A Dissertation Submitted to the Department of Geophysics in Partial Fulfillment of the Requirements for the Master Degree of Science in Exploration Geophysics

بسم هللا الرحمن الرحيم

Al Neelain University

Characterization of Neem Main Low Resistivity Oil Zones - Muglad Basin (Republic of Sudan)

By: Mohamed Mukhtar Mohamed Ibrahim

B.Sc. (Hons.) (Geology & Mining)

A dissertation Submitted to the Department of Geophysics in Partial Fulfillment of the Requirements for the Master Degree of Science in Exploration Geophysics.

Elneelain University Faculty of Petroleum and Minerals Geophysics Department

April, 2018

Characterization of Neem Main Low Resistivity Oil Zones - Muglad Basin (Republic of Sudan)

By: Mohamed Mukhtar Mohamed Ibrahim

B.Sc. Hons. (Geology)

A dissertation Submitted to the Department of Geophysics in Partial Fulfillment of the Requirements for the Master Degree of Science in Exploration Geophysics.

April, 2018

Elneelain University Faculty of Petroleum and Minerals Geophysics Department

Exam Committee:

External Examiner: …………………………………… …………………....

Internal Examiner: …………………………………… … ………………..…

Supervisor: ……………………………………………… ………………………

Approved on: …………………………………………… ……………………….

ABSTRACT Muglad basin is the largest rift basin discovered in Sudan, it trends northwest-southeast and consists of a thick Mesozoic and Tertiary continental syn-rift sequence buried by a Miocene- Recent post-rift sedimentary cover sediments include fluvial alluvial and lacustrine environment with probability of coastal marine depositional environment. The study objectives is to characterize low resistivity possible oil zones and correlate to figure out continuity of the same focusing mainly on Abugabra formation in Neem field where Low Resistivity Pay zones characterization are usually quite difficult that it requires researchers to twist their mindset by analyzing the information unconventionally; because many reasons for low resistivity are possible but not limited to: Invasion of high salinity mud filtrate, high clay bound water content, high capillary irreducible water content due to fine sand grain and/or existence of conductive minerals in pay zones such as: pyrite, siderite, glauconite etc.. Data of seven wells, include: Master logs, Final well reports, Conventional Wire Line logging (the first main run) and then interpreted using geological computer applications {Gravitas, Petrel and Interactive Petrophysics (IP)}. The petrophysical interpretation includes the complete processes to determine the permeability, porosity and water saturation using flow units method which contains determination of the total porosity from wireline logs and then correlated to figure out its continuity in the area. Petrophysical Interpretation results show non clear contrast in the porosity and volume of clay & the water saturation ratio was up to 75 which is acceptable on its compatibility with the characteristics of the reservoir. There have been 7 oil and gas zones in common per well, with total thickness of 265m oil column, with effective porosity calculated upper and middle pay-zones in Abugabra are of higher values 15 to 18 whereas the lower Abugabra porosity value ranging between 9 to 13. Out of the seven different sand layers in Abugabra, the study showed only one continuous layer in all seven wells. The permeability, porosity and saturation of water and oil were calculated for all layers of this formation in addition to the Bentiu formation. This showed variation in the results, indicating the different sedimentary environments and the nature of the migration of the hydrocarbons from the source layers.

الخالصة

حوض المجلد االخدودي جنوبي السودان أكبر األحواض االخدودية التي تم اكتشافها في السودان والذي يمتد من الشمال الغربي- الجنوبي الشرقي حيث أنه يحتوي طبقات رسوبية قارية سميكة من الحقبة الوسطى والحديثة متكونة نتيجة لبيئات قارية كبيئة األنهار المدفونة او المضفرة او نتيجة البيئات البحيرية مع إحتمالية وجود بيئات بحرية بسيطة.

تهدف الدراسة لبحث وتقييم نطاقات المكامن المنتجة ذات المقاومية المنخفضة من تكوين أبوجابرا ومعرفة مدى استمراريتها

بالتركيز بشكل أساسي على حقل نيم؛ حيث عادة ما يكون تمييز طبقات المكامن منخفضة المقاومية صعب للغاية مما يتطلب من الباحثين تحليل بيانات السبر الكهربي بطريقة غير تقليدية؛ ألن هناك العديد من األسباب الكامنة وراء انخفاض تلك المقاومية فعلى سبيل المثال ال الحصر: محتواها المرتفع من ماء سائل الحفر الغازي لطبقات المكمن، المحتوى المرتفع من المياه غير القابلة لإلنحالل الشعري بسبب المادة الطينية الالحمة للحبيبات الرملية الناعمة و/ أو وجود معادن لها خاصية التوصيلية الكهربية في النطاق المنتج من المكمن مثل: البيريت، السيداريت، الجلوكونيت... إلخ.

تم إستخدام وتحليل بيانات سبعة آبار نفط؛ تشمل: تسجيالت سبر األبار، والتسجيالت الطينية باإلضافة إلي تقارير اآلبار

النهائية. ومن ثَم تم إستخدام بعض تطبيقات الحاسوب الجيولوجية {(Petrel, and Interactive Petrophysics (IP} .Gravitas

شمل التفسير البتروفيزيائي العمليات الكاملة لتحديد النفاذية والمسامية وتشبع الماء باستخدام طريقة وحدات التدفق التي تحتوي على تحديد المسامية الكلية من سجالت السبر الكهربي وتمت مضاهاتها في كل أبار الدراسة لتحديد مدي إنتشارها في المنطقة.

من هذه الدراسة وجد أن طبقات الرمل الرقيقة التي تتخلل طبقات الطين، المعادن الموصلة والمحتوى المائي للطين في المادة الطينية الالحمة لهذه الطبقات الرملية في تكوين أبوجابرا هي أكثر األسباب فعالية إلنخفاض المقاومية. كما أظهرت نتائج هذه

الدراسة أيضا من خالل التفسير البتروفيزيائي تباين ا واضحا َ في المسامية وحجم الصلصال مع نسبة تشبع الماء تصل إلى %75 وهي مقبولة عند توافقها مع خصائص المكمن.

هناك ما اليقل عن 7 نطاقات نفط وغاز كحد أدنى لكل بئر، بسمك متوسط إجمالي حوالي 265 متر، مع مسامية فَع الة تتراوح في الطبقات العليا والوسطي المنتجة للبترول من متكون أبوجابرا بين )اكثر15% إلى 18%( في حين تتراوح قيمة مسامية الطبقات السفلى بين )9% إلى %13(.

من أصل سبعة طبقات رملية مختلفة في أبوجابرا، أظهرت الدراسة طبقة واحدة فقط مستمرة في جميع اآلبار السبع. وتم حساب النفاذية والمسامية وتشبع الماء والنفط لكل طبقات هذا المتكون باإلضافة لمتكون بانتيو، فأظهر تباين في النتائج مما يدل علي إختالف البيئات الترسيبية وطبيعة هجرة الهايدركربونات لها من طبقات المصدر )طبقات طين أبوجابرا نفسه المحتوية علي المادة العضوية(.

Dedication To my parents, To my brothers, sisters To my small family

III

ACKNOWLEDGEMENTS

This thesis has been completed at the faculty of petroleum and minerals – Alneelain University. Under supervision of Professor Khalid Mustafa - Department of Geophysics whose guidance and help are greatly appreciated.

Above all, I would like to thank the Almighty Allah for everything that he has given to me, for his blessings and guidance to finish this work.

I am particularly obliged to Dr. Khalid Mustafa who kindly agreed to carry on the supervision of this work; his assistances, guidance and fruitful discussion during the study period, this in addition to his useful suggestions and continuous follow-up are a real drive to this work.

I am extremely grateful to Dr. Mohamed Abdelhafieth for his both academic and technical advices and assistance during the courses and seminars.

I would also like to extend appreciation to all staff of faculty of petroleum and minerals - Alneelain University specially the geophysical Department and to all colleagues in master program, those in addition to my colleagues Ammar Saufeldin, Ayad M. Idriss, Osama Siraj, Abubakr Mahjoub, Anas Ibrahim and Alaaeldin O. Elsamani , more thanks are extended to my direct supervisors in GNPOC the company for which I am working and to friends and colleagues in Ministry of Petroleum who helped a lot on easing the raw data for the research.

Last but certainly not least, my sincere thanks and appreciation go to my both master and small families for their encouragement and assistance throughout the study and research.

TABLE OF CONTENTS

Abstract I II الخالصة Dedication III Acknowledgements IV Table Of Contents V Table of figures IX List of tables XI

CHAPTER ONE page INTRODUCTION 1. INTRODUCTION 1 1.1 Location 1 1.2 Physiography 5 1.3.1 Drainage 5 1.3.2 Climate 6 1-4 Populations 7 1-5 Scope and Objectives 7 1-6 Materials and Method for the study 7 1-5 Scope and Objectives 7 1-6 Materials and Method for the study 7 1.7 Previous Work 8 CHAPTER TWO GEOLOGY OF THE MUGLAD BASIN AND TECTONIC SETTING 2. REGIONAL GEOLOGY 9 2.1 Regional geology 9 2.1.1 Introduction 9 2-1-2 Sudanese Basins 11 2.2 Rifting in Sudan 13 2.3 Pre-rifting Phase 13 2.4 Rifting Phase 13 2.4.1 First Rifting Phase (Fl) 14 2.4.2 Second Rifting Phase (F2) 16

2.4.3 Third Rifting Phase (F3) 17 2.4.4 Sag phase 18 2.5 Sedimentology and Structure of the Muglad Basin: 18 2.5.1 Lithostratigraphic Units of Muglad Rift Basin 2.5.2 The Precambrian Basement Complex 18 2.5.3 The Late Jurassic / Early Cretaceous – Tertiary strata 19 2.5.4 First Cycle Strata 19 2.5.4.1 Sharif and Abu Gabra Formations 2.5.4.2 Bentiu Formation 21 2.5.5 Second Cycle Strata 21 2.5.5.1 Darfur Group 2.5.5.1.2 Amal Formation 23 2.5.5.1.3Nayil and Tendi Formations 24 2.5.6 Third Cycle Strata 24 2.5.6.1 Kordofan Group 2.5.6.1 .1Zeraf Formation 25 2.5.7 The Tertiary – Quaternary sediments of Umm Rawaba Formation 25

2.5.8 Holocene Deposits 25

2-6 Structural Style of the Muglad Basin 26 CHAPTER-THREE METHODS OF INVESTIGATION 3.1 Introduction 29 3-2 Conventional logging tools used In the Evaluation 29 3-2-1 INDUCED MEASUREMENTS: 30 3.2.1.1. Resistivity & Induction logs: 3.2.1.1. A. Resistivity Logs 3.2.1.1. B. Laterologs 31 .2.1.1. C. Microresistivity Log 32 3.2.1.2: Sonic 33 3.2.1.3: Density (RHOB) 36

3.2.1.4: Photoelectric Effect (PEF) 36 3.2.1.5: Neutron (NPHI), 37 3-2-2 ELECTRICAL LOGS 38 3-2-2-1 Spontaneous Potential (SP) 38 3-3: Gamma-Ray 43 3-3-1: Conventional Natural Gamma-Ray Log (GR) 3-3-2 Spectral Gamma Ray (SGR) 44 3-4 Basic wire line logs using In Formation Evaluation 44 3-4-1 THE NUCLEAR LOGS 3-5 AUXILIARY LOGS 45 3-5-1 Caliper Log 45 3-5-2 Temperature Log 46 3.5.3 Mechanical tools 46 3.5.3-1: Caliper CHAPTER-FOUR THE PETROPHYSICAL STUDY

4-1 Introduction 48 4.2 Data 48 a- set: b- Handling 48

4-3 SOFTWARE: 49 4-3-1 INTERACTIVE PETROPHYSICS (IP) SOFTWARE: 4-3-2 GRAVITAS: 50 4-4 Data Quality 51 4-5 Volume of shale 52 4-6 Porosity 51 4-7 Concept of Low Resistivity Pay (LRP) Zone 53 4-8 Water Saturation 55 4-9 Formation Water Resistivity (Rw) 55 4-10 Hydrocarbon saturation 55 4-11 Wells Correlation: 55

VII

CHAPTER-FIVE CORRELATION & PETROPHYSICAL EVALUATION RESULTS 5.1 Introduction 56 5.2 Data Quality 56 5-3 Petrophysical cut-off values determination 56

5-3-1 Volume of shale (Vsh) cut-off 57 5-3-2 Porosity cutoff 57 5-4 Correlation: 58 5-5 Interpretation of Results of Sand Bodies - Reservoir: 61 CHAPTER-SIX CONCULUTION & RECOMMENDATIONS 6.1 Conclusion 68 6-2 Recommendations 69 REFERENCES References 70

VIII

LIST OF FIGURES List of figures Page No Fig (1-1), A: Location Map of Sudan, 2 Fig (1-1), B: Neem field Location Map of Sudan (Faisal, GNPOC, GIS, 2017). 3 Fig (1-1), C: Study Wells in Neem Field location Map (Faisal, GNPOC, GIS, 2017). 3 Fig.1-2: Regional map of West and Central African rift basins (Revised from G. J. 4 Genik, 1993) Fig (I-3), Drainage Pattern of Neem Oil Field Modified After Eng. Faisal GNPOC, GIS, 6 2017. Fig. 2.1.A: geological map of the south-western part of (Sudan revised after Genik, 10 1992, Block1/2/4 is in the central and south of Muglad basin, GNPOC).

