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DEPARTMENT OF PHYS

RESERVOIR CHARACTERIZATION AND VOLUMETRIC

ANALYSIS OF “LONA” FIELD, NIGER DELTA, USING 3

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OKWOLI, EMMANUEL PG/M.Sc/12/63668

Ogbonna Nkiru

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DEPARTMENT OF PHYSICS AND ASTRONOMY


ANALYSIS OF “LONA” FIELD, NIGER DELTA, USING 3

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ANALYSIS OF “LONA” FIELD, NIGER DELTA, USING 3-D

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RESERVOIR CHARACTERIZATION AND VOLUMETRIC ANALYSIS OF

“LONA” FIELD, NIGER DELTA, USING 3-D SEISMIC AND WELL LOG DATA

BY

OKWOLI, EMMANUEL PG/M.Sc/12/63668

A PROJECT WORKSUBMITED TO THE DEPARTMENT OF PHYSICS AND

ASTRONOMY, UNIVERSITY OF NIGERIA, NSUKKA, IN PARTIAL

FULFILMENT OF THE AWARD OF MASTER OF SCIENCE

SUPERVISORS:

DR P.O. EZEMA AND DR J.U. CHUKUDEBELU

JANUARY, 2015

CERTIFICATION

This is to certify that this project work was submitted and approved by the Department of

Physics and Astronomy in partial fulfilment for the requirements for the award of Master of

Science in Physics and Astronomy, University of Nigeria, Nsukka.

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________________________ __________________________

DR. P.O. EZEMADR. J.U. CHUKUDEBELU

(Project supervisor) (Project supervisor)

_____________________________

Prof. R.U OSUJI

(Head of Department)

DEDICATION

This project work is dedicated to God Almighty, who gave me the strength and wisdom to

carry out the work.

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ACKNOWLEDGEMENT

My sincere appreciation goes to God Almighty who made it possible for me to write this project.

I really appreciate my fatherly, caring, co-operating and understanding supervisors: Dr. P. O. Ezema

and Dr. J. U. Chukudebelu for their advice, constructive criticisms and suggestions towards the

successful completion of this work.

Also, my unreserved thanks to all academic and non academic staff of the department of Physics and

Astronomy, UNN, headed by Prof. (Mrs) R.U. Osuji for their contributions towards the successful

completion of this academic programme, God will reward you all accordingly.

I will never forget the effort of Dr. Daniel Obiora, Mr Johnson and my colleagues for their advice,

effort and contributions in the successful completion of this programme.

I appreciate the effort of my parents, Mr and Mrs J.M. Okwoli of Blessed memory, who gave me the

Educational foundation, which i am currently building on. I also want to appreciate my siblings who

stood with me financially, spiritually and otherwise within the period of this Program.

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TABLE OF CONTENT

TITLE PAGE i

CERTIFICATION ii

DEDICATION iii

ACKNOWLEDGEMENT iv

TABLE OF CONTENT v

LISTS OF FIGURES ix

LISTS OF TABLES xi

ABSTRACT xii

CHAPTER ONE: INTRODUCTION

1.1 Background 1

1.2 Purpose of study 2

1.3 Location ofthe study area 2

1.4 Geology of Niger Delta 4

1.4.1 Stratigraphy of the Niger Delta 4

1.4.2 Tectonics 7

1.4.3 Depobelts 8

1.4.4 Structural geology of Niger Delta 10

1.4.5 Hydrocarbon generation and its occurrence 14

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1.4.6 Source rock 15

1.4.7 Reservoir rock 16

1.4.8 Traps and seals 17

1.4.9 Migration 19

1.5 Justification for the study 19

1.6 Expected contribution to knowledge 19

CHAPTER TWO:LITERATURE REVIEW

2.1 Review of previous geophysical surveysusing seismic and well log

data in the Niger Delta 20

2.2 Review of previous geophysical survey using seismic and well log

data in other parts of the world 23

CHAPTER THREE: THEORY, MATERIALS AND METHODS OF STUDY

3.1 Theory of seismic surveying 25

3.2 Seismic waves 25

3.2.1 Body waves 25

3.2.2 Surface waves 27

3.3 Elastic characteristics of solids 28

3.4 Velocity of seismic waves 31

3.4.1 Factors affecting seismic wave velocity 31

3.4.2 Propagation of seismic waves 33

3.4.3 Reflection and transmission coefficient 33

3.5 Seismic energy sources 35

3.6 Detection and recording of seismic waves 36

3.7 Seismic prospecting methods 37

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3.7.1 Seismic reflection survey 38

3.7.2 Data acquisition 39

3.7.3 Seismic data processing 39

3.8 Log evaluation and Classification of geophysical well logs 40

3.8.1 Gamma ray logs 44

3.8.2 Sonic log 46

3.8.3 Density log 49

3.8.4 Resistivity logs 52

3.9 Data interpretation and procedure 55

3.9.1 Well data import 57

3.9.2 Delineation of lithologies 57

3.9.3 Identification of reservoirsDifferentiation of hydrocarbon and

non-hydrocarbonbearing zones 57

3.9.4 Well correlation 58

3.9.5 Determination of petrophysical parameters 58

3.10 Seismic data import 61

3.10.1 Picking of faults 61

3.10.2 Seismic to well tie 62

3.10.3 Mapping of horizons 62

3.10.4 Generation of time structure maps 62

3.10.5 Time to depth conversion 63

3.10.6 Generation of depth structure maps 63

3.11Reservoir area extent mapping 63

3.12 Volumetric Analysis 63

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CHAPTER FOUR: RESULTS AND DISCUSSION

4.1 Qualitative interpretation 64

4.2 Quantitative interpretation 67

4.3 Reservoirs 67

4.3.1 Reservoir Classification 69

4.4 Structural analysis 71

4.4.1 Horizons and faults 71

4.4.2 Time structural map 71

4.4.3 Depth structural map 76

4.5Volumetric analysis 80

CHAPTER FIVE: CONCLUSION AND RECOMMENDATION

5.1 Conclusion 81

5.2 Recommendation 82

REFERENCES 83

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LIST OF FIGURES

Figure 1.1:Location of the study area and the base map showing the seismic lines

3

Figure 1.2: Stratigraphic column showing the three formations of the Niger Delta.

5

Figure 1.: Schematic diagram of a seismic section from the Niger Delta continental

slope/rise showing the results of internal gravity tectonics on sediments at

the distal portion of the depobelt. 9

Figure 1.4: Examples of Niger Delta oil field structures and associated trap types 13

Figure 3.1: Elastic deformations and ground particle motions associated 26

with the passage of body waves. (a)P-wave. (b) S-wave.

Figure 3.2: Elastic deformations and ground particle motions associatedwith 26

the passage of surface waves. (a) Rayleigh wave. (b) Love wave.

Figure 3.3: The elastic moduli. (a) Young’s modulus E. (b) Bulk modulus K. 30

(c) Shear modulus µ. (d) Axial modulus ψ.

Figure 3.4: Logging configuration 43

Figure 3.5: Gamma ray sonde 45

Figure 3.6: The sonic tool 48

Figure 3.7: The formation density compensated tool 51

Figure 3.8: The deep induction logging tool 54

Figure 3.9: Suit of well logs used for data analysis 56

Figure 4.1: Well correlation panel across Lona 1 and 4 showing the 65

top & bases of reservoir 1, 2 and 3

Figure 4.2: Well correlation panel across Lona 2, 1 and 3 showing the 66

top & bases of R2 and R3.

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Figure 4.3: Reservoir ranking using average petrophysical parameters 70

Figure 4.4: Reservoir ranking using average permeability.70

Figure 4.5: Inline 6000 showing the mapped faults and horizons 72

Figure 4.6: Inline 5970 showing the tying of well to seismic

72

Figure 4.7: Time structure map for horizon 1 73

Figure 4.8: Time structure map for horizon 2

74

Figure 4.9: Time structure map for horizon 3 75

Figure 4.10: Depth structure map for horizon 1 77



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LIST OF TABLES

Table 3.1 Seismic Sources 35

Table 3.2 Typical seismic reflection coefficients 36

Figure 3.3 Seismic processing flowchart. 41

Table 4.1: Petrophysical parameters obtained for reservoir 1 68



Table 4.4: Average petrophysical parameters obtained for reservoir 1-3 70

Table 4.6: Volumetric analysis of Lona field 80

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ABSTRACT

An integrated 3-D seismic data, checkshot data and a suite of four well log located at the Lona field,

Niger Delta were analysed with Petrel software for reservoir characterization and volumetric analysis

of the field. The method adopted involves petrophysical analysis, structural analysis, volumetric

analysis and reservoir classification.

Detailed petrophysical analysis revealed three reservoirs.Average reservoir parameters such as

porosity (0.25), gross thickness (27 m), hydrocarbon saturation (0.66)permeability (3734 md) and net-

gross (0.54) were derived from the petrophysical analysis. Structural analysis of the data showed fault

assisted anticlinal structures which serve as structural traps that prevent the leakage of hydrocarbon

from the reservoirs.

The analysis of the all the well sections revealed that each of the sand units extends through the field

and varies in thickness with some unit occurring at greater depth than their adjacent unit that is

possibly an evidence of faulting. The shale layers were observed to increase with depth along with a

corresponding decrease in sand layers. From the analysis, particularly the resistivity log, all the three

delineated reservoirs were identified as hydrocarbon bearing units across the four wells i.e Lona1,

Lona2, Lona3 and Lona4.Volumetric study of the hydrocarbon in place shows that the reservoirs are

of appreciable areas and thicknesses. The volume of hydrocarbon originally in place was estimated to

be 550 thousand barrels of oil.

The three reservoirs have been classified using average results of petrophysical parameters. And

based on these, R1 is said to be the most prolific while R2 is the least prolific within Lona

field.

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CHAPTER ONE

INTRODUCTION

1.1 Background

The prolific demand for hydrocarbon products since the 20th century prompted intensified

exploration for oil and gas accumulation in reservoir rocks. This led to an extensive study of

the Niger Delta depocenters after a long while of non-productive search in the Cretaceous

sediments of the Benue Trough (Doust, 1989; Doust and Omatsola, 1990).

Understanding of reservoir characteristicsmost importantly porosity, permeability, water

saturation thickness and area extent of the reservoir are crucial factorsin quantifying

producible hydrocarbon (Schlumberger, 1989). These parameters are important because they

serve as veritable inputs for reservoir volumetric analysis i.e. the volume of hydrocarbon in

place (Edward, 1990).

Petroleum in the Niger Delta is produced from sandstone and unconsolidated sands

predominantly in the Agbada formation. It is necessary to delineate the hydrocarbon

reservoirs and evaluate them because they are the zones of interest for hydrocarbon

exploitations (Adewoyeet al., 2013).Based on reservoir geometry and quality, the lateral

variation in reservoir thickness is strongly controlled by growth faults; with the reservoirs

thickening towards the fault within the down-thrown block (Weber and Daukoru, 1975).

It is therefore neccessary to use technologically and economically viable methods in the

exploration and exploitation for hydrocarborn because geophysical survey and the subsequent

exploitation via drilling of wells require large capital.In order to avert any loss or wastage of

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resources, there is need to properly and adequately characterise a reservoir and to determine

the hydrocarborn in place. This will help to ascertain the hydrocarbon potential of the

reservoirs.

The objectives of this work are to make detailed use of available wireline log data to

delineate the reservoir units of the wells in parts of the Niger Delta, calculate the

petrophysical properties of the reservoir rocks, and infer the reservoir geometry distribution

and reservoir quality trends using the reservoir correlation. This study will provide an

understanding of the reservoir properties, and their lateral variation in thickness.

1.2 Purpose of study

The purpose of this study is to characterize the reservoirs and determine the hydrocarbon in

place in the study area. This is achieved by

i. Identification of the reservoirs and estimating the petrophysical parameters from

the well logs,

ii. generating time and depth structure of mapped horizons from structural analysis,

iii. carrying out a volumetric analysis in order to estimate the hydrocarbon in place.

1.3 Location of the study area

Lona field is located within the offshore area of Niger delta in Nigeria (Figure 1). The field

belongs to an active oil producing company in Nigeria. The Niger Delta is located in southern

Nigeria, between longitudes 30E (500,088 mE) and 90 E (1,165,306 mE), and between

latitudes 40 N (442,007 mN) and 60 N (666,735 mN) (Klett et al., 1997). The four wells; Lona

1, 2, 3 and 4 provided were aligned in the northwestern to the southeastern direction within

the study area.

