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Petrophysical Evaluation of Reservoir in A Selected Well (Z) in an Onshore Oil Field
(X) in the Niger Delta Basin, Nigeria using Wireline Logs

*1IGHODARO, EJ; 2OKANIGBUAN, PN; 3OKIOTOR, ME; 4IDEMUDIA, N

*1,4
Department of Geology and Petroleum Studies, Western Delta University, Oghara, Delta State, Nigeria
2
Department of Physical Science (Physics Option), Benson Idahosa University, Ugbor, G.R.A., Benin City, Nigeria
3
Department of Marine Geology, Nigeria Maritime University, Okerenkoko, Delta State, Nigeria
*Correspondence Author Email: ehikacross@gmail.com, +2348038598495

ABSTRACT: The petrophysical properties of a well selected from among the onshore oil fields in the Niger Delta
Basin, Nigeria was evaluated using gamma ray log, resistivity log and neutron-density overlay log to analyze for the
hydrocarbon potential of the well. Some petrophysical properties of the reservoir rocks and fluid characters such as
porosity, shale volume, effective porosity, permeability, and formation resistivity factor, resistivity of water,
hydrocarbon saturation, water saturation, and net pay thickness were evaluated. The results show that the volume of
shale in each reservoir zone directly affects the effective porosity and the zones. The volume of shale is inversely
proportional to the effective porosity, as an increase in the volume of shale will bring about a decrease in effective
porosity. On the other hand, permeability is dependent on the effective porosity. Facies type identification of the reservoir
sands were also carried out using the wireline log - Gamma Ray Log. Results of the work revealed the presence of
hydrocarbon in 10 reservoirs across the well, and the hydrocarbon type was observed to be only oil. Oil/Water contacts
occurred at 2288m, 2518mm, and 2989m, and the Net Pay Thickness was calculated to be 238m, that is the total thickness
of the hydrocarbon reservoirs.

DOI: https://dx.doi.org/10.4314/jasem.v23i5.23

Copyright: Copyright © 2019 Ighodaro et al. This is an open access article distributed under the Creative
Commons Attribution License (CCL), which permits unrestricted use, distribution, and reproduction in any
medium, provided the original work is properly cited.

Dates: Received: 29 April 2019; Revised: 26 May 2019; Accepted 30 May 2019

Keywords: Petrophysics, Wireline logs, Facies, Reservoir rocks, Pay thickness.

A petroleum system is defined as a natural system that Reservoir evaluation is the determination of reservoir
encompasses a pod of active source rock and all properties from logs, cores, geophysical data and
related oil and gas, and which includes all the geologic pressure transient data. These properties include
elements and processes that are essential if a porosity, permeability, and fluid saturation amongst
hydrocarbon accumulation is to exist. The main others. Reservoir evaluation is one of the first set of
processes involved in petroleum formation are the trap tasks carried out during exploration for petroleum.
formation, generation-migration-accumulation of Reservoir evaluation can be said to be as old as
petroleum and preservation; but in all, timing is exploration of petroleum itself, but the various
essential. In the petroleum system, basically two (2) techniques applied have been modified and improved
processes occur. They include: (i) Generation- overtime. Thus, a good reservoir is characterized by
migration-accumulation of hydrocarbon (ii) Trap sufficient porosity to contain the hydrocarbon and
formation (iii) The essential elements of a petroleum permeability to permit their movement. In order to
system include: ((a) Petroleum source rock (b) evaluate or characterize a reservoir, various forms of
Reservoir rock (c) A migration pathway ( d) Seal rock analysis can be considered or carried out. They
€ Overburden rock. For the purpose of this work, the include: ( a) Petrophysical Analysis ( b) Geophysical
main focus is going to be on the reservoir component Analysis (c ) Geochemical Analysis. Geochemical
of the petroleum system. A petroleum reservoir is a analysis involves the study of data acquired from fluid
subsurface formation containing gas, oil and water in geochemistry. Geophysical analysis involves the study
varying proportions. These fluids are contained in the of data acquired from geophysical surveys, such as
pore spaces of rock formations, among the grains of seismic data. While petrophysical analysis
sandstones or in cavities of carbonates. The pore encompasses the analysis of well logs run on wireline
spaces are interconnected so the fluids can move and drillstring, conventional and special core analysis,
through the reservoir. mud logging, formation testing and fluid sampling.
For the purpose of this work, petrophysical analysis is
done on Well “Z” in “X” Field, onshore Niger Delta