Fig. 2-1-B: Tectonic evolution of West and Central African rift basins (Genick,1992) 10

Fig. 2-1-C: Moving trace and velocity of Africa plate (175Ma-5Ma) (P. Van et al., 11 2003, Subsurface Sediment Mobilization, Ghent University, Belgium.) Fig. 2-2 Regional Stress field during Early Cretaceous ( from Mohamed Y et al, 1999, 12 Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001

Fig 2-3: Regional Stress field during Late Cretaceous (from Mohamed Y et al, 1999, 14 Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001) Fig 2-5: Generalized Stratigraphic column for the Muglad Basin showing principle 16 lithologies, maximum formation thickness, producing horizons and unconformities cycles Dr. Zayid, GNPOC, 1999. Fig 2.6-A: Structural profile (A-A) across Abu Gabra trend of northern Muglad basin 27 (Dr. Li, GNPOC, 2010). Fig (2.6-B): Clarifies the cross sectional view of general structural style of the Muglad 28 Basin. Figure (2.5) Structure depth map of top Abu Gabra, By Dr. Li Zhi, 2010, Muglad Basin, 29 GNPOC. Fig 3-1: Electrode arrangements for MSFL. Note that the electrode 32

arrangements are miniature versions of LL7, ES, and SFL respectively. Fig 3-2: Sketch showing sonic tool configuration 34

Fig 3.5 Typical responses of the SP log in different lithology types. 40 Fig 3.6 Permeability recognition by SP log. 41 Fig 3.4: Diagram of GR log well in Neem field 42 Fig4-1: sketch showing Bound water (left) and capillary water (right). 54

Fig 5-1: Average effective Porosity Studied wells resulted from IP Software 58 Fig 5-2: Correlation of the Seven studied wells in Neem field 59 Fig 5-3: Average Net pay in the Studied wells resulted from IP Software 60 Fig 5-4: Total Net pay in the studied wells resulted from IP Software 60 Fig 5-5: Neem 25: Abugabra Sand Body @ 2436m probable continuous correlated to 62 other study wells unfortunately showing no pay zone. Fig 5-6: Neem 26: Abugabra @ 2424.5m probable continuous correlated to other study 63 wells Fig 5-7: Neem 27: Abugabra @ 2408.5m probable continuous correlated to other study 64 wells Fig 5-8: Log curve combined with Masterlog 66 Fig 5-9: Neem-2 2720—2730m,Log curve combined with Masterlog OWC 66 Fig 5-10 Log curve combined with Masterlog in Neem-1 67

LIST OF TABLES

No Table Page No. 1 Table 3-1: Classification of the common wireline geophysical well 30 measurements (in open, 2 Table 3.2: Photo-electric absorption factor for common minerals 37 3 Table 4.1: Data sets of the study wells 48 4 Table (5.1) Reservoir Summary of Well NEEM -1 61 5 Table (5.2) Reservoir Summary of Well NEEM -2 61 6 Table (5.3) Reservoir Summary of Well NEEM -25 62 7 Table (5.4) Reservoir Summary of Well NEEM -26 63 8 Table (5.5) Reservoir Summary of Well NEEM -27 64 9 Table (5.6) Reservoir Summary of Well NEEM -28 65 10 Table (5.7) Reservoir Summary of Well NEEM -29 65

CHAPTER ONE INTRODUCTION 1 Introduction although several previous studies and oil companies' activities have made valuable contribution to the geological understanding of various sedimentary basins in Sudan. The net result is still quite schematic in some areas, and needs further detailed study. Hydrocarbon accumulations within central and southern Sudan Interior Rift Basin are of most important resources in Sudan. The Muglad Basin is most petroliferous in Sudan Sedimentary Basin. Recently new discoveries in the Kordofan region in SW Sudan in what is locally known as Neem oil field have added new amount of oil. The area is still under exploration and new discoveries have raised the need for new geological and petrophysical research to be carried out in the area, because Abu Gabra Formation here has proved to be a reservoir by the oil company's discoveries, in all its sections upper middle and lower parts of the formation. Core data, Cutting samples interpretation and log response are very important to establish a petrophysical evaluation criteria for such complicated low resistivity thin beds. 1-1 Location: The Muglad Basin Complex is the main petroliferous sedimentary basin in Sudan and represents the western flank of its interior rift basins which are parts of central African rift System (Fairhead, schull, 1988). The Muglad Basin is a northwest-southeast oriented rift trough situated entirely in the southwest Sudan between 26° E and 32° E, and 5° N and 13°N, and is up to 300 km wide and about 1000 km long as shown in Fig. (1-1), A & B.

Fig. (1-1), A: Location Map of Sudan, approximate outlines of the Muglad basin, southwest Sudan (modified after Schull, 1988).

Fig. (1-1), B: Neem field Location Map of Sudan (Faisal, GNPOC, GIS, 2017).

1:13,000 Fig. (1-1), C: Study Wells in Neem Field Location Map (Faisal, GNPOC, GIS, 2017).

The study area is in SW Muglad in Neem Oil field, it belongs to block 4. The Neem field is located in the Kordofan region, Fig. (1-1), A, B & C approximately 1 10km NW of Bamboo oil field and 98km NE of Diffra Area, it is of +/-515m MSL. The deep Cretaceous-Tertiary Muglad Basin forms pan of a regionally linked intra- continental rift system that crosses Central Africa. The Muglad Basin is the largest of these northwest-southeast oriented rift basins. To the northwest, the basin appears to terminate against the Central African Shear Zone (CASZ), which extends from Cameroon through Chad to Sudan. The southeastern basin limit is poorly known but the Muglad and Melut basins may merge southeastwards and link up with the Anza rift in Kenya as shown in in Fig. (1-2).

Fig.1-2: Regional map of West and Central African rift basins (Revised from G. J. Genik, 1993)

1-2 Physiography

Muglad study area is a flat plain surrounded by three major Basement Complex: Nuba Mountains in NE, spreading in border of the Sudan. The Nuba mountain composed of metamorphic and igneous terrain in NE of the area, and consists of granitic/granodioritic gnessies, mica and graphitic schist, metavolcanic, granite and gabbroic rocks. SW of the Muglad area the rocks is consist of various types of gnessies, Amphiboles, graphitic schists and marble (Vail. 1978). In the NW margins (southern Darfur), the Basement rocks are gneisses, schists and quartzite. Stratigraphically Muglad basin was covered by superficial deposit of Umm Rawaba Formation and black cotton soil (clayey and silty soils) with some lateritic soil between Heglig area and Lake Kailack. Isolated Nubian Sandstone outcrops east of Muglad town. The southern part of Muglad basin was covered by wadi sediments and swamp deposits of White Nile and alluvial streams. Also tributaries are found such as Bahr El Arab forming the main accommodation zone in the basin which displays a graben perpendicular to the rift axis ie.fault control sedimentation on the basin, Rashida (2014). 1.3.1 Drainage

The White Nile and its tributaries which are Bahr Arab, Bahr El Gazal and Bahr El Zaraf are the major drainage in the area. The southern part of the White Nile River is called Bahr El Gabal. The White Nile is flowing across the southern and eastern parts of the Muglad Basin, Rashida (2014). The Kordofan and Darfur surface water drainage systems are mostly seasonal streams, drainage pattern of study area are shown in Fig. (1-3).

Fig. (I-3), Drainage Pattern of Neem Oil Field Modified After Eng. Faisal GNPOC, GIS, 2017. 1.3.2 Climate

The area of southern and central Sudan is characterized by semi-arid in the north and rainy with higher humidity southward. There is seasonal variation in rainfall and temperature, the majority of rainfall occurs normally during, July. August and September, the annual rainfall fluctuated between 100mm- 800mm to the south. This rainfall is subjected to irregularity during 1985- 1987 causing a regional drought and desertification. According to Smith, (1949 and Jackson, 1959), The natural vegetation ranging from drought resistance grass and shrubs in arid north to thick forests in the well-watered south, considerable parts the areas are covered by Hashab, Heglieg, Sunut, Tebledi and Aradeib in the 6 flood plain area, swamp and Lagoons of the Sudd (Now South Sudan country) area where a tropical equatorial vegetation is prevalent, Mohamed,(2003).

1-4 Populations

The population of the study area associate mostly of Baggara tribes like Misseriya, beside Dinka, Nuba and Daju (El Badi, 1995), other minorities living in the area include the Kababish and Kawahla to migrate with their sheep to south. The present of the population settle in the towns and villages, but the rest are nomads who migrate seasonally in search of water and pasture for their herds which are mainly of cattle, sheep and goats (Mohammed, 2003). Livestock rising is the major activity. The ecological conditions as well as the long experience of the inhabitants turn pastoralism as the most worthwhile occupation. However, some people grow sorghum (Dura), millet, cotton, sesame, groundnut, Arabic gum and some vegetable and fruits. All crops are grown depending on episodic rainfalls.

1-5 Scope and Objectives The objective of this is study is to follow an application derived and manual methodology methods in order to interpret well log data for petrophysical evaluation of the Abugabra formation-Neem Field in Muglad basin, focusing on low resistivity pay zone and try to figure out a characteristics that helps in understanding and finding out behavior of different wire line logging tools in such oil bearing zones and can be summarized as follows: I. Interpretation of well logs data for Petrophysical Characteristics Evaluation of, Abugabra formation payzones which are generally characterized by low resistivity. II. Correlation of the well logs data.

1-6 Materials and Method for the study To conduct this study in a successful way, the following materials and information made available by the Oil Exploration and Production Authority (OEPA):

1- Wells data includes: i. Seven Wire Line logs for Seven logs. ii. Seven Master logs. iii. Seven Final geological reports. 1.7 Previous Work Many geological research deals with sedimentary, stratigraphy, tectonics, ground water exploration and geophysical studies led to discovery of sub basined areas in Muglad Basin, having significant oil accumulation. Chevron Overseas petroleum Inc. (1975) carried out aeromagnetic and gravity survey to delineate major fault bounded series of the sedimentary basins striking southeast from Nyala towards the Sudan interior basin., Browne and Fairhead (1983) following Chevron’s successful search for hydrocarbons in southern Sudan rift, extended their hydrocarbons search into Melut concession block along the White Nile. Whiteman (1971) reported that the oldest sedimentary strata within the study area are the purple and green argillaceous mudstone of the Nawa Formation. Rashida, (2014), commented that vertical and lateral clay minerals distribution in Abu Gabra Formation were directly related to depositional environments, tectonic and diagenetic changes, and high abundance of kaolinite due to reworking of laterites on the rift basin flanks and adjacent land masses which has been repeatedly reworked, transported and deposited in fluvial-lacustrine-deltaic system. Rashida (2014), Genik (1992) suggested that the early Cretaceous Abu Gabra Formation is predominantly argillaceous but more are nacreous Abu Gabra Formation Equivalent was identified by Rashida (2014) in the well located within the margins of southeast Muglad basin and conducted characterization of the facies, sequence, palynofacies and established depositional and sequence stratigraphic models for Abu Gabra Formation in Neem field and evaluate the sandstone reservoir heterogeneity and quality of the same. Rashida established guides and leads for future oil exploration based on depositional and sequence stratigraphic models.

CHAPTER TWO

GEOLOGY OF THE MUGLAD BASIN AND TECTONIC SETTING

2. Regional geology and Tectonic Framework 2.1 Regional Geology 2.1.1 Introduction The Muglad Basin is a major part of Sudan rift, which, in turn, is a main component of West and Central African rift-related system (WCARS) (Fig.2-1-A). Muglad basin is formed on the stable Pre-Cambrian basement which was subject to the control and extension of right-lateral shear stress field of Mid-African Shear Zone. The origin and structural style of the basin is similar to other well-known hydrocarbon producing graben systems, such as the North Sea, Viking Graben and the Gulf of Suez. It trends northwest- southeast and consists of a thick Mesozoic and Tertiary continental syn-rift sequence buried by a Miocene-Recent post-rift sedimentary cover. These continental sediments comprise fluvial and lacustrine facies. The Muglad Basin is the most extensively explored and proved to contain as much as 13 km of sediment. An extension of 32% for the southern Muglad Basin was estimated from the amount of basin infill, and a depth of 12-16 km was estimated for detachment within the crust. Rifting began in the Late Jurassic-Early Cretaceous and continued up to the end of the Oligocene (Schull, 1988; Bosworth, 1992; McHargue, 1992) Fig 2.1- B & 2.1-C.

