Petrophysical Evaluation and Reservoir Summation of Bentiu

i

الرحيمالله الرحمن بسم Title page

Petrophysical Evaluation and Reservoir

Summation of Bentiu Formation ـــ Hamra East oil

Field, Muglad Basin, Sudan

By:

Amar Adam Ali Ibrahim

B. Sc. (HONORS) Petroleum Geology

University of Dongola (2012)

A dissertation Submitted to the Department of Geophysics in Partial

Fulfillment of the Requirements for the Master Degree of Science in

Exploration Geophysics

Supervised by:

Dr. Mohamed Abd Elhafeiez Ali Elyass

Alneelain University

Faculty of Petroleum and Minerals

Geophysics Department

November, 2018

ii

Petrophysical Evaluation and Reservoir

Summation of Bentiu Formation ـــ Hamra East oil

Field, Muglad Basin, Sudan

By:

Amar Adam Ali Ibrahim

B. Sc. (HONORS) Petroleum Geology

University of Dongola (2012)

A dissertation Submitted to the Department of Geophysics in Partial

Fulfillment of the Requirements for the Master Degree of Science in

Exploration Geophysics

.

November, 2018

Exam Committee:

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

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

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

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

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Abstract

The Muglad Basin is known as one of the largest rift basins in North Africa, and

comprises an important oil field producing areas in the Sudan. The basin is located

in the southwestern part of the Sudan, bounded by the longitudes 27° 00´ and 30°

00 E and the latitudes 6° 00´ and 12° 00´ N.

The present research work integrates an extensive petrophysical evaluation using

interactive Petrophysics (IP) and manual interpretation for four wells within the

Cretaceous – Albian age of Bentiu Formation in Hamra East oil field, Block 2B in

Muglad basin. The work was carried out in order to identify petrophysical

parameters and reservoir characteristics of the Cretaceous oil-bearing sandstone

reservoirs in Bentiu Formation which is the main reservoir in the study area. The

Data used to carry out this study include: wire-line logs (LAS format), base maps,

master log and final well reports, for all wells. The zones of interest range between

1698 m-1900 m depending on the position of the wells and the correlation that were

made to be known as the top and bottom of the formation for each well.

The results showed that the manual interpretation results are compatible with those

obtained from the IP. The petrophysical parameters achieved after calculations in

Bentiu Formation, range as follows: the average of effective porosity (23% - 25%),

clay volume (17-19 %), water saturation (77 - 85.3%), and hydrocarbon saturation

(net pay), (2.14 -21.03) m.

The results also reveal that the average volumes of shale decrease from the

southeastern part of the field towards the northwestern; while the average porosities

and water saturations increase from the Northwestern through the southeastern part

of the study area.

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لخلاصةا

نتاج النفط لإويضم حقولًا مهمة في شمال أفريقيا ، الإنهدامية د بأنه أحد أكبر الأحواضالمجليعُرف حوض

30° 00´و 27°00 ´ في السودان. يقع الحوض في الجزء الجنوبي الغربي من السودان ، ويحده خطي طول

شمال. . 12° 00´و 6° 00´ عرض يوخط شرق

ا شاملاا باستخدام ه كاملي ا بتروفيزيائيا ي ليدوي لأربعة آبار فاوالتفسير (IP) برنامج الــ ذا البحث البحثي تقييما

في حوض (ب 2 مربع )لتكوين بنتيو في حقل نفط حمرا الشرقي ، يالعصر الألب -العصر الطباشيري

حجر الرملي ئص الخزان لخزانات الت البتروفيزيائية وخصا لاامد. تم تنفيذ العمل من أجل تحديد المعالمجل

البيانات تتضمنالخزان الرئيسي في منطقة الدراسة. يعد الطباشيري الحاملة للنفط في تكوين بانتيو الذي

ي وتقارير السجل الرئيس، الخرائط الأساسية (LAS) تنسيقبار المستخدمة لتنفيذ هذه الدراسة: سجلات الأ

الآبار ععلى موق اا عتمادإم 1900 -م 1698تراوح المناطق ذات الًهتمام بين الآبار النهائية لجميع الآبار. ت

.لكل بئر التكوين التي تم إجراؤها لمعرفة أعلى وأسفل مضاهاهوال

ت لامان المعوتتكو .IP أظهرت النتائج أن نتائج التفسير اليدوي متطابقة مع تلك التي تم الحصول عليها من

-٪ 23الفعالة ) المسامية متوسط بعد الحسابات في تشكيل بانتيو ، على النحو التالي:البتروفيزيائية المحققة

، )صافي دفع(٪( ، وتشبع الهيدروكربونات 85.3 - 77٪( ، تشبع الماء ) 19-17٪( ، حجم الطين ) 25

.( م21.03- 2.14)

ا أن متوسط شرقي من الحقل نحو الشمال ن الجزء الجنوبي المينخفض الطينم حجوتكشف النتائج أيضا

الجزء الجنوبي الغربي من بإتجاه الشمال الغربيلمسامية وتشبعات المياه من االغربي. بينما يزداد متوسط

.منطقة الدراسة

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ACKNOWLEDGEMENTS

Several persons have contributed throughout the preparative of this project

and deserve particular thanks.

I Would like to Express my sincere gratitude to my supervisor, Dr. Mohamed

Abd Elhafeiez for accepting to supervise this Research. The completion of this

research was not possible without his support and guidance during the stages of this

study.

The sincere gratitude also goes to the staff of the department of geophysics –

Faculty of Petroleum and minerals at the university of Alneelain for their helping

and encouragements.

Special thanks go to the petrophysist Hassan elmaleih and Abdalzaher

Mohieldeen, (OEPA) for their helping and support during the stages of this research.

Special thanks and gratitude goes to Abu baker Mahgoub El nour, who

offered their free time to help me.

Thanks and appreciation also goes to Dr. Abd Elazeez Mohamed Elameen,

Dr. Mohamed Abdelwahab Mohamed Ali and Dr. Nour Eldeen Hassan Lissan.

I would also like to express my sincere appreciation to my colleagues at master

program batch 4 for their supports.

Also I would like to thanks everybody who had appositive effect in my life.

Last but certainly not least, my sincere thanks and appreciation go to my

Family for their encouragement and unlimited support.

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DEDICATIONS

I dedicate this work

to my father

to my Mother

to the love of my life, my wife Khanssa Fath Elaleem

to my brothers and sisters.

vii

TABLE OF CONTENTS

Contents Pages

Title page .................................................................................................................. i

Abstract ................................................................................................................... iii

iv ..................................................................................................................... الخلاصة

ACKNOWLEDGEMENTS ........................................................................................ v

DEDICATIONS ........................................................................................................ vi

TABLE OF CONTENTS ...................................................................................... vii

LIST OF FIGURES ................................................................................................ xi

LIST OF TABLES ................................................................................................ xiv

LIST OF ABBREVIATION .................................................................................. xv

CHAPTER ONE .................................................................................................... 1

INTRODUCTION ................................................................................................. 1

1.1 Introduction: ....................................................................................................... 1

1.2 Location and Accessibility of the Study area: ................................................... 3

1.3 Physiography: .................................................................................................... 5

1.4 Climate and Vegetation: .................................................................................... 5

1.5 Drainage system:................................................................................................ 6

1.6 Population: ......................................................................................................... 6

1.7 Previous study: ................................................................................................... 7

1.8 Objectives of the Study: ..................................................................................... 8

1.9 The Methodology:.............................................................................................. 9

CHAPTER TWO ................................................................................................. 11

REGIONAL GEOLOGY AND TECTONIC SETTING ................................. 11

2.1 Introduction: ..................................................................................................... 11

2.2 Lithostratigraphy:............................................................................................. 12

2.2.1 Precambrian- Basement complex: ................................................................ 15

2.2.2 Cretaceous Strata: ......................................................................................... 17

viii

2.2.2.1 Sharaf Formation (Neocomian - Barremian): ............................................ 17

2.2.2.2 Abu Gabra Formation (Neocomian-Barremian): ...................................... 17

2.2.2.3 Bentiu Formation (Aptian-Cenomanian): .................................................. 18

2.2.3 Darfur Group: ............................................................................................... 18

2.2.3.1 Aradeiba Formation (Santonian): .............................................................. 19

2.2.3.2 Zarga Formation (Late Santonian): ........................................................... 19

2.2.3.3 Ghazal Formation (Campanian): ............................................................... 19

2.2.3.4 Baraka Formation (Campanian -Mastrichtian): ......................................... 20

2.2.4 Neogene – Quaternary Strata Units: ............................................................. 20

2.2.4.1 Amal Formation (Paleocene): .................................................................... 20

2.2.4.2 Middle and upper Kordofan Group: .......................................................... 21

2.2.5 Quaternary Sediments: .................................................................................. 21

2.3 Tectonic Setting: .............................................................................................. 22

2.3.1 Pre-rifting Phase: .......................................................................................... 22

2.3.2 Rifting Phase: ................................................................................................ 22

2.3.3 The sag phase: ............................................................................................... 26

2.4. Petroleum Geological Elements: .................................................................... 27

2.4.1 Source rock: .................................................................................................. 27

2.4.2 Reservoir Rock: ............................................................................................ 27

2.4.3 Cap Rock (Seal): ........................................................................................... 28

CHAPTER THREE ............................................................................................. 29

METHODS OF INVESTIGATION ................................................................... 29

3.1 Introduction: ..................................................................................................... 29

3.1.1 The Accumulation of Hydrocarbons in Reservoir: ...................................... 30

3.1.2 Calculation of the Hydrocarbon Volume...................................................... 32

3.2 Classification of wireline logs used in Formation Evaluation: ....................... 34

3.2.1 The Nuclear logs ........................................................................................... 35

3.2.2. Natural Gamma Ray (GR) logging .............................................................. 35

3.2.3. The Natural Gamma Ray Spectrometry (NGS) ........................................... 38

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3.2.4 Density Log: ................................................................................................. 39

3.2.5. Neutron Logs: .............................................................................................. 41

3.2.5.1 Compensated Neutron Log (CNL) ............................................................ 43

3.2.5.2 Sidewall Neutron Porosity (SNP) .............................................................. 43

3.2.6 Acoustic (Sonic) Log .................................................................................... 44

3.2.7 Electrical Logs .............................................................................................. 46

3.2.7.1 spontaneous potential (SP) ........................................................................ 46

3.2.7.2 Resistivity Logs ......................................................................................... 48

3.2.7.2.1 Induction logs ......................................................................................... 48

3.2.7.2.2 Latreologs ............................................................................................... 49

3.2.7.2.3 Microresistivity Log: .............................................................................. 50

3.2.8 Auxiliary Logs .............................................................................................. 51

3.2.8.1 Caliper Log ................................................................................................ 51

3.2.8.2 Diameter Log ............................................................................................. 52

3.2.8.3 Temperature Log ....................................................................................... 54

CHAPTER FOUR................................................................................................ 55

THE PETROPHYSICAL EVALUATION ....................................................... 55

4.1 Introduction: ..................................................................................................... 55

4.2 Data Handling and Basic Flow Chart: ............................................................. 55

4.3 Log quality Control (LQC) .............................................................................. 57

4.4 Determination of Formation Temperature ....................................................... 57

4.5 Lithology determination and zoning of reservoirs .......................................... 58

4.6 Reservoir and non-reservoir rock identification .............................................. 60

4.7 Interpretation .................................................................................................... 61

4.7.1 Shale volume Calculation ............................................................................. 61

7.1.2 Single Curve Shale Indicators ...................................................................... 61

4.7.3 Porosity Calculation ...................................................................................... 65

4.7.4 Fluid type determination from water saturation calculation ........................ 69

4.7.5 Hydrocarbon saturation Estimation (net-pay) .............................................. 72

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4.8 Wells Correlation ............................................................................................. 74

4.9 Reservoir zones and Petrophysical Parameters ............................................... 76

4.10 Petrophysical Cutoff Values Determination .................................................. 81

4.10.1 Cut-off Sensitivity Computations ............................................................... 81

4.10.1 .1 Shale Volume and Porosity Sensitivity Cutoffs ..................................... 81

4.10.1.2 Water Saturation and porosity cutoffs ..................................................... 85

4.11 Reservoir summation and Interpretation of Results ...................................... 86

4.12 Discussion of Results ..................................................................................... 91

CHAPTER FIVE ................................................................................................. 93

CONCLUSIONS AND RECOMMENDATIONS ............................................ 93

5.1 Conclusions………………….......................................................................... 93

5.2 Recommendations ............................................................................................ 94

References .............................................................................................................. 95

xi

LIST OF FIGURES

Fig 1. 1: represents SEEBASETM image of the Muglad Basin and its vicinity.. ..... 2

Fig 1. 2: Location map of the study area (Block 2B) in Muglad Basin. ................. 3

Fig 1. 3: Location map of the study area in Muglad Basin showing distribution of

wells. ........................................................................................................................ 4

Fig 1. 4: Schemtic flow Chart presents the interpretation sequence ..................... 10

Fig 2.1: A compiled Tectono-stratigraphic subdivisions of Muglad Basin.. ........ 13

Fig 2.2: Depositional Model showing non-marine environment operative during

filing of Southern Sudan rift basin. ....................................................................... 14

Fig 2.3: Geological map of the Muglad Basin and vicinity. ................................. 16

Fig 2.4: The generalized Muglad Basin structural-stratigraphic cross section. .... 23

Fig 2. 5: Tectonic model of the West and Central African Rift System including

Muglad basin. ......................................................................................................... 24

Fig 3.1: Volume of hydrocarbons in place. ........................................................... 34

Fig 3.2: Diagram of GR log . ................................................................................. 36

Fig 3.3: Example of GR Log. ................................................................................ 37

Fig 3.4: Gamma-Ray values from common lithology. .......................................... 38

Fig 3.5: A density tool. ......................................................................................... 40

Fig 3.6: Compensated neutron tool drawing. ........................................................ 42

Fig 3.7: shows Neutron logging Tool. ................................................................... 43

xii

Fig 3.8: Sonic logging tool . .................................................................................. 45

Fig 3.9: Illustration the principle of the SP log . ................................................... 47

Fig 3.10: Caliper tool showing the positions of caving and swelling in a well,. .. 52

Fig 3.11: Example of presentation of dip log. ....................................................... 53

Fig 4. 1: Schematic flow Chart presents the interpretation sequence. ................. 56

Fig 4. 2: lithology identification from density – neutron cross-plot, for wells Hamra

East -1and Hamra East-2 ....................................................................................... 59

Fig 4. 3: represent reservoir rock and non-reservoir rock in Bentiu formation from

well Hamra East-4 ................................................................................................. 60

Fig 4. 4: minimum and maximum gamma ray histogram of all Zones well (Hamra

East 4) .................................................................................................................... 62

Fig 4. 5: shows the average values of v-shale for four wells in Bentiu formation. 63

Fig 4. 6: Average -shale ‘Vsh’ contour maps of Net reservoir Bentiu formation. 64

Fig 4. 7: log porosity for well Hamra East- 4 ........................................................ 66

Fig 4. 8: show the average values of Porosity for all wells in Bentiu formation. . 67

Fig 4. 9: Average porosity ‘Phi’ contour maps of Net reservoir in Bentiu formation.