Correspondence Author Email: ehikacross@gmail.com, Tel: +2348038598495

Petrophysical Evaluation of Reservoir in A Selected Well….. 918

as a case study. Wireline logs are the only set of data structural, stratigraphic and palaeontologic evidence
to be considered for this well. have been presented to support a rift model (King,
1950; Bullard et al., 1965; Reyment, 1969; Burke et
Location of Study Well: “Well Z” is located in “Field al., 1971, 1972; Fairhead and Green, 1989; Benkhelil,
X” in the onshore portion of the Niger Delta. 1989; Guiraud and Bellion, 1995). The stratigraphic
history of the region is characterized by three
sedimentary phases (Short and Stauble, 1967; Murat,
1972; Obi et al., 2001) during which the axis of the
sedimentary basin shifted. These three phases were:
(a) The Abakaliki-Benue Phase (Aptian-Santonian)
(b) The Anambra-Benin phase (Campanian-Mid
Eocene) (c) The Niger Delta phase (late Eocene-
Pliocene). The more than 3000 meters of rocks
comprising the Asu River Group and the Ezeaku and
Awgu formations, were deposited during the first
phase in the Abakaliki-Benue Basin, the Benue Valley
and the Calabar Flank. The second sedimentary phase
Fig. 1: Map of the Niger Delta showing Depobelts resulted from the Santonian folding and uplift of the
Abakaliki region and dislocation of the depocenter
The Niger Delta Basin is one of the southern Nigeria into the Anambra Platform and Afikpo region. The
basins. It lies between longitudes 40E and 8.80E and resulting succession comprises the Nkporo Group,
latitudes 30N and 6.50N. From the Eocene to the Mamu Formation, Ajali Sandstone, Nsukka
present, the delta has prograded southwestward, Formation, Imo Formation and Ameki Group. The
forming depobelts that represent the most active third sedimentary phase credited for the formation of
portion of the delta at each stage or its development the petroliferous Niger Delta, commenced in the Late
(Doust and Omatsola, 1990). The depobelts in this Eocene as a result of a major earth movement that
basin form one of the largest regressive deltas in the structurally inverted the Abakaliki region and
world with an area of some 300,000km2 (Kulke, displaced the depositional axis further to the south of
1995), sediment volume of 500,000km3 (Hospers, the Anambra Basin (Obi et al., 2001), resulting in the
1965) and a sediment thickness of over 10km in the evolution of the Akata, Agbada and Benin Formations.
basin depocenter (Kaplan and Norton 1994). The delta The evolution of the delta is controlled by pre- and
sequence comprises an upward coarsening regressive syn-sedimentary tectonics as described by Evamy et
association of tertiary clastics up to 12km thick. It is al. (1978), Ejedawe (1981), Knox & Omatsola (1987)
divided into three (3) gross lithofacies; (iii) marine and Stacher (1995). In the Delta, rifting diminished
claystones and shales of unknown thickness, at the altogether in the Late Cretaceous. After rifting ceased,
base; (ii) alternations of sandstones, silstones and gravity tectonics became the primary deformational
claystones, in which the sand percentage increases process. Shale mobility induced internal deformation
upwards; (iii) alluvial sands, at the top. occurred in response to two processes. First, shale
diapirs formed from loading of poorly compacted,
over‐pressured prodelta and delta‐slope clays (Akata
Formation) by the higher density delta‐front sand
(Agbada Formation). 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 closed spaced flank faults (Evamy
et al 1978). Deposition of the three formations
occurred in each of the five off‐lapping Siliciclastic
Fig 2. Upward –Coarsening Regression of Clastic Sediments of Sedimentation Cycle that comprises the Niger Delta.
Niger Delta The cycles (depobelts) are defined by synsedimentary
faulting that occurred in response to variable rates of
The formation of the Southern Nigerian sedimentary subsidence and sediment supply. The interplay of
basin followed the break-up of the South American subsidence and supply rates resulted in deposition of
and African continents in the Early Cretaceous (Murat, discrete depobelts. When further crustal subsidence of
1972; Burke, 1996). Various lines of geomorphologic, the basin could no longer be accommodated, the focus
IGHODARO, EJ; OKANIGBUAN, PN; OKIOTOR, ME; IDEMUDIA, N
Petrophysical Evaluation of Reservoir in A Selected Well….. 919