The rifting occurred in three episodes giving three cycles of sediment deposition, all of continental facies. Each cycle gave rise to a coarsening-upward sedimentary sequence and the three cycles have been dated as Late Jurassic-Early Cretaceous (140-95 Ma), Late Cretaceous (95-65 Ma) and Paleogene (65-30 Ma).

z Fig. 2.1.A: geological map of the south-western part of (Sudan revised after Genik, 1992, Block1/2/4 is in the central and south of Muglad basin, GNPOC).

Fig. 2-1-B: Tectonic evolution of West and Central African rift basins (Genick,1992)

Fig.. 2-1-C: Moving trace and velocity of Africa plate (175Ma-5Ma) (P. Van et al., 2003, Subsurface Sediment Mobilization, Ghent University, Belgium.)

2-1-2 Sudanese Basins Sudanese interior rift system consists of four rift basins, Evolution of which in particularly in Muglad Basin tectonic sedimentological, paleogeographical developments in central and southern. Sudan rift Basin has been influenced by local and global geological events in NE Africa cover an area some 1000 km wide (Salama, 1997) (Fig. 2.2). The most important one is the Muglad basin, which extends along its length up to 800 km, and is connected, through the South Sudan Shear (SSS), with the Anza rift in the North Kenya (Bosworth, 1992). It is formed due to strike -slip movement and created intensive extensional basins in Nigeria, Cameroon, Niger, Chad, and Kenya. (Fairhead, 1986. 1988', as seen in Fig. (2-2). although the thickness and completeness of the formations are variable from basin to basin. There exist several unconformities or hiatus within the sequences, which separate the Abu Gabra from the Bentiu

Fig. 2-2 Regional Stress field during Early Cretaceous ( from: 1999, Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001)

Formations, the Bentiu Formation from the Darfur Group, the Amal from the Nayil and Tendi Formations, and the Tendi from the Adak and Zeraf Formations in the Muglad basin, however, most of the unconformities can only be observed on the basin margins, but do carry implications for basin development. During late Cretaceous – Teniary is dominated by volcanic eruption in North Kenya and Ethiopia associated with the East African Rift (Rashida, 2014). The Basins within Babanusa trough are defined by the extensive faulting system extending in NW-NE and E-W(Anon,1981a,b.1982:Schull1988). Wadi El Kuu rift is formed by Sag El Naam NW trending graben and Wadi El Kej E_W graben. All these Basin Basins is related to East and West African rift systems and terminate against shear zone. Muglad and Meult Basins extended southward and link up with Anza rift in Kenya. Most of these basins are asymmetrical halfgraben and also symmetry graben was present. They are a combination of NW-SE. NS or NNE-SSW directions.

2.2 Rifting in Sudan:

Fairhead. 1988 and Mc Hargue et al. 1992 suggested that the rift basins of southern Sudan are related to Jurassic rifting of the Lamu Embayment and Anza trough in NW Keny. this is supported by geophysical. Structural, palynological and sedimentological data. Based on deep seismic reflections profiles and from well information they divided the tectono-sedimentary evolution of the southern rift basin in Sudan into a pre-rifting phase, three rifting phase and a sag phases.

2.3 Pre-rifting Phase Late Paleozoic-Early Mesozoic By the end of the Pan African orogeny (550±100 Ma). the region became consolidated platform. From Paleozoic-early Mesozoic this highland platform provided sediments for adjacent subsiding areas, which is continental sediment in nonhwest Sudan, close to Chad and Libyan border.

2.4 Rifting Phase

Because of the scarcity of Cretaceous-Early Tertiary outcrops, the knowledge about the stratigraphy only relies on well information and the inferences made with the Seismic data (Fig.2-3).

Fig. 2-3: Regional Stress field during Late Cretaceous (from: 1999, Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001)

Three distinct periods of rifting occurred in response to crustal extension, which provided the isostatic mechanism for subsidence which accomplished to basin axis and margins. Each rift cycle shows regionally angular unconformity, a basined sandstone unit deposited above unconformity of the rift initiation phase followed by an upward coarsening section of lacustrine mudstone and sandstone that accumulated during the rift phase. And regionally clipping blanket of fluvial and al1uvial and alluvial sandstone deposited during thermal sag phase, while the shale dominated deposited during active faulting.

2.4.1 First Rifting Phase (Fl) The early Cretaceous (140 - 90 Ma),( rifts of the interior Sudan were linked to major rifts/spreading centers in the proto-south Atlantic by the dextral

WSW-trending Central African Shear Zone and to the Indian ocean NW-trending Anza rift in Kenya. (Mohammed et., al 1999). Some basins developed within and in the immediate vicinity of the Cretaceous Shear zones due to shear movements. Moreover. Fairhead and Green (1989) suggested that the movements of the Central Africa Shear Zone as extensional basins »!' the Sudan interior. Fl deformation involved high strain rates, rapid syn-rift crustal stretching and subsidence, and the formation of' deep, fault-bounded transitional and transtensional pull-apart basins. The sediments of this cycle are consisting mainly of clay stone and shales deposited in lacustrine/flood plain environments. The first cycle end with the sag phase deposition of predominantly thick sandstone of braided streams of Bentiu formation. In Abu Gabra Formation No volcanism evidence was seen in phase1 Fig., (2.1, A).

Fig. 2-5: Generalized Stratigraphic column for the Muglad Basin showing principle lithologies, maximum formation thickness, producing horizons and unconformities cycles Dr. Zayid, GNPOC, 1999.

2.4.2 Second Rifting Phase (F2) The second rifting phase occurred during Late Cretaceous and Lower Tertiary (90-60 Ma). Changes in the opening of the South Atlantic account for a Late Cretaceous period of shear movement on the West and Central African Rift system. This movement could explain Late Cretaceous Benue compression and dextral reactivation of the Central African Share Zone (CASZ). During the F2 and F3 deformations, the rates ofsubsidence and stretching were much lower and were focused within smaller geographic areas. The second rift

16 phase may be related to this movement. In the east-northeast -west-southwest trending Baggara Graben to the northwest, a continuation of the Central African Shear Zone strike-slip movement has been inferred from compression features interpreted from seismic data. This continuing strike-slip movement is not seen in the adjoining northwestern Muglad Basin or further. This rifting was accompanied by minor volcanism represented by wells located in north western part ofMuglad basins and by a Senonian andesitic tuffin central Melut basin (Schull, 1988), Fig. (2-2).

2.4.3 Third Rifting Phase (F3) The third rifting phase during Tertiary to Recent respectively (fiOMa-recent). The initiation of this cycle was occurring during initial opening of the Red Sea (Wuenschel P. C., 1960).This formation is dominated by claystone of fluvial flood plain and lacustrine environments, and was contemporaneous with the initial phases of the opening of Red Sea and East African Rift System. The Muglad, Melut and Blue Nile basins are sub-parallel to the Red Sea and rifted in response to the African-Arabian extensional movements. A direct relationship between East African rifting and the development of southern Sudan basin is not apparent (Schull, 1988). A sharp contrast is seen between the Teniary development of the southern Sudan basins and the West African basins, which exhibited strong Cretaceous similarerities.In the Late Tertiary, the regional stress regime changed, resulting in the Middle Miocene termination of southern Sudan rifting. The only evidence of volcanism in wells is the occurrence of thin Upper Eocene basalt flows in the Melut Basin near Ethiopia. However, age dating of widely scattered volcanic outcrops indicates volcanism in Sudan at this time (Vail, 1978, Schull, 1988), Fig. (2.2).

2.4.4 Sag phase Mid Miocene Recent The basin evolution is started with rifting which is generally characterized By alternating tectonic pulses and quiet periods (sag phase), pluses of extension and quiet are indicated by high faulting and fault-controlled sedimentation (tectonic subsidence), while sag phases are indicated by minor faulting (thermal subsidence). In Muglad and Melut basin sag phase related to the three rifting phases suggesting an erosion of the sags and/or a shon duration of the quiet period, it is more obvious for the third phase. In Mugatd basin, Bentiu formation deposited during the first sag phase, Amal formation deposited in the second Sag phase and Adok formation deposited in the third sag phase, the sediment area became wider in the basin in the sag phase. Currently the area is tectonically stable with little earthquake and no volcanic an activity, (Rashida 2014, Browne et ai. 1985).

2.5 : Sedimentology and Structure of the Muglad Basin: 2.5.1 Lithostratigraphic Units of Muglad Rift Basin The main stratigraphic units in the Muglad area are: i. The Precambrian Basement Complex. ii. Late Jurassic / Early Cretaceous–Tertiary strata. iii. The Tertiary–Quaternary sediments of Umm Rawaba Formation. iv. Holocene to recent.

2.5.2 The Precambrian Basement Complex The basement rocks bordering towards the NE and SW constitute the elevated shoulders of the Muglad basin (Fig. 2.1 A&B). These rocks are part of the Sudanese shield and comprise of a metamorphic terrain intruded by localized igneous bodies. These metamorphic rocks date back to the Archean Era. They experienced multiple deformation and reworking phases through their evolution and that ended with the Pan African Tectono Thermal Episode (Schandelmeier et al., 1987) at about 550 Ma. The Basement

18 rocks were penetrated and cored in many wells within the NW Muglad area, in Baraka-1, Adila-1 by Chevron and one wells by GNPOC Azraq E-1 well, . At Baraka-1, Adila-1 the primary composition is granitic and granodioritic gneisses which has been dated as 540 ±40 Ma (Schull, 1988).

2.5.3 The Late Jurassic / Early Cretaceous – Tertiary strata The lower strata (Late Jurassic / Early Cretaceous to Tertiary) in the Muglad Basin are no marine sediments deposited in lakes, deltas, alluvial fans and fluvial environments. Based on the cyclic subdivision of the “Nubian Sandstone” of NW Sudan, the sedimentary rocks of the Muglad Basin belong to the upper or the Nubian Cycle. The following accounts, which are on the stratigraphy and sedimentology of the Late Jurassic / Early Cretaceous–Tertiary strata were summarized after Schull (1988) and Kaska (1989). Kaska (1989) have established five spore/pollen zones for the Early Cretaceous to Tertiary no marine sediments of the central Sudan on which age determination and correlations are made. These zones are: Early Cretaceous, Middle Cretaceous, Late Cretaceous, Early Paleocene and Oligocene/Late Eocene. The discovered flora is related to the Africa–South America (ASA) flora province. As a result to the repeated rifting, subsidence and sedimentation, three coarsening upward cycles have formed:

2.5.4 First Cycle Strata 2.5.4.1 Sharif and Abu Gabra Formations The Sharif and Abu Gabra Formation comprise the first sedimentary units that were deposited during the early rift phases in the new graben like developing structures (Fig. 2.6). The Sharaf Formation is early syn-rift sediments of this first cycle deposited during the Neocomian–Barremian. During the Neocomian the Sharif Formation was deposited in fluvial flood plain and lacustrine environments. It comprises clay-stones, siltstone, and fine-grained sandstones. The maximum thickness of this unit is approximately 370 m in the NW of the Muglad Basin (Schull, 1988), however seismically it is indicated to be much thicker in the deeper troughs (Fig. 2.6). Within the Albian–Aptian time, the sedimentation was continued in lacustrine and deltaic fan environments resulting in the Abu Gabra Formation (Fig. 2.6). Several

19 thousand feet of organic rich lacustrine claystones and shale were deposited with interbedded fine-grained sands and silts. The nature of this deposit was probably the result of a humid climate and lack of external drainage. This unit is estimated to be up to 1830 m thick and it is the main source rock in the Muglad basin (Schull, 1988). Vertical and lateral clay minerals distribution in Abu Gabra Formation were directly related to depositional environments, tectonic and diagenetic changes, and high abundance of kaolinite due to reworking of laterites on the rift basin flanks and adjacent land masses which has been repeatedly reworked, Transported and deposited in fluvial-lacstrine-deltaic system. Two assemblage zone were detected in clay minerals distributions in Abu Gabra Formation, upper zone represent upper Abu Gabra Formation consisting of kaolinite, smectite, illite.illite/smectite and chlorite and middle zone represent middle Abu Gabra formation consist of kaolinite,smectite,illite,illite/smectite and chlorite, and High percentage of kaolinite in upper Abu Gabra Formation in fluvial/distributary channels of delta which are dominant coarse grain and high energy power promote kaolin formation due to rapid flush of ion concentration. Middle Abu Gabra Formation, lacustrine systems form kaolin through pedogenetic processes due to intensive weathering and strong leaching in source area under humid and warm climate. Smectite in upper Abu Gabra Formation were formed during hot dry period with low relief area and poorly drainage that prevents the silica and the alkaline earth ions to be rapidly removed, it decreases with depth and due to diagenetic processes, and disappear in middle Abu Gabra Formation, and transformed to illite, chlorite and/or nixed layer of illite/smectite. The upper Abu Gabra clay minerals distribution show abundance of kaolinite and smectite which widely affected by environment influence factors, and less effects by burial diagenesis.