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Figure 1.1:Base map of the study area showing the seismic lines and wells

Lona1

Lona 3

Lona 2

58

00

58

00

59

00

59

00

60

00

60

00

61

00

61

00

58

00

58

00

59

00

59

00

60

00

60

00

61

00

61

00

Lona 4

58

00

58

00

59

00

59

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60

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60

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61

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61

00

478000 480000 482000 484000

478000 480000 482000 484000

66000

68000

70000

72000

66000

68000

70000

72000

0 500 1000 1500 2000 2500m

1:50000

LONA FIELD NIGER DELTA.

mN

mE

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1.4 Geology of Niger Delta

A delta is a large accumulation of sediments deposited at the mouth of a river where it is

discharged into the sea with more than one channel called tributaries. It results from a stream

reaching a body of water such as the sea and building a deposit of sediments because of the

reduction of its velocity of flow.

1.4.1 Stratigraphy of Niger Delta

In an advancing delta such as that of the Tertiary Niger delta, sediments are stratigraphically

superimposed. The submarine delta fringe will encroach on sediments and will in turn, be

covered by a younger lower deltaic plain.

In the Niger delta, this sequence is modified by the numerous transgressions which have

occurred from time to time, breaking the continuity of the main overall regression, and

becoming stratigraphically superimposed (Short and Stauble, 1967). The thick wedge of the

Niger delta is considered to consist of three units Benin, Agbada and Akata formations

(Figure 1.2). These formations are strongly diachronous and cut across the time stratigraphic

units which are characteristically S-shaped in cross section. The typical sections of these

formations are described by Short and Stauble (1967) and summarized in a variety of papers

(Avbovbo, 1978; Doust and Omatsola, 1990; Kulke, 1995). These three geologic formations

in the Niger Delta are discussed below:

i. Benin formation

The Benin formation overlies the Agbada formation. The age of the formation is oligocene in

the north, and becomes progressively younger southwards. To date, very little hydrocarbon

deposits have been found in this highly porous and generally freshwater bearing formation

(Short and Stauble, 1967). The Benin formation extends from the west across the whole

17

Figure 1.2: Stratigraphic column showing the three formations of the Niger Delta. (Modified

from Shannon and Naylor, 1989; and Doust and Omatsola, 1990).

18

Niger Delta and has been described as coastal plain sands which outcrop in Benin, Onitsha

and Owerri provinces. It consists of massive continental lsands; gravels with thickness

ranging from 0.2 to 100metres.The sand and sandstone are coarse to fine and commonly

granular in texture. In general, they appear to be poorly sorted, sub-angular to well rounded.

The sand and sandstone may represent point bar deposits, channel fills and natural levees

while the shale may be interpreted as black swamp deposits and oxbow fills.

ii. Agbada formation

This is a paralic sequence of sandstone and shale underlying the Benin formation. It consists

of the sandy parts, which serve as the main hydrocarbon reservoir of the Delta and shale as

the cap rock. This sequence is associated with syn-sedimentary growth faulting. The Agbada

formation is thickest at the center with a maximum thickness of 457.2m (Doust and Omatsola,

1990).The upper part is predominantly sandy unit minor shale intercalation and a lower shaly

unit, which is thicker than the upper sandy unit. The formation was deposited beginning from

the Eocene and continued into the Recent. The formation consists of paralic siliciclastics over

3700 meters thick, and represents the actual deltaic portion of the sequence. In the lower

Agbada formation, shale and sandstone beds were deposited in equal proportions; however,

the upper portion is mostly sand with only minor shale inter-beds. The depositional

environment is therefore defined as “transitional” between the upper continental Benin

formation and the marine underlying Akata formation. It is Miocene in the north and

Pliocene/Pleistocene in the south and has a maximum thickness of possibly 4600 meters.

(Doust and Omatsola, 1990)

The proliferous Agbada formation is divided into four distinct members:

a. D-1 member which is predominantly an alternating sequence of regressive sands and

marine shale with minor oil and gas reservoir.

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b. Qua-Iboe consisting of thick pile of shale with thin intercalated sands that are possible

oil and gas reservoir in some places

c. The Rubble bed consisting of heterogeneous mixture of eroded Biafra sand and shale.

d. The Biafra member is predominantly of alternating sequence of sand and shale. It

contains principally oil and gas reservoir (Doust and Omatsola, 1990).

iii. Akata formation

This unit is composed of deeper marine shale, the deepest stratigraphic unit. It is chiefly

represented by plastic, low density, under-compacted and high-pressure shallow marine to

deep water-shale; with only local inter-beddings of sands and/or siltstones. It is deposited as

the high-energy delta advanced into deep water. In general, the shale is overpressured and

this provides the mobile base for subsequent growth faulting associated with the deposition of

the overlying paralic sequence. It serves as the hydrocarbon source in the Niger Delta.

Majority of wells drilled in the Niger Delta only penetrated into the marine Akata Shale.

Little of the formation has been drilled; therefore, not much is known about this formation. It

is estimated that the formation is up to 7,000 meters thick (Doust and Omatsola, 1990).

1.4.2 Tectonics

The tectonic framework of the continental margin along the West Coast of equatorial Africa

is controlled by Cretaceous fracture zones expressed as trenches and ridges in the deep

Atlantic. The fracture zone ridges subdivide the margin into individual basins, and in Nigeria,

form the boundary faults of the Cretaceous Benue-Abakaliki trough, which cuts far into the

West African shield. The trough represents a failed arm of a rift triple junction associated

with the opening of the South Atlantic. In this region, rifting started in the Late Jurassic and

persisted into the middle Cretaceous (Lehner and De Ruiter, 1977). Shale mobility induced

internal deformation and occurred in response to two processes (Kulke, 1995). First, shale

20

diapirs formed from loading of poorly compacted, overpressured, pro-delta and delta-slope

clays (Akata formation) by the higher density delta-front sands (Agbada formation). Second,

slope instability occurred due to a lack of lateral, basin ward, support for the under-

compacted delta-slope clay (Akata formation) (Figure 1.3). For any given depobelt, gravity

tectonics were completed before deposition of the Benin formation and are expressed in

complex structures, including shale diapirs, roll-over anticlines, collapsed growth fault

crests, back-to-back features, and steeply dipping, closely spaced flank faults (Evamy et al.,

1978; Xiao and Suppe, 1992). These faults mostly offset different parts of the Agbada

formation and flatten into detachment planes near the top of the Akata formation.

1.4.3 Depobelts

Deposition of the three formations occurred in each of the five offlapping siliciclastic

sedimentation cycles that comprise the Niger Delta. These cycles (depobelts) are 30-60

kilometers wide, prograde southwestward, 250 kilometers over oceanic crust into the Gulf of

Guinea (Stacher, 1995), and are defined by syn-sedimentary faulting that occurred in

response to variable rates of subsidence and sediment supply (Doust and Omatsola, 1990).

Each depobelt is a separate unit that corresponds to a break in regional dip of the delta and is

bounded landward by growth faults and seaward by large counter-regional faults or the

growth fault of the next seaward belt (Evamy et al., 1978; Doust and Omatsola, 1990).Five

major depobelts are generally recognized, each with its own sedimentation, deformation, and

petroleum history. Doust and Omatsola (1990) describe three depobelt provinces based on

structure. The northern delta province, which overlies relatively shallow basement, has the

oldest growth faults that are generally rotational, evenly spaced, and increases their steepness

seaward. The central delta province has depobelts with well-defined structures such as

successively deeper rollover crests that shift seaward for any given growth fault.

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Figure 1.3: Schematic diagram of a cross section from the Niger Delta continental slope/rise

showing the results of internal gravity tectonics on sediments at the distal portion of the

depobelt. The Late Cretaceous-Early Tertiary section has low velocity gradient, probably

marine shales, whereas the Late Tertiary has a normal velocity gradient, suggesting a much

sandier facies. (Modified from Lehner and De Ruiter, 1977; Doust and Omatsola, 1990).

22

Last, the distal deltaprovince is the most structurally complex due to internal gravity tectonics

on the modern continental slope.

1.4.4 Structural geology Of Niger Delta

One of the most conspicuous geological features of the Niger Delta is its growth faultpattern.

The Niger Delta oil province is characterized by East-West trendingsyn-sedimentary faults

and folds. The energy responsible for their genesis is most likely to be inherent in the

sedimentsthemselves rather than in any external orogenic forces. In fact, they are believed to

be gravityfaults contemporaneous with rapid sedimentation and initiated by the differential

loadingof the underlying and mobile (laterally and vertically) under-compacted Akata

shale.The sedimentation and gravity faulting has resulted in the deposition ofthicker

sediments on the down-thrown than on the up-thrown block. Besides, because ofthe large

weight of sediments deposited in the delta front and the down dip subsidenceaccompanying

this deposition, the strata have been tilted basin ward.Most of the oil accumulated in the

Niger Delta is contained in the rollover anticlinestructure. The oil in these structures may be

trapped in dip closures or against a Syntheticor antithetic fault.

The delta sequence is deformed by syn-sedimentary faulting and folding. Evamy et al.(1978)

described the main structural features of the Niger Delta as growth faults androllover

anticlines.

i. Growth Faults

Growth faults are formed as a result of rapid sedimentation along the edge of the Niger Delta,

on top of clay and they are characterized by the occurrence of thicker sediments onthe down-

thrown block relative to the up-thrown block. Growth faults are mostly termed

contemporaneous fault (Weber andDaukoru, 1975; Evamy et al., 1978;Doust&Omatsola,

1990) and they are important in interpretation because they serve asmajor path for

23

hydrocarbon migration from marine shale of the Akata formation to thereservoir sand of the

Agbada formation of the delta.

Rapidsand deposition along the Delta edge on top of under-compacted clay has resultedin the

development of a large number of syn-sedimentary gravitational faults. These socalled

“growth faults” are also well known from U.S. Gulf coast.The spacing between successive

growth faults decrease with an increase of depositionalslope or an increase in rate of

deposition over the rate of subsidence. Growth faults tendto envelop local depocentres at their

time of formation. Their trend is thus an indicationof the prevailing sedimentological

pattern.The name “growth fault” derives from the fact that after their formation, the fault

remainsactive and thereby allows a faster sedimentation in the downthrown relative to

theupthrown block. Evamy et al. (1978) classified growth faults into structure building

faults,crestal flankfaults. The combined effects of the growth faults are a strongrollover of the

northern flank. As a result, the upper surfaces of Akata formation alsobecome markedly

curved and gravitational instability causes the shale bulge to moveupward. This in turn led to

the formation of antithetic faults.

a. Structure-building faults

These are the faults which define the up-dip limit of themajor rollover structures. In the

horizontal plane, they are essentiallyconcave in a down-dip direction. The degree of curvature

varies from being rather linearin the east to truly crescent-shaped in the western and southern

part of the Delta. Thecurvature of the structure-building fault at their lateral extremities

creates a mappingproblem because of the way they repeat each other in the strike directions.

In some placesthe structure-building faults repeat each other. Where these occur,

thestructure-building faults die out in the flanks of the adjacent rollover structures.

24

b. Crestal faults

A rollover structure may contain one or more crestal faults. They arecharacteristically parallel

to the axis of the structure and differ from structure-building faultsin that they show less

curvature in the horizontal plane (Figure 1.4). They are generallysteeper in the vertical plane.

They display less growth, which also tends to be lesscontinuous. In some structures, the

crestal faults have very large vertical displacements.At depth, they may bring sandy marine

shales-some crestal faults even cut the slip planeof the structure-building fault.

c. Flank faults

These faults as their name suggest, are located on the southern flanks ofmajor rollover

structures. Although they may show some rollover deformation at shallowlevels, southerly

dips are typical on either side of the fault at depth.

d. Major counter regional faults

Major counter-regional growth faults are located at thesouthern end of regional flanks.

Antithetic faults also have counter-regionalnature, but they are of secondary structural

importance and display no growth, beingsimple compensation for extension in the

overburden. K- type faults are essentially flankfaults. They are considered as a separate class

only because of their extremely close spacing, which gives rise to a multiplicity of narrow

fault blocks. They are common (as their name implies) in shell-BP original “K” block.

ii. Rollover anticline

The rollover anticline is formed as a result of reversal of dip section such as by rotation of a

block resulting from sliding along a curved fault plane usually associated with gravity

faulting coinciding with deposition of sediments. These are the reversal of dip direction as

produced by rotation of a curve (listric) fault plane usually associated with gravity faulting

contemporaneous with deposition.

