND THE PALEO-

HEAT FLOW AT THE BOTTOM MUST BE ESTABLISHED TO DETERMINE THE INTERIOR TEMPERATURE FIELD.

SEDIMENT–WATER INTERFACE TEMPERATURE DEPENDS ON WATER DEPTH AND PALEOLATITUDE, SYNTHESIZED

AFTER (WYGRALA, 1989). THE BASAL HEAT FLOW VALUES WERE SPECIFIED FOR EACH GEOLOGIC EVENT USING

THE KNOWN PLATE TECTONIC FRAMEWORK AND CRUSTAL EVOLUTION MODELS (ALLEN AND ALLEN, 1990)..... 4-27

FIGURE 4.14: ABBREVIATED GEOCHEMICAL LOG FOR DITCH CUTTINGS OF THE ENCOUNTERED ORGANIC-RICH INTERVALS

IN BM-57 WELL, BASED ON ROCK-EVAL PYROLYSIS, TOC, AND VITRINITE REFLECTANCE. VITRINITE

REFLECTANCE-DEPTH PLOT SHOWING THE GENERALIZED POSITION OF THE OIL AND GAS ZONES, WHICH WILL VARY

DEPENDING ON KEROGEN TYPE. THESE RO VALUES ARE RELATED TO THE MAXIMUM TEMPERATURE TO WHICH A

PARTICULAR ZONE HAS BEEN EXPOSED................................................................................................. 4-31

FIGURE 4.15: ABBREVIATED GEOCHEMICAL LOG FOR DITCH CUTTINGS OF THE ENCOUNTERED ORGANIC-RICH INTERVALS

IN BM-65 WELL, BASED ON ROCK-EVAL PYROLYSIS, TOC, AND VITRINITE REFLECTANCE. VITRINITE

REFLECTANCE-DEPTH PLOT SHOWING THE GENERALIZED POSITION OF THE OIL AND GAS ZONES, WHICH WILL VARY

DEPENDING ON KEROGEN TYPE. THESE RO VALUES ARE RELATED TO THE MAXIMUM TEMPERATURE TO WHICH A

PARTICULAR ZONE HAS BEEN EXPOSED................................................................................................. 4-32

FIGURE 4.16: QUANTITATIVE SIMULATED GEOHISTORY, BURIAL HISTORY AND RECALIBRATED TEMPERATURE

DEVELOPMENT HISTORY AS A FUNCTION OF TIME AND SPACE OF THE REFERENCE (WELL BM-57) USING THE

PALEOTEMPERATURE DETERMINED BY EASY RO% APPROACH. THE SOLID LINES TRACES THE DEPTH-TIME RELATION

FOR THE SEDIMENT WITH DISCREPANCY BETWEEN PRESENT (COMPACTED) AND DECOMPACTED THICKNESS. THE

LOWER CURVE SHOWS SUBSIDENCE OF THE BASEMENT. THE UPPER CURVES ARE SEA-LEVEL AND THE SEDIMENT

INTERFACE...................................................................................................................................... 4-33






INTERFACE...................................................................................................................................... 4-33






Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Figuresxxii


INTERFACE...................................................................................................................................... 4-34






INTERFACE...................................................................................................................................... 4-34






INTERFACE...................................................................................................................................... 4-35






INTERFACE...................................................................................................................................... 4-35


DEVELOPMENT HISTORY AS A FUNCTION OF TIME AND SPACE OF THE REFERENCE (WELL 113-M-27) USING THE




INTERFACE...................................................................................................................................... 4-36


DEVELOPMENT HISTORY AS A FUNCTION OF TIME AND SPACE OF THE REFERENCE (WELL 113-M-34) USING THE




INTERFACE...................................................................................................................................... 4-36

FIGURE 4.24: THE CORRECTED LOG DATASETS THROUGH A LIMESTONE SEQUENCES OF THE EOCENE THEBES

FORMATION (2565M – 2661M) OF THE BM-57 WELL DRILLED BY THE BELAYIM PETROLEUM COMPANY

(PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE WELL LOGGING DEDUCED LITHOLOGICAL

PARAMETERS AND ORGANOFACIES....................................................................................................... 4-38




List of Figuresxxiii












FORMATION (2859M – 2995M) OF THE BM-23 ST WELL DRILLED BY THE BELAYIM PETROLEUM COMPANY



FIGURE 4.29: THE CORRECTED LOG DATASETS THROUGH A LIMESTONE SEQUENCES OF THE UPPER SENONIAN DUWI

FORMATION (2763 M AND 2772 M) OF THE BM-57 WELL DRILLED BY THE BELAYIM PETROLEUM COMPANY




FORMATION (3049 M AND 3085 M) OF THE BM-23 WELL DRILLED BY THE BELAYIM PETROLEUM COMPANY




FORMATION (3307 M AND 3353 M) OF THE 113-M-34 WELL DRILLED BY THE BELAYIM PETROLEUM COMPANY



FIGURE 4.32: THE CORRECTED LOG DATASETS THROUGH A SHALE AND SANDSTONE SEQUENCES OF THE EARLY

CRETACEOUS NUBIA-A FORMATION (2988 M AND 3129 M) OF THE BM-57 WELL DRILLED BY THE BELAYIM

PETROLEUM COMPANY (PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE WELL LOGGING

DEDUCED LITHOLOGICAL PARAMETERS AND ORGANOFACIES. ................................................................... 4-55










Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Figuresxxiv

FIGURE 4.35: THE CORRECTED LOG DATASETS THROUGH A SHALE AND SANDSTONE SEQUENCES OF THE

CARBONIFEROUS NUBIA-B FORMATION (3297 M AND 3342 M) OF THE BM-65 WELL DRILLED BY THE BELAYIM


DEDUCED LITHOLOGICAL PARAMETERS AND ORGANOFACIES..................................................................... 4-62


CRETACEOUS NUBIA-B FORMATION (3018 M AND 3094 M) OF THE BM-24 WELL DRILLED BY THE BELAYIM


DEDUCED LITHOLOGICAL PARAMETERS AND ORGANOFACIES..................................................................... 4-63

FIGURE 4.37: THE SIMULATED VITRINITE REFLECTANCE VALUE AND THE ASSOCIATED THERMAL HISTORY OF THEBES,

DUWI, NUBIA-A, NUBIA-B FORMATIONS IN A REFERENCE WELL (BM-57) AGAINST TIME. THE CALCULATED

VITRINITE REFLECTANCE VALUE CARRIED OUT USING THE EASY RO% ALGORITHM (SWEENEY AND BURNHAM,

1990) AND TEMPERATURE PROFILE AGAINST GEOLOGIC TIME SCALE (MA). ............................................... 4-68

FIGURE 4.38: THE SIMULATED VITRINITE REFLECTANCE VALUE AND THE ASSOCIATED THERMAL HISTORY OF THEBES

FORMATION IN A REFERENCE WELL (BM-70) AGAINST TIME. THE CALCULATED VITRINITE REFLECTANCE VALUE

CARRIED OUT USING THE EASY RO% ALGORITHM (SWEENEY AND BURNHAM, 1990) AND TEMPERATURE PROFILE

AGAINST GEOLOGIC TIME SCALE (MA). ................................................................................................ 4-69


NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (BM-36) AGAINST TIME. THE CALCULATED VITRINITE

REFLECTANCE VALUE CARRIED OUT USING THE EASY RO% ALGORITHM (SWEENEY AND BURNHAM, 1990) AND

TEMPERATURE PROFILE AGAINST GEOLOGIC TIME SCALE (MA). ................................................................ 4-70





FIGURE 4.41 THE SIMULATED VITRINITE REFLECTANCE VALUE AND THE ASSOCIATED THERMAL HISTORY OF NUBIA-B





AND DUWI FORMATIONS IN A REFERENCE WELL (BM-23) AGAINST TIME. THE CALCULATED VITRINITE




AND DUWI NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (113-M-27) AGAINST TIME. THE

CALCULATED VITRINITE REFLECTANCE VALUE CARRIED OUT USING THE EASY RO% ALGORITHM (SWEENEY AND

BURNHAM, 1990) AND TEMPERATURE PROFILE AGAINST GEOLOGIC TIME SCALE (MA)................................. 4-74


AND DUWI FORMATIONS IN A REFERENCE WELL (113-M-34) AGAINST TIME. THE CALCULATED VITRINITE


List of Figuresxxv


TEMPERATURE PROFILE AGAINST GEOLOGIC TIME SCALE (MA)................................................................. 4-75

FIGURE 4.45: THE SIMULATED TRANSFORMATION RATIO VALUE AND THE ASSOCIATED BULK GENERATION MASS OF

THEBES, DUWI, NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (BM-57) AGAINST GEOLOGIC TIME

SCALE (MA). ................................................................................................................................... 4-76


THEBES FORMATION IN A REFERENCE WELL (BM-70) AGAINST GEOLOGIC TIME SCALE (MA)........................ 4-77


THEBES, NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (BM-36) AGAINST GEOLOGIC TIME SCALE

(MA). ............................................................................................................................................ 4-78


THEBES, NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (BM-65) AGAINST GEOLOGIC TIME SCALE

(MA). ............................................................................................................................................ 4-79


NUBIA-B FORMATION IN A REFERENCE WELL (BM-24) AGAINST GEOLOGIC TIME SCALE (MA). ..................... 4-80


THEBES, DUWI FORMATIONS IN A REFERENCE WELL (BM-23) AGAINST GEOLOGIC TIME SCALE (MA). ........... 4-81


THEBES, DUWI NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (113-M-27) AGAINST GEOLOGIC

TIME SCALE (MA). ........................................................................................................................... 4-82


THEBES AND DUWI FORMATIONS IN A REFERENCE WELL (113-M-34) AGAINST GEOLOGIC TIME SCALE (MA).. 4-83


DUWI, NUBIA-A, NUBIA-B FORMATIONS IN A REFERENCE WELL (BM-57) AGAINST TIME. THE CALCULATED

VITRINITE REFLECTANCE VALUE CARRIED OUT USING THE EASY RO% ALGORITHM (SWEENEY AND BURNHAM,

1990) AND TEMPERATURE PROFILE AGAINST GEOLOGIC TIME SCALE (MA). ............................................... 4-84














Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Figuresxxvi

FIGURE 4.57: THE SIMULATED VITRINITE REFLECTANCE VALUE AND THE ASSOCIATED THERMAL HISTORY OF NUBIA-B





AND DUWI FORMATIONS IN A REFERENCE WELL (BM-23) AGAINST TIME. THE CALCULATED VITRINITE




AND DUWI NUBIA-A AND NUBIA-B FORMATIONS IN A REFERENCE WELL (113-M-27) AGAINST TIME. THE

CALCULATED VITRINITE REFLECTANCE VALUE CARRIED OUT USING THE EASY RO% ALGORITHM (SWEENEY AND

BURNHAM, 1990) AND TEMPERATURE PROFILE AGAINST GEOLOGIC TIME SCALE (MA)................................. 4-90


AND DUWI FORMATIONS IN A REFERENCE WELL (113-M-34) AGAINST TIME. THE CALCULATED VITRINITE



FIGURE 4.61: THE SIMULATED BURIAL HISTORY OF WELL BM-57, WITH THE HYDROCARBON ZONE PROPERTIES

OVERLAY ACCORDING TO THE PEPPER&CORVI(1995)_TII-S(A) OIL-GAS KINETICS EQUATION OF (PEPPER AND

CORVI, 1995) FOR THE SOURCE INTERVAL OF THEBES AND DUWI FORMATIONS THROUGH GEOLOGIC TIME SCALE

(MA). ............................................................................................................................................ 4-92


OVERLAY ACCORDING TO THE PEPPER&CORVI(1995)_TII(B) OIL-GAS KINETICS EQUATION OF (PEPPER AND

CORVI, 1995) FOR THE SOURCE INTERVAL OF NUBIA-A AND NUBIA-B FORMATIONS THROUGH GEOLOGIC TIME

SCALE (MA). ................................................................................................................................... 4-92



CORVI, 1995) FOR THE SOURCE INTERVAL OF THEBES FORMATION THROUGH GEOLOGIC TIME SCALE (MA). .. 4-93







SCALE (MA). ................................................................................................................................... 4-94





List of Figuresxxvii




SCALE (MA). ................................................................................................................................... 4-95



CORVI, 1995) FOR THE SOURCE INTERVAL OF NUBIA-B FORMATION THROUGH GEOLOGIC TIME SCALE (MA). 4-95




(MA). ............................................................................................................................................ 4-96

FIGURE 4.70: THE SIMULATED BURIAL HISTORY OF WELL 113-M-27, WITH THE HYDROCARBON ZONE PROPERTIES



(MA). ............................................................................................................................................ 4-96




SCALE (MA). ................................................................................................................................... 4-97




(MA). ............................................................................................................................................ 4-97

FIGURE 4.73: THE CORRECTED LOG DATASETS AND LITHO-SATURATION CROSS PLOT THROUGH A SANDSTONE

SEQUENCE OF THE BELAYIM FORMATION (HAMMAM FARAUN MEMBER) (2026-2040 M TVDSS) OF THE BM-57

WELL DRILLED BY THE BELAYIM COMPANY (PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE

WELL LOGGING DEDUCED SATURATION AND LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE

PETROPHYSICS SOFTWARE. ............................................................................................................... 4-99


SEQUENCE OF THE RUDEIS FORMATION (RUDEIS-P1 AND RUDEIS-P2) (2424-2456 M AND 2480-2550 M

TVDSS, RESPECTIVELY) OF THE BM-57 WELL DRILLED BY THE BELAYIM COMPANY (PETROBEL), SHOWING THE

ZONE–WISE REPRESENTATION OF THE WELL LOGGING DEDUCED SATURATION AND LITHOLOGICAL PARAMETERS

UTILIZING THE IP- INTERACTIVE PETROPHYSICS SOFTWARE. ................................................................ 4-100


SEQUENCE OF THE RUDEIS FORMATION (RUDEIS-P 2984-3005 M TVDSS) OF THE BM-70 WELL DRILLED BY THE

BELAYIM COMPANY (PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE WELL LOGGING DEDUCED

SATURATION AND LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE PETROPHYSICS SOFTWARE.. 4-101


SEQUENCE OF THE RUDEIS FORMATION (RUDEIS-P 2410-2466 M TVDSS) OF THE BM-24 WELL DRILLED BY THE


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Figuresxxviii


SATURATION AND LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE PETROPHYSICS SOFTWARE .. 4-101












SEQUENCE OF THE THEBES FORMATION (THEBES-P) (3340-3346 M TVDSS) OF THE BM-70 WELL DRILLED BY

THE BELAYIM COMPANY (PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE WELL LOGGING

DEDUCED SATURATION AND LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE PETROPHYSICS

SOFTWARE. ................................................................................................................................... 4-105


SEQUENCE OF THE MATULLA FORMATION (MATULLA-P) (2831-2866 M TVDSS) OF THE BM-57 WELL DRILLED BY



SOFTWARE. ................................................................................................................................... 4-106





SOFTWARE. ................................................................................................................................... 4-107





SOFTWARE. ................................................................................................................................... 4-108


SEQUENCE OF THE WATA FORMATION (WATA-P) (2894-2909 M TVDSS) OF THE BM-36 WELL DRILLED BY THE




SEQUENCE OF THE WATA FORMATION (WATA-P) (2746-2754 M TVDSS) OF THE BM-24 WELL DRILLED BY THE


List of Figuresxxix




SEQUENCE OF THE RAHA FORMATION (RAHA-P) (2907-2933 M TVDSS) OF THE BM-57 WELL DRILLED BY THE




SEQUENCE OF THE NUBIA A FORMATION (NUBIA A-P1, NUBIA A-P2, NUBIA A-P3 AND NUBIA A-P4) (2933-

2988, 3030-3039, 3056-3069, AND 3129-3144 M TVDSS, CORRESPONDINGLY) OF THE BM-57 WELL

DRILLED BY THE BELAYIM COMPANY (PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE WELL

LOGGING DEDUCED SATURATION AND LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE PETROPHYSICS

SOFTWARE.................................................................................................................................... 4-113


SEQUENCE OF THE NUBIA A FORMATION (NUBIA A-P) (2909-2931 M TVDSS, CORRESPONDINGLY) OF THE BM-

36 WELL DRILLED BY THE BELAYIM COMPANY (PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE

WELL LOGGING DEDUCED SATURATION AND LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE

PETROPHYSICS SOFTWARE. ............................................................................................................. 4-114


SEQUENCE OF THE NUBIA A FORMATION (NUBIA A-P1, NUBIA A-P2, AND NUBIA A-P3) (2834-2875, 2916-

2923, AND 2983-3005 M TVDSS, CORRESPONDINGLY) OF THE BM-24 WELL DRILLED BY THE BELAYIM COMPANY

(PETROBEL), SHOWING THE ZONE–WISE REPRESENTATION OF THE WELL LOGGING DEDUCED SATURATION AND

LITHOLOGICAL PARAMETERS UTILIZING THE IP- INTERACTIVE PETROPHYSICS SOFTWARE. ......................... 4-115

FIGURE 4.89: THE THERMAL HISTORY OF THE PAY-ZONE INTERVALS (BELAYIM HAMMAM FARAUN MEMBER, UPPER

RUDEIS, MATULLA, AND RAHA, NUBIA-A, NUBIA-B AND NUBIA C FORMATIONS) IN A REFERENCE WELL (BM-57),

WHICH REPRESENTS THE TEMPERATURE HISTORY IN CELSIUS AGAINST GEOLOGIC TIME SCALE (MA). IT IS OBVIOUS

THAT THE RESERVOIR TEMPERATURE IS RELATIVELY HIGH (MORE THAN 80°C) SUGGESTING A BIODEGRADATION

EFFECTS. THIS SUGGESTS A THERMODYNAMICALLY INSTABLE CRUDE OIL WITHOUT ANY POSSIBILITY TO

SECONDARY CRACKING GAS GENERATION. .......................................................................................... 4-117

FIGURE 4.90: THE THERMAL HISTORY OF THE PAY-ZONE INTERVALS (UPPER RUDEIS AND THEBES FORMATIONS) IN A

REFERENCE WELL (BM-70), WHICH REPRESENTS THE TEMPERATURE HISTORY IN CELSIUS AGAINST GEOLOGIC TIME

SCALE (MA). IT IS OBVIOUS THAT THE RESERVOIR TEMPERATURE IS RELATIVELY HIGH (MORE THAN 80°C)

SUGGESTING A BIODEGRADATION EFFECTS. THIS SUGGESTS A THERMODYNAMICALLY INSTABLE CRUDE OIL

WITHOUT ANY POSSIBILITY TO SECONDARY CRACKING GAS GENERATION................................................. 4-117

FIGURE 4.91: THE THERMAL HISTORY OF THE PAY-ZONE INTERVALS (UPPER RUDEIS, MATULLA, WATA, AND NUBIA-A

FORMATIONS) IN A REFERENCE WELL (BM-36), WHICH REPRESENTS THE TEMPERATURE HISTORY IN CELSIUS

AGAINST GEOLOGIC TIME SCALE (MA). IT IS OBVIOUS THAT THE RESERVOIR TEMPERATURE IS RELATIVELY HIGH

(MORE THAN 80°C) SUGGESTING A BIODEGRADATION EFFECTS. THIS SUGGESTS A THERMODYNAMICALLY INSTABLE

CRUDE OIL WITHOUT ANY POSSIBILITY TO SECONDARY CRACKING GAS GENERATION. ................................ 4-118


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed List of Equationsxxx

FIGURE 4.92: THE THERMAL HISTORY OF THE PAY-ZONE INTERVALS (UPPER RUDEIS, WATA, AND NUBIA-A

FORMATIONS) IN A REFERENCE WELL (BM-24), WHICH REPRESENTS THE TEMPERATURE HISTORY IN CELSIUS

AGAINST GEOLOGIC TIME SCALE (MA). IT IS OBVIOUS THAT THE RESERVOIR TEMPERATURE IS RELATIVELY HIGH

(MORE THAN 80°C) SUGGESTING A BIODEGRADATION EFFECTS. THIS SUGGESTS A THERMODYNAMICALLY INSTABLE

CRUDE OIL WITHOUT ANY POSSIBILITY TO SECONDARY CRACKING GAS GENERATION.................................. 4-118

FIGURE 4.93: THE THERMAL HISTORY OF THE PAY-ZONE INTERVALS (UPPER RUDEIS AND MATULLA FORMATIONS) IN A

REFERENCE WELL (BM-23), WHICH REPRESENTS THE TEMPERATURE HISTORY IN CELSIUS AGAINST GEOLOGIC TIME

SCALE (MA). IT IS OBVIOUS THAT THE RESERVOIR TEMPERATURE IS RELATIVELY HIGH (MORE THAN 80°C)

SUGGESTING A BIODEGRADATION EFFECTS. THIS SUGGESTS A THERMODYNAMICALLY INSTABLE CRUDE OIL

WITHOUT ANY POSSIBILITY TO SECONDARY CRACKING GAS GENERATION. ................................................ 4-119


List of Equationsxxxi

LIST OF EQUATIONS

EQUATION 3-1: FORMATION TEMPERATURE EQUATION (ASQUITH, 1980). ....................................................... 3-1

EQUATION 3-2: SHALE INDEX FROM GAMMA RAY LOG. ................................................................................... 3-1

EQUATION 3-3: CORRECTED VOLUME OF SHALE BASED ON SHALE INDEX (STIEBER, 1970)................................... 3-2

EQUATION 3-4: VOLUME OF SHALE ESTIMATED FROM NEUTRON LOGS (PGL, 2000) .......................................... 3-2

EQUATION 3-5: VOLUME OF SHALE ESTIMATED FROM RESISTIVITY LOGS (PGL, 2000)........................................ 3-2

EQUATION 3-6: SHALE VOLUME ESTIMATED FROM NEUTRON/DENSITY LOGS AS A DOUBLE SHALE INDICATOR (PGL,

2000) . ........................................................................................................................................... 3-3

EQUATION 3-7: SHALE VOLUME ESTIMATED FROM SONIC/DENSITY LOGS AS A DOUBLE SHALE INDICATOR (PGL, 2000).

...................................................................................................................................................... 3-3

EQUATION 3-8: SHALE VOLUME ESTIMATED FROM NEUTRON/SONIC LOGS AS A DOUBLE SHALE INDICATOR (PGL,

2000). ............................................................................................................................................ 3-3

EQUATION 3-9: ROCK RESISTIVITY-POROSITY RELATIONSHIP (ARCHIE, 1942). ................................................. 3-3

EQUATION 3-10: ROCK RESISTIVITY-POROSITY RELATIONSHIP (WINSAUER, 1952)............................................ 3-3

EQUATION 3-11: POROSITY-TRANSIT TIME RELATIONSHIP IN COMPACTED FORMATION (WYLLIE ET AL., 1956). ..... 3-4

EQUATION 3-12: POROSITY-TRANSIT TIME RELATIONSHIP IN UNCONSOLIDATED FORMATION (WYLLIE ET AL., 1958).3-

4

EQUATION 3-13: POROSITY OF UNCOMPACTED LAMINATED SHALY FORMATION (DRESSER ATLAS, 1979). .............. 3-5

EQUATION 3-14: THE DENSITY POROSITY IN THE FORMATION OF INTEREST (BASSIOUNI, 1994; DRESSER ATLAS,

1979). ............................................................................................................................................ 3-5

EQUATION 3-15: THE NEUTRON POROSITY IN THE FORMATION OF INTEREST (BASSIOUNI, 1994). ....................... 3-6

EQUATION 3-16: THE SONIC POROSITY IN THE FORMATION OF INTEREST (BASSIOUNI, 1994). ............................ 3-6

EQUATION 3-17: TRUE EFFECTIVE POROSITY OF A SHALY FORMATION IN THE ZONE OF INTEREST (BASSIOUNI, 1994).

...................................................................................................................................................... 3-6

EQUATION 3-18: WATER SATURATION IN A CLEAN FORMATION (ARCHIE, 1942)................................................ 3-7

EQUATION 3-19: THE GENERALIZED WATER SATURATION EQUATION (ARCHIE, 1950)........................................ 3-7

EQUATION 3-20: SIMANDOUX WATER SATURATION EQUATION (SIMANDOUX, 1963). ......................................... 3-7

EQUATION 3-21: WATER SATURATION EQUATION OF A SHALY FORMATION (FERTL AND HAMMACK, 1971). ............ 3-7

EQUATION 3-22: AVERAGE POROSITY (PGL, 2000). ..................................................................................... 3-8

EQUATION 3-23: AVERAGE WATER SATURATION (PGL, 2000). ....................................................................... 3-8

EQUATION 3-24: AVERAGE CLAY VOLUME (PGL, 2000). ................................................................................ 3-8

EQUATION 3-25: ∆LOG R=LOG10 (RT/RTBL) +0.02*(∆ T - ∆TBL) ............................................................ 3-9

EQUATION 3-26: TOC%= (∆ LOG R) * 10(2.297-0.1688*LOM) ......................................................... 3-10

EQUATION 3-27: THE RATE OF SEDIMENTATION WITH RESPECT TO TIME (VAN HINTE, 1978)............................ 3-12

EQUATION 3-28: BOUNDARY CONDITION FORMULATION............................................................................... 3-14

EQUATION 3-29: SEDIMENT WATER INTERFACE TEMPERATURE FROM AIR-SURFACE TEMPERATURE....................... 3-15


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed xxxii

EQUATION 3-30: VITRINITE REFLECTANCE ESTIMATION BASED ON (SWEENEY AND BURNHAM, 1990). ................ 3-18

EQUATION 3-31: ARRHENIUS LAW. ........................................................................................................... 3-19

EQUATION 3-32: TOTAL MASS OF PETROLEUM THAT GENERATED IN THE SOURCE ROCK PER TOTAL VOLUME OF THE

SEDIMENT....................................................................................................................................... 3-19


xxxiii

Mansoura UniversityIntroduction2015

General1-1

1. INTRODUCTION

1.1 GENERAL

The hydrocarbon potentiality of the Gulf of Suez basin is closely linked with the tectono-stratigraphic

history that has created multiple reservoirs and seal combinations. Adequate potential source rocks

are spatially widespread in the area with two major oil types identified. The research study aims to

improve resolution of the basin architecture and understanding of the basin history of this prolific

producing area, through the application of the Petroleum System Modeling (PSM). The Petroleum

System Modeling (PSM) is an integrative approach using structural, stratigraphic, seismic data with

petrophysical and geochemical analysis data in a basin to simulate basin development in a forward

modeling approach, e.g. subsidence, structural and tectonic events, hydrocarbon generation,

migration and emplacement through geologic time. It outlines the spatial extent of the different

petroleum systems and provides data for risk maps to guide subsequent new exploration phases.

The Gulf of Suez (Figure 1.1) considered as the most prolific oil province in Egypt with excellent

hydrocarbon potentiality. It contains more than 80 oil fields (Alsharhan, 2003). The Belayim Marine Oil

Field is located in the eastern side of the Gulf of Suez, 165 km southeast of Suez city. The Belayim

Marine Field concession is about 9km2 to the west of Sinai shore line.

1.2 EXPLORATION HISTORY OF BELAYIM MARINE OIL FIELD

The Gulf of Suez province produces about 66% of the total crude oil production of Egypt (Hammad,

2009) and therefore it is subjected to intensive exploration activities. In 1950-1952, a group of

California independents commenced exploration activities in the Belayim area. Their efforts led to the

discovery of a number of significant fields. The first offshore seismic line was shot in 1955 by the

Company Orientale des Petroles d ‘Egypt (COPE) (now Petrobel) and by mid 1950s; they and their

partner Agip and Petrofina had seismically mapped several large structural prospects immediately

offshore from the Belayim field production. This led to the discovery of Belayim Marine field in 1961

by (COPE). The discovery well (BM-1) oil accumulations were found in a number of sand horizons in

the Miocene (zones II, IV and V) and in the Cretaceous, Turonian and the Cenomanian sands and

sandstones. The Lower Senonian, which is eroded in the discovery well, was reported oil-bearing in

other wells drilled later in the field area. The important pre-Cenomanian clastic unit as a reservoir

(known as Nubia “A”) was discovered in 1985 (well BM-24). Since 1961 till 1967, 18 wells were drilled.

Since 1977 till now more than 100 wells mostly deviated wells were drilled.

1.3 AIM OF STUDY

The rationale for the research comes from the realization that there is a heterogeneous distribution of

the productive wells, hydrocarbon phases (that includes dry, light hydrocarbon and crude oil with

different API and sulfur contents, depths and rates of production) in the Gulf of Suez, Egypt. The

present study aims to:

1) Integrate geochemical and geophysical as well as the available geological data in Belayim Marine

Oil Field. 2) Evaluate the organic source facies utilizing an extensive modeling study. 3) Improve the

understanding of the petroleum system. Integrated 1D modeling was applied and led to a maturity

model, using lithologic concepts, derived from well log analysis and available geochemical data.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Aim of study1-2

Figure 1.1: Map showing the study area and location of the studied wells, Belayim Marine oil field, central Gulf of Suez, Egypt (modified after (Mohamed and Baker, 2002)). Enlarged location map of the study area, Belayim Marine oil field and spatial distribution of the available wells, which located between latitudes 28° 38.5' and 28° 51.5' and between longitudes 32° 44' and 33° 13' in the western part of Belayim Pay in the Gulf of Suez. This dataset belongs to Belayim Petroleum Company “Petrobel” concessions (Belayim Marine Oil Field). The Study area includes 8 wells, two of them are water injection (113-M-27,113-M- 34), well BM-65 is dry well, and (BM-57, BM-70, BM-36, BM-24, BM-23) are oil producing wells.


Proposed investigation1-3

The primary objectives of this research are:

- Reconstruct the multi-phase tectonic history responsible for the development of the basin from the

preserved stratigraphy (in particular, the strata patterns).

- Give a proper appraisal of the geologic situation integrated with comprehensive petroleum

characterization model to evaluate the petroleum system and hydrocarbon potentialities of Belayim

Marine Oil Field.

- Interpretation of available wireline logs to identify the lithological, mineralogical and petrophysical

parameters of the petroleum system element (e.g. source, reservoir and seal rock).

- Numerical basin modeling using PetroMod software to studying the physical and thermal histories of

Belayim Marine Oil Field that lead to an estimation of the timing of hydrocarbon generation and their

expulsion.

- Quantify the process of oil generation and expulsion of the organic rich intervals using PetroMod

software.

- Recognize the geometrical evolution of the basin (sedimentation, tectonics and erosion); assess the

thermal history of the source rock and the history of hydrocarbon generation; and investigate

hydrocarbon entrapment.

- Calculate the basal heat flow and source maturation with the reconstructed tectonic history.

- Determination of the oil-generation window is the objective of maturity analysis performed on

possible source rocks. A second application is to decide whether oil will be stable in a given reservoir.

- Investigate the geochemical analysis data and Rock Eval pyrolysis data as a guide for identification

of the kerogen types and source rock maturity.

1.4 PROPOSED INVESTIGATION

In this study, the author shed light on the geodynamic evolution of the Belayim Marin Oil Field, Gulf of

Suez and its implications on its petroleum system using the available geological, geochemical and

geophysical studies for numerical basin modeling.

1.4.1 GEOLOGICAL INVESTIGATIONS

Including reviewing the general geologic setting and its relation to the hydrocarbon potentials using

the subsurface data gathered from deep drilling and lithofacies. Depending on the previously

published literatures about the area.

1.4.2 GEOCHEMICAL INVESTIGATIONS

Including source rock analysis and interpretation of the available geochemical and Rock Eval Pyrolysis

data, as a guide for the identification of the kerogen types and petroleum potential.

1.4.3 GEOPHYSICAL INVESTIGATIONS

1.4.3.1 Tectonic Evolution Studies:

Including reconstruction of the conceptual model (multi-phase tectonic history) to evaluate the

subsurface structural framework, stratigraphic and sedimentologic characteristics of the subsurface

sedimentary sequence in the Belayim Marine Oil Field. In addition to the influence of the tectonic

events through geological time scale on the spatial distribution of the hydrocarbon reservoirs,

accumulation and the entrapment styles has been investigated.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Approach and methods1-4

1.4.3.2 Petrophysical Studies:

Including analysis and interpretation of the available wireline logs to identify the lithological,

mineralogical and petrophysical parameters and saturations of the hydrocarbon reservoirs.

1.4.4 NUMERICAL BASIN MODELING

Basin modeling has been used to study the physical and thermal histories of basin. In order to lead to

an estimation of the timing of hydrocarbon generation and expulsion. It is carried out through the

construction and interpretation of 1D Basin Model. Data derived from drilling logs, core and cutting

samples, company literature, published reports and seismic profiles are used to construct the models.

1.5 APPROACH AND METHODS

1.5.1 CONCEPTUAL FRAMEWORK

1.5.1.1 1D MODELING

The primary function of 1D Basin Modeling is to construct a geological model of stratigraphy versus

time (burial history) and a thermal history in order to evaluate hydrocarbon potential of the Belayim

Marine oil field. Moreover, a wide range of other values are calculated to predict hydrocarbon

generation and expulsion, such as maturity, porosity, permeability, and pressure that can be used in

petroleum systems analysis.

1.5.1.2 RESERVOIR STUDIES

Petrophysical data alongside data from a variety of other sources is integrated to produce a detailed

1D model of the reservoir. Combined with porosity and permeability data derived from wireline

studies, and well tests, the model can incorporate fluid-flow characteristics. Once field development

begins, the model can be enhanced using data on production rates and changes in formation

pressures. The comprehensive full-field model, which will usually develop throughout the field life in

both its level of detail and complexity, is a vital tool in understanding and planning and one of the

most effective means of developing the field.

1.5.2 EXPLORATION GEOCHEMICAL MODELING

1.5.2.1 Petroleum source rock kinetics and yield analysis:

Accurate description of the timing of decomposition of organic matter (kerogen) into oil and gas under

geological conditions is the goal for the highest quality basin modeling effort. When evaluating a play

or prospect using basin modeling, the conversion of kerogen into gas and petroleum is dependent on

the composition of the kerogen. The composition of the kerogen and possibly the surrounding rock

matrix determines the thermal energy required to cause cracking of bonds releasing gas and

petroleum from the source rock.

1.5.2.2 Reservoir Geochemistry:

Reservoir Geochemistry is a tool using detailed, high resolution geochemical procedures and data to

obtain specific information on reservoir characteristics such as mixing of oils of different origin, timing

of oil migration, different phases of reservoir filling, reservoir continuity, water infiltration potential,

water washing/biodegradation of parts of the reservoir potential and extent of asphaltene

precipitation.


Data base1-5

1.5.3 RISK MANAGEMENT SYSTEM

Exploration Risking is directed at key geological features such as the charge (source rock richness,

thickness, maturity), and the trap (prospect geometry, reservoir and seal qualities) of a prospect or

play. These features are all included in petroleum systems models which can be simulated to

determine the thermal, pressure and hydrocarbon generation throughout the entire geologic evolution

of the system. This enables the timing risk to be addressed, as the dynamics of the system and the

evolving processes are modeled.

1.6 DATA BASE

The present study will be mainly based on subsurface geological, geophysical and geochemical data.

The data have been gathered by oil companies, geological surveys and other research institutions,

using different procedures and standards.

These are as follow:

1.6.1 SUBSURFACE DATA

Constitutes borehole lithostratigraphical, thermal and wireline logs, data of already analyzed core

and/or ditch samples. Most of these data were supplied by the authority of the EGPC.

1.6.2 TECHNICAL FACILITIES

Including software’s for 1D Numerical Basin Modeling, wireline logs interpretation, as well as for

graphical presentation of the data.

Mansoura UniversityGeologic Setting and Tectonic Framework2015

General2-1

2. GEOLOGIC SETTING AND TECTONIC FRAMEWORK

2.1 GENERAL

The Gulf of Suez is a rift basin (Figure 2.1) oriented approximately north-northwest–south-southeast;

it is approximately 400 km long and varies in width between 40 km and 80 km. The southern end of

the Gulf meets the Red Sea at the Strait of Guban where the Red Sea bifurcates into the Gulf of Suez

and the Gulf of Aqaba (IHS, 2006). The basin covers an area of about 23000 km2 (Sestini, 1995).

Overall, the basin appears as a simple, narrow, elongated trough dominated by two almost symmetric

shoulders. This extensional tectonic basin is approximately 60 to 80 km wide and contains a

sedimentary prism about 3–5 km thick, with fill ranging in age from Miocene to Holocene (James et

al., 1988).

2.2 GEOLOGICAL OVERVIEW

The Gulf of Suez lies between the basement massif of the Sinai Peninsula to the east and the

basement outcrops of the Red Sea Hills to the west. The basin limits are generally defined by major

down-to-the-basin normal faults of Oligocene-Miocene age. An important part of the sedimentary

sequence within the basin pre-dates formation of the rift is considered to have been deposited within

a continental margin sag basin. These sediments are missing from the margins of the present day Gulf

of Suez Basin due to erosion of the uplifted rift shoulders. A number of sub-basins are informally

recognized lying between major basin-forming extensional faults and areas of on lap to major uplifted

basement blocks that lie within the overall basin limits. These are (approximately from north to south)

the Darag, Zenima, October, Issran, South Belayim, Morgan, Gebel Zeit, Gemsa, Zeit Bay and Mallaha

sub-basins (Figure 2.2). The northernmost dip province consists of the Darag and Lagia sub-basins.

The Darag sub-basin is separated from the southern basins by the Lagia sub-basin, a narrow trough,

which lies between the Hammam Faraun outcrop in Sinai and the foundered Zafarana Plateau, which

is the buried extension of Wadi Araba. South of Wadi Araba in the northern-central Gulf of Suez, a

massive half graben extends the width of the Gulf of Suez. This half graben is broken into subsidiary

blocks, which separate the Issran sub-basin to the west from the October, and Abu Zenima sub-basins

to the east. The eastern boundary of the Abu Zenima sub-basin is marked by a massive clysmic fault,

which has a throw of more than 4000 m. The South Belayim sub-basin and the tilted fault blocks of

the Belayim oil field are lie to the east of the Ras Amer-Ras Gharib High. West of the Morgan field lies

the GS-334 structure, a tilted horst block which is overlain by a salt dome. This structure marks the

northern extent of the B Trend, a line of salt domes and ridges overlying the crests of a line of clysmic

trending tilted fault blocks (Figure 2.3) (IHS, 2006).

The Tor/Nazzazat high separated the South Belayim and Central sub-basins from El Qaa sub-basin,

which is trending northeast to southwest and almost parallel to the main rift basin. El-Qaa sub-basin

onshore in the Western Sinai is a mirror image of the Zeit Bay sub-basin on the western side of the

clysmic Gulf of Suez. The basin is fault bounded in the east by the uplifted shoulders of the Gulf of

Suez rift. The bounding normal fault marking the eastern limit displaces the basement some 3700 to

4,300m at its deepest part.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Geological overview2-2

Figure 2.1: Structural map of Gulf of Suez Rift with location of oil fields and main discoveries, Inset: location of sub basins (geology based on (Colletta et al., 1988; Meshref, 1990).


Geological overview2-3

A thin cover of Nubia and younger strata on the eastern up thrown side of the fault gives way to the

basement massif of southern Sinai. Generally, the Gulf of Suez is subdivided into three tectonic

provinces (from north to south, the Ataqa, Gharib, and Zeit). The three provinces are separated by

two north-northeast and south-southwest major accommodation faults or hinge zones. Each province

has its own structural and stratigraphic history. The accommodation faults include a zone of fault

rotation in the Gulf of Suez, called the Galala-Zenima hinge zone. This fault separates the northern

province of the Gulf of Suez, with a basin floor generally dipping southwest, from the central province,

with a northeast-dipping basin floor. Another similar zone is called the Morgan hinge zone, which

separates the central and southern provinces, the latter with dips toward the southwest (IHS, 2006).

Figure 2.2: Tectonic setting and structural framework map (IHS, 2006) showing major tectonic developments. Successive group of tilt blocks with regional dips. The homogeneous tilt provinces are separated by tectonic boundaries (transform faults), which are the effects of Aqaba faults that acted as strike-slip faults during the early stage of rift structuration (Alsharhan, 2003). Cross-sections A-A', B-B', and C-C' illustrated in (Figure 2.3).


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Geological overview2-4

Belayim Marine field is located in east central part of the Gulf of Suez which resemble the central

fields in their models, tectonics and petroleum system. Numerous exploratory and development wells

were drilled through long history of production and tested this conventional play concept. Generally,

the Belayim field structure is faulted northeast (as well northwest) dipping Pre-Miocene blocks (Figure

2.4) (Youssef, 2000).

Figure 2.3: Regional geological cross-sections (IHS, 2006). (Meshref and Khalil, 1990) calculated 5.1 and 14 km of widening in the northern and central provinces of the Gulf of Suez, respectively, representing an increase of 11 and 17%, respectively, in the initial basin width.


Geological overview2-5

Figure 2.4: Structural cross-section along the central rift segment (Youssef, 2000). The rollover anticline structure trending NW is the structural style of the syn-rift sequences whereas the faulted NE dipping blocks (faulted monocline) are the structural style of the pre-rift sequences. This reflects the role of the syn-rift listric faults and the pre-rift planar faults on the structural model of the Belayim area. During the Early Miocene, the Belayim area was subsided to form the hanging wall of the Ekma-Nezzazat Clysmic fault zone. This was followed by the formation of two sub-basins that are controlled by two sets of major NW synthetic listric fan Clysmic fault zones throwing SW and created a system of down step blocks towards the NE. The Belayim offshore and Belayim onshore oil fields are located on the uplift footwalls of those listric fan fault zones (Hammad, 2009).


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Tectonic evolution of the Gulf of Suez.2-6

2.3 TECTONIC EVOLUTION OF THE GULF OF SUEZ.

The basement complex, with the exception of the basic intrusives, is generally accepted to be

Precambrian in age from (620-580Mabp). The Gulf of Suez rift lies within the Arabian-Nubia shield, a

segment of upper Proterozoic to lower Paleozoic continental crust formed during the widespread Pan-

African tectono-thermal event; this crust forms the basement of much of northeast Africa and western

Saudi Arabia. Pan-African tectono-thermal event was mentioned during (580-570Mabp) (IHS, 2006).

This segment of crust developed through the progressive cratonization and accretion of numerous

intraoceanic island arcs and Andean-type magmatic arcs during the interval of 900-550Mabp (Engel et

al., 1980); and (Gass, 1981). The pre-rift sediments were deposited in continental margin sag basins

at the southern margin of Tethys/Neo-Tethys in at least two cycles of subsidence commencing in the

Cambrian. The first groups of clastic sediments are usually referred to as Nubia-B, Nubia-C and Nubia-

D and are probably all Paleozoic in age from (570-299Mabp). The second major phase of pre-rift

sedimentation commenced in a successor basin in Early Cretaceous times. An essentially northward

thickening wedge of dominantly marine sediments, commencing with the clastics of the Nubia A and

comprising both clastics and carbonates, was deposited more or less continuously from Albian-Aptian

times to Late Eocene (IHS, 2006). The final group, the Nubia-A, is dated as mid-late Jurassic and

latest Early Cretaceous. An unconformity exists between the Nubia-A and the Nubia-B, plus

unconformity exists between the Nubia-B and the Nubia-C. (Patton et al., 1994) have discussed this

evidence and conclude there is evidence for two phases of Hercynian tectonics affecting the

distribution of Nubia sediments first phase was during (443-336Mabp) and second phase of the

Hercynian tectonic event was during (299-260Mabp). Unfortunately, stripping-off of the pre-Miocene

cover at the uplifted shoulders of the rift later in the Miocene has destroyed a lot of the evidence that

might have helped define the controls on these trends. According to (IHS, 2006) the late Permian to

early Triassic (Permo-Triassic) Quisib red shale Member of Nubia A formation was deposited from

(260-245Mabp). The Gulf of Suez regional uplift tectonic event was during time from (245-145Mabp)

(Figure 2.7). The late Jurassic to early Cretaceous uplift resulted in a hiatus in the geological record.

During the Aptian time, sedimentation renewed and alluvial sediments of the Malha Formation

(Aptian-Albian) from (145-99Ma) were deposited over rocks ranging in age from the Precambrian to

Jurassic (Patton et al., 1994).

The regional northward tilting event was for the duration of time from (99-97Mabp) (Figure 2.7).

Where from (97-50Mabp) stress becomes comperational and resulted in fold-anticline. This genetic

unit is characterized by at least two phases of thermally driven subsidence at divergent plate margins

(southern margins of Tethys and Neo-Tethys) ending with the collision between the African and

Eurasian plates (88.5-39Mabp). The dominant deformation during the Syrian Arc folding (early Late

Cretaceous to Early Eocene) was a north-south compression, swinging to north northwest-south

southeast. The principal structures were folds with axes oriented approximately west-southwest-east-

northeast. Geochronologically Pre-rift Continental Margin Sag Unit continued to 35.4Mabp (IHS, 2006).

The present-day Gulf of Suez rift, together with the Red Sea oceanic basin and the Aqaba–Dead Sea

transform systems; comprise the Sinai triple junction, which initiated during the northeasterly


Tectonic evolution of the Gulf of Suez.2-7

movement of Arabia away from Africa. The age of such movements is mainly Neogene (Fichera et al.,

1992).

The basin originated as a failed arm of the Red Sea continental rift system in the latest Oligocene or

earliest Miocene. The Gulf of Suez Rift was then initiated by lithospheric stretching in latest Oligocene

times followed by extensionally driven subsidence, which commenced in earliest Miocene times. After

this initial phase of subsidence, there was a period of isostatic uplift on the rift shoulders and some re-

arrangement of the rift blocks during the Early Miocene, before renewed extensional subsidence,

which ended in the mid-Miocene. Active divergent continental margin (gravitational subsidence)

ranging in age from 29.3 to 14.2Mabp (IHS, 2006). The Syn-rift unit is characterized by the initial

extension due to lithospheric stretching, at the northern extremity of the East African-Red Sea Rift

System, followed by isostatic uplift of the rift shoulders (17Mabp).