................................................................................................................................ 68

Fig 4. 10: distribution of water saturation for all wells in Bentiu formation. ....... 70

Fig 4. 11: Average water saturation ‘Sw’ contour maps for Bentiu Formation. ... 71

Fig 4. 12: percentage of net pay for each well in the study area. ......................... 73

xiii

Fig 4. 13: 3D model showing the hydrocarbon Saturation (Net-pay) distribution for

the studded wells in Bentiu formation. .................................................................. 73

Fig 4. 14: showed wells correlation and profile map. .......................................... 75

Fig 4. 15: top Bentiu Structure Map for Hamra east oil field................................ 76

Fig 4. 16: Petrophysical parameters of well HE-1 zone 1,2 and 3 for Bentiu

Reservoir. ............................................................................................................... 77


reservoir. ................................................................................................................ 78

Fig 4. 18: Petrophysical parameters of well HE-3 zone 1,2 and 3 for Bentiu reservoir

................................................................................................................................ 79


reservoir. ................................................................................................................ 80

Fig 4. 20: shale volume Sensitivity cutoff for all wells ......................................... 82

Fig 4. 21: Porosity Sensitivity cutoff for all wells. ................................................ 83

Fig 4. 22: shale volume and porosity cutoffs verses zones ................................... 84

Fig 4. 23: water saturation and porosity cutoffs verses zones ............................... 85

xiv

LIST OF TABLES

Table 3.1: shows the density log readings of lithology ......................................... 41

Table 3.2: shows common curve names used for the Microresistivity logs ......... 50

Table 4. 1: Bottom hole temperature of the study area……………………………58

Table 4. 2: Water and oil saturation in all of the studied wells. ............................ 72

Table 4. 3: show the depth of Bentiu, top and bottom in the study area ............... 74

Table 4. 4: show Reservoir Summary of well Hamra East-1. ............................... 87

Table 4. 5: show Pay Summary of well Hamra East-1. ......................................... 87

Table 4. 6: Show Reservoir Summary of well Hamra East-2 ............................... 88

Table 4. 7: Show Pay Summary of well Hamra East-2 ......................................... 88

Table 4. 8: Show Reservoir Summary of well Hamra East-3 ............................... 89

Table 4. 9: Show Pay Summary of well Hamra East-3 ......................................... 89

Table 4. 10: Show Reservoir Summary of well Hamra East-4 ............................. 90

Table 4. 11: Show Pay Summary of well Hamra East-4 ....................................... 90

xv

LIST OF ABBREVIATION

NAME ABBREVIATION

Water Saturation Sw

Hydrocarbon Saturation So, Sh

Oil water contact OWC

Gas oil contact GOC

Gas water contact GWC

Measurement/logging while drilling MWD/LWD

The Natural Gamma Ray Spectrometry

(NGS,GR, CGR, SCGR, POTA, POTA, POTA,

POTA, THOR and *GR)

Spontaneous Potential SP

Acoustic or Sonic logs (AC/DT)

Density log (RHOB, RHOZ, DEN, RHO*, PEF and PE)

Neutron Log ( NPHI, TNPH, CN CN,CNC and NPHI)

Deep Laterolog Resistivity DLL, LLD, RLLD

Shallow Laterolog

Resistivity

SLL, LLS, RLLS

Micro normal resistivity MNOR

Micro inverse resistivity MINV

Micro Spherically Focused resistivity MSFL, RXO

Medium Induction log (ILM)

Deep Induction log (ILD).

Water saturation at Flushed zone Sxo

Residual hydrocarbon saturation Shr

Geothermal gradient Gg

Bottom hole temperature BHT

Volume of shale Vsh

Volume of Clay VCL

Effective porosity (PHIE)

Total porosity (PHIT)

1

CHAPTER ONE

INTRODUCTION

1.1 Introduction:

The Muglad Basin is known as one of the largest rift basins in North Africa,

it is bounded approximately by the longitudes 27° 00´ and 30° 00´ E and latitudes

6° 00´and 12° 00´ N (Fig. 1.1), and comprises an important oil fields producing areas

in the Sudan, and its oriented in NW-SE Straddling in Sudan and South Sudan

Republic (Fig. 1.1), which were discovered by Chevron Company and partners in

the early 1970s, and the first discovery was made in 1979. Chevron has acquired

vast amount of geological and geophysical data between 1970 to 1982. These data

include extensive aeromagnetic and gravity surveys 36,040 miles (58,000 km) of

seismic data and 86 wells.

The sedimentary basins of interior Sudan including the Muglad basin which

was characterized by thick non-marine clastic sequence of Late Jurassic Early-

Cretaceous and Neogene age (Schull, 1988).

Muglad Basin is located in southwest Sudan and represents parts of Central Africa

Rift System, which extends from North of Cameron and South Nigeria at the Atlantic

Coast to western and Central Sudan, that extending continues in southeast wards

from south Darfur to the Sudanese Kenyan border and it is trending NW-SE and

occupies an area of about 120000km² (200 km wide and 800 km in length). There is

a huge amount of locally deposited Cretaceous-Tertiary sediments of about 13 km

in thickness in the depocenter of the Basin (Idris, 2001). (Fig. 1.1).

2

Fig 1. 1: represents SEEBASETM image of the Muglad Basin and its vicinity. (after

Blevin et al., 2009).

3

1.2 Location and Accessibility of the Study area:

The study area is named Hamra East field; and located in the southwestern

part of Muglad basin Block 2B. Its approximately bounded by latitudes 9°55'0.72"

and 9°53'16.05"N and longitudes 29°26'12.28" and 29°27'30.24"E. The study area

width is about 2.37 km and length is about 3.22 km, with the total area of about

7.6314 km² (Fig. 1.3 and Fig. 1.4).

Heglig is accessible by Heglig airport and by asphalt roads or railway runs from

Khartoum through Kosti at the White Nile to Muglad. The study area specifically is

accessible from Heglig using unpaved road or season road.

Fig 1. 2: Location map of the study area (Block 2B) in Muglad Basin.

4

Fig 1. 3: Location map of the study area in Muglad Basin showing distribution of wells.

5

1.3 Physiography:

Generally, the Muglad Basin area is a flat plain of low relief surrounded by

hilly metamorphic and igneous terrain of the Nuba mountains in the NE, isolated

Basement and Nubian outcrops in the north and Basement Complex terrain in the

SW. Along the Sudanese and Central Africa Republic border, with the exception of

some isolated sandstone outcrops of Miocene to Pliocene age east of the Muglad

town (El Shafie, 1975), the Muglad area is covered by stabilized sand dunes locally

veneered by silt or clay in the northern part. in the southern and southeastern parts,

the surface sediments tend to be clayey and silty soils commonly referred to as black

cotton soils. Moreover, alluvial and wadis sediments as well as swamp deposits of

the White Nile tributaries border the eastern side of the area.

1.4 Climate and Vegetation:

The following is summarized after (Smith, 1949) and (Harrison and Jackson,

1958). The southern Central Sudan is generally considered to have Savannah-type

climate where the average annual precipitation ranges between 120 and 800 mm.

This Savannah-type climate shows a gradual change from the very humid southern

equatorial climate to the semi-arid northern zone. The majority of the rainfall

happens normally during July, August and September. The annual rainfall is

irregular especially during the last decades when more dry seasons than expected

occurred, causing a regional drought and desertification. The prevailing reaches

approximately 38°C in May and September. In winter (December – March) the

temperatures are lower, around 20° – 25°C. The mean humidity ranges from about

21% in the dry season to an average of 75% during the rainy season. The natural

vegetation ranges from a sparse cover of drought resistant grasses and shrubs in the

arid north through a belt of open woods and grass land in the semi-arid central

region, to thick forests in the well-watered south. Considerable parts of the area are

6

covered by the genus Acacia such as Acacia verek (Hashab) which form one of the

economic resources by producing Gum Arabic; Balanites aegyptiaca (Heglig);

Borassus flabellifer (Daleib palm); Adansomia digita (Tebeldi or the Baobab tree);

Tamarindus indica (Aradeib); as well as Acacia nilotica (Sunut); etc. In the flood

plains, swamps and lagoons of the Sudd area a typical equatorial vegetation is

prevalent.

1.5 Drainage system:

The major water courses in the area are White Nile and its tributaries which

are Bahr El Arab, Bahr El Gazal and Bahr El Zaraf. The White Nile is flowing across

the southern and the eastern parts of the Muglad Basin. The southern part of the

White Nile river is called Bahr El Jabal. The Kordofan and Darfur surface water

drainage systems are mostly seasonal streams. The most significant drainage system

of this kind in the area are Khor Abu Habel and Wadi Khadari. Some of the small

spring-fed streams and of the ephemeral wadi and khors which carry run off, reach

the White Nile or its perennial tributaries. The White Nile and its tributaries are

largely affected by evaporation and infiltration (Mohamed, 2003).

1.6 Population:

The study area is characterized by very low populations but since the area has

started the activity of the oil exploration (especially in 1997, when the Greater Nile

Petroleum Operation Company, GNPOC, consortium was established) the area is

becoming more attractive for the Population, which is well distributed throughout

the area. (Abu Zeid, 2005).

The northern part of the study area is inhabited by the Meseria Tribe, who are cattle

herder nomadic tribe that moves from north to Bahr El Arab their farthest point. In

the south lives the nelotic tribes of Dinka, Sholok and Nower, who depend for their

livelihood on cattle herding and fishing especially during the rainy season, and they

7

live in small groups where water is available (Idris, 2001). The main activity of the

population is animal breeding. However, some people grow sorghum (dura), millet,

cotton, sesame, groundnut, gum Arabic, besides some vegetables and fruits. All

crops are grown depending on episodic rainfalls (Mohamed, 2003). Economically

the area is become richest areas in Sudan due to the oil operation activity (Abass,

2012).

1.7 Previous study:

The Muglad basin has been studied intensively and most of these studies by

oil industry and academic at early time in 1970, this is due to its economic

importance. Most of these workers have investigated and summarized the basic

geology, evolution and structural setting, sequence stratigraphy, biostratigraphy,

lithology and depositional environment of the basin, other studies include production

characteristics, field development and optimization mechanism of the basin. Some

of these studies and contributions are discussed as follows:

Whiteman (1971) reported that the oldest sedimentary strata in the study area are

purple and green argillaceous of the Nawa formation.

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 location of a continental scale transcurrent fault zone named Central

African Shear Zone (CASZ), which is envisioned to link the Sudan basins with

Mesozoic rift basins in chad and Niger.

Vail (1978, 1988) studied and reported the stratigraphy and the regional geology of

Muglad Basin, Schull (1988) gave an excellent account of petroleum geology, oil

discoveries in the area, and the exploration history and operation. He also discussed

the stratigraphy of the basin, and geochemistry as well as the reservoir

characteristics. There are three phases of rifting affecting the stratigraphic column,

8

each of which represent general coarsening upward cycle that began with lacustrine

through shore lake deposit into fluvial deposit. This fluvial lacustrine sequences in

the Central Sudan were subdivided by the means of biostratigraphy into five

palynological zones (Kaska, 1989).

Mann (1989) studied the thick skin and thin skin structural features of the Muglad

rift basin. Norman (1990) studied the tectonic influence in the fold and fault trap of

the Muglad basin. McHargue et al. (1992) studied the tectonostratigraphic of the

Muglad rift basin. Abdullatif (1992) studied the Late Jurassic /Cretaceous strata of

the NW Muglad Basin with respect to the paleoenvironment, thermal analysis and

paleogeography of the area. A’amir (2000) studied the sedimentology of the

Cretaceous outcropping strata along the NE margin of the Muglad rift Basin. Omer

(2016) Studied petrophysical evaluation and reservoir summation of Bentiu

formation–Diffra west area, Muglad basin, Sudan.

1.8 Objectives of the Study:

The current is significant in the petrophysical evaluation for Bentiu formation,

the following objectives were set out to be revealed by suitable methodologies:

1/ To provide a reliable approach for the interpretation and the quantitative

evaluation of the reservoir properties (lithology, porosity, water saturation, fluids

contacts and distribution) of Hamra East oil field, Bentiu formation using single

curve method determination.

2/ Correlation of bottoms and tops of the formation zones interpreted from well logs

data.

3/ To conduct manual interpretation so as to confirm the computer results.

4/ To identify new-multi-target prospect in Bentiu using Archie's

equation.

9

1.9 The Methodology:

To realize the objectives of this study in successful way, the following

materials and information were made available:

1. Wells data includes:

i. Wireline logs of four wells.

ii. The four master logs of the chosen wells.

iii. Four final geological reports.

iv. Location maps.

2. The softwares been used included IP software 3.6 version for interpretation,

surfer13 and petrel 2014.

3. The study was conducted with the procedure shown flow Chart (Fig. 1.5).

10

Fig 1. 4: Schematic flow Chart presents the interpretation sequence

11

CHAPTER TWO

REGIONAL GEOLOGY AND TECTONIC SETTING

2.1 Introduction:

Muglad basin is one of the major basins of the Sudan and considered as the

main components of West and central Africa Rift system (WCARS). It is the largest

oriented NW-SE rift basin, covers at least 120000 km square (200km wide and about

800 km long). The thickness of the Cretaceous-Tertiary sediments accumulated in

the deepest part of the basin equal to more than 13 km. The sedimentary Succession

of the Muglad basin is characterized by thick non marine clastic sequence of Jurassic

– Cretaceous and Neogene age (Schull, 1988). The first depositional cycle (Early

Cretaceous) consists mainly of suboxic organic - rich shale representative the main

lacustrine source beds of the Sharif and Abu Gabra Formations, overlain by medium

– coarse grained sandstones of Bentiu Formation. The second depositional cycle

(Late Cretaceous – Paleocene) Darfur Group, consists of fluvial and deltaic

claystones at the bottom (Aradeiba Formation), thin sandstone beds (Zarga and

Ghazal Formations), thickening toward the top of the section (Baraka Formation)

and overlain by the coarser Amal Formation. The thin intercalating sandstones in the

Darfur Group are the main reservoirs in the Unity field. The Kordofan Group

(Oligocene–Late Eocene), which forms the third depositional cycle, consists of the

largely shaly Nayil and Tendi Formations and terminates in the coarse sandstones of

the Adok Formation. The Miocene –Holocene Zeraf Formation unconformable

overlies the Adok and probably represents fluvial reworking of these earlier deposits

(Mohammed et. al., 2003).