of sediment deposition shifted seaward forming a new The modern Niger Delta is subdivided into three (3)
depobelt. Each depobelt is separate unit that formations based on the evidence of sedimentological
corresponds to a break in regional dip of the delta and and faunal configurations similar to that of the past
is bounded landward by growth faults and seaward by (Short and Stauble, 1967). The three major subsurface
large counter‐regional faults or the growth fault of the stratigraphic units are; (i) Akata Formation (ii) Agbada
next seaward belt (Evamy et al 1978). Formation (iii) Benin Formation

Table 1: Formations in the Niger Delta area. (Modified from Short MATERIALS AND METHOD
and Stauble, 1967)
Materials: The primary materials used for the study
were wireline logs obtained from Well “Z” in “Field
X” of the Niger Delta. The logs contained include;
Gamma Ray Log, Density Log, Neutron/Density
Cross Plot Log, Resistivity Log

Gamma Ray Log: The Gamma Ray log, commonly

given the symbol GR is a continuous measurement of
the natural radioactivity emanating from the
formations. Principal isotopes emitting radiation are
Potassium-40, Uranium, and Thorium (K40, U, Th).
Sensitive detectors count the number of gamma rays
per unit of time. Once the gamma rays are emitted
from an isotope in the formation, they progressively
reduce in energy as the result of collisions with other
atoms in the rock (compton scattering). Compton
scattering occurs until the gamma ray is of such a low
energy that it is completely absorbed by the formation.
Hence, the gamma ray intensity that the log measures
is a function of: (i) The initial intensity of gamma ray
emission, which is a property of the elemental
composition of the rock. (ii) The amount of compton
scattering that the gamma rays encounter, which is
related to the distance between the gamma emission
and the detector and the density of the intervening
material.

Fig 3: Stratigraphic column showing the three formations of the

Niger Delta. Modified from Shannon and Naylor (1989) and Doust
and Omatsola (1990)

Five major depobelts are generally recognized, each

with its own sedimentation, deformation, and Fig. 4: Gamma Log Presentation
petroleum history. The northern delta province, which
overlies relatively shallow basement, has the oldest Principal isotopes emitting radiation (Potassium-40,
growth faults that are generally rotational, evenly Uranium, and Thorium) are more concentrated in
spaced with increased steepness seaward. The central clays; thus higher radioactivity in shales than other
delta province has depobelts with well-defined formations.
structures such as successively deeper roll over crests
that shifts seaward for any given growth fault. Lastly, Resistivity Log: The whole of resistivity logging is
the distal delta province is the most structurally based upon a few very important equations which
complex due to internal gravity tectonics in the relate the resistivity of a formation to the resistivity of
modern continental slope. the fluids saturating a formation, the porosity of the
IGHODARO, EJ; OKANIGBUAN, PN; OKIOTOR, ME; IDEMUDIA, N
Petrophysical Evaluation of Reservoir in A Selected Well….. 920

