Dr. Mohamed Abdalhafeiz Ali Elyass

ALNEELAIN UNIVERSITY THE GRADUATE COLLEGE

Petrophysical Evaluation For Abu Gabra Formation-Muglad Basin, Neem K Area (Block 4) Using Wells Data

A Dissertation Submitted to the Graduate College in Partial Fulfillment of the Requirements for the Master's Degree in Geophysics.

By: Altayeb GassemAlbari Altayeb Ibrahim

B sc. (Hons.) in Hydrogeology Alneelain University (2013).

Supervisor: Dr. Mohamed Abdalhafeiz Ali Elyass

Dec. 2019

بسم الله الرحمن الرحيم جمهورية السودان Republic of The Sudan جـــامــعــة النـيـــليــــن AL NEELAIN UNIVERSITY كلية الدراسات العليا The Graduate College

Approval Page (To be completed after the college council approval)

Name of candidate: Atayeb GassemAlbari Altayeb Ibrahim Thesis title: Petrophysical Evaluation for Abu Gabra Formation-Muglad basin, Neem K Area (Block 4) using wells data Degree Examination for: M.Sc. in Geophysics.

1. External Examiner Name…………………………………………………………...... Signature…………………..… Date…………………………… 2. Internal Examiner Name: ……………………………………………………………… Signature…………………..… Date……………………………

3. Supervisor Name: ……………………………………………………………… Signature…………………..… Date……………………………

Abstract

This study Petrophysical Evaluation for Abu Gabra formation – Muglad basin, Neem k subfield (Block 4) four wells data by using Interactive petrophysics IP.

Interpretation of Shaly sand oil reservoirs is still evolving, with researchers to conduct a large number of studies to verify the effect of clay minerals on the conductivity of the reservoir through theoretical and experimental methods. In this study have been Petrophysical evaluated to Shaly sand reservoirs in the Neem k subfield by selecting one formation to know of the Petrophysical properties of the reservoir, it is formation of Abu Gabra. Determination of layers of clay and layers of sand in the well logs was done by using interpretation of gamma-ray records, records the electrical resistivity, density recordings, and Neutron recordings. The results obtained were effected by three major factors: porosity, the volume of clay in layers and water saturation of layers, experimental results show clear contrast in the average porosity (≥ 10%), average volume of clay (≤ 50%) and average water saturation (≤ 80%), was very compatible with characteristics of the reservoir.

الخالصة

هذه الدراسه تمثل تقييم بتروفيزيائي لمتكون ابوجابره – حوض المجلد حقل نيم ك)مربع4(الربعه ابار باستخدام برنامج انتراكتيف بتروفيزيك. تفسير خزانات الرمل الطيني النفطيه الزالت تتطور مع اجراء الباحثين لعدد كبير من الدراسات للتحقق من تاثير المعادن الطينيه علي الموصليه الكهربيه للخزان من خالل الطرق النظريه والتجريبيه ،في هذه الدراسه تم تقييم بتروفيزيائي لخزانات الرمل الطيني في حقل نيم ك وذلك بتحديد متكون واحد لمعرفة الخصائص البتروفيزيائيه وهو متكون ابوجابره،تم تحديد الطبقات الطينيه والطبقات الرمليه بواسطة تفسير تسجيالت اشعة جاما ، تسجيالت المقاومه الكهربيه، وتسجيالت الكثافه ، وتسجيالت النيترون ، النتائج المتحصل عليها تم تقييمها عن طريق ثالث عوامل هي المساميه، حجم الطين في الطبقات ونسبة التشبع بالماء وقد اظهرت النتائج تفارق واضح في متوسط نسبة المساميه ، ومتوسط حجم الطين في الطبقات ، ومتوسط نسبة التشبع بالماء وقد كانت متوافقه جدا مع خصائص الخزان.

Dedication

I dedicate this work to my parent, to my Wife, to my brothers and my sisters, to the soul of my grandmother.

III

Acknowledgements

I wish to express my appreciation to my supervisor Dr. Mohamed Abdalhafiez Ali for his support and guidance through this project, Thanks and appreciation goes to the staff of the department of geophysics –Faculty of Petroleum and minerals at university ofAlneelain for their helping and encouragements. Special thanks and gratitude to Hasan Almalieh(OEPA) and Abd alzahier Mohiealdien (OEPA) for their supporting and helping during data interpretation, Sincere thanks are due to my colleagues at the Master program Batch 4 for their supports.

Contents Title Page Abstract I Abstract in Arabic II Dedication V Acknowledgements IV Contents V List of Figures X List of Tables XIII

CHAPTER ONE INTRODUCTION

1-1 Introduction 1 1-2 Physiography 3 1-3 Climate 3 1-4 Population 3 1-5 Location of study area 4 1-6 Accessibility 5 1-7 Problem Statement 5 1-8 Objective of the study 5 1-9 History of the Exploration 6 CHAPTER TWO REGEONAL GEOLOGY AND TECTONIC EVOLUTION 2-1 Introduction 8 2-2 Regional Geological Setting 9 2-3 Sudanese rift basins 15 2-3-1 West and Central African Rift Basins 15 2-3-2 Key Sudanese Rifts 16

2-3-3 Stress Field of Muglad Basin 17 2-3-3-1 Combined wrench and Normal Extension 19 Mechanism 2-3-3-2 Derivative Normal Extension Mechanism 20 2-3-3-3 Transtensional Mechanism 22 2-4 Stratigraphy of Muglad Basin 24 2-4-1 Precambrian-Jurassic 25 2-4-2 Cretaceous 25 2-4-2-1 Abu Gabra Formation 26 2-4-2-2 Bentiu Formation 26 2-4-2-3 Darfur Group 27 2-4-3 Tertiary 27 2-4-3-1 Amal Formation 28 2-4-3-2 Nayil and Tendi Formations 28

CHAPTER THREE METHODS OF IVESTIGATION 3-1 Introduction 29 3-2 Log Interpretation 30 3-3 Zoning 32 3-3-1 SP 32 3-3-1-1 SP Theory 32 3-3-1-2 SP uses 35 3-3-1-3 Rw from the SP 35 3-3-1-4 SP borehole Effects 38 3-3-2 Gamma Ray Principles 39 3-3-2-1 GR Technique 39 3-3-2-2 GR Uses 40 3-3-2-3 GR parameters 42 3-3-2-4 GR applications 42 3-3-2-5 GR Limits 43

3-3-3 Caliper 46 3-3-4 Lithology and Porosity Tools 47 3-3-4-1 Neutron Tool 47 3-3-4-1-1 Hydrogen Index 48 3-3-4-1-2 Thermal Neutron Parameters 49 3-3-4-1-3 Interpretation and Uses 50 3-3-4-2 Density Tool 50 3-3-4-2-1 Density Parameters 51 3-3-4-2-2 Interpretation and Uses 52 3-3-4-2-3 The Porosity from Density 53 3-3-4-3 Sonic Tool 53 3-3-4-3-1 Sonic Porosity Equation 54 3-3-4-3-2 Sonic Parameters 55 3-3-5 Electrical Resistivity Logs 56 3-3-5-1 Resistivity Theory 56 3-3-5-2 Resistivity Theory 2 57 3-3-5-3 Resistivity Model 58 3-3-5-4 Mud Resistivities 59 3-3-5-5 Normal and Lateral Tools 59 3-3-5-5-1 Laterolog Principle 61 3-3-5-5-2 Tool Types 62 3-3-5-5-3 Azimuthal Laterolog principle 62 3-3-5-5-4 Laterologs borehole effect 63 3-3-5-5-5 Azimuthal Laterolog corrections 63 3-3-5-5-6 Bed Correction 66 3-3-5-5-7 Laterolog Applications 67 3-3-5-5-8 Laterolog Limits 68 3-3-5-6 Microresistivity Tool 68 3-3-5-6-1 Uses of Microresistivity Tool 68 3-3-5-6-2 MSFL Borehole Corrections 68 3-4 Saturation Computation 69

VII

3-4-1 Basics 1 69 3-4-2 Basics 2 70 3-4-3 Other Relationships 71

CHAPTER FOUR PETROPHYSICAL EVALUATION 4-1 introduction 73 4-2 acquiring raw data from logs 74 4-2-1 correlation between logs 74 4-2-2 zone selection 74 4-3 petrophysical evaluation 76 4-3-1 reservoir and lithology determination 77 4-3-1-1 Reservoir Identification 77 4-3-1-2 lithology determination 80 4-3-1-2-1 shale volume content 80 4-3-1-2-1-1 shale content from sp log 80 4-3-1-2-2 shale content from the gamma ray log 80 4-3-1-3 porosity esitmation 85 4-3-1-3-1 quantitative interpertation from porosity logs 85 4-3-1-3-2 the porosity from the neutron/density crossplot 86 4-3-2 saturation determenatin 90 4-3-2-1 determination of water saturation 90 4-3-2-2 determination of hydrocarbon saturation 92 4-4 petrophysical cut-off values determination 95 4-4-1 clay volume cutoff 95 4-4-2 porosity cutoff 96 4-4-3 water saturation cutoff (Sw cutoff) 97 4-4-4 reservoir summation and interpretation of results 98

VIII

CHAPTER FIVE CONCLUSION AND RECOMMENDATION

5-1 Conclusion 113

5-2 Recommendations 114

5-3 References 115

5-4 Appendix 121

LIST OF FIGURES Title Page 1-1 Location map for the Muglad basin 2 1-2 Location map for the study area Neem K 4 2-1 Gondwana, showing location of cratons and Pan-African 9 belts in West and Central Africa and adjacent regions 2-2 Tectonic models of the West and Central African Rift 11 System from Fairhead (1988). 2-3 Tectonic Development of West and Central Africa. 13 2-4 Diagram showing Sudanese rift system and its relationship 17 to adjacent structures. 2-5 Sketches of Paleogeologic evolution of WCARS 18 (Genik,1993). 2-6 Regional Stress field during Early Cretaceous, (from 20 Mohamed Y et al, 1999, Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001). 2-7 Regional Stress field during Late Cretaceous, (from 21 Mohamed Y et al, 1999, Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001) 2-8 Regional Stress field during late Eocene to recent, (from 23 Mohamed Y et al, 1999, Bosworth W., 1991, Rene Guiraud et al, 1992, RIPED, 2001). 2-9 Composite Column of Muglad Basin (from Schull 1988). 24 3-1 Explaining Why Run Logs (Log interpretation can provide 29 answers to questions on). 3-2 Sketch show the reservoir and well. 30 3-3 Explain sp curve and shaleline. 34 3-4 chart sp-1 to find ratio Rmfe/Rwe 36 3-5 Chart sp-2 to determine RW. 37 3-6 SP deflection , shows the beds as distinct from each ot9her. 38 3-7 Shows the radioactive series (Potassium, Thorium, 39 Uranium). 3-8 Shows GR curve minimum and maximum 41 deflection(Russel,1944).

