Geological controls on the reservoir petrophysical properties of “BETA Field” have been carried out using suites of wireline logs. Stratigraphic relationship among the reservoir sand bodies including their geometrical architectures, and their stacking patterns were also established. Exponential regression analysis of some of the petrophysical parameters were carried out to establish any relationship with depositional processes as well as depositional environments of the reservoir sand bodies in the field. The main factor controlling petrophysical properties and thickness for these reservoirs is the type of sandstone facies. The petrophysical evaluation of both reservoirs (K and Q) depicts porosity range from fair to very good across wells (i.e 11% to 25%). From the evaluated reservoirs porosity, there is no significant reduction of porosity with depth increase. The values obtained for the permeability of both reservoirs (K and Q) varied widely and inconsistent across the wells in the study field. The various depositional environments established in BETA field include fluvial, tidal channel, mouth bars, delta front, and the reservoir sands occurring in different depositional settings, resulting from different depositional processes, which had a wide range of petrophysical properties.

1. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Evidence of Geological Control on Reservior Petrophysical
Properties of “Beta” Field, Eastern Niger Delta, Nigeria
*1Uzoegbu, M.U., 2Emenike, K.
1Department of Geology, College of Physical and Applied Sciences, Michael Okpara University of Agriculture, Umudike,
Abia State, Nigeria
2Department of Geology, Faculty of Science, University of Port Harcourt, Rivers State, Nigeria
Geological controls on the reservoir petrophysical properties of “BETA Field” have been carried
out using suites of wireline logs. Stratigraphic relationship among the reservoir sand bodies
including their geometrical architectures, and their stacking patterns were also established.
Exponential regression analysis of some of the petrophysical parameters were carried out to
establish any relationship with depositional processes as well as depositional environments of
the reservoir sand bodies in the field. The main factor controlling petrophysical properties and
thickness for these reservoirs is the type of sandstone facies. The petrophysical evaluation of
both reservoirs (K and Q) depicts porosity range from fair to very good across wells (i.e 11% to
25%). From the evaluated reservoirs porosity, there is no significant reduction of porosity with
depth increase. The values obtained for the permeability of both reservoirs (K and Q) varied widely
and inconsistent across the wells in the study field. The various depositional environments
established in BETA field include fluvial, tidal channel, mouth bars, delta front, and the reservoir
sands occurring in different depositional settings, resulting from different depositional
processes, which had a wide range of petrophysical properties.
Key words: Reservoir, Petrophysical properties, Porosity, permeability, Stratigraphy, Depositional environment.
INTRODUCTION
BETA is a name assigned to a field in the Eastern Niger
Delta. It is situated within the Coastal Swamp depobelt of
the eastern Niger Delta, which lies within latitude 5o27ˈ36
‫״‬N to 6 o 30ˈ00 ‫״‬ N and longitude 6 o 32ˈ24 ‫״‬ E to 6 o 38ˈ24 ‫״‬
E (Fig.1).
The potentials and performance of reservoir sands depend
on certain essential petrophysical properties such as
porosity, permeability, water saturation, formation factor
and formation water resistivity (Slatt, 2006).
The depositional environments of reservoir sandbodies
can be inferred by comparing the gamma ray log
signatures with standard log motifs indicative of gamma
ray response to variations in grain size (Amajor and
Lebekmo, 1990).
Geological processes within a depositional environment
impart their characteristic by creating lithofacies changes
both lateral and vertical with varying porosities (Slatt,
2006). The depositional environments reconstruction in
clastic sequences provides optimum framework for
describing and predicting reservoir development and
distribution on both local and regional scale (Ugwueze,
2015).
Depositional environment, detrital composition and sorting
are the main function of primary porosity of any siliciclastic
reservoir (Ugwueze, 2015). The initial porosity with time
(secondary porosity) in which the deposit has been
subjected to, may be modified by post depositional
processes, such as; compaction, dissolution, cementation,
replacement, as well as synsedimentary and post-
sedimentary micro and macro tectonic processes produce
structural elements like faults, fold and diapirs (Amajor and
Aghaire, 1984 in Ugwueze, 2015). This paper deals with
(a) evaluation of stratigraphic relationship among the
reservoir zones, (b) the geometric architectures and
*Corresponding Author: Uzoegbu M. Uche; Department
of Geology, College of Physical and Applied Sciences,
Michael Okpara University of Agriculture, Umudike,
Nigeria. Email: mu.uzoegbu@mouau.edu.ng, Tel:
+2348030715958.