formation and the fractional degree of saturation of For quick look evaluation a vertical line is drawn in
each fluid present. Resistivity is a measure of the between the shale and the sand line as is referred to as
ability of a formation to resist or conduct electric the cut-off line. All intervals where the GR log is on
current. left are then assumed to be sandstone. For the wireline
log used as a case study in the evaluation here, shale
Density Log: The formation density log measures the line was read at 100 API, while the sand line was read
bulk density of the formation. Its main use is to derive at 30 API, thus making a cut- off line at around 65 API.
a value for the total porosity of the formation. It is also The level of the GR within a reservoir interval
useful in the detection of gas-bearing formations and indicates the level of its shaliness, and is calculated as
in the recognition of evaporites, oil and gas. The bulk the volume of shale. This volume of shale in reservoir
density (ρb) of a reservoir is the weighted average sand has an effect on the porosity, and is thus used in
density of the present pore fluids (ρfl) and its rock evaluating the effective porosity from the average
matrix (ρma) porosity of a particular reservoir.

Neutron Log: The neutron log is sensitive mainly to Evaluation of Porosity Determination: Porosity
the amount of hydrogen atoms in a formation. The tool calculations were done using both density and neutron
operates by bombarding the formation with high logs. The NPHI log (porosity) which was in limestone
energy neutrons. A source and two detectors are porosity units and this was corrected with neutron
mounted in a tool, which is pressed against the porosity correction chart (shown below) to get the true
borehole wall. The two detectors only count the neurton porosity. Then porosity was also calculated
returning neutrons which have a thermal energy level. using the density readings. After which certain
From the ratio of thermal neutrons detected by the far formulas were applied to get the total porosity on the
and the near detector, the amount of the hydrogen (H) average of both logs. These formulas are given in the
atoms is empirically determined. The tool assumes H petrophysical parameters listed in one of the
atoms to be present in the pore space (water or subsequent sub-headings of this chapter. Also, in other
hydrocarbons). to check the consistency of the porosities, the bulk
density (ρb) and the neutron porosity (p.u) were
Density/Neutron Combination: The densities and plotted. The neutron-density cross plot (shown below)
neutron tool both determine the porosity of a reservoir, and porosity was estimated on each lithologic line. In
but do this by measuring different quantities. The gas bearing reservoirs where the neutron porosities are
density tool measures the bulk density and The very low due to low density of H atoms in gas phase,
neutron tool measures the hydrogen density. For this this cross plot can also be used to correct the porosity
reason, both tools react differently to certain pore of gas bearing reservoir by drawing a line through the
fluids and lithologies. It is standard practice to plot plotted point parallel to the Approximate Gas
both logs in one track using a scale such that both logs Correction arrow.
overlay in water bearing limestone. Using these scales,
the logs will separate uniquely in other lithologies for
example.In gas bearing zones the recorded is lower
and the bulk density is reduced compared with the
responses in similar water/oil bearing formation.
These effects can be significant depending on the gas
saturation in the invaded zone. The resulting (large)
separation with neutron on the right and density on the
left is called gas separation. This effect for a balloon
shape and is therefore popularly known as the
“Balloon Effect”.

Evaluation of Lithology Identification: The gamma

ray (GR) log was used to identify lithology. Within the Fig. 5: Neutron-Density cross plot
log strip shale, on the right hand side, the GR level of
the thickest shale bed is read which is assumed to After obtaining the total porosity, effective porosity
represent a section that is 100% shale, and a straight was then determined, to remove the effect of shale
line through these points is the shale line. Similarly, a within the reservoir sand. This effective porosity is
sand line is constructed on the left hand side of the log the parameters used in most cases to determine other
strip, reading the average GR level of thick sands petrophysical properties such was water saturation,
which is equivalent to sands with the lowest GR level. permeability, etc.

IGHODARO, EJ; OKANIGBUAN, PN; OKIOTOR, ME; IDEMUDIA, N

Petrophysical Evaluation of Reservoir in A Selected Well….. 921

the water is absorbed on the grains in a rock or is held

in capillaries by capillary pressure. It was calculated
using the formation resistivity factor in an equation by
Asquith and Krygowski (2004). After which the
permeability was then calculated using Tumur’s
equation (both equations are shown in petrophysical
parameters below).