3-9 GR logs require correction for the effects of the mud. 44 3-10 An additional correction is needed if there is barite in the 45 borehole 3-11 Shows the cliper tool inside the well 46 3-12 Sketch shows the energy neutron “ev”. 47 3-13 Shows the hydrogen Index. 48 3-14 Shows the density tool inside the well. 51 3-15 Sketch shows the sonic tool inside the well. 54 3-16 showing the resistivity with only water RW & water and 57 matrix RO . 3-17 sketch explain resistivity modle to the formation of well. 58 3-18 Sketch showing the lateral device. 60 3-19 Showing the resistivity beds above and below the 61 formtation. 3-20 Chart explain borehole correction for Laterolog. 64 3-21 Chrat explain borehole correction for LLD & LLS. 65 3-22 Chart explain bed correction for LLD. 66 3-23 Chart explain bed correction for LLS. 67 3-24 Chart explain Mud cake correction for MSFL. 69 4-1 show the zone selection from well Neem k-1. 75 4-2 depth structure map top Abu Gabra formation in Neem k 76 (1,2,3,4). 4-3 show the reservoir identification from well Neem k-2. 78 4-4 show the reservoir identification from well Neem k-4. 79 4-5 lithology determination by Gamma ray from well Neem k-1 82 4-6 lithology determination from GR histogram ( Neem k-1). 83 4-7 Map shows Average clay volume for the study area. 84 4-8 log porosity for well Neem k-4. 87

4-9 density-Neutron crossplot for porosity estimation (Neem k-4). 88 4-10 Map shows average porosity for the study area. 89 4-11 Map shows average water saturation for the study area. 94 4-12 explain the clay volume cutoff. 95 4-13 Explain the porosity cutoff. 96 4-14 Explain water saturation cutoff 97 4-15 show the determination reservoir by Vcl & Phi cutoff. 98 4-16 Average clay volume of Abu Gabra formation. 109 4-17 Average porosity for Abu Gabra formation 109 4-18 show all tracks log for Neem k-3. 111

XII

LIST OF TABLES Title Page 3-1 show the GR resolution 42 3-2 show the GR readings in some rocks. 42 3-3 Shows Vertical resolution to the neutron . 49 3-4 Shows readings in zearo porosity . 49 3-5 Shows typical readings in shale and coal. 49 3-6 show the vertical resolution by density tool 51 3-7 show the readings in some rocks. 52 3-8 Shows the vertical resolution by sonic tool. 55 3-9 Shows the depth of investigation by sonic tool. 55 3-10 Shows the readings in some rocks by the sonic tool. 56 4-1 Reservoir summary of well Neem k-1. 100 4-2 Pay summary of well Neem k-1. 101 4-3 Reservoir summary of well Neem k-2. 102 4-4 Pay summary of well Neem k-2. 103 4-5 Reservoir summary of well Neem k-3. 104 4-6 Pay summary of well Neem k-3. 105 4-7 Manual calculation reservoir summary for Neem k-3. 106 4-8 Reservoir summary of well Neem k-4. 107 4-9 Pay summary of well Neem k-4. 108

XIII

CHAPTER ONE INTRODUCTION 1-1 Introduction

The Muglad Basin Complex is the main petroliferous sedimentary basin in the Sudan and represents the western flank of its interior rift basins which are parts of the Central African rift system (Fairhead, 1988). The Muglad Basin Complex, which is about 300 km wide and more than 1200 km long, is predominantly trending NW–SE. It extends from its northern part at the Southern Darfur Province, passes southwards through the Southern Kordofan, (Fig. 1.1). The northern end of the Muglad Basin terminates against the metamorphic and igneous complexes of the Darfur Dome, whereas the northwestern part ends at the Baggara Basin which is an E–W trending sedimentary basin, that formed synchronous with the Muglad Basin and the other Cretaceous sedimentary basins of West and Central Africa (Fig. 1.1).

Fig (1-1) represents SEEBASE image of the Muglad Basin and its vicinity (a

after Blevin et al., 2009).

1-2 Physiography

The Muglad rift basin is characterized by low relief flat plain area, except for sparse isolated outcrops in the northern part of the Basin. Therefore, this area is considered flat and surrounded by the Nuba Mountains, which represent the uplifted composed of basement terrain main igneous and metamorphic rocks. The superficial deposits of black cotton soils cover the area and some isolated sandstone outcrops east of Muglad town, laterite deposits.

1-3 Climate

Climate ranges from desert in the north to semi-tropical in the south with high to very high temperatures throughout the year. Heavy tropical rains occur in the central and southern areas, with most abundant rainfall between June and November. The annual average rainfall range between 120-800 mm. Average annual temperature over the area is around 38ºC in summer (May September) and 25ºC in winter (December - March). Wind velocities are usually less than 8 km/h. The mean humidity ranges from 21% in the dry season to 75% during the rainy season (Harrison and Jackson, 1958).

1-4 Population

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 sheeps 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 Location of study area

In this study the area of interest is called Neem k subfield is part of Muglad basin, located in the north part of the eastern flank of Block 4.

Fig (1-2) Location map for the study area Neem K

1-6 Accessibility

The Muglad Basin is accessible by railway or by roads and airport. The railway runs from Khartoum through Kosti at the Whit Nile to Muglad the main town in the study area, unpaved road which path through El-Obied to Muglad. 1-7 Problem Statement

Abu Gabra Formation is composed of mainly shale with interbeded of thin beds of sandstone and have been evaluated as a common and main source rock in the Muglad basin But here in this study, Neem K subfield was consider as main reservoir rocks (thin sandstone beds), but the problem all hydrocarbons is oil down to and there is no adjacent water containing beds to get the resistivity of the water Rw which is so important to correctly calculate the hydrocarbon percentage in the Formation, so this study in the Formation (Abu Gabra) will be petro physically correctly evaluated. 1-8 Objective of the study

The main objective of this study is to evaluate and determine the petrophysical parameters of reservoir rocks quality (Abu Gabra Formation) in Neem K Sub- field in terms of: 1-Calculate Shaleness (shale volume) percentages. 2-Determine the petrophysical properties (Porosity, Permeability…etc.). 3-Calculate water and hydrocarbon saturation. 4-Lithological interpretation and correlation of Abu Gabra Formation.

1-9 History of the Exploration

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 et al, 1985) 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. (Browne and Fairhead, 1983), (Schull,1988), (Mann,1989) and (McHargue et al. 1992) provided strong evidence of several deep Mesozoic-Cenozoic rifting in southern Sudan that commenced during Neocomian. The kinematic of the rift has been interpreted as varying along the length of the system.

The Sudan rift basins are composed of a complex system of linked extensional and transtensional sub-basins. The sub-basins typically have a half graben geometry that was modified by subsequent reactivation during younger rift cycle. Initial graben asymmetry was reversed in some cases by younger superimposed grabens. In addition, thin skinned detachments within the syn-tectonic sedimentary fill further complicated the final structural geometries (Mann,1989). (Browne and Fairhead ,1983) stated that the Sudan rifts terminate in northwest along a smooth gently arcuate line passing just north of Khartoum city. This has been interpreted as the location of a continental scale trans current fault zone which is envisioned to link the Sudan basins with Mesozoic rift basins in Chad and Niger. (Schull ,1988) stated that Abu Gabra- Muglad rift is the largest rifts in the Sudan system consequently displays the most complete stratigraphic section and greatest cumulative crustal extension.

The Muglad basin consist of several rows of alternating NW and/or NNW oriented highs and lows, corresponding to alternating NW and/or NNW oriented grabens and 6

horsts separated by fault step zones of different width. These step zones from the west to east; the Abyei flank (west fault step zone), Kaikang trough, are eastern fault step zone, Heglig ridge, Bamboo-Unity sub-basin and eastern uplift. Abu Gabra Formation is predominantly argillaceous but more are nacreous Abu Gabra Formation equivalent was identified by (Mohammed,1997) in the well located within the margins of southeast Muglad basin. (Abdullatif ,1992) pointed out that in the rift basins of the Sudan more than two rifting phases have been recorded with half grabens dominating the structural style.

CHAPTER TWO REGEONAL GEOLOGY AND TECTONIC EVOLUTION

2.1 Introduction

The Muglad basin is a major part of Sudanese rift, which is a main component of West and Central African rift-related system (WCARS). The onset of intra-continental rifting within West and Central Africa was synchronous with gradual breakup of Gondwana (Fig.2-1), and in particular, with separation of South America from Africa, implying their generic linkage. Late Jurassic – Early Cretaceous was the period of the opening of the Central and South Atlantic oceans (schull,1988; Bosworth,1992; McHargue et al,1992).and also saw the occurrence of strong and extensive rifting in the interior of West and Central Africa Multiphase rifting and some basin inversion are in response to the change of regional tectonic process, such as variations of regional stress field, shifting of plate movement, and continent- continent collision along the Alpine orogeny. In general, basins of the WCARS share much in common in occurrence and evolution because they were developed in a similar tectonic setting, though individuals show their unique histories due to local influences.

Fig (2-1) Gondwana, showing location of cratons and Pan-African belts in West and Central Africa and adjacent regions. (Bosworth,1992)

2.2 Regional Geological Setting

Basins in the WCARS are arranged in two distinct orientations, NE-SW and NW- SE, respectively (Fig. 2.2). The most prominent basin among the NE-SW striking group is the Benue Trough, and the others are distributed along the Central African Shear Zone(CASZ), such as, from west to east, Doba, Doseo, Salamat and Bagarra basins. All these basins are interpreted as pull-apart structure in nature as a result of strike-slip faulting along the CASZ, as evidenced by their basin geometry, intra-basin flower structures, and tectonic situation. The group of NW-SE striking basins is widely distributed in West Africa, such as the Tenere rift in East Niger, and Central Africa, such as the Muglad, White Nile, Blue Nile,

and Atbara basins which comprise the south Sudanese rift-related system, and the Anza rift in the North Kenya. The west and Central Africa is composed of three major cratons, West African, Arabian-Nubian, and Congo cratons, which were amalgamated through the Pan-African orogenic belts. All the Mesozoic-Cenozoic rifts occur between the cratons, or rest on the orogenic belts. The West African rifts appear between the West Africa and the Arabian-Nubian cratons, Sudanese and Anza rifts occurs on the eastern side of Congo craton, and the E-W striking basins are between the Arabian-Nubian and Congo cratons (Schull 1988; Schandelmeier and Puddlo 1990). All these clearly show that basement fabrics exert a strong effect upon the occurrence of the rifts. Actually, orogenic belts serve as crustal weakness zones, where internal structure can be easily re-activated in subsequent tectonic events, and therefore control occurrence of the Mesozoic rifts of the West and Central Africa according to RRI (1988).

Fig (2.2) Tectonic models of the West and Central African Rift System from Fairhead (1988).

The Central African Shear Zone was a reactivated faulted zone inherited from the Pan-African orogeny. It separates the NW-SE-trending rifts of West Africa from the Central Africa, and played an important role in initiation and development of

the NE-SW-trending rifts as well as Sudanese rift basins (Schull, 1988). The Shear Zone was identified mainly by geophysical means, and has been demonstrated to have experienced right lateral movement in the Cretaceous. All the basins of the Sudanese rift-related system, such as the Muglad, White Nile, Blue Nile, and Atbara basins, terminate northwards at the Shear Zone(Fig.2-2). In particular, basins near and within the shear zone show their basin axes parallel or sub-parallel to the shear, and possess typical flower structures. All these explicitly indicate apparent strong control of the CASZ on evolution of the Central African rifts. The CASZ is parallel to transform faults in the equatorial Atlantic Ocean, (Fairhead,1988) and (Schull, 1988) suggesting that its origin should be related to the opening of Central and south Atlantic around130 Ma. Actually, the gradual and diachronous opening of the Atlantic Ocean indifferent segments must have led to strike-slip movement in between. The resulted wrench faults extended into the Africa, and re-utilized old faults, thus producing the CASZ. In addition, differential extension between adjacent cratons of the Africa could also promote the striking-slip faulting of the CASZ.The West and Central Africa basins experienced multiphase subsidence from the Cretaceous to recent in response to the change of regional crustal stress field (Fig.2-3).

Fig (2-3) Tectonic Development of West and Central Africa. (Schull, 1988)

The onset of rifting was related to the opening of the Atlantic Ocean on the Western side and the Indian Ocean in the eastern side of Africa during the period from the Middle/Late Jurassic to the Early Cretaceous The first phase of subsidence was quite active and extensive (Schull 1988; Schandelmeier and Puddlo 1990). characterized by early-stage rifting3 and late stage (thermally contracted) sagging. Transition of the two stages is marked by an unconformity on basin margin, the sagging continued until the Santonian, when a number of basins, particularly the-W-trending basins, were uplifted and suffered erosion. The basin inversion was attributed to the far-field effect of initial collision of the African and Eurasian plates along the Alpine orogenic belt. The NW-SE-trending basins, such as the Tenere and Sudanese rifts escaped the inversion, because these basin axes are sub-parallel to compressional stress direction caused by the collision. As a result, the derivative tensile force in NE-SW direction promotes

the second phase of subsidence of the basins, as evidenced by the observations of the Muglad basin. This phase of subsidence was possibly also strengthened by change of movement direction of African plate relative to the Eurasian plate according to geomagnetic data, leading to crustal-scale horizontal extension in NE-SW direction in association with wrench-related basin inversion along the CASZ. The second phase subsidence persisted until the Middle Eocene, when the most intense collision occurred along the alpine orogenic belt, resulting in complete closure of the Tethyan Ocean and exerting very strong influence on basin development in interior of Africa. Most of Mesozoic rift basin came to an end during the Middle Eocene, except for the NW-SE-trendingTenere and Sudanese rifts. The third phase of subsidence began from the Late Eocene and only occurred in theTenere and some parts of Sudanese rifts system. The rifting of the Muglad basin was in a trans tensional tectonic regime during this period, and genetically related to generation of the East Africa rift-related system. It has been widely accepted that the East Africa Rift (EAR) serves as the southern arm of a triple junction (Davidson and Rex, 1980) created by upwelling of mantle materials, with the Red Sea and the Gulf of Aden being the other two. The EAR underwent differential extension, thus producing transfer fault or accommodation zones between different segments. The Muglad basin is parallel to one of those accommodation zones, the Aswa Lineament, and so influenced by wrench tectonism during the Tertiary.