The rifting commenced in the pre-Miocene, with the maximum tectonic subsidence, accompanied by

magmatic events, occurring in the late Oligocene–early Miocene (Gandino and Milad, 1990). Rifting

was caused by tensional stresses transmitted through the lithosphere, accompanied by an upwelling

of hot asthenosphere. Both the crustal extension and tectonic subsidence of the axial trough reached

their maximum development between 19 and 15Mabp (Steckler et al., 1988). Subsidence may have

continued until the late Neogene. The interpretation of the phases of tectonic subsidence and their

periods and structural stages during the late Tertiary are shown in (Figure 2.6). The Suez rift was

initiated between 24 and 21Mabp, that is, latest Oligocene to earliest Miocene (Evans, 1990). The

uplifting of rift shoulders was through the time from (21-20Mabp) (Figure 2.7) (IHS, 2006). Between

20 and 17Mabp, the flanks of this basin began to rise because of heating effects (Steckler, 1985).

Several unconformities interrupt the sedimentary record, with major ones in the Paleozoic, Triassic–

Jurassic, Oligocene, and late Miocene (Messinian). These basin wide unconformities formed primarily

in response to regional tectonic adjustments associated with different rift phases of the Gulf of Suez

(Dolson et al., 2001).

A further pulse of extension ended in the Middle Miocene (14.2Mabp). The principal structures formed

during this period were tilted fault-blocks, half-grabens, rollover and other accommodation structures

in hanging wall blocks. A number of other trends are commonly reported, of which the most important

are the Aqaba Trend (020°-200°) and the so called "cross" trend (050°-230°) (IHS, 2006). At this

time from (14.2-14Mabp) Suez phase extension terminates and Aqaba transverse begins (Figure 2.5)

(Bosworth et al., 1998) and (Griffin, 1999). Further extension fault block rotation tectonic event at

14.2Mabp (Figure 2.7) (IHS, 2006).

The period (14.2-5.2Mabp) is characterized by post-rift thermal subsidence, during a period of relative

quiescence on the whole Red Sea rift system. The principal structures are rollover and other

accommodation structures in hanging-wall blocks of re-activated faults, and compaction/subsidence

driven structures. Following Kareem deposition, there appears to have been another period of relative

uplift resulting in local unconformity at the top of the Kareem Formation. Thereafter the dominant

control appears to have been post-rift thermal subsidence, during a period of quiescence on the whole

Red Sea Rift System, until latest Miocene time when the Red Sea Rift System again became active.

This relative uplift may have been responsible for establishing a barrier that isolated the Suez Rift



from its former open link to the Mediterranean. The result of the barrier was the end of normal marine

conditions in the Gulf and the first phase of massive evaporite deposition. Within the first of the

evaporite units, the Belayim Formation, there were, however, two periods of normal marine

deposition, the last of which produced important carbonate reservoir facies, in the form of algal

buildups on the crest of tilted pre-Miocene fault-blocks. Thermal subsidence time is (11.4-10.7Mabp)

(Figure2.7). Post-Belayim deposition consists of two further evaporitic units, the South Gharib

Formation (dominantly halite) and the Zeit Formation (interbedded anhydrite and clastics, with minor

halite). These evaporites are the key sealing facies in the basin (Figure2.7) (IHS, 2006).

By 5Mabp, Aqaba–Dead Sea transform fault replaced the Gulf of Suez as the primary plate boundary

between the African and Arabian plates (Evans, 1990). The period (5.2-0Mabp) is characterized by

subsidence driven dominantly by cooling following active rifting, but with an overprint of locally

renewed extensional faulting in the south of the basin from (5.2-4Mabp). The main structures include

half-grabens, drape structures and modification of existing block traps through the rejuvenation of

bounding faults. A pronounced unconformity is recognized at the top of the Zeit Formation, before

renewed subsidence and accumulation of Plio-Pleistocene clastics commenced. This renewed

subsidence appears to reflect the resumption of extension and sea floor spreading in the south of the

Red Sea Rift System. Although the bulk of the extension in the Red Sea appears to have been

accommodated by movements on the Dead Sea-Gulf of Aqaba transform, there is evidence for

renewed extension in both the north and south of the Gulf of Suez, from about 5Mabp to present. In

the south, a number of faults cut the seabed and earthquake data shows there is active faulting at the

present. In the north, the very large thicknesses of Zeit Formation and Post-Zeit sediments adjacent

to the Darag Fault, following negligible deposition of South Gharib sediments, points to renewed

extension (Figure2.7) (IHS, 2006).


Tectonic evolution of the Gulf of Suez.2-9

Figure 2.5: The relationship between tectonic subsidence rates, types, periods, climate and sea level changes during the Neogene in the Gulf of Suez (compiled and modified from (Bosworth et al., 1998) and (Griffin, 1999). Smaller V symbols represent periods of rapid basin subsidence, for example, the Burdigalian; larger V symbols represent modest rates of basin subsidence, for example, in the Serravallian.



The evolution of Gulf of Suez basin in stages from the Paleozoic to the Holocene and is characterized

by tectonic extensional episodes producing tension block faulting (horst and graben) and block

subsidence (Figure 2.6) (see also (Kingston et al., 1983). The Gulf of Suez has developed in a series

of distinct evolutionary stages.

1) In the first stage, Paleozoic terrestrial clastics were deposited over Precambrian crystalline

basement with minor tectonic movements. The Hercynian epirogeny folded and uplifted the

Paleozoic deposits. The hiatus caused by these movements is evident in the thinning or

absence of sedimentation in many parts of the Gulf of Suez, where Cenomanian strata rest

unconformably on Carboniferous strata.

2) The second stage occurred during the Permian–Triassic to Jurassic and is characterized by

local subsidence and minor transgression, leading to deposition of fluviomarine red shale's

and sandstones.

3) The third stage dates from the Early Cretaceous and involved rifting of the continental crust,

under tension, to produce a system of grabens via block faulting.

4) During the fourth stage, which extended from the middle Cretaceous to the Miocene, normal

faulting continued and the graben system gradually subsided to form a deep basin. Early and

middle Alpine movements occurring in this stage had significant effects on the structure of

Mesozoic and Paleogene strata and gave rise to a series of folds in areas of tectonic

compression. Marine waters invaded the basin and deposited a range of different sedimentary

facies, varying with location in the basin. Marine sandstone and shallow marine limestone,

including reefal limestone, were deposited on structural highs, whereas shale and (Globigerina

Marl) accumulated in the low areas. The last strata of this stage were thick salt deposits.

5) During the fifth and final stage of rift evolution, the interior fracture system widened during

the Pliocene–Holocene, the basin fill was uplifted at the rift margins because of continued

block faulting, and non-marine wedge-top strata (mainly sandstone) penetrated the basin.

Within-basin faulting is generally not evident in this stage, and sedimentary accumulation in

the basin was accommodated by sag (Alsharhan, 2003).


Structural setting of the Gulf of Suez2-11

Figure 2.6: Development stages of the Gulf of Suez, as an example of a typical interior fracture rift basin after (Alsharhan, 2003).

2.4 STRUCTURAL SETTING OF THE GULF OF SUEZ

There are essentially two distinct structural styles in the Gulf of Suez Basin, although only the second

style is important from a trap point of view:

1) Syrian arc folding (Early Late Cretaceous to Early Eocene); folding of Mesozoic and earliest Tertiary

sequences in response to closure of Neo-Tethys. Two phases of activity are inferred, first in the

Turonian to Early Senonian, second in the Late Paleocene and Early Eocene. Folding is most obvious

in the north of the basin, but subtle expressions of it are apparent in the subsurface further south

(Patton et al., 1994). Dominant Deformation: North-south compression, swinging to north-northwest-


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Lithostratigraphy2-12

south southeast. Dominant Transport Expression: uplift and folding, possibly involving inversion of

preexisting fault controlled basins. Principal structures: folds with axes oriented approximately west-

southwest-east northeast (IHS, 2006).

2) Initial rifting (Late Oligocene to Middle Miocene); extensional block faulting of the pre-Miocene

sedimentary wedge and Precambrian basement in response to rotation of the Arabian Plate away from

the Nubia Craton. Rotation of rifted blocks occurred together with uplift of fault blocks forming the rift

shoulders. Formation of accommodation zones/transfer zones between discrete rift segments having

opposite polarity. Dominant Deformation: extension oriented approximately northeast-southwest.

Dominant Transport Expression: dip-slip on faults of varying dip angle. Minor oblique-slip, particularly

at the accommodation zones separating rift segments having reverse dip polarity. Rotation of faulted

blocks on listric fault geometries. Uplift of rift shoulders, particularly in the central and southern Gulf.

Principal structures: tilted fault blocks with the major faults trending 145°-325°, the so called Clysmic

Trend. Half-grabens rollover and other accommodation structures in hanging wall blocks. A number of

other trends are commonly reported of which the most important are the Aqaba Trend (020°-200°)

and the so called "Cross" Trend (050°-230°) (IHS, 2006).

3) Thermal subsidence (Mid to Late Miocene); A reduction or total cessation of extension, particularly

apparent in the northern Gulf. Much reduced rate of subsidence. Some faults remain active in deep

basinal areas, but this activity may have reflected elements of differential compaction and/or relatively

shallow growth faulting rather than crustal extension. Dominant Deformation: thermal contraction.

Dominant Transport Expression: subsidence. Dip slip on faults of varying dip angle. Reactivation of

some extensional faults resulting in wedges of sediment in the hanging wall thickening towards the

footwall. Some modification and further rotation of pre-existing tilted fault blocks. Principal structures:

rollover and other accommodation structures in hanging-wall blocks of re- activated faults.

Compaction/subsidence driven drapes structures (IHS, 2006).

4) Renewed extension (Plio-Pleistocene); renewed activity on the whole Red Sea/Gulf of Aqaba/Dead

Sea system appears to have resulted in some renewed extension in some parts of the Gulf of Suez.

Elsewhere, thermally driven subsidence continued. Dominant Deformation: extension oriented

approximately northeast-southwest. Subsidence in many of the component half-grabens. Continued

uplift on shoulders. Sedimentary loading leading to movement of salt to form salt swells, pillows and

walls. Dominant Transport Expression: Dip slip on faults of varying dip angle. Uplift of rift shoulders,

particularly in central and southern Gulf. Some further block rotation. Folding and flexuring of

overburden due to salt movement. Principal structures: half-grabens. Modification of existing fault

block traps through rejuvenation of bounding faults, and the impact of further rotation. Drape

structures (IHS, 2006).

2.5 LITHOSTRATIGRAPHY

The lithostratigraphic units of the Belayim Marine Oil Field range from Precambrian to Holocene in age

and have been divided into three major sequences relative to the Miocene rifting event: Pre-rift

lithostratigraphic units (pre-Miocene units), Syn-rift lithostratigraphic units (Miocene units), and Post-

rift lithostratigraphic units (post-Miocene units) (Alsharhan, 2003).


Lithostratigraphy2-13

2.5.1 Pre-rift succession

The pre-rift stratigraphic sequence is composed of strata ranging from Precambrian to late Eocene

and contains sand, shale, and carbonate facies that were laid down under terrestrial and marine-

platform environments. This period of sedimentation was affected by major unconformities

representing non deposition or erosion at different geologic times (Alsharhan, 2003).

The pre-rift stratigraphic sequence is composed of strata ranging in age from Precambrian to Late

Eocene (620Mabp-35.4Mabp) (IHS, 2006). The Pre-Miocene section contains the basement complex

comprises a great variety of crystalline and metamorphic rock types, Nubia Group (Nubia-D, Nubia-C,

Nubia-B, and Nubia-A), Raha Formation, Abu Qada Formation, Wata Formation, Matulla Formation,

Duwi or Brown Limestone Formation, Sudr Formation, Esna Shale Formation, and Thebes Formation

(Figure 2.7).

2.5.1.1 The Precambrian Basement

Different types of granites, crystalline schists, gneisses and porphyrites are recognized (Schlumberger,

1984). Basement samples are composed of quartz, potassium feldspars, with patches of light green

minerals (hornblend and chlorite) and dark grey mica (biotite) (Zahran, 1986) and (Zahran and

Meshref, 1988). In the Belayim Marin oil field, the Basement is mainly granite composed of white,

milky, colorless, and angular with sharp edges quartz, and red brown, pink, massive and moderately

hard feldspars, moreover black, dark brown and hard maffic minerals. It is recorded in BM-57 well at

depth 3600m TVDSS.

2.5.1.2 Paleozoic

2.5.1.2.1 The Pre-Cenomanian clastic

(Nubia Group) The Pre-Cenomanian clastic overlies the Basement rocks and mainly composed of

sandstone and shale intercalations. The maximum thickness drilled is about 667m in well BM-57. The

sandstone is differentiated into four Members, which are named Nubia A, B, C and D. The Nubia-D

facies in the Gulf of Suez region is mainly composed of gray to greenish gray shale and sandstones. It

rests unconformably over the Precambrian basement. It is derived from shallow marine depositional

setting environment (Alsharhan, 2003). The authors (Issawi and Jux, 1982; Weissbrod, 1970) have

reported early Paleozoic age for the outcrops of Nubia-D in Um Bogma area and evidenced by

burrows, tracks, and other trace fossils. (Hassan, 1967) has introduced Araba Formation to the

sediments equivalent to Nubia-D series. The Nubia-D Member is not represented in the Belayim

Marine oil field.

The facies of Nubia-C was called Naqus Formation by (Hassan, 1967). The Nubia-C Member is mainly

colorless and fine to coarse, rounded and moderately sorted grains of sandstones with shale inter

beddings (Hammad, 2009). This sandstone is deposited in continental depositional setting

environment (Alsharhan, 2003). In the Belayim Marine Oil Field, the maximum drilled thickness of the

Nubia C Member is 338m, which recorded in BM-57 well. While the minimum drilled thickness of the

Nubia C Member is 53m, is recorded in BM-23 well. Moreover the Nubia C Member not penetrated in

BM-70 well.

The Nubia-B Member composed of dark-gray, reddish brown, black and non calcareous shale with

some fine grained sandstone inter beddings. The Nubia B Member is indicating a shallow-marine



environment with coastal deposits (Hammad, 2009). (Hassan, 1967) assigned Abu Durba Formation to

the Nubia-B shales. Regionally (to the north) Nubia-B (Abu Durba Formation) rests on Nubia-C unit

with probable disconformities (Steen, 1982). In the Belayim Marine Oil Field, the maximum drilled

thickness of the Nubia B Member is 165m, which recorded in 113-M-34 well. Meanwhile the minimum

drilled thickness of the Nubia B Member is 64m, which recorded in BM-65 well. Furthermore the Nubia

B Member not penetrated in BM-70 well. In Belayim Marine Oil Field, TOC analyses showed that the

Nubia-A and B formations sediments are immature fair to good source rocks with very high hydrogen

index indicative of kerogen type II (Abu Al-Atta et al., 2014). The analyzed interval contains both

marine and terrestrial organic matter with variable but nearly equal proportions. All maturity

parameters except Pyrolysis analysis Tmax values, suggest that the analyzed carboniferous rock in

BM-57 well are past the oil floor (defined by 1.35% Ro), and has probably reached maturities grater

than 1.7% Ro (Abu Al-Atta et al., 2014).

2.5.1.3 Mesozoic

2.5.1.3.1 Cretaceous

Nubia-A

The Nubia-A Member is mainly composed of colorless, and medium to cross-grained sandstones of

braided-river environment and kaolinitic up to 30% with occasional shale and rare limestone layers

(Hammad, 2009). A relatively thin wedge of barren continental to shallow marine sandstone separates

marine Cenomanian rocks from the underlying Paleozoic formations. Its stratigraphic position is

debated; some authors place it in the Early Cretaceous, while others consider it to be of Late

Cretaceous (Cenomanian) age (Schlumberger, 1984). The Nubia A Member is considered as one of

the best reservoir in Belayim Marine Field especially to the north western part of the field (Hammad,

2009). In the Belayim Marine Oil Field, the maximum drilled thickness of the Nubia A Member is

225m, which recorded in BM-23 well. Meanwhile the minimum drilled thickness is 64m, which

recorded in BM-70 well.

Raha Formation

The marine transgression at the beginning of the Cenomanian marked the onset of Middle Calcareous

division in the Gulf of Suez area (Ghorab, 1961) and (Said, 1962). The Cenomanian sequences were

given the name Raha Formation by (Ghorab, 1961). Cenomanian is unconformably overlying the so-

called Nubia A in the sense of oil geologists; it is composed mainly of sandstone, shale and interbeds

of limestone. Cenomanian sands are more shaly compared to the pre-Cenomanian clastic unit. Thick

massive marl and limestone bed highly laden with oysters emphasize the shallow-water depositional

environment (Schutz, 1994). This sedimentlogical inverse pattern between the maximum recording

thickness and the location of the basin depocenter indicates a possible post depositional tilting of the

area from north west to north east which reveals to uplift and erosion at the beginning of Cenomanian

(Alsharhan and Salah, 1998).

In the Belayim Marine Oil Field, the maximum drilled thickness of the Cenomanian Raha Formation is

107m, which recorded in BM-23 well; meanwhile the minimum drilled thickness is 59m, which

recorded in BM-70 well. Furthermore Cenomanian Raha Formation not existed in BM-36 and BM-65

wells.



Abu Qada Formation

Abu Qada Formation consists of brown to dark grey shale grading to argillaceous limestone with

glauconite with average thickness 15m. It is indicating an open marine environment (IHS, 2006). Abu

Qada sediments deposited in shallow marine depositional setting environment (Alsharhan, 2003). This

formation is not represented in the Belayim Marine Oil Field.

Wata Formation

The Wata Formation consists of hard siliceous partly dolomitic limestones with intercalated shales and

sandstones. In the type section, the Wata Formation can be divided into three parts: lower

carbonate, a middle clastic and an upper carbonate part (IHS, 2006). The Wata Formation sediments

reflect shallow marine environments (Schutz, 1994). It is composed mainly of limestone with some

interbeds of sandstone and shale. The clastic unit sandstone of Turonian Wata Formation in BM-24

well considered as a good reservoir. The maximum drilled thickness is 100m, which recorded in BM-23

well. Meanwhile the minimum drilled thickness is 15m, which recorded in BM-36 well. Furthermore, it

completely missed in BM-57 and BM-65 wells. Application of the petroleum kinetics equations for type

II kerogen of Wata Formation indicates that, oil generation started close to the Early Miocene

(Burdigalian ~18.25 Mabp), and has been in the wet gas window (gas onset) since ~17.55 Mabp

(Early Miocene), during the deposition of the Lower Miocene Rudeis Formation and shortly after the

Oligocene rifting phase and its associated thermal subsidence, at both RB-C1 and RB-B5 wells (Atia et

al., 2015). It is considered as an active currently expelling effective source rock that has already

generated and expelled hydrocarbons. Hydrocarbon generation is mainly related to the exchange of

basin evolution and burial (Atia et al., 2015).

Matulla Formation

The sediments of the Early Senonian time are assigned as Matulla Formation (Ghorab, 1961). It

overlies unconformably the Turonian Wata Formation. The base of the section is made up of cross-

bedded sandstone with thin argillaceous limestone and shale interbeds of low stand facies due to a

drastic drop in global eustatic sea level (Darwish, 1994). The Matulla Formation consists of

intercalated grey shale, sandstone and pyretic glauconitic, argillaceous limestones. Sandstones are

developed in the central and southern parts, while carbonates predominate in the northern part of the

Gulf (IHS, 2006). It unconformably overlies the Wata Formation. Lower Senonian is considered the

best and the widest reservoir in the Pre-Miocene sequence, after the Pre-Cenomanian sandstone

reservoir and is mainly composed of sandstone and shale. There are two main sub units composing

this formation, the top unit is made of thinly interbedded sandstone and shale, while the bottom unit

is clean sandstone with few interbeds of shale and limestone. This sandstone makes the best reservoir

in the western side of the Belayim Marine Field while the top part includes sandstone which also is a

good reservoir in the eastern side of the Belayim Marine Field (Hammad, 2009). The sandstone is

white, medium to fine grained, sub angular to angular, moderately sorted with calcareous cement,

glauconitic and occasionally pyritic. The shale is gray, dark gray, light gray, soft, moderately hard,

massive sub flaky, and highly calcareous. The limestone is white, milky white, occasionally earthy

white cryptocrystalline, hard to moderately hard, argillaceous in parts. The Matulla Formation was

deposited under shallow marine conditions (Hammad, 2009). In the study area, the Matulla sandstone



unit is considered as good reservoir in BM-57, BM-36, and BM-23 wells. The maximum drilled

thickness is 128m, which recorded in 113-M-27 well; meanwhile the minimum drilled thickness is 78m,

which recorded in BM-36 well. Furthermore, Matulla Formation is completely missed at BM-65 well.

Sudr Formation

The Sudr formation composed mainly of chalky limestone with thin interbeds of argillaceous limestone

deposited in deep marine depositional environment unconformably overlain by Esna shale (Alsharhan,

2003). This formation is differentiated into two main units; the top one is Sudr chalky limestone,

which is white, off white, moderately hard to hard, cryptocrystalline, while the bottom part is hard,

brown to dark brown cherty limestone. The Sudr Formation was deposited under open marine

conditions, with less organic–rich sediments (Hammad, 2009). In Belayim Marine Oil Field, the

maximum drilled thickness is 66m, which recorded in BM-57 well. Meanwhile the minimum drilled

thickness is 27m, which recorded in BM-36 well. Furthermore Sudr Formation does not exist in 113-M-

27, BM-24, BM-65, and BM-70 wells. The Sudr Formation is reported as good organic-rich interval that

is characterized by a high TOC value of ~1.48wt% and by immature Type II kerogen (SH-D3 and SH-

E8 wells) and an early-mature type II kerogen intervals (SHD4 well) but mature at single well, SH-A1

well, assigned to a limestone organic- rich interval that deposited in open marine environment

(Othman et al., 2013). It is characterized by type II kerogen with an excellent generation potential for

liquid hydrocarbons (oil-prone type II-S kerogen or type II) (Othman et al., 2013).

Duwi Formation

The Duwi Brown Limestone (cherty limestone) is generally regarded as the key source rock in the Gulf

of Suez Basin (IHS, 2006). In the Belayim Marine Oil Field, the Duwi limestone is described as brown

to dark brown, moderately hard to hard, massive, and cryptocrystalline, with trace of calcite. The

maximum drilled thickness is 46m, which recorded in 113-M-34 well. Meanwhile the minimum drilled

thickness is 9m, which recorded in BM-57 well. Furthermore, Duwi Formation does not existed in BM-

24, BM-36, BM-65, and BM-70 wells.

2.5.1.4 Cenozoic

2.5.1.4.1 Paleocene

Esna Formation

The marine transgression continued into the Lower Tertiary with the deposition of Paleocene chalks

and marls over Lower and Middle Eocene carbonates and marls. Pyritic and cherty limestones, micrite

and reefal build-ups are frequent. The thickness of the Lower Tertiary formation varies considerably,

depending on which part of a structure is being, evaluated (Schlumberger, 1984). The Esna Formation

was described by (Beadnell, 1905) and reviewed by (Said, 1962) to describe the thick Paleocene shale

sequence conformably overlying the Late Cretaceous chalky limestone exposed at Gebel Oweinat,

Upper Egypt and described by (Soliman, 1988) at Gebel Nazzazat as of yellow gypsiferous marl,

argillaceous limestone and grayish green shale in the lower part. In the study area, the Paleocene is

represented by a relative thin section of shale with limestone interbeds, light grey, grey, dark grey,

occasionally soft, moderately firm, sub blocky to blocky, calcareous to high calcareous, fossilliferous.

The maximum drilled thickness of the Esna Formation is 49m, which recorded in BM-36 well.



Meanwhile the minimum drilled thickness is 4m, which recorded in 113-M-27 well. Furthermore, Esna

Formation is completely missed in BM-24, and BM-70 wells.

2.5.1.4.2 Eocene

Thebes Formation

The Eocene sequence conformably follows the Paleocene deposits. These deposits were given the

formation name of the Thebes Formation (Said, 1960). The cherty and argillaceous limestones of

Lower and Middle Eocene occurs throughout the Gulf of Suez region. The wide lateral extent and

homogeneity of the predominant chert-rich limestone is evident for this extensive open marine

environment prevailing through Egypt (Said, 1990). Eocene rocks are the first pre-Miocene formations

unconformably underlying the Miocene units (Hammad, 2009). In the Belayim Marine Oil Field, the

Eocene Thebes Formation is mainly composed of limestone interlaminated with shale, differentiated

into two main units; the top limestone considered as mature source rock in most of study area. It is

light brown, creamy, white to off white moderately hard, blocky cryptocrystalline, argillaceous and

cherty. The penetrated thicknesses range from 44 m to 237 m at 113-M-34 well and 113-M-27 well,

respectively. Furthermore, Thebes Formation completely missed in BM-24 well.

Samalut Formation

Samalut Formation is highly fossilliferous creamy limestone with average thickness 90m, it was

deposited under shallow marine conditions (IHS, 2006), it is completely missed in the study area

Belayim Marine Oil Field.

2.5.2 Syn-rift succession

The syn-rift stratigraphic sequence in the Gulf of Suez is composed of Miocene strata ranging from

(29.3Mabp–13Mabp) in age. It represented by Abu Zenima Formation, Nukhul Formation, Rudeis

Formation and Kareem Formation which is divided into two members (Markha Member and Shagar

Member). However, in Belayim Marine Field the stratigraphic succession with the absence of Abu

Zenima Formation (Oligocene), Nukhul Formation (basal Miocene), (these formations called Oligo-

Miocene Red beds), (Figure 2.7) (IHS, 2006).

2.5.2.1 Oligocene

Abu Zenima Formation

Abu Zenima Formation is porcellaneous limestone coarsing upward siltstone beds and basal

conglomerates with average thickness of 100m. The Abu Zenima Formation was deposited in

terrestrial (fluvial) depositional environment (IHS, 2006). Abu Zenima Formation is not represented in

the study area.

2.5.2.2 Miocene

Nukhul Formation

The term Nukhul was introduced by (EGPC Committee, 1964) for the marine sediments in Sinai and

the Gulf of Suez regions to characterize the Early Miocene calcareous sediments, shale, and marls

unconformably overlying the Oligocene red beds in Wadi Nukhul, west central Sinai. It contains

carbonates and high energy reefal build-ups on Pre-Miocene topographic highs, and sands and shales

in the lows between fault blocks and on tilted surfaces on fault blocks (Ouda and Masoud, 1993;

Schlumberger, 1984). The Early Miocene Nukhul Formation that deposited as a variety of facies



reflects the heterogeneity of the environmental setting and is the product of different tectonic settings

of separate fault blocks (Meshref and Khalil, 1990). In general, they represent fluvio-estuarine to

shallow marine clastics at the base and change in areas to marls, Limestone of shallow to partly open

marine environment at the upper units (Darwish et al., 1998). However, in the South Gebel el Zeit

area the Nukhul Formation interpreted as a relatively deep-marine sediment gravity flow deposit,

contrary to previous interpretations of the unit as entirely shallow marine (Winn et al., 2001).

It overlies the continental “Tayeba Red Beds” and underlies the marine Miocene beds of the Rudeis

Formation. The Nukhul Formation in its type locality is mainly composed of shallow marine reefal

limestone, calcareous sandstones with shell fragments and occasionally glauconitic shale and marls

with fine pyritic sandstone stringers, sand, sometimes anhydrite and conglomerates (mainly

limestones and chert nodules derived from the higher surrounding Eocene rocks) (Hammad, 2009). In

the Belayim Marine Oil Field, the Nukhul Formation is not represented.

Rudeis Formation

The Rudeis Formation overlies the Nukhul Formation and is composed essentially of highly

fossilliferous shales and marls referred to as the Globigerina Marls, (Globigerina Marl of (Moon and

Sadek, 1923)) and the sandstones. The thickness of the Globigerina Marls exceeds 2200 m in the

northern part of the gulf thinning to less than 200 m at the Red Sea-Gulf of Suez junction

(Schlumberger, 1984). This formation is oil bearing in Belayim Land, Belayim Marine, Morgan and

other fields. The Rudeis Formation grades upwards into the Kareem Formation across a laterally

extended anhydritic level (Schlumberger, 1984). (Ouda and Masoud, 1993) stated that “the

Burdigalian sediments are distinguished into two distinct facies: a) Deep water clastic facies deposited

along the entire stretch of the Gulf of Suez basins, in which whose axes were more or less coincident

with the axis of the present Gulf, and b) Shallow water carbonate facies with tendencies for reefal

development toward both sides of the Gulf”. The Rudeis Formation shows a sharp change to deep

marine environment as is indicated by abundant pelagic foraminifera and outer shelf and bathyal

benthonic fauna (Schutz, 1994).

The Rudeis Formation subdivided into Lower and Upper Rudeis using the biostratigraphic evidences

only according to (EGPC Committee, 1964, , 1974; Hosny et al., 1986).

The Upper Rudeis Formation is characterized by different parts of lithologies; the top part of the

Upper Rudeis Formation is represented by shale whereas the middle and lower parts are sandstones.

The shale is gray to light gray, moderately firm to soft, sub-blocky to sub flaky, silty and pyritic in

parts, with variable calcareous content grading in part to argillaceous limestone. The sandstone is in

the form of loose, medium to fine grained, surrounded, and moderately sorted, with calcareous

cement (Hammad, 2009). In Belayim Marine Oil Field, the maximum drilled thickness of the Upper

Rudeis Formation is 471m, which recorded in BM-70 well. Meanwhile the minimum drilled thickness is

89m, which recorded in BM-65 well. On the other hand the Lower Rudeis is mainly composed of

conglomerates, is not represented in the study area except in BM-65 well with total thickness of

130m.



Kareem Formation

The Kareem Formation is predominantly shaly, but with frequent intervals of sandstones. The

interbedded sands provide excellent reservoirs with porosities ranging from 11 to 24%. The thickness

of the Gharandal Group is about 1400 m with the Nukhul Formation being 350 m thick and the Rudeis

and Kareem formations exceeding 1000 m in average. Paleo-depositional environments are difficult to

interpret because of lack of faunal content, but the lack of fossils may record shallow, saline water,

fresh water (Wescott et al., 2000), or a deeper water in a restricted basin. The Kareem Formation is

divided into two Members, Shagar Clastic Member at the top and Markha Carbonate Member at the

bottom. The Shagar Clastic Member consists mainly of shale with sandstone streaks. The shale is light

gray, dark gray, greenish gray, soft to moderately firm, sub-blocky to blocky, highly calcareous

grading to marl, sandy and silty in parts. The sandstone is mainly colorless, white, and occasionally

pink, fine to medium grains, occasionally coarse grained, sub angular to sub-rounded, moderately

sorted, with calcareous cement, cherty in parts and pyritic in other parts (Hammad, 2009). In the

Shagar Member, full–marine conditions were established and sedimentation of Globigerina rich marls

continued as in the Rudeis Formation which represents high subsidence and sedimentation rates

(Schutz, 1994). The maximum penetrated thickness of the Shagar Member is 230m, which recorded in

BM-36 well. Meanwhile the minimum drilled thickness is 144m, recorded in BM-65 well. The Markha

Member is consists of one anhydrite body which was white to milky white and occasionally colorless,

moderately hard to hard, occasionally soft, fine crystalline to cryptocrystalline. The Kareem Formation

was deposited during the end phase cycle of sedimentation in which the Gharandal Group was

deposited. Three facies are differentiated: a fully marine facies that coincides with the Shagar

Member; an anhydritic, restricted–environment facies (the Markha Member); and a sandy facies

(Schutz, 1994). Paleo geographic maps hint at these being deposited in shallow water lagoonal

environments on the flanks of the basin (Tawfik et al., 1992), but their presence in the central, deeper

parts of the basin has been interpreted along with other lines of evidence to argue for a deeper water

environment (May et al., 1991). Both may have been operative.

2.5.3 Post-rift succession

The post-rift stratigraphic sequence in the Gulf of Suez is represented by lithology of strata from

(14.2Mabp-0Mabp) in age (IHS, 2006), and divided into two sequences:

2.5.3.1 Early Post-rift Sag unit: (14.2Mabp-5.2Mabp) in age

This sequence is represented by Belayim Formation, South Gharib Formation, and Zeit Formation

(Figure 2.7).

Belayim Formation

The Belayim Formation consists in general of anhydrite and salt at the bottom, and is topped by a

sequence of sandstone and shales. The sandstones have excellent reservoir characteristics and

contain oil in the Morgan, Belayim Land, and Belayim Marine and Shukheir fields. On structural highs

where Lower Miocene deposits are absent, reefal build-ups are developed and contain the oil of the

Ras Gharib, Bakr and Gemsa fields (Schlumberger, 1984).

Belayim Formation was divided into four Members from base to top; (Baba, Sidri, Feiran and

Hammam Faraun Members) (EGPC Committee, 1974). Lateral facies change was observed near the



base of the formation from sand to shale, anhydrite to salt and anhydrite to clastics (Nabih, 1992).

The Belayim Formation varies in thickness from 132m in BM-36 well to the minimum 503m in BM-65

well.

A - BABA MEMBER

The name of Baba Member suggested after Wadi Baba well (Said and El Hiny, 1967). The Baba

Member Anhydrite with thin interbeds of shale and salt, indication of shallow marine lagoon

depositional environment (Alsharhan, 2003). The Baba Member consists mainly of salt with anhydrite

at base. The anhydrite is milky white, white, occasionally white, moderately hard, cryptocrystalline,

occasionally slightly argillaceous.

B - SIDRI CLASTIC MEMBER

Sidri Member was introduced by (Moon and Sadek, 1923) after Sidri field, where the Member is

present, it is the bottom clastics unit of Belayim Formation that overlies the Baba Member and

underlies the Feiran Member. The Sidri Member is characterized shale with thin interbeds of

sandstone, indication of inner neritic to littoral marine depositional environment (Alsharhan, 2003).

It consists mainly of shale with streaks of sandstone in some area. The shale is gray, greenish gray,

dark gray, occasionally light gray, soft to moderately firm, sub-blocky to sub flaky, silty in parts, non-

to slightly calcareous. The sandstone was colorless, yellow, gray, occasionally pink, fine to medium

grained, occasionally coarse grained, sub angular to sub rounded, moderately to ill sorted with

siliceous cement, and cherty in parts.

C - FEIRAN MEMBER

Feiran Member is the upper evaporite unit of the Belayim Formation. The term Feiran was first used

by (Moon and Sadek, 1923) after its type section Feiran well No. 2, it conformably overlies the Sidri

Member and underlies the Hammam Faraun Member. It consists of mainly of anhydrite with thin

interbeds of shale and sandstone, indication of shallow marine lagoon depositional environment

(Alsharhan, 2003).

A characteristic feature of the Feiran Member is its lateral facies variation. In the study area the

thickness generally increases northeast ward. The anhydrite is white, milky white, colorless,

moderately hard to hard occasionally soft cryptocrystalline, and fine crystalline. The shale is gray,

greenish gray, dark gray, occasionally light gray, soft to moderately firm, sub-blocky to sub flaky, silty

in parts, non-to slightly calcareous. The sandstone is in loose form, colorless, medium to fine grained,

sub-rounded to sub-angular and moderately sorted.

D - HAMMAM FARAUN MEMBER

Hammam Faraun Member was first used by the (EGPC Committee, 1964) after the Wadi Gharandal

area, north Gebel Hammam Faraun to describe the upper clastic and carbonate Member of Belayim

Formation in the Miocene of the Gulf of Suez region. It is conformably underlain by Feiran Member

and overlain by South Gharib Formation. The Hammam Faraun Member is characterized by a massive

body of shale, sandstone and carbonate with occasionally thin beds of anhydrite, indicating an open

marine depositional environment in the central basin and tidal flat to intertidal in the marginal areas

(Alsharhan, 2003).



Figure 2.7: Litho-stratigraphic column of Gulf of Suez, (IHS, 2006).



It underlies the South Gharib Formation and overlies the Feiran Member of the Belayim Formation.

The Hammam Faraun Member is represented by massive body of shale, sand and carbonates which

are known as the Nullipore or Lypiaster bed, which historically has been accepted by most geologists

as being coeval with the Hammam Faraun Member (Fawzy and Aal, 1984). The shale is gray to green

gray, brownish gray, occasionally light gray, soft to firm, sub-blocky to sub-flaky, fissile, silty, sandy in

parts, and variably calcareous.

South Gharib Formation

South Gharib Formation consists of a few very thick salt beds with anhydrite, shale and sandstone

stringers in between. The thickness exceeds 1000m especially in the central part of the Gulf. Its

depositional cycles vary from place to place in number and in thickness of salt and anhydrite layers

(Schlumberger, 1984). The South Gharib Formation coincident with the major, rapid global sea level

drop (Haq et al., 1987).

The South Gharib Formation was deposited in water of high salinity, and consequently is deprived of

fauna (Said and El Hiny, 1967). The South Gharib Formation consists of a thick evaporite (salt and

anhydrite) with thin intercalations of shale and sand, indicating restricted subsiding saline basin

depositional setting environment (Alsharhan, 2003).

The South Gharib Formation covers most of depositional cycle. In the study area it consists of a

typical massive cyclic evaporate sequence, consisting of thick salt beds and anhydrite, marking the

beginning of each sandstone streaks present within the anhydrite bed at the middle part of the

formation as well as shale streaks at the lower part. The anhydrite was generally white to milky white,

occasionally smoky white, moderately hard to soft, occasionally hard, cryptocrystalline to fine

crystalline. The thick salt section, acts as a sealing unit that prevents the migration of oil from the

underlying Belayim and Kareem formations upward, toward the Zeit Formation. The shale is gray,

light gray to dark gray, occasionally brownish gray, hard to firm sub- blocky to sub flaky, sticky, and

non to slightly calcareous towards the base of the interval (Hammad, 2009).

The sandstone is in the form of loose quartz grains, colorless to white, fine to very fine grained,

rounded to sub-rounded, and sorted to moderately sorted with siliceous cement and no oil stain is

recorded. The sands are usually water wet, often causing drilling problems due to high pressures in

some oil fields in the Gulf of Suez as in Amal and Morgan fields (Fawzy and Aal, 1984). The maximum

drilled thickness is 561m recorded in 113-M-34 well. Meanwhile the minimum drilled thickness is 463m

that recorded BM-70 well.

Zeit Formation

The Zeit Formation forming the upper most part of the Ras Malaab Group and is represented by

numerous alternating thin beds of shale, gypsiferous shale, anhydrites and sandstones. The thickness

varies since it has been exposed to strong erosion that led to the major unconformity between the

Miocene and the Plio-Pleistocene strata (Schlumberger, 1984). These evaporites are the key sealing

facies in the basin (IHS, 2006). The Zeit Formation underlies the Pliocene “continental sands” and

overlies the evaporites of the South Gharib Formation. It consists of anhydrite and shale intercalations

with sand and sandstone streaks. The anhydrite is white, milky white, hard, occasionally soft and

cryptocrystalline to fine crystalline. The shale is gray, light gray, green gray and brownish gray,



moderately hard, firm, soft, washable, blocky to sub-blocky, occasionally sub-flaky toward the bottom,

non calcareous, and is slightly calcareous at the lower part. The sandstone is in the form of loose

quartz grains which are translucent, colorless, white tan, fine to very fine grained, occasionally coarse

grained, sorted to moderately sort with siliceous cement and with no oil stain. Lithologic

characteristics of the Zeit Formation indicate that its environment of deposition is shallow marine to

predominant lagoonal facies (Hammad, 2009). Locally in the marginal areas, it contains some

intercalations of sandstone and limestone which indicating deep semi restricted to lagoonal

depositional setting environment. The Zeit Formation is encountered all over the area with thickness

ranging from 637m and 832m at BM-24 well and BM-70 well, respectively.

2.5.3.2 Late Post-rift Sag unit: (5.2Mabp-0Mabp) in age

This period is characterized by subsidence driven dominantly by cooling following active rifting, but

with an overprint of renewed extensional faulting in the south of the basin. The main structures

include half-grabens, drape structures and modification of existing block traps through the

rejuvenation of bounding faults and represented by Post Zeit Formation (IHS, 2006).

2.5.3.2.1 Pliocene-Pleistocene

Post Zeit Formation

Four new formations were established for the Post Miocene section. These sediments are

characterized by different types of lithologies: sandstone at the margin of the Gulf (El-Tor Formation),

carbonate in the south and middle area (Ashrafi Formation), and intercalation of evaporites and

clastics are present in the northern part of the Gulf (Zafarana and Wardan formations) (Abd El Shafy,

1992).

A pronounced unconformity is recognized at the top of the Zeit Formation, before renewed subsidence

and accumulation of Plio-Pleistocene clastics commenced. This renewed subsidence appears to reflect

the resumption of extension and sea floor spreading in the south of the Red Sea Rift System.

Although the bulk of the extension in the Red Sea appears to have been accommodated by

movements on the Dead Sea-Gulf of Aqaba transform, there is evidence for renewed extension in

both the north and south of the Gulf of Suez, from about 5Mabp to present. In the south, a number of

faults cut the seabed and earthquake data shows that there is active faulting at the present.

A blanket of coarse and fine clastics and, in some areas, oolitic limestones cover the unconformity

surface of the Miocene formations. This blanket is widespread and its thickness varies from a few

meters to about 500m. During the relatively short period of Lower and Middle Miocene had

experienced a strong and fast subsidence accompanied by an infill of sediments, which kept space

with subsidence. The environment must have been super-saline at least during Middle Miocene with

hot brines that favored the deposition of thick salt (Schlumberger, 1984).

The lithologic characteristics of the Post Miocene units indicate that deposition took place under

shallow marine to lagoonal environments. These deposits extend from the sea floor to the anhydrite

and shales intercalations marking the top of the Zeit Formation. The thicknesses and lithological

characteristics of Post Miocene sediments show variations from one locality to another (Hammad,

2009). The Post Miocene units in Belayim Marine Oil Field consist mainly of sand, gravels and minor

clay, sandstone and shale interbedded with few anhydrite streaks near the base of the section. The


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Petroleum system2-24

sandstone is yellow to reddish brown, occasionally gray, loose, soft, friable, and fine to moderately

coarse-grained, with quartz and flint gravels, angular to sub angular, rounded in parts, and well

sorted, becoming rounded to surrounded. The sandstones on the bottom of the Post Zeit Formation

have few chips of patchy brown oil stain which is yellow. The clay is light gray to gray, occasionally

dark gray, soft sticky and washable. The shales are gray, light gray, green gray, blocky to sub-blocky,

occasionally sub-flaky, soft, sticky, and non-calcareous. The sand consists of loose quartz grains,

which are colorless, coarse, angular and poorly sorted. The anhydrite is white milky white, moderately

hard, soft cryptocrystalline. The maximum thickness of the Post Zeit Formation is 1128m that

recorded at 113-M-27 well and the minimum thickness is 772m recorded at BM-24 well.

2.6 PETROLEUM SYSTEM

The Gulf of Suez is the main oil province in Egypt with production ranking seventh among the world’s

petroliferous rift basins (Clifford, 1986). This situation arises from the Early Miocene block

fragmentation of the Paleozoic-Eocene pre-rift sequence, sedimentation of a thick syn-rift series with

excellent source, reservoir and sealing qualities, and by juxtaposition of source, seal, and reservoir

rocks in structural traps (El Ayouty, 1990). There is a close and well-established relationship between

tectonics and hydrocarbon potential in the Gulf of Suez. Maturation of the Late Cretaceous source rock

was controlled by rapid subsidence of small half-grabens from Early Miocene time's onward (Salah and

Alsharhan, 1996). The structural style and proven petroleum system of the Gulf of Suez should

continue southward into the Red Sea, although the dominant petroleum product is likely to be gas

(Dolson et al., 2001). In addition, geochemical studies (Salah and Alsharhan, 1996) show that

common Miocene source rocks have charged reservoirs in the southern end of the Gulf of Suez and

eastward in Midyan field of Saudi Arabia.

2.6.1 Source rocks

Several good quality source rocks have been identified in the Gulf of Suez. They range in age from

Carboniferous to Miocene. The Miocene source rocks are generally of a poorer quality and more

localized than the major pre-Miocene source rocks identified. Some of the source rock units identified

within the Miocene section, although of good quality, are immature or only marginally mature over

most of the Gulf of Suez (IHS, 2006).

Three source intervals are believed to have made significant contributions to the oil found in the Gulf

of Suez: the Brown Limestone and Thebes Formation of the pre-rift sequence and the Rudeis

Formation of the syn-rift. Of these three, the Brown Limestone has probably made the largest

contribution (Cooles et al., 1986) and (Lelek et al., 1992) quoted in (Zahran and Meshref, 1988).

The Thebes Formation appears to have less raw potential and is less mature than the Brown

Limestone. The Rudeis Formation, though widespread and with good potential in its basinal facies, is

generally immature to only early mature. The one exception to this appears to be in the southern Gulf

(Shahin and Shehab, 1984), (Shahin and Shehab, 1988), and (Mostafa et al., 1993).