Reservoir Sand Facies Classification: For the

classification reservoir sand facie and depositional
environment, the shapes of the gamma rays could be
matched or compared with standard log models. In this
case the model used was the Electrofacies
Fig. 6: Porosity model for a shaly sand reservoir (from Al-Ruwaili classification for deltaic environments from Gamma
et al 2004) Ray log, by World Energy Council (WEC), 1985.

Fluid Type Determination: The resistivity log was

used to determine the kind of fluid in a sand reservoir
(determined from the Gamma Ray log), which
basically can be either water or hydrocarbon. The log
was calibrated on a logarithm scale between 0.2 and
2000ohm.m, thus making the different intervals to be
0.2, 2, 20, 200 and 2000ohm.m. Generally, water will
show a low deep resistivity reading while
hydrocarbons will give a high deep resistivity reading.
Typically for the quick look evaluation of the case
study wireline log. Any reservoir with resistivity
reading higher than 20ohm.m was assumed to contain Fig. 7: Electro facies classification for deltaic environments from
gamma ray logs (adapted from Schlumberger 1985)
hydrocarbon, while those less than 20ohm.m were
taken to be water. But theoretically, these lesser
resistivity readings that indicated water were observed Petrophysical Characteristics of the Reservoirs: The
following petrophysical parameters were calculated
to mostly be around 2ohm.m on the case study log.
and used for the hydrocarbon analysis of the study
Furthermore, the type of hydrocarbon present at a
well.
particular interval (i.e. whether oil or gas) can also be
determined by studying the separation of the porosity 1. Volume Of Shale (Vsh)
logs (neutron and density logs in this case) as
explained in the neutron-density combination above. Vsh = [ ]
Therefore, identification of potential hydrocarbon
reservoir intervals is by looking for the separation of It is expressed in percentage i.e. multiplied by 100
resistivity curves in combination with GR and porosity
logs. Where; GRlog = GR reading of the reservoir; GRmin
= GR reading of sand line; GRmax = GR reading of
Permeability Determination: Permeability is best shale line
determined from core analysis to get a more accurate
result. But where core data is not available, such as in 2. Porosity From Density Reading Or Density
the case of this work, relative permeability can be Porosity (ØD)
calculated for quick-look evaluation purpose, using
quantitative parameters such as porosity, water ØD = [ ] ×100
saturation, formation resistivity factor, bulk volume
water, etc. Applying them to various equations or
formulas such as those postulated by Timur (1968), Where; ρma = Density of matrix material (2.65 for
Asquith and Krygowski (2004), etc. For this work, in sand); ρb = Bulk density reading of reservoir read
order to determine the permeability of hydrocarbon from log; ρf = Density of contained fluid (1 for water,
bearing reservoirs, the Irreducible Water Saturation and O.85 for oil)
(Swirr) was first obtained. The Irreducible Water
Saturation describes the water saturation at which all