The middle and lower Abu Gabra Formation show abundance of kaolinitic lacustrine system and illitc, and mixed layer which affected by tectonic/environmental changes and burial diagenesis process controls. The higher percentage of illite may be due to climatic factors such as dry conditions as well as to the origin of parent rock of the sediments, with active and strong pedogenesses processes with depth, thus kaolinite and K-feldspar at greater depth with high temperature are transformed and illitization take place. At the same time with increase in depth there is an increase of I/S mixed layer under the influence of climatic/diagenetic processes (Rashida, 2017).

2.5.4.2 Bentiu Formation

The first depositional cycle ended with deposition of the predominantly sandy sequence of the Bentiu Formation during Late Albian–Cenomanian (Fig. 2.6 A). The deposition of the Bentiu Formation most probably represents a period of ceasing of the initial active rifting. This period constitutes the sag phase of the basin development that followed the rapid initial tectonic subsidence. This formation consists predominantly of thick sandstone beds, deposits of braided and meandering streams, intercalated with thin claystone beds. The Bentiu Formation represents a change in the depositional style from an internal to an external drainage system. The Bentiu Formation may reach up to over 1500 m thickness in some localities (Fig. 2.5). and typically shows good reservoir quality (Schull, 1988).

2.5.5 Second Cycle Strata 2.5.5.1 Darfur Group

The deposition of the Darfur Group during Turonian–Late Senonian represents the second rift phase. It is characterized by a coarsening upward sequence comprising five formations from bottom to top; these are Aradeiba, Zarga, Ghazal and Baraka

Formations (Fig. 2.6 A&B). At the bottom of the sequence the Aradeiba Formation was first assigned by Chevron to include mainly the thick sandstone-clay strata which lie over the thick sandstone sequences of the Bentiu Formation and underlie the Zaraga Formation. In lithofacies criteria, the boundary between Aradeiba and Bentiu Formations is seen as an upward passage from predominantly fluvial sandstone at the top of the Bentiu Formation to very thick mudstone – shale sequences at the base of the Aradeiba Formation. The formation consists of mudstone, subfissile shale, siltstone and moderately thick interbeds of fine to medium grained sandstone. The mudstones and the shales are dominantly grey in color and locally grading into siltstones of the same color. The thickness of this formation in Heglig and Unity areas ranges between 242.5 – 385 meter (Fig. 2.5).. The upper boundary of this formation with the overlying Zarga Formation is hard to pick, because of the similarity between the upper part of Aradeiba and the lower part of Zarga Formation. In Unity and Heglig Fields, this formation acts as a major reservoir horizon and as a seal as well. Palynological studies by (RRI, 1991) suggest a lacustrine depositional environment with fluvial – deltaic channels and assigned a Turonian–Cretaceous age for this formation. The Zarga Formation was originally identified by Chevron. Its Coniacian age was assigned by (RRI, 1991). The Zarga Formation overlies comformably the Aradeiba Formation. The upper boundary of this formation with the overlying Ghazal Formation is recognized by lithofacies criteria as an upward passage from the mudstone – shale intervals at the top of the formation, to a more arenaceous siltstone section at the base of Ghazal Formation. The formation consists of interbedded sequences of mudstone, sandstone and siltstone (Fig. 2.5). It is more argillaceous towards the basin centre. The sandstone as seen from the wells of Unity and Heglig Fields is coarse to fine-grained. The mudstone and the siltstone are yellow to brown in color and slightly calcareous. This formation was identified in all wells of the SE Muglad Basin and particularly in the Unity and Heglig Fields with variable thicknesses ranging between ± 45.5–288 feet. Similar to the Aradeiba Formation, the Zarga Formation was deposited in a lacustrine environment with fluvial – deltaic channels (RRI, 1991). The name of the Ghazal Formation was given by Chevron to describe the sediments of the uppermost reservoir horizon in Unity and Heglig Fields. Recently, (RRI, 1991) has assigned a Coniacian–Santonian age to this formation. This

22 formation was identified in all wells of the SE Muglad Basin, and particularly in the Unity and Heglig Fields. However, in the NW Muglad Basin this formation is undifferentiated. The thickness of this formation in Unity and Heglig areas ranges between ± 118–318 feet. The formation is litho logically similar to the underlying Zaraga Formation. It contains mudstone, shale, siltstone and sandstone (Fig. 2.5). The mudstone is yellow to brown in color, slightly calcareous and occasionally grading into brown siltstone. The sandstone is mainly medium- to coarse-grained. The upper boundary is identified by an upward passage from a section of equally interbedded mudstone, siltstone and sandstone sequences to predominantly arenaceous intervals at the base of the overlying Baraka Formation. On the basis of abundant microspores and freshwater algae, (RRI, 1991) proposed a fluvial and alluvial fan environment for this formation. The Baraka Formation was originally identified by Chevron in the Muglad Basin as the topmost arenaceous strata of the Darfur Group. Unlike the other members of the Darfur Group, the Baraka Formation does not contribute to the reservoir zones in the Unity and Heglig Fields; this is because of the absence of adequate sealing (Fig. 2.5). The age (Lower Campanian) of the formation was assigned by (RRI, 1991) using palynological evidence. This formation was identified in all of the wells of the SE Muglad Basin. The thickness of this formation in the SE Muglad area ranges between 91–364 feet. The Baraka Formation consists mainly of sandstone interbedded with thin beds of green to grey mudstone. The sandstone is dominantly fine- to coarse- grained and occasionally very coarse. The presence of abundant microspores and freshwater algae (RRI, 1991), suggests that the formation was essentially deposited in fluvial to alluvial fan environment. However, the presence of minor evaporitic intercalations, may further suggest short periods of hypersalinity.

2.5.5.1.2 Amal Formation

Amal Formation declared the onset of depositional processes during the Tertiary period; however this Formation represents the closure of the second depositional cycle in the Muglad basin (Fig. 2.6). During the Paleocene the massive sandstones sequence of the Amal Formation (up to 762 m thick (Fig. 2.5) was deposited in high-energy

23 environments comprising regionally extensive alluvial plains with coalescing braided streams and alluvial fans. The Amal sandstone is composed dominantly of coarse to medium grained quartz arenite, which forms potentially excellent reservoirs (Schull, 1988). 2.5.5.1.3Nayil and Tendi Formations These sediments represent a coarsening-upward depositional cycle that occurred from late Eocene to middle Miocene. The lower portion of the cycle is characterized by fine- grained sediments related to the final rifting phase. The deposits represent an extensive fluvial-floodplain and lacustrine environment. These lake deposits appear to have only minor oil source potential; however, they offer an excellent potential as a seal overlying the sandstones of the Amal Formation.

2.5.6 Third Cycle Strata 2.5.6.1 Kordofan Group

This group constitutes the final depositional cycle in the Muglad Basin (Fig. 2.2). The third rifting phase was created by the reactivation of extensional tectonism during Late Eocene–Oligocene time (Schull, 1988). The syn-rift sediments of this cycle consist of the Nayil and Tendi Formations, which represent the middle part of the Kordofan Group (Fig. 2.5). These formations are dominated by claystones deposited in fluvial/ floodplain and lacustrine environments. The lacustrine facies of the Nayil and Tendi formations appear to have only minor oil source potential, however they offer an excellent seal for the underlying massive sandstones of the Amal Formation. On top of the section of the Kordofan Group the Adok Formation was deposited during the Late Miocene. It comprises medium to coarse-grained sandstone, rarely interbedded with thin beds of claystones (Schull, 1988).

2.5.6.1 .1Zeraf Formation

The third cycle ended the deposition of the Zeraf Formation during Late Oligocene to Middle Miocene/ Recent. Sandstones and sands dominate in the Adok and Zeraf Formations, with only minor clay interbeds. Deposition happened mainly in braided stream environments. In the seismic sections the Zeraf Formation shows no evidence of disturbance of the sedimentary horizons due to tectonic faulting

2.5.7 The Tertiary – Quaternary sediments of Umm Rawaba Formation

The Tertiary–Quaternary sediments of the Umm Rawaba Formation represent the most widespread formation within the south central Sudan basins. It covers the surface area of the Muglad Basin, and consists of unconsolidated to semi-consolidated gravels, sands, clayey sands and clays of fluvial and lacustrine environments, deposited during the Miocene– Pliocene (El Shafie, 1975). The sediments of the Umm Rawaba Formation generally show rapid facies changes, which make the lateral correlation somewhat difficult (Ahmed, 1983).

2.5.8 Holocene Deposits

These are unconsolidated sands, clayey sands and black clays, which vary considerably in thickness. Black clays vary in thickness from a few centimeters to over 10 meters and conformably overlie the Umm Rawaba Formation (Table. 2.6-A). Wind- blown sand deposits (Goz) are widely spread in the northwestern part of the Muglad Basin. Fluvial deposits are found along the major drainage systems and are generally composed of sandy and clayey sediments, which sometimes form shallow aquifers. The weathering products along the western side of the Nuba Mountains form narrow bands of washed out debris deposits around the hills (Vail, 1978).

2-6 Structural Style of the Muglad Basin

Structure of Muglad basin is the below types graben/half graben, horst, fault step. Up to now, there are 5 major trap types were found in Block1/2/4, such as up-thrown fault block, Faulted anticline, Complex fault block, down-throw fault block and Rollover faults (Dr. Li, GNPOC, 2010). Structurally the Muglad Basin is dominated by dip-slip normal faults, oblique-slip, strike- slip faults, and partially reverse faults as well. The three rifting phases resulted in a complex history of horst and graben development and the formation of highly complicated fault systems Schull (1988). The predominated orientation is parallel or sub- parallel to the strike of the primary grabens and basins margins. These longitudinal faults strike N40 – 50W. Faults oblique to the primary trends of the Muglad, Melut and Blue Nile Basins are common. Few major transverse faults occurred and faulting in general exhibits great variety in the displacement of the rocks (Fig. 2.6 A). Neem reservoir is an up-throw fault block oilfield. A classic tilted fault block reservoir; and this trap was Controlled by intra-basinal fault systems in Eastern trend related to tilted basement background (Dr. Li, GNPOC, 2010).

Fig. 2.6-A: Structural profile (A-A) across Abu Gabra trend of northern Muglad basin (Dr. Li, GNPOC, 2010). Fig. (2.6-B): Clarifies the cross sectional view of general structural style of the Muglad Basin.

Fig. (2.5) Structure depth map of top Abu Gabra, By Dr. Li Zhi, 2010, Muglad Basin, GNPOC.

CHAPTER THREE METHODS OF INVESTIGATION

3-1 INTRODUCTION Wireline logging is a process that depends on lowering the logging cable into a drill well by loggers for the measurements of physical, chemical, electrical, or other properties of rock/fluid mixtures penetrated by drilling a well into the Earth’s mantle. Well logging is usually carried out with instruments that are either suspended from a steel cable (wireline) or embedded in the drill string (logging while drilling, LWD). The wireline log is a graph and the data are continuous measurements of a log parameter against depth. When a log is made, it is said to be RUN. A log run is made at the end of a drilling phase and before casing is set in the hole and each of the runs is numbered being counted from the first time that the particular log is recorded. The geophysical well logging was first developed for the petroleum Industry by Marcel and Conrad Schlumberger in 1927. The Schlumberger brothers developed a resistivity tool to detect differences in the porosity of the sandstones of the oil field at Merkwiller- Pechelbronn in eastern France (Schlumberger, 1989). Wireline logging is the established way of gathering about hydrocarbon bearing reservoirs over the length of the well and the objective is to obtain information on hydrocarbon. Schlumberger is the most giant international logging company, additional two American names raised later are Western atlas logging services which was called atlas and Halliburton logging services Physical properties such as resistivity, density, natural gamma radiation, and magnetic resonance are recorded as a function of depth. These physical properties are converted into petrophysical properties of the rock . 3-2 Conventional logging tools used In the Evaluation In this study the two conventional set of tools are PEX-HRLA and SLAM sets , they were run to well together as one package of almost same function with different resolutions and depth of investigation including Deep Laterolog (LLD) , Shallow Laterolog (LLS) , Micro-Spherically Focused log (MSFL), Acoustic log (DT), Density log (RHOB), Neutron log (NPHI), Natural Gamma ray log (GR), Spontaneous Potential (SP) and Caliper log (CAL).