Research Article
Vol. 5(2), pp. 275-281, July, 2019. © www.premierpublishers.org. ISSN: 3019-8261
International Journal of Geology and Mining

2. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Uzoegbu and Emenike 276
Fig. 1: Map showing location of study area modified (Ocheli et al., 2013).
stacking patterns of the reservoirs sandbodies across the
field, (c) to establish environments of deposition of the
reservoir sandbodies in the field, and to carry out
exponential regression analyses of some of the
petrophysical parameter
REGIONAL GEOLOGIC SETTING
The studies of the Niger Delta have widely been done
mostly by oil companies and academician because of its
petroliferous province which is of economic importance.
Many authors have investigated and summarized the
basic geology, structural setting, depositional
environments, production characteristics, and field
development strategies among others. Short and Stauble
(1967), outlined the regional geology of the Niger Delta.
The origin of the Niger Delta was attempted and they
established that the Tertiary deltaic fill is represented by a
strong diachronous sequence (Eocene- recent), which is
divided into three lithofacies units namely; the Akata,
Agbada and Benin Formations.
Doust and Omatsola (1990), observed that sands of the
Niger Delta are poorly consolidated with porosity as high
as 40% in oil bearing reservoir, reservoir sands of more
than 15m thick in most places consists of two or more
stacked channel. They also observed gradual reduction of
porosity with depth and permeability in hydrocarbon
bearing reservoirs are commonly in the range of 1-2 Darcy
and sands shallower than 3000m have porosity of more
than 15%, but below 3000m only a few sands have more
than 15% porosity. Bustin (1988) established that the
Niger Delta basin is divided into continental, marginal
marine and marine facies. He also observed that
sediments of the onshore are separately mapped as
alluvium in contrast with the offshore sediments, in which
the youngest sediments were not investigated because
cutting samples could not be collected from the upper
hundred feet below sea level.
Akaegbobi and Schmitt (1998), established that
heterogeneity of reservoir, and formation evaluation
problems can make it difficult to characterize fluid
distribution, determine permeability and estimate
hydrocarbon in place. They suggested that the approach
used in characterizing a reservoir involves a combination
of analysis of geological framework of the reservoir,
hydrocarbon trapping components (stratigraphic and
structural), formation evaluation and calculation of
volumetric hydrocarbon in place. Haack et al. (2000)
discussed the tertiary petroleum systems of the Niger
Delta. He observed the lower cretaceous petroleum
system is characterized by lacustrine source rocks which
occurs in the north-western part of the delta and might be
present in the Benin trough and the upper cretaceous
lower Paleocene petroleum system, which is characterized
by marine source rocks, is defined for the north-western
part of the delta.
Various depositional processes gave rise to the Niger
Delta Cenozoic stratigraphy. The studies of Short and
Stauble (1967), Frankyl and Cordey (1967) and Avbovbo
and Ogbe (1978) provided the initial information on the
stratigraphic unit distribution of the Niger Delta subsurface.
Also, the works of Evamy et al. (1978), Ejedawe et al.
(1984), Nwachukwu and Chukwura (1986), Haack et al.
(2000), Reijer (1996) among others provided useful
information on the stratigraphic units of the region. The

3. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Int. J. Geol. Min. 277
Fig. 2: Stratigraphic Column showing Eastern Niger Delta lithofacies units and Cenozoic Geological Data (Reijers,
1996).
Niger Delta subsurface is divided into three major
lithostratigraphic units such as the Akata, Agbada and
Benin Formations (Reijers, 1996) (Fig. 2). Basin-ward,
there is a decrease in age, which reflects the overall
regression of the Niger Delta clastic wedge depositional
environments. In the south southern Niger Delta,
stratigraphic units equivalent to these three formations are
exposed, and it reflect a gross coarsening upward
progradational clastic wedge (Short and Stauble, 1967),
deposited in marine, deltaic and fluvial environments
(Weber and Daukoru, 1975; Weber, 1987).