2.3 Sudanese rift basins

Sudan stretches out over the contact of two regional African structural zones: � in the East and the South the Basement Complex, a Precambrian platform, developed over the central African or Congolese craton (Schandelmeier et al,1987) The craton emerged from the Paleozoic and is actually reduced to a peneplain. � in the North, a sedimentary basin developed on the Arabo-Nubian shield since the Mesozoic in which the Nubian Formation was deposited. These sediments were disturbed by Tertiary basaltic intrusions related to the Ethiopian plateau uplift and the opening of the Red Sea (Whiteman, 1971).

1. West and Central African Rift Basins

From the Upper Jurassic/Early Cretaceous to present a complex system of connected rifts extending from Nigeria to Kenya, has recorded the complex history of South American, African and Arabic plate interactions. Several rift phases alternating with compressive tectonic periods are correlated to the South Atlantic and Red Sea multi-stage opening. The West and Central African basins are typical rifts, which evolved in response to intra-plate stresses expressed along pre-existing lineaments separating the old cratonic areas. The important rifts are known as: Nigeria Chad basin, Niger Agadem-Termit basin, South Chad basin, Sudan rift basins (Franz et al., 1994 et.al,1997). These rifts recorded very thick sedimentation essentially during Cretaceous and Tertiary, but the precise stratigraphy and the subsequent ages of activity of each rift remains difficult to anticipate. It seems that regionally the EW trending fracture zones were active during the Early Cretaceous (Barremian). In contrast the meridian or NW-SE fracture zones were active during the Upper Cretaceous and Tertiary This suggests that the NS oriented initial stress changed to the EW direction during the Upper Cretaceous. The petroleum potential of Sudan is focused on three main rift 15

systems: The Muglad, Meluta and Blue Nile rift systems, which show an overall NW-SE and NS striking direction nearly perpendicular to the Central African Shear Zone (CASZ). As mentioned above the timing of the sedimentary infill may be very different between each graben. During the Gondwana break-up，the relative plate motions of the main African Cratons induced the development of large linear rift systems, where sediment thicknesses range between 10000 m to 18000 m.(Fairhead and Green, 1989) The main elongated rifts (Muglad, Benoue, Maidaguri and Agadem) are indirectly connected to the Central African Shear Zone by transitional pull apart or relay grabens: Logorne-Birni in Cameroon,

Bongor-Doba in Chad, Bagarrra in Sudan (Bermingham et al., 1983; Schull 1988; Fairhead 1988).

2.3.2 Key Sudanese Rifts

In Sudan, five NW-SE trending continental rifts are known. They define together an extensional province, which has a wide of 1000 km and a length of at least 800 km parallel to the strike direction (Fig.2-2 and Fig, 2-4). From North to South(Salama,1997).

these rifts are referred to as: i. Atbara rift. ii. The Blue Nile Rift (Khartoum and Khartoum South). iii. The White Nile Rift (Bara and Kosti). iv. The Muglad-Abu Gabra Rift (The Muglad is the best known and is the largest of the Sudan rift basins). v. The Bagarra Basin. The Sudan rift basins terminate along a smooth, gently accurate line in the northwest, interpreted as the location of the trans current fault zone at continental

scale. The Central African Shear Zone is envisioned to link the Sudan rift basins with the Lower and Upper Cretaceous rift basins in Chad and Niger. The South- eastern terminations of the Sudan rifts are more complex The South termination of Muglad occurs in Mongala area along a transverse strike slip fault. This graben has no real prolongation in NW Kenya(Bosworth,1992). where the thickness of Cretaceous is null. The Anza graben is not the straight prolongation of Sudan riffs but shows some similarities with Melut displaying particularly abundant volcanic Melut and Khartoum Blue Nile die out rapidly in Ethiopia below thick volcanics

Fig(2-4) Diagram showing Sudanese rift system and its relationship to adjacent structures, (Bosworth,1992).

2.3.3 Stress Field of Muglad Basin

The Muglad basin had suffered three regional basin forming mechanism since Early Cretaceous. Different phases of rifting of the Muglad basin were under the control of distinct tectonic regimes. In general, three basin-forming mechanisms are tentatively invoked to explain subsidence of the Muglad basin at different stages (Genik,1992) (Fig.2.5).

Fig (2.5) Sketches of Paleogeologic evolution of WCARS (Genik,1992).

2-3-3-1 Combined wrench and Normal Extension Mechanism

The Early Cretaceous was a period when the Muglad basin underwent intense subsidence. The subsidence was fault-controlled in early stage and characterized by the sagging in late Stage. Trans current faulting along the CASZ must have exerted a strong influence upon basin development, especially upon early-stage rifting (Schull, 1988). This inference is supported by the following facts: 1.The Muglad basin terminates in the north at the CASZ, which serves as northern boundary of the basin. The same is true for the other rift basins of Sudanese rift system. 2.The sub-basins in the northernmost of the Muglad basin are parallel to the CASZ, showing features of pull-apart basins; 3.The Muglad basin is wider in the north, and gets narrower toward the south, suggesting a relatively large amount of extension in the north due to tearing of the CASZ. 4.There exists some transfer or trans current faults within the Sudanese rift system, which apparently affected the basin architecture and development. This sort of faults is parallel to the CASZ, and accordingly attributed their origin to the same regional crustal shearing. Extension in NE-SW orientation, or normal to basin axis, can easily be perceived because the Early Cretaceous extensional basins were not restricted to the region near the CASZ, but distributed over a large area. Therefore, the Early Cretaceous subsidence of the Muglad basin resulted from a combined effect of strike-slip faulting and normal extension (Schull, 1988). Fig (2-6) presents a model for the Early Cretaceous rifting of the Muglad basin and regional stress field.

Fig (2-6) Regional Stress field during Early Cretaceous, (Schull, 1988). 2-3-3-2 Derivative Normal Extension Mechanism

Regional stress field changed dramatically during the Santonian epoch when the African plate began to collide with the Eurasian plate, leading to establishment of N-S-orientated compressional tectonic setting in African interior. As a result, most of the E-W-trending basins in West and Central Africa were inverted, such as the Benue Trough and pull-apart basins along the CASZ. The NW-SE-trending Muglad basin, however, deepened instead of uplift. The apparent reason is that, unlike the-W-trending basins, the Muglad basin occurred with its axis sub-parallel to the compressional stress direction, and so was affected by induced E-W- oriented extension. However, in the northwest of Muglad within E-W trending sub-basins, like Abu Sufyan sub-basin, there the Upper Cretaceous was very thin

comparing to the NW-SE sub-basins, which also indicated the change of regional stress field. (Fig. 2.7). explains the regional stress field and basin formation during the Late Cretaceous.

Fig (2.7) Regional Stress field during Late Cretaceous, (Schull, 1988).

2-3-3-3 Transtensional Mechanism

The creation of Tertiary transtensional tectonic setting for the Muglad basin, quite different from those of previous periods, was primarily related to the East African Rift evolution. The East African Rift consists of two branches, west and eastern. At the northern most end of Western Branch, there is a NW-SE-trending fault zone, Aswa lineaments, which is considered to serve as a major accommodation zone to adjust differential extension of diverse segments, and extend northwestwards into southwest side of the Muglad basin. The Aswa lineament underwent pronounced left-lateral movement since the Oligocene, thus putting the Muglad basin in a Transtensional tectonic setting. The Tertiary structural framework in block 4 characterized by the fault arrangement in an en echelon pattern, agrees well with the inference of the sinistral trans current faulting. (Fig. 2.8) explains the regional stress field and basin formation during the Tertiary (Schull 1988; Schandelmeier and Puddlo 1990).

Fig (2-8) Regional Stress field during late Eocene to recent (Schull 1988; Schandelmeier and Puddlo 1990).

2.4 Stratigraphy of Muglad Basin

Because of the scarcity of Cretaceous-Early Tertiary outcrops, the knowledge about the stratigraphy is limited to well information and the inferences made with the seismic data (Fig.2.9).

Fig (2.9) Composite Column of Muglad Basin (from Schull 1988).

2.4.1 Precambrian-Jurassic The basement is predominantly Precambrian and Cambrian metamorphic rock with limited occurrences of intrusive igneous rock. From the Cambrian to the Mesozoic, the area was an extensive continental platform (Schandelmeier et al.,1987) The oldest penetrated sedimentary rocks are non-marine Jurassic (?) salts (halite), siltstones, and claystones in the Blue Nile basin. In subsurface, basement rocks were recognized by only few wells(Schull,1988). 2.4.2 Cretaceous The Nubian sandstones crops out or is covered by surface deposits over most of northern Sudan. The sediments are non-marine medium to coarse-grained sandstones. A thick sequence of Cretaceous sediments has been penetrated by wells. This sequence is believed to be time equivalent to most of the outcropped Nubian sandstones. Based on seismic data and well control, at least an estimated 6100 m (20,000 ft.) thickness of Cretaceous sediments has been deposited in the deepest troughs. In the depocenter where no well reached the deep Early Cretaceous sediments, total Cretaceous deposits could reach at least a thickness of 8000 M (26,250 ft.), according to seismic data (basement depth at 15,000 m to 18,000 m). Cretaceous-Paleocene sediments reflect two cycles of deposition, each represented by a coarsening-upward sequence after (Schull,1988) and (Kaska, 1989). These cycles can be correlated basin wide and are directly related to rifting and basin infilling. The first cycle is represented by the Abu Gabra and Bentiu Formations. The second cycle is present in the Cretaceous Darfur Group and the Paleocene Amal Formation.

2-4-2-1 Abu Gabra Formation

The early graben-fill clastics are sediments derived from the basement and are associated to the first-cycle. During the early phase of rifting, Late Jurassic to Neocomian, claystones, siltstones, and fine-grained sandstones of the Lower Abu Gabra Formation were deposited in fluvial-floodplain and lacustrine environments. Towards the basin edges and in areas of major sediment influx these sediments graded to coarse alluvial clastics. The maximum penetration of this unit is approximately 365m (1,200 ft.) in the Muglad basin; however, on the seismic the unit is indicated to be much thicker in the deep center of the troughs. The Neocomian to Barremian the middle and upper Abu Gabra Formation represents the period of greatest lacustrine development. Several thousands of feet of organic-rich lacustrine claystones and shales were deposited with interbedded fine-grained sands and silts. The nature of this deposit was probably the result of a humid climate and the lack of external drainage, indicating that the basins were tectonically sealed. The lacustrine claystones and shales are the most important source rock of the basins. In the northern part of the Muglad basin, several wells encountered oil in the Abu Gabra sands.

2-4-2-2 Bentiu Formation

During the Aptian, shales with interbedded fine-grained sands and silts up to1000- 1500 m (approx. 3280-4920 ft.) were deposited in the deepest part of the basin. This faces with lacustrine influence shows similarities to the underlying Abu Gabra Formation. During the Albian-Cenomanian, a predominantly sandy sequence was deposited. The alluvial and fluvial-floodplain environments expanded, probably due to a change from internal to external drainage. This unit, which is up to 2000-2500 m (6560-8200 ft.) thick, typically shows good reservoir

quality. These sandstones are the primary reservoirs of the Heglig field (Schull, 1988).