25

Figure 1.4. Examples of Niger Delta oil field structures and associated trap types. (Modified

from Doust and Omatsola, 1990; Stacher, 1995).

26

1.4.5 Hydrocarbon generation and its occurrence

Hydrocarbons are compounds of carbon formed as result of breakdown of organic

matterdeposited alongside sediments in a reducing environment, from its original state

tokerogen and then to hydrocarbon under the right temperature, pressure, and

chemicalconditions. Evamy et al. (1978) set the top of the present-day oil window in the

NigerDelta at the 240°F (115° C) isotherm.

In the northwestern portion of the delta, the oil window (active source-rock interval) liesin

the upper Akata formation and the lower Agbada formation, to the southeast, the topof the oil

window is stratigraphically lower (up to 1220 m) below the upper Akata/lowerAgbada

sequence (Evamy et al., 1978). Although there are argumentsover the effects of the ratios of

sand/shale overburden on the depth to top of the oilwindow, it is believed that the depth

increases southwards as reported Beka and Oti(1995).

The process through which hydrocarbons migrate from the source to reservoir rocks

wasexamined by Hunt (1990). He related this process to the case of the Gulf of Mexico

underthe assumption that the phenomenonis plausible in the Niger Delta. Beka and Oti(1995)

predicted a biastowards lighter hydrocarbons (gas and condensate) from the over-pressured

shale as aresult of down-slope dilution of organic matter as well as differentiation associated

withexpulsion from overpressured sources.

Petroleum occurs throughout the Agbada formation of the Niger Delta. However,

severaldirectional trends form an “oil-rich belt” having the largest field and lowest gas/oil

ratio(Ejedawe, 1981; Evamy et al., 1978; Doust and Omatsola, 1990). The belt extends

fromnorthwest offshore area to southeast offshore and along a number of north-south trends

inthe area of Port Harcourt. It roughly corresponds to the transition between continental

andoceanic crust, and is within the axis of maximum sedimentary thickness. Ejedawe(1981)

27

states that the two factors controlling the distribution of petroleum are; anincrease geothermal

gradient relative to the minimum gradient in the delta centre and thegenerally greater age of

sediments within the belt relative to those further seaward.Weber (1987) indicates that the

oil-rich belt (“golden lane”) coincides with aconcentration of rollover structures across

depobelts having short southern flanks andlittle paralic sequence to the south. Doust and

Omatsola (1990) suggest that thedistribution of petroleum is likely related to heterogeneity of

source rock type (greatercontribution from paralic sequences in the west) and/or segregation

due to remigration.

1.4.6 Source rock

Based on the volume, organic-matter content and type of the Akata shale,it is believed tobe

the source rock. However, there has been much discussion about the source rock

forpetroleum in the Niger Delta (Evamy et al., 1978; Ekweozor et al., 1979; Ekweozor

andOkoye, 1980; Lambert-Aikhionbare and Ibe, 1984; Bustin, 1988; Doust and

Omatsola,1990).Possibilities include variable contributions from the marine interbedded

shale in theAgbada formation and the marine Akata shale, and Cretaceous shale (Weber

andDaukoru, 1975; Evamy et al., 1978; Ejedawe et al., 1979; Ekweozor and Okoye,

1980;Ekweozor and Daukoru, 1984; Lambert-Aikhionbare and Ibe, 1984; Doust and

Omatsola,1990; Stacher, 1995; Frost, 1977; Haack et al., 1997).

The Agbada formation has intervals that contain organic carbon contents sufficient to

beconsideredgood source rocks (Ekweozor and Okoye, 1980; Nwachukwu and

Chukwura,1986). The intervals, however, rarely reach thickness sufficient to produce a

world-classoil province and are immature in various parts of the delta (Evamy et al.,

1978;Stacher, 1995). The Akata shale is present in large volumes beneath the Agbada

28

formation and is at least volumetrically sufficient to generate enough oil fora world class oil

province such as the Niger Delta.

Based on organic-matter content and type, Evamy et al.(1978) proposed that both themarine

shale (Akata formation.) and the shale interbedded with paralic sandstone (lowerAgbada

formation) are the source rocks for the Niger Delta oils.

1.4.7 Reservoir rock

Petroleum in the Niger Delta is produced from sandstone and unconsolidated

sandspredominantly in the Agbada formation. Characteristics of the reservoirs in the

Agbadaformation are controlled by depositional environment and by depth of burial (Tuttle et

al., 1999). Known reservoir rocks are Eocene to Pliocene in age, and are often stacked,

ranging in thickness from less than 15meters to 45 metersthickness (Evamy et al., 1978).

The thicker reservoirs likely represent composite bodies of stacked channels (Doust

andOmatsola, 1990). Based on reservoir geometry and quality, Kulke (1995) describes

themost important reservoir types as point bars of distributary channels and coastal

barrierbars intermittently cut by sand-filled channels. Edwards and Santogrossi (1990)

describethe primary Niger Delta reservoirs as Miocene paralic sandstones with 40%

porosity,2darcys permeability, and a thickness of 100 meters.The lateral variation in reservoir

thickness is strongly controlled by growth faults; thereservoir thickens towards the fault

within the down-thrown block (Weber and Daukoru,1975). The grain size of the reservoir

sandstone is highly variable with fluvial sandstonestending to be coarser than their delta front

counterparts; point bars fine upward, andbarrier bars tend to have the best grain sorting.Much

of this sandstone is nearly unconsolidated, some with a minor component ofargillo-silicic

cement (Kulke, 1995). Porosity only slowly decreases with depth becauseof the young age of

the sediment and the low temperature regime of the delta complex (Tuttle et al., 1999). In the

29

outer portion of the delta complex, deep-sea channel sands, low-stand sandbodies, and

proximal turgidities create potential reservoirs (Beka and Oti, 1995).

1.4.8 Traps and seals

Most known traps in Niger Delta fields are structural, although, stratigraphic traps are

notuncommon (Figure 1.5). The structural traps developed during syn-

sedimentarydeformation of the Agbadaparallic sequence (Evamy et al., 1978; Stacher, 1995).

Thestructural complexity increases from north (earlier formed depobelts), to the south

(laterformed depobelts) in response to increasing instability of the under-

compactedoverpressured shale. Doust and Omatsola (1990) describe a variety of structural

trappingelements, including those associated with simple rollover structures; clay filled

channels,structures with multiple growth faults, structures with antithetic faults, and

collapsedcrest structures. The primary seal rock in the Niger Delta is the interbedded shale

within the Agbada formation. The shale provides three types of seals-clay smears along

faults, interbeddedsealing units against which reservoir sands are juxtaposed due to faulting,

and verticalseals (Doust and Omatsola, 1990). On the flanks of the delta, major erosional

events ofearly to middle Miocene age formed canyons that are now clay-filled. These clays

formthe top seals for some important offshore fields (Doust and Omatsola, 1990).

i. Structural traps

The majority of the hydrocarbon traps in the Niger Delta are structural. Theywereformed as a

result of syn-sedimentary structural deformation of sediments in the Nigerdelta. Folding

however is not a reliable guide in searching for hydrocarbon pool becauseof a change in

shape, size, and amplitude in depth and shift in their lateral position inpassing from surface to

depth.

30

Folding and faulting that occur below buried unconformities are frequently not indicatedat

the surface. Pools trapped by normal faulting are almost always on the upper side ofthe fault

because oil and gas escape up dip around the end of the fault. Those that formed in the lower

side are rare if at all found.

ii. Stratigraphic traps

These are traps formed due to lateral variation in the lithology of the reservoir rocks, or

abreak in its continuity. It is due to the character of the material in the reservoir rock andthe

condition under which it was being deposited. It could be formed when a permeablereservoir

rock changes to a less permeable or to an impermeable rock.Stratigraphic traps could also be

formed when a reservoir rock is truncated by anunconformity or by original deposition of the

strata-like channel sandstone or lift bar,leading to lithologic and stratigraphic variation of the

reservoir rock. This changes cause local variation in porosity or termination of reservoir rock

up-dip. Stratigraphic traps arenot as conspicuous as structural traps on seismic sections due to

insufficient acousticimpedance contrast between elements forming the trap.

iii. Combined structural and stratigraphic traps

These are sometimes regarded as the third type of traps. These traps are formed by

bothstructural and stratigraphic trap forming mechanisms. They exhibit both structural

andstratigraphic features. Instances include a faulted diapiric stratigraphic trap, salt

domeoverlying domes and faults compaction anticlines and salt dome-cap rock in

reservoir.They are in most cases complex and best trap system.

31

1.4.9 Migration

The process of primary migration is the movement of oil and gas out of the source rocks into

the permeable reservoir rocks. Secondary migration is a process by which fluids move within

a porous reservoir rock or from one reservoir rock to another. Faults in this case are highly

relevant as means by which the fluids can migrate. In Niger delta, the best evidence for the

vertical conductivity of major boundary faults is the fact that in most cases the fault

intersection with the upper bedding plane of the reservoir functions as the spill point of the

accumulation.At the level of the Akata formation, the major growth faults offset a thickness

of up to several thousand meters of overpressured shale against paralic sediments in the

downthrown block. A plausible migration may thus be from the overpressured shale into and

through the fault zone.

1.5 Justification for the study

One of the major challenges in hydrocarbon exploration and development is the proper

delineation of reservoir extent for volumetric computation and optimization of well

placement. The sole reliance on structural interpretation in reservoir characterisation has

reduced the accuracy and resolution of results.

1.6 Expected contribution to knowledge

The study is expected to;

(a) enhance knowledge of the subsurface geology and structural setting of the study area;

(b) enable an evaluation of the hydrocarbon potential of the field.

32

CHAPTER TWO

LITERATURE REVIEW

Research has shown the use of well and seismic data in reservoir characterizationboth within

and ouside the Niger Delta depocenters.

2.1 Review of previous geophysical survey using well and seismic data in the Niger Delta

Adaeze et al. (2012) carried out petrophysical evaluation of Uzek well. The study essentially

determined reservoir properties such as lithology, depositional environments, shale volume,

porosity, fluid saturation among others from well log and cores, which are variables that

determine reservoir quality. The analysis identified four hydrocarbon bearing reservoirs; I, P,

Q and R. Average permeability values of the reservoirs is above 100 md, while porosity

values ranged between 20 to 30 %, reflecting well sorted coarse grained sandstone reservoirs

with minimal cementation, indicating very excellent reservoir quality. Plots of porosity

values against permeability values showed fairly strong linear relationships between the two

variables in all the reservoirs indicating that uzek well reservoirs are permeable and have

pores that are in strong communication. Hence the petrophysical properties of the reservoirs

in uzek well are enough to permit hydrocarbon production.

Egba and Agbogun (2012) used mathematical modelling method of petrophysical parameters

to characterize reservoirs in Kwale area of Delta state, Nigeria. They concluded that most

reservoirs in the wells are gas bearing zones with hydrocarbon saturation ranging from

74.18% to 94.64% with high resistivity values.

Reservoir characterisation and formation evaluation of some parts of Niger delta using 3-D

seismic and well log data was carried out by Abe and Olowokere (2013). In this work, only

one reservoir was delineated across the wells. The result of this analysis has proved that the

integration of attribute analysis with structural interpretation is a reliable and efficient way of

33

carrying out formation evaluation and reservoir characterisation. It has also enhanced

hydrocarbon exploration for optimal well placement and reserve estimation.

A suite of geophysical wire-line logs from an oil field in Niger Delta have been successfully

examined and analysed by Abraham-Adejumo (2013) for the purpose of Well correlation

and petrophysical analysis of “Rickie” field onshore Niger Delta. Litho-stratigraphic

correlation sections of four wells (R1, R2, R3 and R4) depict that the subsurface stratigraphy

is that of sand – shale interbedding. Three prominent hydrocarbon bearing reservoirs (L, P

and S), located at depths of 2,943 m, 3,248 m and 3935 m were identified and mapped.

Petrophysical parameters of the reservoirs which included porosity, hydrocarbon saturation,

volume of shale, formation resistivity and formation factor were also computed for ‘Rickie’

oil filed.

