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Int. J Sci. Emerging Tech Vol-3 No 1 January, 2012
19
Reservoir Characterization of KONGA Field,
Onshore Niger Delta, Southern Nigeria*Omoboriowo, A.O.
1, Chiaghanam, O.I.
2, Chiadikobi,K.C.
3, Oluwajana,O A
4
Soronnadi-Ononiwu C.G5,Ideozu,R .U.
6
1,6
Department of Geology, University of Port Harcourt, Port Harcourt, Nigeria2,3Department of Geology, Anambra State University, Uli,Nigeria
4Department of Geology,Adekunle Ajasin University,Akungba Akoko,Ondo,Nigeria
5Department of Geology,Niger Delta University,Wilberforce Island,Nigeria
,
Abstract - The evaluation of the reservoircharacterization of KONGA Field, Onshore Niger
Delta, Southern Nigeria using a suite of wire line logs
from five (5) wells and biofacies data was undertaken.
Five reservoir sand units were identified. These units
were penetrated by three wells. The results revealed
that the rock properties are variable and are controlledby environments of deposition during Oligocene late
Miocene. Reservoir sands were found to range from
2496.73m/s to 2687.65m/s (8191.37ft/s 8817.73ft/s).
The porosity of reservoir sands, which ranged from
17.34% to 22.78%, was good to very good. Their
permeability, with average field range from 35.03mD to
103.68mD, was moderate to good. Hydrocarbon
saturation was high in all the reservoir sands, ranging
from 73.16% to 84.90%, with corresponding water
saturation from 15.10% to 26.84%. Water saturations
were not irreducible for reservoir sands I and J. The oil
and gas yield of the field is high and can be exploited at
profit.
Keywords- wireline logs, reservoir, porosity, permeability,water saturation.
1.IntroductionThe Field first discovery was made in 1975 by
KONGA Well-01 which found some 264ft NGS and307ft NOS in 11 intervals. A total of 5 wells have
been drilled into the KONGA structure encountering19 reservoirs between the depth of 7,000 and 12,000
feet. Thirteen of these reservoirs are oil bearing while6 are gas bearing. Two of the oil bearing reservoirsare planned for further development. No hydrocarbonbearing reservoirs were logged in well-01. There are7 completed drainage points in 4 wells, all producingunder primary recovery technique.
The KONGA FIELD is located in the coastalswamp region of the western onshore Niger Delta,
Nigeria. It lies between latitudes 5 52 50 and 6
15 00N and longitudes 481 25 and 49225E.
The figure below shows the location of KONGAField with respect to two Nigerian cities, pipelines
and oil producing fields.
Figure 1: The location of the field under study in the
Niger Delta, Nigeria
2.Objectives of the StudyThe objectives of this study include, but not limitedto the:
Definition of the rock properties of the KONGAField
Determination of fluid types and contacts inreservoirs
Definition of the limits of gas and/or oil productionof the reservoirs
Determination of variables that influencedvariation in rock properties of KONGA Field
3.Geological Setting of the Niger DeltaNiger Delta is a large arcuate Tertiary prograding
sedimentary complex deposited under transitionalmarine, deltaic, and continental environments sinceEocene in the North to Pliocene in the South. Located
within the Cenozoic formation of Southern Nigeria inWest Africa, it covers an area of about 75,000 Km2
from the Calabar Flank and Abakaliki Trough inEastern Nigeria to the Benin Flank in the West, and it
opens to the Atlantic ocean in
the South where it protrudes into the Gulf of
Guinea as an extension from the Benue Trough andAnambra Basin provinces (Burke and Whiteman,1970; Burke et al, 1972; Tuttle et.al 1999; IHS,2010).