2-4-2-3 Darfur Group The Darfur Group is up to 2600 m (8600 ft.) thick. The Santonian to early Maastrichtian period was characterized by a cycle of fine to coarse-grained deposition. The initial deposits, Aradeiba and Zarqa Formations, predominantly claystones, shales, and siltstones, followed the first rifting phase. Floodplain and lacustrine deposits were widespread (RRI,1991). These units may represent a time when the basins were partially silled. Throughout the basin, the Aradeiba and Zarqa Formations are an important seal. The floodplain, lacustrine claystones and red to brown shale, are interbedded by several fluvial/deltaic channel sands generally 3m to 21m (10-70 ft.) thick. These sands are significant reservoirs in the Unity field. In the Ghazal-Lower Baraka Formations, the sand-shale alternating intervals present amore regular vertical distribution corresponding to a floodplain environment. The Cretaceous ended with the deposition of increasingly coarse grained sediments of the Middle –Upper Baraka Formation. This Formation was deposited in sand-rich fluvial and alluvial fan environments, which prograded from the basin margins. 2.4.3 Tertiary

On outcrops, the Tertiary is represented by sequences of unconsolidated sands, gravels, silts and clay deposited in alluvial, fluvial and lacustrine environments. In the subsurface, based on well control and seismic data, over 5485m (18,000 ft.) of Tertiary sediments are present in the deep trough center (Schull,1988 and Kaska, 1989).

2-4-3-1 Amal Formation

The massive sandstones of the Paleocene, which are up to 762m (2,500 ft.) thick, are dominantly coarse-grained sandstones. The unit represents a high energy deposition in alluvial-plain environment with coalescing braided streams and fluvial fans. These sandstones are potentially excellent reservoirs (Schull, 1988). 2-4-3-2 Nayil 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.

CHAPTER THREE METHODS OF IVESTIGATION

3-1 Introduction

The Uses of logs has advanced over the 60+ years since the technique was pioneered. Simple correlation and hydrocarbon indication has advanced to geochemistry and resistivity profiling. Logs are employed to give information about the reservoir. From formation tops and marker beds to porosity and permeability of layers, to porosity and fluids and their types. The data used depends on the needs and the type of wells being evaluated. An exploration well needs more data than a simple development well.

Fig (3-1) Explaining Why Run Logs (Log interpretation can provide answers to questions on).

3-2 Log Interpretation

Interpretation is defined as the action of explaining the meaning of something.

Log Interpretation is the explanation of logs ρb, GR, Resistivity, etc. in terms of well and reservoir parameters, zones, porosity, oil saturation, Log interpretation can provide answers to on:

Fig (3-2) Sketch showing the reservoir and well.

In a well evaluation the questions asked are simple, where is the oil and how much is there. Effectively the question is where will we perforate and how much will come out, will it produce. These answers are available (usually) from log evaluation.

Interpretation Flowchart

This interpretation procedure follows some simple guidelines to arrive at a final answer. The input is the environmentally corrected and quality checked log data. This is an important step which cannot be avoided if a proper answer is required. Additional information such as core data may also be used. This information is zoned, broken into sections of interest (the reservoir) and other (such as shale and bad hole). Lithology selection takes the flowchart into two paths. In carbonates the problem is porosity and porosity type before computing saturation. In clastics

it is the shale, shale type and possible other minerals that have to be evaluated first. 3-3 Zoning

Zoning is the first step in any interpretation procedure. During zoning, the logs are split into intervals of: 1) Porous and non-porous rock. 2) Permeable and non-permeable rock. 3) Shaly and clean rock. Additionally; Good hole conditions and bad hole conditions. Good logs and bad logs. Zoning Tools:(SP, GR, Caliper, Neutron Density, Resistivity). The objective of zoning is to eliminate (or put aside for later study) zones which are not of prime interest, i.e. non reservoir or poor data quality. The best tools to use are the simple ones, the SP and GR which react to simple phenomena. The caliper is good as it often shows shale as bad hole and clean zones as having mud cake, in addition to showing bad hole where the log response is poor. The neutron- density-Pef are good but the first two also react to the fluid type and the Pef may be affected by barite. The resistivity is the last tool to use as it is affected mainly by fluids (Dobrin,1981). 3-3-1 SP

3-3-1-1SP Theory

SP results from electric currents flowing in the drilling mud. There are three sources of the currents, two electrochemical and one electro kinetic. Membrane potential -largest. Liquid - junction potential. Streaming potential - smallest. The SSP is the quantity to be determined. It is the deflection seen on the SP from the

Shale Base Line (zero point) to the Sand Line (max. deflection) The convention is that the SP deflection is negative when the Rmf>Rw and positive when the opposite is true. The Magnitude of the deflection depends on the difference between the two and the temperature. The shale base line may shift over a long interval. Hence, before any computations the base line is adjusted back in agreement for all the shales in the interval. The maximum deflection indicates the cleanest zone. Smaller values of SSP mean increasing shaliness. Note the SSP in this example is -60mV (3 divisions at 20mV per division), (Schlumberger Ltd 1977).

Fig (3.3) SP curve and shaleline (Schlumberger Ltd 1977).

3-3-1-2 SP uses

Differentiate potentially porous and permeable reservoir rocks from impermeable clays. Define bed boundaries. Give an indication of shaliness (maximum deflection is clean; minimum is shale). Determine Rw in both salt and fresh muds. The log depends on invasion, if there is no invasion there is no SP. Hence the SP shows where there is permeability. If there is permeability there must also be porosity. The vertical resolution of the tool is poor, hence while it will show the boundaries they will not be precise. The volume of shale can be computed from the SP using a simple linear equation.

3-3-1-3 Rw from the SP

Rw is often known from client information or local knowledge. The SP can be used to check the value or compute it when it is unavailable. It is especially useful when there are variations along the borehole. SSP = - k log Rmf/Rw (3-1) K is a constant - depending on the temperature, The SP is an excellent method of computing the vital Rw parameter. The Rmf value is usually measured on a sample, if not it can be computed charts knowing the mud salinity. The constant,

K, is a complex figure that is incorporated into the charts. Knowing the SSP (the maximum deflection) from the log and the temperature, the ratio of resistivities is obtained from Log Interpretation Chart SP-1. output = Rmfe/Rwe (3-2) The first chart gives the ratio of Rmfe/Rwe knowing the SSP and the temperature. Rmfe and Rwe are used instead of Rmf and Rw as the complete equation relates the chemical Activities of the two solutions. These “equivalent” resistivities take

this transform into account. The entire computation must be carried at the relevant borehole temperature.

Fig (3.4) chart sp-1 to find ratio Rmfe/Rwe (Schlumberger Ltd 1977).

Rmf is measured, using the mud cell. Rmfe is computed from Log Interpretation ChartSP-2. Rwe is computed, from the ratio above and Rmfe. Chart SP-2 is used to determine Rw.

Fig (3.5) Chart sp-2 to determine RW (Schlumberger Ltd, 1979).

3-3-1-4 SP borehole Effects

In some situations, there can be a number of different salinities along the logged interval. In this case the SP deflection will show these beds as distinct from each other. This is the only measurement that will show the changes in salinity. Resistivity tool will simply show more or less resistivity which could be salinity changes or changes in water saturation i.e. hydrocarbon presence.

Fig (3.6) SP deflection , shows the beds as distinct from each other (Schlumberger Ltd ,1977).

These can occur when there are beds of different salinities separated by impermeable shales. 3-3-2Gamma Ray Principles

3-3-2-1 GR Technique The tool measures a spectrum that is the result of the three naturally occurring radioactive series (Potassium, Thorium, Uranium).

Fig (3.7) Shows the radioactive series (Potassium, Thorium, Uranium).

The Potassium has a sharper shape than the other two as it decays through a single reaction to a stable element. The other two decay through a number of daughter elements each with some contribution to the final picture. The total GR is made up of these three series in varying proportions, the actual amounts of each depends on many geological factors such as depositional environment, as this leads to a greater understanding of the reservoir the measurement brings a lot more information than the simple Gamma Ray. 3-3-2-2 GR Uses

The commonest uses for the measurement is for zoning, picking clean beds from Shaly ones. the GR has a reasonable vertical resolution and hence it is a good tool to identify the bedding. The use of the gamma ray for shale volume is very common. It is perhaps the tool most used for this application. Care has to be taken when there is radioactive material in the cleans zones. A typical example would be feldspar in a sandstone.

Fig (3.8) Shows GR curve minimum and maximum deflection.

The tool reacts if the shale is radioactive (usually the case), hence show the sands and shales, the permeable zones and thenon-permeable zones.Computation of the amount of shale:The minimum value givesthe clean (100%) shale freezone, the maximum 100%shale zone, All other pointscan then be calibrated in the amount of shale.

3-3-2-3GR parameters

Table (3-1) show the GR resolution Vertical resolution 18" Depth of investigation 6"-8"

Table (3-2) show the GR readings in some rocks.

Readings in API units

Limestone <20

Dolomite <30 Sandstone <30 Shale 80-300 Salt <10 Anhydrite <10

These are some typical values for the gamma ray tools in a variety of formations, Anhydrite and salt are normally very clean, and have low values, also No formation is perfectly clean, hence the GR readings will vary, Limestone is usually cleaner than the other two reservoir rocks and normally has a lower GR. 3-3-2-4 GR applications

The tool has a number of important uses in formation evaluation, the corrected gamma ray curve (CGR) is essential to correctly compute shale volumes, in addition, minerals such as mica which contain potassium also confuse the standard gamma ray, the three outputs of this tool can identify this type of

lithology and the appropriate corrections made(Dobrin,1981). Depositional environments and the rocks diagenesis are studied by looking at the relationships between the various elements. 3-3-2-5 GR Limits

The simple gamma ray records a total of all the radioactivity in the formation, hence it is confused by the presence of organic materials or other radioactive materials such as micas, The NGT tool has no problem in identifying the components of the total gamma ray, However, this tool does have to record parts of the total spectrum hence the signal level is low and statistical, Errors will be increased by the presence of anything likely to reduce the total signal such as barite in the mud or large borehole Modern tools have less effect than older versions (Dobrin,1981).

Fig (3-9) GR logs require correction for the effects of the mud (Dresser,1983).

Fig(3-10) An additional correction is needed if there is barite in the borehole (Dresser,1983).

3-3-3 Caliper

The Caliper log is a continuous measure of the actual borehole diameter, to know the condition of the well where the other tools are being ran, measurement of the borehole diameter is done using two or four flexible arms, symmetrically placed on each side of a logging tool.The caliber shows where deviations occur from the nominal drill bit diameter, 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. The curve is traditionally a dashed line and usually plotted in track one with 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, Is also used to calculate the volume of cement needed behind the casing (Hilchie,1968).

Fig(3.11) Shows the cliper tool inside the well, (Hilchie,1968). 46

3-3-4Lithology and Porosity Tools

All tools react to lithology - usually in conjunction with the porosity,Major lithology tools are: 1. Neutron - reacts to fluid and matrix. 2. Density - reacts to matrix and fluid. 3. Sonic - reacts to a mixture of matrix and fluid,

complicated by seeing only primary porosity, A more complex method, geochemical logging, identifies 10 elements,K, U, Th, Al, Si, Ca, S, Fe, Gd, Ti From these the exact mineralogy can be computed. 3-3-4-1 Neutron Tool

Neutrons start as “ fast Neutrons “ and rapidly loose energy passing through the epithermal state to reach the thermal range, The process of slowing down is primarily caused by collision hydrogen atoms, The more hydrogen the fewer neutrons reach the detectors,The final stage is capture by an atom when a “capture” gamma ray isemitted, The oldest tools measured these gamma rays as there were nosmall reliable neutron detectors.

Fig (3.12) Sketch shows the energy neutron “ev”. 47

The first neutron tools used a chemical neutron source and employed a single detector which measured the Gamma Rays of captureThey were non- directional,The units of measurement were API units where1000 API units were calibrated to read 19% in awater-filled limestone,The tool was badly affected by the borehole environment, The second generation tool was the Sidewall Neutron Porosity (SNP),This was an epithermal device mounted on a pad,The current tool is the Compensated NeutronTool (CNT),The latest tool is the Accelerator Porosity Sonde(APS), using an electronic source for the neutronsand measuring in the epithermal region. 3-3-4-1-1 Hydrogen Index

Hydrogen Index is the quantity of hydrogen per unit volume,Fresh water is defined as having a Hydrogen Index of 1,Hence oil has a Hydrogen Index which is slightly less than that of water,The Hydrogen Index of gas is a much smaller than that of water,.In a formation, it is generally the fluids that contain hydrogen.