Petrophysical and structural analysis of ‘maiti’ field, Niger Delta, using well logs and 3-D

seismic data was carried out by Adewoye et al. (2013). In this work, Well logs, checkshot

and 3-D seismic data have been evaluated to delineate oil bearing sand reservoirs, to

determine the petrophysical parameters and to analyse the geologic structures within ‘Maiti’

field. Three wells were evaluated and three hydrocarbon reservoirs were delineated as R1,

R2, and R3. From the result it was deduced that reservoir R1 is the most prolific reservoir

while R2 is the least prolific. The structural analysis shows a fault assisted anticlinal structure

known as structural trap within ‘Maiti’ field, Niger Delta, Nigeria.

Amigun and Bakare (2013) carried out reservoir evaluation of “Danna” field Niger Delta

Using petrophysical analysis and 3D seismic interpretation. The petrophysical analysis

carried out on the sand bodies indicates three sand units that are hydrocarbon bearing

reservoirs (Sand J, Sand M and Sand P). Time and depth structural maps were generated from

34

seismic data to study the field’s subsurface structures serving as traps to hydrocarbon and

estimate the prospect area of the reservoirs in acres. From the analysis of the well and seismic

data, the gas reserve was estimated to be 225,997 bbl/ft3 while the oil reserve for the three

reservoirs (Sand J, Sand M and Sand P) is computed as 6,566,089.09 bbl/acre, 14,006,716

bbl/acre and 42,746, 580 bbl/acre respectively.

Amigun and Odole (2013) used petrophysical properties to evaluate wells for reservoir

characterisation of ‘SEYI’ oil field (Niger-Delta). The analysis of the different petrophysical

parameters indicate the presence of hydrocarbon in all the reservoirs. Computed

petrophysical parameters across the reservoirs gave porosity as ranging from 0.22 to 0.31;

permeability 881.58 md to 14425.01 md and average hydrocarbon saturation of 41.44%,

20.29%, 30.82%, 37.92%, 51.20%, 91.97% and 85.11% for reservoir A, B, C, D, E, F and G

respectively. These results together with the determined movable hydrocarbon index (MHI)

values (0.05 to 0.75) of the reservoir units suggest high hydrocarbon potential and a reservoir

System whose performance is considered satisfactory for hydrocarbon production.

Ihianle et al. (2013) used three dimensional seismic/well logs to carry out the structural

interpretation over ‘X – Y’ field in the Niger Delta area of Nigeria. The seismic section and

structure map revealed fault assisted closures at the center of the field, which correspond to

the crest of rollover anticlines and which served as the trapping medium. The estimated

volume of hydrocarbon in place within the interval ranging from 3,909.06m (12,825ft) to

4,053.84m (13,300ft) was calculated as 289,227,007 bbl (37,281acre-ft) of oil. The study

showed the feasibility of integrating borehole data and structural map in mapping reservoir

fluid boundaries towards calculating the volume of hydrocarbon in place.

Structural style and reservoir distribution in deep-water Niger Delta: A Case Study of “Nanny

Field” was carried out by Adeoti et al. (2014).The results from the seismic interpretation and

35

well log data showed that in the inner fold and thrust belt synthesis of the structural province

is characterized by complex; broad scale thrust cored anticlines and imbricates structures that

are widely spaced. This spacing creates accommodation space for reservoir development. The

analysis of the transition zone reveals that the structural province is typified by large areas of

little or no formation. From the findings, it was inferred that shallow reservoirs have higher

porosity and permeability than reservoirs that are emplaced deeper stratigraphically.

Integrated 3D seismic and petrophysical data was employed by Edigbue et al. (2014) to

evaluate hydrocarbon of ‘Keke’ field in the Niger Delta. Two sand units (S1 and S2) which

existed between 9127ft and 11152ft were correlated and mapped using gamma ray log. The

results obtained from the analysis of this field shows that the trapping mechanisms and the

petrophysical parameters in ‘Keke’ field are favourable for hydrocarbon accumulation.

2.2 Review of previous geophysical surveys using well and seismic data in the other

parts of the world

Dorrington et al.(2004) successfully used Neural-network prediction of well-log data with

seismic attributes in characterizing the reservoir. This study presented a new method for

seismic attribute selection using a genetic-algorithm approach. The genetic algorithm

attribute selection uses neural-network training results to choose the optimal number and type

of seismic attribute for porosity prediction. Thus the use of a supervised neural-network is

adopted to predict bulk porosity using seismic attributes.

Reservoir characterization and facies prediction within the Late Cretaceous Doe Creek

Member, Valhalla field, west-central Alberta, Canada was carried out by Stacy et al. (2010).

The reservoir within the field is subdivided into four thin (1–10 m [3–33 ft]), cyclic

alternations of offshore mudrock and shoreface sandstone that are designated as I − 1, I, I +

1, and I + 2 units. Open-hole well logs are used to predict depositional facies and calcite

36

cement occurrence in wells that lack core control. Facies distributions predicted for the I

sandstone closely match trends of the sandstone gross pore volume and daily total fluid

production, and suggest that open-hole well logs may be used to anticipate reservoir quality

and continuity.

Reservoir characterization of sand-prone mass-transport deposits within slope canyons was

carried out by Lawrence et al. (2011). In this work, seismic cross sections show that sands,

visualized as single seismic loops, have flat bases and rugose tops, and occur above a

characteristically chaotic, low-amplitude seismic facies. Well logs and whole-rock cores over

each of these three reservoir-prone intervals indicate that there is a preferred facies

association. This association is a muddy debrite (corresponding to the chaotic seismic facies)

overlain by massive sands and composite sandy and/or mixed-lithology breccias, in turn

overlain by thinbedded turbidites, culminating in thin-bedded hemipelagic sediments.

Conglomerates punctuate the stratigraphic column but are most prevalent in the lowermost

part of the succession.

Simon et al. (2013) carried out depositional interpretation and reservoir characterization of

the Tithonian in Mizzen F-09, Flemish pass basin, Canada. The core obtained from the

Bohdrán formation Ti-3 member in Mizzen F-09 is representative of the thickness and quality

of the Tithonian reservoir sandstones that exist in the Flemish Pass and adjacent Orphan

basins. The discovery of the Mizzen field has established a proven hydrocarbon accumulation

in the Flemish Pass, and may signal the opening stages of a new oil province in an

underexplored Canadian frontier basin.

37

CHAPTER THREE

THEORY, MATERIALS AND METHODS OF STUDY

3.1 Theory of seismic surveying

3.2 Seismic waves

Seismic waves are parcels of elastic strain energy that propagate outwards from a seismic

source such as an earthquake or an explosion (Kearey et al.,2002). Sources suitable for

seismic surveying usually generate short-lived wave trains, known as pulses, which typically

contain a wide range of frequencies. Except in the immediate vicinity of the source, the

strains associated with the passage of a seismic pulse are minute and may be assumed to be

elastic. On this assumption the propagation velocities of seismic pulses are determined by the

elastic moduli and densities of the materials through which they pass through.

3.2.1 Body Waves

These are the waves that propagate through the body of an elastic solid. They can be

subdivided into 2 groups; these are compressional and share waves.

i. Compressional (primary) wave, like the wave that reaches one’s ear from a sound

source, consists of a series of compressions and rarefactions of the transmitting medium. The

medium therefore undergoes rapid small changes both in volume and shape (Figure 3.1). The

38

Figure 3.1Elastic deformations and ground particle motions associated with the passage of

body waves. (a) P-wave (After Reynolds, 1997) (b) S-wave (From Bolt, 1982).

Figure 3.2:Elastic deformations and ground particle motions associated with the passage of

surface waves. (a) Rayleigh wave. (b) Love wave. (After Bolt, 1982).

39

velocity of such a wave is therefore proportional to both the bulk modulus of the medium (its

capacity to resist change of volume) and its rigidity (the instantaneous resistance it offers to

deformation by elastic shear).

ii. Shear (secondary) or transverse wave on the other hand, represents displacement

of the particles of the medium in the direction perpendicular to the propagation direction;

changes of shape is imposed on the medium but without change in volume. Thus, the velocity

of a shear wave is directly proportional only to the rigidity of the medium, which is the

reason why shear waves cannot be transmitted by fluids; rigidity is the fundamental

characteristic of elastic solids.A horizontal travelling shear wave so polarized that the particle

motion is all vertical is designated as an SV wave but when its motion is all in the horizontal

plane, it is then called an SH wave.

Note that for most consolidated rocks Vp/Vs fall within1.5-2.0. As shear deformation cannot

be sustained in a fluid, shear waves will not propagate in fluid materials at all. This accounts

for one of the limitations of the S-wave in hydrocarbon prospecting.

3.2.2 Surface waves

These propagate through the free surface of solids; i.e. they do not penetrate deep into

subsurface media. The surface waves typically constitute noise in seismic prospecting.

i. Rayleigh waves:These waves travel along the free surface of a solid material with

particle motion in the vertical plane. The speed of Rayleigh wave is slower than forany

other body wave and are believed to be the principal component of ground rollwhichare

of large amplitude; low frequency surface waves that obscure/mask useful reflectionson

seismic records during oil exploration hence they are considered to be noise.

40

ii. Love waves:Love waves are surface waves which travel along a low speed layer

overlying a higher speed stratum. The wave motion is horizontal and transverse.

Surface waves have the characteristics that their waveform changes as they travel because

different frequency components propagate at different rates, a phenomenon known as wave

dispersion. The dispersion patterns are indicative of velocity structure through which the

waves travel and thus waves generated by earthquakes can be used in the study of the

lithosphere. Body waves are non-dispersive. In exploration seismology, Rayleigh waves

manifest themselves normally as large amplitude low-frequency groundroll, which can mask

reflections on a seismic record and thus are considered to be noise, which can be further

reduced by filtering during data processing (Figure 3.2).

3.3 Elastic characteristics of solids

A solid body can be deformed by the application of an external force. If the solid is perfectly

elastic, it will return to its original shape once that force is removed. In the context of

exploration seismology, the earth can generally be considered as perfectly elastic because the

stress generated by seismic exploration activities are too small to permanently deform

subsurface rocks. The elastic limit is the maximum stress that can be applied to a solid

without permanently deforming it. When an impulsive or transitory stress is applied to a

finite area on the surface of an elastic solid, a strain is generated in the immediately adjacent

sub volume. The strained sub volume then transfered stress to adjacent interior areas within

the solid, which generates strains in the surrounding sub volumes. In this fashion an

impulsive

stress propagates through a solid as an elastic wave. Elastic waves that propagate in the earth

are known as seismic waves.

41

All frequencies contained within body waves travel through a given material at the same

velocity, subject to the consistency of the elastic moduli and density of the medium through

which the waves are propagating. The fomulae for the elastic moduli is prsented as: (After

Reynolds, 1997)

� Axial Modulus = ��

�� =

�/�

∆�/�= σ/ε (3.1)

In the case of triaxial strain

� Bulk Modulus K = �� (∆�)

�� (∆�/�) (3.2)

In the case of excess hydrostatic pressure

� Shear Modulus (a Lame’s constant)

µ = ��

�� (3.3)

(µ = 1.7 x 104 Mpa: µ = 0 for fluids)

Relationship between Young’s modulus (E), Poisson‘s ratio (σ) and the Lame’s constants (µ

and λ)

E = �(�� !�)

(� �),σ = �

!(� �)K = �� !�

� (3.4)

and λ = &σ

(' σ)('(!σ) (3.5)

42

Figure 3.3:The elastic moduli. (a) Young’s modulus E. (b) Bulk modulus K. (c) Shear

modulus µ. (d) Axial modulus ψ. (After Reynolds, 1997)

43

3.4 Velocity of seismic waves

The rates at which waves propagate through elastic media are dictated by the elastic moduli

and the densities of the rock through which they pass. Seismic wave velocities are functions

of density and elastic moduli; in sedimentary rocks they are affected by the compositions of

the rocks, their maximum depths to which they have been buried, the porosities and the fluids

occupying the pore spaces and by the fluid pressures exerted by them.

The velocity of a body, V, depends on the elastic constant and the density

V= ()) �) ��**��

��+�� ) ½ (After Reynolds, 1997)

For P wave, VP= ( ,

-)½ (3.6)

But E = . + 0�1

Therefore VP = {( . + 0�1

)/ρ}½ (3.7)

For S wave, VS = (1

-)½ (3.8)

K is always positive; hence VP is greater than VS.

The ratio VP/VS is defined in terms of Poisson’s ratio and is given by

2 =(�3 �4)⁄ 6(!

