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
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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
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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
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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
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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
Fig 4. 17: Petrophysical parameters of well HE-2 zone 1,2 and 3 for Bentiu
reservoir. ................................................................................................................ 78
Fig 4. 18: Petrophysical parameters of well HE-3 zone 1,2 and 3 for Bentiu reservoir
................................................................................................................................ 79
Fig 4. 19: Petrophysical parameters of well HE-4 zone 1,2 and 3 for Bentiu
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
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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
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 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
Av Phi Av Sw Av Vcl Phi*H PhiSo*H
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
Av Phi Av Sw Av Vcl Phi*H PhiSo*H
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
Table 4. 8: Reservoir Summary of well Hamra East-3
Table 4. 9: Pay Summary of well Hamra East-3
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 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
Table 4. 10: Reservoir Summary of well Hamra East-4
Table 4. 11: Pay Summary of well Hamra East-4
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 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
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 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
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