Fig (3.13) Shows the hydrogen Index.

The tools read a hydrogen Index. Fresh water has a value of one while saltis less. (chlorine replaces some of the hydrogen). Gas has a very low value hence the change seen by the neutron tool in a gas zone. Porosity reads too low. 3-3-4-1-2 Thermal Neutron Parameters

Table (3.3) Shows Vertical resolution to the neutron . Vertical resolution Reading inch Standard (TNPH) 24" Enhanced 12" Depth of investigation 9"-12"

Table (3.4) Shows readings in zearo porosity . Type of rock Readings in zearo porosity Limestone (0%) 0 Sandstone (0%) -2.00 Dolomite (0%) 1.00 Anhydrite -2.00 Salt -3.00

Table (3.5) Shows typical readings in shale and coal. Rock type Readings Shale 30-45 Coal 50+

The depth of investigation of this tool depends on the porosity of the system,The tool will only read zero porosity truly in limestone as it is calibrated to this mineral. Other minerals will show a deviation from this value dueto the formation salinity effect and the calibration,Shales have a high apparent porosity because of the water (i.i hydrogen) trapped by them, The actual value depends on the clay type.

3-3-4-1-3 Interpretation and Uses

The tool measures hydrogen index.Its prime use is to measure porosity,Combined with the bulk density, it gives the best possible answer for lithology and porosity interpretation, The neutron tool is recorded on a scale of “apparent neutron porosity”,This is equal to the actual porosity only in a clean limestone because the calibration is made in this mineral, It is normally combined with the density tool when the combination will handle the different minerals. 3-3-4-2 Density Tool

The Density Tools use a chemical gamma ray source and two or three gamma ray detectors.The number of gamma rays returning to the detector depends on the number of electrons present, the electron density, ρe.The electron density can be related to the bulk density of the minerals by a simple equation.

ρe = ρ ( 2Z/A ) (3-3) Where Z is the number of electrons per atom and A is the atomic weight.

Fig (3.14) Shows the density tool inside the well.

It uses gamma ray interactions in the Compton Scattering energy range to measure the bulk density of the formation.This interaction is when the incident gamma ray reacts with an electron deflecting it from its path and losing energy in the process.The PEX TLD has three detectors and the LDT two. 3-3-4-2-1 Density Parameters

Table (3.6) show the vertical resolution by density tool vertical resolution Reading inch Standard 18" Enhanced 6" Depth of investigation 6"-9"

Table (3-7) show the readings in some rocks.

Rock type Density G/CM Limestone (0pu) 2.71 Sandstone (0pu) 2.65 Dolomite (0pu) 2.85 Anhydrite 2.98 Salt 2.03 Shale 2.2-2.7 Coal 1.5

The density of each mineral is unique. The tool is calibrated in limestone ,sandstone has a lower density and dolomite is higher; shale varies with the precise clay minerals present,The vertical resolutions of the density measurements is better than the neutron tool,With alpha processing a very high resolution can beobtained.

3-3-4-2-2 Interpretation and Uses

The density tool is extremely useful as it has high accuracy and exhibits small borehole effects,Major uses include:Porosity.Lithology (in combination with the neutron tool),Mechanical properties (in combinationwith the sonic tool),Acoustic properties (in combination withthe sonic tool),Gas identification (in combination with the neutron tool),also The density is often used in a development situation as the porosity tool,This is possible if the matrix density is known,Combination with sonic measurements gives both rock mechanical properties and the acoustic impedance,The latter is used in seismic applications.

3-3-4-2-3 The Porosity from Density

Ρb= ρf + ρma(1 -Ф ) (3-4)

Ф= ρma- ρb /ρma- ρf (3-5)

There are two inputs into the porosity equation:the matrix density and the fluid density, The matrix density rma is known from core analysis or from the neutron density crossplot. The fluid density ρf , is the density of the mud filtrate.This can be measured on a sample or computed knowing the salinity. In the case of oil base mud it has to be measured. 3-3-4-3 Sonic Tool

The sonic tools create an acoustic signal and measure how long it takes to pass through a rock, By simply measuring this time we get an indication of the formation properties,The amplitude of the signal will also give information about the formation

Fig (3.15) Sketch shows the sonic tool inside the well.

3-3-4-3-1 Sonic Porosity Equation

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

Δtlog =φΔtf + (1 −φ )Δtma (3-6)

Ф=Δtlog – Δtma/ Δtf- Δtma (3-7)

The Wyllie time average equation is a linear equation of the same form as the equation relating density to porosity,Hence if the matrix value Δtma and the fluid value Δtf are known a porosity can be computed. An additional term C,is added

to take into account compaction ( or lack of it) in some sandstones then the equation becomes

Φs = (1/cp )(Δt – Δtma /Δtf - Δtma ) (3-8)

The sonic tool only measure primary porosity, it doesn't see vugs or fractures, Hence it can be used with the neutron density tools which see the total porosity to compute a "secondary porosity index",As with the density tool there are two inputs to the equation, the matrix and fluid slowness,The sonic translation to porosity is complicated by the presence of two equations, Both can be valid underdifferent circumstances. 3-3-4-2 Sonic Parameters

Table (3.8) Shows the vertical resolution by sonic tool. Vertical resolution Reading inch Standard (BHC, LSS, MSTC) 24" STC 36" 6"DT 6"

Table (3.9) Shows the depth of investigation by sonic tool. Well type Readings in(ms/ft) BHC 5" LSS-SDT 12" (12 ft spacing)

Table (3.10) Shows the readings in some rocks by the sonic tool. Type of rock Readings in(ms/ft) Limestone (0pu) 47.5 Sandstone (0pu) 51-55 Dolomite (0pu) 43.5 Anhydrite 50 Salt 67 Shale >90 Coal >120 Steel (casing) 57

The depth of investigation of a sonic tool is approximately in inches, its longest spacing in feet,One important slowness is that of steel casing as it forms part of the tools check, A section of log is run in casingand should read 57 μsec/ft. As this tool has no calibration (it measures time) this is an essential part of the LQCprocedure. 3-3-5 Electrical Resistivity Logs

3-3-5-1 Resistivity Theory

The resistivity of a substance is a measure of to impede the flow of electrical current,Resistivity is the key to hydrocarbon saturation determination,Porosity gives the volume of fluids but does not indicate which fluid is occupying that pore space (Archie, 1942)Resistivity is resistance per unit length, We can often employ electrical analogies when dealing with resistivity tools measuring in the

formation,This was the first type of measurement ever made and it is still the only way to find and evaluate the hydrocarbons in a reservoir. 3-3-5-2 Resistivity Theory 2

The Current can only pass through the water in the formation, hence the resistivity depends on: 1.Resistivity of the formation water. 2,Amount of water present. 3.Pore structure.

Fig (3-16) showing the resistivity with only water RW & water and

matrix RO .

The flow of current can only be carried by ions in the formation,The ions are only present in the pore space andonly in the water, The more ions (more water) the lower the resistivity,The higher the salinity (more ions) thelower the resistivity,The formation water has a resistivity of Rw,The formation containing only water has a resistivity of Ro, This is adefinition. 3-3-5-2 Resistivity Model Most tools read in the invaded zone, hence only parameters here are required. Resistivity tools have to measure both the invaded and virgin zones, This means that the parameters for both zones have to be defined, The borehole also contains components which are “seen” by the tools,These three zones have resistivities, Rm, Rmc, Rmf, Rw of the fluids involved,There are also the resistivities of the formations, Rxo and Rt The water saturations of both zones also need to be defined as this determines the resistivity, Sxo and Sw, Finally the diameter of the invaded zone, di is needed to compute the contribution fromthis zone.Some of these parameters are measured, others are calculated.

Fig (3.17) sketch explain resistivity modle to the formation of well.

3-3-5-4 Mud Resistivities

The first resistivities encountered are those of the mud, mud filtrate and mud cake,The surface measurements to obtain these valuesare often erroneous, The problem with the surface measurement of the mud resistivities is not with the measurement procedure or equipment, but with the procurement of the samples,The mud sample comes from the mud tanks and is usually good, The mud filtrate and cake come from a sample of mud put through a mud press, This is often done in advance of the logging and the samples left exposed to contamination,The checks given in the Chart Books enable the values to be verified and if necessary redone with fresh samples.These values are important as they are used in corrections and in computations. 3-3-5-5 Normal and Lateral Tools

The Lateral device used the same principle,The difference is in electrode configuration and spacing, Problems came from"thin beds" when the signature of the curve was used to try and find the true resistivity.

Fig (3.18) Sketch showing the lateral device .

The configuration of the lateral device is different but the principle is the same with the equipotential surface voltage being read by the measure electrode M.Devices using this type of technique are still in use in Ultra Long Spacing Electrical Log (ULSEL) used for the detection of salt domes and nearby well casings (when drilling relief well for a blow out) also in use in some Russian logging tools.

3-3-5-5-1 Laterolog Principle

A current-emitting electrode, Ao, has guard electrodes positioned symmetrically on either side, Guard electrodes emit current to keep the potential difference between them and the current electrode at zero, This forces the measuring current to flow into the formation of interest.

Fig (3.19) Showing the resistivity beds above and below the formtation. The problem of a resistive bed with lower resistivity beds on either side is that in the old tools the current takes the easiest path,The solution is to focus the measure current into the formation, This is done using a current emitted from electrodes above and below the measure electrode,This forces the current to flow in a sheet directly into the formation in front of it with little deviation.

3-3-5-5-2 Tool Types

Various configurations have been used:

1.LL3 to LL7 to LL9 to DLT tools added more electrodes and were,eventually able to run deep and shallow simultaneously,These tools looked in all directions. 2.HALS/ARI Using the same principle, these are azimuthal,tools capable of looking in 12 directions. 3.HRLA Latest tool, using modern techniques to eliminate,the need for a voltage reference and produce a much more accurate resistivity. The names of the tools reflect the number of electrodes, Extra electrodes are added to improve the focusing,The current tools use the same electrodes to produce two different depths of investigation, a shallow and a deepmeasurement, This is achieved using different frequencies for each. 3-3-5-5-3 Azimuthal Laterolog principle

These are focused to give a deep reading(LLD) and a very shallow reading(LLS) of the tool stand-off, The current emitting electrode is split into twelve separate electrodes, It has 12 electrodes set equally spaced around the tool giving 12 azimuthal Laterolog readings. The objective of this tool is twofold, firstly to better the vertical resolution and secondly to look all around the borehole.This is achieved using a set of twelve electrodes much smaller than the standard ones set in a ring around the tool.This means each electrode looks at a 30Þ region.As the tool can be run eccentred in the borehole each electrode will have a different borehole correction. To be able to perform this correctly a very shallow

measurement is made giving an electrical radius of the hole in front of every electrode. This is used to correct the raw readings. It can also be used to provide a borehole profile. 3-3-5-5-4 Laterologs borehole effect

The string of resistivities in series is all measured by the tool. The objective is to minimise the unwanted Rm, Rmc and Rxo and read the best possible Rt. Hence the need for salty muds which would give low Rm, Rmc and Rxo.Rmc is neglected as its a small thickness compared to the beam width of the tool.This type of tool reads best at the highest resistivities. Laterologs see the borehole environment as: RLL = Rm + Rmc + Rxo + Rt (3-9) Rm: resistivity mud Best measurement is in salt-saturated, low resistivity mud.Worst readings obtained in fresh mud. Measurements cannot be made in oil- based mud. Rmc:resistivity mud cake ,Usually neglected as very small. Rxo: Depends on Rmf, needs to be known. Rt:true resistivity,Parameter to be measured, the higher the better. 3-3-5-5-5 Azimuthal Laterolog corrections

The borehole correction is similar to the other Laterolog measurements. It is a function of the borehole diameter and the ratio of formation to mud resistivity.This chart is used to make the correction. It can be done by the surface acquisition system.The corrections are very similar to the deep Laterolog in magnitude. This chart shows the centred chart. Once again the chart is entered with the ratio of the resistivity measured divided by the mud resistivity, reading up to the hole size and across to the y-axis gives the correction factor.