MATERIALS AND METHODS
The data sets used in the studied project were obtained
from Nigeria Agip Oil Company (NAOC), and it includes
the base map of BETA Field suite of wireline logs. The
correlation of wells across a field serves as an excellent
aid in determining the lateral and vertical continuity of
sands within that field, which provides subsurface
information such as lithology, reservoir thickness,
formation tops and base, porosity and permeability of
production zones.
First the depth unit, coordinates (for both x and y) which
contains information of each well, were obtained from the
well-header. Only one correlation transects (SSW-NNE)
were used to infer the stratigraphic positions of each of the
reservoir sands under study (Fig. 3).
The wells were correlated using gamma ray log signature
to identify the major sandstone units, and the deep
resistivity log for detailed correlation on emphasis on the
shale sections. The stratigraphic relationship and reservoir
continuity among various reservoir sands as well as their
geometries and direction of sand development were
inferred.
The quantitative interpretation involved the use of
mathematical models and relations whose values of the
log response to the formation parameters, while the
qualitative interpretation involved the use of models which
represent the characteristics log responses to formation
parameters.
RESULTS AND DISCUSSION
In the SSW-NNE correlation panel, K and Q-reservoir
sands developed across the six well correlated (Fig. 3) at
different depths. From this analysis it shows that each of
the well thickness in the “BETA” field varies throughout the
field with possibly evidence of faulting.

4. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Uzoegbu and Emenike 278
Fig. 3: SSW-NNE lithostratigraphic correlation of the
‘BETA’ Field showing positions of ‘K’ & ‘Q’ Reservoirs
For Reservoir petrophysical properties a total of six wells
were provided, in which two hydrocarbon bearing
reservoirs were picked and analyzed from each of the
wells across the study field. The reservoirs were labeled
“K and Q”, and the following petrophysical parameters
from the reservoirs using well log values and petrophysical
calculation were computed namely; Porosity (Φ),
permeability (K), water saturation (Sw), Hydrocarbon
saturation (SH), formation factor (F) volume of shale (Vsh),
Bulk volume water (BVW), and irreducible water saturation
(Swi). From the petrophysical calculation and computation,
the analyses of the results of (K and Q) reservoirs across
the six wells are presented in Table 1 and 2.
Table 1: Average Petrophysical evaluation of K-Reservoir
in ‘BETA’ field
WELL F E D C A B
Gross
Thickness
90 76 89 86 77 69
Vsh (%) 12 24 17 27 29 14
Net
Thickness
78 52 72 59 48 55
Net-Gross
Ratio
0.87 0.68 0.81 0.69 0.69 0.8
ɸ (%) 23 18.95 21.5 11.4 25 24.4
F 17.25 33.41 19.21 105.1 16.5 46.45
Sw 0.54 0.67 0.57 0.83 0.51 0.61
SH 0.46 0.33 0.38 0.18 0.39 0.39
Swirr 0.089 0.12 0.095 0.213 0.085 0.092
BVw 0.123 0.12 0.124 0.08 0.12 0.135
K (mD) 5.4 3.6 4.1 1.9 206.4 8.6
From the reservoir petrophysical properties values
computed were from both quantitative and qualitative
interpretations of the results were done for the study area.
The porosity of K-Resrvoir was found to show an average
value between 11% in well C to 25% in well A which is
described as fair to very good porosity. Porosity being a
function of the degree of uniformity of grain size, the
shapes of the grains, the manner in which the grains were
packed, the environment of deposition, and the effect of
compaction during and after deposition. There is a gradual
decrease in average porosity values from one well sand to
the other as depth of burial increase, which is a function of
the degree of compaction of the sediment deposited.
The evaluation of water saturation (Sw) in K-hydrocarbon
reservoir sands indicates a value range of 0.51% in well A
to 0.83% in well C (Table 1). The higher the value of (Sw)
in the reservoir sands the lower the value of hydrocarbon
saturation in the reservoir sands, and vice-versa.