12

The tectonic development of this area can be divided into a pre rifting phase, three

rifting phases and a sag phase. The first rifting phase of the Muglad basin consists

of two formations which are Abu Gabra and Bentiu Formations (Schull, 1988).

The three major episodes of extensional tectonism recognized in the Muglad basin

composed of three depositional cycles related to these episodes, Early Cretaceous Fl

approximately (140-95 Ma); Late Cretaceous F2 (95-65 Ma); and Paleogene F3 (65-

30 Ma). (McHargue et. al., 1992), which is represented in (Fig. 2.1).

From the Exploration results which were showed that the hydrocarbon system in

Paleogene, Neogene Cretaceous periods, and the main hydrocarbon play is the

Cretaceous petroleum system. These petroleum systems have perfect assemblage of

source, reservoir and top seal (Norman, 1990).

2.2 Lithostratigraphy:

Muglad Basin is covered by thick sequence of non-marine sediments, which

vary in age from Cretaceous to Neogene (Idris, 2002).

Correlation and age assignment have been established by palynomorphs

assemblages from which a five part spores’/pollen zonation was created and the

subsurface units have been palynologically defined for Lower, Middle and Upper

Cretaceous as well as Paleogene and Eocene/Oligocene. Lower cretaceous

correlations have been confirmed by presence of ostracodes, and because of scarcity

of Cretaceous- Early Neogene-Paleogene outcrops and inferences made from

seismic data and well control. A seismic stratigraphic analysis technique becomes

useful in predicting stratigraphic facies and constructing depositional models

(Schull, 1988). The depositional environments (alluvial fan, fluvial-braided stream,

fluvial floodplain and lacustrine) are illustrated in (Fig. 2.2).

13

Fig 2.1: A compiled Tectono-stratigraphic subdivisions of Muglad Basin. Numerical

ages are based on Cohen et al., 2013; updated 2015.

14

Fig 2.2: Depositional Model showing non-marine environment operative during

filing of Southern Sudan rift basin (Schull, 1988).

15

2.2.1 Precambrian- Basement complex:

This interval is mainly represented by crystalline basement predominantly

metamorphic rocks with limited igneous intrusions (Fig. 2.3). From the Cambrian to

the Mesozoic, the area was an extensive continental platform which had become

consolidated and stabilized by the end of the Pan-African episode (Schull, 1988). In

subsurface, basement rocks were reached in only few wells. The oldest penetrated

sedimentary rocks are non-marine Jurassic (?), Lower Cretaceous strata of the Sharaf

and Abu Gabra Formations. To reach basement two wells have been drilled on

structurally high blocks over which thick pre-rift section may have been removed

(Schull, 1988).

The basement rocks cropping out at the NE, SW and NW margins of the Muglad

basin, and the term basement complex is closely used in the stratigraphy of Sudan

to include all Precambrian and crystalline rocks found in the country (Vail,1978). In

Nuba Mountains the rocks consist granites, granodiorites, gneisses, micaschists,

metavolcanic and gabbroic rocks, the basement complex rocks of SW Southern

Sudan Republic in Equatorial province consist of various type of gneisses

amphibolite, graphitic schist and marbles (Vail,1978) at the NW margins in Southern

Darfur it consists of gneisses, quartzite.

16

Fig 2.3: Geological map of the Muglad Basin and vicinity (after GRAS, 1981).

17

2.2.2 Cretaceous Strata:

A few Nubian sandstone outcrops exist adjacent to the Muglad block, east and

northeast of the Muglad town. In the subsurface, a thick sequence of Cretaceous

sediment is believed to be time equivalent to much of the Nubian outcrops. Based

on seismic data and well control, Cretaceous sediment has been deposited in the

deepest troughs (Schull, 1988).

Cretaceous-Paleocene sediments reflect two cycles of deposition, each represented

by a coarsening-upward sequence. The first cycle is represented by the Abu Gabra

and Bentiu Formations. The second cycle is represented by the Cretaceous Darfur

Group and the Paleocene Amal Formation (Schull, 1988). This Cretaceous System

Comprises Seven Formations named Sharaf, Abu Gabra, Bentiu, Aradeiba, Zarga,

Ghazal and Baraka.

2.2.2.1 Sharaf Formation (Neocomian - Barremian):

The Sharaf Formation unit originally has been introduced by Schull (1988) to

indicate the early graben - fill clastic sediments derived from the gneissic basement

complex during the early phases of rifting. These sediments are deposited in fluvial

floodplain and lacustrine environments and rest unconformabaly on the basement

rocks (becipFranlab, 2004). However, palynological evidence indicated a

Neocomian-Barremian age (Kaska, 1989).

2.2.2.2 Abu Gabra Formation (Neocomian-Barremian):

The Formation was identified in the majority of well in NW Muglad Basin

complex with thickness ranges between (600-1000 feet). It’s dated palynologically

as Neocomian-Albian, represents the period of greatest lacustrine development, and

consists of several thousand feet of organic-rich lacustrine claystones and shales

interbedded with fine-grained sand and silts the lower boundary of the Abu-Gabra

Formation rests directly on the Basement Complex. The lacustrine claystone and

18

shales of this unit are the primary source rock of the interior basins. Abu Gabra

Formation is estimated to be up to 4500 m thick (Schull, 1988).

Based on spore\pollen assemblage, the Abu Gabra Formation is dated as

Neocomian-Aptian Palynofacies types (dominated by palynomorphs, freshwater

algae and amorphous organic matter) reflect a changing environment from very

near- shore in the lower part to an open lacustrine towards the upper part of the

formation (Awad and Omer, 2011).

2.2.2.3 Bentiu Formation (Aptian-Cenomanian):

The Abu Gabra Formation is unconformabaly overlain by the Bentiu

Formation which is comprises a massive sandstone sequence, the main reservoir

rock) with some thin claystone enter beds. The thin claystone enter beds is similar

to the upper most part of the Abu Gabra Formation (Awad and Omer, 2011). It is

predominantly a sand sequence deposited in alluvial-fluvial flood plain environment.

The regional base level, which was created by the earlier rifting and subsidence, no

longer existed when Bentiu Formation was deposited. These thick sandstone

sequences were deposited in braided and meandering streams. These units form up

to 1550 m thick and typically show good reservoir rocks of the Heglig area (Schull,

1988).

2.2.3 Darfur Group:

The Turonian-Late Santonian period was characterized by a cycle of fine to

coarse-grained deposition, which is represent the second rift phase. The lower part

of the group, Aradeiba and Zarga formations are characterized by the predominance

of claystone, shale, and siltstone. Floodplain and lacustrine deposits were

widespread. The low organic carbon content indicates deposition in shallow and

well-oxygenated water. Although this unit offers little source potential to date, it

may develop an organic-rich facies in areas not yet drilled. Throughout the basin,

the Aradeiba and Zarga formations are an important seal (Schull, 1988).

19

The Cretaceous ended with the deposition of increasingly coarser grained sediment,

reflected in the higher sand percentage of the Ghazal and Baraka formations. These

units were deposited in sand-rich fluvial and alluvial fan environments. The Ghazal

Formation is also an important reservoir unit in Unity field. The Darfur Group is up

to 3200 m thick (Schull, 1988).

2.2.3.1 Aradeiba Formation (Santonian):

This is the oldest unit of the Darfur Group; this lithostratigraphic unit is

separated from the underlying Upper Bentiu Formation by a basin-wide

unconformity.

Core data analysis suggests deposition in a fluvial channel complex and possibly

deltaic distributary channels and the upper part of Aradeiba formation consists of

stable lacustrine/ floodplain shale (Abbas, 2012). The coarsening upward succession

of cross-bedded to massive sandstones with finer-grained sands and silts are likely

to represent a sequence of distributary mouth bars and sand bar deposits. The

mudstones and siltstones possibly represent pro-delta or overbank deposits.

2.2.3.2 Zarga Formation (Late Santonian):

The second unit in the Darfur Group is the Zarga Formation which consists of

interbedded sequences of mudstones, sandstones and siltstone, which becomes more

argillaceous towards the basin center. The formation has been identified in all wells

of southeast Muglad Basin, particularly in the Unity and Heglig Fields with variable

thickness ranging between (50-315 m, RRI and GRAS, 1991). Similar to the

Aradeiba Formation, the Zarga Formation was deposited in a lacustrine environment

with fluvial-deltaic channels (RRI and GRAS, 1991).

2.2.3.3 Ghazal Formation (Campanian):

This unit characterized by high percentage of sand which is moderately

heterogeneous due to interbedded shale intervals throughout the reservoir. The

lithological composition and Palynofacies association of the Ghazal Formation are

20

similar to that of the Zarga Formation, but its thicker sand indicates deposition in

braided streams. The upper part of the formation has relatively lesser sands content

assuming a fining-upward sequences buildup of Para sequences, each of which starts

with scour surface and lag deposits characteristic of meandering streams (Awad and

et. al. 2015).

2.2.3.4 Baraka Formation (Campanian -Mastrichtian):

Baraka Formation is the topmost unit of the Darfur Group which consists of

sands and sandstones with thinly interbedded silty claystones. The sandstones are

dominantly fine- to coarse grained and occasionally very coarse-grained. Unlike the

other members of the Darfur group, the Baraka Formation does not contribute to the

reservoir zones in the Unity and Heglig Fields, due to the absence of adequate sealing

(RRI and GRAS, 1991).

2.2.4 Neogene – Quaternary Strata Units:

Strata of this age are assigned to the lowermost units within the Kordofan

Group and Amal Formations.

The Neogene is represented by sequences of unconsolidated sands, gravels, silts, and

clays deposited in alluvial, fluvial, and shallow lacustrine environments (Vail, 1978).

The initial deposits of the Tertiary were medium to coarse-grained clastic, followed

by a single cycle of fine to coarse-grained sedimentation associated with the final

rifting phase. Tertiary is up to 3450 m thick (Schull, 1988).

2.2.4.1 Amal Formation (Paleocene):

Amal Formation consists of medium to coarse - grained massive sandstones.

Palynofacies association consists of abundant dark structured organic matter

reflecting deposition in high energy near shore settings (Awad and Omer, 2011). The

massive sandstones of the Paleocene, which are up to 2, 500 ft, (762 m) thick, are

composed dominantly of medium to coarse -grained quartz arenites. This Formation

represents high energy deposition in a regionally extensive alluvial-plain

21

environment with coalescing braided streams and alluvial fans. These sandstones are

potentially excellent reservoir (Schull, 1988).

2.2.4.2 Middle and upper Kordofan Group:

These sediments are representing by coarsening-upward depositional cycle

that occurred from the Late Eocene to middle Miocene. The lower part of this cycle,

were known by the Nayil and Tendi formations, are characterized by fine-grained

sediment related to the final rifting phase. The deposits represent an extensive

fluvial-floodplain and lacustrine environment. They offer excellent potential as a

seal overlying the massive sandstone of the Amal Formation (Schull, 1988). This

unit is generally characterized by inter bedded sandstone and claystone with an

increasing sand content. The fluvial-floodplain and limited lacustrine environments

gave way to the increasing alluvial input reflected in the sand-rich braided streams

and fan deposits of the Adok and Zeraf formations. An exception occurs in the area

of the suddenly swamp where approximately 2000 ft (610 m) of Late Tertiary

claystone were deposit (Schull, 1988).

2.2.5 Quaternary Sediments:

The interval comprises the Zeraf and the Umm Ruwaba Formations, Zeraf

formation consists of massive sands, predominantly coarse to very coarse-grained.

The age of this unit was inferred from its stratigraphic position above the well-dated

Adok Formation. Palynological recovery from this interval is very poor; however,

the majority of palynomaceral are abundant palynomorphs, structure less organic

matter and Botryococcus Sp. which indicates lacustrine environment (Awad and

Omer, 2011). These are unconsolidated sands, clayey sands and black clays, which

vary considerably in thickness. Black clays vary in thickness from a few centimeters

to over 10 meters and conformably overlie the Umm Ruwaba Formation. Wind-

blown sand deposits (Qoz), are widely spread in the northwestern part of the Muglad

Basin. Fluvial deposits are found along the major drainage systems and are generally

22

composed of sandy and clayey sediments, which sometimes form shallow aquifers.

The weathering products along the western side of the Nuba Mountains form narrow

bands of washed out debris deposits around the hills (Vail, 1978).

Superficial deposit is unconsolidated sands, clayey sands and black clays, which

vary considerably in thickness. Black clays vary in thickness from a few centimeters

to over 10 meters and conformably overlie the Umm Ruwaba Formation.

2.3 Tectonic Setting:

The Muglad basin is bisected by major sub-basins, which superimposed on

the earlier Lower Cretaceous to early Neogene sediments. It was formed by regional

rifting and divided into one pre-rifting phase and three rifting phases. Rift activity

has continued through to present time. This evolutionary sequence is well

documented by geophysical data, well information and regional geology (Schull,

1988).

2.3.1 Pre-rifting Phase:

By the end of the Pan-African orogeny (550 ±100 Ma), the region had become

a consolidated platform. During the remainder of the Paleozoic and up to the Late

Jurassic, this platform was the site of alkaline magmatism probably caused by a long

lived mantle plume (Vail 1978). The general lack of lithic fragments in the oldest

rift sediments further suggests that no significant amount of sedimentary section

existed in the area prior to rifting (Schull, 1988).

2.3.2 Rifting Phase:

The distinct periods of rifting have occurred in response to crustal extension

(Fig. 2.4), which provided the isostatic mechanism for subsidence (Browne and

Fairhead, 1983). The subsidence was accomplished by normal faulting parallel and

Sub-parallel to basin axes and margins.

23

Fig 2.4: The generalized Muglad Basin structural-stratigraphic cross section (after

Schull, 1988).

