ABSTRACT
Evaluation of elastic parameters of reservoirs can be used in
geomechanical modelling, wellbore stability analysis, and sanding, which can be
applied in practical situation to optimize drilling, completion and productions
of wells. Petrophysical analysis was done to identify various reservoirs in
five wells, using sonic, neutron, gamma, resistivity and density logs.
Porosity, Lithology and Water/Hydrocarbon saturation were determined. The
lithology are mostly sand, shale and sandstone with sand/sandstone been the
main lithology found in the reservoirs. Porosities in the five wells decrease
with depth except in few cases, due to over pressured zones, caused by fluid
contents. The reservoirs identified in the five wells are of economic
importance due to their net pay zone ranging from 7.16 m to 225.25 m, with 1067
m to 3507 m depth, which is within the Agbada formation, having a minimum
average hydrocarbon saturation of 50%. Elastic parameters evaluated are Vs, Vp,
Vp/Vs, Poisson’s ratio, Shear Impedance, Acoustic Impedance, Bulk Modulus,
Shear Modulus and Young Modulus. Vp/Vs and Poisson ratio was used also to infer
and confirm the lithology gotten from gamma log and also used to discriminate
between, oil sand, gas sand and brine sand. The Elastic properties of the
reservoirs that are found mostly in the sandstone lithology varies between
16039.61 to 28156.01 psi, 7.102 to 17.634 Kbar, 5929.511 to 16772.83 psi, 0.729
to 9.789 Kbar, 1.695 to 2.923, 2.091 to 27.645 psi of Acoustic Impedance, Bulk
Modulus, Shear Impedance, Shear Modulus, Velocity ratio and Young Modulus
respectively.
TABLE OF CONTENTS
Title Page i
Declaration ii
Certification iii
Dedication iv
Acknowledgement v
Abstract vii
Table of Contents viii
List of Tables x
List of Figures xi
CHAPTER 1: INTRODUCTION
1.1 Introduction 1
1.2 Aim and Objective of the study 3
1.3 Scope of the Study 3
1.4 Study Area 4
CHAPTER 2: LITERATUREREVIEW
2.1 General Introduction 7
2.2 Basin Structure of Niger Delta 11
2.3 Stratigraphy and Sedimentology of Niger
Delta 13
2.4 Petroleum System 16
2.4.1 Lower cretaceous (lacustrine) petroleum
system 16
2.4.2 Upper cretaceous-lower palaeocene (marine)
petroleum system 16
2.4.3 Tertiary (deltaic) petroleum system 17
2.5 Reservoir Formation Evaluation 18
2.6 Static Measurement of Rock Mechanical
Properties 24
2.7 Dynamic Calculations of Rock Mechanical
Properties 29
CHAPTER THREE: MATERIALS AND METHOD
3.1 Materials 37
3.2 Methods 37
3.2.1 Data Collection 38
3. 3 Petrophysical and Elastic Parameters
Techniques 38
3.4 Shear Wave Velocity Prediction Method 38
3.5 Elastic Impedance 39
CHAPTER FOUR: RESULTS AND DISCUSSION
4.1 Results 42
4.2 Discussion 61
CHAPTER FIVE: SUMMARY, CONCLUSION AND RECOMMENDATION
5.1 Summary 67
5.2 Conclusion 69
5.3 Recommendation
69
References 70
LIST OF TABLES
2.1 Constants
for simple exponential curve fits to porosity - mechanical
properties
relationships for sandstone and carbonates 34
4.1 Petrophysical and Elastic Properties of
four reservoirs in well 1 46
4.2 Petrophysical and Elastic Properties of
four reservoirs in well 2 50
4.3 Petrophysical and Elastic Properties of
four reservoirs in well 3 53
4.4 Petrophysical and Elastic Properties of
four reservoirs in well 4 57
4.5 Petrophysical and Elastic Properties of
four reservoirs in well 5 61
4.6 Velocity
ratio for different rock types 64
LIST OF FIGURES
2.1 Schematic
of the regional stratigraphy in the Niger Delta
showing the main
stratigraphic units in the outer fold and
thrust belt. 15
2.2 Schematic
structural section through the axial portion of the
Niger Delta showing the tripartite division of the Tertiary
sequence in relation to the basement. 15
2.3 Stress against Strain 28
4.1 Petrophysical and Elastic
analysis for Well 1 Reservoir 1 44
4.2 Petrophysical and Elastic
analysis for Well 1 Reservoir 2 44
4.3 Petrophysical and Elastic
analysis for Well 1 Reservoir 3 45
4.4 Petrophysical and Elastic
analysis for Well 1 Reservoir 4 45
4.5 Pore
fluid prediction using Poisson’s ratio and velocity ratio
for Well 1 46
4.6 Petrophysical and Elastic
analysis for Well 2 Reservoir 1 48
4.7 Petrophysical and Elastic
analysis for Well 2 Reservoir 2 48
4.8 Petrophysical and Elastic
analysis for Well 2 Reservoir 3 49
4.9 Pore
fluid prediction using Poisson’s ratio and velocity
ratio for Well 2 49
4.10 Petrophysical and Elastic
analysis for Well 3 Reservoir 1 51
4.11 Petrophysical and Elastic
analysis for Well 3 Reservoir 2 52
4.12 Petrophysical and Elastic
analysis for Well 3 Reservoir 3 52
4.13 Pore
fluid prediction using Poisson’s ratio and velocity
ratio for Well 3 53
4.14 Petrophysical and Elastic
analysis for Well 4 Reservoir 1 55
4.15 Petrophysical and Elastic
analysis for Well 4 Reservoir 2 56
4.16 Petrophysical and Elastic
analysis for Well 4 Reservoir 3 56
4.17 Pore
fluid prediction using Poisson’s ratio and velocity
ratio for Well 4 58