!{(�3 �4⁄ )6('} (3.9)

3.4.1 Factors affecting seismic wave velocity

Seismic waves velocities in porous granular media are controlled by lithology; the types and

the chemistry of the fluids filling the pore spaces, stress and signal frequency.

i. Effect of lithology

There is a general trend for velocity and density to increase with depth of burial and age of

formation. Velocity ranges are so broad and there is so much overlap that velocity alone does

not provide a good basis for distinguishing lithology. Sand velocities, for example, can be

44

smaller or larger than shale velocities, and the same is true for densities; both velocity and

density play important roles in seismic reflectivity.

ii. Effect of porosity

This is the ratio of void space in a rock to the total volume of rock . Porosity depends on

depth of burial and pressure so, velocity is sensitive to these factors also. Velocity is

generally lowered when gas or oil replaces water as the interstitial fluid, sometimes by so

much that amplitude anomalies result from hydrocarbon accumulations.

iii. Effect of pore shape and anisotropy

The shape of the rock pores also affect the velocity. When porosity increases, velocity

decreases.

iv. Effect of density

The density of a rock is the volume-weighted average of the densities of the rock

constituents. Rocks vary in density because they vary in porosity. The velocity and density

depend on the mineral composition, granular nature of rock matrix, cementation, porosity,

fluid content and environmental pressure. The densities of igneous and metamorphic rocks

are generally higher than those of sedimentary rocks because they have low porosity.

v. Effect of age

Older rocks have had longer time to be subjected to cementation, tectonic stresses and so on

which decrease porosity. Older rocks generally have higher velocities than younger rocks.

vi. Effect of interstitial fluid

The pores in oil and gas reservoirs are filled with varying amounts of saturated fluids, mostly

salt water. The replacement of this water by oil or gas changes the bulk density, and elastic

45

constants of the reservoir. The velocities of compressional waves are higher in rocks that

contains brine, intermediate in oil and very low in gas. The P-wave velocity and the reflection

coefficient also change. These changes are sometimes sufficient to indicate the presence of

oil or gas.

vii. Effect of depths of burial and pressure

With increasing depth the velocity increases partly because the pressure increases and partly

because cementation occurs at the grain to grain contacts. Cementation is the more important

factor.Porosity generally decreases with increasing depth of burial (or overburden pressure)

and hence velocity increases with depth.

3.4.2 Propagation of seismic waves

Following an explosion, a spherical cavity is created with its periphery forming a zone of

permanent deformation. However, at further distance away from the cavity, the seismic

energy induces elastic deformation. The particle motion associated with its deformation can

be a time varying function.

The physical basis for propagation of wave is Huygens’s principle, which states that every

point on an advancing wavefront is the envelope tangent to all secondary waves. The

principle is used to describe reflection and refraction at layer boundaries and diffraction from

sharp discontinuities in the subsurface.

3.4.3 Reflection and transmission coefficient

When a compressional ray of amplitude A0normally incident on an interface between two

media of differing velocity and density, a transmitted ray of amplitude A2 travels on through

the interface in the same direction as the incident ray and a reflected ray of amplitude A1

returns back along the path of the incident ray.

46

The reflection coefficient ( R.C) , is therefore the ratio of the amplitude of the reflected ray

( A1) to the amplitude (Ao) of the incident ray (AfterKaerey and Brooks, 1984).

9. ; = <=<>

(3.10)

Defining the acoustic impedance (Zi) of layer i as Zi =ρiVi where ρi and Vi are the density

and P wave velocity respectively of the layer,

For normal incident ray;

9. ; = ?6(?=?6 ?=

(3.11)

then,

9. ; = -6�6(-=�=@6�6 @6�=

(3.12)

where ρ1, V1, Z 1, and ρ2, V2, Z2, are the density, P-wave velocity and acoustics impedance

values in the first and second layers, respectively.

Note that whatever energy not reflected is usually transmitted into the lower medium,

Thus the transmission coefficient T.C is the ratio of the amplitude A2 of the transmitted ray

to the amplitude A0 of the incident ray.

9. ; = <6<>

(3.13)

T.C = 1 - R.C since T.C + R.C = 1

Therefore for a normal incident ray ;

A. ; = !?=?6 ?=

(3.14)

Reflection coefficient (R) for interfaces between different rock types rarely exceed 0.5 and

are typically less than 0.2 (Kearey and Brooks, 1984), and sea beds usually cause the

strongest reflections in seismic sections (Table 3.1).

47

Table 3.1Typical Seismic reflection coefficients(After Kaerey and Brooks, 1984) .

Interface Approximate R.C

Air 1.0

Sea over Limestone 0.65

Sea over Clay 0.45

Sea over Sand 0.30

Clay over Gas -0.30

Sea bed multiples 0.2

Sand /Shale over Limestone 0.20

10% change in acoustic impedance ±0.05

3.5Seismic energy sources

The aim of using any seismic source is to produce a large enough signal in the ground to

ensure sufficient depth penetration and high enough resolution to image the subsurface.

Some basic requirements of a seismic source include:

i. Short duration source pulse (with high enough frequency) for the required

resolution.

ii. A source wave of known shape.

iii. Minimal source –generated noise.

There are 3 basic types of seismic source in use presently (Table 3.2). Selection of the most

appropriate source type for a particular survey is very important.

In selecting a seismic source, there is always a fundamental consideration between depth

penetration and minimum resolution, which is dependent upon one-quarter wavelength. To

achieve good depth of penetration requires a low –frequency source but this usually has low

48

resolution. High resolution shallow seismic survey requires higher frequency sources which

usually have restricted depth penetration.

TABLE 3.2: Seismic sources(After Reynolds, 1997)

TYPE LAND WATER

Impact Sledge hammer

Drop-weight

Accelerated weight

--

Impulsive Dynamite

Detonating Cord

Air gun

Shot Gun

Air Gun

Gas Gun

Sleeve Gun

Water Gun

Steam Gun

Vibration Vibroseis

Vibrator Plate

Rayleigh wave generator

Multi-pulse

Geochirp

3.6 Detection and recording of seismic waves.

Seismic energy released from the source are detected and recorded via detector/receiver and

recording stations.

� Detectors/recievers.

There are 2 main types of detectors/receivers:

i. Geophones:These are electromechanical transducers that convert seismic energy

to electrical energy on land. They are sensitive to particle motion.

ii. Hydrophones: These are piezoelectric transducers that convert pressure to

mechanical energy and are sensitive to vertical signals only.

Phones are planted in electrically connected patterns for cancellation of noise. They can be

connected either in series or in parallel. Their output which goes into a single amplifier

channel represents the ground motion at the center of the group currently, multi-channel

(48/96) phone group are laid out at a time.

49

3.7 Seismic prospecting method

Seismic surveying is one among other geophysical exploration methods that employ the

principles of physics. Specifically, the physical properties of rocks are sensed remotely to

determine the disposition of the rocks below the surface of the earth. Waves passing through

the earth during earthquakes travel with velocities that are dependent upon the elastic

properties of the rocks through which they pass. They are reflected from, and refracted by

discontinuities in these rocks. It is from the study of wave motions in thousands of earth

quakes that the greater part of our understanding of the earth’s interior has been derived.

Because exploration for petroleum is concentrated on layered sedimentary rocks, which have

no great range of densities or electrical properties and little magnetic signature, petroleum

geophysical exploration is practically synonymous with seismology. The exploration

seismologist simply creates a tiny earthquake of his own and studies the reflection and

refraction patterns of the waves he creates.

The seismic method of exploration involves the measurement of the travel times of refracted

or reflected waves at the interface between strata/media having different velocities and /or

densities. Therefore the geophysicist regards the earth as a series of layers with rather abrupt

changes in physical properties between them vertically but only rather gradual changes

laterally along a layer. In essence, the reflection seismic method explores these bouncing

sound wave between these various rocks layers. The travel times to and from various

interfaces enable the geophysicist to estimate depth, structural dip, and possible lithology

within the earth.

There are two methods of seismic exploration: refraction and reflection. The seismic

refraction surveying method utilizes seismic energy that returns to the surface after traveling

through the ground along refracted ray paths. Refraction is sometimes used as a depth probe

50

in a reconnaissance survey to determine the depth and velocity of high velocity member, such

as carbonate or evaporate layer or basement rock. The most frequently used application of

refraction technique is to map the base of the seismic weathered layer or low velocity layer

(LVL). The method is good for investigating the shallow part of the earth crust.The problem

of hidden layer, also known as low velocity or velocity inversion has limited the use of

seismic refraction method in today’s exploration.

The seismic reflection method determines the location and attitude of the two way travel time

of primary reflectors and infers the geologic structures. The seismic waves generated are

reflected back from a reflector within the earth from which there is an acoustic impedance

contrast. The intensity of the reflected wave depends on the velocity and density contrast of

the layers and the contained pore fluids.

3.7.1 Seismic reflection survey

This geophysical method of exploration involves generating an impulse at the earth’s surface

(source) and elastic disturbances propagating to a reflector in the surface. Any boundary

(interface) between rock layers with different properties can constitute a seismic reflector.

Due to a difference in the acoustic properties at this boundary, a part of the energy is

transmitted back to the surface (by reflection) where it is detected by a receiver. The output

of the receiver is time, representing the time at which the reflection is received, and is given

by twice the depth of the reflector divided by the average velocity between the reflector and

the Receiver.

The main objective of a seismic reflection survey is to obtain a regional structural geological

control of a sedimentary pile whose rudimentary data have been provided by other

geophysical methods (such as magnetic and gravity) and outcrop sections. Generally, seismic

method is used at different scales of investigation ranging from the mapping of sedimentary

51

basins, mapping of fault patterns within producing fields; mapping depositional packages to

ascertain sand and pore fluid distribution and more detailed actual depth-controlled seismic

data acquisition (Vertical Seismic Profiling -VSP) from drilled wells.

3.7.2 Data acquisition

The acquisition system involves the passage of acoustic waves into the subsurface and

measurement of time where source and spread of receivers are arranged in gridded array. The

objective is to record the reflection signal which appears on the record as a curved event or

wavelet (Seismic trace) with variations in amplitude. Undesirable signals, known as noise,

such as the direct waves which travel along the surface between shot points and receivers and

the refracted waves which travel along the boundary of high velocity layers are also present.

These may be attenuated during recording or by subsequent processing.

By moving the source and receivers along the grids, a seismic line is formed from individual

field records (traces). The three (3) main components in all acquisition systems include

source (at a shot point position), aspread of receivers and a recording instrument.

3.7.3 Seismic data processing

The objective of seismic data processing is to improve signal-to-noise ratio (SNR), and

improve the vertical resolution of the individual seismic traces by waveform manipulation as

to facilitate interpretation of the data.

� Signal processing

The aims of signal processing are

i. To enhance signal and reduce noise (random or coherent) and

ii. To produce a set of seismic traces, called a section, whose display is a representation of the

structure of the reflecting surface on a cross- section or slice through the earth crust .

52

The major processing steps should involve Deconvolution, Stacking and Migration. Other

processing techniques includethose shown in the flow chart (Table 3.3).

3.8 Log evaluation and classification of geophysical well logs

After seismic interpretation has been carried out and confirmatory analysis has been done to

ascertain a hydrocarbon bearing reservoir at a particular depth, a well is drilled. Some

information is revealed about the formation encountered in the drilled hole and these are

recorded as a function of depth on logs. Logs provide good information about the vertical

resolution of the survey area unlike the seismic section, which provide a good lateral

resolution.

Well logging, also known as borehole logging is the practice of making a detailed record (a

well log) of the geologic formations penetrated by a borehole. Log analysis is useful in

delineating reservoirs and estimating its properties (Mode and Anyiam, 2007).

The log may be based either on visual inspection of samples brought to the surface

(geological logs) or on physical measurements made by instruments lowered into the hole

(geophysical logs) (Figure 3.4). After a section of the well is drilled, logs are obtained by

lowering a sonde or tools attached to a cable or wire to the bottom of a well bore filled with

drilling mud. Electrical, nuclear or acoustic energy is sent into the rock and returned to the

sonde or are obtained from the rock and measured as the sonde is continuously raised from

the bore bottom at a specific rate. The well is logged when the sonde arrives at the top of the

interval to be investigated.

53

Table 3.3 Seismic processing flowchart.(After Kaerey and Brooks, 1984) .