IGHODARO, EJ; OKANIGBUAN, PN; OKIOTOR, ME; IDEMUDIA, N

Petrophysical Evaluation of Reservoir in A Selected Well….. 922

3. Porosity From Combination Of Neutron And 8. Bulk Volume Of Water (BVW)

Density (Ø)
BVW = Sw × Øe
Ø Ø
For Oil or Waters Zones; Ø =
9. Irreducible Water Saturation (Swirr)
&
For Gas Zones; Ø =
Ø Ø
10. Swirr = %* , (Asquith and
+++
Krygowski, 2004)
Where; Ø = Corrected neutron porosity
11. Permeability (K)
4. Effective Porosity (Øe) Ø-...0
K (md) = 0.136 (Tumur, 1968)
1#233 4
Øe = Ø – (1 – Vsh)
RESULT AND DISCUSSION
5. Formation Resistivity Factor (F) The well log analyzed contains of sandstone
reservoirs. Various petrophysical properties as given
F= above in the previous chapter were calculated at
∅ different depth intervals and zones within the wells are
shown in table 2a and 2b. The facie type for the
Where; m is taken as 2, and a is taken as 1 (both reservoir sand that contained hydrocarbon are given in
constants) the table 3
6. Water Saturation (Sw) Table 3: Hydrocarbon Bearing Reservoir Sand Facie Types
Reservoir Sand Facie Types
×"# 27a Tidal Flat
Swn =
∅ × "$ 31 Tidal Flat
32 Tidal Flat
Where; n = saturation exponent and taken as 2 33a Distributary Channel
37 Tidal Flat
38 Tidal Flat
&×"#
Thus Sw = % 39 Tidal Flat
"$ 40 Distributary Channel
41a Stream Mouth Bar
Where; Rt = Resistivity of hydrocarbon bearing 44a Distributary Channel
formation (read from the log); Rw = Formation water Summary: NET SAND (total sand thickness) = 958m; NET/ GROSS
= 958/1950 = 0.49; OWC = 2288m, 2518m, 2989m; GOC = None
resistivity GWC = None; NET PAY THICKNESSES = 238m (Oil only)

Note: Rw is usually constant and is best determined

from core data, but can be calculated in the absence of
core data and for quick look evaluation, in which case
it become Apparent Formation Water Resistivity. It
can be calculated from a water-bearing reservoir sand
(preferably the thickest) using the formula below
(derived from Archie’s first equation);

Rwa = ∅' × ()
Fig 8a: A Profile Section of Well X

Where Ro = Resistivity of water bearing formation

(read from the log).

Thus the Rwa used during the course of this work was
calculated from Reservoir 12 and was given as 0.19
ohm.m

7. Hydrocarbon Saturation (Shc)

Shc = (1 – Sw ) × 100 Fig 8b: A Profile Section of Well X (Cont’d)