Generally PEX-HRLA including tools advance than the SLAM log mainly in resistivity which reads in different five depths of investigation into formation perpendicular to the bore hole column. The wells interpreted in this study are Neem 25, Neem 26, Neem 28 and Neem 29 were logged by CNLC i.e. SLAM log and Formation Multi Tester Log (FMT) whereas the well Neem 27 was logged by Schlumberger i.e. PEX-HRLA conventional log and Modular Dynamic Tester log (MDT-GR) for the formation pressure measurements (Table 3-1).

Table 3-1: Classification of the common wireline geophysical well measurements (in open hole) main run conventional logging tools No Log type Formation parameter measured 1 Induced Resistivity Resistance to electrical current measurement Induction Conductivity of electrical current Sonic Velocity of sound propagation Density Reaction to gamma ray bombardment Photoelectric Reaction to gamma ray bombardment Neutron Reaction to neutron bombardment 2 Spontaneous Temperatures Borehole temperature measurements Self-potential Spontaneous electrical currents Gamma ray Natural radioactivity 3 Mechanical Caliper Hole diameter Tools

3-2-1 INDUCED MEASUREMENTS: 3.2.1.1. Resistivity & Induction logs: 3.2.1.1. A. Resistivity Logs The Resistivity log are measurement of the formation resistivity with direct current using the principles of Ohm’s law into different depth along the wall of the drilled well. During the first quarter century of well logging, the only electrical surveys (ES) available were the resistivity logs made with so-called lateral and normal devices plus the spontaneous potential (SP). Resistivity is a measure of the formation’s ability to impede the flow of electric current.

The basic measuring system has two current electrodes and two voltage electrodes. Resistivity is the key to hydrocarbon saturation determination and the measuring unit is ohm-meters and they are plotted on a logarithm scales in track 2. The Resistivity logs can be grouped into three measurements; Induction logs, Laterologs, and Microresistivity measurements.

3.2.1.1. B. Laterologs The laterolog tools use focusing or bucking currents into a planar disc shape and monitor the potential drop between an electrode on the tool and a distant electrode. The potential drop changes as the current and the formation resistivity changes and therefore the resistivity can be determined.

Because new information can often be obtained by reinterpreting old ES logs, this chapter includes discussion of the principles and responses of the ES measurements.

The first resistivity devices were the normal and laterals. These were, in concept, extensions to laboratory four-terminal resistivity-measuring cells. Current is injected in the formation from a single electrode and returned to a point remote from the well. The current near the injection electrode spread out radially from the electrode. Two voltage–measuring electrodes (M and N) on the sonde approximated the measurement of a constant-voltage spherical shell around the injection electrode. The measurements of voltage and current are converted to a resistivity measurement.

Laterolog applications include the following:  Measures True (Undisturbed) formation resistivity Rt  Useful in medium to high resistivity environments  Overpressure detection.  Fluid saturation determination.  Diameter of invasion determination.

For normal devices (Fig. 3-1), the distance AM is small: 1 to 6 ft as compared with MN, MB, and BN. In practice, N or B may be placed in the hole at a large distance above A and M [the voltage measured is practically the potential of M (because of current from A), referred to an infinitely distant point]. The distance AM of a normal device is its spacing. The point of

31 measurement is midway between A and M. The most common normal spacings were 16 and 64 in. Limitations of the Laterologs are:  Affected by the Groningen effects in some environments  Cannot be used in oil-based muds  Cannot be used in air-filled holes 3.2.1.1. C. Microresistivity Log The microresistivity logs are pad mounted tools with shallow depth of investigation and of higher resolution All had electrodes implanted on a small pad pushed against the face of the wellbore. They are designed to measure only an inch or two vertically, with a similar depth of investigation.. Tools are focused to pass through the mud cake. The tool uses a set of five electrodes which focus the signal into the invaded zone just before the mud cake. The shallow reading versions of this resistivity tool are always pad-mounted. First was the Micro-log which is still in use, second was the Micro-Laterolog (MLL), replaced by Proximity (Pl) tool and thirdly the Micro-Spherically Focused Log (MSFL) which has another version as Micro-Cylindrical Focused Log (MCFL). The tools are variously affected by factors like mud cake thickness of the invaded zone. Table 3.5 below shows common names used for the microresistivity logs.

Fig 3-1: Electrode arrangements for MSFL. Note that the electrode arrangements are miniature versions of LL7, ES, and SFL respectively.

Microresistivity log applications are:  Determination of flushed zone formation resistivity Rxo.  Flushed zone water saturation (Sxo) through Archie’s Equation.  Invasion corrections deep resistivity tools.  Thin bed definition.

Limitations of the tools are:  Rugose hole  Oil-Based mud  Heavy or thick mud cake

3.2.1.2: Sonic Sonic logging is a well logging tool that provides a formation’s interval transit time, designated as Δt which is a measure of a formation’s capacity to transmit seismic waves. Geologically, this capacity varies with lithology and rock textures, most notably decreasing with an increasing effective porosity. This means that a sonic log can be used to calculate the porosity of a formation if the seismic velocity of the rock matrix, Vmat, and pore fluid, Vt, are known, which is very useful for hydrocarbon exploration.

Fig 3-2: Sketch showing sonic tool configuration

The basic equation for sonic porosity is the Wyllie Time Average given below:

Where:

= Sonic Porosity

= Formation of interest sonic log reading

= Matrix travel time

= Mud Fluid travel time

There is another way of transforming slowness to porosity called “Raymer Gardner Hunt”. This formula tries to take into account some irregularities observed in the field. The simplified Version of Ramer –Gardner Hunt is given in equation 5 below:

Where C is a compaction constant usually taken as 0.67.

3.2.1.3: Density (RHOB) This tool is a continuous record of formation bulk density which is the overall density of a rock including solid matrix and the fluid enclosed in the pores. The unit of Density measurement is in gram per centimeter cubed (g/cm3), plotted on a linear scale. The density tool is extremely useful as it has high accuracy and exhibits small borehole effects. But badly affected by bad hole condition due to its shallow depth of investigation compared to resistivity DLL tools. The major uses are in the determination of porosity as given below: Determination of porosity=

……………….. )3.3(

Where:

= Porosity

= matrix density

= density from log

=Fluid density of the mud filtrate

The other uses of the density log are:  Lithology identification in combination with Neutron tool.  Gas indication in combination with Neutron tool.  Formation acoustic impedance in combination with sonic tool.  Shaliness of formation in combination with Neutron log.

3.2.1.4: Photoelectric Effect (PEF)

The photo-electric effect log is influenced more by atomic number than by electron density. The photo-electric effect only occurs at low energy; generally below 100 KeV (Fig.

3.3). It measures the absorption of low energy gamma rays by the formation and is calibrated into units of barns per electron.The logged value is a function of the aggregate atomic number of all the elements in the formation and so is a sensitive indicator of mineralogy. The log is less sensitive to porosity and caving effects since hydrogen has a very low atomic number. The Phoelectric response depends on the atomic number of the elements in the formation and varies according to the chemical composition. The Photoelectric effect log provides a direct indication of lithology. The Table below present the photoelectric absorption factors (Pe) for common sedimentary minerals.

Table 3.2: Photo-electric absorption factor for common minerals

3.2.1.5: Neutron (NPHI), (NPHI), Natural Gamma ray log (GR), are the Nuclear logs which record radioactivity that may be either naturally emitted or induced by particle bombardment. Radioactive materials emit alpha, beta and gamma radiation. Only the gamma radiation has sufficient penetrating power to be used in well logging. Neutrons are used to excite atoms by bombardment in the well logging.

They have high penetrating power and are only significantly absorbed by hydrogen atoms. The hydrogen atoms in the formation fluids are very effective in slowing neutrons and thus tend to be an important property in well logging. There are two interactions that generally affect counts at the neutron sound’s detector. The presence of hydrogen in the formation which is thermalisation and the presence of chlorine or iron which is early absorption. The log reacts to the presence of hydrogen, and so water in the formation. This in turn indicates the formation porosity, both primary and secondary and the system can be calibrated to estimate the percentage of pore space in the clean sandstone, limestone or dolomite. In some wells in the Neem field (part of which is the study area) there is presence of CO2, which is one of the misleading phenomenons that shows no porosity due to absence of Hydrogen so the tool reads very poor porosity although it is not. 3-2-2 ELECTRICAL LOGS The electrical logs measure electrical properties of the formation in different frequency ranges. This includes the Spontaneous Potential (SP) and the Resistivity Logs.

3-2-2-1 Spontaneous Potential (SP)

The spontaneous potential log, commonly called the self-potential log or SP log, is a passive measurement taken by oil industry well loggers to characterize rock formation properties, it is one of the most essential cheap to free cost tool.

The log works by measuring small electric potentials (measured in millivolts) between depths in the borehole and a grounded electrode at the surface. Conductive bore hole fluids are necessary to create a SP response, so the SP log cannot be used in nonconductive drilling muds (e.g. oil- based mud) or air filled holes.

The change in voltage through the well bore is caused by a buildup of charge on the well bore walls. Clays and shales (which are composed predominantly of clays) will generate one charge and permeable formations such as sandstone will generate an opposite one. Spontaneous potentials occur when two aqueous solutions with different ionic concentrations are placed in contact through a porous, semi-permeable membrane. In nature, ions tend to migrate from high

38 to low ionic concentrations. In the case of SP logging, the two aqueous solutions are the well bore fluid (drilling mud) and the formation water (connate water). The potential opposite shales is called the baseline, and typically shifts only slowly over the depth of the borehole.

The relative salinity of the mud and the formation water will determine the which way the SP curve will deflect opposite a permeable formation. Generally if the ionic concentration of the well bore fluid is less than the formation fluid then the SP reading will be more negative (usually plotted as a deflection to the left). If the formation fluid has an ionic concentration less than the well bore fluid, the voltage deflection will be positive (usually plotted as an excursion to the right). The amplitudes of the line made by the changing SP will vary from formation to formation and will not give a definitive answer to how permeable or the porosity of the formation that it is logging.

The presence of hydrocarbons (e.g. oil, natural gas, condensate) will reduce the response on an SP log because the interstitial water contact with the well bore fluid is reduced. This phenomenon is called hydrocarbon suppression and can be used to diagnose rocks for commercial potential. The SP curve is usually 'flat' opposite shale formations because there is no ion exchange due to the low permeability, low porosity properties (tight)thus creating a baseline. Tight rocks other than shale (e.g. tight sandstones, tight carbonates) will also result in poor or no response on the SP curve because of no ion exchange.

The SP tool is one of the simplest tools and is generally run as standard when logging a hole, along with the gamma ray. SP data can be used to find:

 Depths of permeable formations  The boundaries of these formations  Correlation of formations when compared with data from other analogue wells  Values for the formation-water resistivity

The SP curve can be influenced by various factors both in the formation and introduced into the wellbore by the drilling process. These factors can cause the SP curve to be muted or even inverted depending on the situation.

 Formation bed thickness  Resistivities in the formation bed and the adjacent formations  Resistivity and make up of the drilling mud  Wellbore diameter  The depth of invasion by the drilling mud into the formation

Mud invasion into the permeable formation can cause the deflections in the SP curve to be rounded off and to reduce the amplitude of thin beds.

A smaller wellbore will cause, like a mud filtrate invasion, the deflections on the SP curve to be rounded off and decrease the amplitude opposite thin beds, while a larger diameter wellbore has the opposite effect. If the salinity of the mud filtrate is greater than formation water the SP currents will flow in opposite direction. In that case SP deflection will be positive towards to the right. Positive deflections are observed for fresh water bearing formations.

Fig. 3.5 Typical responses of the SP log in different lithology types.

Fig. 3.6 Permeability recognition by SP log.

3-3: Gamma-Ray 3-3-1: Conventional Natural Gamma-Ray Log (GR) The natural radiation is due to the disintegration of nuclei in the subsurface. Potassium, Thorium and Uranium are the major decay series that contribute to natural Radiation. These elements Potassium, Thorium and Uranium tend to be concentrated in shale’s, and are present in feldspars and micas that occur in many sandstone reservoirs. The gamma-ray log is a log of this naturally occurring radiation. The units are American Petroleum Institute (API). Clean sands has fairly low levels of <45 API and Shale’s has high gamma reading > 75 API. The measurements are used to calculate the amount of shale as a function of depth and the vertical resolution of the tool is approximately 0.6 m with a depth of investigation of 0.15 – 0.3 m depending on the density of the rock. The gamma ray log is used for basic lithology analysis.