Field note Sort Field tapes

CMP Gather

Mute First Break

Dephase

Spreading Corrections

QC Plot

Deconvolution

Residual Statics

Corrections Stack

Datum Correction

Nmo Corrections

Array Simulation

Filter

Dereverberation

Migration

Amplitude Adjustments

Instrument response

Velocity Analysis

Decon Test

Field notes

Filter Tests

Water Depths

QC Plot

Inversion

54

Formation water, porosity, permeability, radioactivity are rock properties that affect logging

and the types of logs to be obtained. Well logging is done when drilling boreholes for oil and

gas, groundwater, minerals, and for environmental and geotechnical studies. Many modern

oil and gas wells are drilled directionally. At first, loggers had to run their tools somehow

attached to the drill pipe if the well was not vertical. Modern techniques now permit

continuous information at the surface. This is known as logging while drilling (LWD) or

measurement-while-drilling (MWD). MWD logs use mud pulse technology to transmit data

from the tools on the bottom of the drill string to the processors at the surface.

Wireline logs can be classified into three groups;

a. Lithology logs (spontaneous potential, gamma ray).

These logs discriminate different lithologies

b. Resistivity logs (induction, electrode)

They are used to delineate reservoirs and in combination with porosity logs they are used to

calculate hydrocarbon saturation.

c. Porosity logs (sonic, neutron, density).

These are logs used to identify lithology, calculate porosity, and differentiate oil from gas.

55

Figure 3.4: Logging configuration ( Telford et al., 1990)

56

3.8.1 Gamma ray logs

The gamma ray log is a measurement of natural radioactivity of the formation. The log

normally reflects the shale contents of the formation in a sedimentary formation. This is due

to the concentration of radioactive elements in clay and shales. Very low level of radioactive

elements is present in clean formation, unless radioactive contaminants such as volcanic ash

or granite wash are present.

� Equipment

The gamma ray sonde contains a detector to measure the gamma radiation originating in the

volume of formation near the sonde (Figure 3.5). The total gamma ray level is recorded and

plotted in API units on a scale of 0-150 API.

� Principle of Measurement

Gamma rays are burst of high energy electromagnetic waves emitted spontaneously by

unstable elements. Such elements are thorium, uranium and potassium which contribute to all

the natural radiation in sedimentary rocks. In passing through matter, gamma rays experience

successive Compton –scattering collisions with atoms of the formation material losing energy

with each collision. After gamma ray has lost enough energy, it is absorbed by means of

photoelectric effect, by an atom of the formation.

Thus natural gamma rays are gradually absorbed and their energies reduce as they pass

through the formation. The gamma ray log response after appropriate corrections is

proportional to the weight concentrations of the radioactive material in the formation.

The standard unit of measurement is API (American Petroleum Institute) units and it is

normally presented in track 1 of a composite log

57

Figure 3.5: Gamma Ray Sonde (Stacy et al., 2010)

58

� Applications

(i) Well-to-well correlation;

(ii) Lithology indicator;

(iii)Open hole and cased hole usage;

(iv) Evaluation of shale content.

� Auxiliary Functions:

(a) Permeable bed definition;

(b) Evaluation of radioactive minerals/delineation of non-radioactive mineral beds.

3.8.2 Sonic log

The sonic tool measures the interval transit time (∆t) of a compressional sound

wavetravelling through one foot of a formation. The (∆t) measurement is the reciprocal of

thevelocity of an acoustic sound wave. The unit of velocity (V) is meter per second, that

of(∆t) is microsecond per foot.

� Equipment

A transmitter sends out a sound pulse. The difference in arrival time of the pulse ismeasured

with two receivers (R1 and R2), which are 60cm apart (Figure 3.6). A secondtransmitter and

pair of receivers measure the same physical parameter in the oppositedirection.

� Principle of measurement

Sonic tools in current use are of the borehole compensated type. Compressional sound pulse

is emitted into the borehole. As the BHC transmitter is pulsed alternately, interval transit time

values are read on alternate pairs of receivers. The interval transit time values from the two

sets of receivers are averaged automatically by a computer on the surface. Consequently, four

modes of propagation to a distance receiver in the borehole include;

59

i. Compressional wave – Sound pulse is refracted at the borehole wall into the

formation at a critical angle determined by Snell’s law and travels through the

formation. It is then refracted back as a P –wave to the receiver where it is

changed to an elastic signal for transmission to the surface. Normally, the P- wave

is the first arrival at the distant receiver.

ii. Shear wave- Compressional pulse is refracted into the formation at a different

critical angle and converts to an S-wave where it travels down the formation with

an S-wave velocity. It is refracted back into the borehole and reconverted to a P-

wave to reach the receiver.

iii. Direct wave- This wave of relatively high frequency, travels down the borehole

fluids directly to the receiver.

iv. Tube wave- The pulse strikes the formation at normal incidence and sets up a

standing wave that propagates down the borehole interface where it is transmitted

back normally to the receiver.

� Applications

(a) Calibration of seismic data.

(b) Identification of compaction trends

(c) Correlation of wells.

(d) Lithology identification.

60

Figure 3.6: The sonic log (a) A simple sonic tool. (b) A borehole-compensated sonic log

(Kearey et al., 2002).

61

3.8.3 Density log

The formation density log is a porosity log that measures electron densityof a formation.The

density logging device is a contact tool which consists of a medium-energy gammaray source

that emits gamma rays into the formation. The gamma ray source is eitherCobalt-60 or

Cesium-137.Density logging results from the following phenomena:

i. Photoelectric absorption effect: - This occurs at low energy levels about

0.1Mevwhere the incident gamma ray is captured by an atom and a photoelectron

isejected.

ii. Compton scattering effect: - This occurs at higher energy levels from 0.075 to

2Mev where there is an ejection of a Compton recoil electron and an

incidentgamma ray of slightly lower energy.

iii. Pair production: - This occurs above 2Mev and is uncommon because the

conventionalgamma ray logging sources have energy levels considerably less than

2Mev.

� Equipment

The formation density compensated tool (FDC) makes use of two detectors, the shortand long

spacing detectors. This logging tool types automatically corrects for mud cakeand near

borehole problems. The short spacing detector is mainly affected bythe mud cake, the

difference between the long and short spacing density gives acorrection to be added to or

subtracted from the long spacing according to their signs.

� Principle of Density Logging Equipment

The density tool (Figure 3.7) has two detectors. Formation density compensated tool (FDC),

which provide some measure of compensation for borehole conditions. When the emitted

rays collide with electrons in the formation, the collisions result in a loss of energy from the

62

gamma ray particle. The scattered gamma rays that return to the detector in the tool are

measured in two energy ranges. The number of returning gamma rays in the higher energy

range, affected by Compton scattering, is proportional to the electron density of the

formation. The principle of density logging is predominantly by Compton scattering effect. It

involves the emission of medium energy gamma ray into a formation through a radioactive

source (i.e. Cesium 137) attached to the sonde.

These gamma rays may be high velocity particles that collide with the electrons in the

formation. A gamma ray would lose some of its energy to the electron at each collision and

then continues with diminishing energy. The scattered gamma ray reaching the detector at a

fixed distance from the source is counted as an indicator of the formation density.

The number of Compton scattered collision is related to the number of electrons in the

formation. A mathematical expression is shown below.

ne = BC

��, where, ne = number of electrons per unit volume, N = Avogadros number (6.02 x

1023), Z = Atomic number, A = Atomic weight, P = Density of material

Formation bulk density (ρb) is a function of matrix density, porosity, and density of the fluid

in the pores (salt, mud, fresh mud, or hydrocarbons). To determine density porosity by

calculation, the matrix density and type of fluid in the borehole must be known. The formula

for calculating density porosity is:

ØEFG = -HI(-J-HI(-K

(Dresser Atlas, 1979) (3.15)

where: Øden= density derived porosity,ρma= matrix density, ρb= formation bulk density

ρf= fluid density (1.1 salt mud, 1.0 fresh mud, and 0.7 gas)

63

Figure 3.7: The formation density compensated tool (Telford et al., 1990)

64

� Applications

(a) Determination of formation porosity.

(b) Identification of minerals in evaporate deposits;

(c) Gas zone detection.

(d) Determination of hydrocarbon density.

(e) Evaluation of shaly sands and complex lithology.

(f) Oil-shale yield determination

(g) Calculation of overburden pressure and rock mechanical properties.

3.8.4 Resistivity logs

Resistivity logs are electric logs which measure the resistance of a formation to thepassage of

an electric current. Because the rock’s matrix or grains are non-conductive,the ability of the

rock to transmit a current is almost entirely a function of water in thepores. Hydrocarbons,

like the rock’s matrix, are non-conductive; therefore, as thehydrocarbon saturation of the

pores increases, the rock’s resistivity also increases.

LM = (N

ØH× PQ

PR)' GS (Archie, 1942) (3.16)

where: Sw = water saturation, F = formation factor ( N∅H), a = tortuosity factor,

m = cementation exponentRw= resistivity of formation water

Rt= true formation resistivity as measured by deep reading resistivity log, n = saturation

exponent (most commonly 2.0)

The resistivity log can be classified into; Induction logs: - Measures conductivity of

formation, Electrode logs: - Measures resistivity of formation.

Resistivity logs can also be classified based on depth of investigation, i.e flushed, invadedand

un-invaded zones respectively.

65

i. Deep induction logs (ILD)

The induction log was developed to measure formation resistivity in boreholes containingoil

based mud, because electrode device do not work in these non-conductive muds.Induction

logging devices focus formation current in order to minimize the influence ofborehole and of

the surrounding formations. They are designed for deep investigation andreduction of the

influence of the invaded zone.

� Equipment

The sonde consist of two sets of coils; transmitter coil and receiver coil. They are housedin a

non-conductive fibre glass (Figure 3.8). An oscillator feeds a constant current to

thetransmitter coil.

� Principle of Measurement

The induction tool consists of one or more transmitting coils that emit a high-

frequencyalternating current of constant intensity (Figure 3.8). The alternating magnetic

fieldwhich is created induces secondary currents in the formation. The multiple coils are

usedto focus the resistivity measurement to minimize the effect of materials in the

borehole,the invaded zone, and other nearby formations. These currents flow in circular

groundloop paths coaxial with the transmitter coil. The ground-loop currents, in turn, create

magnetic fields which induce signals in the receiver coil. The measuring circuit balances the

signal produced by direct coupling of transmitter and receiver coil. The induction log

operates to advantage when the borehole fluid is an insulator- air, gas or fresh water mud. It

is also effective in the conductive mud, provided that the mud is not too salty, the formation

is not too resistive, and the borehole diameter not too large.

66

Figure 3.8: (a) simple induction log (b) A focused induction log (Kearey et al., 2002).

67

� Log presentation

The log is presented in logarithmic grid of the log-linear grid on track 2. However, the

conductivity logs are recorded in either track 2 or 3. Induction logs are scaled.

� Applications

(a) It is used to measure true resistivity of formation,

(b) It is used in non-conductive fluids such as oil, and air based drilling mud,

(c) Gives better results in low resistivity formations,

(d) Determine hydrocarbon versus water-bearing zones

(e) indicate permeable zones,

(f) determine resistivity porosity,

Other types of log used for borehole investigation are formation tester (which measure

formation pressure), sidewall sampler (small rock samples are collected and used for

lithology and fluid type) and dip-meter and F.M.S (measures dip and azimuth).

3.9 Data interpretationprocedure

Suites of four geophysical well logs and seismic data obtained from an active oil company in

Nigeria, recorded at various locations within the Lona field, Niger Delta basin was used in

these work. These well logs are shown in Figure 3.9.

The given data was properly studied, and then sorted into format which is PETRELTM

compatible. All the data files were stored in a location on the PC, from where it is accessed.

Before the interpretation process, PETRELTM workflow has defined folders, which are

symbolic. According to PETRELTM workflow, the following procedures were followed for

the data analysis.

i. Well data import

ii. Delineation of lithologies

68

Figure 3.9: Suite of well logs used for data analysis.

10300

10400

10500

10600

10700

10800

10900

11000

11100

11200

11247

SSTVD

1:3606

0.00 150.00GR 0.20 2000.00LLD -0.031.10 1.13 2.81RHOB

sand

sand

shale

sand

sand

sand

sand

sand

sand

sand

shale

sand

shale

sand

shale

shale

sand

litho Legend

GR = Gamma ray log

LLD = resistivity log

RHOB = Density log

Track 1 Track 2 Track 3

Hydrocarbon

water contact

69

3.9.1 Well data import

The sequence of data import begins with the well heads and logs. The well heads file, contain

the well name, surface location of the wells (2D-XY coordinate system), Kelly bushing (Kb),

the top depth and bottom depth. This will allow the display of well position on the base

map.The logs(gamma ray, resistivity, density, porosity, water saturation and volume of shale)

were then imported for the four wellsLona 1, 2, 3 and 4 respectively.