Rifting is thought to have begun during Jurassic (?) to Early Cretaceous time (130 –

160 Ma). Three distinct periods of rifting have occurred in response to crustal

extension, which provided the isostatic mechanism for subsidence. Subsidence was

accomplished by normal faulting parallel and subparallel to the basinal axes and

margins (Browne and Fairhead 1983; Schull 1988). These three rifting phases can

be described as follows:

The primary rifting phase had begun in the Jurassic (?) – Early Cretaceous and

continued until near the end of the Albian, simultaneously with the initial opening

of the South Atlantic and the subsequent extension at the Benue Trough (Fig. 2.5).

Consequently, several African rifts and troughs such as Benue, East Niger,

Ngaoundere and Anza began to develop. Some basins developed within and in the

immediate vicinity of the Cretaceous shear zones in the period from 120 – 90 Ma,

24

Fig 2. 5: Tectonic model of the West and Central African Rift System including

Muglad basin (After Fairhead, 1988).

due to shear movements. Moreover, Fairhead (1988) suggested that the movements

of the Central African Shear Zone were translated into the extensional basins of the

Sudan interior. However, no volcanism is known to be associated with this early

rifting phase in Sudan. The termination of the initial rifting is stratigraphically

25

marked by the basin wide deposition of thick sandstones of the Bentiu Formation

(Schull 1988). The second rifting phase occurred during the Turonian – Late

Senonian. Stratigraphically, this phase is documented in the widespread deposition

of lacustrine and floodplain claystones and siltstones, which abruptly terminated the

deposition of the Bentiu Formation (Schull 1988). Furthermore, Fairhead (1988)

concluded that changes in the opening of the Southern Atlantic account for the Late

Cretaceous period of shear movement in the West and Central African Rift System.

These tectonic effects came as compressional stresses at the Benue area and as a

dextral reactivation along the Central African Fault Zone during the Late Cretaceous

time, and hence, gave rise to the second rifting phase. In the ENE– WSW trending

Baggara Basin, a continuation of (CAFZ) movement has been inferred from the

compressional stresses in the seismic data, which is not proven in the adjacent NW

Muglad Basin. Further to the SE, the trend appeared to have been terminated and

replaced by the NW–SE trending basins, which are extensional in their development.

In contrast to the primary rifting phase, this rifting phase was accompanied by minor

volcanism. In wells, this phase is represented by a 300 ft. (91 m) dolerite sill in the

northwest Muglad Basin, dated (82 ±8 Ma) and a Senonian andesitic tuff in the

central Melut Basin (Schull,1988). These occurrences fit well with the approximate

90 Ma date cited as one of two periods of Mesozoic (?) igneous activity in central

and northern Sudan (Vail, 1978). The end of this phase is marked by the deposition

of an increasingly sand-rich sequence which ended with the Paleocene sandstone of

the Amal Formation (Schull, 1988).

The final rifting phase began in the Late Eocene – Oligocene. The initiation of this

phase was occurring simultaneously with the initial opening of the Red Sea (Lowell

and Genik 1972). This final phase is reflected in the sediments by a thick sequence

of lacustrine and floodplain claystones and siltstones. The only evidence of

26

volcanism in wells is the occurrence of thin Eocene basalt flows in the southern

Melut Basin near Ethiopia (Schull 1988). However, (Vail, 1971) pointed out that the

age dating of the widely scattered volcanic outcrops in Sudan indicates occurrence

of similar age volcanism. After this period of rifting throughout the Late Oligocene

– Miocene, deposition became more sand-rich (Schull,1988).

2.3.3 The sag phase:

In the Middle Miocene, the basinal areas entered an intra cratonic sag phase

of very gentle subsidence accompanied by little or no faulting subsidence. This intra

cratonic sag phase was identified at first time by Schull (1988). Limited outcrops of

the volcanic rocks in the area southeast of the Muglad Basin, which were been dated

as 5.6 ± 0.6 Ma and 2.7 ± 0.8 Ma, indicate that minor volcanism occurred locally.

During that time the sedimentation in the Central and Southern Sudan Interior Rift

Basins was essentially controlled by subsidence due to differential compaction of

sediments. In Muglad and Melut Basins the Eocene-Oligocene sedimentation has

continued across the Oligocene/Miocene boundary with the deposition of basin wide

fluvial and floodplain sediments of the upper members of the Kordofan Group. Also

in northern Sudan, the basin evolution started with the formation of intra cratonal

rift basins and was followed by sag phase. In the sag phase, sedimentation was

dominated by fluvial systems (Bussert, 2002 a). Basically, there are two regions of

deep sedimentary basins identified in Sudan. The first one are the well-known rift

basins (South and Central Sudan), where oil was already produced in some basins

and the other region is northwest Sudan basins was already discovered. Based on

seismic data and well control, the southern Sudan sedimentary basins (Muglad and

Melut basins) are characterized by thick continental clastic sequences of Jurassic,

Cretaceous and Tertiary age (Schull, 1988; Wycisk et al., 1990). Over 13,716 m of

sediments was deposited in the deepest trough and extensive basinal areas are

27

underlain by more than 6,096 m of sedimentary rocks. In the rift basins all

sedimentary rocks penetrated are of continental origin.

2.4. Petroleum Geological Elements:

2.4.1 Source rock:

The source rocks of the Muglad basin are organic-rich shale of Abu Gabra

Formation that was deposit in stratified lake during Neocomian to Barremian time.

In some parts of the basin the Barrera in Sharaf formation has also been found to

contain some source intervals appreciable volumes. Total organic carbon in the

penetrated Abu Gabra section averages 1.3 but exceeds 7 in places in the north

western part of the basin.

Abu Gabra Formation is one of the main source rocks characterized by the rich

lacustrine clay stones and shales that were deposited with inter bedded fine grained

sands and silts, besides Baraka, Nayil and Tendi formations (Schull, 1988). The

regional Muglad structural-stratigraphic cross section indicates the position of these

claystones and shale as well as Turonian-Late Senonian and Late Eocene-Oligocene

intervals (Schull, 1988).

The depositional environment of the thickest oil-prone source claystone and shales

was within large lakes distal from the primary clastic influx within these area sub-

material deposits on the lake bottom (Schull, 1988).

2.4.2 Reservoir Rock:

The reservoir rocks are defined as a porous and permeable rock capable of

bearing commercial accumulation of oil and gas. Reservoir rocks are commonly

coarse-grained sandstones, but they can also be fractured fine-grained rocks (shales,

limestones, dolomites). These reservoir rocks range from quartz arenites and

wackestones, to arkosic arenites and wackestones. Generally, the better reservoirs

were deposited in the more proximal alluvial and fluvial environments. The more

distal lacustrine environment generally lacked the energy necessary to rework and

28

clean up the potential reservoir sands (Schull,1988). Typically, sandstone of the

Bentiu Formation is the primary reservoir of the Muglad basin, and the Ghazal

Formation is also an important reservoir, and the sandstone of the Amal Formation

is potentially excellent reservoirs (Schull,1988). Bentiu Formation is the main

reservoir in the region which is sandstones sequence were deposited in braided and

on meandering streams, and Ghazal Formation is also an important reservoir, and

the sandstone of Amal Formation are potentially excellent reservoirs (Schull, 1988).

Most of the unity reservoir sandstone generally is characterized by good porosity

and permeability. Porosity of these reservoirs is range from (8 -38) with average

equal to 27 where permeability’s range from (40 to over 10.000 md), averaging 1600

md. These sandstones, exhibit good reservoir quality at depth where the typical

Cretaceous reservoirs are unattractive. The following conclusion can be drawn from

the reservoir data compiled from the study of 3,200 ft. (975 m) of conventional core

taken from 30 wells (Schull, 1988).

2.4.3 Cap Rock (Seal):

Most seals in the Muglad Basin are intra formational shales interbedded with

the reservoirs. Major Cretaceous seals are shales of the Abu Gabra, Bentiu,

Aradeiba, Zarga and Ghazal formations, with minor intra formational seals in the

Tendi Formation. Eocene shales of the Nayil Formation may form local seals.

29

CHAPTER THREE

METHODS OF INVESTIGATION

3.1 Introduction:

The wireline logging tools and interpretive methods are developing in

accuracy and sophistication, they are playing an expanded role in the geological

decision-making process. In present day, the petrophysical log interpretation is one

of the most useful and important tools available for petroleum geologist

Their traditional use of logs in exploration is to correlate zones, in addition to

their basic role in assisting the preparation of structural and isopach mapping, it helps

to define the physical rock characteristics such as lithology, porosity, pore geometry,

and the permeability. Logging data is used to: (1) identify productive zones within

the Formation, (2) to determine depth and thickness of zones, (3) to distinguish

between oil, gas, or water, in reservoir. and (4) to estimate hydrocarbon reserves.

The geologic maps developed from log interpretation help the determination of

facies relationships and drilling locations. There are many types of logs frequently

used in hydrocarbon exploration. They are called (open hole logs) with such name

applied because these logs are conducted in the uncased portion of the well bore.

(Asquith,1982).

The two basic parameters determined from well log measurements are

porosity, and the fraction of pore space filled with hydrocarbon. The parameters of

log interpretation are determined both directly or inferred indirectly. They are

interpreted from one of three general types of logs (1) electrical, and (2) nuclear, and

(3) acoustic or sonic., The names refer to the sources used to obtain the

measurements. The different sources create records (logs) which contain one or more

30

curves related to some property in the rock surrounding the well bore

(Asquith,1982).

3.1.1 The Accumulation of Hydrocarbons in Reservoir:

To interpret the conditions allowing the accumulation of hydrocarbons in a

reservoir, it essential to understand the geological processes leading to the

accumulation. It is understood that oil and gas reservoirs have come into being over

large periods of time, and that the hydrocarbon formed from rich organic remains

which may have migrated into the reservoir rocks, and then have been trapped there

by overlying rock formations with very low permeability. Hence, for the existence

of hydrocarbon reservoir, we need the following conditions to be available at the

same location:

1/ Mature and organic-rich source rocks.

2/ Suitable pressure & temperature to convert the organic-rich into oil and gas.

3/ Porous and permeable reservoir rocks to store the accumulated oil and gas.

4/ System of retention composed of trap and seal, to prevent oil and gas from leaking

away.

5/ Suitable trap to keep the hydrocarbons in the reservoir rock until to exploit it.

These processes take extremely long periods of time. Formations that contain

reservoirs are sedimentary rocks, where the deposition of organically rich material

has been followed by clean sandstones that form high porosity well connected pore

systems, and are subsequently capped by shales with very low permeability. Here

the burial of the deposition provides the pressures and temperatures to produce

hydrocarbons (Glover, 2000). The hydrocarbons are less dense than water, so they

migrate upwards into the sandstone, replacing the water that originally occupied the

reservoir sandstone, where the hydrocarbons are constrained from rising further by

the shale cap.

31

The depositional and post-depositional history of the reservoir rock, and particularly

the diagenetic history (compaction, cementation, and dissolution), all contribute to

the mineralogical composition of the rock, and hence its grain size distribution,

porosity, pore distribution, size and the connectivity. It has been noticed that in the

process of migration the hydrocarbon replaces water in the reservoir rock because it

is less dense than water. In practice, the replacement is almost never complete, with

some water associated with even the best oil accumulations. The reason for the

remaining water is that the grains comprising the reservoir rock are usually water-

wet, i.e., having a chemical preference to be covered in water rather than

hydrocarbon, hence they retain a thin film of water when the hydrocarbon replaces

most of the water in the pores. Oil-wet rocks do exist, and the ability to distinguish

between oil and water wet rocks is extremely important in reservoir management,

especially in the final stages of reservoir production.

In any given reservoir rock, the pore space will be occupied by a water

saturation (Sw), a gas saturation (Sg), and an oil saturation (So), the gas is less

density than oil, which is less density than water, the fluids separate in hydrocarbon

reservoirs with the gas occurring just below the trapping lithology, oil a little deeper,

and water at the bottom. The fluids are commonly immiscible and so we can define

a gas-oil contact (GOC) and an oil-water contact (OWC). Since, the gravity is the

force that separates the fluids into these layers, the GOC and OWC are horizontal

providing that horizontal and vertical permeability is good in the reservoir and there

are no complicating structures or fractures. Note that it is not compulsory to have all

three fluids occurring together. Hence in gas reservoirs, the oil is missing and there

is a gas-water contact (GWC). Similarly, oil reservoirs can exist without a gas cap

(Glover, 2000).

32

3.1.2 Calculation of the Hydrocarbon Volume

We can define a reservoir rock as porous and permeable rock capable of

bearing commercial accumulation of oil and gas. Reservoir rocks are commonly

coarse-grained sandstones, but they can also be fractured fine-grained rocks (shales,

limestones, dolomites) that allows the extraction of significant amount of

hydrocarbon. A non-reservoir rock may have a porosity that is too low, a

permeability that is too low or zero hydrocarbon saturation. The major control is

often the basic lithology. For example, shales often contain hydrocarbon with high

saturations, but have porosities and permeability that are much too low for the

hydrocarbon to be extractable. Therefore, shales are considered to be non-reservoir

rock. In contrast a high porosity, high permeability sandstone could be a reservoir

rock providing that the hydrocarbon saturations are sufficiently high, i.e, above the

oil water contact.

The calculation of hydrocarbon volume requires us to know the volume of the

formations containing the hydrocarbons, the porosity of each formation, and the

hydrocarbon saturation in each formation. In practice each reservoir will be made up

of a number of zones each with its own thickness, areal extent, porosity and

hydrocarbon saturation. For example, reservoir sandstones may alternate with non-

reservoir shales, such that each zone is partitioned. Such zonation is mainly

controlled by lithology. Hence, it is an early requirement to identify the lithology’s

in a particular well, identify which formations have the required porosity to enable

it to be a reservoir rock, and determine the formation contains hydrocarbons.

Reservoir rocks containing hydrocarbons are allocated a zone code.

The volume of reservoir rock in a single zone depends upon the area of the zone A,

and the thickness of reservoir rock in the zone h. The area is obtained usually from

seismic data (from the reservoir geologist), and is the only data used in the

33

calculation of hydrocarbon volumes in place that is not derived from petrophysical

techniques. The thickness of reservoir rock is derived from the zonation of the

reservoir based upon an initial lithological interpretation and zonation of the

reservoir from the wireline logs. The bulk volume of the reservoir VBulk = A × h

The majority of this volume is occupies by the solid rock matrix, and the remainder

is made up of the pore space between the minerals. The relative amount of pore space

to the bulk volume is denoted by the porosity ɸ = Vpore/VBulk . However, note that

the fractional form is used in ALL calculation. The pore volume in any given zone

is therefore Vpore = ɸ × A × h.