Fig. 3.4: Diagram of GR log well in Neem field

Quantitative estimation of clay content, correlation of formations, and the depth matching of multiple tool runs. The simple gamma ray log is usually recorded in track one and scales chosen locally, but 0-100 and 0 – 150 API are common. A deflection of GR log to the right indicates shales, where the maximum and constant recorded radioactivity to the right shows shale line. A deflection to the left indicates sandstone, where the maximum and constant recorded radioactivity to the left shows sandstone line as indicated in Fig. (3.4) above in the conventional gamma sonde, a scintillation counter detects total disintegration from sources in the radial region close to the hole. The scintillation detector uses a sodium iodide crystal coupled to a photomultiplier tube to detect tiny flashes of light associated with penetrations of the crystal by gamma rays .

3-3-2 Spectral Gamma Ray (SGR) The spectral gamma ray log record individual responses for potassium, thorium and Uranium bearing minerals. The detectors record radiation in several energy windows as Gamma- Ray – Potassium, Gamma-Ray- Thorium, and Gamma-Ray-Uranium. In the three window tool, estimates of the concentrations of the three radioactive elements can be made as follows :  Potassium: Gamma Ray Energy 1.46 Mev (K40)  Thorium Series: Gamma Ray Energy 2.62 MeV (T1205)  Uranium-Radium Series: Gamma Ray Energy 1.76 MeV (Bi214) Spectral gamma sounds also provide a total GR counts from a fourth window that is equivalent to a conventional gamma log. The main applications of spectral gamma logs are :  Clay Content Evaluation – Spectral logs will distinguish between clays and other radioactive minerals such as phosphate .  Clay type identification – Ratios such as the: K are used to distinguish particular clay minerals .  Source Rock Potential – There is an empirical relationship between U: K ratios and organic carbon in shale. 3-4 Basic wire line logs using In Formation Evaluation 3-4-1 THE NUCLEAR LOGS The Nuclear logs record radioactivity that may be either naturally emitted or induced by particle bombardment. Radioactive materials emit alpha, beta and gamma radiation. Only the

44 gamma radiation has sufficient penetrating power to be used in well logging. Neutrons are used to excite atoms by bombardment in the well logging. They have high penetrating power and are only significantly absorbed by hydrogen atoms. The hydrogen atoms in the formation fluids are very effective in slowing neutrons and thus tend to be an important property in well logging. The basic nuclear logs that will be discussed briefly are the following :  Conventional Natural Gamma-Ray (GR)  Spectral Gamma-Ray (SGR)  Formation Density (RHOB)  Photoelectric Effect (PEF)  Compensated Neutron (CNL)  Sidewall Neutron Porosity (SNP)

3-5 AUXILIARY LOGS These are logs that are required to assist in the quantitative interpretation of many other logs that are sensitive to borehole diameter, wall roughness, hole deviation, and fluid temperature. This includes; the calliper, temperature, and diameter logs. 3-5-1 Caliper Log The calliper logs are the first runs in borehole to measure the diameter of the hole or casing for corrections to other logs and measurements. The measurement of the borehole diameter is done using two or four flexible arms, symmetrically placed on each side of a logging tool. The calliper shows where deviations occur from the nominal drill bit diameter. The simple calliper log records the mechanical response of formations to drilling. Holes with larger diameter than the bit size is caved or washed out. The curve is traditionally a dashed line and usually plotted in track one with a scale of 6 to 16 inches. The log also provides information on fracture identification, lithology changes, well construction and serve as input for environmental corrections for other measurements. It can be run in any borehole conditions.

3-5-2 Temperature Log

The temperature tools measures the temperature of borehole fluids. Temperature logging is used to detect changes in thermal conductivity of the rocks along the borehole or to detect water flow through cracks or fractures. The temperature log is normally plotted so that changes in the temperature gradient (change in temperature to depth) might be related to lithological boundaries or aquifers. Ideally the logging sonde is run twice; once immediately after drill rods are withdrawn and after 24 hours in order to describe the temperature gradient. The unit of measurement is normally in Degree Fahrenheit (Fo). The logs are to be run in fluid– filled boreholes and are also used for temperature corrections to other logs and measurements.

3.5.3 Mechanical tools 3.5.3-1: Caliper Caliper log is one of the important tools in the main conventional first run immediately after well reached Total Depth (TD), it is run in borehole to measure the diameter of the hole for corrections to other logs and measurements. The measurement of the borehole diameter in this study is done using four flexible arms, symmetrically placed on each side of a logging tool in SLAM log and six arm one for PEX-HRLA log. The simple caliper log records the mechanical response of formations to drilling. Holes with larger diameter than the bit size is caved or washed out. It helps in predicting the lithology changes, well construction and serve as input for environmental corrections for other measurements and to exclude the data that badly affected by hole diameter changes such as sonic and density tools. Quantitative estimation of clay content, correlation of formations and the depth matching of multiple tool run The Induced Measurements are, Resistivity, Sonic, Density, Photoelectric and Neutron

The wireline logging tools can be grouped into active and passive tools. The active tools measure the response of formation to some form of excitations. Examples include density, neutron, resistivity, and the nuclear magnetic resonance (NMR) tools. The passive tools measure natural occurring phenomenon such as the gamma radiation that is emitted by elements in the rock or electric potential caused by difference in salinity of the mud in the well and the formation water. Examples include gamma ray (GR) and Spontaneous Potential (SP) logs. Formation Evaluation (FE) is the process of interpreting a combination of measurements taken inside a wellbore to detect and quantify oil and gas reserves in the rock adjacent to the well. FE data can be gathered with wireline logging instruments or logging while drilling tools. Study of the physical properties of rocks and the fluids contained within them. Data are organized and interpreted by depth and represented on a graph called a log (a record of information about the formations through which a well has been drilled. In this study, to identify the reservoir quality (shale volume, porosity, permeability, water saturation and net pay thickness) and predict the depositional environment, sand continuity of Bentiu formation by applying Petrophysical Evaluation of Neem Fields were investigated essentially by two subsurface techniques. These included interpretation of wire line logs and Fine correlation for wells to six low resistivity zones in Abugabra formation as well as on Mudlogging and Wireline logging data analyses at five wells in the field. There are five well logs data available which include Deep Laterolog (LLD) , Shallow Laterolog (LLS). Micro-Spherically Focused log (MSFL), Acoustic log (DT), Density log (RHOB), Neutron log (NPHI), Natural Gamma ray log (GR), Spontaneous Potential (SP) and Calliper log (CAL). In this Greater Neem Field Development, total of 7 wells were evaluated. The list of wells covered in this evaluation were: Neem-01, Neem-02, Neem-25, Neem-26, Neem-27, Neem-28 and Neem-29. All the seven wells were drilled by GNPOC. The subject wells are vertical with the Mudlogging contractor CNLC and one of the wire line logging service providers, using mainly Heloberton Technologies in addition to other western technologies with some Chinese modifications and developments, recently most of the tools are produced locally in china. The location of these wells is shown in (Fig. 1.1).

CHAPTHER FOUR

THE PETROPHYSICAL STUDY 4-1 Introduction This chapter presents the complete processes to determine the permeability using flow units method. It includes determination of the total porosity from wireline logs. Properties such as porosity and water saturation which are obtainable from log analysis and can be used to assess the hydrocarbon content of the formation. The evaluation of shaly sand from log analysis provides estimates of total porosity, clay and sand (in the clay model), effective porosity, permeability and water saturation. 4.2 Data a- set: Table 4.1: Data sets of the study wells No Data set Type of data Remarks 1 Geological • Surface geology. • Publications, papers, information  maps, and cross-sections • Sequence stratigraphy  Asccii drilling data  Final well report 2 Wire line logging • Conventional log data  Formation pressure tester data b- Handling Petrophysical evaluation was carried out using the interactive petrophysics (IP) and Petro-View-PLUS which is a module in Geoframe application, as deterministic approach of evaluation. Processing of well data (Neem Field) includes depth matching, environmental corrections and reservoir summations. In Abu Gabra, pressure analysis not only assists in establishing OWC, but also fluid identifications where the log data was unclear and because resistivity of pay zones is very low.

Gravitas software was used to for logging data QC and as a correlation tools for it is capability of viewing of more than one well on multi-screen PC’s and it is PC standalone software.

4-3 SOFTWARE:

4-3-1 INTERACTIVE PETROPHYSICS (IP) SOFTWARE:

IP helps determine the amount of hydrocarbons in the reservoir. It does this by calculating porosity and water saturation using well logging data. But IP™ is more than just petrophysics. It is also a tool for geologists and Reservoir Engineers who want to take control of their analysis and interpretation.

IP™ is able to focus on accurate calculations that get the most out of your reservoir. IP™’s intuitive interface runs on robust algorithms and provides these benefits:

 Diminished uncertainty in the interpretation  Fast results due to the ease of learning IP™  Flexibility so that it work the way the user wants to work and user is free to use different formulas whatever is suitable for the reservoir.

Whether it's used for a single workflow on a single well, or as a complete solution for multi well projects, IP offers technical excellence.

Fast

The IP is easy to learn – and fast. Workflows are efficient and reliable

Interactive parameters that you can pick and adjust as you work

 3D visualization allows user to identify and incorporate trends for geologic variability  Real-time handling of depth- and time-based WITSML data input  Automated interpretation updates

Robust

Calculating porosity and water saturation is the core task of a petrophysicist. IP™ is one of the best tool for these computations because it is mathematically one of the most accurate tools as it is complete, deterministic, multi-well, and interactive interpretation. IP™ Basic bundle is ideal for complex analysis such as:

 Multi-mineral  Thin beds  Organic shales  NMR interpretation

Powerful

IP contains workflows that are the cornerstone of analysis throughout user’s asset’s lifecycle. Geomechanics and Formation Evaluation workflows make IP™ complete, cost-effective solution, it provides workflows for:

 Wellsite operations  Geologists & geophysicists  Stratigraphers  Reservoir engineers  Data managers  Remote use (for up to 30 days)

4-3-2 GRAVITAS:

This is a software that capable of compiling a summarized data of the well cycle starting from the proposal, while drilling data update and testing phases, as it helps a lot in quick view of the history of the well. All this data fit together to provide a rich operations geology toolset to manage the geological workflow and seamlessly integrate with other disciplines such as drilling data.

Gravitas is Scalable from a single laptop user to a multi-user centralized system, Gravitas gives the client flexibility to monitor, log, chart and report operations as required. Information held in the Gravitas database may be instantly shared to facilitate collaboration and avoid duplication of effort.

Gravitas provides a flexible, systematic solution to the problems faced by assets in today’s digital oilfield and ensures that organizations can make informed decisions throughout the well lifecycle.

This Software is currently utilized in most of Sudanese JOC’s. It has proved that it’s very convincing and credible through outputs generated.

The Software enables the user to create composite logs services.

Graphical Users Interface (GUI) for direct user interaction with logs with all modified data saved in the Gravitas network in the data center.

Multiple log formats can be derived from a single data store for accuracy and consistency.

Multi-well and multi-phase correlation capability.

A connectivity option in this software helps to integrate seamlessly with other G&G applications and data bases integrate with other G&G applications and database.

The software is used in this study as correlation tools for the wells in the study area.

4-4 Data Quality Four well were logged with SLAM log by CNLC and the other three wells were logged by Schlumberger PEX-HRLA. Although washouts were observed in several occasions (particularly in deeper Abu Gabra Formations in Neem Main, data quality in general is fair. PEX-HRLA Data which was corrected for hole-condition in real time, showed better quality than (SLAM) data. The Density, Micro Shallow Resistivity and Neutron was highly affected by washed and rogues hole geometry that it causes tool to jump and result to non-reliable data in some areas.

4-5 Volume of shale Volume of Shale (V-shale) was determined using the Density-Neutron crossplot and Gamma Ray log, because most log responses are influenced by the presence of shale in the formation such as Resistivity, SP, GR, RHOB, NPHI and DT. This averaging technique is a commonly used method in wells within the Muglad Basin, thus also applied to this study. 4-6 Porosity Porosity is the most basic and important rock property, it defines the ability of the formation to store fluids. (Selley, 2000) defined the porosity as the ratio of pore space volume, which is not occupied by the solid constituents, to the total volume. It can be expressed either as fraction or percentage and it is mathematically given as:

Porosity (Ф) =Volume of the pore spaces/Total volume of rock

For low resistivity oil zones, there are three steps to determine the RW. Firstly, recognize low resistivity with connecting-well sections, test data, production data, pressure data, SP and MSFL curves. Secondly, calculate SW with J-function. Thirdly, Infer Rw from Sw(J).

Where, C is Constant. Porosity has been classified based on the connectivity into total porosity and effective porosity. Total porosity is the ratio of the total volume of the pore space to the total volume of the rock, whereas effective porosity is the ratio of interconnected pore space to the total volume of the rock.