Petroleum system2-25

2.6.1.1 Primary source rocks

2.6.1.1.1 Pre-rift source rocks

Brown Limestone Formation

The Campanian Brown Limestone is interpreted as the dominant regional source rock in the Gulf of

Suez. It is a pelagic chalky limestone deposited in a markedly anoxic outer shelf environment (Palmer,

1993). Its kerogen is classified as Type I and II and is almost entirely composed of amorphous

sapropel or algal debris. It is therefore oil prone. In wells for which data have been published it is

immature to nearing peak maturity and is probably at or beyond peak in adjacent kitchens. Total

Organic Carbon (TOC) content in immature samples is reportedly in the range 1-8.5% (Cooles et al.,

1986). Because the Brown Limestone is a very efficient source rock (Cooles et al., 1986), averages

based on all data tend to be lower, reflecting maturation and expulsion, and do not reflect its high

initial potential. TOC values as high as 21% have been documented in Campanian Brown Limestone

samples collected from underground phosphate mines in the southeastern Egypt (Lelek et al., 1992).

Thebes Formation

The Eocene Thebes Formation is a very good quality oil source rock in the Central Province. It consists

of limestones of open marine facies and its organic content is variable, but locally it is rich in TOC with

values 1-2.86% reported (IHS, 2006). Kerogen is classified as Type I-II, with 10- 30% woody and

herbaceous material, giving it slightly less oil-prone character than the Brown Limestone (IHS, 2006).

Where maturity data are available, they point marginal mature to early mature at best, but in the

source kitchens greater maturity can be expected and the Thebes may well have contributed

significant volumes of oil (IHS, 2006). Indeed, studies that indicate more than one source for Gulf of

Suez oils (Zein El Din and Shaltout, 1987) may be pointing to a combination of the Brown Limestone

and the Thebes Formation.

2.6.1.1.2 Syn-rift source rocks

Rudeis Formation

The Rudeis Formation was deposited in a variety of marine environments ranging in depth from

shallow to deep basinal. It is dominantly composed of mudstones, where source potential is

developed, but some limestones are also reported as having source potential. Over much of the Gulf

of Suez it is immature (vitrinite reflectance values are commonly reported to be less than 0.5%).

However, many authors believe that the Rudeis has made a significant contribution to the Gulf of Suez

hydrocarbon budget (Barakat, 1982), (Elzarka and Younes, 1987), and (Bosworth, 1994). It is

believed that the Rudeis is more mature in the southern Gulf of Suez and in this area it may have

indeed made a significant contribution (IHS, 2006). The Rudeis is probably not mature to the north of

the Morgan/Amal fields, but it is mature to the south (Shahin et al., 1988). The kerogen types are of

Type II or Type III although (Barakat, 1982) reported an average 60% of kerogen in Lower Miocene

(Rudeis) shales as being oil prone. Detailed analysis, indicates much higher proportions of woody and

herbaceous material than the pre-Miocene source rocks (Elzarka and Younes, 1987) and (Elzarka and

Mostafa, 1988). If this source character, where analyzed, is typical, it seems unlikely that the Rudeis

has made much of a contribution, since it contrasts markedly with the character of the established

Brown Limestone source. The work of (Rohrbach, 1981) points to a single source for the Gulf of Suez



oils, or sourcing from more than one source rock having very similar kerogen types. His data set

included oils from several levels of Morgan (all Miocene reservoirs) and from the Nubia of Shoab Ali

and GS382 in the southern Gulf. Furthermore, an oil-source rock correlation study on Zeit Bay oil (Zeit

Bay being one of the most southerly major fields) showed no similarity with Belayim, Kareem or

Rudeis kerogen types, but it did show similarities to the Brown Limestone and Thebes (Atef and

Mohamed, 1992).

2.6.1.2 Secondary source rocks

A number of other intervals are reported to have source potential, but are not thought to play a

significant part (IHS, 2006). These include the Raha and Abu Qada (matures, but not thought to be

volumetrically significant), the Matulla and Esna (moderate potential, not strongly oil prone) the

Kareem and Belayim formations (some potential, but generally immature):

- Abu Durba & Naqus formations: organically rich shales and coals are present within the Abu Durba

and Naqus formations in the Central Province. Although generally gas prone, they may constitute fair

quality oil and gas source rocks.

- Cenomanian Raha and Abu Qada formations: believed to be a minor source in the northern Gulf. It

has potential but is probably volumetrically insignificant. The Abu Qada and Raha shales have fair

source potential to generate mainly gas and minor oil. The vitrinite reflectance values indicate that the

shales are marginally mature to mature source rocks (Shahin et al., 1994).

- Turonian Wata Formation: shales and limestones within a thin interval of the Wata Formation in the

northern part of the Gulf of Suez can be considered significant source rocks. The TOCs can be as high

as 4.4% and the organic matter is of mixed sapropelic and humic nature. This source rock does not

appear to be present in the south-central province (IHS, 2006). It is considered as an active currently

expelling effective source rock that has already generated and expelled hydrocarbons. Hydrocarbon

generation is mainly related to the exchange of basin evolution and burial (Atia et al., 2015).

- Coniacian-Santonian Matulla Formation: intervals within the Matulla Formation contain limestones

and shales, which are fair to good quality oil source rocks. It is developed as a source rock only in the

south-Central and Southern provinces. TOC values reach as high as 3.37%. The generating capacity

of this unit is approximately 6 bo/sq m (IHS, 2006).

- Upper Campanian-Maastrichtian Sudr Formation: in the northern part of the Gulf of Suez, the Sudr

Formation generally has no source potential, but in the central and southern areas the unit is a good

quality oil source rock. It is early mature (Ro 0.4-0.6%) with TOC values as high as 6.9% and of

mixed humic and sapropelic kerogen type (IHS, 2006). In the Shoab Ali Oilfield, the Sudr Formation of

the Upper Senonian has high organic carbon content and the capacity to generate petroleum liquids

(Othman et al., 2013). The carbonate organic-rich interval of Sudr Formation has generated oil around

the Early Pleistocene (~0.9 Million year before present “Mabp” after the Pliocene tectonic event, called

Messinian Event) in SH-A1 well (Othman et al., 2013).

- Danian-Thanetian Esna Formation: generally, the Esna Formation has little oil source potential but

localized areas with good oil source potential are noted within the central and Southern provinces.

It is early mature (earliest maturity at 2,627-2,655m), with mixed sapropelic and humic kerogen and

TOC values of 2-2.7% (IHS, 2006).



- Middle Eocene Limestone Formation (Mokattam Formation): Mokattam Formation is a good quality

oil source rock in the northeast part of the Central Province (IHS, 2006).

- Aquitanian-Lower Burdigalian Nukhul Formation: the Nukhul Formation is generally only developed

as fair quality oil source rock in the southern part of the Southern Province. It is early mature with

TOC values ranging from 1% to 2.5%, predominantly humic with minor sapropelic nature (IHS, 2006).

- Langhian Kareem Formation: the Kareem Formation contains shales of fair to good oil source

potential only in the southern most part of the Central and the Southern Province. The TOC and S2

values average 1.0% and 5mg HC/g rock. However, samples with TOCs exceeding 2.5% and S2 of

7mg HC/g rock have been recorded from wells in the southern part of the Gulf of Suez. The organic

matter is of Type I, II and III kerogen (IHS, 2006).

- Serravallian Belayim Formation: the Belayim Formation contains fair to good quality oil source rocks

on the western side of the Central Province and in the Southern Province. The Sidri and Hammam

Faraun Members generally contain the thickest shale units. Shales have no source rock potential in the

Northern Province or on the western side of the north-central province, but are a fair to good quality

source rock in the rest of the Gulf of Suez. Average TOCs are 2.0%. The kerogen contains a

significant (up to 30%) sapropelic component. Oil generating capacity ranging from 1.7 bo/sq m to 5

bo/sq m indicate fair to good oil source rocks, but the productivity values are generally low due to the

low levels of maturity (IHS, 2006).

The thick Middle Miocene marls and shales of the basinal facies of the Rudeis and Kareem formations

used to be considered the exclusive source of the Gulf of Suez oils (El Ayouty, 1990) with Total

Organic Carbon (TOC) range from 0.7 to 1.25% (Elzarka and Younes, 1987). However, Late

Cretaceous to Eocene formations have also been found to be organic-rich. The Thebes Limestone,

with ≥1.8-2 wt % TOC and type II Kerogen; the Esna shale with 0.85% TOC, type III Kerogen; the

Sudr Formation (1.5-3.0% TOC, type I-II Kerogen); the Brown Limestone (over 3% TOC, with high

hydrogen indices) (Rohrbach, 1981), (Barakat, 1982), (Shahin and Shehab, 1988), and (Shawky et al.,

1992). Recent correlation studies have indicated that many oils are principally derived from carbonate

source rocks, most likely from the Brown Limestone and the Thebes Formation (Ungerer and et al,

1986) , (Chowdhary and Taha, 1987), and (Mostafa et al., 1993). Especially in the northern and

central sectors of the Suez Rift (Chowdhary and Taha, 1987). The Mid-Carboniferous shales of the

Gulf of Suez experienced rapid subsidence and heating during Miocene rifting, and may well have

contributed toward the charging of the many traps there (Keeley and Massoud, 1998). They are

neither rich enough in organic matter, nor sufficiently deeply buried anywhere but in the very centre

of the basin ever to have been active source rocks. The major source kitchens and probable migration

pathways of hydrocarbons are shown in (Figure 2.8).



Figure 2.8: Major source kitchens and migration pathways of hydrocarbons in the Gulf of Suez, (IHS, 2006).

2.6.1.3 Source rock maturity

Throughout the Gulf of Suez Basin, there are abundant oil source rocks, which are thermally mature

and even those source rocks found near the crests of structural highs are marginally mature. The

maturity levels of the Paleozoic sediments are not well defined, uplift and erosion during Late

Paleozoic-Early Mesozoic time has been significant within the south-Central Province, but the effects

decrease northwards. The Brown Limestone is of limited areal extent and its depth is some of the



down-faulted blocks are not accurately known. The Brown Limestone is always mature and, over large

areas, middle mature. In the Lagia and October troughs, and to the west of the Central horst, it is late

mature, and it is possible that in the latter area the full suite of hydrocarbon products has been

generated from medium gravity oil to gas. The maturity levels of the top Thebes Formation are very

similar to those of the Brown Limestone within the Southern and south-Central Provinces. Within the

north-Central Province, where the Thebes Formation is generally thicker, the Thebes Formation is

generally 0.5 to 1.0 spore color index units less mature than the Brown Limestone. The depth to top

Rudeis source rock is quite well defined. The maturity is most advanced where the top Rudeis is at its

deepest in the hotter areas. Generally this horizon is immature or early mature but reaches middle

maturity in the southern Darag trough, on the eastern side of the Lagia trough, in the South Belayim

and Gemsa troughs, and may be approaching late maturity to the west of the Central horst (IHS,

2006).

2.6.2 Geothermal gradients

Geothermal gradients in the Suez Rift generally range from 1.5 to 4°C/100m (Morgan et al., 1983),

being higher in the troughs, and up to 3.8-4.7°C/100m in the southern Gulf of Suez and northern Red

Sea. The oil generation window is at about 4500-5000 m, the base at 5800-6000m. Peak oil

generation was attained 8-4mio. y. ago, after the deposition of the evaporites (Shahin and Shehab,

1988), (Shawky et al., 1992), and (Mostafa et al., 1993). Migration is considered to have been mainly

vertical (up-dip and along fault planes) from the deep basins adjacent to the main highs (e.g.

Ramadan, October, Ras Bakr, Ras Gharib and South Gharib fields) (Sestini, 1995). A different pattern

with a gradual north to south increased down the Gulf from 20° to 55°C/km, while also noting that

anomalies do exist. Such a north-south transition could be expected, given the basin's evolution

(Shahin, 1988a). Higher heat flows could perhaps be theoretically expected in the southern Gulf of

Suez, which has undergone greater extension than the north (Lambiase and Bosworth, 1995).

(Barakat, 1982) provided a map of gradients, which show broadly gulf-parallel trends, with lower

gradients on the flanks and the same north to south transition to higher gradients, though from

27°C/km, over much of the northern Gulf, to over 46°C/km in the south (Figure 2.9). Geothermal

gradients vary significantly throughout the basin, with trends paralleling the grain of the basin. Values

of as low as 27.5°C/km are recorded where the evaporites are particularly thick, and these can lie

adjacent to zones with much higher gradients, as at Gebel Zeit (>45°C/km) (Schutz, 1994).

Although the basin has experienced periods of uplift, none of the key source rocks reached maturity

prior to the deposition of the thick sequence of mid-late Miocene evaporites. Onset of significant

generation probably started about 10Mabp in the deeper parts of the basin and, in those areas,

continues to the present. Adjacent to the October Field (Lelek and Abdine, 1990) and Ramadan field

(Abdine et al., 1992), the Brown Limestone is reported to be within the oil window at the present day.

For the Ramadan kitchen, the oil floor was computed to be 5822 m sub-sea. The depth of peak

generation varies from 5200 m in the north of the basin to only 3300 m in the south (Shahin, 1988b).

This southward increase in maturity versus depth may explain why there is a gas cap in the Zeit Bay

Field. The peak generation interval for the Brown Limestone as 3.3-3.5k m and suggest that main

generation and expulsion takes place between 120°C and 140°C (Cooles et al., 1986). The depth of



the onset of generation as 2700 m with generation complete at 4200 m (corresponding to Ro of

0.55% and 0.8% respectively) (Clayton, 1991). In the deepest parts of the central basin, the deeper

pre-Miocene source intervals may have reached the oil floor. However, the absence of significant gas

accumulations and the fact that the oils are generally under saturated would argue otherwise. This

may also reflect the reported efficiency of the Brown Limestone source rock, which results in most

hydrocarbons being expelled before the source rock reaches the oil floor (IHS, 2006).

Figure 2.9: Geothermal gradient and hot spot areas in the Gulf of Suez, (IHS, 2006) .



2.6.3 Reservoir rocks

The Gulf of Suez is known for its multi reservoir character (Figure 2.7). Each field contains several

productive reservoirs. Oil has been found in fractured, weathered basement in several fields (e.g.

Shoab Ali and South Geysum) and produced especially in the Zeit Bay field (6-16 m granite wash with

porosity, 8%, and K=0.1-10mD). The bulk of reserves are within the massive “Nubia” sandstones

(especially A and C units in Hurghada, Ras Gharib, Bakr, Amer, July, October fields) which have good

porosity and permeability values (porosity=16-18%, K=100-250mD) (IHS, 2006).

Quantitatively less important are the more lenticular Cenomanian-Turonian sands (porosity=13-18%,

K=100-200mD), which produce in the Belayim Marine, October, Bakr, Amer, Ras Gharib, Kareem, July

and Ramadan fields (Sestini, 1995). Proven Syn-rift reservoirs occur in the Belayim and Rudeis

formations (sand pays with porosity ≤24% in the Morgan, Belayim Land and Marine, July, Shoab Ali

and Zeit Bay fields), in some instances also in the early rift Nukhul clastics (Sestini, 1995).

Fractured and cavernous Late Cretaceous and Eocene limestones are oil-bearing in a number of fields

throughout the gulf. In some cases, their porosity is enhanced by early rifling exposure and

weathering. Proven Miocene carbonate reservoirs (dolomites and reefal limestone) occur within the

Kareem-Rudeis Formation; they have good quality, but distribution is patchy. Notable examples are

the reef limestone over a basement horst in the Gemsa field and the “Nullipore” biostrome in the Ras

Fanar field (Kulke, 1982). The Miocene carbonate reservoirs of the Gulf of Suez have a pore system

that has been modified by arid-climate, glacio-eustatic linked digenesis (Buday, 1980). Proven

reservoirs occurs at all stratigraphic levels from basement to Miocene and in both sandstones and

carbonates. The principal reservoirs in the Gulf of Suez are sandstones of the Miocene Rudeis and

Kareem formations, followed by the Paleozoic to Lower Cretaceous Nubia Formation. In addition to

these, significant amounts of oil are reservoirs in both carbonates and sandstones of the Middle

Miocene Belayim and Lower Miocene Nukhul formations and in sandstones of the Upper Cretaceous

Matulla Formation. Minor reservoirs exist elsewhere in the Upper Cretaceous sequence, within the

Eocene limestones, within sandstones interbedded with the Mid-Upper Miocene evaporites and finally

within fractured and weathered basement (IHS, 2006).

From the oldest to youngest, the formation reservoirs are as follows:

2.6.3.1 Nubia Group (Paleozoic-Early Cretaceous) & MALHA FORMATION (Jurassic-

Albian)

- The Nubia sandstones are important reservoir in fields including October, July, Belayim Marine (IHS,

2006) and Ras Budran field (Atia et al., 2015). The Nubia Group/Formation sandstones and its sub-

units vary in age from Cambrian to Early Cretaceous. They are generally interpreted as being

deposited in fluvial to alluvial environments interspersed with periods of marine transgression, which

generally deposited non-reservoir facies. These reservoirs are widespread throughout the basin, but

are locally absent. In the very north of the basin pre-Miocene folding, uplift and erosion has removed

some of the Nubia Formation. In general the Nubia sandstones are fair reservoir, locally poor or good,

depending on the content of clay minerals, intensity of secondary silica dissolution and precipitation

and burial depth and compaction. Porosity values range from 10% to 25%, and permeability from 10

mD to 10000 mD in the October field.



- The Malha sandstones were deposited in marginal marine to near shore marine in the north and

continental to marginal marine environment in the south. The sandstones form a reservoir in the Ras

El Ush field, with an average porosity (one well) of 21% (IHS, 2006).

2.6.3.2 Raha & Wata Formations (Cenomanian-Turonian)

In general, locally shallow marine sandstones and carbonates within the Cenomanian and Turonian

Raha and Wata formations form minor incremental pays. Lateral variations and modest quality mean

that these are not realistic targets, but can be useful re-completion options in Matulla/Nubia wells.

- Fair sandstone reservoirs of the Raha Formation are developed in the Central Province of the Gulf of

Suez. The sand beds are thin and show limited lateral extent. They form an important reservoir at

Belayim field with an average porosity and permeability of 18% and 200mD, respectively.

- Good quality sandstone reservoirs (locally fair) of the Wata Formation are present in most parts of

the central portion of the Gulf of Suez and are fair to poor in most parts in the north. Significant

sandstone reservoirs are present within Wata units 1, 3 and 5. Within the Wata Formation, carbonates

have poor to fair porosity and low permeability values in the majority of wells. It is possible that some

of these carbonates may develop vuggy and/or fracture porosity. Wata sandstones form important

reservoir only in the Bakr field (IHS, 2006).

2.6.3.3 Matulla Formation (Coniacian-Santonian)

The sandstones of the Matulla Formation also form an important secondary reservoir in many fields

that produce primarily from the Nubia sands in the southern part of the Gulf of Suez. They are

essentially structurally conformable with the Nubia and separated from the Nubia by the largely non-

reservoir facies of the Raha, Abu Qada and Wata formations. Matulla sands were deposited in shallow

marine environments and typically are laterally impressments and of poorer quality than the Nubia.

They are fairly widespread in the basin, though more affected by erosion in both north and south than

the underlying Nubia (IHS, 2006).

2.6.3.4 Sudr Formation (Late Campanian-Maastrichtian)

The Sudr carbonates are in general poor reservoirs, very minor reservoirs in Abu Zenima and

Ramadan Marine South discoveries. It is reported that Ramadan Marine South 1A well tested

3,500bo/d of 35°API crude, and gas/oil ratio of 158cf/b. The quality of the oil reserves in the

Ramadan Marine South discovery depends on the lateral extent of the fractures (IHS, 2006).

2.6.3.5 Thebes & Waseyit Formations (Ypresian-Lutetian)

- The Thebes Formation and, locally, the related (but slightly younger) Middle Eocene carbonates form

minor reservoirs. Matrix poro-permeability in these shallow marine carbonates is usually either poor or

totally lacking. However, leaching of fracture systems and soluble elements at the base-Miocene

unconformity has locally produced a viable reservoir. The porosity values range from 3% to 23%,

averaging 12%, and permeability from 40mD to 1,993mD, is averaging 70mD. Fractured and vuggy

carbonates produced oil in fields including Bakr, Kareem, Rahmi and Ras Matarma fields.

- Carbonates of the Waseyit Formation are reservoirs in the Ras Amer field. Porosity values range

from 6% to 18%; generally, they improve towards the northeast (IHS, 2006).



2.6.3.6 Nukhul Formation (Aquitanian-Lower Burdigalian)

In the Lower Miocene Nukhul Formation and its Members (Shoab Ali, October and Gharamul), the

sandstones deposited in continental alluvial/fluvial and in shallow marine environments form important

secondary reservoirs in many fields, and the principal reservoir in a few. Sandstone reservoirs with fair

to good properties (locally excellent) are well developed in the south. Carbonates are developed in the

central part of the Gulf. They exhibit fair to good reservoir characteristics, but are unpredictable in

undrilled areas. Many fields produce from the carbonate reservoirs. Lateral impressments of reservoir

facies is often observed in the Nukhul Formation, which was deposited during the earliest stages of

rifting and basin development. Much of the sediment was locally derived and deposition interspersed

between eroding high standing fault blocks. The one exception to this appears to be the Shoab Ali

Member, deposited in the southern Gulf, which appears to be a more widespread, persistent unit.

Sandstone reservoirs have porosity range from 13% to 25% and permeability from 20mD to

1,500mD. Carbonate reservoirs have a maximum porosity of 20% and the permeability ranges from

80 mD to 260 mD. Two fields produce from reefal limestone facies within the Gharamul Member of

the Nukhul Formation. This appears to have developed on high standing tilted pre-Miocene fault

blocks, and is a relatively localized facies of the Nukhul (IHS, 2006).

2.6.3.7 Rudeis and Kareem Formations (Burdigalian- Langhian)

Sandstone reservoirs occur at a number of levels in both the Rudeis and Kareem formations and their

sub-units. They are the most important reservoirs in the basin concerning discovered reserves.

Sandstones have fair to good reservoir properties with significant sand depocenters in the southern

part of the Gulf. They were deposited in a variety of environments ranging from shallow to deep

marine. Most commonly, however, they are described as being the products of fan delta deposition.

Characteristically there is significant lateral variation in sand development within both formations.

Sand is more common in both formations in the southern and south-central Gulf areas, but there is

major Kareem-Rudeis sand deposition in the Belayim field area. Kareem and Rudeis sands also

commonly form reservoirs in the western onshore portion of the basin and sporadically in northern

areas (IHS, 2006).

2.6.3.8 Belayim Formation (Serravallian)

Reservoirs are reported at two discrete levels within the Middle Miocene Belayim Formation, and

within undifferentiated Belayim Formation, where the conventional, four fold subdivision is not

recognizable: within the Sidri Member reservoirs are of sandstone, and within the Hammam Faraun

Member/Hammam Faraun Nullipore Facies both limestones and sandstones form reservoirs. Where no

division is possible, both limestone and sandstone reservoirs are identified.

- The Sidri Member is more normally composed of fine-grained clastics; however, it contains reservoir

sandstones in several fields. In both cases, these sands can be interpreted as being due to the

persistence of the transport systems that delivered sand to the underlying, sand-rich Kareem and

Rudeis. The depositional environment is again interpreted as fan delta. This is also true for the

majority of the Belayim sandstone reservoirs not attributed to a specific Member, such as in the giant

Morgan field. Dolomitic limestones of the Sidri Member form an important reservoir in the Zeit Bay

field.



- The Hammam Faraun Member has both sandstone and carbonate reservoirs, and the Hammam

Faraun Nullipore Facies has only carbonate reservoirs. The carbonate reservoirs all occur in the central

Gulf area, where normal marine, algal-reefal sediments form buildups on the tops of pre-Miocene

tilted fault blocks in the Ras Gharib, Shoab Gharib, Bakr and Ras Fanar fields. Elsewhere, such as in

Belayim Marine and Amal, sandstones within the Hammam Faraun again represent the products of

persistent fan delta deposition (IHS, 2006).

2.6.3.9 Zeit and Gharib Formations (Upper Tortonian-Messinian)

Grouped together to form the last of the minor Miocene reservoirs are thin sandstones within the Mid-

Upper Miocene Zeit and South Gharib formations. These will never be serious targets, as, generally,

the South Gharib salt effectively seals all younger reservoirs from charge. However, leakage can

locally charge such sands and further fortuitous discoveries may well be made at these levels (IHS,

2006).

2.6.3.10 Shukheir Formation (Pliocene-Quaternary)

The Pliocene-Quaternary reservoirs have been found to be oil-bearing only in the Abu Durba field

(Shukheir Formation). The average net pay thickness in the field is 15m. Sandstone porosities range

from 16 to 33%, and permeabilities from 20mD to 730mD. The good reservoir quality is a result of

shallow depths of burial (Alsharhan, 2003). The overall reservoir quality depends on the shale content

and the importance of diagenetic processes. Most of the Pliocene-Quaternary clastics in the southern

and central Gulf are derived from eroded basement rocks flanking the Gulf. Erosion of horsts within

the Quaternary basin partly contributed to sand accumulation. However, some of these highs have

acted as a barrier, effectively preventing the advance of prograding alluvial fans. Most sand bodies are

developed adjacent to these highs, and in places overstep the highs (IHS, 2006).

2.6.4 Seals

The Miocene evaporites constitute the most effective seal in the Gulf of Suez, especially those of the

South Gharib and Zeit Formation (Sestini, 1995). Top seals are dominantly middle Miocene shales and

evaporites of the Belayim and South Gharib Formations (Dolson et al., 2001). However, thick

mudstone sequences within the rift fill, notably within the Rudeis, also play a key part in sealing both

Miocene rift fill accumulations and those in pre-rift, tilted fault block traps. Oil accumulations in areas

where the Brown Limestone is less likely to be mature on the flanks of the rift, may attest to lateral

processes, perhaps due to the efficiency of the regional seal (IHS, 2006). Generally, the sealing of the

Miocene section is achieved by faults with 300-500m throw; throws of over 1200m are required to

bring the evaporites to seal the pre- Miocene reservoirs (Sestini, 1995).

A large throw brings the Miocene evaporites in juxtaposition with the pre-Miocene reservoirs on the

uplifted block, as shown at the Hilal, Belayim Marine, and Belayim Land fields (Saoudy, 1990). The

Miocene clastic section, such as the Rudeis and Kareem formations, can act as seals especially in

areas where some shaly facies have developed. In such cases, porous intervals within the formation

act as reservoirs, whereas the shaly intervals become vertical and/or horizontal seals, depending on

the magnitude of the throw of the fault. The Miocene shales also are an important factor in

stratigraphic traps, where they confine a body of sandstone as a lateral facies variation. The pre-rift

Cretaceous carbonates (Brown Limestone and Sudr), the Paleocene Esna Shale, and the Eocene



Thebes limestone formations can act as vertical seals over the Cretaceous sandstone reservoirs

(Alsharhan, 2003).

The principal seals in the Gulf of Suez Basin are as follows:

- Upper Miocene South Gharib Formation: Halites with minor anhydrite and shales are the ultimate

regional seal in the Gulf of Suez. Less frequently is the direct sealing formation, lying unconformably

or in fault contact with almost all reservoirs at some points in the basin.

- Middle Miocene Belayim Formation (Baba, Feiran, Hammam Faraun and Sidri Members): Anhydrites

and halites with interbedded mudstones form important seals, particularly in the southern Gulf of

Suez, where best developed, and where the evaporites lie directly on Kareem sandstone reservoirs

and cross fault from Kareem, Rudeis and Nubia reservoirs.

- Lower-Middle Miocene Rudeis Formation (Ayun, Mheiherrat, Mreir, and Safra Members): Shales form

intra-formational seals for Rudeis reservoirs, but also as a top seal to Nukhul reservoirs. Also

frequently, the sealing facies sitting on the base-Miocene unconformity act as top-seal to Thebes

Formation reservoired oils. Cross-fault and unconformity seal Nubia and other accumulations in the

pre-Miocene tilted fault-block plays. In parts of the basin where sand is rare in the Rudeis, these

mudstones form a semi-regional seal.

- Middle Miocene Kareem Formation (Markha, Rahmi and Shagar Members): Mudstones and

anhydrites can contribute to cross-fault seal for underlying Rudeis sands, and may locally form top

seal to Upper Rudeis reservoirs (IHS, 2006).

2.6.5 Traps

Most and the major oil fields are located in the central and southern sectors where the pre-rift pays

are most prolific along the mid-rift ridge (Ramadan-Morgan-Amal). Trapping was maintained by the

combined effect of structural, stratigraphic and lithological conditions. The Suez Rift fields are mainly

structural traps: fault closures or flexures draped across fault-block boundaries, or a combination of

the two (Meshref et al., 1988) and (El Ayouty, 1990). The fields in pre-Miocene reservoirs tend to be

pure structural traps (most prominent are Hurghada, Ras Gharib, Bakr, Kareem, Belayim Marine,

Ramadan, Sidky, GS-391, October, Shoab Ali, Ras Budran, ASL, Sudr and Matarma). Closures are

provided by the unconformity that truncates the rotated pre-Miocene fault blocks, by faulting, and by

fault-associated flexures. Stratigraphic-structural combination traps are dominant in most of the

Miocene pools. Stratigraphic trapping is caused by the lateral up-dip wedging out of sandstones in

both up-thrown and downthrown fault blocks (esp. in the upper part of Ras Malaab Group), by several

reefs located at the upper edges of fault blocks, and by Nukhul sandstones nested within the

irregularities of the basal unconformity (Sestini, 1995).

In the Belayim Marine and Zeit Bay fields, a four-way dip closure trap has formed as a hanging wall

anticline, related to thrusting of Miocene strata. This trap is sealed vertically by intra formational

mudstones or Miocene evaporites, with sources lying across or in the up fault direction from pre-rift

source rocks. Draping over fault-block boundaries created by differential sediment compaction over

the crests of blocks is common in syn-rift formation. Such traps are found in the Belayim Land and

Belayim Marine fields. A subtle trap occurs as flat lying areas between two grabens or two horst

structures, such as in South Ramadan field (Alsharhan, 2003).



2.6.6 Oil types

The Gulf of Suez is essentially an oil province. There are no dry gas discoveries to date, only one non-

associated gas discovery, and very few of the oil discoveries have a free gas cap. The one really

notable exception to this is Zeit Bay field, which has an 85m column of free gas overlying a 253m oil

column. Oils generally have moderate to high sulfur contents (typically 1-5% by weight) and are

moderate to low gravity (20-31°API) (IHS, 2006). Oils in the Gulf of Suez fields have a wide range of

API values from very immature (12.8°API) to mature oil or condensate (44.6°API). Sulphur content

varies between 0.3 and 5.3% (Rohrbach, 1981).

Locally, however, both higher and lower API values are recorded. Lower values notably in the western

onshore and northern Sinai fields (Bakr fields 13-20°API; north Sinai onshore fields 15-23°API) and

higher values notably in the Rudeis of October field (39°API) and along the 'B' trend fields in the

southern Gulf (32-43°API) (IHS, 2006). The higher values in the southern Gulf probably arise from

higher levels of maturity in the deep source kitchens adjacent to the 'B' trend. Analysis of a wide

spread of oils from reservoirs of all ages and from all segments of the basin suggest that these API

gravity variations are a function of the maturity of the source rock at expulsion. They are not due to

differences in the source material or, in the case of the low gravities, due to biodegradation

(Rohrbach, 1981). In a number of fields, downward decrease in oil gravity is noted with a heavy oil

zone or tar mat being found just above/at the oil-water contact (Ras Budran field, (Chowdhary and

Taha, 1987); October field, (Lelek and Abdine, 1990)). All the analyzed oils appear to have been

generated from source rocks containing predominantly marine derived organic matter, with some

notable exceptions (IHS, 2006).

There are three different oil groups in the Gulf of Suez (Mostafa et al., 1993):

1) In the onshore NE, fields of ASL, Sudr, and Ras Matarma (group 1) oils have 20-23°API, with 1.8-

2% Sulphur, and have n-alkane distributions with pristine dominant over phytane. Derivation from the

Cenomanian Raha Formation is considered likely (Mostafa et al., 1993). These oils have been

generated at early to middle levels of thermal maturity, their heavy nature being due to the source

rock type (IHS, 2006).

2) In the central part of the Gulf (group 2), oil densities are 17-30° API in the East (Ras Budran,

October, Abu Rudeis, Belayim, Wadi Feiran), and 20-24° API in the western onshore (Rahmi, Ras

Amer, Ras Bakr, Ras Gharib, Umm el Yusr fields). The oils are non-biodegraded, with a high Sulphur

content (2.3-5.3%), a low to medium amount of saturates, predominance of low molecular weight n-

alkanes, and a predominance of phytane over pristine (Mostafa et al., 1993). These oils show very

similar geochemical characteristics, but exhibit a wide range of physical properties. These oils have

been generated from the Brown Limestone, Thebes or Sudr formations. The similarity of the organic

matter type in these three units makes assessment of the relative contribution of each to the

reservoired oils impossible (IHS, 2006).

Based on volumetric considerations and regional variations in source rock quality for these three units

the following conclusions can be drawn:

- Oils in the north-Central Province have been generated from the Brown Limestone or Thebes

formations.


Belayim Marine Oil Field reserves by play2-37

- Oils from the western side of the south-Central Province are derived from the Brown Limestone.

- Oils from the central part of the south-Central Province and from the Southern Province may contain

components generated from the Brown Limestone, Sudr and Thebes formations with the Brown

Limestone and Sudr formations being the major contributors. The variation in physical properties of

these oils is related to the maturity level of the source rock from which they have been generated,

although in some cases the physical properties have been modified by the presence of a biodegraded

component or by water washing.

- Oils from the north-Central Province and from the western flank of the south-Central Province have

been generated at a lower, early level of thermal maturity, while oils from the central part of the area,

e.g. Ramadan and Morgan fields, have been generated at higher, middle levels of thermal maturity

(IHS, 2006).

3) Group 3 includes several fields in the southern sector (Ramadan, July, Morgan, Ras Shukheir, Zeit

Bay, Shoab Ali, Ashrafi, Sidky etc.). Their oils are medium-light (32-40°API) with a low to medium

Sulphur content (< 2%), a higher saturates content, aromatics overweight N, S, O compounds, and

pristine: phytane ratios are high (Mostafa et al., 1993). The GH-376 and GS-347 oils in the Southern

Province may contain a component generated from the Brown Limestone or Sudr formations, but are

also thought to contain a component generated from the Miocene sediments with the Nukhul and

Rudeis Formations being the most likely contributors. The LL87-2, July-41 and July-45 oils in the

south-Central Province may also contain a contribution from the Rudeis Formation. The Tawila West-1

oil and condensate has been generated at middle to late levels of thermal maturity, with the most

likely source being the Matulla Formation (IHS, 2006).

2.7 BELAYIM MARINE OIL FIELD RESERVES BY PLAY

2.7.1 Belayim Stratigraphic-Structural Play

In the Belayim Stratigraphic-Structural Play, lateral shaling out of the reservoir sandstone is

demonstrated and may contribute to defining trap limits. In other cases, there is a preferential

development of algal carbonate facies over pre-existing structural highs; with continued activity on

pre-Miocene, extensional faults contributing to the definition of trap limits. The Belayim Formation and

its sub-units Hammam Faraun, Hammam Faraun Nullipore Facies and Sidri Member are the main

reservoirs, sealed by intra formational anhydrites and shales of the Belayim Formation or overlying

anhydrites and shales of the South Gharib and Zeit formations. The petroleum system in this play is

Brown Limestone /Thebes – Miocene and Rudeis Miocene (IHS, 2006).

2.7.2 Kareem-Upper Rudeis Stratigraphic-Structural-Unconformity Play

Kareem-Upper Rudeis Stratigraphic-Structural-Unconformity Play is the most important play in the

Gulf of Suez (Figure2.10). It is present in fields including Morgan and Belayim Marine fields. The

Kareem-Upper Rudeis group of plays contains the largest share of the proved reserves in the Gulf of

Suez. The majority of Kareem-Upper Rudeis reservoirs comprise sandstones and conglomerates and

these are usually fairly uniform in a given locality, but are products of a great variety of depositional

environments. Significant lateral variation in sand supply to the rift basin, combined with the impact of

the pre-existing rift topography on depositional patterns, has resulted in significant localization of


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Belayim Marine Oil Field reserves by play2-38

reservoir sand development. This is a key element of the plays. In the eastern part of the basin,

particularly onshore Sinai, the lateral equivalent of the Kareem-Upper Rudeis sequence, the lower part

of the Abu Alaqa Group, comprises coarse fan clastics. These were deposited in alluvial fans and in

fan deltas. Reservoir quality is generally good. However, there is significant lateral and vertical

variation due to the provenance. Older sands seem to be derived from the reworking of quartz-rich,

pre-Miocene sandstones such as the Nubia formation sands. These have the best reservoir quality.

Some younger sands seem to be derived from the unroofing basement in the catchments area and

are less clean with impact on both porosity and permeability. Seals for most of these sands comprise

interbedded Miocene basinal mudstones, but in some traps, the key regional seal, the South Gharib

Formation salt and/or evaporates of the Belayim Formation also play apart or are the key seal. The

Kareem-Upper Rudeis Stratigraphic-Structural-Unconformity Play is similar to the Structural,

Stratigraphic and combined Structural-Stratigraphic plays, with examples where the structural

component is a tilted fault block or faulting, while in many examples it is anticlinal drape; the

stratigraphic component is a facies change or depositional pinch-out; and the presence of an

unconformity as additional component to the trap mechanism. The petroleum system in this play is

Brown Limestone/Thebes–Miocene and Rudeis Miocene (IHS, 2006).

Figure 2.10: Schematic play types in the Gulf of Suez, (IHS, 2006) .

2.7.3 Nubia Structural-Unconformity Play

The Nubia Structural-Unconformity Play is the second important play in the Nubia reservoirs (Figure

2.10). In this play, the sands are involved in typical pre-Miocene tilted fault block configurations, but

with clear modification by erosion and sealing across the unconformity by Miocene mudstones or

evaporates. The petroleum system in this play is Brown Limestone/Thebes–Pre-Miocene (IHS, 2006).


Belayim Marine Oil Field reserves by play2-39

2.7.4 Upper Cretaceous Stratigraphic-Structural Play

The Upper Cretaceous plays contain important amount of hydrocarbons in the Gulf of Suez and are

present in many fields/discoveries. The various Upper Cretaceous reservoirs form useful secondary

targets in a number of traps were the principal play is the Nubia sandstone. The Upper Cretaceous

reservoirs, dominantly by Matulla and Wata formations, have variable quality and development. The

petroleum system in this ply is Brown Limestone/Thebes–Pre-Miocene (IHS, 2006).

2.7.5 Upper Cretaceous Structural Play

The Upper Cretaceous Structural Play occurs in several fields/discoveries. It mirrors the underlying

Nubia Structural play and shares many of its principal features. Reservoirs occur principally within the

Matulla and Wata formations, but they also occur in the Raha, Wata and Sudr formations. The

petroleum system in this play is Brown Limestone/Thebes–Pre-Miocene (IHS, 2006).

Mansoura UniversityTheoretical Aspects2015

Procedures of Formation Evaluation3-1

depth total theis

(m)depthformationtheis

etempertaurholebottomtheis

etemperatursurfacemeantheis

C)(etemperaturformationtheiswhere

.

TD

FD

BHT

MST

FT

FDTD

MSTBHTMSTFT

°

−+=

ity)radioactivminimumofzonefree(shale

zonecleanesttheinreponselograygammaaveragetheis

zoneshaleadjacenttheinreponselograygammatheis

(API)interestofanalyzedzonetheinreponselograygammatheis

indexshaletheiswhere

log

log

clean

clay

sh

cleanclay

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sh

GR

GR

GR

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=

3. THEORETICAL ASPECTS

PART I: BOREHOLE GEOPHYSICS: TECHNIQUES USED AND DATA PROCESSING

3.1 PROCEDURES OF FORMATION EVALUATION

3.1.1 Formation temperature and Rw determination

The formation temperature, (Equation 3-1), is an important parameter in log analysis because the

electric resistivities of the drilling fluid, mud filtrate, and the formation water vary with temperature

which is determined by Asquith’ formula (Asquith, 1980)

Equation 3-1: Formation Temperature Equation (Asquith, 1980).

The water resistivity, Rw, from SP module used to create a continuous Rw curve. A formation

temperature curve must be entered. The result RwSP curve will be calculated and corrected to the

output temperature entered.

3.1.2 Clay volume analysis

A problem of interpreting shaly formations is the calculation of porosity and water saturation

considering the shale effect. Because the shale effect depends on the shale content, the estimation of

the Vsh is of prime importance. Qualitatively, Vsh indicates whether the formation is considered clean

or shaly. This determines the types of the model or approach to be used for the interpretation.

Quantitatively, Vsh used to estimate the shale effect on log responses and to correct them to the

clean formation responses.

3.1.2.1 Single shale volume indicator

The volume of shale can be calculated using gamma ray (Equations 3-2, 3-3 and 3-4); neutron or

resistivity logs (Equations 3-5 and 3-6):

Equation 3-2: Shale index from Gamma Ray log.

Shale index, ISh, first calculated from (Equation 3-2). The shale volume related to shale index. It is

customary to assume that Vsh=ISh. This assumption, however, tends to exaggerate the shale volume.

Therefore, several empirical relationships developed to correct the shale volume for different geologic

ages and areas. The most notable correlations were developed by (Stieber, 1970) as in(Equation 3-3):


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Procedures of Formation Evaluation3-2

( )

indexshaletheis

shaleofvolumetheiswhere

23

sh

sh

sh

shsh

I

V

I

IV

−=

( )( )

zonecleanesttheinreponselogneutronaveragetheis

zoneshaleadjacenttheinreponselogneutrontheis

(%)interestofanalyzedzonetheinreponselogneutrontheis

logneutronfromcalcualtedshaleofvolumetheiswhere )(

)(

cleanneu

clayneu

neu

Neush

cleanNeuclayNeu

cleanNeuNeu

clayNeu

NeuNeush

V

V

Φ

ΦΦ

Φ−ΦΦ−Φ

ΦΦ=

( )( )

zonecleanesttheinreponselogresistvityaveragetheis

zoneshaleadjacenttheinreponselogresistvitytheis

m)(Ωzonetrueofresistvitytheis

logyresistivitfromcalcualtedshaleofvolumetheiswhere )(

clean

clay

t

Neush

clayclean

tclean

t

claysh

R

R

R

V

RR

RR

R

RV

−

−−=

Equation 3-3: Corrected volume of shale based on shale index (Stieber, 1970).

Equation 3-4: Volume of shale estimated from neutron logs (PGL, 2000) .

Equation 3-5: Volume of shale estimated from resistivity logs (PGL, 2000).

3.1.2.2 Double Shale volume indicators

The double indicators rely on the principle of defining a clean line and a clay point. The shale volume

calculated as the distance the input data falls between the clay point and the clean line, (Figure 3.1).

These are indicators utilizing a pair of the porosity tools. These may be Neutron/Density,

Sonic/Density or Neutron/Sonic combinations (Equations 3-6 to 3-8).

Figure 3.1: Neutron / density cross plot that used as a double shale indicator (PGL, 2000) .



( )( ) ( )( )[ ]( )( ) ( )( )[ ]

linecleantheofendstwotheforvaluesneutronanddensitytheare,,,,

logsdensityandneutronfromcalculatedshaleofvolumetheiswhere

2211

)(

121112

121112)(

−−−−

−−−−−−

−−−−−−

−−−−−−−−−−=

clclclcl

NDsh

clclclclayclclayclcl

clclclclclclNDsh

NDND

V

NNDDNNDD

NNDDNNDDV

( )( ) ( )( )[ ]( )( ) ( )( )[ ]

linecleantheofendstwotheforvaluessonicanddensitytheare,,,,

logsdensityandsonicfromcalculatedshaleofvolumetheiswhere

2211

)(

121112

121112)(

−−−−

−−−−−−

−−−−−−

−−−−−−−−−−=

clclclcl

SDsh


clclclclclclSDsh

SDSD

V

SSDDSSDD

SSDDSSDDV

( )( ) ( )( )[ ]( )( ) ( )( )[ ]

linecleantheofendstwotheforvaluessonicandneutrontheare,S,N,S,N

logssonicandneutronfromcalculatedshaleofvolumetheiswhere

2cl2cl1cl1cl

)(

121112

121112)(

−−−−

−−−−−−

−−−−−−

−−−−−−−−−−=

NSsh


clclclclclclNSsh

V

SSNNSSNN

SSNNSSNNV

exponentncementatiotheis

(%)valueporositytheis

factoryresistivitformationtheiswhere

m

F

F m

Φ

Φ= −

exponentncementatiotheis

constanttcoefficientheis

(%)valueporositytheis

factoryresistivitformationtheiswhere

m

a

F

aF m

Φ

Φ= −

Equation 3-6: Shale volume estimated from Neutron/Density logs as a double shale indicator (PGL, 2000) .

Equation 3-7: Shale volume estimated from Sonic/Density logs as a double shale indicator (PGL, 2000).

Equation 3-8: Shale volume estimated from Neutron/sonic logs as a double shale indicator (PGL, 2000).

3.1.3 Porosity analysis

3.1.3.1 Clean formation analysis

On the basis of laboratory measurements of F and φ on core samples, (Archie, 1942) suggested the

following empirical relationship (Equation 3-9):

Equation 3-9: Rock resistivity-porosity relationship (Archie, 1942).

Another empirical equation (Equation 3-10) relating F and φ was also suggested by the result of

experimental measurements conducted by (Winsauer, 1952):

Equation 3-10: Rock resistivity-porosity relationship (Winsauer, 1952).

The usefulness of (Equations 3-9 and 3-10) in determining F is governed by the values of "a" and "m".

Theoretical and experimental investigation revealed that the values of "a" and "m" are mainly

dependent on the pore geometry. The exponent "m" is dependant mainly on the degree of

consolidation of the rock and is termed the cementation exponent. (Timur et al., 1972) studied a large

number of sandstone formations and found that the coefficient "a" and "m" vary over wide ranges.