In general, the porosity is completely occupied by either water and

hydrocarbon, where the saturation of the water is Sw, and that of the hydrocarbon is

Sh, and Sw + Sh = 1. In most reservoirs the hydrocarbon has replaced all the water

that it is possible to replace, and under these conditions the water saturation is termed

the irreducible water saturation Swi. Now we can write the hydrocarbon saturation

as Sh = (1 − Sw). Hence the volume of hydrocarbons in place can be calculated as

follow:

Vh = Ahϕ (1 − Sw) (3.1)

The determination of Vh shale value is the primary job for the petrophysicist,

which is required to assess a lithological and reservoir zonation, in addition at a

later stage the petrophysicist may also be called to assess the permeability of the

reservoir under various conditions. However, the primary function of the

petrophysicist is to assess the amount of hydrocarbons initially in place.

All the parameters in Eq. (3.1) except the area derived from measurements made in

the borehole using wireline tools or increasingly using data obtained from tools that

measured the rock formations during drilling (measurement/logging while drilling:

34

MWD/LWD). So the (Fig. 3.1) illustrates the derivation of Eq ⋅ (3.1)

diagrammatically.

Fig 3.1: Volume of hydrocarbons in place.

3.2 Classification of wireline logs used in Formation Evaluation:

Wireline logs can be classified based on either the principles of operations of

logging tools or their usage i.e. measurable physical parameters and deductions that

can be made from them (Serra, 1984).

Classification based on operational principles:

I. Electrical logs: Spontaneous Potential (SP) and Resistivity logs.

II. Nuclear or Radioactive logs: Gamma-Ray (GR), Density and Neutron logs.

III. Acoustic logs: Sonic (DT) logs.

Classification based on their usage:

I. Porosity logs: Sonic (DT), Density (RHOB) and Neutron (NPHI) logs.

II. Lithology logs: Gamma-Ray (GR) and Spontaneous Potential (SP) logs

35

III. Resistivity logs: Induction (ILD), Latreologs (LLS, LLD), Microresistivity

(MSFL) logs.

IV. Auxiliary logs: Caliper (CALI), Diameter etc.

3.2.1 The Nuclear logs

The Nuclear logs record radioactivity that may be either naturally emitted or

induced by particle bombardment. Radioactive materials emit alpha, beta and

gamma radiation. Only the gamma radiation has sufficient penetrating power to be

used in well logging. Neutrons are used to excite atoms by bombardment in the well

logging. They have high penetrating power and are only significantly absorbed by

hydrogen atoms. The hydrogen atoms in formation fluids are very effective in

slowing neutrons and thus tend to be an important property in well logging.

The basic nuclear logs that will be discussed briefly in the following section:

Natural Gamma-Ray (GR) logging

The Natural Gamma Ray Spectrometry (NGS)

Formation Density log (RHOB)

Compensated Neutron log (CNL)

Sidewall Neutron Porosity log (SNP)

3.2.2. Natural Gamma Ray (GR) logging

The gamma log measures the natural radiation of the formation, which is due

to the disintegration of nuclei in the subsurface. Potassium, Thorium, and Uranium

are the major decay series that contribute to natural radiation. These elements tend

to be concentrated in shales, and are present in feldspars and micas that occur in

many sandstone reservoirs.

The gamma-ray log is based on this naturally occurring radiation. The units are

American Petroleum Institute (API). Clean sands have fairly low levels of ˂45 API

and Shale has high gamma ray reading ˃ 75 API. The measurements are used to

36

calculate the amount of shale as a function of depth and vertical resolution of the

tool is approximately 0.6 m with a depth of investigation of 0.15-0.3 m depending

on the density of the rock. The gamma ray log is used for basic lithology analysis

Quantitative estimation of clay content, correlation of formations, and the depth

matching of multiple tool runs.

The simple gamma ray log is usually recorded in track one and scales chosen locally,

but 0-100 and 0-150 or 0-250 Which is illustrated in (Fig. 3.3) API are common. A

deflection of GR log to the right indicates shales, where the maximum and constant

recorded radioactivity to the right shows shale line. A deflection to the left indicates

sandstone, where the maximum and constant recorded radioactivity to the left shows

sandstone line as indicated in (Fig. 3.2). The scintillation counter detects total

disintegration from sources in the radial region close to the hole. These scintillation

detectors use a sodium iodide crystal by gamma rays.

Fig 3.2: Diagram of GR log (Modified after Russell, 1941).

37

Fig 3.3: Example of GR Log.

No formation is perfectly clean; hence the GR readings will vary. Limestone is

usually cleaner than the other two reservoir rocks (sandstone and Dolomite) and

normally has a lower Gamma ray. Anhydrite and salt are normally very clean, and

have very low values (Fig. 3.4) represent gamma reading in common lithology.

Gamma ray log is very useful in computation of the amount of shale:

The minimum value gives the clean (100%) shale free zone, the maximum 100%

shale zone. All other points can then be calibrated in the amount of shale by the following formula

(schlumberger,1974).

IGR = Vsh = 𝐺RLog − 𝐺Rmax

GRshale − GRmin (3.2)

38

Where the IGR is gamma ray index, Vsh is the amount of shale content, GRlog

is the gamma-ray reading from the log, GRmax is the maximum gamma-ray

reading, and GRmin it is the minimum gamma-ray reading.

Some Code/Name that has been used in wireline logging: (GR, CGR, SCGR,

POTA, POTA, POTA, POTA, THOR and *GR).

Fig 3.4: Gamma-Ray values from common lithology.

3.2.3. The Natural Gamma Ray Spectrometry (NGS)

Unlike the GR log, which measures only the total radioactivity, this log

measures both the number of gamma rays and the energy level of each and permits

the determination of the concentrations of radioactive potassium, thorium and

uranium in the formation rocks.

39

3.2.4 Density Log:

The density log is a continuous record of a formation’s bulk density. This is

the overall density of a rock including the density of minerals (solid matrix) and the

volume of free fluid enclosed in the pores (porosity).

Quantitatively, the density log is used to calculate porosity and indirectly,

hydrocarbon density. Qualitatively, it is a useful lithology indicator (combined with

Neutron logs); it can be used to identify certain minerals and may help to identify

overpressure and fracture porosity.

logging technique of the density tool is to subject the formation to a bombardment

of medium-high collimated (focused) gamma rays, and to measure their attenuation

due to their backscattering and absorption by the materials in the formation, between

the tool source and detectors. The rate of absorption and the intensity of the

backscattered rays depend on the number of electrons (electron density) that the

formation contains, which in turn is closely related to the common density of the

materials. Dense materials have more electrons per unit-volume (electrons/cm3),

with which the gamma particles can collide and loose energy. Hence, higher energy

is absorbed in dense formations. In light materials with lower electron density, more

gamma particles reach the detectors and are converted directly to bulk density for

the log printout. However, although electron density as detected by the tool and real

density are almost identical, there are differences when water (hydrogen) is

involved. For this reason, the values presented on the density log are transformed to

give actual values of calcite (2.71g/cm3) and pure water (1.00g/cm3).

40

Fig 3.5: A density tool (After Rider, 1996).

An illustration of a density tool is provided in Fig 3.5 above. It consists of a

collimated gamma-ray source and two detectors (near and far) which allow

compensation for borehole effects when their readings are combined and

compared.

We can easily calculate the porosity of the formation from density tool it has high

accuracy and exhibits small borehole effects. The major uses are in the determination

of porosity as given below:

Determination of porosity (ɸ) , ɸ = ρma – ρb / ρma – ρf (3.3)

41

ρb is the bulk density as measured by the logging tool, the two other inputs into the

porosity, ρma and ρf is the matrix density and fluid density consequently and the fluid

density is normally that of the mud filtrate. table (3.1) showed the density log

readings in common lithology.

The other uses of the density log are:

Lithology (in combination with the neutron tool)

Mechanical properties (in combination with the sonic tool)

Acoustic properties (in combination with the sonic tool)

Gas identification (in combination with the neutron tool)

Code/Name :( RHOB, RHOZ, DEN, RHO*, PEF and PE).

Table 3.1: shows the density log readings of lithology (after shlumberger,1972)

3.2.5. Neutron Logs:

The Neutron log was introduced commercially by Well Surveys Incorporated

two years after the gamma ray log. Gus Archie working for Shell used the neutron

porosity log in his equation (Archie,1942).

The neutron log is a measurement of induced formation radiation produced by

fast moving neutrons bombarding the formation. It is an indication to formation

richness in hydrogen. A high neutron count rate indicates low porosity, while low

neutron count rate indicates high porosity.

Lithology Reading (g/cm3)

Limestone 2.71

Sand stone 2.65

Dolomite 2.85

Anhydrite 2.98

Salt 2.03

Shale 2.2-2.7

Coal 1.5

42

The principal uses of a neutron log are to measure porosity and to discriminate oil

from gas saturations (the porosity will appear very low when gas is measured). It is

a very good porosity indicator in limestones (Fig. 3.6.B), and can be used to identify

gross lithology, evaporites, hydrated minerals and volcanic rocks. When combined

with a density log, it is one of the best subsurface lithology indicators available.

The source (Fig. 3.5) used to produce neutrons is usually a mixture of Beryllium and

Radium. As Radium decays, it emits alpha particles. The Beryllium responds to

these alpha particles by emitting high energy neutrons through the formation. This

energy will be slowed down by collisions with Hydrogen atoms, because of their

masses approximately equal. The schematic trajectories of a neutron in a limestone

with no hence (Fig. 3.6), the distribution of the neutrons at the time of detection is

primarily determined by the Hydrogen concentration.

Fig 3.6: Compensated neutron tool drawing.

43

Neutron log responses vary, depending on: the difference in detector types (Thermal,

epithermal, and gamma-ray), spacing between source and detector (Near or far), and

lithology (sandstone, limestone, and dolomites).

Fig 3.7: shows Neutron logging Tool.

3.2.5.1 Compensated Neutron Log (CNL)

The compensated Neutron log (CNL) tool has two detector spacing and is

sensitive to slow neutrons. The tool detects thermal neutrons. The logs can be run in

open and cased hole.

3.2.5.2 Sidewall Neutron Porosity (SNP)

The sidewall neutron porosity tools are a single detector pad tool that detect

part slowed epithermal neutrons. All neutron tools be run in cased holes to determine

formation porosity. Corrections must be made for the presence of casing and cement.

Principal uses of the Neutron logs are listed below:

Porosity display directly on the log.

Lithology determination in combination with Density and Sonic logs.

44

Gas indication in combination with Density log.

Clay content estimation with gamma Ray log.

Correlation in open or cased holes.

Code/Name :( NPHI, TNPH, CN and CNL)

3.2.6 Acoustic (Sonic) Log

The sonic or acoustic log measures the travel time of an elastic wave through

the formation. This information can also be used to derive the velocity of elastic

waves through the formation. in addition, to its main use is to provide information

to support and calibrate seismic data and to derive the porosity of formation.

The tool measures the time it takes for a pulse of sound (and elastic wave) to travel

from a transmitter to a receiver, which are both mounted on the tool. The transmitted

pulse is very short and of high amplitude. This travels through the rock in various

different forms while undergoing dispersion (spreading of the wave energy in time

and space) and attenuation (loss of energy through absorption of energy by the

formations). The simplest form of Sonic Logs consists of a transmitter that generates

a sound pulse and receiver that picks up and records the pulse as it passes the

receiver, (Fig. 3.8).

A simple tool that uses a pair of transmitters and four receivers to compensate for

caves and sonde tilt, the normal spacing between the transmitters and receivers is 3’

– 5’. It produces a compressional slowness by measuring the first arrival transit

times.

45

Fig 3.8: Sonic logging tool (Modified from Website: www.terraplus.ca. (2018).

The porosity from the sonic slowness is different than that from the density or

neutron tools, it reacts to primary porosity only, i.e. it doesn’t “see” the fracture or

vugs. The difference between the sonic porosity and the neutron-density porosity

gives a Secondary Porosity Index (SPI) which is an indication of how much of this

type of porosity there is in the formation.

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

ɸ = Δt log – Δt mat

Δf – Δt mat ...…………. (3.4)

Where:

ɸ = sonic porosity, Δt log = Formation of interest sonic log reading. Δt mat =

Matrix travel time and Δf = Mud Fluid travel time.

46

3.2.7 Electrical Logs

Basically electrical logging involves measurements of the variations of

electrical resistivity and natural potential of rocks down the drilled well. Depending

on the applied electrode configuration, the following techniques are in common use:

The spontaneous potential (SP).

The resistivity logs.

3.2.7.1 spontaneous potential (SP)

Spontaneous potential is also known as self-potential log, it is a measurement

of the natural potential differences between an electrode in the borehole and a

reference electrode at the surface: no artificial current is applied. They originate from

the electrical disequilibrium created by connecting formations vertically when in

nature they are isolated.

The principal uses of the SP log are to calculate formation water resistivity and to

indicate permeability.

It can also be used to estimate shale volume, to indicate facies and in some cases for

correlation.

Three factors are necessary to provoke an SP current: a conductive fluid in the

borehole, a porous and permeable bed surrounded by an impermeable formation and

a difference in salinity (or pressure) between the borehole fluid and the formation

fluid. The principle of measurement is based on the difference in the diffusion

potential of sodium chloride (Fig. 3.9), due to a variation of pore throws within the

formation. The chloride ion is both smaller and more mobile than the larger, slower

sodium. Therefore, because shale consist of layers with large negative surface

charge, the negative chloride ions effectively cannot pass through the negatively

charged shale layers, while the positive sodium ions pass easily. The shale (semi-

permeable membrane) acts as a selective barrier. As sodium ions diffuse

47

preferentially across a shale membrane, an overbalance of sodium ions is created in

the dilute solution and hence a positive charge. A corresponding negative charge is

produced in the concentrated solution. The shale potential is the larger of the two

electrochemical effects. Consequently, the actual potential currents which are

measured in the borehole are for the most part, a result of the combination of the two

electrochemical effects described above. Likewise, the less saline solution opposite

the sandstone bed (permeable membrane), the mud filtrate will become positively

charged. As a result, the excess charge is negative next to the sand and positive next

the shale (Rider, 1996)

Fig 3.9: Illustration the principle of the SP log (from Rider, 1996).

48

3.2.7.2 Resistivity Logs

Resistivity is one of the primary inputs required to evaluate the producing

potential of an oil or natural gas well. This measurement is needed to determine Sw,

which is needed to estimate the amount of oil or natural gas present in the well. The

basic measuring system has two current electrodes and two voltage electrodes.