__________________________________________________________________________
International Journal of Science & Emerging TechnologiesIJSET, E-ISSN: 2048 - 8688
Copyright ExcelingTech, Pub, UK (http://excelingtech.co.uk/)
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Int. J Sci. Emerging Tech Vol-3 No 1 January, 2012
20
The Niger Delta as a prograding sedimentarycomplex is characterized by a coarsening upward
regressive sequences. The overall regressivesequence of clastic sediments was deposited in aseries of offlap cycles that were interrupted byperiods of sea level change (Etu-Efeotor, 1997;Bouvier et al, 1989; IHS, 2010). These periodsresulted in episodes of erosion or marine
transgression. Stratigraphically, the Tertiary NigerDelta is divided into three Formations, namely Akata
Formation, Agbada Formation, and Benin Formation(Evamy et al, 1978; Etu-Efeotor, 1997; Tuttle et al,1999). The Akata Formation at the base of the delta ispredominantly undercompacted, overpressuredsequence of thick marine shales, clays and siltstones(potential source rock) with turbidite sandstones(potential reservoirs in deep water). It is estimated
that the formation is up to 7,000 meters thick(Bouvier et al, 1989; Doust and Omatsola, 1990). TheAgbada Formation, the major petroleum-bearing unitabout 3700m thick, is alternation sequence of paralic
sandstones, clays and siltstone and it is reported toshow a two-fold division. (Evamy et al, 1978; Etu-Efeotor, 1997; Tuttle et al, 1999). The upper BeninFormation overlying Agbada Formation consists of
massive, unconsolidated continental sandstones.
4.MethodologyThe various methodology adopted in the course
of this study is summarized into a work flow chart asshown in Figure 2.
5.Results and InterpretationThis presents the results of the data processed /
analysed and their interpretation with respect toresearch objectives.
6.Lithologic Units and Well CorrelationFive reservoir sand units were identified and
correlated across five wells. The reservoir sands arenamed Sand H, I, J, K, and L. Three wells namelyKONGA 02, 03 and 05 penetrated through all these
units whereas the other two wells, KONGA 01 and04 penetrated through four sand units.
The figure 3 is a panel showing the differentlithologic units and their correlation across the fivewells in KONGA Field. The top, base and thickness
of each lithologic unit are presented in Table 1.
7.Petrophysical Properties of the RockUnits
The petrophysical properties evaluated included:volume of shale, porosity, formation factor, watersaturation, hydrocarbon saturation, irreducible water
saturation, bulk water volume and permeability.
Figure 2: Work flow chart showing different stagesand methodology
8.PorosityAs expected, due to changing environmental
condition, the porosity of different units of reservoirsands shows variation laterally. Sand body H, with
average porosity of 22.78% across the field, had
average porosities of 22.79% at Well 02, 17.73% atWell 03, 24.39% at Well 04 and 26.22% at Well 05;Sand I, with average value of 22.22% had the valueof 20.84% at Well 02, 18.11% at Well 03, 20.27% atWell 04 and 25.65% at Well 05; Sand J with average
field value of 20.43% had average with average fieldvalue of 20.44% was found to have the porosityvalues of 16.48%, 17.52% and 27.31% at Well 02,Well 03 and Well 05, respectively (Table 2). Theporosity values show a decrease down the depth. TheTable below shows the result of porosity evaluationof the sand units of the Field.
9.PermeabilityAlthough highly variable, the average
permeability of Sand H which is the most permeable
Environments of
deposition and effects
on rock properties/fluid
contents
Well Logs
Delineation and
correlation of shale and
reservoir sands
Well Log
Analysis
Evaluation of
Marock propertiesEvaluation of Gamma
Ray log motif
Geologic Interpretation
Conclusion and
Report
Biofacies data
Dating of lithologic
facies
Methodology / Work Flow Chart
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unit within the field, ranged from 8.71mD to233.49mD with overall average value of 106.63mD -
130.25mD. This was closely followed by Sand I withaverage field value of 71.13mD, and with averagepermeability values of 130.25mD, 12.56mD,21.30mD and 70.39mD at Wells 02, 03, 04 and 05,respectively. These two reservoir sandstones (SandsH and I) are the most porous and permeable units
within the field. However, the other three sandbodies, reservoir sand J, K and L have moderate
permeability values compared to sand bodies H and J.While sand L showed a slightly higher permeabilityvalues than sands J and K, the later nevertheless hasalmost the same permeability values across the field.From Table 4.5, it is observable that sand J with anoverall average permeability value of 35.03mD, hadaverage values of 4.35mD, 21.23mD, 12.40mD and
102.13mD at Wells 02, 03, 04 and 05, in that order.Similarly, Sand K with average field value of 35.43mD was found to have the permeability of2.96mD, 13.84mD, 13.97mD and 111.04mD at Wells
02, 03, 04 and 05, respectively (Table 3). In thewhole, permeability was found to decrease down thedepth, though sand L has higher values than sands Jand K lying several feet above it. The permeability
values of the five (5) reservoir sands encountered inthe study area are presented in Table 3.