The coefficient "a" varies from 0.35 to 4.78 and "m" varies from 1.14 to 2.52.



fluiddrillingtheintimetravelacqustictheis

matrixtherocktheintimetravelacqustictheis

sec/ft)(interestofzonetheinresponselogsonictheis

logsonicfromcalculatedporositytheiswhere

f

ma

maf

maS

t

t

t

tt

tt

∆∆∆

Φ

∆−∆∆−∆=Φ

µ

shalecompactedintimetraveltransitspecifictheis100

1.0)(normalytcoefficiencompactiontheis

factorcompactiontheis

shaleadjacentintimetransitspecifictheis




logsonicfromcalculatedporositytheiswhere100

.

where

1.

c

C

t

t

t

t

ctC

Ctt

tt

P

sh

f

ma

shP

Pmaf

maS

∆

∆∆∆

Φ

∆=

∆−∆∆−∆

=Φ

µ

The velocity of a compressional wave through a rock formation influenced both by the solid

framework or rock matrix as well as by the fluids fillings the pore spaces. A relation, (Equation 3-11),

defining a uniform intergranular porosity in terms of the total formation velocity, rock matrix velocity,

and fluid velocity was proposed by (Wyllie et al., 1956) and suggested earlier by (Hughes and Jones,

1950) has been very popular with respect to logging approaches.

This relation was experimentally determined and generally accepted as being substantially accurate

for a broad-range of conditions. It is usually referred to as the Wyllie's time average formula. It is

expressed as the reciprocal value of velocity, ∆t, or specific transit travel time. The use of this

equation in a clean, compacted, and consolidated sandstones yields representative porosity values

(Geertsma, 1961).

Equation 3-11: Porosity-transit time relationship in compacted formation (Wyllie et al., 1956).

(Tixier et al., 1959) suggested the introduction of a compaction correction factor (Equation 3-12).

Formations, which are not subjected to sufficient overburden pressures, do not have the necessary

degree of compaction and rigidity for proper transmission of an acoustic wave.

Equation 3-12: Porosity-transit time relationship in unconsolidated formation (Wyllie et al., 1958).

c= shale compaction coefficient, which is a constant which normally 1.0 (Hilchie, 1978).



fluiddrillingtheintimetravelacoustictheis

matrixrockshaletheintimetravelacoustictheis

shaleadjacent in thetimetransitspecifictheis

shale theofvolumetheis

factorcompactiontheis




logsonicfromcalculatedporositytheiswhere

.1

f

ma

sh

sh

P

f

ma

maf

mashsh

Pmaf

maS

t

t

t

V

C

t

t

t

tt

ttV

Ctt

tt

∆∆∆

∆∆∆

Φ

∆−∆∆−∆−

∆−∆∆−∆=Φ

µ

fluiddrillingtheofdensitytheis

matrixrockshaletheofdensitytheis

shaleadjacentinresponselogdensitytheis

zoneshaleainlogdensityfromcalculatedporositytheis)(

shaleofvolumetheis

fluiddrillingtheofdensitytheis

matrixrocktheofdensitytheis

interestofzonetheinresponselogdensitytheis

logdensityfromcalculatedporositytheiswhere

)(

where

)(

f

ma

sh

shD

sh

f

ma

b

D

fma

shmashD

fma

bmaD

shDshD

V

V

ρρρ

ρρρ

ρρρρ

ρρρρ

Φ

Φ−−=Φ

−−=Φ

Φ+Φ=Φ

In uncompacted shaly sands, the porosity, corrected by the compaction factor cp, is (Equation 3-13):

Equation 3-13: Porosity of uncompacted laminated shaly formation (Dresser Atlas, 1979).

3.1.3.2 Shaly formation analysis

Most sand, whether compacted or unconsolidated, which contain appreciable amounts of shale or clay

particles will exhibit longer transit travel times than clean sand of identical porosities in the same

borehole environment. The increase in transit travel time primarily results from the difference in the

velocities of the shale or clay particles and the sand matrix. For this reason, a correction has been

introduced in order to obtain more reliable porosity values. Therefore, it is necessary to estimate the

fractional shale volume from other log readings relying strongly on the shale content. The manner in

which shaliness affects the sonic log response not only depends upon the amount of the shale

present, but also upon the type of the distribution of the shale within the sand beds.

Equation 3-14: The density porosity in the formation of interest (Bassiouni, 1994; Dresser Atlas, 1979).

The presence of shale complicate the interpretation of the tool response because of the diverse

characteristics of shales and the different responses of each porosity tool to the shale content. On the

density porosity log, shales display low to moderate porosity values, (Equation 3-14), while on the

sonic and neutron logs, shales display moderate to relatively high porosity values (Equations 3-15 and



zoneshaleainlogneutron thefromcalculatedporositytheis)(Φ

shaleofvolumetheis

logneutron thefromcalculatedporositytheiswhere

)(

shN

sh

N

shNshN

V

V

ΦΦ+Φ=Φ

zoneshaleadjacentinlogsonicby thedisplayedporosityapparenttheis)(

shaleofvolumetheis

formationshalyainlogsonicby thedispalyedporosityapparenttheiswhere

)(

shS

sh

S

shSshS

V

V

Φ

ΦΦ+Φ=Φ

zoneshaleadjacentintoolthebydisplayedporosityapparenttheis)(

filledliquidcleanisformationthethatassumingtool,thebydisplayedporosityapparenttheis

shaleofvolumetheis

formationshalyaofporosityeffectivetruetheiswhere

)(

sha

a

sh

true

shashatrue

V

V

Φ−Φ

ΦΦ−Φ=Φ

3-16). In a shaly liquid–filled formation assumed to have normal compaction and no secondary

porosity. Therefore, the tool response expressed depends on the porosity, shale content and the fluid,

shale and matrix properties. This value is calculated by assuming a certain ρma that corresponds to a

clean formation (e.g. 2.65 g/ccm in sandstones). The fluid type assumed liquid and then, ρf chosen

accordingly. Because of these assumptions, φD, is an apparent porosity. It is equal to the true

porosity, φ only in clean, and liquid filled- formations. The term (φD)Sh, is the apparent density

porosity displayed by the tool if placed in a 100% shale formation having the same characteristics as

the shale present in the formation of interest (Equation 3-17).

Equation 3-15: The neutron porosity in the formation of interest (Bassiouni, 1994).

Equation 3-16: The sonic porosity in the formation of interest (Bassiouni, 1994).

Equation 3-17: True effective porosity of a shaly formation in the zone of interest (Bassiouni, 1994).

The term, Vsh (φ a) Sh, regarded as a correction term.

3.1.4 Water saturation analysis

3.1.4.1 Fluid saturation in clean formation

This section regards reservoir rocks, whose pore spaces are filled with both, brine and hydrocarbons.

Because oil and gas are non-conductors, the resistivity of the rock partially saturated with

hydrocarbons, Rt, is higher than the resistivity of the same rock completely saturated with water, RO.

Formation resistivity increases with increasing hydrocarbon saturation. In true porous media, as

hydrocarbon replaces water, the resistivity increases slowly at first, the oil or gas usually fill the center

of the pores, leaving enough room for the current to flow. At higher hydrocarbon saturation, when

most of the pore spaces are occupied by non-conductors, the resistivity will increase strongly

(Bassiouni, 1994). The resistivity ratio is called the resistivity index, IR, IR= Rt / RO. The presence of

hydrocarbon is indicated by the value of the resistivity index and not by the absolute values of Rt. By

using experimental studies of clean formations (clay–free rock, or, rock containing moderate amount

of clay) (Archie, 1942) stated at the following empirical relationship (Equation 3-18).



exponentsaturationtheis

/indexyresistivittheis

saturationwatertheiswhere

1

n

otR

nW

R

nW

RRI

S

IS

=

=


21

21

21

W

tm

W

t

W

t

oW

S

R

Ra

R

RF

R

RS

Φ=

=

=


5

4.0

21

22

2

W

tW

e

sh

sh

sh

she

WW

S

RRR

V

R

V

RS

Φ+

+

−Φ

=


4.0

21

W

she

Wsh

t

WW

S

R

RV

R

RFS

Φ−

=

Equation 3-18: Water saturation in a clean formation (Archie, 1942).

The saturation exponent, n, depends on the rock type, primarily the manner in which the pores are

connected. The values of, n, ranging from 1.0 to 2.5 have been reported in literature. For clean,

consolidated sand, the value of n appears to be close to 2.0, so an approximate generalized relation

written as shown in (Equation 3-19):

Equation 3-19: The generalized Water saturation equation (Archie, 1950).

3.1.4.2 Fluid saturation in shaly formations

(De Witte, 1957; Wyllie and Pantode, 1950) concluded that, in addition to the conventional

conductivity associated with the formation water, there is a conductivity component associated with

the clay and this conductivity component is independent of the water resistivity (Equation 3-20).

Equation 3-20: Simandoux water saturation equation (Simandoux, 1963).

Where Φe= effective porosity that exclude the shale effect; VSh= bulk volume fraction of the shale,

RSh= shale resistivity.

(Fertl and Hammack, 1971) used actual field examples that represent various amounts of shaliness.

They recommended the use of their own empirical equations (Equation 3-21), which was found to be

of acceptable statistical representativeness. It bears a few advantages compared to the Simandoux

equation (Equation 3-20); it treats the shale effect as a correction term subtracted from the clean–

sand term. This equation holds the advantage of pointing out the practical aspects of the shale effect.

First, treating shaly sand as clean will underestimate the potential of a hydrocarbon formation because

of the high Sw values calculated. Second, using an inflated Vsh will produce exactly the opposite

effect, i.e., overestimation of the potential of a hydrocarbon formation.

Equation 3-21: Water saturation equation of a shaly formation (Fertl and Hammack, 1971).

According to Fertl and Hammack, (1971) it can be expresses as:


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Source Rock Analysis3-8


4.0

81.0 21

2

W

she

Wsh

te

WW

S

R

RV

R

RS

Φ−

Φ=

termcorrectiontheiswhere

4.0

W

she

WshW

S

R

RVS

∆

Φ=∆

porosityaveragetheiswhere

.

1

1

av

ni

ii

ni

iii

av

h

h

Φ

Φ=Φ∑

∑=

=

=

=

( )

saturationwateraveragetheiswhere

.

1..

1

1

av

ni

iii

ni

iWii

av

h

ShS

Φ

Φ

−Φ=

∑

∑=

=

=

=

samplesofnumbertheis

valueinputthi'theis

valueinputthi'theis

shaleofvolumeaveragetheiswhere

.

1

1

n

i

i

av

ni

ii

ni

iii

av

h

Vcl

h

hVclVcl

∑

∑=

=

=

==

The correction term can be expressed by the following equation:

3.1.5 Cutoffs and summation reports

Cutoff porosity is the minimum value above which economically acceptable single-phase permeability

is probable. The most important parameters is the hydrocarbon saturation, it represents not only a

volumetric quantity, but also is related to the ability of the rock to transmit fluids. As the hydrocarbon,

saturation approaches some critical or cutoff saturation value, the ability of the hydrocarbons to flow

decrease rapidly and, in turns, the ability of water to flow increases rapidly.

Each depth in the data is considered a discrete interval, with the recorded depth being the center of

the interval. Therefore, when making averages over an interval, only half of the top and bottom depth

increments counted. The following equations (Equations 3-22 to 3-24) inform how net reservoir and

pay are to be calculated (PGL, 2000):

Equation 3-22: Average porosity (PGL, 2000).

Equation 3-23: Average water saturation (PGL, 2000).

Equation 3-24: Average clay volume (PGL, 2000).

3.2 SOURCE ROCK ANALYSIS

Many publications advocate to use wireline logs to evaluate source rock potential (Herron, 1991;

Meyer and Nederlof, 1984; Schmoker, 1981). The advantage of wireline logs is the high spatial data

resolution. Logs may indicate stratigraphic intervals of unidentified source rocks, and in more explored

basins, they are used to quantify the vertical and lateral extent of source rock units. Tools

comprehensively most frequently used are gamma ray, resistivity, sonic transit time, and density logs.


Source Rock Analysis3-9

In contrast, logs are only indirect measures of source rock characteristics and subject to drilling

problems. Most evaluations approaches of source rocks use multiple logs and calibrate them by

geochemical data, in order to estimate quantitatively the TOC, the volume and the maturity of

potential source rocks in order to distinguish source rocks from non-source rocks. Although wireline

logs are a useful supplement to conventional geochemical studies, they must be used with

considerable caution, for several reasons: (1) pyrite and other minerals producing anomalously high

density readings, (2) under compacted formations showing less contrast between organic-rich and

lean layers and poor correlations between resistivity and sonic logs, (3) large washouts in boreholes,

(4) low-porosity dense rocks such as limestones and dolomites showing anomalously high resistivity

because of a lack of electrically conducting fluids, and (5) igneous intrusions causing variable gamma

ray intensities (Hunt, 1995).

Organic-rich shales also have low sonic velocities. Sonic transit times slow from about 60 to nearly

100µsec/ft in the most organic-rich zone. Bulk density decreases in the same zone, and the gamma

ray log shows an increase. The nature of sonic logs makes for relative changes that are quite sensitive

within a given well. Electrical resistivity increases where organic matter or oil replaces water in rock

pores, because the former are not electrically conductive. Therefore, resistivity is very high where oil

has been generated, whereas resistivity is in zone of immature organic matter. Attempts were made

to identify mature source rock horizons on petrophysical wireline logs, such as gamma ray, sonic, and

resistivity logs. Detection generally depends on the occurrence of nonconductive petroleum in the

pore space of the mature source rock, which makes it abnormally resistive, or on the overpressure

that tends to be created by actively generating source rocks, which causes abnormally long sonic

transit times. Source rocks known to be abnormally radioactive compared to surrounding non source

shales, may therefore be detected on gamma ray logs. There are numerous pitfalls, however, in the

identification of source rocks on wireline logs, and potential source rock horizons should always be

confirmed where possible by correlation with geochemical indicators (Allen and Allen, 2005).

3.2.1 ∆T log R Technique

This technique was first developed and tested within EXXON/ESSO beginning in1979. Since that, it has

been successfully applied to many wells worldwide. It is found to work adequately in both carbonate

and clastic source rock, and can be accurate in predicting TOC% over wide range of maturities

(Passey et al., 1990). The method employs the overlying of a properly scaled porosity log (Sonic,

Density or Neutron) on a resistivity curve (preferably from deep reading tool). The organic-rich

intervals can be then recognized by the separation and non parallelism between these two curves (∆

log R). (Passey et al., 1990) proposed the following algebraic expression for the calculation of DT log

R from sonic and resistivity overlay: (Equation 3-25) Average clay volume

Equation 3-25: ∆log R=log10 (Rt/Rtbl) +0.02*(∆ t - ∆tbl)

Where ∆log R is the curve separation measured in logarithmic resistivity cycles, Rt is the true

resistivity log reading, ∆t is the sonic log reading, Rtbl and ∆tbl are the base line resistivity and sonic

readings in front of non-source shale, and 0.02 is a constant based on the ratio of 50µsec/ft per one

resistivity cycle.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Source Rock Analysis3-10

Density and neutron can be also scaled in combination with the resistivity curve in a similar way to

that used in the sonic/resistivity combination. The total organic carbon (TOC %) can be then

calculated as follows:

Equation 3-26: TOC%= (∆ log R) * 10(2.297-0.1688*LOM)

Where TOC is the total organic carbon content and LOM is the level of maturity (ranges between 7

and 12 for mature oil).

Figure 3.2: Schematic representation of sonic and resistivity-log responses in source. Non-source and reservoir intervals using a delta log R overlay (modified from (Passey et al., 1990)).


Introduction3-11

PART II: NUMERICAL BASIN MODELING

3.3 INTRODUCTION

Basin modeling comprises numerical simulation of the geologic structures through time, based on

physical and chemical reactions (Burrus et al., 1996; Ungerer et al., 1990; Welte and Yükler, 1981). It

refers to simulation of the thermal history of a basin for a given geologic and depositional history and,

associated with this the timing (and volume) of hydrocarbon generation as well as migration and

accumulation (Ungerer et al., 1990). The basin modeling term was renamed to “Petroleum System

Modeling” pointing out the combination of sedimentary basin analysis with petroleum generation and

accumulation processes (Magoon and Dow, 1994). The main model classes or program modules

performed in one forward simulation in each time step for a complete analysis is showing in (Figure

3.3). Based on this classification, most of the presented models, parameters and process are closely

interconnected.

Figure 3.3: The general work-flow of petroleum system modeling based on the fundamental concept of (Welte and Yükler, 1981).

3.3.1 Construction of The New Geometry

Basin modeling is the temporal reconstruction of basin history and specifically refers to the procedure

of establishing the sequential record of changes in controls and products, which have occurred during

the long geologic history of a basin. The basin model depends on a well-defined conceptual model,

based on the sum of all available geologic data. The conceptual model is a formulation, suitable for

numerical treatment of the principal elements of the basin history. The simulation is then performed


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Introduction3-12

( )( )

(%)depositionoftimeatporositytheis

(%)porositypresenttheis

durationtimetheis

Φ)(porositypresentatthicknesstheis

timetorespectwithonaccumulatisedimentofratetheiswhere

1

1

o

P

o

P

A

T

R

A

TR

ΦΦ

Φ−Φ−=

based on the numerical representation of the conceptual model. If necessary, the conceptual model is

adjusted or modified to lead to a better match between simulation and calibration data (Poelchau et

al., 1997).

Basin modeling requires first a well-designed geologic time framework. This means that the physical

sequence of layers (as depth or thickness) must be converted into an uninterrupted sequence of

events (geochronologic units) with absolute ages for each event boundary (Poelchau et al., 1997).

Each event represents the time span during which either deposition, erosion, or non-deposition

occurred. Physical sedimentary units that result from geologic processes during a single event are

called “layers”. Events are defined in terms of their duration as a part of the conceptual model,

whereas the corresponding layers are defined in terms of their local (present) thickness as well as of

their lithological and physical properties. In addition, two other parameters are important for thermal

history simulation, paleo-water depth and sediment-water interface temperature.

3.3.1.1 Compaction model

Present-day stratigraphic thicknesses are a product of cumulative changes in rock volume through

time. Since present thicknesses are of compacted sediments, it must be corrected to reflect the actual

porosity at the geologic time plotted, the layers must be decompacted. This achieved by the

“Backstripping” methods or by iterative forward modeling using assumptions about original

porosities. The exact determination of the rock porosities and their changes are very important where,

most of the rock properties, such as thermal conductivity, heat capacity, density, and elastic or plastic

modulus, strongly depend on rock porosity (Poelchau et al., 1997).

An alternative phenomenological model of porosity versus depth, the porosity decrease as a function

of the load on the layer being considered (Falvey and Middleton, 1981). In this model, a relationship

formulated by assuming the incremental change in porosity is proportional to the change in load. In

order to model layer thickness as a function of time, calculated burial history and geo-history and

plots in which compaction is modeled. It is necessary to model the change in porosity as a function of

time or, equivalently, as a function of depth. This modeling is illustrated by considering the rate of

sediment accumulation (R) with respect to time (Van Hinte, 1978) (Equation 3-27).

Equation 3-27: The rate of sedimentation with respect to time (Van Hinte, 1978).

3.3.1.2 Estimation of maximum burial depth

Stratigraphers have commonly estimated the amount of erosion by comparison of sections that

appear complete or less eroded to reconstruct pre-erosion thicknesses and geometries (Kalkreuth and


Introduction3-13

McMechan, 1989). This method has its limitations where nearby sections are incomplete or

unavailable, and it has to be assumed that no irregular thickness changes were present.

3.3.1.2.1 Sonic log method

The irreversible effects of burial and compaction on the physical properties (density, porosity, velocity

and resistivity changes, or maturation, etc.) of shales are used to restore and estimate the maximum

depth of burial. Plotting sonic travel time of shale intervals vs. depth (on a semi log plot) and

extrapolating the resulting (hopefully) straight line to, ∆t0, reveals the typical value of uncompacted

shale at the surface (Magara, 1976, , 1986). The extrapolated height above the present-day surface

represents the estimated amount of missing overburden or erosion (Figure 3.4).

Figure 3.4: Estimation of erosion of overburden based on extrapolation of sonic interval transit times vs. depth to an uncompacted shale value of 656µs/m (Magara, 1986) .

3.3.1.2.2 Vitrinite reflectance profile

This approach is based on earlier attempts by (Hacquebard, 1977) who used coal rank and moisture

to determine the maximum burial depth. (Connolly, 1989) has estimated erosion by extrapolating log

VRr trends to a surface value of 0.2%.

Using of vitrinite reflectance for estimation of erosion has two distinct disadvantages. First, the

extrapolation approach assumes that only the temperature associated with the maximum burial depth

has influenced the maturation. Second, vitrinite reflectance is commonly used for calibrating the basin

simulation temperature history, should not be, even indirectly, enter the input data for the simulation

(Poelchau et al., 1997).

3.3.2 Heat Flow Analysis

Paleo-temperatures are controlled by the basal heat flow history of the basin (which in turn reflects

the lithospheric mechanics), but also by internal factors such as variations in thermal conductivities,

heat generation from radioactive sources in the continental crust and within the sedimentary basin-fill,

regional water flow through aquifers, and surface temperature variations (Allen and Allen, 2005).



etemperaturinterfacewatersedimenttheiswhere

:

0:

.:

:

intint

−−=∆=∆

==∆=

swi

sid

botbotbot

swiswi

B

etemperaturfixedTTB

flowheatnoTB

etemperaturorflowheatfixedTTorQTB

etemperaturfixedTTB

λ

Radiogenic heat production is greatest where the underlying basement is granitic and where the

basin-fill contains “hot” shales. Radiogenic heat production is particularly important in deep, long-lived

basins (Allen and Allen, 2005).

Another possible source/sink of heat in the crust is exothermic/endothermic metamorphic reactions.

Reaction connected with contact metamorphosis (heat, without significant shear stress) are

endothermic (absorb heat) while those linked to dynamic metamorphism (involving intense localized

stresses, which tend to break up the rock) are exothermic (release heat) (Harker, 1932).

Petroleum system modeling simulation tools determine temperature field in the earth’s interior using

mathematical techniques such as the finite element method. Therefore, the simulation program only

needs boundary conditions (Figure 3.5). Temperature at the top, the bottom and sides of a

sedimentary basin must be established to determine the interior temperature field (Broichhausen,

2004). In the basin modeling analysis three outer boundaries are distinguished: the upper boundary

(sediment water interface) Bswi, the bottom boundary Bbot, and the basin sides Bsid. Additionally some

special inner boundary conditions Bint, (Equation 3-28).

Equation 3-28: Boundary condition formulation.

The temperature at depth (Z) computed either from a given (or assumed) geothermal gradient and

surface temperature, or from heat flow at the base of the section, thermal conductivity and surface

temperature. The first method based on the calculation of ancient geothermal gradient. The

procedure is essentially empirical and dependent upon the availability of a vitrinite reflectance-depth

(time) profile through the basin sequence.

Using the kinetic approach developed for the simulation of petroleum generation, a model for the

thermal maturation of vitrinite using an iterative techniques for a best fit (Tissot and Espitalie, 1975).

The model based on the second method consists of heat flow values specified for each geologic event

and each grid point. For paleo heat flow values the only reasonable approach is to use analogies for

the basin to be investigated with respect to the plate tectonic framework and apply crustal evolution

models to estimate the basins heat flow history (Yükler et al., 1978).

3.3.2.1 Sediment-Water Interface Temperature

Surface water temperature is a function of latitude, oceanic currents and long–term climatic changes

as well as seasonal events. Temperature at the sediment–water interface depends partly on water

depth. The sediment water interface temperatures depend on the water depth and are much smaller

in deep water. In Shallow water, a temperature decrease of 1°C in 100m is assumed (Equation 3-29).

(Wygrala, 1989) has synthesized surface temperature trend as a time-latitude diagram (Figure 3.6)

which can be quite useful for estimating values for shallow water sediments within global climatic

belts.


Introduction3-15

( )

depthwatertheis

etemperaturarctictheis

etemperaturairaveragetheis

etemperaturinterfacewatersedimenttheiswhere

600

6002003400

2003

2001003

10002

01

0

w

T

T

T

mwforTT

mwmforCTTmw

CTT

mwmforCTT

mwforCTT

mwforCTT

mwforTT

n

a

swi

nswi

anaswi

aswi

aswi

aswi

aswi

−−≥=

<<°+−−+°−=

<<°−=≤<°−=

≤°−=≤=

Figure 3.5: Boundary value problem of the heat flow analysis. Equation 3-29: Sediment water interface temperature from air-surface temperature.

The following steps are taken to determine the sediment/water interface temperature through time at

a specific location: define the present latitude; define paleo-latitude through geologic time, using

paleo-continental distribution map; determine paleo-annual mean surface temperature from map of

global paleo-temperature distribution; correct these surface temperature to sediment water interface

temperatures by taking the effects of water depth, basin type, and global ocean current patterns into

account (Equation 3-29).



Figure 3.6: Geologic age-latitude plot of average ocean surface temperature that shows the effect of climate model and latitude on variations in mean annual sea surface temperatures. The inflected lines represent the isotherms through geologic time at the corresponding latitude. The lines labeled by temperature in °C. The dotted line indicates the evolution of the SWI temperature for an example (Wygrala, 1989) .

3.3.3 Kinetics of Calibration Parameters

The systematic testing and evaluation of results is a crucial and distinctive step of all well designed

modeling studies. Graphic comparison of calculated values with the measured observations quickly

indicates whether the conceptual model matches the geologic reality. The procedures are commonly

referred to as optimization, calibration, checking, and sensitivity analysis (Hermanrud, 1993; Wygrala,

1989; Yükler, 1979). When calculated outputs are within “acceptable” error limits (which of course

must be specified) of observed values, the solution is judged as “successful” (Welte and Yükler,

1981). If the match is good, the geologic assumptions made for the conceptual model can be said to

be reasonable although not necessarily true (Poelchau et al., 1997). Optimization has logically also

been called “calibration” because the procedure involves making corrections (Poelchau et al., 1997).

Because of its substantial influence on most aspects of basin modeling, calibration of thermal history

outputs is always essential. This is usually accomplished by the comparison of calculated present-time

temperature profiles and calculated vitrinite reflectance, compared to present-day measured borehole

temperatures and observed vitrinite reflectance-values (Poelchau et al., 1997).

3.3.3.1 Temperature calibration

The most commonly used temperature parameters are present-day bottom hole temperatures (BHT)

and borehole temperature logs. BHT temperatures are corrected with respect to the circulation of

cooler drilling fluids. This is carried out by means of the “Horner plot extrapolation” when two or more

temperatures measurements during different logging runs are available from the same depth at

different times after circulation has stopped (example, Figure 3.7).


Introduction3-17

4

2

2

Re

Re

Re

Re

4

3

2

1

CHVitrinitesidualVitrinite

CHVitrinitesidualVitrinite

COVitrinitesidualVitrinite

OHVitrinitesidualVitrinite

i

i

i

i

k

n

k

k

k

+⇒

+⇒

+⇒

+⇒

VolatilesVitrinitesidualVitriniteik

+⇒Re1

Simulated present-day temperature is affected by recent heat flow, surface temperature, and by

thermal conductivity of the underlying and overlying layers (Poelchau et al., 1997).

Figure 3.7: Example of Horner Plot extrapolation method to correct BHT for cooling during drilling and circulation. The corrected steady state temperature for the formation is 79°C (Poelchau et al., 1997).

3.3.3.2 Vitrinite reflectance models

The most widely used thermal maturity indicator is the reflectance of the vitrinite macerals in coal,

coaly particles, or dispersed organic matter, which increase as a function of temperature and time

from approximately 0.25%Ro at the peat stage to more than 4.0%Ro at the meta anthracite stage.

The general reaction assumed that vitrinite transformed to residual (modified or mature) vitrinite and

some condensates.

An important application of vitrinite reflectance measurements in basin analysis is the calibration of

thermal and burial history models with present-day maturity data. For calibration, the increase in

vitrinite reflectance is simulated in the basin modeling program in accordance with the conceptual

model and the temperature history. Several “kinetic” models for vitrinite reflectance evolution have

been designed and used extensively (Poelchau et al., 1997).

3.3.3.2.1 Burnham-Sweeney (1989) model

The model has been proposed by (Burnham and Sweeney, 1989; Sweeney and Burnham, 1990),

describing the chemical changes of vitrinite by four overlapping reactions: the successive release of

water, CO2, higher hydrocarbons and methane (as shown).

3.3.3.2.2 Easy %Ro model

The increasing reflectance of vitrinite with time and temperature can be modeled as the result of a

number of parallel chemical reactions that act to eliminate water, carbon dioxide, methane and higher

hydrocarbons from the maceral (Sweeney and Burnham, 1990). A simplified, but nevertheless equally

effective model, the so called “EASY %Ro model” (Sweeney and Burnham, 1990), combines the four

reactions into one spectrum of activation energies (Equation3-30). This model has been most

successfully applied because it is applicable for maturation values as high as 4.6% vitrinite



TR

R

=20.0

66.4.20.0%0

reflectance. The result was a method known as EASY %Ro (Sweeney and Burnham, 1990). It uses a

set of twenty reactions with a common pre-exponential factor A= 1.0 x 1013 s-1, weighted factors and

activation energies (Table 3.1). The EASY %Ro breaks the thermal history of a source bed into

segments of constant heating rates.

Equation 3-30: Vitrinite reflectance estimation based on (Sweeney and Burnham, 1990).

Table 3.1: Weighted Factors and activation energies used in EASY %Ro. Reaction

number (i)

Stoichionmeteric

factor (Fi)

Activation Energy

Ei (kJ mol-1)

1 0.03 142

2 0.03 151

3 0.04 159

4 0.04 167

5 0.05 176

6 0.05 184

7 0.06 192

8 0.04 201

9 0.04 209

10 0.07 218

11 0.06 226

12 0.06 234

13 0.06 243

14 0.05 251

15 0.05 259

16 0.04 268

17 0.03 276

18 0.02 285

19 0.02 293

20 0.01 301

3.3.4 Petroleum Generation Kinetics

Generated petroleum compounds are thought to result from a multitude of quasi-irreversible,

assumed first-order thermal cracking reactions (Hanbaba and Jüntgen, 1969; Huck and Karweil, 1955;

Tissot, 1969) whose overall rate is mainly governed by the kerogen structure and the extent of

thermal stress over geologic time. Temperature is considered to be of overriding importance in

generating petroleum from organic matter, enclosed in source rocks (Philippi, 1965; Vassayovich et

al., 1969; Welte, 1965).

Kinetic models can be used in basin simulation to determine the extent of petroleum generation using

experimental data on immature samples (Burnham et al., 1987; Schaefer et al., 1990; Ungerer and

Pelet, 1987). Most importantly, it was found that reaction rates do not double for each temperature

increase of 10°C as in the Lopatin /Waples TTI mode (Waples, 1980), but rather for a 3-5°C increase

(Sweeney et al., 1987; Tissot et al., 1987). The speed of the reaction is named reaction rate, k,


Introduction3-19

/mol/K)Ws(8.314ConstantGasBoltzmann

EnergyActivation

FactorFrequency

(K) startsion ransformatat which t eTemperatur Absolute theis

)(s RateReactionwhere

exp.1-

)./(

R

E

A

T

K

AK TRE−=

DensityPetroleumAverage

PorosityAverage

MassGenerationPetroleumInitialwhere

.)1(..

p

o

po

p

x

pHITOCx

Φ

Φ−=

)()( yPetroleumxKerogenik

i ⇒

substancesfinaltheofmasses,

itypeboundthewithsubstanceinitialtheofmass

ctackingsecondarytheofratesReaction

ctackingfirsttheofratesReactionwhere

)()()(

2

1

21

zy

x

k

k

zGasyOilxKerogen

i

i

kk

i

i

→⇒

depend strongly on temperature. The rate at which a kinetically controlled reaction proceeds (ki) is a

function of the absolute temperature (T), the activation energy (Ei), the gas constant (R), and a

constant (A) given by the Arrhenius equation (Equation 3-31).

Equation 3-31: Arrhenius law.

All kerogen degradation profiles are asymptotic with respect to temperature (Pepper and Corvi, 1995).

Kinetics is dependant on the cracking type (primary or secondary), on the kerogen type (I, II or III)

and on the number and type of generated petroleum components (bulk, oil-gas, compositional

kinetics).

3.3.4.1 Bulk kinetics

Bulk kinetics focus on kerogen cracking and do not distinguish between petroleum components.

The transformation ratio of the chemical reaction represents the ratio of the cracked kerogen, which is

the main output of these models. The total generation masses are determined via two values, the

TOC (total organic carbon) content and HI (hydrogen index) (Equation 3-32).

Equation 3-32: Total mass of petroleum that generated in the source rock per total volume of the sediment.

3.3.4.2 Oil –gas kinetics

Two components phase model considered here, for the lighter and heavier hydrocarbon. Usually, C1-

C5 used for gas and C6+ and NSO is used for oil, respectively. Most of the oil-gas models also use a

secondary cracking kinetics for the oil to gas cracking, which finally yields to the following reaction

scheme and the corresponding balance for the generated and cracked masses. This equation assumes

only one sub-reaction for secondary cracking.

It is also necessary to input ratio (percentage) values to describe how the total HI value is splitted

into the HI for kerogen to oil, HIOil, and the HI for kerogen to gas, HIGas, reaction. The calculated

hydrocarbon generation potential for oil and gas used to define the main zones for oil and gas

generation. Herein, the actual potential value is compared to the maximum possible value for oil and

gas, namely HImaxoil = HIOil and HImaxgas= HIGas + r. HIOil respectively.



21;..12,1)()(

..1)()(

2211

,2,1

iiniiforyCompyComp

niforyCompxKerogen

ii

k

ii

ii

k

ij

jii

ij

>=⇒

=⇒

161214.2

112 42

+⇒

+⇒ CHCCH

gasmaxgas

gasmaxgasgasmaxgas

gasmaxgasoilmaxoil

gasmaxgasoilmaxoil

HI.0.9pot:Overmature

HI.0.9potandHI.0.1pot:GenerationGas

HI.0.1potandHI.0.1pot:GenerationOil

HI.0.1potandHI.0.1pot:Immature

>≤>

<≥<<

One popular definition of the zones is the following:

In oil to gas cracking, the reduction of organic mass due to the loss of coke, a reduction factor (total

gas to oil mass) therefore introduced in the mass balance, which is usually in the range of 0.4% to

0.7%. The following principle equation gives a reduction factor of r= 16/28= 0.57.

These equations are defined with different reactions parameters for the different kerogen types. For

kerogen types I and II, the kerogen–to-oil to gas reaction is the main process. Regarding kerogen

type III, an important part of the gas is obtained from the kerogen to gas reactions. In case of gas,

cracking from oil the organic mass is reduced. Cracking of 1g oil results in 0.4-0.7g gas (Mann et al.,

1997).

3.3.4.3 Compositional kinetics

Compositional Kinetics considers more than two hydrocarbon components. In the following equation

array for the primary and secondary cracking, the components named with (i= 1.n) and the bound

classes for the different activation energies specified with the index (j= 1..m). The reactions for

secondary cracking follow a triangle scheme where each component is cracked into lighter ones. The

maximum number of primary and secondary reactions are (n) and 1/2 n (n-1).

(Espitalie et al., 1988 b) introduced four hydrocarbon classes (C1, C2-C5, C6-C15 and C15+) to be used in

basin modeling programs. These or slightly modified classes have been used in many publications and

data bases to describe primary cracking, such as (Behar et al., 1997; Ungerer, 1990; Vandenbroucke

et al., 1999). For the secondary cracking, they proposed to consider cracking from each higher HC-

component class to methane with coke as a byproduct.

3.3.4.4 Compositional phase kinetics

The petroleum kinetics is used to describe the reactions of different hydrocarbon component classes

(for examples C1, C2-C4, C5-C6, C7-C15, C15+). Then, instead of the properties of a whole kerogen type,

only the properties of the special hydrocarbon component classes are considered. In a multiple source

rock concept, the petroleum from each different source unit is tracked or traced separately throughout

its entire migration history to ensure that the properties of mixed petroleum are determined correctly.

It is therefore possible to correlate modeled hydrocarbon loads (Figure 3.8) with individual potential

source rocks (Mann et al., 1997).


Introduction3-21

Figure 3.8: Concept of multiple source tracing (Mann et al., 1997).

3.3.4.5 Kinetics parameters and organo facies

The global kinetic model (Pepper and Corvi, 1995) considers kinetic parameters to be based on gross

depositional environment and stratigraphic age; this is useful in areas lacking of geochemical data.

It broadly relates five kerogen kinetic organo facies, each characterized by a specific organic matter

input and early diagenetic overprint, to sedimentary facies/age associations. The relatively simple five-

fold kerogen kinetic classification based on the “organo facies” concept is shown in (Figure 3.9 and

Table 3.2). An organo facies is defined as: a collection of kerogens derived from common organic

precursors, deposited under similar environmental conditions and exposed to similar early diagenetic

histories (Pepper and Corvi, 1995). From a chemical viewpoint hydrogen-rich organic matter is

considered to have the greatest potential for oil generation, whereas rocks with terrigenous organic

matter of low hydrogen content are viewed as gas prone (Littke et al., 1997). Fluvial and deltaic

sediments are among the most important source rocks for natural gas (Littke et al., 1995; Lutz et al.,

1975; Masters, 1984; Rice et al., 1989) but are also reported as source rocks for oil (Durand and

Paratte, 1983; Horsfield et al., 1988; Hvoslef et al., 1988; Khavari Khorasani, 1987; Risk and Rhodes,

1985; Shanmugam, 1985; Thomas, 1982; Thompson et al., 1985). Sulfur-rich kerogen produces a

petroleum rich in asphaltenes, i.e., an “immature oil,” at low levels of thermal maturity (Tannenbaum

and Aizenshtat, 1985).

Figure 3.9: Kerogen kinetic classification: definition of five global organo facies (Pepper and Corvi, 1995) .



Table 3.2: Results of optimization of kinetic parameters and temperature limits of the oil and gas windows for the five kerogen organo facies (compiled after (Pepper and Corvi, 1995)).

Organo facies A Emean σE Top Range Base

S-1 kJ mol-1 kJ mol-1 °C °C °C

Oil Generation Oil Generation Windows

A 2.13e13 206.4 8.2 95 40 135

B 8.14e13 215.2 8.3 105 40 145

C 2.44e14 221.4 3.9 120 20 140

DE 4.97e14 228.2 7.9 120 40 160

F 1.23e17 259.1 6.6 145 30 175

Gas Generation Gas Generation Windows

A 3.93e12 206.7 10.7 105 50 155

B 2.17e18 278.7 18.4 140 70 210

C 2.29e16 250.4 10.1 135 35 170

DE 1.88e11 206.4 7.7 175 45 220

F 1.93e16 275.0 9.9 175 45 220

Mean activation energies, governing the oil generation, increase systematically in the order A-F,

causing a corresponding increase in generation temperature. The oil generation window (OGW) is

affected by at least 10% (oil generation threshold or OGT), but no more than 90% of oil-prone

kerogen degraded to oil; and the gas generation window (GGW) at least 10% (=gas generation

threshold or GGT), but no more than 90% of gas-prone kerogen degraded to gas (Pepper and Corvi,

1995).

3.3.5 Adsorption Models

Adsorption models can estimate the amount of generated and released hydrocarbons. Un-reacted and

inert kerogen can bind the generated petroleum components by adsorption before releasing them into

the open pore space of the source. The term expulsion is used to specify the amount of petroleum

(phases) passing the source to carrier interface. This means it encompasses all the processes

petroleum molecules are undergoing within the source rock. The main processes and nomenclatures

for the petroleum migration from source to reservoir are shown in (Figure 3.10) and are considered as

a chain of discrete steps.

Figure 3.10: Adsorption and migration processes.


Introduction3-23

3.3.5.1 Flow path Modeling

The transport of the liquid and vapor petroleum phase are calculated within the permeable layers. The

modeling of petroleum migration is performed considering both, flow path and Darcy flow in an

interactive link. This kind of migration is called “Hybrid Modeling”. The corresponding flowcharts for

the simulation models are showing in (Figure 3.11). In order to enable a high-resolution 3D petroleum

migration algorithm, without excessively increasing computer processing time for the simulation run,

the “Hybrid” Darcy/Flow path migration modeling techniques can be used (Hantschel et al., 2000).

This migration method is a combination of the Darcy Flow modeling and the Ray Tracing “Flow path”

modeling methods.

Special geological factors and processes that must be included in the conceptual model for migration

modeling include: (a) fracturing and fault properties; (b) aquifer flow also plays an important role in

some basins, both as an effective heat transfer medium that can lead to severe perturbation of the

conductive temperature field, and as an additional direct force on oil and gas movements that, in

extreme cases, can flush hydrocarbons from potential trap areas (Mann et al., 1997).

Figure 3.11: Flowcharts of (a) Darcy Flow and (b) Flow path modeling.

3.3.6 PVT Analysis

The widely used fluid flow simulators work with three fluid phases: water, liquid petroleum and gas. A

(PVT) model is therefore necessary to decide which components dissolve in the different phases. The

simplest idea is to put the light hydrocarbons (C1-C5) in the gas phase (vapor) and the heavier ones

(C6+ and NSO) in the liquid phase, but that is only applicable with restrictions considerations near

surface conditions. Flash calculations have been established for subsurface temperatures and

pressures. These flash calculations provide not only phase envelopes and compositions; they also

calculate phase properties such as densities, GOR and viscosities.

3.3.7 Reservoir Characterization

The volume of the reservoir bodies is calculated together with the compaction. This is important

output information for petroleum exploration.

3.3.8 Risk and Uncertainty

Both the optimization and subsequent calibration procedures raise questions concerning the influence

that different input parameters have on simulation results. These effects evaluated through the



procedure of sensitivity analysis. This method simply involves making finite changes of input

parameters (ordinarily one at a time) for the previously optimized “successful” model followed by

recomputation of results. Sensitivity is defined as the rate of change of the resulting output with

respect to change of the input parameter (Zwach, 1995). The result of the optimization and

calibration procedure is a finalized “successful” or acceptable basin model. However, as pointed out by

(Yükler, 1987), “checking parameters should be chosen in such a way that they are independent of

the optimization parameters”. The calculated parameters are compared with measured data so that

less well-defined thermal input database and paleo-heat flow values calibrated.

Risk maybe defined as the probability of a specific or discrete outcome. There are commonly many

more possible outcomes for a particular event. The different outcomes may not have equal

probabilities and, importantly, there may be outcomes that are not recognized (Gluyas and Swarbrick,

2004). Uncertainty defined as the range within which the true value of a parameter lies. Moreover, the

degree of uncertainty will vary between parameters. In order to calculate the uncertainty, it is

necessary to estimate the uncertainty associated with the input parameters and propagate these

component uncertainties through the calculation. Uncertainty is commonly displayed as a probability

distribution, in which the x-axis is the value of a parameter and the y-axis the probability of

occurrence of that parameter (Gluyas and Swarbrick, 2004).

Mansoura UniversityResults and Discussions2015

Formation Evaluation4-1

4. RESULTS AND DISCUSSIONS

4.1 FORMATION EVALUATION

Digital log curves for the wells were provided that represent the raw INPUT for the used "Interactive

Petrophysics" (IP) log analysis software. Typical log suite included SP, caliper, deep, intermediate,

and shallow resistivity, density, neutron, sonic, gamma ray, and composite logs for the same well.

Prior to petrophysical property evaluation, in order to understand and obtain more accurate estimation

and interpretation of the well log data, utilizing the IP-software, and application of these

environmental corrections are essential. These corrections have been applied in order to predict

accurate values of total and effective porosity, types of pore fluids and saturations as well as

hydrocarbon reserves.

The litho-saturation deduced well logging parameters, resulting from application of the formation

evaluation program, in addition to its input-data (corrected wireline log datasets) are presented zone

wise in one vertical cross plot for each well. This is to evaluate the petroleum system elements of the

studied interval on the light of the petrophysical and lithological parameters achieved from the

analytical formation evaluation for each well individually.

The cross plot of the corrected log data and volume of shale analysis displays, in a number of tracks

from left to right, age, names of the examined formation, the corrected natural gamma ray, the

caliper log readings, the depth track (in meter below main sea level), the corrected induction electrical

resistivity logs (LLD, LLS, and MSFL, respectively) and the porosity tools input data (corrected density,

neutron and sonic log readings). At the extreme right hand-side of the plot, the clay volume analysis

is presented as a result of all the interactive single and/or double shale indicators through the IP

program, and Remarks track.

The litho-saturation cross plot displays in a number of tracks, the net results of the formation

evaluation of the examined interval utilizing the IP-software. At the three left-hand side tracks, the

depth scale, the examined zones (used for displaying the current zonation used in the interpretation)

and the RwAPP and RmfAPP are displayed. In the next four tracks, to the right-hand side, the water

saturations (Sw and Sxo), the porosity (total and effective), the movable oil plot, and the cutoff are

displayed. At the extreme right-hand side track of the plot, the lithofacies analysis (silt, matrix, and

total wet clay by volume) is presented associated with effective porosity curves. This lithofacies track

is accompanied by a complementary track (right-hand side of the plot), which has been used to

differentiate the studied interval into different litho-saturation zones annotated with specific letters to

be used in the subsequent processes for evaluating the hydrocarbon potentiality of the examined

interval.