The measuring unit is ohm-meters and they are plotted on a logarithm scales in

track 2 or 3. The resistivity logs can be grouped into three measurements: Induction

logs, Latreologs, and Microresistivity measurements.

3.2.7.2.1 Induction logs

An induction tool uses a high frequency electromagnetic transmitter to induce

a current in a ground loop of formation, this, in turn, induces an electrical field whose

magnitude is proportional to the formation conductivity, a high-frequency AC of

constant intensity is sent through a transmitter coil -> magnetic field -> create

currents in the formations as ground loops coaxial with the transmitter coil ->

magnetic field that induces a voltage in the receiver coil. Induction tool works best

when the borehole fluid is an insulator, air or gas, even when the mud is conductive.

The Induction tool is designed for an 8.5 inches’ hole and can be run

successfully in much larger hole sizes in which logging is usually performed with a

1.5 inch stand off from the borehole wall. The tools work best in low resistivity

Formations and in wells drilled with high resistivity muds. Tool resolution is in the

order of 6 feet. Depth of investigation is 4-6 feet for the Medium Induction log (ILM)

and about 10 feet for the Deep Induction log (ILD).

The typical application of the Induction Logs is:

Measure the true (undisturbed) formation resistivity (Rt)

Ideal in Fresh or Oil –based environments

Ideal for Low resistivity measurements

49

Fluid saturation determination.

3.2.7.2.2 Latreologs

The Latreologs is designed to measure true Formation resistivity (Rt) in

boreholes filled with saltwater muds (where Rmf = Rw). A current from the

surveying electrodes. The focusing electrodes emit current of the same polarity as

the surveying electrode but are located above and below it.

The potential drop changes as the current and the Formation resistivity

changes and therefore the resistivity can be determined.

Latreolog Applications include the following:

Correlation, Water saturation, and Invasion analysis

Evaluate mud cake and mud resistivity for borehole correction using very

shallow measurements.

Enhance the evaluations of horizontal and or highly-deviated wells using

azimuthal and array measurements.

Fracture analysis using azimuthal measurements.

Enhance the evaluations of thin and invaded formation using array

measurements.

Enhance the accuracy of Rt evaluation in difficult environments such as

Groningen affected areas, high contrasts, thinly bedded formations and high

apparent dip by using array measurements and formation inversion processes.

Limitations of the Latreolog are:

Affected by the Groningen effects in some environments

Cannot be used in oil-based muds also cannot be used in air-filled holes.

50

3.2.7.2.3 Microresistivity Log:

The Microresistivity logs are pad type resistivity devices that primarily detects

mud cake (Hilchie, 1978). The pad is in contact with the borehole and consists of

three electrodes spaced one inch apart. From the pad, two resistivity measurements

are made; one is called the micro normal and the other is the microinverse, the micro

normal device investigates three to four inches into the Formation (measuring Rxo)

and the micro inverse investigates approximately one to two inches and measures

the resistivity of the mud cake (Rmc) the detection of mud cake by the Microlog

indicates that invasion has occurred and the formation is permeable.

(MSFL) which has another version as Micro-Cylindrical Focused Log (MCFL) the

tools are variously affected by factors like mud cake thickness of the invaded zone.

(table 3.2) below shows common names used for the Microresistivity logs.

Table 3.2: shows common curve names used for the Microresistivity logs

Microresistivity log application are:

Determination of flushed zone formation resistivity Rxo.

Flushed zone water saturation (Sxo) through Archie's Equation.

Invasion corrections deep resistivity tools.

Thin bed definition.

Curve Name Mnemonics Curve Name Mnemonics

Micro normal resistivity MNOR

Micro inverse resistivity MINV

Micro Spherically Focused resistivity MSFL

51

Limitations of the tools are:

Rugose hole.

Oil-Based mud.

Heavy or thick mud cake.

3.2.8 Auxiliary Logs

These are the logs that are required to assist in the quantitative interpretation

of many other logs that are sensitive to borehole diameter, wall roughness, hole

deviation, and fluid temperature. This includes the caliper, diameter, and

temperature logs.

3.2.8.1 Caliper Log

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 run (Fig. 3.10).

The 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 as shown in Fig. (3.10).

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.

52

Fig 3.10: Caliper tool showing the positions of caving and swelling in a well, (from

Mondol N.H. et, al, 2015).

3.2.8.2 Diameter Log

The oldest dipmeter consists of four Microresistivity device mounted on pads.

Modern dipmeter tools not consist only of the logging tool sonde for the

Microresistivity curves, but also a positioning sonde so that tool orientation,

inclination, and speed are known, all essential to the computation of the dip and

azimuth. The dipmeter provides data for structural and sedimentary geology.

In structural geology dipmeter provides information about structural dip,

unconformities, faults and folds. In sedimentary geology diameter provides

information about facies and environments.

The dipmeter tools, however, can detect the very thin events that are related

to sedimentary features. With the introduction of electronic computers, dipmeter

data can be interpreted in much more detail. Dips are computed at many more levels,

53

and computations are made by correlating the dipmeter curves over shorter intervals.

These short-interval correlations reveal the fine structure of current bedding and

other sedimentation-related dips. When long-interval correlations are made, this

detailed information is averaged out, and essentially what remains is the structural

dip.

Fig 3.11: Example of presentation of dip log.

The dipmeter results are usually presented in “arrow” plots (or “tadpole” plots).

The stem on each plotting symbol indicates the direction of the dip. The

54

displacement of the symbol from the left edge of the plot represents magnitude of

dip angle. Vertically, the symbols are plotted versus depth.

It is common practice to identify various characteristic patterns on the plots by

coloring them. In the diameter interpreter the various patterns are called by the color

names. the red, blue, and green patterns. In a red pattern, successive dips increase

progressively with depth and keep about the same azimuth. In a blue pattern,

successive dips with about the same azimuth decrease progressively with depth. A

green pattern, corresponds to structural dip. It is consistent in azimuth and dip

magnitude, (Fig.3.11).

3.2.8.3 Temperature Log

The temperature tools measure the temperature of borehole fluids.

Temperature logging is used to detect changes in thermal conductivity of the rocks

along the borehole or to detect water flow through cracks or fractures.

The log is normally plotted so that changes in the temperature gradient (change in

temperature to depth) might be related to lithological boundaries or aquifers. Ideally

the logging sonde is run twice; one immediately after drill rods are withdrawn and

after 24 hours in order to describe the temperature gradient.

The unit of measurement is normally in Degree Fahrenheit (Fº) or centigrade (Co).

The logs are to be run in fluid-filled boreholes and are also used for temperature

corrections along other logs and measurements.

55

CHAPTER FOUR

THE PETROPHYSICAL EVALUATION

4.1 Introduction:

One of the basic uses of well logs is to evaluate subsurface formations for

example, in-situ porosity cannot be measured directly in the field as in the laboratory.

Therefore, only indirect measurements are made through well logging. These

measurements use either sonic energy or some form of induced or applied radiation.

Most log evaluation is concerned primarily with determining in-situ porosity and

water saturation. Neither in-situ water saturation or hydrocarbon saturation can be

measured directly in the wellbore. However, it is possible to infer the water

saturation if the porosity is known by measuring the resistivity of the formation.

The main role of this study is making a comprehensive petrophysical

evaluation by using Interactive Petrophysics (IP) software, to calculate the

petrophysical parameters for Formation evaluation, for 4 wells to determine

lithology, clay volume, porosity, water saturation, hydrocarbons potentiality and all

Formation Evaluation in Bentiu formation in Muglad basin at Hamra east Area. As

well as manually interpretation for all wells have been done using true resistivity

(RT) method determination to confirm and supporting software results.

4.2 Data Handling and Basic Flow Chart:

This study utilizes a suite of four well logs data of Hamra east field, one of

the early challenge is to get familiar with the well log data sets, their limitations and

uncertainties related to the extraction of rock properties that not measured directly.

Besides learning the different geological software's (interactive petrophysics, petrel,

surfer 13) which have been used in this study to handle different data formats are

also challenging. It is very important to know what exactly the software's are

56

Fig 4. 1: Schematic flow Chart presents the interpretation sequence.

calculating/estimating behind the scenes. Four wireline combined logs information

are available in this study. The logs items include: deep resistivity log (RD/LLD),

shallow resistivity log (RS/LLS), micro-resistivity log (MSFL/RMSL), acoustic log

(AC/DT), density log (ZDEN/RHOB), neutron log (CNL/CNC/NPHI), natural

57

gamma ray log (GR), spectral gamma ray log, spontaneous potential log (SP) and

Caliper log (CAL). The intrpretation were done through the flow chart ( Fig. 4.1)

4.3 Log quality Control (LQC)

Log quality control include:

i. Splicing logging run to make a continuous curve.

ii. Depth shifting curves to a common depth reference to ensure all logs are

aligned with respect to depth and the measurement of each tool at any

particular depth can be assumed to represent the properties of the same

formation.

iii. Consistency between logs.

4.4 Determination of Formation Temperature

The resistivity of formation water and (drilling mud) is a function of

temperature. Therefore, it is important to generate temperature curve in the absence

of one of them to be able to properly estimate the resistivity of water in a formation

of interest. A mean annual surface temperature was estimated for the study area and

geothermal gradient (Gg) is assumed to be linear using the linear regression equation

because the knowledge of the increasing of temperature with depth in borehole is

one of the basic requisite for accurate logs calculations. The bottom hole temperature

(BHT) measurement was used to calculate a mean geothermal gradient (Gg).

Temperature information for each well at this study were given with the LAS format

files of wells and is shown on (Table 4:1).

58

Table 4. 1: Bottom hole temperature of the studded wells

4.5 Lithology determination and zoning of reservoirs

Lithology in the Hamra East field was determined by incorporating local

knowledge with the use of well logs. The Muglad Basin is predominantly composed

of sandstone and shale. Bearing this in mind, gamma ray was used to distinguish

between reservoir (sands) and non-reservoirs (shale). This was corroborated with

the use of resistivity, neutron and density logs. Each reservoir unit was defined as a

zone. A zone represents the boundary of a reservoir unit and is defined by a top and

bottom.

For Determination lithology there are two independent sources of lithology

data available from oil wells, one set of data coming directly from mud logging

(master-logs), and one set from wireline logging. These two sets of data are essential

When any two log values are cross plotted, the resulting series of points used to

define the relationship between the two variables. The neutron – density cross plot

is the best method for lithology identification. Density – Neutron cross plot values

had been used to identify the pure matrix and/or the related porosity. This cross plot

uses a straight line relationship between two variables to quantify the desired

characteristics and to determine lithology (Fig. 4.2).

No Well Name Mud Sample Temperature Bottom Hole Temperature

1 Hamra East-1 27.7o C 82.2o C

2 Hamra East-2 29.5o C 73o C

3 Hamra East-3 29o C 70o C

4 Hamra East-4 29.1o C 70o C

59

Fig 4. 2: lithology identification from density – neutron cross-plot, for wells Hamra

East -1and Hamra East-2

Shale increasing

Shale increasing

60

4.6 Reservoir and non-reservoir rock identification

There are many ways of reservoir identification but the most useful indicator

of reservoir rock is from the behavior of the density and neutron logs, with the

density moving to the left (lower density) and crossing the neutron curve. All this

cases were corresponded to a fall in the gamma ray log and Resistivity logs, in

addition to the presence of the mud cake, right deflection of SP and the separation

between three resistivity curves, respectively. The greater cross over between the

density to the left and neutron to the right indicates the better quality of the reservoir

and vice versa (Fig. 4.3) shows reservoir rock and non-reservoir rock delineated

from log. Non-reservoir rock (shale) was clearly identified as zones where the

density lies to the right of the neutron, associated with increasing in gamma ray. Also

presence of washout is dominantly related to the presence of shale, left deflection of

SP and when the three resistivity curves lies each other.

Fig 4. 3: represent reservoir rock and non-reservoir rock in Bentiu formation from

well Hamra East-4

Reservoir

Rock

Non-Reservoir

Rock

61

4.7 Interpretation

The major part of this present study is to make full interpretation models for

the petrophysical parameter in order to pick up all zones that are considered to be

reservoir rocks for the best identification of hydrocarbons places, at this Study V-

shale, porosity and water saturation models had been done and full interpreted

from the initial results, cut off parameters also determined and multi targets

prospects of all wells had been marked, besides net-reservoir and net-pay were

obtained successfully.

4.7.1 Shale volume Calculation

The volume of shale is used to account for the effect of clay in the formation.

Different types of measurements exist for Vsh and one could be calculated using

clay indicators in individual curves (GR, SP, resistivity, or neutron) and cross plots

(neutron density, neutron-sonic or sonic-density). Generally, clean and clay points

are defined for any method used and Vsh is scaled in between.

These logs are called shale indicators and include:

1-Single Curve Shale Indicators

2-Duble Curve Shale Indicators

7.1.2 Single Curve Shale Indicators

This method was used for estimation Volume of shale in this study, by using

gamma ray log because the gamma ray log is the best single indicator of shale. It is

suitable because no radioactive minerals other than clays are suspected. Shale

volume is calculated in the following way:

Firstly, calculate the Gamma ray index from the Gamma ray log by using the

following Relationship:

Vsh = IGR = [GR log – GR min] / [GR max – GRmin]

62

Where:

Vsh = volume of shale

IGR = index gamma ray

GRlog = gamma ray reading of formation of interest

GRmin = minimum gamma ray in clean sand or carbonate formation GR max =

maximum gamma ray in shale or clay formation

For taking the GR max and GR min values, a histogram is run on the well data in

order to mark the maximum average (clay) and minimum average value (sand) In

Fig. 4.4 the red line is for the gamma ray minimum (39API) and the green line at

right end of the scale is for the gamma ray maximum (150 API).

Fig 4. 4: minimum and maximum gamma ray histogram of all Zones well (Hamra

East 4).

63

Fig 4. 5: shows the average values of v-shale for four wells in Bentiu formation. a)

Av-Vclay calculated using IP software, b) Av-Vclay calculated manually.

These values of clay volume had been obtained using Single curve shale indicators

method and from the results were mentioned it's clear that the Bentiu formation is

almost has low content of shale. So it's considered to be mainly sand sequence, but

the wells that have high rate of shale volume must show low value of porosity as

shown in the comparison map and histogram of V-clay and porosity on (Fig. 4.5, 4.6

a & b) and (Fig. 4.8 a & b) in porosity model.