The permeability of K-reservoir shows values between the
ranges of 1.6mD in well C to 206mD in well A, which is
described as poor to very good permeability.
Again, the porosity of Q-Reservoir was found to show an
average values between 14% in well C to 22% in well B
and F which is described as fair to very good porosity
(porosity is a function of the degree of uniformity of grain
size, the shapes of the grains, the manner in which the
grains were packed, the environment of deposition, and
the effect of compaction during and after deposition).
There is a gradual decrease in average porosity values
from one well sand to the other as depth of burial increase,
which is a function of the degree of compaction of the
sediment deposited.
Table 2: Average Petrophysical evaluation of Q-Reservoir
in ‘BETA’ field.
WELL F E D C A B
Gross
Thickness
118 48 48 73 69 49
Vsh (%) 11 26 11 24 34 10
Net
Thickness
107 22 37 49 35 39
Net-Gross
Ratio
0.91 0.46 0.77 0.67 0.51 0.8
ɸ (%) 22 19 23 14 19 22
F 18.53 42.31 17.5 66.4 65.17 16.87
Sw 0.59 0.69 0.61 0.67 0.78 0.62
SH 0.41 0.31 0.39 0.33 0.22 0.38
Swirr 0.09 0.12 0.09 0.17 0.11 0.09
BVw 0.13 0.12 0.14 0.08 0.13 0.14
K (mD) 3.95 3.75 3.92 2.9 93.4 3.98
The evaluation of water saturation (Sw) in K-hydrocarbon
reservoir sands indicates a value range of 0.59% in well F
to 0.78% in well B (Table 2). The permeability of K-
reservoir shows values between the ranges of 2.9mD in
well C to 73mD in well A, which is described as poor to
very good permeability.
Depositional Environment
When K-reservoir (Fig. 4) top is flattened and the gamma
ray patterns are compared with the gamma ray log facies
association of well log defining depositional systems in the
central Maracaibo basin and the facies log shapes relating
to the sedimentological relationship, the prediction of
depositional environment of the reservoir sandbodies can
be inferred by comparing the shapes of the gamma ray log
with the standard motif (Fig. 5).

5. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Int. J. Geol. Min. 279
Analysis of the gamma ray log motif indicates that the log
trend of K-Reservoir sands falls mostly into five categories
namely; serrated (saw teeth) shape, funnel shape,
cylindrical shape, symmetrical shape and bell shape.
Well F, well E and well B which are found at the depth
range of 2787-2877ft, 2856-2932ft, and 2479-2548ft
respectively have a serrated and blocky log signature
which is typical of amalgamated fluvial/distributory channel
deposits. Well D which is found at the depth range of 2778-
2867ft shows a blocky and fining upward log signature
typical of fluvial channel and tidally influenced delta. Well
C found at the depth range of 2740-2826ft shows a spiky
and coarsening upward cycle typical of mouth bar, delta
front or tidal bar. Well A which is the shallowest well in the
studied field found at depth between 2344-2422ft shows a
symmetrical log signature typical of middle to lower delta
plain. Delta front, tidal and mouth bar processes in well C
and well D (Fig.4) dominated over fluvial processes in well
A, B, E, and F
Fig.4: K-Reservoir Stacking pattern and depositional
environment.
Also, when Q-reservoir (Fig. 6) top is flattered and the
gamma ray patterns are compared with the gamma ray log
facies association of well log defining depositional systems
in the central Maracaibo basin and the facies log shapes
relating to the sedimentological relationship, the prediction
of depositional environment of the reservoir sandbodies
were inferred by comparing the shapes of the gamma ray
log with the standard motif (Fig. 5).
Fig.5: Facies log shapes relating to the sedimentological
relationship (Cant, 1992)
Analysis of the gamma ray log motif indicates that the log
trend of Q-Reservoir sands fall mostly into five categories
namely; serrated (saw teeth) shape, funnel shape,
cylindrical shape, symmetrical shape and bell shape.