The first capital letter is added to the zone annotations to indicate the name of the examined

formation. Moreover, the formation letter is followed with a letter that represents a petroleum system

element as follow: the letter “S” represents an organic rich interval (source rock), letter “P” represents

a zone attains pay parameters, letter “U and/or O” represents either an under burden or overburden

zone, while letter “C” represents a zone of seal parameters.

However, these letters are post-scripted by the number that represents the number of that zone.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Basin Modeling Procedure4-2

4.2 BASIN MODELING PROCEDURE

Basin modeling has become an important tool in the study of the burial history and thermal evolution

of sedimentary basins (Littke et al., 1994) and (Yalcin et al., 1997) and has a great potential to verify

or falsify different theories on basin subsidence. In recent years, the development of two-dimensional

integrated programs also permitted the analysis of aspects of fluid flow in sedimentary basins, in

particular of migration and accumulation of oil and gas (Zhou and Littke, 1999) and (Yahi et al.,

2001). It comprises numerical simulation of the geologic structures through time, based on physical

and chemical reactions (Welte and Yükler, 1981), (Ungerer et al., 1990) and (Burrus et al., 1996). The

thermal history of a basin controls hydrocarbon generation as well as migration and accumulation

(Ungerer et al., 1990). The basin model depends on a well-defined geologic time framework

(conceptual model). The simulation is then performed on the numerical representation of the

conceptual model (Tables 4.1-4.8). The physical sequence of layers has been converted into an

uninterrupted sequence of events with absolute ages for each event boundary (Poelchau et al., 1997).

Each stratigraphic event represents a time span during which one of the three basic geologic

processes prevailed, i.e. accumulation of a layer (deposition), non-deposition (hiatus), or uplift and

erosion (unconformity).

The goal is to achieve a reliable “chronostratigraphic” interpretation of a basin-fill, so that the

distribution and nature of sedimentary facies is modeled in terms of geologic processes operating at a

specific time. The composite time scale of (Harland et al., 1990) that includes the geologic records

from the Cambrian to the present time was used for chronostratigraphic subdivisions. Since present-

day thicknesses are those of compacted sediments, they must be corrected to reflect the actual

porosity at any geologic time, i.e. the layer must be decompacted. This is achieved by a

“Backstripping method” or by iterative forward modeling using assumptions about original porosities.

In order to model layer thickness as a function of time, it is necessary to model the change in porosity

as a function of time or, equivalently, as a function of depth.

The 1D models were established using modeling software (PetroMod® V.2011.1 SP3) developed by

IES GmbH (Aachen, Germany). The Interactive-Petrophysics software of Schlumberger was used for

borehole geophysical data processing and petrophysical evaluation of the penetrated sequence in

each well. The available data were utilized for differentiation of the logged sequence into elements of

the petroleum system as source rock, reservoir zone, and pay zone and seal rock. Wireline logs were

applied to deduce the vertical extent of source rock units. Evaluations of source rock intervals required

calibration with geochemical reports and maturity data for certain wells, in order to distinguish source

rocks from non-source rock intervals.


Basin Modeling Procedure4-3

Table 4.1: Chronostratigraphic conceptual model of the basin fill in terms of geologic processes operating at a specific time for well BM-57.

Thickness Deposition

Age Eroded Age

Top Base

Present Eroded From To From To Layer

(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology

Sediment Surface 38 38 0 0 1.8 0 0 0 SANDSTONE

Post Zeit 38 835 797 4 1.8 Sandstone (clay poor)

Zeit 835 1500 665 96 7.1 5.2 5.2 4 ANHYDRITE

South Gharib 1500 2002 502 10.7 7.1 SALT

Belayim-HF Seal 2002 2026 24 27 11.6 11.4 11.4 10.7 SHALE

Belayim-HF P 2026 2040 14 11.7 11.6 SANDSTONE

Belayim-HF 2040 2055 15 11.9 11.7 SHALE

Belayim-Fe 2055 2137 82 12.5 11.9 ANHYDRITE

Belayim-Si 2137 2157 19 13.4 12.5 SHALE&SAND

Belayim-Ba 2157 2247 90 14 13.4 Salt

Kareem-Sh 2247 2424 177 72 14.8 14.2 14.2 14 SHALE

Kareem-Ma 2424 2424 0 50 15.3 15 15 14.8 Anhydrite

Upper Rudeis-P1 2424 2456 32 193 15.9 15.6 15.6 15.3 Sandstone (typical)

Upper Rudeis-Seal 2456 2480 24 16.2 15.9 Shale (typical)

Upper Rudeis-P2 2480 2550 70 16.6 16.2 Sandstone (typical)

Upper Rudeis 2550 2565 15 16.8 16.6 Shale (typical)

Lower Rudeis 2565 2565 0 245 20 17.2 17.2 16.8 Conglomerate (quartzitic)

Nukhul 2565 2565 0 427 23 21.5 21.5 20 SANDSTONE

Abu Zinema 2565 2565 0 120 37 25 25 23 Conglomerate (quartzitic)

Samalut 2565 2565 0 90 42.1 38.6 38.6 37 Limestone (shaly)

Thebes-S 2565 2590 25 50 42.1 Limestone (organic rich - 1-2% TOC)

Thebes 2590 2661 71 56.5 50 Limestone

Esna 2661 2697 36 65 56.5 SHALE

Sudr 2697 2763 66 45 74 69.1 69.1 65 Limestone (Chalk, typical)

Duwi-S 2763 2772 9 84 74 Limestone (organic rich - 1-2% TOC)

Matulla Seal 2772 2831 59 35 87.8 86.5 86.5 84 SHALE&LIME

Matulla-P 2831 2866 36 88.5 87.8 Sandstone (typical)

Wata 2866 2866 0 100 90.4 89.5 89.5 88.5 Limestone (shaly)

Qada 2866 2866 0 94.8 90.4 SHALE

Raha Seal 2866 2907 41 96 94.8 SHALE&LIME

Raha-P 2907 2933 25 97 96 SANDSTONE

Nubia A-P1 2933 2988 55 31 145.6 99.6 99.6 97 Sandstone (typical)

Nubia A-S1 2988 3030 42 88 250 245 245 145.6 Shale (organic rich, typical)

Nubia A-P2 3030 3039 9 252 250 SANDSTONE

Nubia A-S2 3039 3056 17 254 252 Shale (organic rich, typical)

Nubia A-P3 3056 3069 13 255 254 SANDSTONE

Nubia A-S3 3069 3129 60 259 255 Shale (organic rich, typical)

Nubia A-P4 3129 3144 16 260.4 259 SANDSTONE

Nubia B-P 3144 3185 40 17 312 299 299 260.4 Sandstone (clay poor)

Nubia B-S 3185 3262 76 336.3 312 Shale (organic rich, typical)



Nubia C-P 3262 3547 286 88 445 443.7 443.7 336.3 SANDSTONE

Nubia C 3547 3600 53 486 445 SHALE&SAND

Nubia D 3600 3600 0 60 570 488.3 SANDSTONE

Basement 3600 4600 1000 200 620 580 580 570 Granite (500 Ma old)

620

Thebes-S, Source rock interval with 2.71 wt% TOC, HI is 409 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Duwi-S, Source rock interval with 4.02 wt% TOC, HI is 557 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Nubia A-S1, Source rock interval with 0.6 wt% TOC, HI is 265 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia A-S2, Source rock interval with 0.69 wt% TOC, HI is 244 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia A-S3, Source rock interval with 1.03 wt% TOC, HI is 167 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia B-S, Source rock interval with 2.62 wt% TOC, HI is 268 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)).



Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology


Post Zeit 34 1067 1033 4 1.8 SANDSTONE

Zeit 1067 1899 832 138 7.1 5.2 5.2 4 ANHYDRITE


Belayim-HF 2362 2426 64 40 11.9 11.4 11.4 10.7 SHALE&SAND



Belayim-Ba 2516 2592 76 14 13.4 Salt

Kareem-Sh 2592 2792 200 51 14.8 14.2 14.2 14 Shale (typical)


Upper Rudeis Shale1 2792 2984 192 18 16 15.6 15.6 15.3 Shale (typical)

Upper Rudeis-P 2984 3003 19 16.2 16 Sandstone (typical)

Upper Rudeis Shale2 3003 3263 260 16.8 16.2 Shale (typical)





Thebes-S1 3263 3340 77 51 42.1 Limestone (organic rich - 1-2% TOC)

Thebes-P 3340 3346 6 51.8 51 LIMESTONE

Thebes-S2 3346 3387 41 56.5 51.8 Limestone (organic rich - 1-2% TOC)

Esna 3387 3387 0 40 65 56.5 SHALE


Duwi 3387 3387 0 84 74 Limestone (organic rich - 1-2% TOC)

Matulla 3387 3474 86 43 88.5 86.5 86.5 84 SAND&SHALE


Qada 3556 3556 0 15 94.8 90.4 SHALE

Raha 3556 3615 59 35 97 94.8 SHALE&LIME

Nubia A Shale 3615 3679 64 26 145.6 99.6 99.6 97 SHALE sand

Nubia A 3679 3679 0 246 260.4 245 245 145.6 Sandstone (clay rich)

Nubia B 3679 3679 0 56 306 299 299 260.4 Sandstone (clay rich)

Nubia B Shale 3679 3679 0 107 336.3 306 Shale (organic rich, typical)



Nubia C 3679 3679 0 426 488.3 443.7 443.7 336.3 SANDSTONE



620

Thebes-S1, Source rock interval with 1.96 wt% TOC, HI is 358 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Thebes-S2, Source rock interval with 1.8 wt% TOC, HI is 396 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)).



Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology



Zeit 916 1600 684 96 7.1 5.2 5.2 4 SHALE&SAND


Belayim-HF 2078 2120 42 27 11.9 11.4 11.4 10.7 SANDshaly



Belayim-Ba 2166 2209 44 14 13.4 ANHYDRITE

Kareem-Sh 2209 2439 230 72 14.8 14.2 14.2 14 SHALE


Upper Rudeis-Seal1 2439 2475 36 29 15.8 15.6 15.6 15.3 SHALE

Upper Rudeis-P1 2475 2489 14 16 15.8 Sandstone (clay poor)

Upper Rudeis-Seal2 2489 2556 67 65 16.8 16.3 16.3 16 SHALE

Upper Rudeis-P2 2556 2621 65 53 17.1 17 17 16.8 Sandstone (clay poor)






Thebes 2640 2740 100 56.5 48 Limestone (shaly)

Esna 2740 2789 50 4 65 56.5 SHALE&LIME


Duwi 2816 2816 0 75 84 80 80 74 Limestone (organic rich - 1-2% TOC)

Matulla 2816 2846 30 35 87 86.5 86.5 84 SANDshaly

Matulla-P 2846 2894 48 88.5 87 SANDSTONE

Wata-P 2894 2909 15 85 90.4 89.5 89.5 88.5 Limestone (shaly)

Qada 2909 2909 0 50 94.8 90.4 SHALE

Raha 2909 2909 0 65 97 94.8 Sandstone (clay rich)

Nubia A-P 2909 2931 22 31 145.6 99.6 99.6 97 SANDSTONE

Nubia A-S 2931 3094 164 88 260.4 245 245 145.6 Shale (organic lean, sandy)

Nubia B Sandstone 3094 3130 36 17 306 299 299 260.4 Sandstone (clay rich)

Nubia B- S 3130 3223 93 27 336.3 306 Shale (organic rich, typical)






620

Thebes-S, Source rock interval with 1.8 wt% TOC, HI is 396 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Nubia A-S, Source rock interval with 1.03 wt% TOC, HI is 167 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia B-S, Source rock interval with 2.32 wt% TOC, HI is 211 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)).



Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology

Sediment Surface 37 37 0 0 1.8 0 0 0 Sandstone (typical)


Zeit 840 1626 786 30 7.1 5.2 5.2 4 SAND&SHALE




Belayim-Si 2510 2530 20 13.4 12.5 SHALE

Belayim-Ba 2530 2667 137 14 13.4 SALT

Kareem-Sh 2667 2811 144 80 14.8 14.2 14.2 14 SHALE


Upper Rudeis 2811 2900 89 126 16.8 15.6 15.6 15.3 SAND&SHALE

Lower Rudeis 2900 3030 130 115 20 17.2 17.2 16.8 LIMEshaly






Esna 3101 3124 23 65 56.5 SHALE


Duwi 3124 3124 0 40 84 74 Limestone (organic rich - 1-2% TOC)



Qada 3124 3124 0 30 94.8 90.4 SHALE

Raha 3124 3124 0 100 97 94.8 SAND&LIME

Nubia A Sandstone 3124 3164 40 1 145.6 99.6 99.6 97 Sandstone (clay rich)

Nubia A-S 3164 3268 104 186 260.4 245 245 145.6 Shale (organic lean, sandy)


Nubia B-S 3297 3342 45 62 336.3 306 Shale (organic lean, sandy)




620

Thebes-S, Source rock interval with 1.8 wt% TOC, HI is 396 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Nubia A-S, Source rock interval with 0.69 wt% TOC, HI is 244 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia B-S, Source rock interval with 2.1 wt% TOC, HI is 78 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)).





Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology

Sediment Surface 37 37 0 1.8 0 Sandstone (typical)


Zeit 809 1446 637 152 7.1 5.2 5.2 4 Sandstone (clay rich)


Belayim-HF 1978 2011 33 85 11.9 11.4 11.4 10.7 Sandstone (clay poor)



Belayim-Ba 2097 2183 86 14 13.4 SALT

Kareem-Sh 2183 2373 190 40 14.8 14.2 14.2 14 Shale (typical)


Upper Rudeis-Seal 2373 2410 37 253 15.8 15.6 15.6 15.3 Shale (typical)

Upper Rudeis-P 2410 2466 56 16 15.8 SANDSTONE

Upper Rudeis Shale 2466 2572 107 16.2 16 SHALE sand

Upper Rudeis Limestone 2572 2590 18 16.8 16.2 Limestone (Chalk, typical)





Thebes 2590 2590 0 260 56.5 42.1 Limestone (organic rich - 1-2% TOC)

Esna 2590 2590 0 50 65 56.5 Shale (organic rich, typical)


Duwi 2590 2590 0 60 84 74 Limestone (organic rich - 1-2% TOC)

Matulla 2590 2682 91 49 88.5 86.5 86.5 84 Sandstone (clay rich)

Wata 2682 2746 65 7 90.1 89.5 89.5 88.5 SHALE&LIME

Wata-P 2746 2754 8 90.2 90.1 SANDSTONE

Wata-Limestone 2754 2775 20 90.4 90.2 Limestone (shaly)

Qada 2775 2775 0 94.8 90.4 SHALE

Raha 2775 2834 60 46 97 94.8 Limestone (shaly)

Nubia A-P1 2834 2875 40 14 106 99.6 99.6 97 Sandstone (typical)

Nubia A Shale1 2875 2916 41 110 106 SHALE

Nubia A-P2 2916 2923 8 119 110 Sandstone (typical)

Nubia A Shale2 2923 2983 59 124 119 SHALE

Nubia A-P3 2983 3005 22 145.6 124 Sandstone (typical)

Nubia A 3005 3005 0 59 260.4 245 245 145.6 SHALE

Nubia B 3005 3018 13 78 303 299 299 260.4 Sandstone (clay rich)

Nubia B-S1 3018 3024 6 305 303 Shale (organic rich, typical)

Nubia B Sandstone 3024 3036 12 310 305 Sandstone (clay rich)

Nubia B-S2 3036 3094 58 336.3 310 Shale (organic rich, typical)






620

Nubia B-S1, Source rock interval with 1.33 wt% TOC, HI is 281 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia B-S2, Source rock interval with 2.32 wt% TOC, HI is 211 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)).



Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology


Post Zeit 35 1033 998 4 1.8 Sandstone (typical)


South Gharib 1711 2197 486 10.7 7.1 Salt

Belayim-HF 2197 2231 34 27 11.9 11.4 11.4 10.7 SHALE sand


Belayim-Si 2328 2360 32 13.4 12.5 Sandstone (clay rich)

Belayim-Ba 2360 2503 143 14 13.4 SALT

Kareem-Sh 2503 2686 182 72 14.8 14.2 14.2 14 SHALE


Upper Rudeis-Seal1 2686 2766 80 105 15.8 15.6 15.6 15.3 Shale (typical)

Upper Rudeis-P1 2766 2771 5 15.9 15.8 Sandstone (typical)

Upper Rudeis-Seal2 2771 2810 39 16 15.9 Shale (typical)

Upper Rudeis-P2 2810 2818 8 44 16.3 16.1 16.1 16 Sandstone (typical)

Upper Rudeis 2818 2859 41 16.8 16.3 Shale (typical)

Lowe Rudeis 2859 2859 0 245 20 17.2 17.2 16.8 Conglomerate (quartzitic)






Esna 2995 3013 18 65 56.5 Shale (organic lean, typical)



Matulla-Seal 3085 3176 91 10 87 86.5 86.5 84 SHALE sand

Matulla-P 3176 3191 15 87.5 87 SANDSTONE

Matulla 3191 3210 18 88.5 88 SHALE sand


Qada 3311 3311 0 15 94.8 90.4 SHALE

Raha 3311 3417 106 97 94.8 Sandstone (clay rich)

Nubia A Sandstone 3417 3562 146 40 145.6 99.6 99.6 97 Sandstone (clay poor)

Nubia A Shale 3562 3642 80 88 260.4 245 245 145.6 Shale (organic lean, sandy)


Nubia B Shale 3722 3806 84 336.3 306 Shale (organic lean, typical)






620

Thebes-S, Source rock interval with 1.8 wt% TOC, HI is 396 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Duwi-S, Source rock interval with 2.75 wt% TOC, HI is 458 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)).

Table 4.7: Chronostratigraphic conceptual model of the basin fill in terms of geologic processes operating at a specific time for well 113-M-27.


Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology


Post Zeit 18 1146 1128 4 1.8 Sandstone (clay rich)

Zeit 1146 1896 750 36 7.1 5.2 5.2 4 SAND&SHALE





Belayim-Ba 2603 2710 107 14 13.4 Salt

Kareem-Sh 2710 2929 219 79 14.8 14.2 14.2 14 SHALE


Upper Rudeis 2929 3331 402 69 16.8 15.6 15.6 15.3 SAND&SHALE





Thebes-S 3331 3568 237 53 56.5 42.1 Limestone (organic rich - 1-2% TOC)

Esna 3568 3572 4 36 65 56.5 SHALE





Qada 3803 3803 0 15 94.8 90.4 SHALE

Raha 3803 3907 104 2 97 94.8 SAND&LIME

Nubia A Sandstone1 3907 3933 26 57 145.6 99.6 99.6 97 Sandstone (clay rich)

Nubia A-S 3933 3978 45 57 252 245 245 145.6 Shale (organic rich, typical)

Nubia A Sandstone2 3978 4002 24 35 260.4 255 255 252 Sandstone (clay poor)

Nubia B-S 4002 4088 86 46 312 299 299 260.4 Shale (organic rich, typical)

Nubia B Sandstone 4088 4121 33 336.3 312 Sandstone (clay rich)

Nubia C 4121 4181 60 230 488.3 443.7 443.7 336.3 Sandstone (clay rich)



620

Thebes-S, Source rock interval with 1.8 wt% TOC, HI is 396 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Duwi-S, Source rock interval with 2.75 wt% TOC, HI is 458 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)). Nubia A-S, Source rock interval with 0.7 wt% TOC, HI is 244 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)). Nubia B-S, Source rock interval with 1.4 wt% TOC, HI is 116 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII (B)).



Table 4.8: Chronostratigraphic conceptual model of the basin fill in terms of geologic processes operating at a specific time for well 113-M-34.


Age Eroded Age

Top Base


(m) (m) (m) (m) (Ma) (Ma) (Ma) (Ma)

Lithology





Belayim-HF 2404 2466 62 56 11.9 11.4 11.4 10.7 Sandstone (clay rich)


Belayim-Si 2567 2592 26 13.4 12.5 SHALE sand

Belayim-Ba 2592 2698 105 14 13.4 SALT

Kareem-Sh 2698 2919 221 120 14.8 14.2 14.2 14 Sandstone (clay rich)


Upper Rudeis 2919 3175 256 74 16.8 15.6 15.6 15.3 Sandstone (clay rich)

Lower Rudeis 3175 3175 0 245 20 17.2 17.2 16.8 Conglomerate (typical)




Thebes-S 3175 3219 44 189 56.5 42.1 Limestone (shaly)

Esna 3219 3244 25 65 56.5 Shale (typical)



Matulla 3353 3472 119 20 88.5 86.5 86.5 84 Sandstone (clay rich)


Qada 3559 3559 0 15 94.8 90.4 SHALE

Raha 3559 3657 98 97 94.8 SAND&LIME

Nubia A Sandstone1 3657 3701 44 39 145.6 99.6 99.6 97 Sandstone (clay rich)

Nubia A Shale 3701 3820 119 15 252 245 245 145.6 Shale (organic lean, typical)

Nubia A Sandstone2 3820 3842 22 25 260.4 255 255 252 Sandstone (clay poor)

Nubia B Shale1 3842 3860 18 22 312 299 299 260.4 Shale (organic lean, typical)

Nubia B Sandstone 3860 3887 27 320 312 Sandstone (clay rich)

Nubia B Shale2 3887 4007 120 336.3 320 Shale (organic lean, typical)

Nubia C 4007 4160 153 107 488.3 443.7 443.7 336.3 Sandstone (clay rich)

Nubia-D 4160 4160 0 60 570 488.3 SANDSTONE


620

Duwi-S, Source rock interval with 2.75 wt% TOC, HI is 458 mgHC/g TOC, Kinetics (Pepper&Corvi (1995) _TII-S (A)).

The backbone of basin modeling is the reconstruction of paleo-temperature and its spatial variation in

the basin. Basin simulation tools determine temperature fields using the finite element method.

Therefore, the simulation program needs boundary conditions. Temperature at the top, the bottom

and sides of a sedimentary basin must be established to determine the interior temperature field

(Broichhausen, 2004) and (Broichhausen et al., 2005). Temperature is calculated from basal heat flow



values specified for each geologic event, thermal conductivity (Table 4.9) and surface temperature

(Yalcin et al., 1997). The thermal boundary conditions are the sediment-water interface temperature

at the top of the model and the paleo-heat flow at the bottom (Tables 4.10-4.17). Temperatures at

the sediment– water interface depend on water depth and paleolatitude. (Wygrala, 1989) has

synthesized surface temperature trends as a time-latitude diagram, which is useful for estimating

values for shallow water sediments within global climatic belts. For paleo heat flow values the most

reasonable initial approach consists of using the known plate tectonic framework and analogies of the

basin to be modeled and crustal evolution models (see (Allen and Allen, 1990)).

The calculation of vitrinite reflectance from temperature histories was carried out using the EASY%Ro

algorithm of (Sweeney and Burnham, 1990) which is based on reaction kinetic results that allow the

calculation of vitrinite reflectance values between 0.3 and 4.5 %Ro. The thermal modeling procedures

include the reconstruction of the present-time temperature regime and the temperature history

evaluation. Bottom-hole temperatures (BHTs) were used to calculate the present-day temperature

(Figure 4.1). Deficiencies in the database must be recognized. Normally, more than one interpretation

fits the observable data. The calculated parameters are compared with measured data so that the

thermal model can be calibrated (Figure 4.2-4.5). If necessary, the conceptual model is adjusted or

modified to lead to a better match between simulation results and calibration data.



Table 4.9: Summary of some established characteristic parameters of lithostratigraphic unit in Belayim Marine Oil Field used for modeling.

Lithology Radiogenic Heat Mechanical

Compaction

Thermal

Conductivity

Heat

Capacity

Name U Th K40 Density IP MP 20°C 100°C 20°C 100°C

ppm ppm % Kg m-3 Untiless W m-1 K-1 Kcal kg-1 K-1

Sandstone (typical)* 1.3 3.5 1.3 2720 0.41 0.01 3.95 3.38 0.204 0.236

Sandstone (clay rich)* 1.5 5.1 3.6 2760 0.4 0.01 3.35 2.95 0.206 0.238

Sandstone (clay poor)* 0.7 2.3 0.6 2700 0.42 0.01 5.95 4.85 0.196 0.226

Sandstone (quartzite, typical)* 0.6 1.8 0.9 2640 0.42 0.01 6.15 5 0.213 0.246

Sandstone (subarkose, dolomite rich)* 0.9 2.7 0.9 2710 0.4 0.01 4.1 3.49 0.201 0.232

Sandstone (arkose, clay poor)* 2 7 1 2710 0.39 0.01 4 3.42 0.2 0.231

Shale (typical)* 3.7 12 2.7 2700 0.7 0.01 1.64 1.69 0.206 0.238

Shale (organic lean, typical)* 3.7 12 2.7 2700 0.7 0.01 1.7 1.74 0.206 0.238

Shale (organic lean, sandy)* 2.8 11 2.5 2700 0.65 0.01 1.84 1.84 0.206 0.238

Shale (organic lean, silty)* 3 11 2.6 2700 0.67 0.01 1.77 1.79 0.206 0.238

Shale (organic lean, siliceous, typical)* 2 4.5 2 2710 0.7 0.01 1.9 1.88 0.206 0.238

Shale (black) 19 11 2.5 2500 0.7 0.01 0.9 1.15 0.225 0.26

Shale (organic rich, typical)* 5 12 2.8 2600 0.7 0.01 1.25 1.41 0.215 0.248

Shale (organic rich, 3% TOC)* 5 12 2.8 2610 0.7 0.01 1.45 1.55 0.21 0.243

Shale (organic rich, 8% TOC)* 10 11 2.9 2500 0.7 0.01 1.2 1.37 0.215 0.248

Siltstone (organic lean)* 2 5 1 2720 0.55 0.01 2.05 1.99 0.217 0.251

Siltstone (organic rich, typical) 2 5 1 2710 0.55 0.01 2.01 1.96 0.225 0.26

Conglomerate (typical) 1.5 4 2 2700 0.3 0.01 2.3 2.18 0.196 0.226

Anhydrite* 0.1 0.3 0.4 2970 0.01 0.01 6.3 5.11 0.179 0.207

Chert 1 1 0.7 2650 0.45 0.01 4.8 4.01 0.213 0.246

Gypsum 0.08 0.2 0.3 2320 0.01 0.01 1.5 1.59 0.263 0.304

Halite 0.02 0.01 0.1 2200 0.01 0.01 6.5 5.25 0.206 0.238

Chalk (typical) 1.9 1.4 0.25 2680 0.7 0.01 2.9 2.62 0.203 0.234

Coal (pure) 1.5 3 0.55 1600 0.76 0.01 0.3 0.71 0.311 0.359

Kerogen 100 0 0 1100 0.76 0.01 1 1.22 0.002 0.002

Limestone (ooid grainstone)* 1 1 0.2 2740 0.35 0.01 3 2.69 0.2 0.231

Limestone (shaly)* 2 4 1 2730 0.48 0.01 2.3 2.18 0.203 0.234

Limestone (organic rich - typical) 5 1.5 0.26 2680 0.51 0.01 2 1.96 0.202 0.233

Limestone (organic rich - 1-2% TOC)* 2.5 1.7 0.27 2710 0.51 0.01 2.63 2.42 0.201 0.232

Limestone (Chalk, 95% calcite)* 1.9 1.4 0.25 2680 0.7 0.01 2.9 2.62 0.198 0.229

Limestone (Chalk, 75% calcite)* 1.9 1.4 0.25 2680 0.67 0.01 2.65 2.43 0.201 0.232

Marl 2.5 5 2 2700 0.5 0.01 2 1.96 0.203 0.234

Dolomite (typical)* 0.8 0.6 0.4 2790 0.35 0.01 4.2 3.57 0.206 0.238

Basalt (normal) 0.9 2.7 0.8 2870 0.01 0.01 1.8 1.81 0.191 0.221

Gabbro 0.25 0.8 0.5 2870 0.01 0.01 2.6 2.4 0.191 0.221

Granite (150 Ma old) 6.5 17 5.7 2650 0.01 0.01 2.6 2.4 0.191 0.221

Granite (500 Ma old)* 4.5 15 4.5 2650 0.01 0.01 2.6 2.4 0.191 0.221

Granite (> 1000 Ma old) 4 13.5 3.5 2650 0.01 0.01 2.6 2.4 0.191 0.221

Granodiorite 2.3 9.3 2.8 2720 0.03 0.03 2.6 2.4 0.174 0.201

Gneiss 2.1 9.7 2.2 2740 0.01 0.01 2.9 2.62 0.22 0.254



*Actual used lithologies for the used model. IP: Initial Porosity. MP: Minimum Porosity.

Table 4.10: The thermal boundary conditions for well BM-57 including the sediment-water interface temperature at the top of the model and the paleo-heat flow at the bottom. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values are specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).

Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 38 0 19.66 0 64 86.5 70

3 5 3 19.87 4 60 87.5 62

6.1 5 6.1 20.12 5.2 65 88.5 62

8.9 10 8.9 20.41 8 60 89.5 67

11.65 15 11.65 20.74 10.7 63 93.2 62

12.3 15 12.3 20.84 11.4 67 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 65 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 77 253 62

18.6 150 18.6 19.77 15 95 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 125 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 60

90 15 90 29 21.5 70 620 60

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 115

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69

SWIT: Sediment-water interface temperature HF: Heat flow




Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 34 0 19.66 0 62 86.5 70

3 5 3 19.87 4 57 87.5 62

6.1 5 6.1 20.12 5.2 65 88.5 62

8.9 10 8.9 20.41 8 58 89.5 67

11.65 15 11.65 20.74 10.7 63 93.2 62

12.3 15 12.3 20.84 11.4 67 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 77 253 62

18.6 150 18.6 19.77 15 95 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 125 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 115

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69





Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 34 0 19.66 0 54 86.5 70

3 5 3 19.87 4 55 87.5 62

6.1 5 6.1 20.12 5.2 65 88.5 62

8.9 10 8.9 20.41 8 58 89.5 67

11.65 15 11.65 20.74 10.7 63 93.2 62

12.3 15 12.3 20.84 11.4 67 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 77 253 62

18.6 150 18.6 19.77 15 95 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 120 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 115

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69





Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 38 0 19.66 0 61 86.5 70

3 5 3 19.87 4 58 87.5 62

6.1 5 6.1 20.12 5.2 65 88.5 62

8.9 10 8.9 20.41 8 58 89.5 67

11.65 15 11.65 20.74 10.7 63 93.2 62

12.3 15 12.3 20.84 11.4 67 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 77 253 62

18.6 150 18.6 19.77 15 95 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 125 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 118

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69





Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 37 0 19.66 0 52 86.5 70

3 5 3 19.87 4 70 87.5 62

6.1 5 6.1 20.12 5.2 75 88.5 62

8.9 10 8.9 20.41 8 62 89.5 67

11.65 15 11.65 20.74 10.7 67 93.2 62

12.3 15 12.3 20.84 11.4 72 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 80 253 62

18.6 150 18.6 19.77 15 100 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 120 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 115

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69





Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 35 0 19.66 0 59 86.5 70

3 5 3 19.87 4 70 87.5 62

6.1 5 6.1 20.12 5.2 75 88.5 62

8.9 10 8.9 20.41 8 62 89.5 67

11.65 15 11.65 20.74 10.7 67 93.2 62

12.3 15 12.3 20.84 11.4 72 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 80 253 62

18.6 150 18.6 19.77 15 100 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 120 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 110

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69




Table 4.16: The thermal boundary conditions for well 113-M-27 including the sediment-water interface temperature at the top of the model and the paleo-heat flow at the bottom. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values are specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).

Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 18 0 19.66 0 54 86.5 70

3 5 3 19.87 4 70 87.5 62

6.1 5 6.1 20.12 5.2 75 88.5 62

8.9 10 8.9 20.41 8 62 89.5 67

11.65 15 11.65 20.74 10.7 67 93.2 62

12.3 15 12.3 20.84 11.4 72 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 80 253 62

18.6 150 18.6 19.77 15 100 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 120 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 115

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69




Table 4.17: The thermal boundary conditions for well 113-M-34 including the sediment-water interface temperature at the top of the model and the paleo-heat flow at the bottom. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values are specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).

Age

(Ma)

PWD

(m)

Age

(Ma)

SWIT

(°C)

Age

(Ma)

HF

(mW/m2)

Age

(Ma)

HF

(mW/m2)

0 14 0 19.66 0 60 86.5 70

3 5 3 19.87 4 70 87.5 62

6.1 5 6.1 20.12 5.2 75 88.5 62

8.9 10 8.9 20.41 8 62 89.5 67

11.65 15 11.65 20.74 10.7 67 93.2 62

12.3 15 12.3 20.84 11.4 72 97 72

12.95 20 12.95 20.99 12.7 62 99.6 75

13.7 10 13.7 21.05 14 69 122.6 62

14.5 60 14.5 20.19 14.2 75 145.6 72

15.15 17 15.15 21.32 14.5 62 245 75

16.2 60 16.2 20.41 14.8 80 253 62

18.6 150 18.6 19.77 15 100 260.4 72

22.25 10 22.25 22.15 15.15 62 299 75

31 10 31 23.24 15.3 72 317.6 62

40.35 30 40.35 24.08 15.6 77 336.3 72

49.3 150 49.3 23.69 16.2 62 443.7 75

61 180 61 24.66 16.8 100 505 62

71.6 300 71.6 22.89 17.2 120 570 85

79 20 79 28.59 18.6 62 580 90

87.5 15 87.5 29 20 69 600 62

90 15 90 29 21.5 70 620 62

92.6 50 92.6 29 22.25 62

96 50 96 29 23 100

122.6 0 122.6 30 25 115

253 0 253 26.48 31 62

303.5 0 303.5 23.94 37 69

309.5 30 309.5 24 38.6 70

324 0 324 25 49.3 62

465 5 465 22.81 65 70

529 2 529 22.81 69.1 75

600 0 600 23.81 76.5 62

620 0 620 23.81 84 69




Figure 4.1: The sediment-water interface temperature at the top of the model and the paleo-heat flow at the bottom. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values are specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).

Figure 4.2: Plot of paleotemperature calibrated with measured corrected static bottom hole temperature in a reference wells (BM-57 and BM-70) against depth. The cross-plot of observed and computed reflectance shows a good fit.


Geohistory4-23

Figure 4.5: Plot of paleotemperature calibrated with measured corrected static bottom hole temperature in a reference wells (113-M-27 and 113-M-34) against depth. The cross-plot of observed and computed reflectance shows a good fit.

4.3 GEOHISTORY

4.3.1 Burial history

The burial history of the Belayim Marin Oil Field is represented by time-depth history plots (Figures

4.6-4.13) that show the burial of different horizons traced through time, from deposition to present

day. The model of the unconformity surface is considered as a period of deposition and erosion.

Sediments were deposited continuously until a period of uplift occurred. This uplift was followed by

renewed subsidence until a depositional hiatus was reached. The hiatus persisted until subsidence

commenced again with deposition of sediments. The rapid deposition contrasts with slow subsidence.

Figures (4.15-4.22) show the tectonic subsidence of the studied wells, normalized from the start of

the burial. The sediment and water load above the horizon of interest in a sedimentary basin causes

isostatic effects so that the total subsidence is made up of a tectonic driving force component (due to

extensional forces acting on the lithosphere), thermal effects (due to changes in the lithosphere heat

flow), and the response of the lithosphere due to the load of sediment.

Rapid early subsidence created coarse, non-marine, alluvial and fluvial sediments during the Oligocene

and Miocene rifting phases. Continued rifting and associated subsidence eventually led to inundation

of the basin by the sea. Later stages are characterized by a marine transgression and progressively

finer-grained and deeper-water marine sediments, as the subsidence exceed the sediments supply.

The basin contains rift to post-rift mega-sequences with duration of 2 Ma for Oligocene and ~0.4 Ma

for Miocene rifting phases, with Syn-rift tectonic subsidence and exponentially decreasing post-rift

tectonic subsidence due to thermal relaxation.


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Geohistory4-24

4.3.2 Thermal history

The second aspect of the basin model is the temperature. The subsurface temperature was specified

for every layer throughout the geologic past. The thermal history of rocks in a basin is determined by

the boundary conditions of surface temperature and the basement heat flow (Figures 4.15-4.22). The

temperature at points in between is controlled by the thermal conductivities of the sediments (Table

4.9). The boundary conditions of surface temperature and basement heat flow vary through time

during the evolution of a sedimentary basin (Tables 4.10-4.17). There has been progressive decay of

the thermal pulse associated with continental rifting, especially over the past 50 Mabp (Figures 4.15-

4.22).

Figure 4.6: The boundary conditions assessments for well BM-57 including the paleo water depth at the top, the sediment-water interface temperature at middle (top of the model) and the paleo-heat flow at the bottom must be established to determine the interior temperature field. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values were specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).



Geohistory4-25




Geohistory4-27

Figure 4.12: The boundary conditions assessments for well 113-M-27 including the paleo water depth at the top, the sediment-water interface temperature at middle (top of the model) and the paleo-heat flow at the bottom must be established to determine the interior temperature field. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values were specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).

Figure 4.13: The boundary conditions assessments for well 113-M-34 including the paleo water depth at the top, the sediment-water interface temperature at middle (top of the model) and the paleo-heat flow at the bottom must be established to determine the interior temperature field. Sediment–water interface temperature depends on water depth and paleolatitude, synthesized after (Wygrala, 1989). The basal heat flow values were specified for each geologic event using the known plate tectonic framework and crustal evolution models (Allen and Allen, 1990).

During the burial of the sediments, their thermal conductivities have altered as the rock compacted.

The boundary conditions have also changed. Because the Gulf of Suez basin was created by stretching

and thinning of the continental lithosphere, both tectonic and thermally induced forces acted in

concert. The subsidence creates space for early syn-rift sediments to be deposited (Nukhul, Rudeis



and Kareem formations). Because the lithosphere thinned and the base of the lithosphere, the heat

flow through the crust and mantle were higher than they were prior to stretching. A high heat flow

peak has been assumed in the model provide the high temperatures in the Miocene. During the

Miocene rifting phase which reached a maximum value of 125 mW/m2, whereas that for the Oligocene

rifting phase is set at maximum of 118 mW/m2.

The response when the stretching stopped was a reduction in the heat flow as the lithosphere cooled

and returned eventually to its original thickness. Stretching of the continental lithosphere produced a

rapid subsidence followed by an exponentially decreasing post-rift subsidence due to thermal

relaxation. Subsidence in sedimentary basins causes thermal maturation in the progressively buried

sedimentary layers. The cooling includes contraction and further subsidence creates more space for

the post-rift sediment to be deposited. The Miocene rifting phase has a background heat flow values

of 60 mW/m2, where Oligocene rifting cooled down to average 60 mW/m2.

The thermal modeling procedures include the reconstruction of the present-time temperature regime

and the temperature history evaluation (Figures 4.16-4.22). Bottom-Hole Temperatures (BHTs) were

used to estimate the present day temperature of the control wells addressed throughout the research

(Figures 4.2-4.5). The temperature of a volume of rock is a function of heat flow and the conductivity

of a rocks and fluids. In sedimentary basin there is the background heat flux from the underlying

basement, and granitic rocks have higher heat production and temperatures than basic rocks. When

there are rocks with low thermal conductivity (Belayim and Kareem formations) near the surface the

geothermal gradient will be higher so that the underlying sediments will be warmer. This is called a

Blanketing Effect. Salt of South Gharib Formation with high thermal conductivity has a low

temperature gradient and the temperature will be relatively high at the top of the salt (Zeit Formation)

and low at the bottom (Belayim and Kareem formations). This has a consequences for maturation of

under laying organic-rich intervals.

4.3.2.1 Basement

The main heat flow decline results from the decay of a sub-lithosphere transient thermal perturbation

associated with tectongenesis of granite. The age of the granite is ~620 Mabp (i.e. only 110 Ma prior

to onset of sedimentation) with a modeled basal heat flow of 60 mW/m2. Thus, the majority of the

cooling proposed in the model took place prior to the sedimentation of the Paleozoic sediments.

Therefore, most subsidence resulting form this cooling took place early, which explains the regular

subsidence of the Paleozoic sediments, over granite (Figures 4.16-4.22).

4.3.2.2 Present heat flow

The present heat flow ranges from 52-64 mW/m2, with the higher values occurring in BM-57 well.

Areas of present heat flow maxima are generally coincident with distribution of basement relief and/or

high conductivity basement. Heat flow ranges from 52 to 64 mW/m2, with higher values occurring at

BM-57 with thick highly thermal conductive basin-fill sediment, i.e. South Gharib Formation, whereas

the lower values modeled for the BM-24 well are associated with thick lower thermal conductive

basin-fill sediment, i.e. Post South Gharib Formation. The higher heat flow is explained by uplift

followed by erosion, which provides an additional 1-17 mW/m2 above background of 52-64 mW/m2.

Heat is refracted away from regions of thick sediment cover and preferentially channeled through


Thermal Maturity and Hydrocarbon Generation4-29

areas of elevated basement. An additional 15 mW/m2 may be produced by conductivity contrasts in

basement. The paleo-heat flow values are shown in (Tables 4.10-4.17 and Figures 4.6-4.13) which

results in a valid paleo-temperature model. High sedimentation rate can also affect the temperature

field due to the low heat conductivity of highly porous sediments.

4.3.2.3 Uplifting

Erosion results in an upward movement of rocks in relation to a reference point on the surface.

Therefore, erosion increases the observed heat flow. Surface heat flow increases by an amount

dependent upon the elapsed time and rate of erosion (Figures 4.16-4.22). Uplift events cause

unconformities that cut down variably into the rocks. The paleo-temperature profile suggests that

heating in the Gulf of Suez basin was caused primarily by burial and thermal rather than by local

magmatic or fluid flow effects.

4.3.2.4 Subsidence

The heat flow is only constant in an equilibrium situation. When sediments subside they are heated

and apart of the background heat flux is used to heat subsiding rocks. During subsidence and

sedimentation the sediments must be heated, and this heat is taken from the background heat and

geothermal gradient is reduced. High sedimentation rates will reduce the geothermal gradient

because of some of the heat flux is used to heat the subsiding sediments (Figures 4.16-4.22). When

rocks are uplifted and cooled the heat given off from the cooling rocks adds to the background heat

flow.

4.3.2.5 Rifting-Phase

The duration of the Rifting Phase is “brief” (~25-23 Mabp and 17.2-16.8 Mabp) and a saw tooth-

shaped temperature profile is created (i.e. an extreme temperature inversion). The rift is rapid

compared to the rate of thermal equilibration and affects organic maturation by causing important

perturbations in subsurface temperatures. Paleo temperature profiles were high at different periods

during the geologic time of the area, with different cooling intervals, that may have been caused by

heat flow decline. The thermal and burial histories were calibrated by comparing measured and

calculated temperature data (Figures 4.2-4.5). Vitrinite reflectance is a measure of the thermal

maturity of organic matter in sediments. The kinetic Easy Ro% approach (Sweeney and Burnham,

1990) was used to predict vitrinite reflectance. Present-day bottom hole temperatures were used to

calibrate the simulated present-day temperature field. To reach an agreement between measured and

calculated temperature data, it was necessary to vary the basal heat flow. The final scenario is based

on the assumption that heat flow during the Mesozoic increased, related to continuing dilatation

movement and crustal thing until the Tertiary. High paleo-heat flow values of 125 mW/m2 at the

Miocene time of the basin evolution (Miocene rifting-phase) decreased to 110 mW/m2 during to the

Oligocene rifting phase (Tables 4.10-4.17 and Figures 4.6-4.13).

4.4 THERMAL MATURITY AND HYDROCARBON GENERATION

The petroleum system is defined by applying specific properties to the geological layers (Table 4.18).

For the source rock sequences, the total organic content (TOC) and quality Hydrogen Index (HI) has

to be defined together with reaction kinetic parameters for the thermal primary cracking to light and


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Thermal Maturity and Hydrocarbon Generation4-30

heavier petroleum components. Once the Paleo-temperatures are well modeled and calibrated,

equations for chemical kinetics can be used to evaluate petroleum generation.

From laboratory pyrolysis, experiments at different heating rates, activation energies and a pre-

exponential factor are calculated and used for the temperature history of the relevant sediments. This

approach assumes the conversion of kerogen to oil and gas to be irreversible reactions, which can be

defined by a set of parallel pseudo-reactions. For a more detailed description of basin modeling, its

concept and limitations see (Yalcin et al., 1997). The respective kinetic values used for hydrocarbon

generation are those of (Pepper and Corvi, 1995). The available geochemical data include vitrinite

reflectance (Ro%) and Rock-Eval Tmax, as well as the total organic carbon (TOC), Rock-Eval S1 (free

low-molecular-weight hydrocarbons), S2 (hydrocarbons generated by thermal cracking of kerogen,

generation potential), S3, Hydrogen Index, Oxygen Index (Table 4.18 and Figures 4.14-4.15).

When there are rocks with low thermal conductivity, (Belayim and Kareem formations), near the

surface the geothermal gradient will be higher so that the underlying sediments will be warmer

(Figures 4.16-4.22). This is called a Blanketing Effect. Salt of South Gharib Formation with high

thermal conductivity has a low temperature gradient and the temperature will be relatively high at the

top of the salt (South Gharib Formation) and low at the bottom (Belayim and Kareem formations).

This has a consequence for maturation of underlying organic-rich intervals (Figures 4.61-4.72).

Organic rich carbonate like (Thebes and Duwi formations) may also contribute significant heat

because of the radioactivity (high sulfur content). On the other hand, Organic rich shale like (Nubia A,

and Nubia B formations) may also contribute significant heat because of the radioactivity (high

uranium content). Sold basin with rapid subsidence and low geothermal gradient require deep burial

of the source rock before they can generate petroleum, both because of low temperature and short

geologic time for petroleum generation.