10. Reservoir fluidsThe five (5) reservoir sandstones, namely Sands
H, I, J, K and L were found to contain gas, oil and
water. The fluid type and their column in each
reservoir vary across Wells.
Reservoir sand H was found to contain gas, oil
and water at Wells 02, 03 and 04 while itaccumulates only oil and water at Well 05. For
reservoir sand I, oil and water accumulate at locationof Well 04 whereas gas, oil and water werewidespread in other locations. While reservoir sand Jwas richer in oil and water at location of Well 02, itcontained appreciable amount of gas in addition to oiland water at locations of Wells 03, 04 and 05.Reservoir sand K and L contained gas, oil and water
at all Well locations. Table 4 shows the reservoir
fluid type and column across four (4) Wells in thestudied field. The fluid type and column could not becomputed for Well 01 due to insufficient Well data.
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Figure 3: Down-hole delineation and well to well correlation panel of sand - shale units across KONGA Field.Numbers 1 - 6 indicate shale units while letters HL indicate sand units.
Table 1: Depth and thickness of Lithologic units across KONGA Field as observed across Wells (All depth andthickness are in Feet)
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11. Hydrocarbon and WaterSaturation
At Well 02 (Table 5), reservoir sand H wasfound to contain 82.30% hydrocarbon saturationand 17.70% saturation water at depth 11325 -11858ft. Gas column was up to (GUT) 11325ft,
with Gas-Oil contact (GOC) at 11375ft and Oil-
Water contact (OWC) at 11600ft. This reservoirsand, with an average Volume of Shale (Vsh) of9.0%, average porosity of 22.79 and averagepermeability of 54.24mD was found to beirreducible at approximately 4% Bulk VolumeWater (BVW), an indication that more oil and gas
will be produced than water.
Reservoir sands K and L encountered at Well02 location were also at irreducible while reservoirsands I and J were not. Sand I had 76.15%hydrocarbon saturation and 23.85% watersaturation; oil up to (OUT) 12000ft and oil-water
contact (OWC) at 12300ft.
Sand J contained 73.16% hydrocarbonsaturation and 26.84% water saturation. The oilwas up to (OUT) 12550ft, with OWC at 12725ft,even as water was down to (WDT) 12810ft.
Reservoir sand K contained 80.68% hydrocarbonsaturation and 19.32% water saturation. Its gascontent was up to (GUT) 12875ft with Gas-Oilcontact (GOC) at 13000ft; oil down to (ODT)13225ft and water up to (WUT) 13200ft.Moreover, sand L had 84.90% hydrocarbon
saturation and 15.10% saturation water.
At Well 03 (Table 6), only reservoir sands Hand L were found to contain saturation
hydrocarbon and water at irreducible state whilereservoir sands I, J and K were not at irreducible.Reservoir sand H contained 81.01% hydrocarbonsaturation and 18.99% saturation water; reservoirsand I contained 84.40% hydrocarbon saturationand 12.64% water saturation. In reservoir sand K,
hydrocarbon saturation was 90.92% and watersaturation 9.08% while hydrocarbon saturation in
reservoir sand L was 96.08% with correspondingsaturation water of 3.92%.