4.18 Petrophysical and Elastic
analysis for Well 5 Reservoir 1 59
4.19 Petrophysical and Elastic
analysis for Well 5 Reservoir 2 59
4.20 Petrophysical and Elastic
analysis for Well 5 Reservoir 3 60
4.21 Pore fluid prediction using Poisson’s ratio
and velocity
ratio for Well 5
60
4.22 Guideline for pore fluid prediction using
Poisson’s ratio and
velocity ratio 63
CHAPTER 1
INTRODUCTION
1.1 General Introduction
It has been ascertained that in many highly-developed
oil fields, only compressional wave velocity may be usable through old sonic
logs or seismic velocity check shots. For practical purpose, such as in
amplitude variation with offset (AVO) analysis, seismic modelling, and
engineering applications, shear wave velocities and moduli are needed. In these
practical applications, it is important to express either empirically or
theoretically, the needed shear wave velocities or moduli from available
compressional velocities or moduli (Wang, 2000). P-wave velocity (Vp) and S-wave
velocity (Vs) show a linear correlation in water saturated
sandstones (Han, 2004). Castagna (1985) proposed a method for shear velocity
estimation in shaly sandstones from porosity and clay content, also well log
studies indicate a correlation between Vp/Vsvalues and
lithology(Pickett, 1963; Nations, 1974; Kithas, 1976; Miller and Stewart, 1990).
Beyond lithology identification, elastic conduct of the material can be known.
As a matter of fact, production of sand along with oil and gas is a redoubtable
problem in many younger, unconsolidated rocks. The object of estimating
formation strength on the basis of elastic constants is to determine whether
the formation is formidable enough to produce at high flow rates without sand.
If the formation cannot sustain high flow rates without sand, it is beneficial
to determine the optimum production rate which can be sustained without producing
sand. There is considerable evidence that a good correlation exists between the
intrinsic strength of the rock and its elastic constants. The sonic or acoustic
log measures the travel time of an elastic wave through the formation. This
information can also be used to derive the velocity of elastic waves through
the formation.
The
velocity of the compressional wave depends upon the elastic properties of the
rock (matrix plus fluid), so the measured slowness varies depending upon the
composition and microstructure of the matrix, the type and distribution of the
pore fluid and the porosity of the rock. The velocity of a P-wave in a material
is directly proportional to the strength of the material and inversely
proportional to the density of the material. Hence, the slowness of a P-wave in
a material is inversely proportional to the strength of the material and
directly proportional to the density of the material.
Elastic properties of rocks are affected by some
geological factors which include: depth of burial, lithology, anisotropy and
diastrophism. The specific transit times are influenced by these geological
factors as well as porosity. Texture and geological history determine the
elastic properties more than the mineral composition. Crystalline rocks
generally exhibit larger values of elastic moduli than fragmental rocks
(Dresser Atlas, 1982). Hooke’s law describing the behavior of elastic materials
states that within elastic limits, the resulting strain is proportional to the
applied stress. Stress is the external force applied per unit area, while
strain is the fractional distortion which results because of the acting force.
Three types of deformation can result, depending upon the mode of acting force.
The modulus of elasticity is the ratio of stress to strain.
A
well log is a continuous recording of one or more geophysical parameters as a
function of depth. The objective of well logging is to measure the physical
properties of the undisturbed rocks and the fluid content.
Reservoirs
characterization is a process of describing various reservoir properties using
all the available data to provide reliable reservoir models for accurate
reservoir performance prediction (Jong, 2005). In order to calculate the
hydrocarbon reserve in a formation, one needs to know the water saturation
amount (Andishehet al., 2011).The
formations in the Niger Delta-Nigeria consist of sands and shale’s with the
former ranging from fluvial (channel) to fluvio-marine (Barrier Bar), while the
later are generally fluvio-marine or lagoon. These Formations are generally
unconsolidated and it is frequently not feasible to take core samples or make
drill stem tests (Aigbedion, 2007.). Formation evaluation is accordingly based
mostly on logs, with the help of mud logger and geological information as in
this study. Petrophysical parameters like the lithology, porosity, fluid content,
hydrocarbon saturation, water saturation and permeability were derived; from
the well log data.