Table 4.18: Source rock intervals and properties used for modeling of hydrocarbon generation in the Belayim Marine Oilfield, BM-57 well, BM-65 well and BM-70 well, Gulf of Suez.

Well Depth

(TVDss) Kerogen S1 S2 S3 TOC

Easy

%Ro HI OI Tmax Lithology

Zone

Name

*BM-57 3078 Type-II 0.17 11.1 1.27 2.71 0.42 409 47 421 Arg. LS Thebes

*BM-57 3276 Type-II 0.23 22.4 1.40 4.02 0.49 557 35 425 Brown LS Duwi

*BM-70 3750 Type-II 0.12 7.12 1.13 1.80 0.54 396 63 428 Brown LS Thebes

*BM-70 3825 Type-II 0.15 12.6 0.96 2.75 0.56 458 35 429 Brown LS Duwi

BM-65 3259 Type -II

III 0.56 1.72 0.89 1.03 167 86 425

Shale &

Sandstone Nubia A

BM-57 3189 Type -II

III 0.83 7.03 1.35 2.62 268 52 427

Shale &

Sandstone Nubia B

TVDSS: True vertical depth sub-sea level; S1:mg/g; S2:mg/g; S3:mg/g; TOC: Total organic carbon (wt%); EASY Ro%: Calculated vitrinite reflectance after (Sweeney and Burnham, 1990) (%); HI: Hydrogen Index (mgHC/gTOC); OI: Oxygen Index (mgCO2/gTOC); Tmax:degC; h: The true thickness (meter). * Data from (W.Sh. El Diasty a, 2014).

The kinetic equations are defined for different kerogen types. For kerogen types I and II, the

kerogen–oil reaction is the main process, while for kerogen type III, kerogen to gas reactions

predominate. Maturity calculation was carried out using the EASY Ro% algorithm of (Sweeney and

Burnham, 1990) (Figures 4.53-4.60). The calculation of hydrocarbon generation was based on the



concept of parallel first order thermal cracking reactions. The respective kinetic values used for

hydrocarbon generation are those of (Pepper and Corvi, 1995).

Figure 4.14: Abbreviated geochemical log for ditch cuttings of the encountered organic-rich intervals in BM-57 well, based on Rock-Eval Pyrolysis, TOC, and vitrinite reflectance. Vitrinite reflectance-depth plot showing the generalized position of the oil and gas zones, which will vary depending on kerogen type. These Ro values are related to the maximum temperature to which a particular zone has been exposed.



Figure 4.15: Abbreviated geochemical log for ditch cuttings of the encountered organic-rich intervals in BM-65 well, based on Rock-Eval Pyrolysis, TOC, and vitrinite reflectance. Vitrinite reflectance-depth plot showing the generalized position of the oil and gas zones, which will vary depending on kerogen type. These Ro values are related to the maximum temperature to which a particular zone has been exposed.



Figure 4.16: Quantitative simulated geohistory, burial history and recalibrated temperature development history as a function of time and space of the reference (well BM-57) using the paleotemperature determined by Easy Ro% approach. The solid lines traces the depth-time relation for the sediment with discrepancy between present (compacted) and decompacted thickness. The lower curve shows subsidence of the basement. The upper curves are sea-level and the sediment interface.




Figure 4.22: Quantitative simulated geohistory, burial history and recalibrated temperature development history as a function of time and space of the reference (well 113-M-27) using the paleotemperature determined by Easy Ro% approach. The solid lines traces the depth-time relation for the sediment with discrepancy between present (compacted) and decompacted thickness. The lower curve shows subsidence of the basement. The upper curves are sea-level and the sediment interface.

Figure 4.23: Quantitative simulated geohistory, burial history and recalibrated temperature development history as a function of time and space of the reference (well 113-M-34) using the paleotemperature determined by Easy Ro% approach. The solid lines traces the depth-time relation for the sediment with discrepancy between present (compacted) and decompacted thickness. The lower curve shows subsidence of the basement. The upper curves are sea-level and the sediment interface.



4.4.1 Thebes Formation

4.4.1.1 Formation Evaluation

The Eocene Thebes Formation is a very good quality oil source rock in the central province. It consists

of open marine limestones and its organic content is variable, but locally it is rich in TOC with values

1-2.86% reported. Kerogen is classified as Type I-II, with 10-30% woody and herbaceous material,

giving it slightly less oil-prone character than the Brown Limestone. Where maturity data are available,

they point marginal mature to early mature at best, but in the source kitchens greater maturity can be

expected and the Thebes Formation may well have contributed significant volumes of oil (IHS, 2006).

Indeed, studies that indicate more than one source for Gulf of Suez oils (Zein El Din and Shaltout,

1987) may be pointing to a combination of the Brown Limestone and the Thebes formations.

The interval ranges between depths from 2565 m (TVDss) at BM-57 to 3331 m (TVDss) at 113-M-27

well, (Figures 4.24-4.28) represent the Thebes-S Formation. The Thebes-S has gamma ray log

ranging from (maximum values 43 API at 113-M-34 and 115 API at BM-65 well). It is characterized by

high gamma ray (trace GR) value up to 115 API, sonic log (trace DT) shows high interval transit time

(79-118µs/ft), density log (Figures 4.24-4.28), ROHB trace values (2.3-2.6 g/c3) all of these are

accompanied with high resistivity log values (Trace LLD 28.6-3741 Ω-m). The log reading readings

indicate limestone lithological nature that prevail nearly the entire section of the Thebes Formation.

This is clearly illustrated on the extreme right-hand-side track of the plot (Figures 4.24-4.28).

However within the Thebes-S interval the gamma ray log not accurately reflect organic carbon

variations. This is believed to be due to varying radioactive concentrations. Therefore, an increase in

total gamma ray reading due to high concentration of organic matter would be balanced by an

increase in total gamma ray caused by feldspars.

The sonic log is plotted on a normalized scale with the resistivity log. When the normalized scales are

correct, the sonic and resistivity logs 'track' one another but separate when a source rock is present

(Passey et al., 1990). The degree of separation is said to be related to both degree of maturity and

source abundance (TOC %) therefore this interval is considered as mature source rock. From Figures

4.24-4.28), the values of interval transit time are high with maximum value of 118µs/ft and high

resistivity values reaching to 3741Ω-m, so with plotting sonic values with resistivity values led to

separation such that of the Passey method, so this interval is mature source rock. The resistivity logs

however have the inherent disadvantages that the signal measured is strongly maturity dependent.

First, due to oil generation with increasing maturity pores become increasingly oil saturated, which

results in an increase of resistivity (Tissot and Welte, 1984). Second, at higher maturity as oil is

cracked to gas which can be expelled, resistivity decreases. Low resistivity therefore can indicate both

immature and over mature oil source rock as well as gas- only source rocks. Because of this maturity

dependence, resistivity logs are not well suited for organic facies determination but have values as

maturity indicator (Smagala, 1984). However they can be used to recognize source rock quality

variations in sections of similar lithology within the oil generation maturity zone. This different log

pattern of Thebes-S may be caused by two types of sedimentary input: one with a more prolific and

one with a poorer source area.



BM-57Scale : 1 : 600

DEPTH (2560.06M - 2665.06M) 7/22/2014 14:58DB : IP Folder Master Final (5)

Age Fm Zone Gamma Ray

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

Lower Miocene

Eocene

Paleocene

Rudeis

Thebes

Esna

Rud

eis-

Sh

ale

The

bes-

S

2600

2650

Thebes FM.(Top @ 2564.7 M)Limestone: Pyritic w ith Chert.

Esna FM. (Top @ 2660.7 M)Shale: Fossiliferous.

The interval called Thebes-S is a source rock with total organic carbon of 2.71wt% and hydrogen

index of 409 and is classified as Thebes S1 and Thebes-S2; it is mature source rock, as there is

separation between the sonic log and the resistivity log at wells BM-70, BM-65, BM-23, 113-M27, 113-

M-34), and immature source rock at BM-57 well and BM-36 well.

Figure 4.24: The corrected log datasets through a limestone sequences of the Eocene Thebes Formation (2565m – 2661m) of the BM-57 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.



BM-70Scale : 1 : 600



GR (gAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

Lower Miocene

Eocene

L. Cretaceous (Lower Senonian)

Rudeis

Thebes

Matulla

The

bes-

S1

Th

ebes

-PT

hebe

s-S

2

3300

3350

Thebes FM.(Top @ 3263 M)Brow n Limestone.Shale: Calcareous to highCalcareous.

Matulla FM. (Top @ 3386 M)Shale: Slightly calcareous,




BM-36Scale : 1 : 600



GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

MSFL (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

Miocene

Eocene

Paleocene

Rudeis

Thebes

Esna

Ru

deis

-R2

The

bes-

S

2650

2700

Thebes FM.(Top @ 2621 M)Limestone.

Esna FM. (Top @ 2739.5 M)Shale: Calcareous to high




BM-65Scale : 1 : 600

DEPTH (3025.M - 3105.M) 7/22/2014 15:09DB : IP Folder Master Final (6)

Age Fm Zone Depth

DEPTH(M)

Gamma Ray

GR (API)0. 150.

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)2.95 1.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

Lower Miocene

Eocene

Paleocene

Rudeis

Thebes

Esna

Rud

eis-

LT

hebe

s-S 3050

3100

Thebes FM.(Top @ 3030 M)

Limestone: High argellaceous,Pyritic.

Shale: Calcareous to highCalcareous.




BM-23 STScale : 1 : 600


Age Formation Zone Gamma Ray

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

Miocene

Eocene

Paleocene

Rudeis

Thebes

Esna

The

bes-

S

2900

2950

3000

Thebes FM.(Top @ 2859.25 M)Limestone.

Esna FM. (Top @ 2994.66 M)Shale.

Figure 4.28: The corrected log datasets through a limestone sequences of the Eocene Thebes Formation (2859m – 2995m) of the BM-23 ST well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.

4.4.1.2 Maturity and hydrocarbon generation of Thebes Formation

The Eocene Thebes Formation was penetrated in seven wells (namely BM-57, BM-70, BM-36, BM-65,

BM-23, 113-M-27, and 113-M-34) at true vertical depths sub sea (TVDss) range between 2565m

(TVDss) at BM-57 well and 3331m (TVDss) at 113-M-27 well. The maximum recorded thickness of the



Eocene Thebes Formation ranges from 44m to 237m at 113-M-34 well and 113-M-27 well,

respectively.

The organic-rich interval, namely Thebes-S, is located at seven wells BM-70, BM-57, BM-36, BM-65,

BM-23, 113-M-27, and 113-M-34 well. The present-day burial depth to top, of the Thebes-s, ranges

between 2565m at BM-57 well and 3331m at 113-M-27 well with total thicknesses range between

19m at BM-36 well and 237m at 113-M-27 well (Figures 4.24-4.28). On the other hand, at single

reference well location at BM-70 well (See Figure 4.25), a second organic rich interval, zone Thebes-

S2 has been recorded at depth 3346m with a total thickness of 41m. It assigned to pre-rift basin fill

deposits of limestone that deposited in open marine depositional environment characterized by type II

kerogen with an excellent generation potential for liquid hydrocarbons (oil prone type II-S kerogen). It

is characterized by a relatively high total organic carbon (TOC) value of ~2.71wt% and by immature

Type II kerogen at wells (BM-57 and BM-36) (Table 4.18) (Figures 4.61 and 4.64) and mature at wells

(BM-70, BM-65, BM-23, 113-M-27 and 113-M-34 well), (Figures 4.63, 4.66, 4.69, 4.70 and 4.72).

For the numerical basin modeling, intervals with present-day TOC values below 0.5wt% for oil-prone

source rocks and 0.8wt% TOC for gas-prone source rocks were considered to have negligible

petroleum generation potential because the kerogen in such lean rocks is often highly oxidized.

The relatively high hydrogen index of 409 mgHC/gTOC and low oxygen index of 47 mgCO2/gTOC, S2

value of 11.1 mg/g rock indicate that the kerogen is made up of an oxygen-lean organic material and

confirm the kerogen as type II that considered mainly as oil generative interval (Table 4.18).

The organic-rich interval of the Thebes Formation, Thebes-S, entered the oil windows close to the

Late Miocene (Messinian ~5.75 Mabp) during the deposition of Upper Miocene Zeit Formation, and

has been in the wet gas windows (gas onset) since ~5.35 Mabp Late Miocene (Messinian) during the

deposition of Upper Miocene Zeit Formation. The oil windows depths range between 2296m (~4.01

Mabp Pliocene-Zancleanian) to 2940m (~2.7 Mabp Pliocene-Piacenzian), before the maximum burial

was reached, at 113-M-34 well and BM-70 well, respectively. The basin wide unconformities formed

primarily in response to regional tectonic adjustments associated with different rift phases of the Gulf

of Suez (Dolson et al., 2001).

The oil windows depth range between 2315m (~5.75 Mabp Late Miocene-Messinian) to 2940m (~2.7

Mabp Pliocene-Piacenzian), before the maximum burial was reached, at 113-M-27 well and BM-70

well, respectively. The oil window is shallower and older in age (~5.75 Mabp Late Miocene-Messinian)

at 113-M-27 well in comparison to that mature source rock interval at BM-70 well, where it is

relatively deeper and younger in age (Figures 4.61 and 4.66). The gas (gas generation onset) depths

range between 2525m (~5.35 Mabp Late Miocene-Messinian) to 3199m (~2.1 Mabp Pleistocene-

Gelasian) at 113-M-27 well and BM-70 well, respectively. The present-day depth of the Thebes-S is in

the range in which a single-phase fluid (Medium oil) generated (Figures 4.63, 4.66, 4.69, 4.70 and

4.72).

Liquid hydrocarbon generation begin at a vitrinite reflectance of 0.51%, which is reached at different

ages and depths throughout the area at BM-65 well (~2.4 Mabp Pleistocene-Gelasian) with a

corresponding temperature of 96°C (Figures 4.40 and 4.56), and at 113-M-27 well (~5.75 Mabp Late

Miocene-Messinian) with a corresponding temperature of 97°C (Figures 4.43 and 4.59). Whereas the



vitrinite reflectance value of 0.52% is encountered since (~4.01 Mabp Pliocene-Zanclean) with a

corresponding temperature value of 94°C at 113-M-34 well (Figures 4.44 and 4.60), then at (~2.7

Mabp Pleistocene-Piacenzian) with corresponding temperature value of 98°C at BM-70 well (Figures

4.38 and 4.54), and later on at (~2.4 Mabp Pleistocene-Gelasian) with a corresponding temperature

value of 98°C at BM-23 well (Figures 4.42 and 4.58). With increasing maturity the generation of gas

from both kerogen (primary cracking) and already generated but unexpelled oil (secondary cracking)

increases by breaking of carbon-carbon bonds (Dow, 1977), (Horsfield et al., 1991) and (Behar et al.,

1995).

The gas-onset vitrinite reflectance value is 0.57% northwestward since (~2.10 Mabp Pleistocene-

Gelasian) at BM-70 well with a corresponding temperature value of 106°C (Figures 4.38 and 4.54), at

BM-65 well (~0.9 Mabp Pleistocene-Calabrian) with a corresponding temperature value of 104°C

(Figures 4.40 and 4.56), and at BM-23 well with a corresponding temperature value of 102°C (Figures

4.42 and 4.58). On the other hand, the gas-onset vitrinite reflectance value is 0.58% southeastward

since (~5.35 Mabp Late Miocene-Messinian) with a corresponding temperature value of 107°C at 113-

M-27 well (Figures 4.43 and 4.59), and since (~3.4 Mabp Pliocene-Piacenzian) with a corresponding

temperature value of 105°C at 113-M-34 well (Figures 4.44 and 4.60).

The present-day vitrinite reflectance values based on the calculation of (Sweeney and Burnham, 1990)

in association with the present day depth show different vitrinite reflectance values for the organic

rich interval of Thebes Formation, Thebes-S. The present-day maximum simulated vitrinite reflectance

value 0.75% at 113-M-27 well corresponds to a temperature of 118°C (Figures 4.43 and 4.59). The

maximum present day temperature value of 120°C is simulated at BM-70 well. However, the present-

day minimum simulated vitrinite reflectance value of 0.43% at BM-57 well corresponds to a

temperature of 78°C (Figure 4.37).

The present day transformation ratio ranges between 1.10% at BM-57 well to 52.53% at 113-M-27

well mainly after the deposition of Post-Zeit Formation, whereas the present-day bulk generation mass

ranges between 0.13 Mtons at BM-23 well (Figure 4.50) to 1.96 Mtons at 113-M-27 well (Figure 4.51).

The expulsion of the hydrocarbons occurred mainly after the generation of the gas and after the

Messinian Time Event (~5.2 to ~4 Mabp Early Pliocene) at wells BM-70, 113-M-27, and 113-M-34

well. However, present day expulsion of the hydrocarbons occurred, at BM-23 and BM-65 wells, after

both the generation of the gas and the deposition of the Post-Zeit Formation. There is no expulsion at

BM-57 and BM-36 wells.

The generated hydrocarbon accumulated in the source rock (adsorbed by the organic matter in the

source). Rocks with lower percentages of organic carbon may not be able to expel the generated oil,

possibly due to the adsorption of the hydrocarbon molecules on minerals (Littke et al., 1997). The

resultant low expulsion efficiency causes a preservation of hydrogen until gas is generated by cracking

of the trapped bitumen at more elevated maturity stages (Littke and Leythaeuser, 1993).

Oil generation windows after both the Messinian Event and the deposition of Zeit Formation and

during the deposition of Post-Zeit Formation and after the maximum burial depth reached.

At 113-M-27 well, hydrocarbon generation mainly related to burial rather than basin evolution, the oil

window started at (~5.75 Mabp Late Miocene-Messinian) during the deposition of the Zeit Formation,



the organic rich interval of the Thebes Formation, Thebes-S, at 113-M-27 well is located at depth of

3331m, it is classed as mature source rock which is related to burial because of the maximum

thickness of Zeit Formation 750m, South Gharib Formation 514m, Belayim Formation 300m, Kareem

Formation 219m and Upper Rudeis Formation 402m (Figures 4.43, 4.51, 4.59, and 4.70).

In addition, at BM-23 well, hydrocarbon generation mainly related to burial rather than basin

evolution, whereas the oil window started at (~2.4 Mabp Pleistocene-Gelasian) during the deposition

of Post Zeit Formation, the organic rich interval of Thebes Formation, Thebes-S, at BM-23 well is

located at depth 2859m, it is classed as mature source rock which is related to burial because of the

maximum thickness of Zeit Formation 678m, South Gharib Formation 486m, Belayim Formation 306m,

Kareem Formation 182m and Upper Rudeis Formation 173m (Figures 4.42, 4.50, 4.58, and 4.69).

Moreover, at BM-65 well, hydrocarbon generation mainly related to burial rather than basin evolution,

The oil window started at (~2.4 Mabp Pleistocene-Gelasian) during the deposition of Post Zeit

Formation, the organic rich interval of Thebes Formation, Thebes-S, at BM-65 well is located at depth

3030m, it is classed as mature source rock which is related to burial because of the maximum

thickness of Zeit Formation 786m, South Gharib Formation 538m, Belayim Formation 503m, Kareem

Formation 144m and Upper Rudeis formation 89m (Figures 4.40, 4.48, 4.56, and 4.66).

Furthermore, at BM-70 well, hydrocarbon generation mainly related to burial rather than basin

evolution, the oil window started at (~2.7 Mabp Pliocene-Piacenzian) during the deposition of Post

Zeit Formation, the organic rich intervals of Thebes formation (Thebes-S1 and Thebes-S2) at BM-70

well is located at depths 3263m and 3346m, respectively. These organic rich intervals are classed as

mature source rock which is related to burial because of the maximum thickness of Zeit Formation

832m, South Gharib Formation 463m, Belayim Formation 230m, Kareem Formation 200m and Upper

Rudeis Formation 471m (Figures 4.38, 4.46, 4.54, and 4.63).

This is due to less heat transfer effect of the relatively low thickness of Late Miocene South Gharib

Formation (463m at BM-70 well) which characterized by high thermal conductivity. In addition, the

burial influences due to the deposition of the Late Miocene sediments of Zeit and Post-Zeit sediments

On the other hand, at 113-M-34 well, hydrocarbon generation mainly related to basin evolution (the

Messinian Event ~5.2 to ~4 Mabp) rather than burial (instead of the deposition of Zeit Formation of

about 739m thick, South Gharib Formation 561m, Belayim Formation 293m, Kareem Formation 221m

and Upper Rudeis Formation 256m). The oil window started at (~4.01 Mabp Pliocene-Zancleanian)

during basin evolution (the Messinian Time Event ~5.2 to ~4 Mabp). The organic rich interval of the

Thebes Formation, Thebes-S at 113-M-34 well is located at depth 3175m and it is classed as mature

source rock which is related to basin evolution (Figures 4.44, 4.55, 4.60, and 4.72).

However, at BM-36 well, the organic rich interval of Thebes Formation at BM-36 well is classed as

immature source rock because of the shallow depth of this Thebes organic rich interval at 2621m, and

the less thickness of the Post Zeit Formation 882m, Zeit Formation 684m, South Gharib Formation

478m, Belayim Formation 132m, Kareem Formation 230m and Upper Rudeis Formation 182m. Even

though the present day simulated vitrinite reflectance value of 0.5% with a corresponding

temperature value of 90.26°C of the organic rich interval of Thebes Formation, Thebes-S at BM-36



well. The bulk generation rate at the present day is 0.01 mgHC/gTOC/My, and the present day

transformation ratio is 4.93% (Figures 4.39, 4.47, 4.55, and 4.64).

In addition, at BM-57 well, the organic rich interval of Thebes Formation at BM-57 well is classed as

immature source rock because of the Thebes organic rich interval of BM-57 well is located at the

shallower depth 2565m, and due to the minimum thickness of the Post Zeit Formation 797m, Zeit

Formation 665m, South Gharib Formation 502m, Belayim Formation 245m, Kareem Formation 177m

and Upper Rudeis Formation 141m. Whereas the present day temperature of the organic rich interval

of Thebes Formation, Thebes-S, at BM-57 well is reached to 78.77°C, the present day vitrinite

reflectance value 0.43%, bulk generation rate at the present day is 0.01 mgHC/gTOC/My, and the

present day transformation ratio is 1.12% (Figures 4.37, 4.45, 4.53, and 4.61).

The important aspects of primary migration are the nature of the hydrocarbons expelled (oil or gas),

the efficiency of expulsion, and the timing of the expulsion. Whether migration occurs mainly in

vertical or horizontal direction also depends on the source rock properties. For example, fractures

seem to develop more often parallel to the bedding plane in shaly source rocks than in carbonate

source rocks, in which fractures cut bedding at high angles (Littke et al., 1988).

This explained by great influence of highly thermal conductivity thick South Gharib Formation that

effectively transfers heat to the overlain formation. This is in association with the opposite effect due

to the low thickness of Belayim Formation that characterized by moderate thermal conductivity. These

values reached after the deposition of thick Zeit Formation.

These variations in maturity are mainly related to the deposition of the maximum thickness of

Belayim, Kareem and Upper Rudeis formations at 113-M-27 well. The hydrocarbon generation of

Thebes Formation is mainly related to basin burial. This means that the source rock will have to be

buried to greater depths in the area to generate oil, all other factors being the same

The simulated vitrinite reflectance and the corresponding temperature values of the oil generation

increase from 0.51% Ro and 97°C to 0.52%Ro and 98°C (~5.75 to ~2.4 Mabp) during the deposition

of Zeit Formation then continuously increased after the Messinian Time Event (~5.2-~4 Mabp) and

throughout the deposition of the Post-Zeit to the present day after the deposition of Post-Zeit

Formation. This is due to both uplift and erosion that followed the Messinian Event (~5.2 to ~4 Mabp

Early Pliocene) and the deposition of the Late Miocene sediments of Zeit and Post-Zeit sediments. This

indicates that the maturity of the organic-reach intervals of Thebes Formation is closely related to

burial with a minor heat flow influence. Hydrocarbon generation is mainly related to exchange of

burial, particularly due to deposition of the Zeit and Post-Zeit formations.



4.4.2 Duwi Formation


The interval between depths 2763 m (true vertical depth subsea, TVDss) at BM-57 well and 3307 m

(TVDss) at 113-M-34 well represents the Duwi-S Formation. The Duwi-S has gamma ray range from

(maximum values 142 API at BM-23 well and 196 API at BM-57 well). It is characterized by high

gamma ray (trace GR) value up to 196 API, sonic log (trace DT) shows high interval transit time (81-

104 µs/ft), density log ROHB trace values range (2.26-2.54 g/c3) all of these are accompanied with

high resistivity log values (Trace LLD averaged value 72-1706 Ω-m). The log readings indicate

limestone lithological nature that prevail nearly the entire section of the Duwi Formation. This is

clearly illustrated on the extreme right-hand-side track of the plot (Figures 4.29-4.31).

However within the Duwi-S interval the gamma ray log not accurately reflect organic carbon







source abundance (TOC %) therefore this interval is considered as mature source rock. From (Figures

4.28-4.30), the values of interval transit time are high with maximum value of 104 µs/ft and high

resistivity values reaching to 1706 Ω-m, so with plotting sonic values with resistivity values led to

separation such that of the Passey method, so this interval is mature source rock, Duwi-S, entered the

oil windows at (~5.88 Mabp Late Miocene-Messinian) and this was during deposition of the Upper

Miocene Zeit Formation and shortly after the deposition of South Gharib Formation. The resistivity logs








variations in sections of similar lithology within the oil generation maturity zone. The interval called

Duwi-S is a source rock with total organic carbon of 4.02wt% and hydrogen index of 557 and is

classified as Duwi-S is immature to early mature source rock, as there is separation between the sonic

log and the resistivity log. The interval called Duwi-S is a source rock with total organic carbon of

2.75wt% and hydrogen index of 458 and is classified as Duwi-S, is mature source rock, as there is

separation between the sonic log and the resistivity log.



BM-57Scale : 1 : 100



GR (GAPI)0. 150.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

L. Cretaceous (Upper Senonian)


Sudr

Daw i

Matulla

Daw

i-SM

atul

la-S

eal

Daw i FM.(Top @ 2763.0 M)Brow n Limestone: massive,cryptocrystlline, argellaceous,trace of Calcite.

Figure 4.29: The corrected log datasets through a limestone sequences of the Upper Senonian Duwi Formation (2763 m and 2772 m) of the BM-57 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.



BM-23 STScale : 1 : 200



GR (GAPI)0. 150.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology



Sudr

Daw i

Matulla

Daw

i-S

3050

3075

Daw i FM.(Top @ 3049 M)Brow n Limestone.

Figure 4.30: The corrected log datasets through a limestone sequences of the Upper Senonian Duwi Formation (3049 m and 3085 m) of the BM-23 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.



Figure 4.31: The corrected log datasets through a limestone sequences of the Upper Senonian Duwi Formation (3307 m and 3353 m) of the 113-M-34 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.

4.4.2.2 Maturity and hydrocarbon generation of Duwi Formation

The Upper Senonian Duwi Formation was penetrated at four wells at depths range between 2763m at

BM-57 well and 3572m at 113-M-27 well. The penetrated thickness ranges from 9m to 46m at BM-57

well and 113-M-34 well, respectively. The Campanian Brown Limestone is interpreted as the dominant

regional source rock in the Gulf of Suez. It is a pelagic chalky limestone deposited in a markedly

anoxic outer shelf environment (Palmer, 1993). Its kerogen is classified as Type I and II and is almost

entirely composed of amorphous sapropel or algal debris. It is therefore oil prone. In wells for which

data have been published it is immature to nearing peak maturity and is probably at or beyond peak

in adjacent kitchens. Total Organic Carbon (TOC) content in immature samples is reportedly in the

range 1-8.5%. Because the Brown Limestone is a very efficient source rock (Cooles et al., 1986),

averages based on all data tend to be lower, reflecting maturation and expulsion, and do not reflect

its high initial potential. TOC values as high as 21% have been documented in Campanian Brown

M-34Scale : 1 : 240



GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Remarks

Lithology



Sudr

Daw i

Matulla

Daw

i-S

3325

3350

Daw i FM. (Top @ 3306.6 M)Brow n Limestone.

Matulla FM. (Top @ 3352.9 M)Sandstone: Calcareous cement,



Limestone samples collected from underground phosphate mines in the southeastern Egypt (Abd El

Aal et al., 1992). The organic-rich interval, namely Duwi-S is distinguished at four wells BM-57, BM-

23, 113-M-27, and 113-M-34 well. The present-day depth of the organic-facies interval ranges

between 2763m at BM-57 and 3572m at 113-M-27 well with total thicknesses range between 9m at

BM-57 well and 46m at 113-M-27 well. It assigned to pre-rift basin fill sediments of limestone organic

rich interval that deposited in open marine depositional environment which is characterized by type II

kerogen with an excellent generation potential for liquid hydrocarbons (oil prone type II-S kerogen).

The Santonian Brown Limestone and the Eocene Thebes formations contain above-average amounts

of organic matter (2-8 wt.%) (Chowdhary and Taha, 1987). It is characterized by a high initial total

organic carbon (TOC) value of ~4.02wt% and by immature to early mature Type II kerogen at single

well (BM-57 well) (Figure 4.61) (Table 4.18), whereas it is classified as thermally mature type II

kerogen at (BM-23, 113-M-27, and 113-M-34 wells) (Figures 4.69, 4.70, and 4.72). Recent correlation

studies have indicated that many oils are principally derived from carbonate source rocks, most likely

from the Brown Limestone and the Thebes formations (Ungerer and et al, 1986), (Chowdhary and

Taha, 1987) and (Mostafa et al., 1993), especially in the northern and central sectors of the Suez Rift.



petroleum generation potential because the kerogen in such lean rocks is often highly oxidized. These

Santonian Brown Limestone and the Eocene Thebes formations units are also rich in extractable

hydrocarbons and their organic matter comprises oil-prone algal and amorphous kerogen. Further,

these units are characterized by high hydrocarbon potentials (600-1,000 mg of hydrocarbon (HC)/g

Co2), typical of Types II and II/I kerogen. Based on organic richness and type of organic matter, the

source sediments of the Brown Limestone and the Thebes formations have excellent source potential

(Chowdhary and Taha, 1987). The high hydrogen index of 557 mgHC/gTOC and low oxygen index 35

mgCO2/gTOC, S2 value of 22.4 mg/g rock indicate that the kerogen is made up of an oxygen-lean

organic material and confirm the kerogen as type II that considered mainly as oil generative interval

(Table 4.18). Based on organic richness and type of organic matter, the source sediments of the

Brown Limestone and the Thebes formations have excellent source potential (Chowdhary and Taha,

1987). The organic-rich interval of the Duwi Formation in Belayim Marine Oil field concession, Duwi-S,

entered the oil windows close to the Late Miocene (Messinian ~5.88 Mabp) during the deposition of

Zeit Formation, and has been in the wet gas windows (gas onset) since ~5.42 Mabp (Late Miocene-

Messinian). The oil windows depths range between 2329m (~3.5 Mabp Pliocene-Piacenzian) at BM-23

well to 2384m (~5.88 Mabp Late Miocene-Messinian) at 113-M-27 well, before the maximum burial

was reached.

Source rocks in the Gulf of Suez, whether the Santonian Brown Limestone Formation or the Eocene

Thebes Formation (or both), reached the main stage of oil generation during the late Miocene. Source

sediments of both the Brown Limestone and the Thebes formations reached the onset stage of oil

generation in the Pliocene and have not yet reached the peak stage of oil generation in the DD83-1

well, which is located on a high block (Chowdhary and Taha, 1987). The oil generation window is at

about 4500-5000m, the base at 5800-6000 m. Peak oil generation was attained 8-4 mio. y. ago, after



the deposition of the evaporates (Shahin and Shehab, 1984), (Barnard, 1992), (Shawky et al., 1992),

and (Mostafa et al., 1993).

The oil window is shallower and younger in age (~3.5 Mabp Pliocene-Piacenzian) at BM-23 well in

comparison to that immature-early mature organic rich interval at BM-57 well, whereas relatively

deeper and older in age at 113-M-27 well (Figures 4.69, 4.61, and 4.70). On the other hand, the gas

(gas generation onset) depths range between 2529m (~4.6 Mabp Pliocene-Piacenzian) at 113-M-34

well to 2793m (~2.4 Pleistocene-Gelasian) at BM-23 well. The present-day depth of the Duwi-S is in

the range in which a single-phase fluid (Medium oil) might be expected (Figures 4.72 and 4.69).

The generation of hydrocarbon mainly related to basin burial rather than basin evolution during the

deposition of Zeit Formation at 113-M-27 well (~5.88 Mabp Late Miocene-Messinian) and 113-M-34

well (~5.65 Mabp Late Miocene-Messinian) and during the Post Zeit Formation at BM-23 well (~3.5

Mabp Pliocene-Piacenzian). At 113-M-27 well, hydrocarbon generation mainly related to burial rather

than basin evolution (~5.88 Mabp Late Miocene-Messinian) during the deposition of the Zeit

Formation. Fortunately, the generation of hydrocarbon mainly after the generation of hydrocarbon of

Both Nubia A and Nubia B formations (6.6 Mabp Late Miocene). It is considered as an active/effective

source rock. Petroleum generation starts at a vitrinite reflectance value close to 0.5%, which is

reached at different age and depth throughout the area (Figures 4.44 and 4.60), (~5.65 Mabp Late

Miocene-Messinian) at 113-M-34 well with a corresponding paleo temperature value of 95°C.

However, at BM-23 well the vitrinite reflectance value of 0.54% is encountered since (~3.5 Mabp

Pliocene-Piacenzian) (Figures 4.42 and 4.58), with a simulated paleo temperature value of 98°C. With

increasing maturity the generation of gas from both kerogen (primary cracking) and already

generated but unexpelled oil (secondary cracking) increases by breaking of carbon-carbon bonds

(Dow, 1977), (Horsfield et al., 1991) and (Behar et al., 1995).

The gas-onset vitrinite reflectance value is 0.57% at (~4.6 Mabp Pliocene-Piacenzian) at 113-M-34

well with a temperature value of 104°C, whereas at 113-M-27 well the maximum simulated vitrinite

reflectance value of 0.59% has been obtained since ~5.42 Mabp (Late Miocene-Messinian) with a

corresponding temperature of 110°C (Figures 4.44 and 4.43). The generation of gas mainly related to

basin burial rather than basin evolution during the deposition of Zeit Formation at 113-M-27 well

(~5.42 Mabp Late Miocene-Messinian) and during the Post Zeit Formation at BM-23 well (~2.4 Mabp

Pliocene-Piacenzian). At 113-M-34 well, gas generation mainly related to basin burial and basin

evolution (~4.6 Mabp Late Miocene-Messinian) after the deposition of Zeit Formation and during the

deposition of the Post Zeit Formation.



rich interval, Duwi-S. The present-day maximum simulated vitrinite reflectance value of 0.76% is

recognized at 113-M-27 well with a corresponding present-day maximum temperature value of 125°C

(Figure 4.59). The maximum present day temperature of 125°C at 113-M-27 well is due to shallower

depth of basement relief (due to minimum thickness of Nubia a 95m and Nubia B 119 m and Nubia C

60m, which is characterized by relatively high thermal conductivity that effectively transfers heat to

the overlain formations) in association with the effect of the thick Post Zeit Formation (1128m), Zeit



Formation (750m), Upper Rudeis Formation (402m) and Thebes Formation (237m). In addition, the

relatively high basal heat flow value due to shallow-seated basement. The thickness of the individual

units varies greatly because of the irregular topography of the underlying block-faulted early Miocene

(Fichera et al., 1992). On the other hand, the present-day minimum simulated vitrinite reflectance

value of 0.48% is recognized at BM-57 well with a corresponding present-day minimum temperature

value of 87°C (Figure 4.37). This is explained by maximum thickness of the relatively low thermal

conductivity of the Nubia C Formation (338m) and the minimum thickness of the Post Zeit Formation

(797m), the Zeit Formation (665m), the Belayim Formation (245m), the Kareem Formation (177m),

and the Upper Rudeis Formation (141m). This indicates that the maturity of the organic-reach

intervals of Duwi Formation is closely related to basin burial. This means that the source rock will have

to be buried to greater depths in the area to generate oil, all other factors being the same.


well whereas the present day bulk generation mass ranges between 0.24 Mtons at BM-23 well to 0.67

Mtons at the present day at 113-M-34 well (Figures 4.50, 4.51, and 4.52).


deposition of the Zeit Formation and during the Messinian Time Event at 113-M-27 well and 113-M-34

wells. However, at BM-23 well the expulsion occurred during the deposition of Post Zeit Formation.

The expulsion depth ranges between 2519m (TVDss) at 113-M-34 well to 3047m (TVDss) at BM-23

well. Therefore, the shallower depths of expulsion at 113-M-34 and 113-M-27 wells may be explained

mainly due to basin evolution as a result of the Messinian Time Event ~5.2 to ~4 Mabp (Pliocene-

Zanclean), whereas at BM-23 well the expulsion is related mainly to basin burial. The efficiency of

expulsion depends on the petrophysical properties of the source rock interval such as the thickness of

the organic rich interval and the amount of hydrocarbon generated that related to the initial amount

of TOC value. The resultant low expulsion efficiency causes a preservation of hydrogen until gas is

generated by cracking of the trapped bitumen at more elevated maturity stages (Littke and

Leythaeuser, 1993). The hydrocarbon expulsion of the organo-facies, called Duwi-S, commerce since

~5.2 Mabp (Pliocene-Zanclean) after both the generation of the gas and the deposition of Zeit

Formation. The expulsion simultaneously started at the beginning of the Messinian Time Event (~5.2-

4 Mabp) at 113-M-27 well. Fortunately, the expulsion of Nubia-B organic rich interval concedes with

that of Duwi organic rich interval. The recent expulsion event started since ~1.8 Mabp (Pleistocene)

after both the generation of the gas and the deposition of the Post-Zeit Formation at single reference

well location at BM-23 well. On contrast, there is no expulsion at BM-57 well. The expulsion occurred

at a generation mass that ranges between 0.06 Mtons HC (~5.2 -4 Mabp Pliocene-Zanclean) at 113-

M-27 well and 113-M-34 well, respectively to 0.09 Mtons HC (~1.8 Mabp Pleistocene) at BM-23 well.

Rocks with lower percentages of organic carbon may not be able to expel the generated oil, possibly

due to the adsorption of the hydrocarbon molecules on minerals (Littke et al., 1997). The resultant

low expulsion efficiency causes a preservation of hydrogen until gas is generated by cracking of the

trapped bitumen at more elevated maturity stages (Littke and Leythaeuser, 1993).

The sum of generated hydrocarbons at the present day ranges between a minimum value of 0.24

Mtons HC at both BM-23 well and 113-M-27 well to a maximum value of 0.66 Mtons HC at 113-M-34



well. The important aspects of primary migration are the nature of the hydrocarbons expelled (oil or

gas), the efficiency of expulsion, and the timing of the expulsion. Whether migration occurs mainly in




4.4.3 Nubia A Formation



(TVDss) at BM-65 well represents the Nubia A-S Formation. The Nubia A-S has gamma ray range from



126 µs/ft), density log ROHB trace values range (2.1-2.7 g/c3) all of these are accompanied with high

resistivity log values (Trace LLD averaged value 7.4-23.2 Ω-m). The log readings indicate ratio of

shale to Sandstone lithological nature that prevail nearly the entire section of the Nubia A-S

Formation. This is clearly illustrated on the extreme right-hand-side track of the plot (Figures 4.32-

4.34).

However within the Nubia A-S interval the gamma ray log not accurately reflect organic carbon








4.31-4.33), the values of interval transit time are high with maximum value of 126 µs/ft and low

resistivity values reaching to 23.2 Ω-m, so with plotting sonic values with resistivity values led to no

clear separation such that of the Passey method, so this interval is immature source rock, Nubia A-S,

entered the oil windows at (~5.88 Mabp Late Miocene-Messinian) and this was during deposition of

the Upper Miocene Zeit Formation and shortly after the deposition of South Gharib Formation. The

resistivity logs however have the inherent disadvantages that the signal measured is strongly maturity

dependent. First, due to oil generation with increasing maturity pores become increasingly oil

saturated, which results in an increase of resistivity (Tissot and Welte, 1984). Second, at higher

maturity as oil is cracked to gas which can be expelled, resistivity decreases. Low resistivity therefore

can indicate both immature and over mature oil source rock as well as gas- only source rocks.

Because of this maturity dependence, resistivity logs are not well suited for organic facies

determination but have values as maturity indicator (Smagala, 1984). However they can be used to

recognize source rock quality variations in sections of similar lithology within the oil generation

maturity zone. This different log pattern of Nubia A-S may be caused by two types of sedimentary

input: one with a more prolific and one with a poorer source area. The interval called Nubia A-S is a

source rock with total organic carbon of 1.03wt% and hydrogen index of 167 and is classified as



BM-57Scale : 1 : 600


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

L. Cretaceous (Cenomanian)

Permo-Carboniferous

Raha

Nubia

Rah

a-P

Nub

ia-A

-P1

Nub

ia-A

-S1

Nub

ia-A

-P2

Nub

ia-A

-S2

Nub

ia-A

-P3

Nub

ia-A

-S3

Nub

ia-A

-P4

Nub

ia-B

-P

2950

3000

3050

3100

3150

Nubia FM. (Top @ 2932.6 M)Sandstone: Kaolinite 30%.Shale.

Nubia A-S, is immature source rock, as there is no separation between the sonic log and the resistivity

log.

Figure 4.32: The corrected log datasets through a Shale and Sandstone sequences of the Early Cretaceous Nubia-A Formation (2988 m and 3129 m) of the BM-57 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.



BM-36Scale : 1 : 600


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

L. Cretaceous (Turonian-Cenomanian)

Early Creataceous

Wata-Raha

Nubia

Nub

ia-A

PN

ubia

-A-S

2950

3000

3050

3100

Nubia FM. (Top @ 2909 M)Sandstone: Kaolinite, slightlycalcareous cement, kaolinite up to30% in Nubia-C.Shale."




BM-65Scale : 1 : 600


Age Fm Zone Depth

DEPTH(M)

Gamma

GR (API)0. 150.

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)2.95 1.95

DT (US/F)140. 40.

Dt

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

L. Cretaceous Nubia

AN

ubia

A-S

B

3200

3250

Nubia FM. (Top @ 3124 M)Sandstone: Kaolinite, High

Gluconite.Black Shale.


4.4.3.2 Maturity and hydrocarbon generation of Nubia-A Formation

The Early Cretaceous Nubia-A Formation was penetrated at eight wells at depths range between

2835m (TVDss) at BM-24 well and 3907m (TVDss) at 113-M-27 well. The maximum penetrated

thickness of the entire Early Cretaceous Nubia-A Formation ranges from 64m at BM-70 well to 225m

at BM-23 well. The organic-rich interval has been differentiated based on well logging interpretation

(Figures 4.32, 4.33, and 4.34) and confirmed by geochemical analysis (Figure 4.15). The organic rich

interval, namely Nubia A-S and located at wells 113-M-27, BM-36, and BM-65 well, but in BM-57 well,

there are three organic-rich intervals, namely Nubia A-S1, Nubia A-S2 and Nubia A-S3. The present-

day depth to top ranges between 2931m (TVDss) at BM-36 and 3933m (TVDss) at 113-M-27 well with



total thickness ranges between 45m at 113-M-27 well and 164m at BM-36 well. It assigned to pre-rift

sediments of shale organic rich interval that deposited in shallow marine depositional environment and

classified as type II-III kerogen with an excellent generation potential for liquid hydrocarbons (oil

prone type II-B – type III kerogen) (Figure 4.15). It is characterized by fairly total organic carbon

(TOC) value of ~1.03wt% and by immature Type II-type III kerogen at BM-57 well (Figures 4.62 and

Table 4.18) and an early-mature type II kerogen intervals at BM-36 and BM-65 wells) (Figures 4.65

and 4.67), but mature at single well, 113-M-27 well, (Figure 4.71). At BM-65 well, the analyzed

intervals appear to have fair potential for gas and oil generation, at the present level of thermal

maturity (Abu Al-Atta et al., 2014). For the numerical basin modeling, intervals with present-day TOC

values below 0.5wt% for oil-prone source rocks and 0.8wt% TOC for gas-prone source rocks were

considered to have negligible petroleum generation potential because the kerogen in such lean rocks

is often highly oxidized.

The relatively high hydrogen index of 167 mgHC/gTOC and low oxygen index 86 mgCO2/gTOC, S2


confirm the kerogen as type II-type III that considered mainly as oil generative interval (Figures 4.14,

4.15 and Table 4.18).

The organic-rich interval of the Nubia A Formation in Belayim Marine Oil Field concession, Nubia A-S,

entered the oil windows close to the Late Miocene-Messinian ~6.6 Mabp during the deposition of the

Zeit Formation, and has been in the wet gas windows (gas onset) since (~3.5 Mabp Pliocene-

Piacenzian) during the deposition of the Post-Zeit Formation and shortly after the Messinian Event

Time (~5.2 to ~4 Mabp). The oil windows depths range between 2450m (~6.6 Mabp Late Miocene-

Messinian) at 113-M-27 well to 3204m (~0.89 Mabp Pleistocene-Calabrian) at BM-36 well and before

the maximum burial was reached at the present day (Figures 4.71 and 4.65). In addition, the oil

window depth at BM-65 well is 3128m (~2.4 Mabp Pleistocene-Gelasian) (Figure 4.67). The oil

window is shallower and older in age (Late Miocene-Messinian) of mature source rock interval at 113-

M-27 well in comparison to that early mature source rock interval at BM-36 well, which are relatively

deeper and younger in age (Figures 4.71 and 4.65). The gas (gas generation onset) reached only at

single well 113-M-27 at depth 3255m (~3.5 Ma Pliocene-Piacenzian). The present-day depth of the

Nubia A-S is in the range in which a single-phase fluid (Medium oil) might be expected.