IGHODARO, EJ; OKANIGBUAN, PN; OKIOTOR, ME; IDEMUDIA, N

Petrophysical Evaluation of Reservoir in A Selected Well….. 923
Table 2A: Well ‘X’ Petrophysical Evaluation
Sand Depth Thick- Fluid HLLD RHOZ ØD TNPH Corrected
Unit (m) ness Present (Ro/Rt) (g/cm3) (%) (ØN) ØN
(m) Ohm/m (%) (%)
1 1500-1515 15 Water 1.8 2.15 30.3 30.0 34.0
2 1558-1567 9 Water 2.0 2.18 28.5 28.0 32.0
3 1570-1580 10 Water 1.6 2.10 33.3 34.0 38.5
4 1584-1593 9 Water 1.7 2.12 32.1 32.0 37.0
5 1647-1654 7 Water 1.9 2.05 36.4 32.0 37.0
6 1659-1664 5 Water 1.8 2.10 33.3 32.0 37.0
7 1678-1700 22 Water 1.8 2.10 33.3 33.0 37.5
8 1717-1725 8 Water 1.9 2.15 30.3 28.0 32.5
9 1729-1739 10 Water 1.8 2.13 31.5 30.0 34.0
10 1775-1785 10 Water 1.8 2.10 33.3 30.0 34.0
11 1788-1793 5 Water 1.7 2.06 35.8 31.0 35.5
12 1803-1868 65 Water 1.9 2.15 30.3 29.0 33.0
13 1875-1895 20 Water 1.9 2.13 31.5 27.0 31.0
14 1910-1934 24 Water 2.2 2.16 29.7 27.0 31.0
15 1938-1945 7 Water 2.4 2.18 28.5 24.0 28.0
16 1950-1967 17 Water 2.2 2.15 30.3 25.0 29.5
17 1970-1976 6 Water 2.0 2.13 31.5 26.0 30.5
18 1982-1995 13 Water 2.0 2.15 30.3 27.0 31.0
19 2000-2007 7 Water 1.9 2.13 31.5 28.0 32.5
20 2029-2034 5 Water 2.2 2.14 31.0 27.0 31.0
21 2067-2119 52 Water 2.6 2.20 27.3 24.0 28.0
22 2123-2143 20 Water 2.2 2.13 31.5 26.0 30.5
23 2157-2172 15 Water 2.2 2.15 30.3 27.0 31.0
24 2176-2199 23 Water 2.2 2.15 30.3 27.0 31.0
25 2202-2221 19 Water 2.4 2.18 28.5 26.0 30.5
26 2238-2248 10 Water 2.2 2.14 31.0 28.0 32.5
27a 2273-2288 15 Oil 20.0 2.15 27.8 18.0 22.5
27b 2288-2333 45 Water 2.6 2.20 27.3 24.0 28.0
28 2345-2359 14 Water 2.0 2.18 28.5 28.0 32.5
29 2362-2368 6 Water 2.0 2.17 29.1 26.0 30.5
30 2384-2393 9 Water 2.0 2.14 31.0 28.0 32.5
31 2451-2486 35 Oil 70.0 2.16 27.2 30.0 34.0
32 2498-2503 5 Oil 40.0 2.05 33.3 26.0 30.5
33a 2508-2518 10 Oil 50.0 2.10 30.6 20.0 24.0
33b 2518-2545 27 Water 2.2 2.20 27.3 24.0 28.0
34 2563-2575 12 Water 2.4 2.21 26.7 27.0 31.0
35 2656-2668 12 Water 2.0 2.20 27.3 28.0 32.5
36 2702-2714 12 Water 2.4 2.20 27.3 27.0 31.0
37 2921-2930 9 Oil 200.0 2.35 16.7 19.0 21.5
38 2939-2945 6 Oil 100.0 2.22 23.9 20.0 24.0
39 2953-2970 17 Oil 600.0 2.25 22.2 18.0 22.5
40 2973-2978 5 Oil 400.0 2.20 25.0 18.0 22.5
41a 2982-2989 7 Oil 80.0 2.25 22.2 20.0 24.0
41b 2989-3018 29 Water 4.0 2.28 22.4 21.0 25.0
42 3022-3078 56 Water 3.0 2.22 26.1 24.0 28.0
43 3085-3092 7 Water 2.5 2.20 27.3 22.0 26.5
44a 3253-3382 129 Oil 1200.0 2.25 22.2 16.0 20.5
44b 3382-3450 68 Water 6.0 2.30 21.2 18.0 22.5

Table 2B: Well ‘X’ Petrophysical Evaluation continue

Sand Ø Vsh Øe F Sw Shc BVW Swirr K
Unit (%) (%) (%) (%) (%) (%) (md)
1 32.2 14.3 27.6 9.7 100 - 27.6
2 30.3 21.4 23.8 10.9 100 - 23.8
3 35.9 17.1 29.8 7.8 100 - 29.8
4 34.6 28.6 24.7 8.4 100 - 24.7
5 34.2 21.4 26.9 8.6 100 - 26.9
6 35.2 25.7 26.2 8.1 100 - 26.2
7 35.4 4.3 33.9 8.0 100 - 33.9
8 31.4 4.3 30.1 10.1 100 - 30.1
9 32.8 7.1 30.5 9.3 100 - 30.5
10 33.7 17.1 27.9 8.8 100 - 27.9
11 35.7 28.6 25.5 7.9 100 - 25.5
12 31.7 11.4 28.1 10.0 100 - 28.1
13 31.3 22.9 24.1 10.2 100 - 24.1
14 30.4 14.3 26.1 10.8 100 - 26.1
15 28.3 11.4 25.1 12.5 100 - 25.1
16 29.9 4.3 28,6 11.2 100 - 28,6
17 31.0 18.8 25.2 10.4 100 - 25.2
18 30.7 17.1 25.5 10.6 100 - 25.5
19 32.0 18.8 26.0 9.8 100 - 26.0
20 31.0 15.7 26.1 10.4 100 - 26.1
21 28.3 20.0 22.2 13.0 100 - 22.2
22 31.0 27.1 22.6 10.4 100 - 22.6
23 30.7 14.3 26.3 10.6 100 - 26.3