Fig (3.20) Chart explain borehole correction for Laterolog. (Dresser,1983).

Fig (3.21) Chrat explain borehole correction for LLD & LLS (Schlumberger Ltd 1972).

3-3-5-5-6 Bed Correction

The next correction accounts for the effects of adjacent beds which still occur despite focusing, the measurement is still affected by beds above and below. This is the so-called squeeze andanti-squeeze effect.If the shoulder beds are more resistive the reading has to be reduced, if it is less resistive it has to be increased. If the shoulder bed is highly resistive, the log hasto be reduced. (Squeeze.)If the shoulder bed is of low resistivity, the log has to be increased. (Anti-squeeze.).

Fig(3.22) Chart explain bed correction for LLD (Schlumberger Ltd ,1972).

Rs is the resistivity of the bed above and below the formation of interest.The chart is entered with the bed thickness,moving up the ratio RLLD/RS.The correction factor is read on the y-axis.

Fig(3.23) Chart explain bed correction for LLS (Schlumberger Ltd, 1972).

3-3-5-5-7 Laterolog Applications

Measures Rt and Standard resistivity in high resistivity environments.alsoUsable in medium-to-high salinity mud and Good results in high contrast Rt/Rm and Fair vertical resolution (same as porosity tools).The Laterolog find most of its application in high resistivities where it works best. It will work in fresh muds if the resistivity is high enough.The tools do not measure Rt directly, rather they measure a deep and shallow Laterolog from which Rt can be found.

3-3-5-5-8 Laterolog Limits

The laterolog Cannot be used in oil-based muds,also Cannot be used in air-filled holes,and it is Poor when Rxo > Rt, the Oil based and air (or foam) muds will not allow the current to pass hence no measurement can be made.Modelling is used to predict the log reading in a given formation, It can be used to explain unanswered questions.The condition Rxo > Rt is that of having mud fresher than the formation water in a water zone. Here the Laterolog is trying to read a low resistivity through a higher one. 3-3-5-5 Microresistivity Tool

Shallow reading versions of resistivity tools;always pad-mounted,the First was the Microlog which is still in use and Second was the Micro Laterolog (MLL),replaced byProximity (PL) tool, replaced by MicroSpherically Focused Log (MSFL),replaced by Micro Cylindrical Focused Log(MCFL)Objective is to read Rxo (Invaded Zone Resistivity) only.Tools are focused to pass through the mud cake.

3-3-5-5-1 Uses of Microresistivity Tool

The microresistivity use to Rxo measurement in water- based muds and

Correction for deep resistivity tools also Sxo determination. The measurement of Rxo is needed to compute the water saturation in the invaded zone, Sxo.Knowing Rxo the deep measurements can be inverted to give the true virgin formation resistivity Rt.As with all pad type tools bad hole conditions will badly affect the measurement quality.

3-3-5-5-2 MSFL Borehole Corrections

In spite of its focusing, the tool still needs to be corrected for the mud cake thickness and resistivity.The correction requires an input of mud cake thickness

which is not measured directly. It also needs the mud cake resistivity which iseither measured or computed from charts.The tool focusing has been set assuming there is always some mud cake, hence the tool always needs some correction, (Schlumberger Ltd 1989).

Fig(3.24) Chart explain Mud cake correction for MSFL, (Schlumberger Ltd 1989).

3-4 Saturation Computation

The saturation of a formation represents the amount of a given fluid present in the

pore space, The porosity logs react to the pore space and The resistivity logs react to the fluids in the pore space, so The combination of the two measurements gives the saturation (Archie, 1942).

3-4-1 Basics 1

(3-10)

F: Formation Factor. Rw: resistivity of water in the pore space.

Ro: resistivity of a rock totally filled with water.

(3-11)

M: is called the "cementation exponent". a: is called the "lithology" constant.

3-4-2 Basics 2 The Saturation can be expressed as a ratio of the resistivities:

(3-12)

n: is the "saturation exponent", an empirical constant.

Substituting for Ro:

(3-13)

Substituting for F:

(3-14)

The last equation ,gives Archie equation is hence very simple. It links porosity and resistivity with the amount of water present, Sw.Increasing porosity, Ф, will reduce the saturation for the same Rt.Increasing Rt for the same porosity will have the same effect.also the sam method can be applied to the invaded zone. The porosity is identical, the lithology is assumed to be the same, hence the constants a, n,m are the same.The changes are the resistivities which are now Rxo and Rmf. Rmf is measured usually on surface and Rxo ismeasured by the MSFL tool. The equation is then:

(3-15)

The change with the virgin zone is that the water in place is now represented by Rmf, the mud filtrate resistivity and the formation resistivity is now Rxo.The value of Sxo is useful in understanding how a reservoir has be haved during drilling. If there is no difference between the two in a hydrocarbon zone there has been no invasion, a large difference suggests a lot of invasion. The is usually represented by the volumes, ФSw and ФSxo.

3-4-3 Other Relationships 1. Dividing for Sxo and Sw, with n set to 2

SW = water saturation

( 3 - 1 6 ) Sxo = saturation for zone invation RT = true resestivity

Rmf = resestivity of filtrate

RW = rsestivity of water Rxo = rsestivity of invation zone

Observations suggest:

(3-17)

Hence:

(3-18)

providing a quick look saturation answer when porosity is not available, This method is called the Ratio Method and was used extensively as a quicklook to find the hydrocarbon zones. Its advantage is that there is no need for a porosity log. This could be useful in the case of bad hole, unfortunately the Rxo tool is also likely to be affected in this case.

CHAPTER FOUR

PETROPHYSICAL EVALUATION

4-1 Introduction

The most important phase of well-logging operations is interpretation, during this phase, geologists, geophysicists, engineers, and log analysts use well logs to obtain information necessary to perform their tasks. Logs have many uses, exploration geologists use logs to recognize deposition environments and other significant geologic features, development geologists use them mostly to correlate and to map potential formations, logs are valuable tools for geophysicists interpreting seismic data. Logs are also used completion .log data are extremely valuable in reservoir engineering calculations, especially in reserve estimation, the most critical use of logs, however, is detection of hydrocarbons and estimation of the potentials of hydrocarbon-bearing formations. The remainder of this project focuses on the last application the detection and evaluation of hydrocarbon- bearing formations. Several interpretations techniques have been used to detect hydrocarbon – bearing zones, and to estimate their porosities and fluid saturations. The optimum interpretation technique for analyzing a formation of interest depends on the quantity and the quality of the data to log analyst. it is also depending on type problem at hand.log analysts are faced with four main questions 1\does specific formation or zone contain hydrocarbons? 2\which hydrocarbon is present, oil, gas or both? 3\is the hydrocarbon saturation high enough to indicate sufficient effective permeability to hydrocarbons?

4\is the hydrocarbon accumulation large enough to warrant the completion of the well? If the log can answer all four question conclusively and positively, the well is usually completed in the zone of interest. If the answers are conclusively negative, the formation is the abounded. 4-2 Acquiring raw data from logs

4-2-1 Correlation between logs

Absolute-depth measurement with wireline tools is very difficult, and depth variation between logs recorded in the same borehole may exist. These variations are caused mainly by borehole irregularities and tool type. Some tools, such as induction, are cylindrical, so withdrawing them from the wellbore is easy. Other tools, such as the density, sidewall neutron and sonic log with caliper. Have arms that drag on the side of the hole. 4-2-2 Zone selection

After the log are placed on-depth the next step is to select zones of interest. In the detection of hydrocarbons, the zones of interest are those that display permeability. The permeable beds are usually identified using the sp log. The microlog is an excellent permeability indicator. The effect of mud filtrate invasion on different resistivity tools helps indicate permeable beds, after the zones are selected, the resistivity or conductivity and other values are read and tabulated.it is good practice also to record the values on the log itself to provide a record that will not be separated from the log. Fig (4.1).

Washout zone

Zone of interest

Pay zone

Fig (4.1) Zone selection from well Neem k-1.

4-3 Petrophysical evaluation

The main target of this study is to evaluate and determine the Petrophysical parameters of reservoir rocks quality (Abu Gabra Formation) in Neem K Sub- field to wells(Neem k-01,Neem k-02,Neem k-03,Neem k-04) (fig4.2) Abu Gabra Formation is composed of mainly shale with interbedded of thin beds of sandstone and have been evaluated as a common and main source rock in the Muglad basin but here in this study, Neem K subfield was considering as main reservoir rocks (thin sandstone beds), the evaluation of Abu Gabra Formation has long been a difficult task clay minerals affect all well-logging measurements to some degree. The shale effects have to be considered during evaluation of such reservoir parameter as porosity and water saturation.

Fig (4.2) Depth structure map top Abu Gabra formation in Neem k (1,2,3,4).

4-3-1 Reservoir and lithology determination

4-3-1-1 Reservoir Identification

The most reliable indicator of reservoir rock is the behavior of the density and neutron logs with the density moving to the left (lower density) and touching or crossing the neutron curve. All these cases were corresponded to a fall in the gamma ray log, in addition to the presence of the mud cake, right deflection of the Spontaneous Potential (SP) and the separation between three resistivity curves respectively. The greater cross over between the density and neutron indicate the better-quality of the reservoir and vice versa, Figures1 and 2 show good and bad reservoir identification from log. Shale was clearly identified as zones where the density lies to the right of the neutron, associated with increase in gamma ray. Also, the shale was identified in addition to the density and neutron from the presence of wash out, left deflection of SP and when the three resistivity curves overlie each other. Fig (4-3).

reservoir

Fig (4.3) The reservoir identification from well Neem k-2.

reservoir

Fig (4.4) The reservoir identification from well Neem k-4.

4-3-1-2 lithology determination

Abu Gabra Formation, this unit represents the early phase of lacustrine environment with thousands of meters of organic-rich claystones and shale deposits interbedded with fine-grained sandstones and siltstones locally overlies the Sharaf Formation or unconformably rests on the basement rocks. However, sediments of older age might well exist in the deepest troughs of the basin. The claystone sand shale represents the main petroleum source rocks in the Muglad Basin. Also reservoirs in this formation are represented by interbedded sands within the shaley source interval in (Neem-k sub-filed). The sandy intervals within AG-2 and AG-4 are considered as the best reservoirs. 4-3-1-2-1 shale volume content

4-3-1-2-1-1shale content from sp log

In this study the sp log was used for estimate the shale volume in Abu Gabra formation The maximum deflection indicates the cleanest zone. Smaller values of SP mean increasing shaliness, also the mathematical models and linear relationship in this case has been used for quantitative interpretation.

(4-1)

: is the shale response in the shaly zone of interest

: is the shale response in an adjacent clean 4-3-1-2-2 Shale content from the gamma ray log

The GR log has been used for estimation of the volume of shale in study area, For estimating the volume fraction of shale in a formation Vsh, the traditional approach is to scan the log for minimum and maximum GR readings, γmin and

γmax. The minimum reading is then assumed to be the clean point (0% shale), and the maximum reading is taken as the shale point (100% shale). Then the GR reading in API units at any other point in the well (γlog) may be converted to the GR index IGR by linear scaling:

(4-2)

: the GR index

: the GR maximum

: the GR minimum

: the GR reading from log For compute the shale volume to Abu Gabra formation in this study was used the larionoy equation (4-3)

: the amount of the shale volume , : the GR index

Shale baseline

Sand baseline

Fig (4.5) Lithology determination by Gamma ray from well Neem k-1.

Fig (4.6) Lithology determination from GR histogram ( Neem k-1).

Average clay volume for the study area

Fig (4.7) Map showing average clay volume for the study area.

4-3-1-3 porosity esitmation

Three types of logging tools were used to estimate the amount of pore space in a rock in the study area: the neutron (NPHI) and density (RHOB) and sonic (DT). The neutron log records count the collisions between neutrons that radiate from a tool source and hydrogen atoms within the rock of the borehole wall. So, the log is mainly a measure of hydrogen concentration (mostly contained by the pore fluids of the formation). The neutron logs are scaled directly in units of porosity. In this study the presence of shale complicates the interpretation of the tool response because of the diverse characteristics of shale and the different responses of each porosity to the shale content. On the density porosity log, shale display low to moderate porosity values, on the sonic and neutron logs, shale display moderate to relatively high porosity values, the tool response expressed by eq, depend on the porosity, shale content and the fluid.