Fig.4.6 (a & b) shows shale volume contour maps using both methods;

manually and IP result. The Bentiu reservoir shows that the shaliness reaches a

minimum of 16.7% and a maximum value of 20% at HE-2 and HE-1 wells

respectively. The shale content increases toward the northwestern direction of the

study area and in the other hand, the shale content decreases toward the southeastern

direction of the study area. In most intervals, the shale volume increases along the

direction where both the effective porosity and water saturation decrease. This

means that the shale content has an effect on the effective porosity as a result of its

way of distribution within the reservoir.

15.00%

16.00%

17.00%

18.00%

19.00%

20.00%

21.00%

Hamra East1

Hamra East2

Hamra East3

Hamra East4

20.16%

16.7%17.1%

18.6%

AV-V CLAY (%)

AV-V Clay Manually

Hamra East1

Hamra East2

Hamra East3

Hamra East4

19%

17%

18.4%

19.3%

AV-V CLAY (%)

IP AV-VCLAY(%) b)

a)

64

Fig 4. 6: Average -shale ‘Vsh’ contour maps of Net reservoir Bentiu formation.

Increasing

V-shale

Increasing

V-shale

65

4.7.3 Porosity Calculation

Porosity can be determined from the density, neutron and sonic logs

individually, the density-neutron cross plot is the most accurate log analysis method

for determining porosity. Both tools are calibrated against a water-filled limestone

basic calibration fixture. The density log measurement is more sensitive to pore

space and the neutron measurement is more sensitive to lithology change. This

tendency also balances out in cross plotted result. This technique is used to estimate

the shale volume as well. For the shaly sand models, the following sets of equations

were used:

RHOB = RHOB matrix + (RHOB shale – RHOB matrix) *V shale + (RHOB fluid – RHOB

matrix) *ɸ effective; And

ɸNeutron = ɸNeutron matrix + (ɸNeutron shale – ɸNeutron matrix) *Vshale + (1– ɸNeutron

matrix)* ɸ effective.

The total porosity is given by:

ɸ Total = ɸ effective + WCLP*V shale

Where:

RHOB is the density log, ɸNeutron is the neutron log and WCLP is the wet clay

porosity from core analysis.

By applying this technique for porosity calculation, the porosity model has been

constructed for Bentiu formation and the results are showed in Fig (Fig. 4.6,4.8 a&

b) and (Fig. 4.9 a& b).

66

Fig 4. 7: log porosity for well Hamra East- 4

67

Fig 4. 8: show the average values of Porosity for all wells in Bentiu formation.

a) Av-Porosity calculated using IP software, b) Av- Porosity calculated manually.

Fig,4.10 shows the highest porosity in Hamra East-2 which represents low V-clay

value as mentioned before for (Fig.4.8 a & b), and any well that had high v-clay

value here showed low porosity due to that shale usually minimizes the effective

porosity and vice versa.

21.0%

21.5%

22.0%

22.5%

23.0%

23.5%

24.0%

24.5%

Hamra East1

Hamra East2

Hamra East3

Hamra East4

22.9%

24.1%

23.2%23%

AV- POROSITY (%)

AV- Porosity Manuallyb)

a)

21%

22%

23%

24%

25%

26%

Hamra East1

Hamra East2

Hamra East3

Hamra East4

23%

25.1%

23.7%24.1%

AV-POROSITY (%)

IP AV-Porosity

68

Fig 4. 9: Average porosity ‘Phi’ contour maps of Net reservoir in Bentiu formation.

Increasing

porosity

Increasing

porosity

69

4.7.4 Fluid type determination from water saturation calculation

Different methods can be used to evaluate the water saturation of a reservoir

formation:

1. The Archie method which involves clean sandstone formations.

2. The shaly sand method comprising the resistivity approach (Simandoux

model, Poupon and Leveaux model, Schlumberger model, Indonesian model)

and the conductivity approach (Waxman-smith model, Dual-water model,

Juhasz model).

In the current study, only Archie and resistivity (Indonesian model) methods was

used. Archie (1942) developed an equation from his experiment on voids saturation.

He found that water saturation of the rocks could be related to their resistivity. The

formula showed that increasing porosity will reduce the water saturation for the same

resistivity in a clean (homogenous) formation. Thus, the relationship between these

parameters was mathematically expressed as follow:

Sw = √Ro

Rt (4.1)

Where:

Sw = water saturation

Ro = resistivity of water formation

Rt = true resistivity of the formation

From the previous calculations the amount of water in all wells were obtained for

Bentiu formation.

70

Fig 4. 10: distribution of water saturation for all wells in Bentiu formation.

a) Av-water saturation calculated using IP software, b) Av- water saturation

calculated manually.

The above Fig indicates that, the maximum value of water Saturation (85.3%) was

recognized in HE-2 well in the southeastern part, and the minimum value range 77-

79.6% at HE-1 and HE-4 respectively in the northwestern part of the study area. The

water saturation decreases in the northwestern parts of the study area, at HE-1 and

HE-4 giving rise to more hydrocarbon content. That will be more clear from (Fig.

4.12) which is showing saturation contour maps. Only hamra east 2 and hamra east-

3 in Fig. 4.11 showed high values of water saturation.

72%

74%

76%

78%

80%

82%

84%

Hamra East1

Hamra East2

Hamra East3

Hamra East4

76%

83%

79%

77.5%

Av-Sw (%)

Manually Result -SW(%)b)

72%

74%

76%

78%

80%

82%

84%

86%

Hamra East 1 Hamra East 2 Hamra East 3 Hamra East 4

77%

85.3%

80.8%

79.6%

Av-Sw (%)

IP Result -SW(%)a)

71

Fig 4. 11: Average water saturation ‘Sw’ contour maps for Bentiu Formation.

Increasing

Saturation

Increasing

Saturation

a)

b)

72

4.7.5 Hydrocarbon saturation Estimation (net-pay)

The hydrocarbon saturation can be deduced from water saturation by the

following relationship:

Shc = 1 – Sw (4.2)

It is normally differentiated into the non-exploitable or residual hydrocarbon (Shr)

and the exploitable or movable hydrocarbon (Shm), as follow:

Shc = Shr + Shm (4.2)

Shc = 1 – Sxo (4.4)

Where:

Shc = hydrocarbon Saturation, Shm= movable hydrocarbon

Shr = residual hydrocarbon saturation Sxo = Water saturation at Flushed zone

The movable hydrocarbon saturation (Shm) is very important because it can be

studied in commercial view, while the residual hydrocarbon saturation (Shr) is not

important because its extraction is difficult.

From the above application of IP software, 3D model for the movable hydrocarbon

had been generated, it appears that the maximum net pay thickness is found in the

well (Hamra east-4), (Hamra East-1), (Hamra East-2) and Hamra East-3

successively as shown in Fig. 4.12, 4.13 and in table 4.2.

Table 4. 2: Water and oil saturation in all of the studied wells.

Well name Well name Well name Well name

Hamra

E-1 Sw (%) Shc (%)

Hamra

E-2 Sw (%) Shc (%)

Hamra

E-3

Sw

(%) Shc (%)

Hamra

E-4 SW (%)

Shc

(%)

Zone1 60% 40% Zone1 56% 44% Zone1 75% 25% Zone1 51% 49%

Zone2 48% 52% Zone2 100% --- Zone2 85% 15% Zone2 46% 54%

Zone3 68% 32% Zone3 83% 17% Zone3 83% 17% Zone3 64% 36%

Zone4 100% ------ Zone4 92% 8% - - - Zone4 100% ------

Zone5 100% ------ Zone5 84% 16% - - - Zone5 100% ------

Zone6 100% ------ Zone6 88% 12% - - - Zone6 100% ------

- - Zone7 100% ---- - - - Zone7 100% ------

73

Fig 4. 12: percentage of net pay for each well in the study area.

Fig 4. 13: 3D model showing the hydrocarbon Saturation (Net-pay) distribution for

the studded wells in Bentiu formation.

18.29;35%

10.03;20%

2.14;

4%

21.03;41%

IP Result-Net Pay (m)

HE-1 HE-2 HE-3 HE-4

18;32%

HE-212;

21%

HE-36.5;8%

22.5;39%

Manually Result -Net pay (m)

HE-1 HE-2 HE-3 HE-4

74

Fig. 4.13 showed 3D model for net pay distribution which were showed that the oil

is concentrated in Hamraeast-4, Hamraeast-1 and Hamraeast-2. only Hamraeast-3

showed very low net pay.

4.8 Wells Correlation

The correlation was carried out to determine the continuity and equivalence

of lithological units for the reservoir sands and marker sealing shales of the for wells

in the study area. The wells were correlated using the gamma ray and deep resistivity

logs as an initial quick look to identify the major sandstones units.

The architecture of the reservoir is essential in describing the lithology, as

well as the flow characteristics of the reservoir. In this research, the various wells of

interest in the sector of the study were correlated (1) to evaluate the various

petrophysical parameters, and (2) to establish a reference depth for a common base

sand and shale volume. The correlation of the wells (Fig.4.14) showed that the

Bentiu Formation continues on all wells and that make idea to link all zones. In

addition to that the area is confined by main and minor faults as shown in top Bentiu

structure map (Fig. 4.15) from this Fig it is more clear that the depth value of the

formation is equivalent (Table 4.3).

Table 4. 3: show the depth of Bentiu, top and bottom in the study area

NO Well Name Top Bentiu (m) Bottom (m)

1 Hamra East-1 1691.79 1878.33

2 Hamra East-2 1733.4 1889.61

3 Hamra East-3 1754.89 1823.47

4 Hamra East-4 1687.98 1883.05

75

Fig 4. 14: showed wells correlation and profile map.

76

Fig 4. 15: top Bentiu Structure Map for Hamra east oil field

4.9 Reservoir zones and Petrophysical Parameters

It is very important to identify properly the lithology and the reservoir to allow

an accurate petrophysical calculation of porosity, water saturation Therefore, in this

section it will be able to discriminate and understand the reservoir zone.

77

From Fig (4.16) to Fig (4.19) displays the total porosity (PHIT), effective porosity

(PHIE), water saturation (Sw), reservoir and pay zones, fluid types and lithology for

all wells. The pay zones sometimes do not match with the reservoir, showing a few

thin pay intervals. From the Fig below its clear that the response gamma ray,

resistivity and neutron – density cross over to distinguish between the sand and shale

by means high gamma ray low resistivity neutron – density cross (shale) and vice

versa.

Fig 4. 16: Petrophysical parameters of well HE-1 zone 1,2 and 3 for Bentiu Reservoir.

Oil

Oil

Oil

Zone 1

Zone 2

Zone 3

78

Fig 4. 17: Petrophysical parameters of well HE-2 zone 1,2 and 3 for Bentiu reservoir.

zone 1

zone 2

zone 3 Water

Water

Oil

OWC

79

Fig 4. 18: Petrophysical parameters of well HE-3 zone 1,2 and 3 for Bentiu reservoir.

Oil

Oil

Zone 1

Zone 2

Zone 3 Water

80

Fig 4. 19:Petrophysical parameters of well HE-4 zone 1,2 and 3 for Bentiu reservoir.

Oil

Oil

Oil

Water Zone 4

Zone 3

Zone 2

Zone 1

OWC

81

4.10 Petrophysical Cutoff Values Determination

A cutoff value Such as Shale volume shale Cutoff (Vsh-Cutoff), porosity

Cutoff (Phi-Cutoff) and Water Saturation Cutoff (SW-Cutoff) it’s very important

parameters in the calculation of Hydrocarbon and calculate the net reservoir rocks

in the field. also for discriminating between the Reservoir and non-reservoir rocks

The net reservoir rock above the oil, water contact defines the net pay rock, which

is going to be used in estimating the original oil in place (OOIP). Therefore, the

intent is to set the cutoff criteria needed to discriminate these non-reservoirs from

the logged reservoir intervals. The values of cutoff should define as follows:

4.10.1 Cut-off Sensitivity Computations

The cut-off criteria that are used to generate a reservoir summary report for 'Net

Reservoir' and 'Net Pay' can be critically important. To deciding what values of V-

clay, Porosity and Sw to use as cut-offs is quite often guesswork and therefore

sensitivities run on the cut-off values can be useful in helping to make a decision on

the appropriate cut-off value to apply.

4.10.1 .1 Shale Volume and Porosity Sensitivity Cutoffs

Based on sensitivity cutoff for Determining the shale value cutoff. the Sensitivity

cutoff showed that shale value cutoff is 40% (Fig. 4.20), Porosity Cutoff is 16% (Fig.

4.21) and for water saturation which is determined by plotting zones against porosity

after interpretation. the Sw value cutoff is 70%. which can be adopted in the study

for Bentiu formation, as showed in (Fig. 4.23).

After defining the Cutoff values, the Relationship between shale volume and

porosity were used to confirm the result by plotting zones against Vsh and Phi, which

were showed in (Fig. 4.22) its present that the volume of shale cut-off and porosity

82

cutoff value is <= 40% and > 16%. Respectively, was identical with the sensitivity

Cutoff in these study Bentiu reservoirs.

Fig 4. 20: shale volume Sensitivity cutoff for all wells

Vcl Cut Res/Pay Cutoff Sensitivity Data

Wells: Hamra E-3 ST, Hamra E-4, Hamra E-2

VclH Reservoir - All Zonesgfedcb

Vcl Cut Res/Pay Cutoff

10.950.90.850.80.750.70.650.60.550.50.450.40.350.30.250.20.150.10.050

VclH

R

eservoir

16

14

12

10

8

6

4

2

0

P10 P50 P90

V clay cutoff < 40 %

V clay cutoff < 40

83

Fig 4. 21: Porosity Sensitivity cutoff for all wells.

Phi Cut Res/Pay Cutoff Sensitivity Data

Wells: Hamra E-4, Hamra East-1, Hamra E-3 ST, Hamra E-2

PhiH Reservoir - All Zonesgfedcb

Phi Cut Res/Pay Cutoff

0.40.380.360.340.320.30.280.260.240.220.20.180.160.140.120.10.080.060.040.020

PhiH

R

eservoir

18

16

14

12

10

8

6

4

2

0

P10P50P90

Porosity cutoff >16

Porosity cutoff >16

84

Fig 4. 22: shale volume and porosity cutoffs verses zones

0

10

20

30

40

50

60

0 2 4 6 8 1 0 1 2 1 4 1 6 1 8 2 0 2 2 2 4 2 6 2 8 3 0 3 2 3 4

VC

L (

%)

POROSITY(%)

VCL Cutoff < 40%

POR cutoff >16 %

Non-Reservoir

Non-Reservoir

Reservoir

Clay volume verses porosity

Water Oil Oil- Water

85

4.10.1.2 Water Saturation and porosity cutoffs

For water saturation cutoff between Sw and porosity against zones (Fig 4.23),

represent the Sw cutoff values <= 70% was adopted in this study for Bentiu

Formation.