Porosity is also classified based on its geological origin to primary porosity and secondary porosity. Primary porosity is developed during the deposition of the sedimentary material and secondary porosity develops by geological processes after the original deposition. Porosity is normally estimated quantitatively from density, sonic log, density and neutron log. Porosity calculation was based from the following formula as documented in the Schlumberger PetroView-PLUS manual: feffective = ( rmatrix (1-Vshale)+(rshaleVshale – r ))/(rmatrix-rfluid) ftotal = feffective + WCLP*Vshale

This technique as well as the technique which was used to estimate the shale volume. For the shaly sand models, the following sets of equations are used:

RHOB = RHOB matrix + (RHOB shale - RHOB matrix)* Vshale + (RHOB fluid – RHOB matrix) * effective And Neutron =  neutron matrix + ( neutron shale -  neutron matrix)* V shale + (1-  neutron matrix)*  effective The total porosity is given by:  Total =  effective + WCLP × V shale Where: RHOB is the density log,  Neutron is the neutron log WCLP is the wet clay porosity from core analysis. Applying this technique for porosity calculation, the porosity model has been constructed for Abugabra formation. 4-7 Concept of Low Resistivity Pay (LRP) Zone

LRP -Type I: high clay bound water content. When clay content is high and clay minerals mainly are smectite, illite and illite-smectite.

LRP -Type II: high capillary irreducible water content due to fine sand grain, small average capillary radius, high capillary pressure, high salinity of capillary irreducible water and a lower oil column.

LRP -Type III: the existance of conductive minerals in pay zones such as pyrite, siderite,etc.

LRP -Type IV: invasion of high salinity mud filtrate. It causes the deep resistivity lower than true formation resistivity.

LRP -Type V: conductive minerals compose of reservoir matrix. Such as glauconite in marine sediments.

Fig.4-1: sketch showing Bound water (left) and capillary water (right).

4-8 Water Saturation The Dual Water Model (DWM) was adopted in calculating Water Saturation. Summary of the model can be visualized as follows: Although saturation can be determined by any number of methods, most of which require similar log measurements, specific circumstances affect or limit the accuracy of each method. It is therefore crucial to use the appropriate method which will be discussed in details in this chapter. Several measurements and petrophysical parameters are essential in deriving accurate saturation values from log data, and they studied in details in this study.

4-9 Formation Water Resistivity (Rw) Formation water resistivity was estimated from the nearby water, using Pickett plot methods. The Rw values vary depending on formations. Rwb on the other hand was estimated from the nearby shale being equal to Rwa in shale.

4-10 Hydrocarbon saturation It is the main target and saturation can be calculated easily after calculation of Sw and Sxo. The HC saturation may be movable or residual hydrocarbons. Movable hydrocarbon saturation (Shm) is very important because it can be studied in commercial point of view, while the residual hydrocarbon saturation (Shr) is of less importance due to its difficulty in extraction. In simple forms, both movable and residual hydrocarbon can be calculated as the following:

Sh = 1 - Sw Shr = 1 - Sxo Shm = 1 - Shr

Where:

Sh = hydrocarbon saturation Shm = movable hydrocarbon saturation Shr = residual hydrocarbon saturation Sxo = Hydrocarbon saturation 4-11 Wells Correlation: Bentiu formation was easily correlated compared to Abugabra, as it wasn’t easy to have a sand to sand correlation due to non-continuity or pinching out of the pay sand bodies and sedimentological horizontal changes. The Two deepest pay zones were not drilled in Neem 1 as the well Total depth was shallower.

CHAPTER FIVE CORRELATION & PETROPHYSICAL EVALUATION RESULTS 5-1 Introduction The low resistivity pay zones were defined as that a resistivity ratio of oil-bearing to adjacent water-bearing zones is less than 2 (Rt / Rw ≤ 2), and the test result is water-free hydrocarbon. Lithologies of the reservoirs are usually shaly siltstone, laminated shaly sandstone and/or pure sandstone, etc. The reservoirs may be high porosity and high Permeability. The result of petrophysical evaluation is to figure out an answer the questions raised, firstly is: what is the potentiality of possible productive pay zones: secondly the low resistivity oil bearing zone, the third is gross and net pay thickness, fourth is the average saturation, finally fifth i s average porosity of each potential pay zone and sixth is to track the continuity of the pay zones, The reply of these challenges in order to weight technical positives and negatives against economic. These questions only can be answered by the petrophysical evaluation after interpretation of the log data from wells and applying the cut-offs to the shale volume, porosity and water saturation. 5-2 Data Quality: Although washouts were observed in several occasions (particularly in deeper Abu Gabra formations of Neem studied wells, data quality in general is fair. Platform Express (PEX) data, which were corrected for hole-condition in real time showed better quality than SLAM data. Borehole condition affected mainly the Density, Micro Shallow Resistivity and Neutron. 5-3 Petrophysical cut-off values determination The main objectives of utilizing cut-off values are to calculate the net reservoir rocks in the field and to eliminate the non-reservoir rocks. The net reservoir rock above the oil water contact defines the net pay rock, which is going to be used in estimating the original oil in place (OOIP). The non-reservoir rocks of Abugabra reservoirs in this field are shale and silt. Therefore, the intent is to set the cut-off criteria needed to eliminate these non-reservoirs from the logged reservoir intervals. There are three types of cut-off values including Shale

Cut-Off (Vsh Cut-Off), porosity Cut-Off (Phi Cut-Off) and Water Saturation Cut-Off (Sw Cut-off). The correlation was done using first by Gravitas and Petrel finally which was found much more flexible and easily used therefore the resulted map Fig. 5-9 was the result. The determination of the values of this Cut-Off for Abugabra reservoirs was done by using the Interactive Petrophysics software and plotting the Zones versus shale volume and porosity respectively and net pay hydrocarbon porosity thickness versus water saturation as the following: 5-3-1 Volume of shale (Vsh) cut-off Volume of Shale (V-shale) was determined using the Density-Neutron cross plot and Gamma Ray log, applying with Hodges-Lehman’s averaging techniques. This averaging technique is a commonly used method in wells within the Muglad Basin, thus applied to this study. 5-3-2 Porosity cutoff Porosity calculation was based from the Archie formula as documented in the Senergy IP manual:

Average Effictive Porosity In Neem Wells 0.2

0.18

0.16

0.14

0.12

0.1

0.08

0.06

0.04

0.02

0 NM1 NM2 NM25 NM26 NM27 NM28 NM29

Fig. 5-1: Average effective Porosity Studied wells resulted from IP Software

5-4 Correlation: Continuity of sand bodies among the studied wells was unclear in the correlation carried, as Abugabra came shallowest in the Neem 26 and the deepest was in Neem 27, the max difference was 65m among the seven studied wells. Most of Sand layers were thin and Neem 1 was not drilled to the depth that can penetrate the botoom most two deeper promising pay zones. Fig. 5-9

Fig. 5-2: Correlation of the Seven studied wells in Neem field

Average Net Pay Neem Wells 8

0 NM1 NM2 NM25 NM26 NM27 NM28 NM29

Fig. 5-3: Average Net pay in the Studied wells resulted from IP Software

Total Net Pay Neem Wells

120

100

0 NM1 NM2 NM25 NM26 NM27 NM28 NM29

Fig. 5-4: Total Net pay in the studied wells resulted from IP Software

5-5 Interpretation of Results of Sand Bodies - Reservoir:

The well Neem -1 results showed the maximum net pay thickness for Abugabra reservoirs is 6.3m and minimum thickness is 0.1m. The average effective porosity is 14%, and the average water saturation is 45%. with minimum resistivity 9.4ohmm show table (5.1). Table (5.1) Reservoir Summary of Well NEEM -1 No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 3 Aradeiba o 1837.0 1840.4 3.4 2.9 16.2 0.186 0.354 0.453 0.115 95 Aradeiba o 1932.3 1935.9 3.7 3.7 16.3 0.215 0.218 0.356 1.208 133 Abugabra o 2419.4 2424.7 5.3 4.7 29.1 0.122 0.216 0.478 3.224 146 Abugabra o 2539.8 2540.8 1.1 0.8 14.8 0.132 0.140 0.548 15.915 148 Abugabra o 2548.1 2552.4 4.3 4.3 19.5 0.172 0.122 0.346 88.872 150 Abugabra o 2554.2 2555.3 1.1 0.1 25.3 0.125 0.547 0.302 8.606 153 Abugabra o 2561.5 2562.9 1.4 1.1 19.7 0.127 0.087 0.420 17.692 161 Abugabra o 2652.2 2658.3 6.1 4.4 13.8 0.125 0.176 0.457 38.991 The well Neem-2 results showed the maximum net pay thickness for Abugabra reservoirs is 17.1m and minimum thickness is 1.7m. The average effective porosity is 16%, and the average water saturation is 42%., with minimum resistivity 7.1ohmm table (5.2).

Table (5.2) Reservoir Summary of Well NEEM -2 No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 115 AbuGabra o 2397.7 2407.3 9.6 9.3 13.0 0.183 0.137 0.344 172.770 116 AbuGabra o 2407.8 2414.0 6.3 5.8 7.1 0.178 0.225 0.514 164.320 117 AbuGabra o 2415.1 2424.1 9.0 8.8 10.2 0.177 0.108 0.409 153.080 125 AbuGabra o 2496.6 2498.3 1.7 1.7 10.1 0.145 0.150 0.471 53.342 126 AbuGabra o 2503.2 2512.0 8.8 8.3 18.3 0.170 0.097 0.327 167.890 128 AbuGabra o 2518.0 2520.4 2.4 2.0 19.6 0.143 0.162 0.322 70.939 129 AbuGabra o 2523.0 2541.0 18.0 17.1 16.1 0.182 0.103 0.293 230.000 130 AbuGabra o 2545.5 2549.2 3.7 3.4 12.1 0.166 0.104 0.416 32.856 136 AbuGabra o 2600.3 2604.2 4.0 3.5 20.7 0.164 0.079 0.425 91.059 137 AbuGabra o 2605.4 2613.8 8.4 8.0 28.9 0.146 0.117 0.337 56.675 146 AbuGabra o 2721.9 2733.3 11.4 11.4 13.7 0.175 0.078 0.395 107.130 157 AbuGabra o 2871.2 2877.3 6.1 5.0 6.3 0.150 0.249 0.451 20.285 163 AbuGabra o 2917.4 2921.8 4.4 3.7 11.2 0.137 0.084 0.509 0.340 170 AbuGabra o 2957.6 2960.7 3.0 2.0 9.8 0.109 0.216 0.511 0.323 171 AbuGabra o 2963.9 2978.8 14.9 14.0 7.4 0.173 0.115 0.494 870.760 The well Neem-25 results showed the maximum net pay thickness for Abugabra reservoirs is 61

10.3m and minimum thickness is 2.1m. The average effective porosity is 16%, and the average water saturation is 41%.show, with minimum resistivity 10.5ohmm table (5.3). Table (5.3) Reservoir Summary of Well NEEM -25 No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 79 Bentiu o 2032.0 2035.6 3.6 2.9 50.9 0.211 0.324 0.322 76.715 119 Abugabra o 2568.3 2578.5 10.1 10.1 22.0 0.173 0.053 0.403 119.920 122 AbuGabra o 2598.3 2600.9 2.7 2.6 33.3 0.156 0.075 0.347 64.362 124 AbuGabra o 2604.0 2606.6 2.6 2.1 36.5 0.145 0.105 0.358 48.129 133 AbuGabra o 2709.3 2717.1 7.8 6.9 14.4 0.144 0.120 0.416 49.400 134 AbuGabra o 2719.6 2730.0 10.4 10.3 13.1 0.154 0.082 0.451 56.875 145 AbuGabra o 2878.5 2882.0 3.5 2.7 19.2 0.104 0.140 0.501 0.043 150 AbuGabra O 2910.4 2916.6 6.2 5.7 15.3 0.155 0.101 0.385 20.460 151 AbuGabra O 2918.8 2936.9 18.1 17.3 12.0 0.170 0.083 0.385 52.581

Fig. 5-5: Neem 25: Abugabra Sand Body @ 2436m probable continuous correlated to other study wells unfortunately showing no pay zone. The well Neem-26 results showed the maximum net pay thickness for Abugabra reservoirs is