1.2 AIM AND
OBJECTIVE OF THE STUDY
The aim of the study is to estimate elastic properties
of hydrocarbon reservoir in five wells in Niger Delta region of Nigeria.
Our
objectives are to determine the primary wave velocity, secondary wave velocity,
Bulk density, Acoustic Impedance, Shear Impedance, Bulk Modulus, Shear Modulus,
Young Modulus andPoisson’s Ratio, and use them to estimate Elastic Impedance of
hydrocarbon reservoir in the five wells that are located in the Niger Delta
region.
1.3 SCOPE OF THE
STUDY
The
elastic parameters evaluated in this work include Acoustic Impedance, Shear
Impedance, Bulk Modulus, Shear Modulus, Young Modulus andPoisson’s Ratio. This
was carried out in five reservoirs in Eket field, Akwa Ibom State in the Niger
Delta region, Nigeria.
1.4 STUDY AREA
The Niger
Delta forms one of the world‘s major hydrocarbon provinces and it is situated
on the Gulf of Guinea on the west coast of central Africa (Southern Nigeria).
It covers an area within longitudes 4ºE – 9ºE and latitudes 4ºN - 9ºN. It is
composed of an overall regressive elastic sequence, which reaches a maximum
thickness of about 12 km (Evamy et al.,
1978).
The
Niger Delta consists of three broad Formations (Short and Stauble, 1967): the
continental top facies (Benin Formation), the Agbada Formation and the Akata
Formation. The Benin Formation is the shallowest of the sequence and consists
predominantly of fresh water-bearing continental sands and gravels. The Agbada
Formation underlies the Benin Formation and consists primarily of sand and
shale and is of fluviomarine origin. It is the main hydrocarbonbearing window.
The Akata Formation is composed of shales, clays and silts at the base of the
known delta sequence. They contain a few streaks of sand, possibly of turbidity
origin. The thickness of this sequence is not known for certain, but may reach
7000m in the central part of the delta (Short and Stauble, 1967).
Petroleum
in the Niger Delta is produced from sandstone and unconsolidated sands
predominantly in the Agbada Formation. The characteristics of the reservoirs in
the Agbada Formation are controlled by depositional environment and the depth
of burial. Known reservoir rocks are Eocene to Pliocene in age and are often
stacked, ranging in thickness from less than 15 meters with about 10% having
greater than 45 meters thickness (Evamy et
al., 1978). The thicker reservoirs represent composite bodies of stacked
channels (Doust and Omatsola, 1990). Based on reservoir geometry and quality,
Kulke (1995) described the most important reservoir types as point bars of distributaries
channels and coastal barrier bars intermittently cut by sandfilled channels.
Doust and Omatsola (1990) described the primary Niger Delta reservoirs as
Miocene paralic sandstones with 40% porosity, 2 Darcy’s permeability, and a
thickness of 100 meters. The lateral variation in reservoir thickness is
strongly controlled by growth faults; the reservoir thickening towards the
fault within the down-thrown block (Weber and Daukoru, 1975). The grain size of
the reservoir sandstone is highly variable with fluvial sandstones tending to
be coarser than their delta front counterparts. Point bars fine upward, and
barrier bars tend to have the best grain sorting. Much of this sandstone is
nearly unconsolidated, some with a minor component of argillo-silicic cement
(Kulke, 1995). Porosity slowly decreases with depth because of the age of the
sediments.
Most
known traps in Niger delta fields are structural although stratigraphic traps
are not uncommon. The structural traps developed during synsedimentary
deformation of the Agbadaparalic sequence (Evamy et al., 1978; Stacher, 1995). Structural complexity increases from
the north (earlier formed depobelts) to the south in response to increasing
instability of the undercompacted, over-pressured shale. Doust and Omatsola
(1990) described a variety of structural trapping elements, including those
associated with simple rollover structures clay-filled channels, structures
with multiple growth faults, structures with antithetic faults and collapsed
crest structures. On the flanks of the delta, stratigraphic traps are likely as
important as structural traps. In this region, pockets of sandstone occur
between diapiric structures. Towards the delta toe (base of distal slope) this
alternating sandstone-shale sequence gradually grades to essentially
sandstone.
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,
interbedded sealing units against which reservoir sands are juxtaposed due to
faulting and vertical seals (Doust and Omatsola, 1990). On the flanks of the
delta, major erosional events of early to middle Miocene formed canyons that
are now clay-filled. These clays form the top seal for some important offshore
field location.
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