Petroleum generation started at a vitrinite reflectance of 0.56%, which is reached at different age and

depth throughout the area, at (~6.6 Mabp Late Miocene-Messinian) at 113-M-27 well with a

corresponding temperature of 100°C (Figures 4.43 and 4.59). Moreover, at BM-65 well the maximum

simulated vitrinite reflectance value of 0.61% since (~2.4 Mabp Pleistocene-Gelasian) with a

corresponding temperature of 110°C (Figures 4.40 and 4.56). Furthermore, at BM-36 well the

simulated vitrinite reflectance value of 0.60% since (~0.89 Mabp Pleistocene-Calabrian) with a

corresponding temperature of 106°C (Figures 4.39 and 4.55). With increasing maturity the generation

of gas from both kerogen (primary cracking) and already generated but unexpelled oil (secondary

cracking) increases by breaking of carbon-carbon bonds (Dow, 1977), (Horsfield et al., 1991) and

(Behar et al., 1995). The simulated gas-onset vitrinite reflectance value is 0.79% since (~3.5 Ma



Pliocene-Piacenzian) at 113-M-27 well with a corresponding temperature of 135°C (Figures 4.43 and

4.59).



rich interval of Nubia A Formation, Nubia A-S. The present-day maximum simulated vitrinite

reflectance value is 0.91% at 113-M-27 well with a corresponding highest present day temperature of

137°C (Figure 4.43). However, the present-day minimum simulated vitrinite reflectance value of

0.53% at BM-57 well with a corresponding temperature of 96°C (Figure 4.37). These variations in

maturity are mainly related to the deposition of the maximum thickness of Post-Zeit, Zeit, Kareem,

Upper Rudeis, Thebes, Matulla, and Raha formations at 113-M-27 well. On the other hand, at BM-57

well are mainly related to the deposition of minimum thickness of the Post Zeit, Zeit, Kareem, and

Upper Rudeis formations.

The simulated vitrinite reflectance of the oil generation with a corresponding temperature values

increase from 0.56% Ro and 100°C (~6.6 Mabp Late Miocene-Messinian) at 113-M-27 during the

deposition of Zeit Formation to 0.61%Ro and 110°C (~2.4 Mabp Pleistocene-Gelasian) during the

deposition of Post-Zeit Formation and continuously increased to present day values.


well mainly after the deposition of Post-Zeit Formation whereas the maximum present day bulk

generation mass ranges between 0.06 Mtons at BM-36 well to 0.12 Mtons at 113-M-27 well (Figures

4.47 and 4.51), Additionally the present day transformation ratio at BM-65 well is 27.88% and present

day bulk generation mass is 0.09 Mtons (Figure 4.48).

The expulsion of the hydrocarbons occurred mainly after the generation of the gas and during the

deposition of Post-Zeit Formation. The first expulsion occurred at (~3 Mabp Pliocene-Piacenzian after

the generation of the gas and during the deposition of Post-Zeit Formation) at 113-M-27 well. The

present day expulsion value of 0.01 Mtons HC at 113-M-27 well. On the other hand there is no

expulsion at wells BM-36, BM-57, and BM-65 well. The sum of generated hydrocarbons ranges

between 0.06 Mtons at BM-36 well and 0.12 Mtons at 113-M-27 well, with a significant amount of

about 0.09 Mtons at BM-65 well. Rocks with lower percentages of organic carbon may not be able to

expel the generated oil, possibly due to the adsorption of the hydrocarbon molecules on minerals

(Littke et al., 1997). The resultant low expulsion efficiency causes a preservation of hydrogen until gas

is generated by cracking of the trapped bitumen at more elevated maturity stages (Littke and

Leythaeuser, 1993). Oil generation windows started during the deposition of Zeit Formation. The oil

generation window is at about 4500-5000m, the base at 5800-6000 m. Peak oil generation was

attained 8-4 mio. y. ago, after the deposition of the evaporites (Shahin and Shehab, 1984), (Barnard,

1992), (Shawky et al., 1992) and (Mostafa et al., 1993). At 113-M-27 well, the organic rich interval

Nubia A-S, located at depth of 3933m (TVDss), and it is classed as mature source rock which is

related to burial. The hydrocarbon generation mainly related to basin burial rather than basin

evolution. The oil window started at (~6.6 Mabp Late Miocene-Messinian) during the deposition of

Zeit Formation at oil windows depth of 2450m (TVDss). Moreover, the effect of the maximum

thickness of Zeit 750m, Upper Rudeis 402m, Thebes 237m and Matulla 128m formations.



At BM-65 well, the organic rich interval Nubia A-S, located at depth 3164m (TVDss) and classed as

early mature source rock which is related to basin burial. The hydrocarbon generation mainly related

to basin burial rather than basin evolution, the oil window started at (~2.4 Mabp Pleistocene-Gelasian)

during the deposition of Post-Zeit Formation at oil windows depth of 3128m (TVDss). Although the

maximum thicknesses of the Belayim Formation 503m, South Gharib Formation 538m and Zeit

Formation 786m has been recorded. Furthermore, the misplaced of different rock units that

represented by the Sudr, Duwi, Matulla, Wata, and Raha formations. At BM-36 well, the organic rich

interval Nubia A-S, located at depth 2931m (TVDss) and characterized by early to mature source rock

which is mainly related to basin burial. The hydrocarbon generation mainly related to basin burial

rather than basin evolution, the oil window started at (~0.89 Mabp Pleistocene-Calabrian) during the

deposition of Post Zeit Formation. This maturity related to exchange of basin burial and basin

evolution is due to both the minimum thickness of the Belayim Formation 132m and low thickness of

the South Gharib Formation 478m. The hydrocarbon generation of Nubia A-S is mainly related to

basin burial. This indicates that the maturity of the organic-reach intervals of Nubia A-S is closely

related to burial with a minor heat flow influence. Hydrocarbon generation is mainly related to

exchange of burial, particularly due to deposition of the Zeit and Post-Zeit formations.

On the other hand, at BM-57 well, the organic rich interval of Nubia A Formation at BM-57 well is

classed as immature source rock related to basin burial due to the shallower depths of Nubia A-S1 at

2988m (TVDss), Nubia A-S2 at 3039m (TVDss), Nubia A-S3 at 3069m (TVDss), in addition to the

minimum thickness of the Post Zeit Formation 797m, Zeit Formation 665m, and Upper Rudeis

Formation 141m. This means that the source rock will have to be buried to greater depths in the area

to generate oil, all other factors being the same.

The gas onset generation mainly related to basin burial with basin evolution effect. At 113-M-27 well,

the gas generation onset started at (~3.5 Mabp Pliocene-Piacenzian) at depth 3255m (TVDss) during

the deposition of Pos-Zeit Formation and shortly after both uplift and erosion that followed the

Messinian Time Event (~5.2 to ~4 Mabp Pliocene-Zanclean), the basin wide unconformities formed

primarily in response to regional tectonic adjustments associated with different rift phases of the Gulf

of Suez (Dolson et al., 2001).

The expulsion of hydrocarbon mainly related to basin burial. At 113-M-27 well, the hydrocarbon

expulsion started since (~3 Mabp Pliocene-Piacenzian) during the deposition of Post-Zeit Formation, at

relatively deeper depth 3501m (TVDss) with simulated vitrinite reflectance value of 0.80% and a

corresponding temperature value of 137°C. The sum of generated hydrocarbons at 113-M-27 well is

0.12Mtons and mainly accumulated in the source rock (slightly adsorbed by the organic matter in the

source). However, in the wells (BM-36 and BM-65, there is no expulsion due to the generated

hydrocarbons mainly accumulated in the source rock and mostly adsorbed by organic matter.








4.4.4 Nubia B Formation



(TVDss) at BM-65 well represents the Nubia B-S Formation. The Nubia B-S has gamma ray range from



145 µs/ft), density log ROHB trace values range (2.19-2.7 g/c3) all of these are accompanied with

high resistivity log values (Trace LLD averaged value 18.3-21.8 Ω-m). The log readings indicate Shale

and Sandstone lithological nature that prevail nearly the entire section of the Nubia B-S Formation.

This is clearly illustrated on the extreme right-hand-side track of the plot (Figures 4.35-4.36).

However within the Nubia B-S interval the gamma ray log not accurately reflect organic carbon








4.35-4.36), the values of interval transit time are high with value of 91 µs/ft and low resistivity values

reaching to 18.3 Ω-m, so with plotting sonic values with resistivity values led to no clear separation

such that of the Passey method, so this interval is immature source rock, Nubia B-S, entered the oil

windows at (~ 6.6 Mabp Late Miocene-Messinian) and this was during deposition of the Upper

Miocene Zeit Formation and shortly after the deposition of South Gharib Formation. The resistivity logs








variations in sections of similar lithology within the oil generation maturity zone. This different log

pattern of Nubia B-S may be caused by two types of sedimentary input: one with a more prolific and

one with a poorer source area. The interval called Nubia B-S is a source rock with total organic carbon

of 2.62wt% and hydrogen index of 268 and is classified as Nubia B-S, is immature source rock, as

there is no separation between the sonic log and the resistivity log.



BM-65Scale : 1 : 600


Age Fm Zone Depth

DEPTH(M)

Gamma Ray

GR (API)0. 150.

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)2.95 1.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Remarks

Lithology

L. Cretaceous Nubia

BN

ubia

B-S

C

3300

3350

Nubia B FM.(Top @ 3268 M)

Black Shale.Sandstone: Kaolinite, High

Gluconite.

Figure 4.35: The corrected log datasets through a Shale and Sandstone sequences of the Carboniferous Nubia-B Formation (3297 m and 3342 m) of the BM-65 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.



BM-24Scale : 1 : 600


Age Fm Member Zone Gamma Ray

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Shale

Shale

Remarks

Lithology

Carboniferous-Early CretaceousNubia

AB

C

Nubia B-S1

Nubia B-S2

3000

3050

3100

Nubia FM. (Top @ 2834.5 M)Sandstone: Glauconitic, Pyritic,Slightly calcareous cement,(Kaolinitic in Nubia-B,C).Shale: Pyritic, non calcareous."

Figure 4.36: The corrected log datasets through a Shale and Sandstone sequences of the Early Cretaceous Nubia-B Formation (3018 m and 3094 m) of the BM-24 well drilled by the Belayim Petroleum Company (Petrobel), showing the zone–wise representation of the well logging deduced lithological parameters and organofacies.

4.4.4.2 Maturity and hydrocarbon generation of Nubia-B Formation

The Carboniferous Nubia "B" Formation was penetrated at seven wells at depths range between

3005m (TVDss) at BM-24 well and 4002m (TVDss) at 113-M-27 well. The penetrated thicknesses

range from 74m to 165m at BM-65 well and 113-M-34 well, respectively.

A single organic-rich interval has been differentiated based on well logging interpretation (Figures

4.35 and 4.36) and confirmed by geochemical analysis (Figure 4.14 and 4.15), namely Nubia B-S. The

organic rich interval Nubia B-S is located at five wells 113-M-27, BM-36, BM-65, BM-57, and at BM-24

well. The present-day depth to top ranges between 3036m (TVDss) at BM-24 and 4002m (TVDss) at

113-M-27 well with total thickness ranges between 45m at BM-65 well and 93m at BM-36 well for



Nubia B-S. The thickness of the individual units varies greatly because of the irregular topography of

the underlying block-faulted early Miocene (Fichera et al., 1992).


depth of 3018m (TVDss) at BM-24 well (Figure 4.36). It assigned to pre-rift sediments of shale

organic rich interval that deposited in shallow marine depositional environment and classified as type

II-III kerogen with an excellent generation potential for liquid hydrocarbons (oil prone type II-B –

type III kerogen) (Figure 4.14 and 4.15). It is characterized by a relatively remaining high total

organic carbon (TOC) value of ~2.62wt% and by immature-early mature Type II-III kerogen at BM-

57 well (Figures 4.62 and Table 4.18) and an early-mature type II-III kerogen intervals at BM-36 and

BM-65 wells) (Figure 4.65 and 4.67) but mature at wells, BM-24 and 113-M-27 well, (Figure 4.68 and

4.71). The analyzed samples contain both marine and terrestrial organic matter with variable but

nearly equal proportions (Abu Al-Atta et al., 2014). The black shale of the Nubia-B is considered as

the mature potential source rock of the Nubia reservoir (Younes, 1991). The analyzed interval show

both marine and terrestrial organic matter, with the marine component dominating in most samples

and decreasing generally with depth (Abu Al-Atta et al., 2014).

The Devonian sandstone is overlain by the Early Carboniferous marine black shales of the Nubia B.

They appear to be poor source rock due to their low content of organic matter and because they are

highly indurate (Schlumberger, 1984). In general, TOC analyses showed that the Nubia-A and B

formations sediments are immature fair to good source rocks with very high Hydrogen Index

indicative of kerogen type II (Abu Al-Atta et al., 2014).

The analyzed interval contains both marine and terrestrial organic matter with variable but nearly

equal proportions and suggesting that the analyzed carboniferous rock in BM-57 well are past the oil

floor (defined by 1.35 % R0), and has probably reached maturities grater than 1.7% R0 (Abu Al-Atta

et al., 2014). In BM-65 well, the analyzed intervals appear to have fair potential for gas and oil

generation, at the present level of thermal maturity (Abu Al-Atta et al., 2014).




The slightly high hydrogen index of 268 mgHC/gTOC and low oxygen index 52 mgCO2/gTOC, S2


confirm the kerogen as type II-III that considered mainly as oil and/or gas generative interval

(Figures 4.14, 4.15 and Table 4.18).

The organic-rich interval of the Nubia B Formation in Belayim Marine Oil field concession, Nubia B-S,

entered the oil windows close to (the Late Miocene-Messinian ~6.6 Mabp) during the deposition of the


Zanclean) at 113-M-27 well (Figure 4.71). The oil windows depths range between 2307m (~6.6 Mabp

Late Miocene-Messinian) at BM-24 well to 3251m (~0.91 Mabp Pleistocene-Calabrian) at BM-57 well

and before the maximum burial was reached at the present day (Figure 4.68 and 4.62).

The oil window is shallower and older in age (~ 6.6 Mabp Late Miocene-Messinian) at BM-24 well in

comparison to that immature to early-mature source rock interval at BM-57 well, which are relatively



deeper and younger in age (Figures 4.68-4.62). The gas (gas generation onset) reached at depths

range between 3190m (~4.6 Mabp Pliocene-Zanclean) at 113-M-27 well and 3499m (0.86 Mabp

Pleistocene-Calabrain) at BM-24 well. The present-day depth of the Nubia B-S is in the range in which

a single-phase fluid (Medium oil) might be expected.

Petroleum generation started at a vitrinite reflectance of 0.60%, which is reached at different age and

depth throughout the area (Figures 4.43 and 4.59), (~6.6 Mabp Late Miocene-Messinian) at 113-M-27

well at a temperature of 104°C. At BM-57 well the vitrinite reflectance value of 0.57% is reached since

(~0.91 Mabp Pleistocene-Calabrian); at a corresponding paleo-temperature of 103°C (Figures 4.37

and 4.53). With increasing maturity the generation of gas from both kerogen (primary cracking) and

already generated but unexpelled oil (secondary cracking) increases by breaking of carbon-carbon

bonds (Dow, 1977), (Horsfield et al., 1991) and (Behar et al., 1995). The gas-onset vitrinite

reflectance value is 0.79% at (~4.6 Mabp Pliocene-Zanclean) in 113-M-27 well with a temperature of

136°C whereas at BM-24 well the vitrinite reflectance value of 0.78% with a corresponding

temperature of 124°C was reached at (~0.86 Mabp Pleistocene-Calabrian) (Figures 4.43, 4.59, 4.41

and 4.57).



rich interval of Nubia B Formation, Nubia B-S. The present-day maximum simulated vitrinite

reflectance value 0.96% at 113-M-27 well corresponds to a present day temperature of 141°C (Figure

4.43). However, the present-day minimum simulated vitrinite reflectance value of 0.60% at BM-57

well corresponds to a temperature of 105°C (Figure 4.37). These values reached due to basin burial

particularly after the deposition of thick Pliocene Post-Zeit Formation. These variations in maturity are

mainly related to the deposition of the maximum thickness of Post-Zeit, Zeit, Kareem, Upper Rudeis,

Thebes, Matulla, and Raha formations at 113-M-27 well. On the other hand, at BM-57 well are mainly

related to the deposition of minimum thickness of the Post Zeit, Zeit, Kareem, and Upper Rudeis

formations.

The simulated vitrinite reflectance of the oil generation and the corresponding temperature values

increase from 0.57% Ro and 103°C (~0.91 Mabp Pleistocene-Calabrian) during the deposition of Post-

Zeit Formation) at BM-57 well to 0.60%Ro and 104°C (~6.6 Mabp Late Miocene-Messinian) during the

deposition of Zeit Formation at 113-M-27 well.


well mainly after the deposition of Post-Zeit Formation, whereas the present day bulk generation mass

ranges between 0.14 Mtons at BM-57 well to 0.46 Mtons at 113-M-27 well (Figures 4.45 and 4.51).

The expulsion of the hydrocarbons occurred mainly before the generation of the gas and after the

deposition of Zeit Formation and during the Messinian Event Time (~5.2 to ~4 Mabp Pliocene

Messinian) at 113-M-27 well. Whereas, there is no expulsion at BM-36, BM-57, and BM-65 wells. The

sum of generated hydrocarbons ranges between 0.14 Mtons at BM-57 well and 0.46Mtons at 113-M-

27 well. Rocks with lower percentages of organic carbon may not be able to expel the generated oil,

possibly due to the adsorption of the hydrocarbon molecules on minerals (Littke et al., 1997).



The resultant low expulsion efficiency causes a preservation of hydrogen until gas is generated by

cracking of the trapped bitumen at more elevated maturity stages (Littke and Leythaeuser, 1993).

The Peak oil generation was attained 8-4 mio. y. ago, after the deposition of the (Shahin and Shehab,

1984), (Barnard, 1992), (Shawky et al., 1992) and (Mostafa et al., 1993). Oil generation windows

started during the deposition of Zeit Formation. At 113-M-27 well, hydrocarbon generation mainly

related to basin burial rather than basin evolution. The oil window started at (~6.6 Mabp Late

Miocene-Messinian) during deposition of the Zeit Formation at oil windows depth of 2474m (TVDss).

Moreover, the effect of the maximum thickness of Zeit 750m, Upper Rudeis 402m, Thebes 237m and

Matulla 128m formations. At BM-24 well, the oil window started at (~6.6 Mabp Late Miocene-

Messinian) during deposition of the Zeit Formation at oil windows depth of 2307m (TVDss). This

means that the source rock will have to be buried to greater depths in the area to generate oil, all

other factors being the same. The variation in maturity depths may be related to the quality of

kerogen and its chemical composition.

However, at BM-36 well, the source rock interval characterized by early mature to mature that is

related mainly to basin burial (the deposition of Post-Zeit Formation) with minor effect of the basin

evolution that occurred during (the Messinian Event Time ~5.2 to ~4 Mabp). The oil windows stated

since (~3.5 Mabp Pliocene-Piacenzian) at relatively shallower depth of 2740m (TVDss). This maturity

related to exchange of basin burial and basin evolution is due to both the minimum thickness of the

Belayim Formation 132m and low thickness of the South Gharib Formation 478m. On the other hand,

the oil generation at BM-65 well is mainly related to basin evolution that occurred at (~4.6 Mabp

Pliocene-Zanclean) during (the Messinian Event Time ~5.2 to ~4 Mabp Pliocene-Zanclean) at oil

windows depth of 2854m. Although the maximum thicknesses of the Belayim Formation 503m and the

South Gharib Formation 538m has been recorded. Furthermore, the misplaced of different rock units

that represented by the Sudr, Duwi, Matulla, Wata, and Raha formations.

The commencing of gas onset generation was after the expulsion of oil expulsion at (~5.2 Mabp

Pliocene-Zanclean) at both wells BM-24 and 113-M-27. At 113-M-27 well, gas generation mainly

related to basin evolution, where started at (~4.6 Mabp Pliocene-Zanclean) during the Messinian

Event Time (~5.2 to ~4 Mabp Pliocene-Zanclean) at relatively deeper depth value of 3190m (TVDss).

The basin wide unconformities formed primarily in response to regional tectonic adjustments

associated with different rift phases of the Gulf of Suez (Dolson et al., 2001). In addition to the

subaltern basin burial influence due to the deposition of thick sediments of the Upper Miocene Zeit

Formation of 750m. By contrast, at BM-24 well, gas generation onset mainly related mainly to basin

burial whereas it commenced at (~0.86 Mabp Pleistocene-Calabrian) during deposition of the Post-Zeit

Formation at relatively deeper burial depth of 3499m (TVDss).

The expulsion of hydrocarbon started at (~5.2 Mabp) that is mainly related to basin evolution (the

Messinian Event Time ~5.2 to ~4 Mabp Pliocene-Zanclean) and before the generation of gas at two

locations 113-M-27 well and BM-24 well. Tectonic movements continued with intensity until post-

Miocene times. In the period of Mio- Pliocene boundary, there was a major uplift of the rift margins.

Rifting has not been active since 5 Mabp, and Pliocene-Pleistocene subsidence has been attributed to

thermal adjustment (Sestini, 1995). The expulsion started at relatively deeper depth 3129m (TVDss)



with simulated vitrinite reflectance value of 0.75% with a corresponding temperature value of 134°C

and a sum of generated hydrocarbons of 0.46Mtons at 113-M-27 well. The generated hydrocarbon

partially accumulated in the source rock and slightly adsorbed by the organic matter. Likewise, at BM-

24 well, the expulsion started at relatively shallower depth of 2875m (TVDss) compared to that of

113-M-27 well with simulated vitrinite reflectance value of 0.72% and a corresponding temperature

value of 129°C with a sum of generated hydrocarbons of 0.30Mtons. The generated hydrocarbon

mainly accumulated in the source rock with slightly adsorbed by the organic matter.





source rocks, in which fractures cut bedding at high angles (Littke et al., 1988). However, in the wells

BM-57, BM-36, and BM-65, there is no expulsion due to the low quantity of the generated

hydrocarbons (Figures 4.45, 4.47, and 4.48) in addition to the adsorbtion of the generated

hydrocarbon by organic matter in the source rock intervals. The resultant low expulsion efficiency

causes a preservation of hydrogen until gas is generated by cracking of the trapped bitumen at more

elevated maturity stages (Littke and Leythaeuser, 1993). This means that the source rock will have to

be buried to greater depths in the area to generate gas, all other factors being the same.

At BM-57 well, the expected expulsion temperature of 115 for the oils with a suggested thermal

maturity of about 0.75% R0 is required (Abu Al-Atta et al., 2014).

Another source rock interval at depth 3018m (TVDss) with a thickness of 6m has been distinguished

at BM-24 well (Figure 4.36). The oil windows started since (~5.65 Mabp Late Miocene-Messinian) at

oil windows depth of 2662m (TVDss) with a corresponding temperature and vitrinite reflectance

values of 117°C and 0.65%Ro, respectively. The oil generation is closely related to basin burial

particularly during the deposition of Zeit Formation with no gas generation. Moreover, the expulsion

occurred at (~1.8 Mabp Pleistocene-Calabrian) that accompanied by a relatively high bulk generation

(Figure 4.49) which is related to burial (deposition of low thickness of Post-Zeit Formation of about

772m) in addition to small thickness of the Nubia B-S1 with no effect of tectonics on expulsion.



Figure 4.37: The simulated vitrinite reflectance value and the associated thermal history of Thebes, Duwi, Nubia-A, Nubia-B formations in a reference well (BM-57) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.38: The simulated vitrinite reflectance value and the associated thermal history of Thebes Formation in a reference well (BM-70) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.39: The simulated vitrinite reflectance value and the associated thermal history of Thebes, Nubia-A and Nubia-B formations in a reference well (BM-36) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.41 The simulated vitrinite reflectance value and the associated thermal history of Nubia-B Formation in a reference well (BM-24) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.42: The simulated vitrinite reflectance value and the associated thermal history of Thebes and Duwi formations in a reference well (BM-23) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.43: The simulated vitrinite reflectance value and the associated thermal history of Thebes and Duwi Nubia-A and Nubia-B formations in a reference well (113-M-27) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.44: The simulated vitrinite reflectance value and the associated thermal history of Thebes and Duwi formations in a reference well (113-M-34) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.45: The simulated transformation ratio value and the associated bulk generation mass of Thebes, Duwi, Nubia-A and Nubia-B formations in a reference well (BM-57) against geologic time scale (Ma).



Figure 4.46: The simulated transformation ratio value and the associated bulk generation mass of Thebes Formation in a reference well (BM-70) against geologic time scale (Ma).



Figure 4.47: The simulated transformation ratio value and the associated bulk generation mass of Thebes, Nubia-A and Nubia-B formations in a reference well (BM-36) against geologic time scale (Ma).



Figure 4.48: The simulated transformation ratio value and the associated bulk generation mass of Thebes, Nubia-A and Nubia-B formations in a reference well (BM-65) against geologic time scale (Ma).



Figure 4.49: The simulated transformation ratio value and the associated bulk generation mass of Nubia-B Formation in a reference well (BM-24) against geologic time scale (Ma).



Figure 4.50: The simulated transformation ratio value and the associated bulk generation mass of Thebes, Duwi formations in a reference well (BM-23) against geologic time scale (Ma).



Figure 4.51: The simulated transformation ratio value and the associated bulk generation mass of Thebes, Duwi, Nubia-A and Nubia-B formations in a reference well (113-M-27) against geologic time scale (Ma).



Figure 4.52: The simulated transformation ratio value and the associated bulk generation mass of Thebes and Duwi formations in a reference well (113-M-34) against geologic time scale (Ma).



Figure 4.53: The simulated vitrinite reflectance value and the associated thermal history of Thebes, Duwi, Nubia-A, Nubia-B formations in a reference well (BM-57) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.54: The simulated vitrinite reflectance value and the associated thermal history of Thebes Formation in a reference well (BM-70) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.57: The simulated vitrinite reflectance value and the associated thermal history of Nubia-B Formation in a reference well (BM-24) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.58: The simulated vitrinite reflectance value and the associated thermal history of Thebes and Duwi formations in a reference well (BM-23) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.59: The simulated vitrinite reflectance value and the associated thermal history of Thebes and Duwi Nubia-A and Nubia-B formations in a reference well (113-M-27) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.60: The simulated vitrinite reflectance value and the associated thermal history of Thebes and Duwi formations in a reference well (113-M-34) against time. The calculated vitrinite reflectance value carried out using the Easy Ro% algorithm (Sweeney and Burnham, 1990) and temperature profile against geologic time scale (Ma).



Figure 4.61: The simulated burial history of well BM-57, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII-S(A) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Thebes and Duwi formations through geologic time scale (Ma).

Figure 4.62: The simulated burial history of well BM-57, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII(B) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Nubia-A and Nubia-B formations through geologic time scale (Ma).



Figure 4.63: The simulated burial history of well BM-70, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII-S(A) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Thebes Formation through geologic time scale (Ma).





Figure 4.68: The simulated burial history of well BM-24, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII(B) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Nubia-B Formation through geologic time scale (Ma).



Figure 4.69: The simulated burial history of well BM-23, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII-S(A) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Thebes and Duwi formations through geologic time scale (Ma).

Figure 4.70: The simulated burial history of well 113-M-27, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII-S(A) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Thebes and Duwi formations through geologic time scale (Ma).



Figure 4.71: The simulated burial history of well 113-M-27, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII(B) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Nubia-A and Nubia-B formations through geologic time scale (Ma).

Figure 4.72: The simulated burial history of well 113-M-34, with the hydrocarbon zone properties overlay according to the Pepper&Corvi(1995)_TII-S(A) oil-gas kinetics equation of (Pepper and Corvi, 1995) for the source interval of Thebes and Duwi formations through geologic time scale (Ma).


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Reservoir Characterization and Hydrocarbon Stability4-98

4.5 RESERVOIR CHARACTERIZATION AND HYDROCARBON

STABILITY

The sandstone intervals of Upper Rudeis and Nubia A formations represent the main important

reservoir intervals. In addition, there are secondary reservoir zones at different stratigraphic levels.

The reservoir characterizations parameters are tabulated in Table 4.19.

Table 4.19: Final calculated petrophysical parameters for each individual borehole addressed. It includes depths and thickness and IP-Interactive Petrophysics® Software deuced parameters as follow; reservoir and pay characterization parameters (includes net thickness, effective porosity, water saturation and shale volume). Well Top Bottom Gross N/G. ratio P.Net Av.Phi Av.Sw Av.Vcl Phase Zone

2026 2040 13.49 12.36 0.917 0.292 0.27 0.031 oil

Belayim-

Hammam

Faraun-P

2424 2456 32 10.59 0.331 0.15 0.306 0.141 oil Rudeis-P1

2480 2550 70 13.35 0.191 0.120 0.206 0.085 oil Rudeis-P2

2831 2866 35.54 22.86 0.643 0.202 0.197 0.075 oil Matulla-P

2907 2933 25.6 13.2 0.516 0.184 0.357 0.061 oil Raha-P

2933 2988 55.4 30.30 0.547 0.218 0.276 0.025 oil Nubia-A-P1

3030 3039 9 6.96 0.774 0.239 0.233 0.029 oil Nubia-A-P2

3056 3069 13 8.76 0.674 0.221 0.222 0.054 oil Nubia-A-P3

BM-57

3129 3144 15.6 14.25 0.913 0.220 0.216 0.028 oil Nubia-A-P4

2984 3003 19 17.51 0.922 0.080 0.364 0.41 oil Rudeis-P BM-70

3340 3346 6 5.55 0.925 0.151 0.114 0.167 oil Thebes-P

2475 2489 13.5 4.25 0.315 0.182 0.558 0.075 oil Rudeis-P1

2556 2621 64.8 29.75 0.459 0.182 0.503 0.120 oil Rudeis-P2

2846 2894 47.8 25 0.523 0.177 0.341 0.088 oil Matulla-P

2894 2909 15 5.55 0.370 0.165 0.361 0.082 oil Wata-P

BM-36

2909 2931 21.7 10.95 0.505 0.173 0.507 0.068 oil Nubia-A-P

2746 2754 8.23 5.79 0.704 0.265 0.221 0.080 oil Wata-P

2834 2875 40.05 21.18 0.529 0.135 0.279 0.029 oil Nubia-A-P1

2916 2923 7.62 2.36 0.310 0.191 0.408 0.044 oil Nubia-A-P2

BM-24

2983 3005 22.42 12.04 0.536 0.148 0.404 0.011 oil Nubia-A-P3

2766 2771 5 2.74 0.545 0.161 0.231 0.005 oil Rudeis-P1

2810 2818 7 0.76 0.104 0.139 0.286 0.008 oil Rudeis-P2 BM-23

3176 3191 15.09 12.5 0.828 0.169 0.361 0.036 oil Matulla-P

Top: depth to the top (m); Bottom: depth to the bottom (m); Gross: the total thickness of the zone (m); N/G. ratio: Net pay / gross thickness ratio;P.Net: thickness of the pay zone (m); Av.Phi: average porosity (%); Av.Sw: average water saturation (%); Av.Vcl: average volume of shale (%);and Phase: hydrocarbon phase (oil or gas).

4.5.1 Belayim Formation (Hammam Faraun)

The zones of interest for the petrophysical interpretation were defined in terms of clean zones with

hydrocarbon saturation (low GR 18-40 API and high resistivity 12.4 Ω-m) high interval transit time

(trace DT) of about 134 Ms/ft on the sonic log, as well as two water zones used to calculate water

resistivity at formation temperature, which is necessary to calculate water saturation. Areas shaded in

red in (Figure 4.73) indicate pay zones, interpreted from crossover of the DT log R logs (Figure 4.73)


Reservoir Characterization and Hydrocarbon Stability4-99

BM-57Scale : 1 : 60


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt

LLD (OHMM)0.2 2000.

DTLF (US/F)140. 0.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Middle Miocene Belayim

Bel

ayim

-Sea

lB

elay

im-H

F-P

2030

2040

based on high resistivity values, green shaded areas correspond to reservoir zones, based on high

resistivity values, and white shaded areas, (Figure 4.73) correspond to water zones (very low

resistivities).

Figure 4.73: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Belayim Formation (Hammam Faraun Member) (2026-2040 m TVDss) of the BM-57 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.

The BM-57 well reached a total vertical depth of 3600 m TVDss. The Bottom Hole Temperature (BHT)

is 82.2°C. Hammam Faraun Member of Belayim Formation reached at 2026 m TVDss. Reservoir rock

is of post-rift succession of Belayim Formation, zone Hammam Faraun-Pay (oil-bearing zone), (Table

4.19). At BM-57 well, the zone Hammam Faraun-P, at depth 2026 m TVDss and a total thickness of 14

m, with average porosity of 29% and Vcl 3% and Sw of 27%. Aerobic bacteria may degrade

petroleum if the temperature is not high (<80°C). There is evidence of anaerobic biodegradation in

anoxic oil reservoirs (Connan J. et al., 1996). The reservoir thermal history, based on well calibrated

model, (Figure 4.89) is more than 80°C, which may suggest as no effect of biodegradation and



BM-57Scale : 1 : 600


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Middle Miocene

Lower Miocene

Kareem

Rudeis

Rud

eis-

P1

Rud

eis-

Sea

lR

udei

s-P

2R

ude

is-S

hale

2450

2500

2550

suggests a thermodynamically stable crude oil without any possibility to secondary cracking gas

generation.

4.5.2 Rudeis oil-bearing zone

The Rudeis pay zones of interest for the petrophysical interpretation were defined in terms of clean

zones with hydrocarbon saturation (low GR 10-84 API and high resistivity 44 ohm-m) high interval

transit time (trace DT) of about 155 Ms/ft on the sonic log, as well as two water zones used to

calculate water resistivity at formation temperature, which is necessary to calculate water saturation.

Areas shaded in red in (Figures 4.74, 4.75, 4.76, 4.77, and 4.78) indicate pay zones, interpreted from

crossover of the DT log R logs (Figures 4.74, 4.75, 4.76, 4.77, and 4.78) based on high resistivity

values, green shaded areas correspond to reservoir zones, based on high resistivity values, and white

shaded areas, Figures 4.74, 4.75, 4.76, 4.77, and 4.78) correspond to water zones (very low

resistivities).

Figure 4.74: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Rudeis Formation (Rudeis-P1 and Rudeis-P2) (2424-2456 m and 2480-2550 m TVDss, respectively) of the BM-57 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.



BM-70Scale : 1 : 200


Age Fm Zone Gamma

GR (gAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Lower Miocene Rudeis

Rud

eis-

P

3000

BM-24Scale : 1 : 600


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Temp

Temp (C)0. 300.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Miocene Rudeis

Rud

eis-

P

2450

Figure 4.75: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Rudeis Formation (Rudeis-P 2984-3005 m TVDss) of the BM-70 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.

Figure 4.76: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Rudeis Formation (Rudeis-P 2410-2466 m TVDss) of the BM-24 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software



BM-36Scale : 1 : 600


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Miocene

Eocene

Rudeis

Thebes

Rud

eis-

P1

Rud

eis-

P2

Theb

es-S

2500

2550

2600




BM-23 STScale : 1 : 200

DEPTH (2764.99M - 2820.M) 8/23/2014 14:24DB : IP Folder Master Final (1)


GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Miocene Rudeis

Rud

ies-

P1

Rud

ies-

P2

2775

2800



is 89°C. Upper Rudeis Formation reached at 2424 m TVDss. Reservoir rock is of post-rift succession of

Upper Rudeis Formation, zone Upper Rudeis-P, (oil-bearing zone), (Table 4.19). At BM-57 well, the

zone U. Rudeis-P1, at depth 2424 m TVDss and a total thickness of 32 m, with average porosity of

15% and Vcl 14% and Sw of 30%. U. Rudeis-P2, at depth 2480 m TVDss and a total thickness of 70

m, with average porosity of 12% and Vcl 8% and Sw of 20%. The reservoir thermal history, based on

well calibrated model, (Figure 4.89) is more than 80°C, which may suggest no biodegradation effect



and suggests a thermodynamically stable crude oil without any possibility to secondary cracking gas

generation.


is 104°C. Upper Rudeis Formation reached at 2792 m TVDss. Reservoir rock is of post-rift succession

of Upper Rudeis Formation, zone U. Rudeis-P, (oil-bearing zone), (Table 4.19). At BM-70 well, the

zone U. Rudeis-P, at depth 2984 m TVDss and a total thickness of 19 m, with average porosity of 8%

and Vcl 4% and Sw of 36%. Geochemistry of two crude oil samples from the Wells BM-29 and BM-70,

which are located within the Belayim Marine Oil Field of the mid-eastern section of the Gulf of Suez,

Egypt; are analyzed. The two samples are recovered from the Upper Rudeis Formation. The two oil

samples are highly similar in composition and represent medium mature oils, and were derived from a

common marine source which is relatively rich in carbonate and contains algal organic matter (Abu Al-

Atta et al., 2014). The reservoir thermal history, based on well calibrated model, (Figure 4.90) is more

than 80°C that retreated the biodegradation effect and suggests a thermodynamically stable crude oil

without any possibility to secondary cracking gas generation.


is 82-88°C. Upper Rudeis Formation reached at 2439 m TVDss. Reservoir rock is of post-rift

succession of Upper Rudeis Formation, zone U. Rudeis-P, (oil-bearing zone), (Table 4.19). At BM-36

well, the zone U. Rudeis-P1, at depth 2475 m TVDss and a total thickness of 14 m, with average

porosity of 18% and Vcl 7% and Sw of 55%. The zone U. Rudeis-P2, at depth 2556 m TVDss and a

total thickness of 65 m, with average porosity of 18% and Vcl 12% and Sw of 50%. The reservoir

thermal history, based on well calibrated model, (Figure 4.91) is more than 80°C that retreated the

biodegradation effect and suggests a thermodynamically stable crude oil without any possibility to

secondary cracking gas generation.


is 80°C. Upper Rudeis Formation reached at 2373 m TVDss. Reservoir rock is of post-rift succession of

Upper Rudeis Formation, zone U. Rudeis-P, (oil-bearing zone), (Table 4.19). The reservoir thermal

history, based on well calibrated model, (Figure 4.92) is more than 80°C that retreated the




is 94-96°C. Upper Rudeis Formation reached at 2686 m TVDss. Reservoir rock is of post-rift

succession of Upper Rudeis Formation, zone U. Rudeis-P, (oil-bearing zone), (Table 4.19). At BM-23

well, the zone U. Rudeis-P1, at depth 2766 m TVDss and a total thickness of 5 m, with average

porosity of 16% and Vcl 5% and Sw of 23%. The zone U. Rudeis-P2, at depth 2810 m TVDss and a

total thickness of 8 m, with average porosity of 14% and Vcl 8% and Sw of 29%The reservoir thermal

history, based on well calibrated model, (Figure 4.93) is more than 80°C that retreated the





BM-70Scale : 1 : 60


Age Fm Zone Gamma

GR (gAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Eocene Thebes

Th

ebes

-S1

The

bes-

PT

heb

es-S

2

3340

4.5.3 Thebes Formation

The Thebes pay zone of interest for the petrophysical interpretation were defined in terms of clean

zones with hydrocarbon saturation (low GR 21 API and high resistivity 5764 ohm-m) high interval



Areas shaded in red in (Figure 4.79) indicate pay zones, interpreted from crossover of the DT log R

logs (Figure 4.79) based on high resistivity values, green shaded areas correspond to reservoir zones,

based on high resistivity values, and white shaded areas, (Figure 4.79) correspond to water zones

(very low resistivities).

Figure 4.79: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Thebes Formation (Thebes-P) (3340-3346 m TVDss) of the BM-70 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.


is 118.33°C. Thebes Formation reached at 3263 m TVDss. Reservoir rock is of pre-rift succession of

Thebes Formation, zone Thebes-P, (oil-bearing zone), (Table 4.19). At BM-70 well, the zone Thebes-

P, at depth 3340 m TVDss and a total thickness of 6 m, with average porosity of 15% and Vcl 17%

and Sw of 11%. The reservoir thermal history, based on well calibrated model, (Figure 4.90 is more

than 80°C that retreated the biodegradation effect and suggests a thermodynamically stable crude oil




BM-57Scale : 1 : 200


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Remarks



Matulla

Raha

Mat

ulla

-Sea

lM

atul

la-P

Rah

a-S

eal

2850

4.5.4 Matulla Formation

The Matulla pay zone of interest for the petrophysical interpretation were defined in terms of clean

zones with hydrocarbon saturation (low GR 20 API and high resistivity 6644 ohm-m) high interval



Areas shaded in red in (Figures 4.80, 4.81 and 4.82) indicate pay zones, interpreted from crossover of

the DT log R logs (Figures 4.80, 4.81 and 4.82) based on high resistivity values, green shaded areas

correspond to reservoir zones, based on high resistivity values, and white shaded areas, (Figures 4.80,

4.81 and 4.82) correspond to water zones (very low resistivities).

Figure 4.80: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Matulla Formation (Matulla-P) (2831-2866 m TVDss) of the BM-57 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.


is 100°C. Matulla Formation reached at 2772 m TVDss. Reservoir rock is of pre-rift succession of

Matulla Formation, zone Matulla-P, (oil-bearing zone), (Table 4.19). At BM-57 well, the zone Matulla-P,



BM-36Scale : 1 : 240


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.



Matulla

Wata-Raha

Mat

ulla

-P

2850

2875

at depth 2831 m TVDss and a total thickness of 35 m, with average porosity of 20% and Vcl 7% and

Sw of 19%. The reservoir thermal history, based on well calibrated model, (Figure 4.89) is more than

80°C that retreated the biodegradation effect and suggests a thermodynamically stable crude oil




is 98.5°C. Matulla Formation reached at 2816 m TVDss. Reservoir rock is of pre-rift succession of








BM-23 STScale : 1 : 100


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

L. Cretaceous (Lower Senonian)Matulla

Mat

ulla

-P

3175



is 111°C. Matulla Formation reached at 3085 m TVDss. Reservoir rock is of pre-rift succession of








BM-36Scale : 1 : 100


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutof f

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.



Early Creataceous

Matulla

Wata-Raha

Nubia

Mat

ull

a-P

Wat

a-P

Nu

bia-

A P

2900

4.5.5 Wata Formation

The Wata pay zones of interest for the petrophysical interpretation were defined in terms of clean

zones with hydrocarbon saturation (low GR 19 API and high resistivity 83 ohm-m) high interval transit

time (trace DT) of about 120 Ms/ft on the sonic log, as well as two water zones used to calculate

water resistivity at formation temperature, which is necessary to calculate water saturation. Areas

shaded in red in (Figures 4.83 and 4.84) indicate pay zones, interpreted from crossover of the DT log

R logs (Figures 4.83 and 4.84) based on high resistivity values, green shaded areas correspond to

reservoir zones, based on high resistivity values, and white shaded areas, (Figures 4.83 and 4.84)

correspond to water zones (very low resistivities).

Figure 4.83: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Wata Formation (Wata-P) (2894-2909 m TVDss) of the BM-36 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.


is 99.8°C. Wata Formation reached at 2894 m TVDss. Reservoir rock is of pre-rift succession of Wata

Formation, zone Wata-P, (oil-bearing zone), (Table 4.19). At BM-36 well, the zone Wata-P, at depth

2894 m TVDss and a total thickness of 15 m, with average porosity of 16% and Vcl 8% and Sw of

36%. The reservoir thermal history, based on well calibrated model, (Figure 4.91) is more than 80°C



BM-24Scale : 1 : 100



GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Cutof f

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

L. Cretaceous (Turonian) Wata

Wat

a-P 2750

that retreated the biodegradation effect and suggests a thermodynamically stable crude oil without

any possibility to secondary cracking gas generation.

Figure 4.84: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Wata Formation (Wata-P) (2746-2754 m TVDss) of the BM-24 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.


is 93.7°C. Wata Formation reached at 2682 m TVDss. Reservoir rock is of pre-rift succession of Wata

Formation, zone Wata-P, (oil-bearing zone), (Table 4.19). At BM-24 well, the zone Wata-P, at depth





4.5.6 Raha Formation

The Raha pay zones of interest for the petrophysical interpretation were defined in terms of clean

zones with hydrocarbon saturation (low GR 11 API and high resistivity 16.4 ohm-m) high interval



Areas shaded in red in (Figures 4.85) indicate pay zones, interpreted from crossover of the DT log R

logs (Figures 4.85) based on high resistivity values, green shaded areas correspond to reservoir

zones, based on high resistivity values, and white shaded areas, (Figures 4.85) correspond to water

zones (very low resistivities).



BM-57Scale : 1 : 100


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutof f

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.


Permo-Carboniferous

Raha

Nubia

Rah

a-S

eal

Rah

a-P

Nub

ia-A

-P1

2925

Figure 4.85: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Raha Formation (Raha-P) (2907-2933 m TVDss) of the BM-57 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.


is 102.2°C. Raha Formation reached at 2866 m TVDss. Reservoir rock is of pre-rift succession of Raha

Formation, zone Raha-P, (oil-bearing zone), (Table 4.19). At BM-57 well, the zone Raha-P, at depth







4.5.7 Nubia A Formation

The Lower Cretaceous of Nubia A Formation is characterized by low gamma ray log readings with

averaged value of (9-16) API (trace GR), resistivity log (trace LLD) exhibits high values up to 502

ohm-m with a maximum value of 1005 ohm-m, high interval transit time (trace DT) of about 97 Ms/ft

on the sonic log. These log response confirm that the lithology of this zone is consisting mainly of

sandstone with shale intercalations. This is shown clearly on the input data plot (Figures 4.86, 4.87

and 4.88). Moreover, a distinct +Ve separation1 between the DT log and Resistivity log curves

(Figures 4.86, 4.87 and 4.88). This positive separation in some intervals indicates the presence of a

hydrocarbon bearing zone within this quartos sand interval.