Well B found at the depth between 2676-2725ft and part
of well F at the depth between 3082-3119ft shows serrated
and blocky log signature typical of amalgamated
fluvial/distributory channel deposits (Fig. 6). Part of well F,
well D, well C and well A which are found at the depth
range between 3016-3048ft, 3012-3032ft, 2992-3016ft
and 2628-2640ft respectively, shows a symmetrical and
blocky log signature typical of middle to lower delta plain.
Well E at the depth between 3131-3179ft shows blocky
and fining upward log signature typical of fluvial channel
and tidally influenced delta, while part of well C at the depth
between 3032-3050ft shows spiky and coarsening upward
cycle typical of mouth bar, delta front or tidal bar. On Q-
reservoir fluvial process in well A, B, E and F dominated
over delta front, tidal and mouth bar processes in well C
and D.
The cross plot of petrophysical properties involved by
establishing their relationships is done using exponential
analysis among petrophysical variables which involves a
method by an equation of investigation. A regression
analysis of water saturation (Sw) against porosity (Φ) was
carried out to get the regression equation through which
the best fitting line on the plotted set of petrophysical
parameters was drawn.

6. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Uzoegbu and Emenike 280
Fig. 6: Q-Reservoir Stacking pattern and depositional
environment.
Fig. 7: Geological control of depositional environment on
K and Q-reservoir sandbodies.
From the cross plot of water saturation (Sw) against
porosity in K-reservoir, it has a good (positive) dispersion
around the exponential curve (Fig. 8), the formation bulk
volume water values are constant or near a constant,
which is an indicative that the formation is homogenous
and the reservoir is at irreducible water saturation, thereby
it will produce water free hydrocarbon.
Fig. 8: Exponential cross plot of water saturation (Sw)
against porosity (Φ) for K-reservoir.
Fig. 9: exponential cross plot of water saturation (Sw)
against porosity (Φ) for Q-reservoir.
From the cross plot of water saturation (Sw) against
porosity in Q-reservoir, it has a wide (negative) dispersion
around the exponential curve (Fig. 9), the formation bulk
volume water values are not constant or near a constant,
which is an indicative that the formation is heterogeneous,
not at irreducible water saturation, and the reservoir will
produce hydrocarbon with water. The formation has more
water than it can hold by capillary pressure.
CONCLUSION
A detailed review on suites of wireline logs (gamma ray
log, Deep resistivity log, Neutron log, density log and sonic
log) to determine the geological control on reservoir
petrophysical properties of reservoir sands from six wells
within BETA field, were achieved by careful examination of
the log shapes responses or signatures, and petrophysical
calculations to determine the petrophysical properties of
the reservoirs. The petrophysical evaluation of K and Q-
reservoirs depict porosity range from fair to very good
across wells within K-reservoir (i.e 11% to 25%) and Q-
reservoir (i.e. 14% to 23%). From the evaluated reservoirs
porosity, there is no significant reduction of porosity with
depth increase, this may be due to the unconsolidated
nature of the Niger Delta sand, or could be possibly due to
digenetic processes which do not only results in porosity
reduction, but can also cause porosity enhancement.
The values obtained for the permeability of both K and Q-
reservoirs varied widely and inconsistent across the wells
in the studied field. Considering the variation in
permeability, no definite trend was established across the
wells. One may infer that the various environments of
deposition (fluvial, tidal channel, mouth bars, delta front)
established in BETA field and the reservoir sands
occurring in different depositional settings, results from
different depositional processes which commonly had a
wide range of petrophysical properties.

7. Evidence of Geological Control on Reservior Petrophysical Properties of “Beta” Field, Eastern Niger Delta, Nigeria
Int. J. Geol. Min. 281
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Accepted 23 August 2017
Citation: Uzoegbu MU, Emenike K (2019). Evidence of
Geological Control on Reservior Petrophysical Properties
of “Beta” Field, Eastern Niger Delta, Nigeria. International
Journal of Geology and Mining 5(2): 275-281.
Copyright: © 2019: Uzoegbu and Emenike. This is an
open-access article distributed under the terms of the
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