At Well 04 (Table 7), only reservoir sand I
which contained only oil and water was atirreducible. Sand H contained 73.36% hydrocarbonsaturation and 20.64% water saturation; sand Icontained 81.72% hydrocarbon saturation and16.22% water saturation; while sand K contained84.22% hydrocarbon saturation and 15.78% watersaturation.
At Well 05 (Table 8), none of the sandstoneunits contained formation water at irreducible stateeven though hydrocarbon occurrence was high andwidespread. Sand H, which contained basically oil,accumulated 75.32% hydrocarbon saturation and
24.68% water saturation; sand I accumulated76.35% hydrocarbon saturation and 23.65% water
saturation; sand J accumulated 85.06%hydrocarbon and 14.65% water saturation.Moreover, sand K contained 90.32% hydrocarbonsaturation and 9.68% water saturation; while sandL contained 91.87% hydrocarbon saturation and8.13% water saturation. (Table 5 - 8).
Table 2: Porosity () values of reservoir sand units across KONGA Field.
Litho
Units
Well 02 Well 03 Well 04 Well 05 Field
Ave.
range
(%)
Field
Ave.
(%)
Quality
evaluation
(%)
Range
(%)
Aver
(%)
Range
(%)
Aver
(%)
Range
(%)
Aver
(%)
Range
(%)
Aver
Sand
H
13.90
35.96
22.79 5.79
21.98
17.73 10.63
49.09
24.39 20.26
37.48
26.22 17.73
26.22
22.78 Very good
Sand
I
9.48
44.78
20.84 7.50
23.01
18.11 12.13
25.88
20.27 22.15
29.12
25.65 18.11
25.65
21.22 Very good
SandJ
8.0519.26
15.28 16.825.45
20.67 13.5923.38
18.64 24.13 32.67
27.11 15.52 27.11
20.43 Very good
SandK
9.76 19.07
15.14 17.023.64
19.83 12.5624.39
19.26 20.41 31.61
27.14 15.14 27.14
17.34 Good
Sand
L
12.78
22.49
16.48 14.2
21.96
17.52 17.54
32.80
27.31 16.48
27.31
20.44 Very good
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Table 3: Permeability (K) values of reservoir sands across KONGA Field
Lith
o
Unit
Well 02 Well 03 Well 04 Well 05 Field
Ave.
K
range
(mD)
Field
Ave. K
(mD)
Quality
evaluati
on
K (mD)Range
K (mD)Aver
K (mD)Range
K(mD) Aver
K (mD)Range
K (mD)Aver
K (mD)Range
K (mD)Aver
SandH
1.06 -540.58
53.24 0.79 -32.02
8.71 0.18305.64
233.49 12.60709.07
119.27 8.71233.49
103.68 Good
SandI
0.25 -2274.88
180.25 0.0229.06
12.56 0.4462.67
21.30 22.15135.68
70.39 12.56180.25
71.13 Good
SandJ
0.03 -11.32
4.35 3.82 -56.12
21.23 0.9232.20
12.40 39.60288.52
102.13 4.35102.13
35.03 Moderate
SandK
0.11 -8.47
2.96 2.71 -34.65
13.84 0.5542.49
13.97 13.24232.47
111.04 2.96111.04
35.45 Moderate
SandL
0.62 -24.96
6.80 1.2521.38
7.61 4.90296.13
127.17 6.80127.17
47.19 Moderate
Table 4: Reservoir fluid type and column
Litho
UnitsWell 02 Well 03 Well 04 Well 05
Fluid
type
Fluid
contact
Fluid
type
Fluid contact Fluid
type
Fluid contact Fluid
type
Fluid contact
Sand H
Gas, Oil