3.9.2 Delineation of lithologies

Sand and shale bodies were delineated from the gamma ray log signatures. Sand bodies were

identified by deflection to the left due to the low concentration of radioactive minerals in

sand while deflection to the right signifies shale which is as a result of high concentration of

radioactive minerals in it.

3.9.3 Identification of reservoirs and differentiation of hydrocarbon and non-

hydrocarbon bearing zones

Reservoirs are subsurface formations that contain water and hydrocarbon. They were

identified by using the log signatures of both gamma and resistivity logs. Intervals that have

high resistivity are considered to be hydrocarbons while low resistivity zones are water

bearing intervals.

A combination of the gamma ray and resistivity logs were used to differentiate between the

hydrocarbon and non-hydrocarbon bearing units. The gamma ray and resistivity logs are

shown in tracks 1 and 2 of figure 3.9 The scale increases from left to right, with a range of 0 -

150 for the gamma ray log and 0.2-2000 ohm meter for the resistivity. As the hydrocarbon

saturation increases, resistivity also increases; on the other hand as water saturation increases,

the resistivity decreases. This is indicated by the deflection on the resistivity log. The

hydrocarbon-water contact (HWC) is indicated on Figure 3.9.

70

3.9.4Well correlation

The logs were activated and displayed on the well section window, on which correlation was

carried out using the lithology log (Gamma ray log), the resistivity was used to check the

fluid contents present within the sediments i.e. hydrocarbon or water. The top and base of the

reservoir were picked.

3.9.5 Determination of petrophysical parameters

i. Determination of gross and net sand reservoir thickness

Gross reservoir thickness interval is the interval covering shale and sand within areservoir.

Net thickness of sand is the interval covering only sand within a reservoir. It iscalled net

productive sand. The gross reservoir thickness is determined by knowinginterval covering

both sand and shale within the reservoir studied using gamma ray log.Net sand thickness is

determined by subtracting the interval covering the shale from grossreservoir thickness.

Well log data were used in this analysis to generate rock properties using these formulae

GST(Gross sand thickness) = Base of sand-Top of sand. (3.18)

NST (net sand thickness) = (base + top of sand- shale) if shale is present in the formationand

if not NST will be the same as GST

NTG (Net to gross) = (NST/GST) (3.19)

ii. Volume of shale (Vsh).

The gamma ray log was used to calculate the volume of shale in a porous reservoir. Thefirst

step used to determine the volume of shale from a gamma ray log was the calculationof the

gamma ray index using the equation:

IVP =VPWXY(VPHZ[VPHI\(VPHZ[

(3.20)

where: IGR = Gamma ray index, GRlog = Gamma ray reading of the formation, GRmin =

Minimum gamma ray (clean sand), GRmax = Maximum gamma ray (shale).

71

All these values were read off within a particular reservoir. Having obtained the gammaray

index, volume of shale was then calculated using the Dresser Atlas (1979) formula,

]̂ _ = 0.083(2�.a×bcd – 1.0) (Tertiary consolidated sand) (3.21)

iii. Porosity (Ø).

Porosity is defined as the percentage of voids to the total volume of rock. The

formationdensity log was used to determine formation porosity. The porosity wasdetermined

by substituting the bulk density readings obtained from the density log withineach reservoir

into the equation 3.22 (Dresser Atlas, 1979).

ØEFG = -HI(-J-HI(-K

(3.22)

where, ØEFG. Is the density derived porosity, ρmais the matrix density = 2.65gm/cm3

(sandstone), ρfl is the fluid density= 1.1gm/cm3 (fluid density), ρb = formation bulk density

The criteria for classifying porosity given by Baker (1992) is:

Ø < 0.05 = Negligible, 0.05 < Ø <0.1 = Poor, 0.1 Ø< 0.15 = Fair, 0.15 < Ø < 0.25 = Good,

0.25 < Ø <0.30 = Very good Ø > 0.30 = Excellent.

iv. Formation factor (F)

The formation factor was determined from the Archie’s (1942) equation below;

e = ( N∅H) (3.23)

where: Ø= Porosity, a = constant (0.62), m = cementation exponent (2 for sands).

v. Estimation of water saturation

Determination of the water saturation for the uninvaded zone was achieved using theArchie’s

(1942) equation:

LM! = f×PQ

PR (3.24)

72

Bute = PXPQ

(3.25)

Thus,

LM! = PX

PR (3.26)

where, Sw= water saturation of the uninvaded zone, Ro= resistivity of formation at 100%

water saturation, Rt= true formation resistivity, F = formation factor

vi. Hydrocarbon saturation (Sh)

This is the percentage of pore volume in a formation occupied by hydrocarbons. It

wasobtained by subtracting the value obtained for water saturation from 100%.

i.e., Sh = (100 – Sw) % (3.27)

where,

Sh = Hydrocarbon saturation, Sw = Water saturation

vii. Irreducible water saturation (ghijj)

This is the water held in the pore spaces by capillary forces. When a zone is at irreducible

water saturation (Sl� ), the water saturation in the univaded zone (LM) will not move because

it is held in grains by capillary pressure. For most reservoir rocks, irreducible water saturation

ranges from less than 10% to more than 50% (Schlumberger, 1979). It was determined from

the equation given by Asquith and Gibson (1982)

ghijj =√f

!nnn (3.28)

viii. Permeability (K)

It is the ability of a rock to transmit fluid. It is related to porosity but it is not always

dependent on it. It is controlled by the size of the connecting passages (pore throats or

capillaries) between pores. It is measured in darcies or millidarcies. Equation 3.29 was used

73

to derive the permeability of each reservoir that was identified (After Asquith and

Krygowski, 2004).

o = [!qn×Ør

ghijj]! (3.30)

where ghijjis the irreducible water saturation

A practical oil field rule of thumb for classifying permeability (Baker, 1992): poor to fair =

1.0 to 14 md, moderate = 15 to 49 md, good = 50 to 249 md, very good = 250 to 1000 md, >1

darcy = excellent.

ix. Estimation of hydrocarbon pore volume (HCPV)

The hydrocarbon pore volume (HCPV) is the fraction of the reservoir volume occupiedby

hydrocarbon. This was calculated as the product of density porosity and

hydrocarbonsaturation and the volume as:

HCPV = Øden × (1 – Sw) x V (3.30)

WhereØdenis the average porosity obtained from density log, the volume (V) is the product of

the area of the closure obtained from depth structure map and the reservoir thickness

3.10 Seismic data import

The seismic volume is imported into a user defined folder in SEG-Y formatand then realized.

From the realized volume, inline, crossline are inserted. After loading into memory, time

slice was also inserted. A 3-D window and a new interpretation window was used to view

and also to carryout fault mapping. The faults were mapped on the crosslines and the

continuity viewed on the inlines.

3.10.1Picking of faults

A fault is a break in continuity of any geologic unit, which has involved either a lateral or

vertical movement of any part of the rock unit, caused by varying geologic processes. The

74

major difference between fault and fracture is that displacement of unit is associated with

fault while no displacement whatsoever is associated with fracture.

Conditions for fault mapping used are:

(a) Abrupt termination of reflection events

(b) Displacement or distortion of reflection

Most of the faults seen on the seismic section were not continuous across the seismic volume,

but major and minor faults that were continuous were mapped. Fault planes and fault

polygons using the variance attribute time slice were generated. The faults were posted on the

surfaces using the fault polygons.

3.10.2 Seismic to well tie

In order to ensure the continuity of events both on the seismic section and wells, well to

seismic tie was done. On a 3-D window, the wells with the reservoir tops and bases were

displayed. This was superimposed on the seismic lines to ensure that there was accurate tie

between the well and seismic event.

3.10.3 Mapping of Horizons

A horizon is a surface separating two different rock layers. The surface is identified by

distinctive reflection pattern that can be observed over a layer with relatively large extent.

Identification of prospective sand is from the composite logs available. In area without well

control, strong reflection on the seismic section can be selected for mapping. Time to depth

conversion was done, and the corresponding depth structure map was produced.

3.10.4Generation of time structural maps

The horizons mapped on both cross line and inline were used to generate a 3-D grid that was

autotracked and used to generate time structure maps for the top and base of the reservoirs.

75

3.10.5Time to depth conversion

Time to depth conversion was done with checkshot data.

3.10.6Generation of depth structure maps

The time structural maps were converted into the corresponding depth maps using the

checkshot data provided.

3.11Reservoir area extent mapping

The area extent of each reservoir was determined from the depth structural maps. The last

close contour was gridded in square and the length of the square was determined. Using

Area= L×L, (3.32)

the area of a single square was obtained. The total number of the square within the reservoir

was multiplied by the unit area in order to get the total area of the reservoir.

3.12 Volumetric Analysis

The basic formulas used for volume calculations are:

Bulk Volume = reservoir thickness(m) × area extent(m2) (3.33)

Where 1 m3 = 6.29 oil barrels

Net Volume = Bulk Volume × tFu

vwx^^ (3.34)

Pore Volume = Bulk Volume × tFu

vwx^^ × Porosity (3.35)

Hydrocarbon pore volume (HCPV) = Bulk Volume × tFu

vwx^^ × Porosity × Sh (3.36)

76

CHAPTER FOUR

RESULTS AND DISCUSSION

4.1 Qualitative interpretation

For the log interpretation shown in Figure 4.1 and 4.2 below, its litho-stratigraphic correlation

furnishes knowledge of the general stratigraphy of the study field. The litho-stratigraphic

correlation is a visual process which provides knowledge of the general stratigraphy of an

area (Amigun, 1998). Based on the above, two lithologies were identified using the Gamma

ray log; sand and shale. From the lithology log, the interval coloured blue is sand, while the

interval coloured grey is shale.

Three sand bodies mapped reservoir R1, R2, and R3 were correlated across the field. The

results obtained from this study are based on both the petrophysical analysis and seismic

interpretation. The well correlation panel showing the tops and bases of the reservoirs is as

shown in Figure 4.1 and 4.2 below. Figure 4.1 shows the three reservoirs within Lona 1 and

4. R1, R2and R3 occur at depth; (2890 m), (3195 m) and (3387 m) respectively in Lona 1;

and (2902 m), (3201 m) and (3376 m) respectively in Lona 4. Figure 4.2 shows two

reservoirs within Lona well 2, 1 and 3. R2and R3 occur at depth; (3308 m) and (3345 m )

respectively in lona 2;R2 occurs at depth (3308) in lona 3.

The analysis of the all the well section revealed that each of the sand units extends through

the field and varies in thickness with some unit occurring at greater depth than their adjacent

unit i.e possibly an evidence of faulting. The shale layers were observed to increase with

depth along with a corresponding decrease in sand layers. This pattern in the Niger Delta

indicates transition from Benin to Agbada formation (Amigun, 2013). From the analysis,

particularly the resistivity log, all the three delineated reservoirs were identified as

hydrocarbon bearing units across the four wells i.e Lona1, Lona2, Lona3 and Lona4.

77

Figure 4.1: Well correlation panel across Lona 1 and 4 showing the tops& base of reservoir 1,

2 and 3(values in feet)

R1 TOP

R1 BOTTOM

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

9200

9400

9600

9800

10000

10200

10400

10600

10800

11000

11227

SSTVD

1:7933

0.00 150.00GR 0.20 2000.00LLD

sand

sand

shale

sand

sand

sand

sand

sand

sand

sand

shale

sand

sand

shale

shale

sand

sand

sand

shale

shale

sand

litho

R1 TOP

R1 BOTTOM

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

Lona1 [SSTVD]

9200

9400

9600

9800

10000

10200

10400

10600

10800

11000

11200

11277

SSTVD

1:7933

0.00 150.00GR 0.20 2000.00LLD

sand

sand

sand

shale

shale

sand

sand

sand

sand

shale

sand

sand

shale

shale

sand

sand

sand

shale

shale

litho

R1 TOP R1 BOTTOM

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

Lonal 4 [SSTVD]

R1 TOP

R1 BOTTOM

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

78

Figure 4.2: Well correlation panel across Lona 2, 1 and 3 showing the tops& bases of

R2 and R3(values in feet).