Tool response = f (matrix, porosity, shale content)

4-3-1-3-1 quantitative interpertation from porosity logs

Mathemtical modles and linear equation as well as denstiyn ,neutron and sonic equation has been used for estimate the porosity in this study , cacluate the porosity from density

(4-4)

: porosity , : density matrix , : density from log, : density fluid

The porosity from the sonic log

(4-5)

: porosity , : sonic reading from log, : sonic through the fluid

: sonic through matrix 4-3-1-3-2 the porosity from the neutron/density crossplot crossplotting is avery useful interpertation technique an ambiguous relationship between two parameters can be clarified by crossplotting the parameters,in this study crossplot between density&neutron has been used for determine lithology and porosity and evaluate shaly formation.(Fig.4.7).

ND&GR matching

porosity

Fig (4.8) Log porosity for well Neem k-4.

Fig (4.9) Density-Neutron crossplot for porosity estimation (Neem k-4).

Map shows Average porosity for the study area

Fig (4.10) Map showing average porosity for the study area.

4-3-2 saturation determenatin

Saturation is the measure of the fluid volume present in the pore volume of a porous medium. By definition, the saturation of a fluid is the ratio of the fluid volume to the pore volume or the rock. Hence, considering the fluids typically present in a reservoir rock:

(4-6)

Where Si and vi i= w,o,g are the saturations and volumes of water, oil, and gas. The sum of saturation of each fluid phase is equal to unity since the pore space is completely filled with fluids (or at least the effective pore volume). Because the fluids and their saturations in the pore space may vary from point to point and pore to pore, the values of saturation are meaningful only for samples large enough for the porous medium to be considered a continuum.There are several technques as well as resistivity logs and archie equation has been used to estimate and determaine the saturation in study area. 4-3-2-1 Determination of water saturation

The desired petrophysical parameter from resistivity measurements is the water saturation Sw, The logs resistivity has been used for determination water saturation The cornerstone of saturation interpretation from resistivity measurements is the evaluation of the Archie relationship , in this study to

obtained the value of saturation water was caucluated many parmater such as formation factor F , RO ,

(4-7), (4-8)

(4-9) , . (4-10)

(4-11)

Sw = water resistivity F = formation factor

RO = resistivity of a rock totally filled with water.

Rw = water resistivity Ф = porosity

Rt = true resistivity

Shaly sand corrections all tend to reduce the water saturation relative to that which be calculated if the shale effect is ignored in the evaluation processes. Over the years, for Shaly sands a large number of models relating fluid saturation to resistivity have been developed according to the geometric form of existing shales (laminated, dispersed and structural). All these models are composed of a shale

term and a sand term. The shale term may be independent or not of the sand term. All models are reduced to the clean sand model when the volume of shale is insignificant. For relatively small shale volumes, most shale models might yield quite similar results ( Waxman and Srnits,1968; Poupon, 1970; and Schlumberger, 1987 ).The comparison of the various water saturation equations in shaley sand shows that: I) The clean sand equation does not compensate for clay conductivity, the water saturation it computes is too high; 2) Simandoux is essentially applicable to laminated clay models, with some adaptation for nonlinear behavior of shale electrical properties and 3) Waxman- Smits is essentially designed for the case of dispersed or structural clay models and as they account for the effects occurring in the pore space, they provide lower water saturation than laminated models (Simandoux, 1963; Waxrnan and Smits, 1968; Fertl and Hammack, 1971). 4-3-2-2 determination of hydrocarbon saturation Hydrocarbon saturation Sh is the percentage of pore volume in a formation occupied by hydrocarbon has been determined in this study by linear equation, depending on logs data valuable in study area, the ability of the mud filtrate to move oil in the invasion processes implies that the formation exhibits permeability to oil and that it could be a hydrocarbon potential formation. This ability is diagnosed by the difference between flushed zone saturation, Sxo, and virgin zone saturation Sw, from this relation between (Sw, Sxo) was obtain movable oil saturation MOS it is expressed As

MOS = Sxo – Sw (4-12)

In the invaded zone the water saturation Sxo was determined by this equation

(4-13)

Where : - Rmf = resistivity of 100% mud filtration, Rxo =resistivity read from MFSL log. the saturation in the unmoved or residual hydrocarbons of the invaded zone was determine by this equation residual oil saturation (ROS)

ROS = 1- Sxo (4-14)

The hydrocarbon saturation (Sh) was calculate from the relation

Sh = 1- Sw (4-15)

Map shows average water saturation for the study area

Fig (3.11) Map showing average water saturation for the study area

4-4 petrophysical cut-off values determination

The aims of usage cut-off values are to eradicate the non-reservoir rocks and calculate the reservoir rocks, in the Neem k filed also evaluating clean or tight sandstones and also determining net -pay zone, they are three types of cut-off clay volume cut-off (Vcl cut-off), porosity cut-off (Phi cut-off) and water saturation cut-off. (Sw cut-off). The determination of values of this cut-off for Abu Gabra formation was done by using the interactive petrophysics software and plotting the VCL reservoir versus zone and porosity Phi reservoir against zone. 4-4-1 Clay volume cutoff w

From the chart the clay volume cutoff was found less than 50, therefore the value Vcl cutoff ≤ 50 was used in this study for Abu Gabra formation, (fig.4.9)

Fig (4.12) Clay volume cutoff.

4-4-2 Porosity cutoff

From the below chart the porosity cutoff was found more than 10 therefor the porosity cutoff was used in this study ≥ 10 for Abu Gabra formation, (fig.4.10).

Fig (4.13) Porosity cutoff.

4-4-3 Water saturation cutoff (Sw cutoff)

The chart below explain the water saturation cutoff was found less than 80 , therefor water saturation cutoff was used in this study ≤ 80  fig(4-11)

1.2 water saturation cutoff

1 Water zone 0.8

 oil1 0.6 Sw oil2 oil3 0.4 oil4 water1 0.2 OilOil zone Zone water2

0 0 10 20 30 40 50 60 LLD/Rt

Fig (4.14) Water saturation cutoff

determination reservoir by Vcl & Phi cutoff 0.8 non resorvoir 0.7

0.6

0.5 

Vcl 0.4 tight zone 0.3 oil1

0.2

0.1 tight reservoir good reservoir 0 0 0.05 0.1 0.15 0.2 PHIE

Fig (4.15) Determination of reservoir by Vcl & Phi cutoff.

4-4-4 Reservoir summation and interpretation of results

The sequential integration and calibration procedures used in this study minimize the errors and uncertainties in the final results. Errors and uncertainties were addressed at each stage of the interpretation from data selection and preparation through to normalization and the final calibration and validation of shale volume, porosity, saturation and parameters. A good understanding of potential errors and uncertainty limits were gathered during all of the analysis stages. The overall petrophysical analysis was then reviewed with respect to variables and parameters

that contribute the largest uncertainty to the computed results. In many cases, the greatest uncertainty is associated with the data itself, like well with limited data and intervals of poor quality or missing data due to hole problem. This kind of uncertainty was minimized by using appropriate data preparation, reconstruction and interpretation procedures. The calculated reservoir parameter such as gross sandstone thickness, net pay thickness, average porosity shale volume and average water saturation, were obtained from each well. The assumption of use cutoff values is that any zone where porosity ≤ 10 and Vcl ≥ 50 and Sw ≥ 80  is not reservoir, and cutoff values is that any zone where porosity ≥ 10  and Vcl ≤ 50  and Sw ≤ 80  is reservoir. The final interpretation is listed in the table for each well in this chapter the characteristics of Abu Gabra formation were studied level by level for whole section of the formations, these tables represent the oil pays mainly distributed in Abu Gabra formation.

Table (4.1) Reservoir summary of well Neem k-1. Zn NO Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl

1 Abu Gabra 2539.03 2545.97 6.94 5.55 0.8 0.161 0.806 0.119

2 Abu Gabra 2560.77 2580.05 19.28 5.71 0.296 0.137 0.762 0.198

3 Abu Gabra 2672.57 2681.97 9.41 6.09 0.648 0.177 0.67 0.115

4 Abu Gabra 2691.38 2696.38 5 3.08 0.617 0.088 0.85 0.292

5 Abu Gabra 2812.27 2825.53 13.26 12.03 0.907 0.192 0.962 0.159

6 Abu Gabra 2828 2841.26 13.26 13.03 0.983 0.187 0.932 0.085

7 Abu Gabra 2861.31 2878.12 16.81 12.49 0.743 0.18 1 0.137

8 Abu Gabra 2882.12 2892.15 10.02 8.02 0.8 0.165 1 0.113

9 Abu Gabra 2897.24 2908.03 10.79 8.64 0.8 0.157 1 0.142

10 Abu Gabra 2912.35 2919.9 7.56 5.24 0.694 0.18 0.992 0.248

11 Abu Gabra 2927.31 2959.22 31.92 20.51 0.643 0.162 1 0.227

12 Abu Gabra 2962.31 2995.31 33 32.77 0.993 0.197 0.996 0.142

13 Abu Gabra 3034.63 3056.52 21.9 19.43 0.887 0.185 0.997 0.155

All Zones 2539.03 3353.51 204.69 152.58 0.745 0.177 0.961 0.156

100

Table (4.2) Pay summary of well Neem k-1. Zn No Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl 1 Abu Gabra 2539.03 2545.97 6.94 3.55 0.511 0.171 0.746 0.112

2 Abu Gabra 2560.77 2580.05 19.28 4.01 0.208 0.139 0.688 0.219

3 Abu Gabra 2672.57 2681.97 9.41 3.78 0.402 0.193 0.525 0.079

4 Abu Gabra 2691.38 2696.38 5 1.85 0.37 0.09 0.803 0.325

5 Abu Gabra 2812.27 2825.53 13.26 0.15 0.012 0.127 0.849 0.224

6 Abu Gabra 2828 2841.26 13.26 1.7 0.128 0.174 0.8 0.102

7 Abu Gabra 2861.31 2878.12 16.81 0 0 ------

8 Abu Gabra 2882.12 2892.15 10.02 0 0 ------

9 Abu Gabra 2897.24 2908.03 10.79 0 0 ------

10 Abu Gabra 2912.35 2919.9 7.56 0 0 ------

11 Abu Gabra 2927.31 2959.22 31.92 0 0 ------

12 Abu Gabra 2962.31 2995.31 33 0.31 0.009 0.347 0.791 0.225

13 Abu Gabra 3034.63 3056.52 21.9 0.15 0.007 0.269 0.826 0.402 All ZONE 2539.03 3353.51 204.69 15.5 0.076 0.163 0.683 0.162

101

Table (4.3) Reservoir summary of well Neem k-2. Zn No Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl 1 Abu Gabra 2613.93 2617.17 3.24 1.7 0.524 0.182 0.42 0.231 2 Abu Gabra 2625.49 2636.91 11.41 11.03 0.966 0.17 0.732 0.17 3 Abu Gabra 2796.5 2806.53 10.02 8.17 0.815 0.145 0.824 0.109