9.5m and minimum thickness is 1.8m. The average effective porosity is 19.5%, and the average water saturation is 42%. With minimum resistivity 7.0ohmm shown in table (5.4). Table (5.4) Reservoir Summary of Well NEEM -26 No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 77 Bentiu-1 o 2014.8 2032.5 17.7 17.3 108.0 0.314 0.242 0.191 12945.000 110 AbuGabra o 2424.7 2430.9 6.3 6.3 11.6 0.189 0.102 0.403 278.070 123 AbuGabra o 2562.1 2565.1 3.0 2.7 34.0 0.152 0.195 0.360 16.351 126 AbuGabra o 2595.9 2599.8 3.9 3.7 14.7 0.175 0.070 0.416 134.170 127 AbuGabra o 2600.9 2605.7 4.9 4.8 50.6 0.180 0.057 0.293 138.900 135 AbuGabra o 2711.2 2720.9 9.7 9.5 12.2 0.193 0.107 0.489 154.880 136 AbuGabra o 2722.5 2728.0 5.5 5.4 13.0 0.192 0.071 0.486 161.830 149 AbuGabra o 2874.7 2878.1 3.4 3.4 14.7 0.137 0.093 0.483 0.822 156 AbuGabra O 2913.1 2922.5 9.4 9.3 11.9 0.195 0.104 0.365 899.150 157 AbuGabra O 2924.6 2927.6 3.0 2.6 9.7 0.174 0.195 0.416 270.750 158 AbuGabra O 2929.6 2939.5 9.9 8.6 9.3 0.149 0.157 0.508 4.947

Fig. 5-6: Neem 26: Abugabra @ 2424.5m probable continuous correlated to other study wells The well Neem-27 results showed the maximum net pay thickness for Abugabra reservoirs is 9.0m

and minimum thickness is 2.3m. The average effective porosity is 16.5%, and the average water saturation is 45%. With minimum resistivity 10.6 ohmm, shown in table (5.5). Table (5.5) Reservoir Summary of Well NEEM -27

No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 1 Aradeiba o 1919.3 1921.9 2.6 2.4 19.6 0.210 0.272 0.398 4.617 2 Aradeiba o 1941.4 1943.7 2.3 2.2 31.7 0.188 0.418 0.312 0.973 3 Bentiu o 2073.4 2076.8 3.4 3.4 132.2 0.247 0.098 0.295 335.500 4 AbuGabra o 2409.6 2417.2 7.6 7.6 17.6 0.162 0.052 0.456 47.980 6 AbuGabra o 2912.4 2915.9 3.5 2.3 31.0 0.112 0.102 0.512 0.068 7 AbuGabra o 2918.5 2927.3 8.8 6.6 10.6 0.163 0.062 0.513 41.676 8 AbuGabra o 2928.2 2933 4.8 3.0 12.6 0.153 0.097 0.505 7.774 10 AbuGabra o 3048.6 3058.4 9.8 9.0 15.3 0.141 0.116 0.442 1.714 11 AbuGabra o 3093.7 3098.6 4.9 4.6 26.7 0.160 0.109 0.416 3.093

Fig. 5-7: Neem 27: Abugabra @ 2408.5m probable continuous correlated to other study wells

The well Neem-28 results showed the maximum net pay thickness for Abugabra reservoirs is 16.7m and minimum thickness is 7.9m. The average effective porosity is 21%, and the average water saturation is 33%. With minimum resistivity 7.9ohmm shown in table (5.6). Table (5.6) Reservoir Summary of Well NEEM -28 No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 1 Bentiu o 2003.7 2012.6 8.9 8.9 181.3 0.273 0.300 0.151 439.180 2 Bentiu o 2014.2 2016.0 1.8 1.7 68.6 0.263 0.366 0.249 339.530 3 Bentiu o 2042.7 2048.7 6.0 5.9 23.1 0.228 0.296 0.390 71.651 4 Bentiu o 2056.7 2059.6 2.9 2.9 35.7 0.219 0.275 0.322 63.865 5 Abugabra o 2735.1 2737.8 2.7 2.5 16.7 0.128 0.101 0.493 52.460 6 Abugabra o 2845.8 2854.8 9.1 8.0 7.9 0.150 0.180 0.432 61.033 7 Abugabra o 2865.1 2870.2 5.0 5.0 15.4 0.221 0.109 0.284 6814.500 8 Abugabra o 2874.3 2878.7 4.4 4.4 13.0 0.199 0.097 0.309 2291.100

The well Neem-29 results showed the maximum net pay thickness for Abugabra reservoirs is 18.1m and minimum thickness is 1.7m. The average effective porosity is 15%, and the average water saturation is 35%, with minimum resistivity 12.0ohmm. Shown in table (5.7).

Table (5.7) Reservoir Summary of Well NEEM -29 No Formation Zone Top Bottom Gross Net LLD PHIE VCL SW PERM 1 Abugabra o 2401.4 2403.5 2.1 1.9 24.9 0.171 0.164 0.369 170.410 2 Abugabra o 2513.3 2522.7 9.4 9.1 19.0 0.166 0.186 0.288 241.300 3 Abugabra o 2533.8 2552.8 19.0 18.1 12.0 0.207 0.185 0.297 515.840 4 Abugabra o 2926.4 2929.8 3.4 1.7 14.4 0.097 0.226 0.479 0.024 5 Abugabra o 3142.2 3151.3 9.2 8.8 39.1 0.127 0.166 0.401 4.654 6 Abugabra o 3253.4 3257.2 3.8 1.8 20.1 0.113 0.290 0.289 0.017

Fig. 5-8: Log curve combined with Masterlog

Fig. 5-9: Neem-2 2720—2730m,Log curve combined with Masterlog OWC

Fig. 5-10 Log curve combined with Masterlog in Neem-1

CHAPTER-SIX

CONCULUTION & RECOMMENDATIONS

6.1 Conclusion:

The study area of this research lies in the north-western part of the Muglad Rift Basin, which is the largest and most important oil-producing basin in the Sudan so far. The previous methods and techniques were applied on the Abugabra formations, to come out with comprehensive petrophysical evaluation results, for 7 wells in the area of study including all interpretation models which show a good match between them; indicate good interpretation result from logs. Petrophysical evaluations and a brief summary of the chapters and recommendations from this study can be summarized below. The grabins and subgrabins characterizes the Muglad Basin and as Abugabra formation’s depositional environment was mostly lacustrine, the sedimentation of fine to very fine Sandstone was dominant with argillaceous cement on coarsening upwards cycles and sub- cycles, characterized by poor porosity as found in wet sample description and wire line logging analysis, from which analyzed that the most probable reasons of the low resistivity are mainly high clay bound water content in sandstone with argillaceous cement in Abugabra formation, high capillary irreducible water content due to fine sand grain, this in addition to existence of conductive minerals in pay zones, such as pyrite, and operationally could be the Invasion of high salinity mud filtrate. From petrophysical results, some parameters such as permeability, porosity and water saturation was found that, these parameters distributed through the Bentiu and Abugabra formations with different values which indicate that the lithology has different sedimentological and stratigraphical properties. The biggest values of porosity and highest net pay was in the well Neem 26 which is 81meters in Abugabra. Analysis of pressure data used in establishing fluid contacts and fluid gradient, also used in various occasion for fluid typing. In Neem-1 and Neem-2 pressure data was acquired utilizing Repeated Formation Pressure tools (RFT). However, close analysis indicates marginal pressure different ranging from 12-19psi between wells. Normalization of pressure data was carried out, as well as to depths. Neem-1 depths were equalized to Neem-02 by 3.527m due to differential in 68

Kelly Bushing (KB) height and smaller values in the rest of the wells maximum was 2m.

The fluid contact is clear on log curves or master-log rather than curve method derived method on which we use formation pressure log data. Although the effective porosity calculated using IP is of less accuracy unless confirmed by core study, but also gave general indication that the upper and middle pay-zones in Abugabra are of higher values 15 to 18 whereas the lower Abugabra porosity value ranging between 9 to 13. The Water saturation was determined using the Archie formula this study, Sw＜50%. Out of six different Abugabra sand bodies, only one sand showed continuity in all studied 7 wells other showed discontinuity and missed in many wells

6-2 Recommendations

Because only petrophysical evaluation of wells in the study area was applied by using wire line logs, Hence for better understanding of the study area, the following are recommendations:  The spectral gamma ray potassium, thorium, and uranium logs with total gamma ray should be run that will help in estimating the actual clay volume in the low resistivity pay zones and in prediction of sedimentological and stratigraphic changes.  In Abugabra, pressure test log and analysis not only assists in establishing Oil Water Contact, but also fluid identifications wherever the log data was unclear.  It is very essential to run FMI log is in the wells for better identification and characterization of thin bedded oil zones for wells in Neem field.  Neem-1 well either to be deepened or to drill a nearby well targeting a good promising sand that penetrated in the other study wells.  For better correlation and understanding of pay zone, core is recommended to be cut from all sands in future wells.

REFERENCES Ahmed, A. S., 1983. Geology of south central Sudan basin, lithostratigraphy and sedimentary evolution. M. Sc. Thesis, University of Khartoum, Khartoum, Sudan. Smith, (1949 and Jackson, 1959), Distribution of tree species in the Sudan in relation to rainfall & Soil texture. Sudan Min agric. Bull. 4, pp. 66. Archie, G.E., 1942. The Electrical Resistivity Log as an Aid in Determining Some

Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001, RIPED, 2001 Bosworth, W., 1992. Mesozoic and early Tertiary rift tectonics in east Africa. Tectonophysics, 209, pp. 115-137. Dobrin, M. B., (1981): Introduction to Geophysical Prospecting. McGraw-Hill, Singapore, 3rd edition, 630 pp. Dobrin, M. B., (1988): Introduction to Geophysical Prospecting. McGraw-Hill, Singapore, 4rd edition, 299-331 pp. El Badi, S., 1995. Sudanese ribes. M.Ar. Thesis, University of Khartoum, 121 p., Khartoum, Sudan. El Shafie, A. A., 1975. Lithology of the Umm Rawaba Formation and its paleageography in connection with water problems, Sudan. Ph.D. Thesis, 130 p., geological Exploration Institute, Moscow. Fairhead, J. D. and Green, C. M., 1989. Controls on rifting in Africa and the regional tectonic model for the Nigeria and east Niger rift basins. Journal of African Earth Science, 8, (2-4), pp. 231-249, Oxford. Fairhead, J. D., 1988. Mesozoic plate tectonic reconstruction of the central South Atlantic Ocean: The role of the west and central African rift system. Tectonophysics, 155, pp. 181-195. Mohamed Y et al, 1999, Bosworth W., 1991, Rene Guiraud et al, 1992, Mohammed, A. S., 2003. Sedimentology and Reservoir Geology of the Middle-Upper Cretaceous Strata in Unity and Heglig Fields in southeast Muglad basin, Sudan. Ph.D. Thesis, 191 pp., Institute of geological, TU Freiberg, Germany. P. Van et al., 2003, Subsurface Sediment Mobilization, Ghent University, Belgium Rashida Sir El khatim , Sedimentological and Sequence Stratigraphy of The Lower Cretaceous Strata Abu Gabra Formation, In South West Sudan, Muglad Rift Basin (Neem Oil Fields), Sudan PHD Thesis In Geology, Department of Geology, Faculty of Science, University of Khartoum, Sudan 2014. ROBERTSON RESEARCH INTERNATIONAL (RRI) & The Geological Research Authority Of Sudan (GRAS) (1991): The geology and petroleum potential of southern, central and eastern Sudan.- Volumes 1- 4 (unpublished reports).. Salama, R.B., 1997. Rift basins of the Sudan. In; R.C. Selley (ed.), African Basins, Sedimentary Basins of the World. 3, Elsevier Science B. V., Amsterdam, 105-149.

Schandelmeier, H., Klitzsch, E., Hendriks, F. and Wycisk, P., 1987. Structural developments of north-east Africa since Precambrian times. Berliner geowissenschaftliche Abhandlungen, A, 75, pp. 5-24, Berlin. Schlumberger Educational Services, 1987, Log Interpretation Principles/Applications. Serra, O, 1984, Fundamental of Well Log Interpretation, Elsevier Science Publisher B.V., p. 142-143. Schull, T. J., 1988. Rift basins of interior Sudan: Petroleum exploration and discovery. American Association of Petroleum Geologists Bulletin, 72, pp. 1128-1142, Tulsa.seismograms from well log data. Geophysics, 20, 516-538. Telford, W. M., Geldart, L. P., Sheriff, R. E. and Keys, D. A., (1990). Applied Geophysics. Cambridge University Press, 2ed edetion 244 pp. Vail, J .R. and Rex, D. C., 1971. Potassium-Argon measurement on Pre-Nubian basement rocks from Sudan. Proc. Geol. Soc., 1664, pp. 205-214, London. Whiteman, A. J., 1971. The geology of the Sudan Republic. Clarendon Press, Oxford. Wuenschel, P. C., 1960. Seismogram synthesis including multiples and transmission coefficients. Geophysics, 25, 106-129. .