Fig 4. 23: water saturation and porosity cutoffs verses zones

0

10

20

30

40

50

60

70

80

90

100

110

0 2 4 6 8 1 0 1 2 1 4 1 6 1 8 2 0 2 2 2 4 2 6 2 8 3 0

SW

(%)

POROSITY

Sw Verses porosity

Sw cutoff ≤ 70%

POR cutoff > 16

%

Non-Reservoir

Reservoir

Non-Reservoir

Water Oil Oil- Water

86

4.11 Reservoir summation and Interpretation of Results

The calibration procedures that is used in this study to minimize the errors and

uncertainties in the final results. 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 of data.

The final interpretation results are listed and tabled for each well in this

Section. The characteristics of Bentiu reservoirs were studied zone by zone for a

whole sections of the formation in all wells. These tables show that the oil pays

mainly distributed in Bentiu Formation, it appears in Hamreast-1, Hamreast-2,

Hamreast-4 and Hamreast-3 wells.

In Hamraeast1 well showed that the maximum net pay thickness for Bentiu

reservoirs is 10.54 m, minimum thickness is 3.28 m and the total net pay 18.29 m.

The average effective porosity is 23%, and the average water saturation is 77%

(Table 4.4, 4.5). While in HamraEast2 well showed that the maximum net pay

thickness for Bentiu reservoirs is 9.63 m, minimum thickness is 0.11 m and the total

net pay 10.06 m. The average effective porosity is 25%, and the average water

saturation is 85.3% (Table 4.6, 4.7).

In HamraEast-3 well showed that the maximum net pay thickness for Bentiu

reservoirs is 1.07 m, minimum thickness is 1.07 m and the total net pay 2.14 m. The

average effective porosity is 23.7%, and the average water saturation is 80.8%

(Table 4.8, 4.9). while in HamraEast-4 well showed that the maximum net pay

thickness for Bentiu reservoirs is 8.84, minimum thickness is 5.98 m and the total

87

net pay 21.03 m. The average effective porosity is 24.1%, and the average water

saturation is 79.6% (Table 4.10, 4.11).

Table 4. 4: Reservoir Summary of well Hamra East-1.

Table 4. 5: Pay Summary of well Hamra East-1.

Zn Zone Name Top Bottom Gross

(m)

Net

(m)

N/G

ratio

Av Phi Av Sw Av Vcl Phi*H PhiSo*H

1 Bentiu-1 1691.79 1725.17 33.38 16.46 0.493 0.227 0.603 0.23 3.74 1.48

2 Bentiu-2 1725.17 1736.9 11.73 4.72 0.403 0.199 0.484 0.30 0.94 0.47

3 Bentiu-3 1736.9 1760.83 23.93 14.17 0.592 0.225 0.684 0.17 3.05 0.98

4 Bentiu-4 1760.83 1801.98 41.15 23.16 0.563 0.221 0.974 0.17 5.12 0.01

5 Bentiu-5 1801.98 1839.93 37.95 23.93 0.631 0.236 0.953 0.19 5.33 0.07

6 Bentiu-6 1839.93 1878.33 38.4 2.29 0.06 0.245 0.925 0.101 0.46 0.01

All Zones 1691.79 1878.33 186.54 84.73 0.454 0.226 0.77 0.19 18.65 3.01


(m)

Net (m) N/G

ratio

Av Phi Av Sw Av

Vcl

Phi*H PhiSo*H

1 Bentiu-1 1691.79 1725.17 33.38 10.54 0.315 0.237 0.477 0.221 2.5 1.31

2 Bentiu-2 1725.17 1736.9 11.73 3.28 0.325 0.232 0.429 0.329 0.77 0.44

3 Bentiu-3 1736.9 1760.83 23.93 4.47 0.312 0.215 0.506 0.214 1.6 0.79

4 Bentiu-4 1760.83 1801.98 41.15 0 0 --- --- --- --- ---

5 Bentiu-5 1801.98 1839.93 37.95 0 0 --- --- --- --- ---

6 Bentiu-6 1839.93 1878.33 38.4 0 0 --- --- --- --- ---

All Zones 1691.79 1878.33 186.54 18.29 0.117 0.23 0.479 0.237 4.87 2.54

88

Table 4. 6: Reservoir Summary of well Hamra East-2

Table 4. 7: Pay Summary of well Hamra East-2

Zn Zone

Name

Top Bottom Gross

(m)

Net

(m)

N/G

ratio


1 Bentiu-1 1733.4 1752.3 18.9 9.63 0.524 0.251 0.495 0.192 2.49 1.26

2 Bentiu-2 1752.3 1770.74 18.44 0.11 0.008 0.269 0.649 0.1 0.04 0.01

3 Bentiu-3 1770.74 1793.14 22.4 0 0 --- --- --- --- ---

4 Bentiu-4 1793.14 1809.75 16.61 0 0 --- --- --- --- ---

5 Bentiu-5 1809.75 1824.08 14.33 0.15 0.011 0.251 0.697 0.062 0.04 0.01

6 Bentiu-6 1824.08 1838.25 14.17 0.14 0.086 0.242 0.645 0.142 0.3 0.1

7 Bentiu-7 1838.25 1889.61 51.36 0 0 --- --- --- --- ---

All Zones 1733.4 1889.61 156.21 10.03 0.073 0.25 0.515 0.184 2.86 1.39

Zn Zone

Name

Top Bottom Gross

(m)

Net

(m)

N/G

ratio


1 Bentiu-1 1733.4 1752.3 18.9 11.96 0.633 0.249 0.562 0.201 2.98 1.3

2 Bentiu-2 1752.3 1770.74 18.44 16 0.868 0.249 0.932 0.142 3.99 0.27

3 Bentiu-3 1770.74 1793.14 22.4 12.19 0.544 0.231 0.826 0.193 2.81 0.49

4 Bentiu-4 1793.14 1809.75 16.61 4.04 0.243 0.213 0.919 0.151 0.86 0.07

5 Bentiu-5 1809.75 1824.08 14.33 3.35 0.234 0.231 0.835 0.138 0.77 0.13

6 Bentiu-6 1824.08 1838.25 14.17 10.97 0.774 0.225 0.878 0.173 2.47 0.3

7 Bentiu-7 1838.25 1889.61 51.36 27.58 0.537 0.22 0.938 0.167 6.08 0.38

All Zones 1733.4 1889.61 156.21 86.11 0.551 0.232 0.853 0.17 19.97 2.94

89



Zn Zone

Name

Top Bottom Gross

(m)

Net

(m)

N/G

ratio


1 Bentiu-1 1754.89 1774.39 19.51 10.74 0.551 0.233 0.747 0.196 2.51 0.63

2 Bentiu-2 1774.39 1791.92 17.53 11.81 0.674 0.236 0.854 0.158 2.79 0.41

3 Bentiu-3 1791.92 1823.47 31.55 5.64 0.179 0.204 0.831 0.217 1.15 0.2

All Zones 1754.89 1823.47 68.58 28.19 0.411 0.229 0.808 0.184 6.44 1.24

Zn Zone

Name

Top Bottom Gross

(m)

Net

(m)

N/G

ratio

Av Phi Av Sw Av

Vcl

Phi*H PhiSo*H

1 Bentiu-1 1754.89 1774.39 19.51 1.07 0.055 0.252 0.642 0.135 0.27 0.1

2 Bentiu-2 1774.39 1791.92 17.53 1.07 0.061 0.236 0.625 0.201 0.25 0.09

3 Bentiu-3 1791.92 1823.47 31.55 0 0 --- --- --- --- ---

All Zones 1754.89 1823.47 68.58 2.14 0.031 0.23.7 0.633 0.168 0.52 0.19

90



Zn Zone

Name

Top Bottom Gross

(m)

Net (m) N/G

ratio


1 Bentiu-1 1687.98 1710.69 22.71 11.28 0.497 0.246 0.508 0.209 2.77 1.37

2 Bentiu-2 1710.69 1728.52 17.83 6.55 0.368 0.231 0.463 0.157 1.51 0.81

3 Bentiu-3 1728.52 1750.92 22.4 10.82 0.483 0.229 0.642 0.256 2.48 0.89

4 Bentiu-4 1750.92 1770.28 19.35 7.32 0.378 0.22 0.955 0.198 1.61 0.07

5 Bentiu-5 1770.28 1796.64 26.37 9.75 0.37 0.24 0.929 0.19 2.34 0.17

6 Bentiu-6 1796.64 1846.78 50.14 28.19 0.562 0.244 0.912 0.187 6.89 0.61

7 Bentiu-7 1846.78 1883.05 36.27 $$8.08 0.223 0.219 0.978 0.139 1.77 0.04

All Zones 1687.98 1883.05 195.07 $$81.99 0.42 0.23 0.796 0.193 19.37 3.95


(m)

Net (m) N/G

ratio


1 Bentiu-1 1687.98 1710.69 22.71 8.84 0.389 0.249 0.397 0.189 2.2 1.32

2 Bentiu-2 1710.69 1728.52 17.83 6.21 0.342 0.233 0.43 0.159 1.42 0.81

3 Bentiu-3 1728.52 1750.92 22.4 5.98 0.252 0.238 0.471 0.277 1.34 0.71

4 Bentiu-4 1750.92 1770.13 19.2 0 0 --- --- --- --- ---

5 Bentiu-5 1770.13 1796.64 26.52 0 0 --- --- --- --- ---

6 Bentiu-6 1796.64 1846.78 50.14 0 0 --- --- --- --- ---

7 Bentiu-7 1846.78 1883.05 36.27 $$0.00 0 --- --- --- --- ---

All Zones 1687.98 1883.05 195.07 $$21.03 0.105 0.241 0.427 0.204 4.96 2.84

91

4.12 Discussion of Results

Lithology determination: the result obtained by using Neutron versus density

cross plot, showed that the cross plots of the neutron as a function of density show

that the sandstone is the main lithology of the Bentiu Formation with intercalation

of shale (Fig. 4.2).

From the petrophysics approach that were used to evaluate the Petrophysical

properties for Bentiu reservoir such as shale volume, porosity and water saturation,

to estimate the hydrocarbon potentiality in the study area.

The average porosity of Bentiu formation from 23% to 25.1% (Fig.4.8. a).

The volume of shale obtained by using Single curve indicators method and found

that the wells Hamra east-4 and Hamra east-1 showed shale volume relatively higher

compared to wells Hamra east-2 and Hamra east-3 in Bentiu formation and range

from 10 % to 30 % with an average value of 19 % (Table 4.4), therefore, the effective

porosity is influenced by the shale volume.

The estimated water saturation in Hamra east-1 and Hamra east-4 in the study

area ranges between 77-79.6%, which is relatively low compared to (Hamra east-3

and Hamra east-2) this result is confirm the hydrocarbon net pay as showing in

(Fig.4.13), and find that the hydrocarbon saturation has matched with the water

saturation in a reverse relationship (Fig.4.11 a & b)

The petrophysical parameters of the studied Bentiu Formation that obtained

from the processing of the available well logging data were averaged as shown in

Table (4.4), (4.6), (4.8) and Table (4.11). The contour maps of these parameters,

which are needed for the formation evaluation, were prepared to reflect the general

lateral distribution throughout in these study for Bentiu reservoir.

Cutoff determination: Sensitivity cut-off value was applied to the reference

parameters with the aim of determining net pay zones. The parameters and cut-offs

92

were selected respectively: volume of shale less than 40. %, porosity more than 16.

% and water saturation less than 70.0 %.

Cutoffs of shale content and porosity: Fig. 4.20 and Fig.4.21 used for the

determination of shale content cutoff and Porosity Cutoff respectively.

The sensitivity cutoff showed that, the volume of shale cutoff (Vsh) value for

reservoir and non-reservoir rock determined is 40%, which means that the rocks with

more than 40% of shale are regarded as non-reservoir rock, while rocks having less

than 40% of shale are regarded as reservoirs. The porosity cutoff is found > 16%,

which is used to discriminate between porous and non-porous ‘tight’ sand intervals

in the gross sand interval. It is an indicator for the lowest accepted effective porosity

that allows oil and gas to flow easily.

Water saturation cutoff is used to discriminate between the net pay productive

reservoir interval and the non-pay intervals in the porous intervals which can be

determined based on the water saturation-effective porosity cross plot as shown in

(Fig. 4.23). The intervals that contain water saturation greater than 70% are assumed

to be water wet or non-productive intervals, while the interval containing water

saturation less than 70% are considered oil wet or producing net-pay zones.

In other words, most of the productive hydrocarbon pay zones are characterized by

decrease in the water saturation less than its cutoff value (70%) and increase in the

effective porosity than its cut off values (16%), as well as low clay contents.

93

CHAPTER FIVE

CONCLUSIONS AND RECOMMENDATIONS

5.1 Conclusions

1- Quantitative Petrophysical analyses of the investigated reservoir for the studied

wells concluded that the clay volume ranges from 17-19 % while the effective

porosity ranges from 23 to 25%. the water saturation values ranges from 77 to 85.3%.

whereas the hydrocarbon saturation has matching with the water saturation in a

reverse relationship. by means The hydrocarbon occurrence decreases, where the

water saturation increases.

2- 3D model had been generated for hydrocarbon net pay the maximum net pay

21.03 m and the minimum net pay 2.14 m which were showing that the hydrocarbon

saturation is combatable with the decreasing of water saturation and also to show the

variations between wells, only Hamraeast-3 showed very low hydrocarbon net pay.

3- From the Porosity and shale volume maps, it is revealed that, the effective porosity

and water saturation are affected by the clay content.

4- It is concluded from petrophysical parameters that the reservoir in the study area

has high hydrocarbon saturation and contain many pay zones.

94

5.2 Recommendations

For accurate petrophysical interpretation the following suggestions is needed

to be considered:

Advance version of Interactive petrophysics should be used for better

interpretation and links the results between all wells.

Basic core analysis of reservoir zones of wells, needs to be done to confirm the

results of this study.

fluid flow modeling along the study area, based on the interpretation of seismic

data run in these field and integrated with the results of this report.

Carrying out of manual interpretation in the current study was very helpful

guide for software interpretation, it is advised therefore for similar research

projects.

95

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Related website Reference

[online]Availableat:http://www.terraplus.ca/products/borehole/sonic-probe.aspx

[Accessed 11 Mar. 2018].

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Petrophysical Evaluation and Reservoir Summation of Bentiu