4 Abu Gabra 2811.46 2816.39 4.94 4.86 0.984 0.137 0.634 0.063

5 Abu Gabra 2816.39 2826.73 10.33 10.1 0.978 0.137 0.963 0.101

6 Abu Gabra 2844.15 2847.39 3.24 2.47 0.762 0.152 0.757 0.071

7 Abu Gabra 2849.55 2858.49 8.94 7.09 0.793 0.135 0.778 0.114

8 Abu Gabra 2862.19 2870.36 8.17 7.48 0.915 0.139 0.76 0.12

9 Abu Gabra 2873.91 2880.85 6.94 6.86 0.989 0.15 0.778 0.06

10 Abu Gabra 2895.96 2899.66 3.7 2.39 0.646 0.134 0.776 0.087

11 Abu Gabra 2899.66 2910.15 10.48 8.25 0.787 0.134 0.943 0.143

12 Abu Gabra 3077.15 3082.15 5 2.78 0.555 0.14 0.722 0.116

13 Abu Gabra 3181.69 3198.96 17.27 11.57 0.67 0.139 0.772 0.096

14 Abu Gabra 3326.03 3335.28 9.25 7.71 0.833 0.197 0.992 0.18

15 Abu Gabra 3550.69 3568.12 17.42 14.49 0.832 0.226 0.992 0.333

16 Abu Gabra 3573.05 3594.64 21.59 17.73 0.821 0.261 0.996 0.385

ALL Zones 2613.93 3594.64 151.95 124.67 0.82 0.174 0.879 0.182

102

Table (4.4) Pay summary of well Neem k-2. Zn No Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl 1 Abu Gabra 2613.93 2617.17 3.24 1.7 0.524 0.182 0.42 0.231 2 Abu Gabra 2625.49 2636.91 11.41 9.1 0.797 0.178 0.703 0.167 3 Abu Gabra 2796.5 2806.53 10.02 4.78 0.477 0.154 0.743 0.107 4 Abu Gabra 2811.46 2816.39 4.94 4.86 0.984 0.137 0.634 0.063 5 Abu Gabra 2816.39 2826.73 10.33 0.39 0.037 0.155 0.81 0.079 6 Abu Gabra 2844.15 2847.39 3.24 1.7 0.524 0.162 0.716 0.055 7 Abu Gabra 2849.55 2858.49 8.94 4.78 0.535 0.138 0.73 0.111 8 Abu Gabra 2862.19 2870.36 8.17 5.09 0.623 0.147 0.699 0.121 9 Abu Gabra 2873.91 2880.85 6.94 5.86 0.844 0.152 0.757 0.053 10 Abu Gabra 2895.96 2899.66 3.7 2.16 0.583 0.136 0.767 0.081 11 Abu Gabra 2899.66 2910.15 10.48 0.15 0.015 0.156 0.848 0.117 12 Abu Gabra 3077.15 3082.15 5 2.78 0.555 0.14 0.722 0.116 13 Abu Gabra 3181.69 3198.96 17.27 7.71 0.446 0.148 0.716 0.088 14 Abu Gabra 3326.03 3335.28 9.25 0 0 ------15 Abu Gabra 3550.69 3568.12 17.42 0.31 0.018 0.264 0.751 0.189 16 Abu Gabra 3573.05 3594.64 21.59 0 0 ------ALL Zones 2613.93 3594.64 151.95 51.35 0.338 0.154 0.705 0.108

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Table (4.5) Reservoir summary of well Neem k-3.

Zn No Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl

1 Abu Gabra 2686.66 2691.92 5.26 4.8 0.913 0.16 1 0.121

2 Abu Gabra 2696.79 2702.02 5.23 4.42 0.845 0.176 1 0.159

3 Abu Gabra 2715.84 2737.33 21.49 21.3 0.991 0.192 0.993 0.112

4 Abu Gabra 2740 2757.98 17.98 17.75 0.987 0.169 1 0.113

5 Abu Gabra 2804.46 2810.64 6.17 5.83 0.944 0.178 0.727 0.083

6 Abu Gabra 2810.64 2817.19 6.55 5.45 0.831 0.152 0.968 0.127

7 Abu Gabra 2822.52 2837.46 14.93 13.87 0.929 0.164 0.999 0.101

All zones 2686.66 2837.46 77.62 73.42 0.946 0.174 0.973 0.112

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Table (4.6) Pay summary of well Neem k-3.

Zn NO Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl

1 Abu Gabra 2686.66 2691.92 5.26 0 0 ------

2 Abu Gabra 2696.79 2702.02 5.23 0 0 ------

3 Abu Gabra 2715.84 2737.33 21.49 0 0 ------

4 Abu Gabra 2740 2757.98 17.98 0 0 ------

5 Abu Gabra 2804.46 2810.64 6.17 5.64 0.914 0.178 0.722 0.083

6 Abu Gabra 2810.64 2817.19 6.55 0 0 ------

7 Abu Gabra 2822.52 2837.46 14.93 0 0 ------

All zones 2686.66 2837.46 77.62 5.72 0.074 0.178 0.724 0.083

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Table (4-7) Manual calculation reservoir summary for Neem k-3.

Zn Zone Name Top Bottom Gross Vsh% ∅ Neutron% ∅ sonic% ∅ density% Sw% NO 1 Abu Gabra 2686.66 2691.92 5.26 13 14.4 14 15 100

2 Abu Gabra 2696.79 2702.02 5.23 17 15 15 15 100

3 Abu Gabra 2715.84 2737.33 21.49 13 18 17.5 17 98.7

4 Abu Gabra 2740 2757.98 17.98 9 18 18 18 96

5 Abu Gabra 2804.46 2810.64 6.17 8 16.8 15 15.15 74

6 Abu Gabra 2810.64 2817.19 6.55 8 15 14.5 15.5 99

7 Abu Gabra 2822.52 2837.46 14.93 7 15 14 14 100

All zones 2686.66 2837.46 77.62 10.71 16.03 15.42 15.66 95.38

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Table (4.8) Reservoir summary of well Neem k-4. Zn No Zone Name Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl

1 Abu Gabra 2539.81 2545.83 6.01 5.09 0.846 0.146 0.804 0.074

2 Abu Gabra 2560.63 2565.87 5.24 2.93 0.559 0.13 0.701 0.099

3 Abu Gabra 2570.19 2573.74 3.55 2.62 0.739 0.119 0.838 0.118

4 Abu Gabra 2581.29 2593.63 12.34 11.33 0.919 0.185 0.984 0.124

5 Abu Gabra 2671.96 2678.13 6.17 5.09 0.825 0.161 0.58 0.069

6 Abu Gabra 2682.14 2688.46 6.32 5.17 0.817 0.143 0.803 0.158

7 Abu Gabra 2691.24 2696.94 5.71 0 0 ------

8 Abu Gabra 2699.41 2717.3 17.89 17.04 0.953 0.163 1 0.076

9 Abu Gabra 2720.38 2741.97 21.59 21.2 0.982 0.186 1 0.081

10 Abu Gabra 2755.08 2766.49 11.41 9.79 0.858 0.178 1 0.118

11 Abu Gabra 3224.62 3229.62 5 1.39 0.278 0.121 0.634 0.215

ALL Zones 2539.81 3229.62 101.22 81.65 0.807 0.168 0.935 0.098

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Table (4.9) Pay summary of well Neem k-4. Zn NO Zone Name Top Bottom Gross Net N/G Phi Sw Vcl

1 Abu Gabra 2539.81 2545.83 6.01 2.78 0.462 0.165 0.713 0.054 2 Abu Gabra 2560.63 2565.87 5.24 2.93 0.559 0.13 0.701 0.099 3 Abu Gabra 2570.19 2573.74 3.55 1.39 0.391 0.129 0.735 0.149 4 Abu Gabra 2581.29 2593.63 12.34 0 0 ------5 Abu Gabra 2671.96 2678.13 6.17 3.55 0.575 0.172 0.441 0.044 6 Abu Gabra 2682.14 2688.46 6.32 2.93 0.463 0.161 0.729 0.17 7 Abu Gabra 2691.24 2696.94 5.71 0 0 ------8 Abu Gabra 2699.41 2717.3 17.89 0 0 ------9 Abu Gabra 2720.38 2741.97 21.59 0 0 ------10 Abu Gabra 2755.08 2766.49 11.41 0 0 ------11 Abu Gabra 3224.62 3229.62 5 1.39 0.278 0.121 0.634 0.215 ALL Zones 2539.81 3229.62 101.22 14.96 0.148 0.152 0.637 0.107

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average clay volume of Abu Gabra formation

18.2 20 18 15.6 16 14 11.2 9.8



1 -

10 2

8 4

VCL VCL

- -

6 Neemk Neemk

Neemk Neemk 2 0 1 2 3 4

Fig (4.16) Average clay volume of Abu Gabra formation.

Average porosity for Abu Gabra formation

17.8 17.7 17.6

17.4 17.4 17.4

17.2 

Phi Phi

- 16.8

16.8 1

- Neemk

16.6 Neemk Neemk

16.4 Neemk

16.2 1 2 3 4

Fig (4.17) Average porosity for Abu Gabra formation.

109

From the summation table for all wells in the study area as well as Neem k-1 the maximum net pay thickness for Abu Gabra formation is 4.01 M and minimum thickness .15 M. the average effective porosity is 16 and average water saturation Is 68 table (5-2) , Neem K-2 the maximum net pay thickness for Abu Gabra formation 9 M and minimum net pay thickness .15M, the average effective porosity is 15.4 and the average water saturation is 70.5 table (5-4) , Neem k-3 maximum net pay thickness for Abu Gabra formation is 5.64 M and minimum zero and average porosity effective 17.8 and average water saturation 72.4, and Neem k-4 the maximum net pay thickness 3.55 M and minimum thickness 1.39 M , and average effective porosity 15 ,average water saturation 64. The most important things they are concluded after evolution for Abu Gabra formation in the study area all hydrocarbons are oil down to and there is no adjacent water containing beds (there is no oil water contact) to get the resistivity of the water Rw which is so important to correctly calculate the hydrocarbon percentage in the Formation, to deal with this problem was used many test well (water and oil) in the study area to make sure and distinguish between them. And support our results by test well (Fig. 4.3), (Fig. 4.4).

110

Fig (4.18) All tracks log for Neem k-3.

111

The previous methods and techniques were applied on the Abu Gabra formation, to come out comprehensive petrophysical evaluation results, for all wells in the study area including parameters interpretation as well as clay volume, porosity and water saturation and determined cutoff for each one of them; which show good match between them indicate good interpretation result from logs, these results display in seen tracks include conventional logs at the first three tracks from the left, and petrophysical interpretation results in the other three tracks Fig (4-15), the petrophysical results start from water saturation in the fourth track (Sw) , total porosity(PHIT) and effective porosity (PHIE) respectively in the fifth track , the sixth track contains the lithology results which involve sand , shale and silt . eventually the petrophysics composite logs and interpreted lithology and raw data displayed in appendix for all wells in this study.

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CHAPTER FIVE CONCLUSION AND RECOMMENDATION 5-1 Conclusion

The petrophysical evolution of Abu Gabra formations, in Neem k sub filed, located in the north part of the eastern flank of Block 4, in the Muglad basin has been carried out .it is hoped that this reaches will serve as guide for future studies on petrophysical evaluations, due to the complex nature of the Neem k field, the petrophysical approach was chosen to assess the reservoir in the study area for four wells. The petrophysical evaluations and brief summary chapters and recommendations from this study can be summarized as following: 1- The data in this study include wire line logs for four wells. 2- The determination of shale volume was achieved using various methods, as well as GR log and density neutron crossplots, and manual calculation to compare between results, the gamma ray indicator to calculate the shale volume of this area, the shale parameter for Abu Gabra formations have been determined statistically using the crossplots and compared with the histogram for all wells, Vsh≤ 50. 3- Porosity can have determined in the both cleaned and Shaly formations using different methods as well as sonic, density and neutron and the combination method like neutron density crossplot, and manual calculation, the porosity obtained from each method excluding shale effect is called the effective porosity, the effective porosity derived from the combination method (neutron-density) was used in the calculations because it gives the most optimum porosity POR ≥ 10. 4- The water saturation was also determined using the Archie formula, Sw ≤ 80.

113

5-2 Recommendations This thesis has only has only considered the petrophysical evaluation of wells in the study area by using logs for better estimate of static reservoir properties, in the future, the following tasks are considered to be important for further development in the area. 1- The new generation wireline logs can be run in the wells and integrated with core data a better robust models. 2- The results should be compared to the results obtained by manual interpretation with output obtained from interpretation by the IP software to get accurate results from the interpretation of wells.

114

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Franz, G., pudlo, D. Urlacher, G. HauBman, U., Boven, A. and Wemmer, K., 1994. The Darfur Dome, western Sudan: the product of a subcontinental mantle plume. Geologische Rundschau, 83, pp. 614-623.

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5-4 Appendix

Fig (5-1) Shows composite for Neem k-1

121

Fig (5-2) Shows composite for Neem k-2

122

Fig (5-3) Shows composite for Neem k-3

123

Fig (5-4) Shows composite for Neem k-4

124