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

10800

10900

11000

11100

11200

11300

11400

11500

11611

SSTVD

1:3245

0.00 150.00GR 0.20 2000.00LLD

sand

sand

sand

sand

sand

sand

sand

sand

sand

sand

sand

sand

sand

litho

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

Lona 2 [SSTVD]

10400

10500

10600

10700

10800

10900

11000

11100

11200

11237

SSTVD

1:3245

0.00 150.00GR 0.20 2000.00LLD

shale

shale

sand

shale

sand

sand

sand

sand

sand

sand

shale

shale

sand

sand

shale

litho

R2 TOP

R2 BOTTOM

R3 TOP

R3 BOTTOM

Lona1 [SSTVD]

11800

11900

12000

12100

12200

12300

12400

12500

12582

SSTVD

1:3245

0.00 150.00GR

shale

shale

shale

sand

shale

shale

sand

litho

R2 TOP

R2 BOTTOM

Lona 3 [SSTVD]

R2 TOP

R2 BOTTOM

79

4.2 Quantitative interpretation

4.3 Reservoirs

i. Reservoirs 1

Table 4.1 shows the result of some computed petrophysical parameters for reservoir 1 which

cut across Lona well 1 and 4. The reservoirs were penetrated at depths of 2890-2921 meters

in Lona well 1 and from 2902-2907 m in Lona 4. It has a gross thickness ranging from 5 to

30 m, net thickness ranges from 3 to 18 m, the net/gross thickness (N/G) is 0.6 in both wells.

Reservoir 1 also has an average porosity value ranging from 0.22 to 0.32 with permeability

value ranging from 676 to 13696 md. The water and hydrocarbon saturation have average

values of 28% and 72% respectively.

The porosity value obtained across the two wells within resevoir1 shows a good to excelent

rating, while the high permeability value obtained in well 1 indicate an excellent value that

permit the free flow of fluid within the reservoir. The hydrocarbon saturation indicates a high

proportion of hydrocabon to the quantity of water within the reservoir. Hence reservoir 1 is a

hydrocabon saturated reservoir.

ii. Reservoir 2

The petrophysical parameters for reservoir 2 is displayed in Table 4.2. It has a gross thickness

ranging from 16 to 35 m, net thickness ranging from 9 to 21m, net per gross ranges from 0.45

to 0.75, porosity ranges from 0.20 to 0.29, the water saturation(Sw) and hydrocarbon

saturation(Sh) ranges from 32% to 55%, and 48% to 68% respectively with volume of shale

(Vsh) ranging from 32% to 64%.

80

Table 4.1: Summary of the computed petrophysical parameters obtained for reservoir 1

Wells Top

(m)

Bottom

(m)

Gross

(m)

Net

(m)

N/G

(%)

Porosity

(v/V)

Sl� Ka

(md)

Sw

(%)

Sh

(%)

Vz{|}~(%)

Lona1 2890 2920 30 18 0.6 0.32 0.070 13696 27 73 6

Lona4 2902 2907 5 3 0.6 0.22 0.102 676 29 71 28


Wells Top

(m)

Bottom

(m)

Gross

(m)

Net

(m)

N/G

(%)

Porosity

(v/V)

Sl� Ka

(md)

Sw

(%)

Sh

(%)

V��(%)

Lona1 3195 3220 25 12 0.48 0.29 0.077 6241 32 68 32

Lona2 3308 3324 16 12 0.75 0.20 0.112 324 42 58 57

Lona3 3604 3639 35 21 0.6 0.22 0.102 676 55 45 64

Lona4 3201 3221 20 9 0.45 0.20 0.112 324 51 49 51


Wells Top

(m)

Bottom

(m)

Gross

(m)

Net

(m)

N/G

(%)

Porosity

(v/V)

Sl� Ka

(md)

Sw

(%)

Sh

(%)

V��(%)

Lona1 3387 3418 31 15 0.48 0.27 0.083 3481 25 75 20

Lona2 3345 3385 40 21 0.52 0.25 0.089 1936 30 70 51

Lona4 3376 3420 44 15 0.34 0.23 0.097 961 35 65 42

81

The porosity values obtained across all the wells in reservoir 2 indicates a good to very good

values. Further more, the permeability showed an excellent value for well 1 and very good

values for all the other wells. The ratio of the hydrocarbon to water saturation indicates that

this reservoir contain both water and hydrocabon, with hydrocarbon slightly higher than

water saturation.

iii. Reservoir 3

Table 4.3 shows petrophysical parameters for reservoir 3. This reservoir cuts across three

wells; which are Lona well 1, 2 and 4 respectively. The reservoirs were penetrated between

3345 to 3420 m with gross thickness ranging from 16 to 35 m, the net thickness is between

9-21 m, N/G ranges from 0.34 to 0.52. Reservoir 3 has porosity and permeability values

ranging from 0.23 to 0.27 and 961 to 3481 md respectively. The water saturation(Sw) ranges

from 25% to 35%, while the hydrocarbon saturation (Sh) ranges from 65% to 75%. The

volume of shale (Vsh) for reservoir 3 ranges from 20% to 51%.

The porosity values of reservoir 3 shows good to very good values which is indicative of a

porous sandstone and the permeability value reveals a good interconnectivity between the

pores. The water saturation and hydrocarbon saturation reveal that both hydrocarbon and

water are present in the reservoirs with the hydrocarbon having a higher ratio. Hence

reservoir 3 is a hydrocarbon bearing unit.

4.3.1 Reservoir classification

In table 4.1 are summary of the average results of the important petrophysical parameters

utilized as variables that determine reservoir quality. These parameters are subjected to

statistical analysis by considering their values across all the delineated reservoirs in the four

wells of the study area and were used to rank the reservoir. The three reservoirs have been

classified in Figure 4.3 and 4.4 using average results of petrophysical parameters. And based

on these, R1 is said to be most prolific while R2 is the least prolific within Lona field.

Table 4.4: Summary of the average 1-3

Reservoirs Top

(m)

Bottom

(m)

Gross

(m)

Reservoir1 2896 2914 18

Reservoir2 3327 3351 24

Reservoir3 3369 3408 38

Figure 4.3: Reservoir ranking using average petrophysical parameters

Figure 4.4: Reservoir ranking using average permeability.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

N/G

Re

lati

ve

am

pli

tud

e

0

1000

2000

3000

4000

5000

6000

7000

8000

R1 R2

Pe

rme

ab

ilit

y

82

average computed petrophysical parameters obtained for reservoir

Gross

(m)

Net

(m)

N/G Porosity

Sl� K|

(md)

Sl

18 11 0.6 0.27 0.086 7186 0.28

24 14 0.57 0.23 0.101 1891 0.45

38 17 0.45 0.25 0.090 2126 0.30

g using average petrophysical parameters

Figure 4.4: Reservoir ranking using average permeability.

POROSITY SH

RI

R2

R3

R2 R3

permeability

computed petrophysical parameters obtained for reservoir

l S�

V��

0.28 0.72 0.17

0.45 0.55 0.51

0.30 0.70 0.38

83

4.4 Structural Analysis

4.4.1 Horizons and faults

Three horizons corresponding to the tops and bottoms of the three reservoirs and two faults

were mapped as horozon 1 (H1), horozon2 (H2), horozon3 (H3), and fault 1 (F1), fault 2 (F2)

respectively accross the seismic section for these analysis as shown in Figure 4.5.To ensure a

good tie, wells with their tops were superimposed on the seismic sections that intersected

each other. Figure 4.6 shows the tying of well to seismic. Some of the reservoir tops and

bases coincide with the peaks and troughs on the seismic section

4.4.2 Time structural map

Mapped horizons and the generated fault polygons were used to generate time structural

maps for the three reservoirs, the time structure maps of the three horizons generated are

shown in Figures 4.7, 4.8 and 4.9. These maps showed an anticlinal structure at the centre of

the surfaces which is a structural trap. The two growth faults seen on the seismic section is

also displayed on the surfaces. Although a time map is compressed in its deeper parts and

stretched out in its shallow areas because of the general increase in velocity with depth, the

highs and lows are normally in the right places. This is particularly true when the geology is

in the form of a layer with near horizontal formations of fairly uniform thickness Amigun and

Bakare, 2013).

Figure 4.5: Inline 6000 showing the mapped faults and horizons

Figure 4.6: Inline 5970 showing the tying of wells to seismic.

Lona 1

84

Figure 4.5: Inline 6000 showing the mapped faults and horizons

Figure 4.6: Inline 5970 showing the tying of wells to seismic.

Lona 1 Lona 4

85


mE

mN

(S)

86


F2

F1

mN

mE (s)

87


F2

F1

mE (s)

mN

88

4.4.3 Depth structural map

The time structure maps were then converted into depth maps Figures 4.10, 4.11 and 4.12

using the checkshot data obtained from the area. The depth structural maps also showed the

anticlinal structure and the two faults. The depth structural map was then used to quantify the

oil in place; from literature, the enclosing contour contains hydrocarbon (Amigun and

Bakare, 2013). Based on the above, the area extents of the reservoirs were mapped to be

20,639 m2for R1, 7,284 m2for R2 and 10,522 m2for R3. The above obtained values were then

multiplied by the gross thickness of the reservoir in order to determine the volume of the

hydrocarbon in place in each reservoir (table 5).

89

Figure 4.10: Depth structural map for horizon 1

F

R1, Area =

20,639 m2

F2

F1

mE (m)

mN

90


R2, Area =

7,284 m2

mN

mE (m)

F1

F2

91


R3, Area

= 10,522 m2

F2

F1

mE

mN

(m)

92

4.5 Volumetric analysis

Table 4.6 shows the summary of the volumetric analysis within the Lona field with the help

of appropriate formulae discussed in section 3.12 Average values of petrophysical parameters

were used and hydrocarbon in place within Lona field was estimated to be 550 Mbbl of oil.

This result also complements the earlier statement thatR1 is most prolific while R2 is least

prolific within Lona field.

Table 4.6: Volumetric analysis of Lona field

RESERVOIRS R1 R2 R3 TOTAL

GROSS (m) 18 24 38 -

N/G 0.6 0.57 0.45 -

POROSITY 0.27 0.23 0.25 -

SH 0.72 0.55 0.70 -

AREA (m2) 20639 7284 10522 -

B V (bbl) 2336748 1099593 2514968 -

NET .V (bbl) 1402049 626768 1131736 -

PORE.V(bbl) 378553 144157 282934 -

HCPV (Mbbl) 273 79 198 550

93

CHAPTER FIVE

CONCLUSION AND RECOMMENDATION

5.1 Conclusion

The reservoir characterisation and volumetric analysis of Lona field Niger Delta have been

carried out. Three hydrocarbon reservoirs were delineated. Also two lithologies were

identified using the Gamma ray log; sand and shale. The analysis show that each of the sand

units extends through the field, varies in thickness with some unit occurring at greater depth

than their adjacent unit i.e possibly an evidence of faulting. The shale layers were observed to

increase with depth along with a corresponding decrease in sand layers. From the analysis,

particularly the resistivity log, all the three delineated reservoirs were identified as

hydrocarbon bearing units across the four wells i.e Lona1, Lona2, Lona3 and Lona4.

Average Reservoir parameters such as porosity (0.25), gross thickness (27 m), hydrocarbon

saturation (0.66), permeability (3734 md) and net-gross (0.54) were derived from

petrophysical analysis. Structure analysis shows fault assisted anticlinal structures which

serve as structural traps that prevent the leakage of hydrocarbon from the reservoirs. The

structural disposition of the three mapped horizons greatly favours the accumulation of

hydrocarbon coupled with the good reservoir parameters obtained from the wells.

The three reservoirs were ranked using average results of petrophysical parameters. R1 is said

to be most prolific while R2 is least prolific within Lona field. Volumetric study of the

hydrocarbon in place shows that the reservoirs are of appreciable areas and thicknesses. The

volume of hydrocarbon originally in place was estimated to be 550 thousand barrels of oil.

From these results, we can infer that Lona field has exploitable potential hydrocarbon.

94

5.2 Recommendations

Based on the qualitative and quantitative interpretation of the Lona field, Niger Delta, it is

therefore, recommended that exploitation for hydrocarbon can be carried out within the Lona

oil field. However, core drilling can be carried out in order to validate the result of the

wireline logging.

95

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