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Petrophysical Evaluation of Reservoir in A Selected Well….. 924
24 30.7 28.6 21.9 10.6 100 - 21.9
25 29.5 31.4 20.2 11.5 100 - 20.2
26 31.8 21.4 25.0 9.9 100 - 25.0
27a 26.4 21.4 20.8 14.4 37 63 7.8 8.5 3387
27b 27.8 14.3 23.8 12.9 100 - 23.8
28 30.5 35.1 19.8 10.8 100 - 19.8
29 29.8 21.4 23.4 11.3 100 - 23.4
30 31.8 22.9 24.5 9.9 100 - 24.5
31 31.9 18.6 26.0 9.8 16.3 83.7 4.2 7.0 11482
32 33.5 31.4 23.0 8.9 20.6 79.4 4.7 6.7 15545
33a 28.7 14.3 24.6 12.1 21.4 78.6 5.3 7.8 5808
33b 27.7 14.3 23.7 13.0 100 - 23.7
34 28.9 21.4 22.7 12.0 100 - 22.7
35 29.9 37.1 18.8 11.2 100 - 18.8
36 27.2 35.7 17.5 13.5 100 - 17.5
37 19.9 28.6 14.2 25.3 15.5 84.5 2.2 11.2 562
38 25.1 22.9 19.4 15.9 17.4 82.6 3.4 8.9 2474
39 23.4 14.3 20.1 18.3 7.6 92.4 1.5 9.6 1562
40 24.9 25.7 18.5 16.1 8.8 91.2 1.6 9.0 2335
41a 23.4 14.3 20.1 18.3 20.9 79.1 4.2 9.6 1562
41b 23.7 28.6 16.9 17.8 100 - 16.9
42 27.1 21.4 21.3 13.6 100 - 21.3
43 26.3 17.1 21.8 14.5 100 - 21.8
44a 22.5 - 22.5 19.8 5.6 94.4 1.3 10.0 1211
44b 21.9 - 21.9 20.9 100 - 21.9

values range from good to excellent, while the

permeability values range from very good to excellent.

Table 4: Qualitative Evaluation of Porosity (Adapted from Rider,

1986)
Percentage Porosity Qualitative Description
0 -5 Negligible
5 – 10 Poor
15 – 20 Good
Over 20 – 25 Very Good
Over 30 Excellent
Fig 8c: A Profile Section of Well X (Cont’d)
Table 5: Qualitative Evaluation of Permeability (Adapted from
Rider, 1986)

Hydrocarbon occurred in basically three (3) types of

sandstone depositional facies, which includes; Tidal
Fig 8d: A Profile Section of Well X (Cont’d)
flats, Distributary channels, and Stream mouth bar.
The total net pay thickness for gas is 238m and is
Hydrocarbon occurred at reservoir zones 27a, 31, 32, mainly dominated by oil. It is important to note that
33a, 37, 38, 39, 40, 41a, 44. Water bearing zones results acquired from a critical petrophysical
generally show a low resistivity of about 2ohm.m in evaluation of well logs only give a theoretical view of
average. This is due to the high conductive nature of such well.
water. The volume of shale in each reservoir zone is
observed to directly affect the effective porosity and Conclusion: In conclusion, for the production and
the zones. The volume of shale is inversely development of the well, it can be said that all the
proportional to the effective porosity, as an increase in hydrocarbon zones are producible since they all have
the volume of shale will bring about a decrease in hydrocarbon saturations greater than 60% and have
effective porosity. On the other hand, permeability is from very good to excellent permeability values.
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IGHODARO, EJ; OKANIGBUAN, PN; OKIOTOR, ME; IDEMUDIA, N