Shale volume was calculated from the total gamma ray curve using a Stieber correction. Individual

clean and shale lines were chosen for each zone in each well. Porosity was calculated from the shale

corrected complex lithology density neutron cross plot model. The dominant lithology is described as

sandstone (with clay), some calcite (increasing somewhere with depth), and traces of pyrite. The

average of the effective porosity values range from 13% to 24%.

The Indonesian equation was used for water saturation calculations which corrects for the effects of

shale. Water resistivity was set at 0.019 ohm-m at 120°C for all zones. Formation temperature

gradient was set at 1.4F/100 ft with a surface temperature of 78F. This gives a formation temperature

of 248F at 11698 ft. the water saturation values typically ranges from 21% to 51%.

At this zone the effective porosity index reads relatively high (20%) with sufficient permeability index

makes distinct +Ve separation2 between the calculated Sxo and Sw curves (Figure 4.5). This positive

separation indicates the presence of a movable hydrocarbon habit within this quartos sand interval

and points indirectly to its own permeability.

Therefore this interval consists of sandstone and laminated shale and has the properties of such a pay

zone. Cutoffs of the pay zone of this interval are following; average porosity (Φav) = 20%, water

saturation (Swav) = 30% and clay volume (Vclav) = 7%.

1 +ve separation between Sxo and Sw means Sxo >Sw and indicates the presence of movable hydrocarbons, while the lack of this case (-ve separation) indicates residual hydrocarbon (oil-in- place) habitat. 2 +ve separation between Sxo and Sw means Sxo >Sw and indicates the presence of movable hydrocarbons, while the lack of this case (-ve separation) indicates residual hydrocarbon (oil-in- place) habitat.



BM-57Scale : 1 : 600


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)0. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.

N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DTCO (US/F)140. 40.

Dt LogR

DTCO (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutof f

PHIE (Dec)0.5 0.

ResFlag ()0.

PayFlag ()10. 0.

Remarks


Permo-Carboniferous

Raha

Nubia

Rah

a-P

Nub

ia-A

-P1

Nub

ia-A

-S1

Nub

ia-A

-P2

Nub

ia-A

-S2

Nub

ia-A

-P3

Nub

ia-A

-S3

Nub

ia-A

-P4

Nub

ia-B

-P

2950

3000

3050

3100

3150

Interval f rom 3504- 3813 M MD, (2907-3143 MTVDss)Gross Sand 101 M, Net Pay 87 M, PorosityRange 18-24%, SW Range 5-48%.

Figure 4.86: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Nubia A Formation (Nubia A-P1, Nubia A-P2, Nubia A-P3 and Nubia A-P4) (2933-2988, 3030-3039, 3056-3069, and 3129-3144 m TVDss, correspondingly) of the BM-57 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.



BM-36Scale : 1 : 200


Age Fm Zone Gamma

GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt LogR

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.


Early Creataceous

Wata-Raha

Nubia Nub

ia-A

PN

ubia

-A-S

2925

Figure 4.87: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Nubia A Formation (Nubia A-P) (2909-2931 m TVDss, correspondingly) of the BM-36 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.



BM-24Scale : 1 : 600



GR (GAPI)0. 150.

CALI (IN)6. 16.

Depth

DEPTH(M)

Resistivity

LLD (OHMM)0.2 2000.

LLS (OHMM)0.2 2000.


N,D,S

NPHI (dec)0.45 -0.15

RHOB (G/C3)1.95 2.95

DT (US/F)140. 40.

Dt

DT (US/F)140. 0.

LLD (OHMM)0.2 2000.

Lithology

Vdisp (Dec)0. 1.

Vlam (Dec)0. 1.

Vstruc (Dec)0. 1.

PHIE (Dec)1. 0.

VClay (dec)0. 1.

VSand (dec)0. 1.

VLime (dec)0. 1.

Dispersed

Laminated

Structural

Porosity

Sandstone

Limestone

Cutoff

PHIE (Dec)0.5 0.

ResFlag ()0. 10.

PayFlag ()10. 0.


Carboniferous-Early Cretaceous

Raha

Nubia

Nub

ia A

-P1

Nub

ia A

-P2

Nub

ia A

-P3

2850

2900

2950

3000

Figure 4.88: The corrected log datasets and litho-saturation cross plot through a sandstone sequence of the Nubia A Formation (Nubia A-P1, Nubia A-P2, and Nubia A-P3) (2834-2875, 2916-2923, and 2983-3005 m TVDss, correspondingly) of the BM-24 well drilled by the Belayim Company (PETROBEL), showing the zone–wise representation of the well logging deduced saturation and lithological parameters utilizing the IP- interactive Petrophysics software.

4.5.7.1 Nubia A-P1

The oil-bearing zone of Nubia A Formation, particularly zone Nubia A P1, is located at depths ranges

from 2834m (TVDss) to 2933m (TVDss) at BM-24 and BM-57 wells respectively, and 2909m (TVDss)



at BM-36 well (Figures 4.88, 4.86 and 4.87). The Bottom Hole Temperature (BHT) value is ranges

between 98.4°C at BM-24 well to 103.9°C at BM-57 well, furthermore at BM-36 well The Bottom Hole

temperature is 100°C. The total thickness ranges from 22m to 55m at BM-36 and BM-57 wells

respectively (Figures 4.87 and 4.86); and the net thicknesses range from 10.95m at BM-36 well to

30.30m at BM-57 well (Table 4.19). The total average porosity ranges from 13.5% at BM-24 to 21.8%

at BM-57; the volume of clay value ranges from 2.5% at BM-57 well to 6.8% at BM-36 well; and the

water saturation values range between 27.6% at BM-57 well to 50.7% at BM-36 well (Table 4.19).

The corresponding present day temperature values of 93.84˚C at BM-57 well and 112.59˚C at BM-24

well, furthermore at BM-36 well, the corresponding present day temperature value is 104˚C (Figures

4.89, 4.92 and 4.91). The reservoir thermal history, based on well calibrated model, (Figures 4.89 and

4.92) is more than 80°C that retreated the biodegradation effect and suggests a thermodynamically

stable crude oil without any possibility to secondary cracking gas generation.

4.5.7.2 Nubia A P2


from 2916m (TVDss) to 3030m (TVDss) at BM-24 and BM-57 wells respectively (Figures 4.88 and

4.86). The Bottom Hole Temperature (BHT) value is ranges between 100°C at BM-24 well to 106.11°C

at BM-57 well. The total thickness ranges from 7m to 9m at BM-24 and BM-57 wells respectively

(Figures 4.88 and 4.86); and the net thicknesses range from 2.36m at BM-24 well to 6.96m at BM-57

well (Table 4.19). The total average porosity ranges from 19.1% at BM-24 to 23.9% at BM-57; the

volume of clay value ranges from 2.9% at BM-57 well to 4.4% at BM-24 well; and the water

saturation values range between 23.3% at BM-57 well to 40.8% at BM-24 well (Table 4.19). The

corresponding present day temperature values of 97.07˚C at BM-57 well and 114.66˚C at BM-24 well

(Figures 4.89 and 4.92). The reservoir thermal history, based on well calibrated model, (Figures 4.89

and 4.92) is more than 80°C that retreated the biodegradation effect and suggests a

thermodynamically stable crude oil without any possibility to secondary cracking gas generation.

4.5.7.3 Nubia A P3


from 2983m (TVDss) to 3056m (TVDss) at BM-24 and BM-57 wells respectively (Figures 4.88 and

4.86). The Bottom Hole Temperature (BHT) value is ranges between 103°C at BM-24 well to 107.22°C

at BM-57 well. The total thickness ranges from 13m to 22m at BM-57 and BM-24 wells respectively

(Figures 4.86 and 4.88); and the net thicknesses range from 8.76m at BM-57 well to 12.04m at BM-24

well (Table 4.19). The total average porosity ranges from 14.8% at BM-24 to 22.1% at BM-57; the

volume of clay value ranges from 1.1% at BM-24 well to 5.4% at BM-57 well; and the water

saturation ranges between 22.2% at BM-57 well to 40.4% at BM-24 well (Table 4.19). The

corresponding present day temperature values of 98.33˚C at BM-57 well and 117.11˚C at BM-24 well

(Figures 4.89 and 4.92). The reservoir thermal history, based on well calibrated model, (Figures 4.89

and 4.92) is more than 80°C, which retreated the biodegradation effect and suggests a

thermodynamically stable crude oil without any possibility to secondary cracking gas generation.



4.5.7.4 Nubia A P4

The oil-bearing zone of Nubia A Formation, particularly zone Nubia A P4, is located at depth 3129m

(TVDss) to 3144m (TVDss) at BM-57 well (Figure 4.86) with a total thickness 15.6m; and the net

thickness 14.25m (Table 4.19). The Bottom Hole Temperature (BHT) is 103.9°C. The value of total

average porosity is 22%; the volume of clay 2.8%; and water saturation 22% at BM-57 well (Table

4.19). And the corresponding present day temperature value of 101.89˚C at BM-57 well (Figure 4.89).

The reservoir thermal history, based on well calibrated model, (Figure 4.89) is more than 80°C that

retreated the biodegradation effect and suggests a thermodynamically stable crude oil without any

possibility to secondary cracking gas generation.

Figure 4.89: The thermal history of the Pay-Zone Intervals (Belayim Hammam Faraun Member, Upper Rudeis, Matulla, and Raha, Nubia-A, Nubia-B and Nubia C formations) in a reference well (BM-57), which represents the temperature history in Celsius against geologic time scale (Ma). It is obvious that the reservoir temperature is relatively high (more than 80°C) suggesting a biodegradation effects. This suggests a thermodynamically instable crude oil without any possibility to secondary cracking gas generation.

Figure 4.90: The thermal history of the Pay-Zone Intervals (Upper Rudeis and Thebes formations) in a reference well (BM-70), which represents the temperature history in Celsius against geologic time scale (Ma). It is obvious that the reservoir temperature is relatively high (more than 80°C) suggesting a



biodegradation effects. This suggests a thermodynamically instable crude oil without any possibility to secondary cracking gas generation.

Figure 4.91: The thermal history of the Pay-Zone Intervals (Upper Rudeis, Matulla, Wata, and Nubia-A formations) in a reference well (BM-36), which represents the temperature history in Celsius against geologic time scale (Ma). It is obvious that the reservoir temperature is relatively high (more than 80°C) suggesting a biodegradation effects. This suggests a thermodynamically instable crude oil without any possibility to secondary cracking gas generation.

Figure 4.92: The thermal history of the Pay-Zone Intervals (Upper Rudeis, Wata, and Nubia-A formations) in a reference well (BM-24), which represents the temperature history in Celsius against geologic time scale (Ma). It is obvious that the reservoir temperature is relatively high (more than 80°C) suggesting a biodegradation effects. This suggests a thermodynamically instable crude oil without any possibility to secondary cracking gas generation.


1D Numerical MODELING Analysis4-119

Figure 4.93: The thermal history of the Pay-Zone Intervals (Upper Rudeis and Matulla formations) in a reference well (BM-23), which represents the temperature history in Celsius against geologic time scale (Ma). It is obvious that the reservoir temperature is relatively high (more than 80°C) suggesting a biodegradation effects. This suggests a thermodynamically instable crude oil without any possibility to secondary cracking gas generation.

4.6 1D NUMERICAL MODELING ANALYSIS

The uncertainties and significance of the two main parameters affecting maturity, heat flow and burial

depth, are discussed. For the studied wells calibration data (corrected bottom hole temperature) are

available. Thus, the influence of changing input parameters (heat flow, thickness of eroded

sediments) can be estimated. Maturity data reflect the thermal history of sedimentary rocks which in

turn depends on depth of burial, basal heat flow, radioactive heat production, and the sediment /

water interface temperature as well as on physical rock properties, in particular heat conductivity and

heat capacity. The burial and temperature histories were calibrated by comparing calculated and

measured temperature data. Burial and heat flow histories were calculated based on the conceptual

model described previously calibrated for times of maximum temperatures/maximum burial with

corrected temperature data.

For the Oligocene and Miocene rifting phases heat flow values of 115 mW/m2 and 125 mW/m2,

decreasing exponentially with time, respectively, were assumed and comparison between the

calculated and measured temperature data has been done (Figures 4.10-4.17). An increase of these

heat flow values to 125mW/m2 and 135mW/m2, decreasing exponentially with time, was assumed for

a second scenario for both rifting phases, respectively.

There is no variation of the calculated vitrinite reflectance values compared to the original values.

These heat flow modifications do not change the shape of the temperature and maturity curves. It

should be noted that the maximum heat flows reached during both rifting phases did not affect the

present-day maturity, because sediments were deposited as post-rifting basin fill at shallow depth and

younger in age. In contrast, there is no clear evidence for heat flow values during the syn-rift and

early post-rift stage, i.e. for both Oligocene and Miocene rifting phases. However, heat flows much


Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed 1D Numerical MODELING Analysis4-120

higher than those applied do not seem to be probable, since there is no evidence of intense magmatic

activity in the study area.

Higher numbers than those used in this study would lead largely to early petroleum generation from

the mature source rock intervals. A change in present-day heat flow values by more than 5 mW/m2

leads to significant differences between measured and calculated temperature data.

Table 4.20: Summary of hydrocarbon potentiality of source rock intervals.

Formation Item Belayim Marine Oil field

BM-57 BM-70 BM-36 BM-65 BM-23 113-M-27 113-M-34

Depth (m) 2565 3263 2621 3030 2859 3331 3175

Thickness (m) 96 77 119 71 136 237 44

Depth-S (m) 2565 3263 3346 2621 3030 2859 3331 3175

Thickness-S (m) 25 77 41 51 62 237 44

Present-day

Temp. 78° 118° 120° 90° 108° 102° 118° 116°

Present-day VR 0.43% 0.68% 0.70% 0.5% 0.62% 0.61% 0.75% 0.71%

OW-Depth (m) 2933 2904 2826 2611 2315 2296

OW-Age 2.7 2.7 2.4 2.4 5.75 4.01

OW-Temp. 99° 98° 96° 98° 97° 94°

OW-VR 0.52% 0.52% 0.51% 0.52% 0.51% 0.52%

GW-Depth (m) 3193 3199 3021 2851 2525 2704

GW-Age 2.1 2.1 0.9 0.9 5.35 3.4

GW-Temp. 107° 107° 104° 102° 107° 105°

GW-VR 0.57% 0.57% 0.57% 0.57% 0.58% 0.58%

EXP-Depth (m) 3245 3330 3030 2859 2350 3169

EXP-Age 1.8 1.8 0 0 5.2 1.8

EXP-Temp. 109° 112° 108° 102° 105° 116°

EXP-VR 0.59% 0.61% 0.62% 0.61% 0.57% 0.64%

Remaining

Potential 0.46 0.55 0.28 0.21 0.46 0.60 1.76 1.72

Accumulated in

Source 0.01 0.09 0.05 0.01 0.07 0.10 0.30 0.28

Adsorbed 0.01 0.07 0.03 0.01 0.06 0.07 0.22 0.22

Thebes

HC Loss 0 0.28 0.19 0.0 0.06 0.04 1.66 0.92

S: Source Temp: Temperature VR: Vitrinite Reflectance OW: Oil Window GW: Gas Window EXP: Expulsion




BM-57 BM-23 113-M-27 113-M-34

Depth (m) 2763 3049 3572 3307

Thickness (m) 9 36 15 46

Depth-S (m) 2763 3049 3572 3307

Thickness-S (m) 9 36 15 46

Present-day Temp. 86° 109° 125° 124°

Present-day VR 0.48% 0.64% 0.76% 0.74%

OW-Depth (m) 2329 2384 2356

OW-Age 3.5 5.88 5.65

OW-Temp. 98° 100° 95°

OW-VR 0.54% 0.52% 0.49%

GW-Depth (m) 2793 2581 2529

GW-Age 2.4 5.42 4.6

GW-Temp. 107° 110° 104°

GW-VR 0.58% 0.59% 0.57%

EXP-Depth (m) 3047 2681 2519

EXP-Age 1.8 5.2 4

EXP-Temp. 111.0° 115° 104°

EXP-VR 0.62% 0.63% 0.59%

Remaining Potential 0.35 0.55 0.11 0.43

Accumulated in Source 0.01 0.08 0.02 0.07

Adsorbed 0.01 0.07 0.01 0.05

Duwi

HC Loss 0.0 0.16 0.22 0.60



Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed 1D Numerical MODELING Analysis4-122


BM-57 BM-36 BM-65 113-M-27

Depth (m) 2933 2909 3124 3907

Thickness (m) 211 186 144 95

Depth-S (m) 2988 3039 3069 2931 3164 3933

Thickness-S (m) 42 17 60 164 104 45

Present-day Temp. 96° 98° 100° 107° 120° 137°

Present-day VR 0.53% 0.54% 0.56% 0.62% 0.70% 0.91%

OW-Depth (m) 3204 3128 2450

OW-Age 0.89 2.4 6.6

OW-Temp. 106° 110° 100°

OW-VR 0.60% 0.61% 0.56%

GW-Depth (m) 3255

GW-Age 3.5

GW-Temp. 135°

GW-VR 0.79%

EXP-Depth (m) 3501

EXP-Age 3

EXP-Temp. 137°

EXP-VR 0.80%

Remaining Potential 0.12 0.05 0.19 0.49 0.23 0.05

Accumulated in Source 0 0 0.01 0.06 0.09 0.08

Adsorbed 0 0 0.01 0.05 0.05 0.01

Nubia A

HC Loss 0 0 0 0 0 0.04





BM-57 BM-36 BM-65 BM-24 113-M-27

Depth (m) 3144 3094 3268 3005 4002

Thickness (m) 118 129 74 89 119

Depth-S (m) 3185 3130 3297 3018 3036 4002

Thickness-S (m) 77 93 45 6 58 86

Present-day Temp. 105° 114° 126° 118° 120° 140°

Present-day VR 0.60% 0.66% 0.73% 0.77% 0.79% 0.96%

OW-Depth (m) 3251 2740 2854 2662 2307 2474

OW-Age 0.91 3.5 4.6 5.65 6.6 6.6

OW-Temp. 103° 99° 104° 117° 100° 104°

OW-VR 0.57% 0.58% 0.58% 0.65% 0.60% 0.60%

GW-Depth (m) 3499 3190

GW-Age 0.86 4.6

GW-Temp. 124° 136°

GW-VR 0.78% 0.79%

EXP-Depth (m) 3415 2875 3129

EXP-Age 1.8 5.2 5.2

EXP-Temp. 128° 129° 134°

EXP-VR 0.76% 0.72% 0.75%

Remaining Potential 1.54 0.94 0.32 0.02 0.30 0.14

Accumulated in Source 0.20 0.22 0.20 0.02 0.14 0.14

Adsorbed 0.04 0.10 0.04 0 0.04 0.02

Nubia B

HC Loss 0 0 0 0.01 0.16 0.32


Mansoura UniversitySummary and Conclusions2015

Summary and Conclusions5-1

5. SUMMARY AND CONCLUSIONS

The Gulf of Suez rift is considered the first and most important petroleum province in Egypt. It has

excellent hydrocarbon potentials.

As mentioned before, this thesis aimed to:

1) Quantify the processes of oil and gas generation, expulsion, and migration of Belayim Marine Oil

Field utilizing PetroMod software.

2) Give a proper appraisal of the geologic situation integrated with a comprehensive petroleum

characterization model pointed to evaluate the petroleum system and hydrocarbon potential of

Belayim Marine Oil Field.

3) Show the pattern of success and failure across the region within the Mesozoic and Tertiary sections

and contribute to the development of new exploration plays.

4) Explain the factors controlling the distribution of the different oil and gas fields at the same

stratigraphic level.

Integrated 1D basin modeling was applied to evaluate the thermal history of the sedimentary

sequence in the Belayim Marine Oil Field. In all 1D models, the present heat flow ranges from 52-64

mW/m2, with the higher values occurring in BM-57 well. Areas of present heat flow maxima are

generally coincident with distribution of basement relief and/or high conductivity basement. This

higher value occurring at BM-57 with thick highly thermal conductive basin-fill sediment, i.e. South

Gharib Formation, whereas the lower values modeled for the BM-24 well are associated with thick

lower thermal conductive basin-fill sediment, i.e. Post South Gharib Formation. The higher heat flow is

explained by uplift followed by erosion, which provides an additional 1-17 mW/m2 above background of

52-64 mW/m2. Heat is refracted away from regions of thick sediment cover and preferentially

channeled through areas of elevated basement. An additional 15 mW/m2 may be produced by

conductivity contrasts in basement. The paleo-heat flow values are shown in (Tables 4.10-4.17 and

Figures 4.6-4.13) which results in a valid paleo-temperature model. High sedimentation rate can also

affect the temperature field due to the low heat conductivity of highly porous sediments. The results

of the 1D simulations show the differences in burial, thermal and maturity history. The burial history

of the study area is represented by time-depth history plots that show the burial of different horizons

traced through time, from deposition to present day. The subsurface temperature was specified for

every layer throughout its geologic history. The following thermal regime for Belayim Marine Oil field

is proposed based on present-day corrected static bottom-hole temperatures.

1) Paleo-heat flow was highest at ~25-23 Mabp (the Oligocene rifting phase), with cooling caused by

a heat flow decline.

2) Paleo-heat flow has increased during the Miocene rifting phase. This thermal scheme has been

implemented in the 1D model, applying high heat flows from (~17.2 to 16.8 Mabp.) There was a

decline in geothermal gradient due to rapid sediment accumulation (as indicated during the deposition

of the South Gharib Formation) resulting in a subsurface temperature that was anomalously low.

3) Paleo-heat flow has increased during the Late Messinian Time Event from ~5.2-4 Mabp, and



Assistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed Summary and Conclusions5-2

For the different source rock sequences, the content of organic matter (TOC) and quality Hydrogen

Index (HI) has to be defined together with reaction kinetic parameters for the thermal primary

cracking to light and heavier petroleum components.

Thebes Formation is a limestone of shallow marine depositional environment with a reported thickness

in the range of 44 to 237m. It is characterized by a relatively high total organic carbon (TOC) value of

~2.71wt% and by immature Type II kerogen (BM-36 and BM-57 wells) and mature at wells (BM-70,

BM-65, BM-23 and 113-M-27 well) (Table 4.18).




The relatively high hydrogen index of 409 mgHC/gTOC and low oxygen index 47 mgCO2/gTOC, S2


confirm the kerogen as type II that considered mainly as oil generative interval.

Duwi Formation assigned to pre-rift basin fill sediments of limestone organic rich interval that

deposited in open marine depositional environment which is characterized by type II kerogen with an

excellent generation potential for liquid hydrocarbons (oil prone type II-S kerogen). It is characterized

by a high initial total organic carbon (TOC) value of ~4.02wt% and by immature to early mature Type

II kerogen at single well (BM-57 well) (Figure 4.61) (Table 4.18), whereas it is classified as thermally

mature type II kerogen at (BM-23, 113-M-34, and 113-M-27 wells).

Nubia-A Formation has organic-rich intervals, namely Nubia A-S1, Nubia A-S2 and Nubia A-S3. The


well with total thickness ranges between 45m at 113-M-27 well and 164m at BM-36 well. It assigned

to pre-rift sediments of shale organic rich interval that deposited in shallow marine depositional

environment and classified as type II-III kerogen with an excellent generation potential for liquid

hydrocarbons (oil prone type II-B – type III kerogen). It is characterized by fairly total organic carbon

(TOC) value of ~1.03wt% and by immature Type II-type III kerogen at BM-57 well, and an early-

mature type II kerogen intervals at BM-36 and BM-65 wells), but mature at single well, 113-M-27 well,

At BM-65 well, the analyzed source rock intervals with (TOC 1.27-1.43%) appear to have fair potential

for gas and oil generation, at the present level of thermal maturity (Pyrolysis S2 2.70-3.74 mg/g and

HI 189-281). The relatively high hydrogen index of 167 mgHC/gTOC and low oxygen index 86

mgCO2/gTOC, S2 value of 1.72 mg/g rock indicate that the kerogen is made up of an oxygen-lean

organic material and confirm the kerogen as type II-type III that considered mainly as oil generative

interval.

Nubia-B Formation is characterized by early-mature source rocks that were deposited under



generated and expelled hydrocarbons. The organic-rich interval has been differentiated based on well

logging interpretation and confirmed by geochemical analysis, namely Nubia B-S. The organic rich

interval Nubia B-S is located at five wells 113-M-27, BM-36, BM-65, BM-57, and at BM-24 well. The




well with total thickness ranges between 45m at BM-65 well and 93m at BM-36 well for Nubia B-S.


depth of 3018m (TVDss) at BM-24 well. It assigned to pre-rift sediments of shale organic rich interval

that deposited in shallow marine depositional environment and classified as type II-III kerogen with

an excellent generation potential for liquid hydrocarbons (oil prone type II-B – type III kerogen).

It is characterized by a relatively remaining high total organic carbon (TOC) value of ~2.62wt% and

by immature-early mature Type II-III kerogen at BM-57 well (Table 4.18) and an early-mature type

II-III kerogen intervals at BM-36 and BM-65 wells but mature at wells, BM-24 and 113-M-27 well.

The analyzed samples contain both marine and terrestrial organic matter with variable but nearly

equal proportions. The black shale of the Nubia-B is considered as the mature potential source rock of

the Nubia reservoir. The analyzed interval show both marine and terrestrial organic matter, with the

marine component dominating in most samples and decreasing generally with depth.

5.1 CONCLUSIONS

Accurate description of the timing of decomposition of organic matter (kerogen) into oil and gas under

geological conditions is the goal for the highest quality basin modeling effort.

The scenario investigated was restricted to the available well locations and reflect their geological

evolution through time. The multiple 1D model was calculated with “PetroMod 2011.1 SP1” software,

provided by IES. The Eocene Thebes Formation is a very good quality oil source rock in the central

province. It consists of limestone of open marine facies and its organic content is variable, but locally

it is rich in TOC with values 1-2.86% reported. Kerogen is classified as Type I-II, with 10- 30% woody

and herbaceous material, giving it slightly less oil-prone character than the Brown Limestone. The

Thebes Formation source rock is considered as an active currently expelling effective source rock that

has already generated and expelled hydrocarbons.

The oil window is shallower and older in age (~5.75 Mabp Late Miocene-Messinian) at 113-M-27 well

in comparison to that immature source rock interval at BM-57 and BM-36 wells, where they are

relatively deeper and younger in age. The gas (gas generation onset) depths range between 2525m

(~5.35 Mabp Late Miocene-Messinian) to 3199 m (~2.1 Mabp Pleistocene-Gelasian) at 113-M-27 well

and BM-70 well, respectively. The present-day depth of the Thebes-S is in the range in which a single-

phase fluid (Medium oil) generated. Oil generation windows after both the Messinian Event and the

deposition of Zeit Formation and during the deposition of Post-Zeit Formation and after the maximum

burial depth reached. The hydrocarbon generation mainly related to burial rather than basin evolution,

the oil window started at (~5.75 Mabp Late Miocene-Messinian) during the deposition of the Zeit

Formation at 113-M-27 well. The oil window started at (~2.4 Mabp Pleistocene-Gelasian) during the

deposition of Post Zeit Formation at BM-23, BM-65 and BM-70 wells. On the other hand, at 113-M-34

well, hydrocarbon generation mainly related to basin evolution (the Messinian Event ~5.2 to ~4

Mabp) rather than burial. The oil window started at (~4.01 Mabp Pliocene-Zancleanian) during basin

evolution (the Messinian Event ~5.2 to ~4 Mabp). The organic rich interval of the Thebes Formation,

Thebes-S at 113-M-34 well is classed as mature source rock which is related to basin evolution.




Messinian Event (~5.2 to ~4 Mabp Early Pliocene), except the expulsion of hydrocarbons at 113-M-27

well at (~5.2 Mabp Pliocene-Zanclean) after the generation of the gas but during the Messinian Time

Event (~5.2 to ~4 Mabp Early Pliocene). Moreover, recently at the present day, after the generation

of the gas, and also after the deposition of the Post-Zeit Formation at BM-23 and BM-65 wells.

However, the organic rich interval of Thebes Formation at BM-36 and BM-57 wells is classed as

immature source rock because of the shallow depth of this Thebes organic rich interval, and the less

thickness of the Post Zeit Formation, Zeit Formation, South Gharib Formation, Belayim Formation,

Kareem Formation and Upper Rudeis Formation.

The organic rich interval of Duwi Formation limestone that deposited in open marine depositional

environment, it is characterized by type II kerogen with an excellent generation potential for liquid

hydrocarbons (oil prone type II-S kerogen). The Duwi Formation source rock has a tendency to

produce mainly liquid oil and gas generation capacities. It is considered as an active currently

expelling effective source rock that has already generated and expelled hydrocarbons. The oil window

is shallower and younger in age (~3.5 Mabp Pliocene-Piacenzian) at BM-23 well in comparison to that

immature-early mature organic rich interval at BM-57 well, whereas relatively deeper and older in age

at 113-M-27 well (Figures 12, 11, and 14). On the other hand, the gas (gas generation onset) depths

range between 2529m (~4.6 Mabp Pliocene-Piacenzian) at 113-M-34 well to 2793m (~2.4

Pleistocene-Gelasian) at BM-23 well. The present-day depth of the Duwi-S is in the range in which a

single-phase fluid (Medium oil) might be expected. The generation of hydrocarbon mainly related to

basin burial rather than basin evolution during the deposition of Zeit Formation at 113-M-27 well

(~5.88 Mabp Late Miocene-Messinian) and 113-M-34 well (~5.65 Mabp Late Miocene-Messinian) and

during the Post Zeit formation at BM-23 well (~3.5 Mabp Pliocene-Piacenzian).

At 113-M-27 well, hydrocarbon generation mainly related to burial rather than basin evolution (~5.88

Mabp Late Miocene-Messinian) during the deposition of the Zeit Formation. The generation of gas

mainly related to basin burial rather than basin evolution during the deposition of Zeit Formation at

113-M-27 well (~5.42 Mabp Late Miocene-Messinian) and during the Post Zeit Formation at BM-23

well (~2.4 Mabp Pliocene-Piacenzian). At 113-M-34 well, gas generation mainly related to basin burial

and basin evolution (~4.6 Mabp Late Miocene-Messinian) after the deposition of Zeit Formation and

during the deposition of the Post Zeit Formation. The expulsion of the hydrocarbons occurred mainly

after the generation of the gas and after the deposition of the Zeit Formation and during the

Messinian Time Event at 113-M-27 well and 113-M-34 wells. However, at BM-23 well the expulsion

occurred during the deposition of Post Zeit Formation. The hydrocarbon expulsion of the organo-

facies, called Duwi-S, commenced since ~5.2 Mabp (Pliocene-Zanclean) after both the generation of

the gas and the deposition of Zeit Formation. The expulsion simultaneously started at the beginning of

the Messinian Time Event (~5.2-4 Mabp) at 113-M-27 well. The recent expulsion event started since

~1.8 Mabp (Pleistocene) after both the generation of the gas and the deposition of the Post-Zeit

Formation at single reference well location at BM-23 well. On contrast, there is no expulsion at BM-57

well. The expulsion occurred at a generation mass that ranges between 0.06 Mtons HC (~5.2 -4 Mabp



Pliocene-Zanclean) at 113-M-27 well and 113-M-34 well, respectively to 0.09 Mtons HC (~1.8 Mabp

Pleistocene) at BM-23 well.

The organic-rich interval of the Nubia A Formation in Belayim Marine Oil field concession, Nubia A-S,

entered the oil windows close to the Late Miocene-Messinian ~6.6 Mabp during the deposition of the


Piacenzian) during the deposition of the Post-Zeit Formation and shortly after the Messinian Event

Time (~5.2 to ~4 Mabp). The oil windows depths range between 2450m (~6.6 Mabp Late Miocene-

Messinian) at 113-M-27 well to 3204m (~0.89 Mabp Pleistocene-Calabrian) at BM-36 well and before

the maximum burial was reached at the present day. In addition, the oil window depth at BM-65 well

is 3128m (~2.4 Mabp Pleistocene-Gelasian). The oil window is shallower and older in age (Late

Miocene-Messinian) of mature source rock interval at 113-M-27 well in comparison to that early

mature source rock interval at BM-36 well, which are relatively deeper and younger in age. The gas

(gas generation onset) reached only at single well 113-M-27 at depth 3255m (~3.5 Ma Pliocene-

Piacenzian). The present-day depth of the Nubia A-S is in the range in which a single-phase fluid

(Medium oil) might be expected. Petroleum generation started at a vitrinite reflectance of 0.56%,

which is reached at different age and depth throughout the area, at (~6.6 Mabp Late Miocene-

Messinian) at 113-M-27 well with a corresponding temperature of 100°C. Moreover, at BM-65 well the

maximum simulated vitrinite reflectance value of 0.61% since (~2.4 Mabp Pleistocene-Gelasian) with

a corresponding temperature of 110°C. Furthermore, at BM-36 well the simulated vitrinite reflectance

value of 0.60% since (~0.89 Mabp Pleistocene-Calabrian) with a corresponding temperature of 106°C

The simulated gas-onset vitrinite reflectance value is 0.79% since (~3.5 Ma Pliocene-Piacenzian) at

113-M-27 well with a corresponding temperature of 135°C. The present-day maximum simulated

vitrinite reflectance value is 0.91% at 113-M-27 well with a corresponding highest present day

temperature of 137°C. However, the present-day minimum simulated vitrinite reflectance value of

0.53% at BM-57 well with a corresponding temperature of 96°C. These variations in maturity are

mainly related to the deposition of the maximum thickness of Post-Zeit, Zeit, Kareem, Upper Rudeis,

Thebes, Matulla, and Raha formations at 113-M-27 well. On the other hand, at BM-57 well are mainly

related to the deposition of minimum thickness of the Post Zeit, Zeit, Kareem, and Upper Rudeis

formations. The simulated vitrinite reflectance of the oil generation with a corresponding temperature

values increase from 0.56% Ro and 100°C (~6.6 Mabp Late Miocene-Messinian) at 113-M-27 during

the deposition of Zeit Formation to 0.61%Ro and 110°C (~2.4 Mabp Pleistocene-Gelasian) during the

deposition of Post-Zeit Formation and continuously increased to present day values.


well mainly after the deposition of Post-Zeit Formation whereas the maximum present day bulk

generation mass ranges between 0.06 Mtons at BM-36 well to 0.12 Mtons at 113-M-27 well,

Additionally the present day transformation ratio at BM-65 well is 27.88% and present day bulk

generation mass is 0.09 Mtons. The expulsion of the hydrocarbons occurred mainly after the

generation of the gas and during the deposition of Post-Zeit Formation. The first expulsion occurred at

(~3 Mabp Pliocene-Piacenzian after the generation of the gas and during the deposition of Post-Zeit

Formation) at 113-M-27 well. The present day expulsion value of 0.01 Mtons HC at 113-M-27 well. On



the other hand there is no expulsion at wells BM-36, BM-57, and BM-65 well. The sum of generated

hydrocarbons ranges between 0.06 Mtons at BM-36 well and 0.12 Mtons at 113-M-27 well, with a

significant amount of about 0.09 Mtons at BM-65 well. At 113-M-27 well, the organic rich interval

Nubia A-S, located at depth of 3933m (TVDss), and it is classed as mature source rock which is

related to burial. The hydrocarbon generation mainly related to basin burial rather than basin

evolution. The oil window started at (~6.6 Mabp Late Miocene-Messinian) during the deposition of


thickness of Zeit 750m, Upper Rudeis 402m, Thebes 237m and Matulla 128m formations.

At BM-65 well, the organic rich interval Nubia A-S, located at depth 3164m (TVDss) and classed as

early mature source rock which is related to basin burial. The hydrocarbon generation mainly related

to basin burial rather than basin evolution, the oil window started at (~2.4 Mabp Pleistocene-Gelasian)

during the deposition of Post-Zeit Formation at oil windows depth of 3128m (TVDss). Although the

maximum thicknesses of the Belayim Formation 503m, South Gharib Formation 538m and Zeit

Formation 786m has been recorded. Furthermore, the misplaced of different rock units that

represented by the Sudr, Duwi, Matulla, Wata, and Raha formations. At BM-36 well, the organic rich

interval Nubia A-S, located at depth 2931m (TVDss) and characterized by early to mature source rock

which is mainly related to basin burial. The hydrocarbon generation mainly related to basin burial

rather than basin evolution, the oil window started at (~0.89 Mabp Pleistocene-Calabrian) during the

deposition of Post Zeit Formation. This maturity related to exchange of basin burial and basin

evolution is due to both the minimum thickness of the Belayim Formation 132m and low thickness of

the South Gharib Formation 478m. The hydrocarbon generation of Nubia A-S is mainly related to

basin burial. This indicates that the maturity of the organic-reach intervals of Nubia A-S is closely

related to burial with a minor heat flow influence. Hydrocarbon generation is mainly related to

exchange of burial, particularly due to deposition of the Zeit and Post-Zeit formations.

On the other hand, at BM-57 well, the organic rich interval of Nubia A Formation at BM-57 well is

classed as immature source rock related to basin burial due to the shallower depths of Nubia A-S1 at

2988m (TVDss), Nubia A-S2 at 3039m (TVDss), Nubia A-S3 at 3069m (TVDss), in addition to the

minimum thickness of the Post Zeit Formation 797m, Zeit Formation 665m, and Upper Rudeis

Formation 141m. This means that the source rock will have to be buried to greater depths in the area

to generate oil, all other factors being the same.

The gas onset generation mainly related to basin burial with basin evolution effect. At 113-M-27 well,

the gas generation onset started at (~3.5 Mabp Pliocene-Piacenzian) at depth 3255m (TVDss) during

the deposition of Pos-Zeit Formation and shortly after both uplift and erosion that followed the

Messinian Time Lap (~5.2 to ~4 Mabp Pliocene-Zanclean). The expulsion of hydrocarbon mainly

related to basin burial. At 113-M-27 well, the hydrocarbon expulsion started since (~3 Mabp Pliocene-

Piacenzian) during the deposition of Post-Zeit Formation, at relatively deeper depth 3501m (TVDss)

with simulated vitrinite reflectance value of 0.80% and a corresponding temperature value of 137°C.

The sum of generated hydrocarbons at 113-M-27 well is 0.12Mtons and mainly accumulated in the

source rock (slightly adsorbed by the organic matter in the source). However, in the wells (BM-36 and



BM-65, there is no expulsion due to the generated hydrocarbons mainly accumulated in the source

rock and mostly adsorbed by organic matter.

The Nubia B Formation is characterized by early-mature source rocks that were deposited under



generated and expelled hydrocarbons. Oil generation windows started during the deposition of Zeit

Formation. At 113-M-27 well, hydrocarbon generation mainly related to basin burial rather than basin

evolution. The oil window started at (~6.6 Mabp Late Miocene-Messinian) during deposition of the


thickness of Zeit 750m, Upper Rudeis 402m, Thebes 237m and Matulla 128m formations. At BM-24

well, the oil window started at (~6.6 Mabp Late Miocene-Messinian) during deposition of the Zeit

Formation at oil windows depth of 2307m (TVDss). This means that the source rock will have to be

buried to greater depths in the area to generate oil, all other factors being the same. The variation in

maturity depths may be related to the quality of kerogen and its chemical composition. However, at

BM-36 well, the source rock interval characterized by early mature to mature that is related mainly to

basin burial (the deposition of Post-Zeit Formation) with minor effect of the basin evolution that

occurred during (the Messinian Event Time ~5.2 to ~4 Mabp). The oil windows stated since (~3.5

Mabp Pliocene-Piacenzian) at relatively shallower depth of 2740m (TVDss). This maturity related to

exchange of basin burial and basin evolution is due to both the minimum thickness of the Belayim

Formation 132m and low thickness of the South Gharib Formation 478m. On the other hand, the oil

generation at BM-65 well is mainly related to basin evolution that occurred at (~4.6 Mabp Pliocene-

Zanclean) during (the Messinian Event Time ~5.2 to ~4 Mabp Pliocene-Zanclean) at oil windows

depth of 2854m. Although the maximum thicknesses of the Belayim Formation 503m and the South

Gharib Formation 538m has been recorded. Furthermore, the misplaced of different rock units that

represented by the Sudr, Duwi, Matulla, Wata, and Raha formations. The commencing of gas onset

generation was after the expulsion of oil expulsion at (~5.2 Mabp Pliocene-Zanclean) at both wells

BM-24 and 113-M-27. At 113-M-27 well, gas generation mainly related to basin evolution, where

started at (~4.6 Mabp Pliocene-Zanclean) during the Messinian Event Time (~5.2 to ~4 Mabp

Pliocene-Zanclean) at relatively deeper depth value of 3190m (TVDss). In addition to the subaltern

basin burial influence due to the deposition of thick sediments of the Upper Miocene Zeit Formation of

750 m. By contrast, at BM-24 well, gas generation onset mainly related mainly to basin burial whereas

it commenced at (~0.86 Mabp Pleistocene-Calabrian) during deposition of the Post-Zeit Formation at

relatively deeper burial depth of 3499 m (TVDss). The expulsion of hydrocarbon started at (~5.2

Mabp) that is mainly related to basin evolution (the Messinian Event Time ~5.2 to ~4 Mabp Pliocene-

Zanclean) and before the generation of gas at two locations 113-M-27 well and BM-24 well. The

expulsion started at relatively deeper depth 3129m (TVDss) with simulated vitrinite reflectance value

of 0.75% with a corresponding temperature value of 134°C and a sum of generated hydrocarbons of

0.46Mtons at 113-M-27 well. The generated hydrocarbon partially accumulated in the source rock and

slightly adsorbed by the organic matter. Likewise, at BM-24 well, the expulsion started at relatively

shallower depth of 2875m (TVDss) compared to that of 113-M-27 well with simulated vitrinite



reflectance value of 0.72% and a corresponding temperature value of 129°C with a sum of generated

hydrocarbons of 0.30Mtons. The generated hydrocarbon mainly accumulated in the source rock with

slightly adsorbed by the organic matter. It is worth to mention that, all the expelled hydrocarbons

completely lost through the migration pathways. However, in the wells BM-57, BM-36, and BM-65,

there is no expulsion due to the low quantity of the generated hydrocarbons, in addition to the

adsorption of the generated hydrocarbon by organic matter in the source rock intervals. Another

source rock interval at depth 3018m (TVDss) with a thickness of 6m has been distinguished at BM-24

well. The oil windows started since (~5.65 Mabp Late Miocene-Messinian) at oil windows depth of

2662m (TVDss) with a corresponding temperature and vitrinite reflectance values of 117°C and

0.65%Ro, respectively. The oil generation is closely related to basin burial particularly during the

deposition of Zeit Formation with no gas generation. Moreover, the expulsion occurred at (~1.8 Mabp

Pleistocene-Calabrian) that accompanied by a relatively high bulk generation which is related to burial

(deposition of low thickness of Post-Zeit Formation of about 772m) in addition to small thickness of

the Nubia B-S1 with no effect of tectonics on expulsion. Integrated 1D basin modeling was applied to

evaluate the thermal history of the sedimentary sequence in the Belayim Marine oil field. Best

accordance between measured and calculated present-day temperatures was achieved with present-

day heat flows in the range of 52-64 mW/m2. The lower values modeled for the BM-24 well are

associated with comparatively thick lower thermal conductive basin-fill sediments, i.e. Rudeis

Formation 217m, and Kareem Formation 190m. The higher heat flow is explained by uplift followed by

erosion, which provides an additional 5-17 mW/m2 above background of 60mW/m2. Paleo-heat flow

was highest at ~25-23 Mabp (the Oligocene Rifting Phase), with cooling caused by a heat flow

decline. Paleo-heat flow has increased during the Miocene Rifting Phase. This thermal scheme has

been implemented in the 1D model, applying high heat flows from ~17.2 to 16.8 Mabp. There was a

decline in geothermal gradient due to rapid sediment accumulation as indicated during the deposition

of the South Gharib Formation resulting in a subsurface temperature that was anomalously low.

Paleo-heat flow has increased during the Late Messinian Event Time from ~5.2 to 4 Mabp, and


Migration

The generated hydrocarbon partially accumulated in the source rock and adsorbed by the organic

matter. Not all expelled hydrocarbons accumulated in the reservoir but mostly was lost through the

migration pathways. The important aspects of primary migration are the nature of the hydrocarbons

expelled (oil or gas), the efficiency of expulsion, and the timing of the expulsion. Whether migration

occurs mainly in vertical or horizontal direction also depends on the source rock properties. In the

study area there is no vertical migration as the reservoirs under lines the source rock.

5.2 RECOMMENDATIONS

• 2D & 3D modeling for migration pathways simulation.

• Oil-Source correlations.

• Organic geochemistry analysis for Thebes and Duwi formations as source rock.

• Oil chromatograph and crude oil analysis for Nubia-A oils.

Mansoura UniversityReferences2015

References6-1

6. REFERENCES

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Mohamed Abu Al-AttaAssistant Prof. Dr. Ghalib Issa, Dr. Mohamed Afife and Dr. Mohammed Awad Ahmed

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hydrocarbon exploration and tectonic evolution of belayim marine oil field, gulf of suez, egypt

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