and Water
GUT: 11325
GOC: 11375OWC: 11600
Gas, Oil
andWater
GUT: 11325
GOC: 11350OWC: 11800
Gas, Oil
andWater
GUT: 11375
GOC: 11475OWC: 11625
Oil and
water
ODT: 11775
OWC: 11775
Sand IGas, Oiland Water
GUT: 11950OUT: 12000OWC: 12300
Gas, OilandWater
GUT: 11950GOC: 11985OWC: 12150
Oil andwater
OUT: 12050OWC: 12300
Gas, OilandWater
GUT: 12025GOC: 12050ODT: 12150WUT: 12100
Sand JOil OUT: 12550
OWC: 12725WDT: 12810
Gas, OilandWater
GUT: 12525GOC: 12950OWC: 12625
Gas, OilandWater
GUT: 12600GOC: 12635OWC: 12800
Gas, OilandWater
GUT: 12525GOC: 12600ODT: 12725WUT: 12650
Sand KGas, Oiland Water
GUT: 12875GOC: 13000
ODT: 13225WUT: 13200
Gas, Oiland
Water
GUT: 12815GOC: 12950
OWC:1 3025
Gas, Oiland
Water
GUT: 12900GOC: 12975
ODT: 13200WUT: 13050
Gas, Oiland
Water
GOC: 12925OWC: 13050
Sand L
Gas, Oil
and Water
GUT: 13375
GOC: 13450OWC: 13525
Gas, Oil
andWater
GUT: 13375
GOC: 13425OWC: 13510
Gas, Oil
andWater
GUT:13400
GOC: 13475OWC: 13535
GUT: Gas Up To; OUT: Oil Up To; ODT: Oil Down To;
WUT: Water Up To; WDT: Water Down To; GOC: Gas-Oil Contact; OWC: Oil-Water Contact.
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Table 5: Summary of reservoir sand properties at KONGA Well 02.
San
d
Depth
(ft)
Thick
ness
% Vsh (%) K (mD) Sw
(%)
Swirr Sh
(%)
BV
W
(%)
Fluid
Type
Fluid contact
/ Column
Nature of
formation
waterRang
e
Aver
H
11325-
11885
560 0.8-
66.5
9.0 22.79 54.24 17.70 8.95 82.30 3.96 Oil
andGas
GUT:11325
GOC:11375OWC:11600
Irreducible
at 4%BVW
I
12000-
12360
360 0.8
21.6
5.6 20.84 180.25 23.85 11.02 76.15 4.69 Oil
andGas
GUT: 11950
OUT:12000OWC:12300
Not at
irreducible
J
12555-12800
245 1.7 54.0
11.6 15.28 4.35 26.84 14.69 73.16 4.14 Oil OUT:12550OWC:12725
WDT:12810
Not atirreducible
K
12875-13225
350 0.8 34.9
5.3 15.14 2.96 19.32 13.99 80.68 2.84 Oiland
Gas
GUT:12875GOC:13000
ODT:13225WUT:13200
Irreducibleat 2%
BVW
L
13410-13525
115 4.8 16.6
10.1 16.48 6.80 15.10 12.80 84.90 2.93 OilandGas
GUT:13375GOC:13450ODT:13525
OWC:13525
Irreducibleat 2%BVW
Table 6: Summary of reservoir sand properties at KONGA Well 03
San
d
Depth (ft) Thick
ness
% Vsh (%) K (mD) Sw
(%)
Swirr Sh
(%)
BV
W
(%)
Fluid
Type
Fluid contact
/ Column
Nature of
formation
waterRang
e
Aver
H
11325-11885
560 1.5 38.9
4.9 17.73 8.71 18.99 12.40 81.01 3.39 Oiland
Gas
GUT:11325GOC:11350
OWC:11800
Irreducibleat 3%
BVW
I
11975-12300
325 5.3 69.2
27.1 18.11 12.56 15.60 12.48 84.40 2.74 Oiland
Gas
GUT:11950GOC:11985
OWC:12150
Not atirreducible
J
12525-12750
255 1.5 83.1
18.7 20.67 21.23 12.64 9.83 87.36 2.52 Oiland
Gas
GUT:12525GOC:12950
OWC:12625
Not atirreducible
K
12825-13100
275 3.3 83.1
12.6 19.83 13.84 9.08 10.19 90.92 1.85 OilandGas
GUT: 12815GOC:12950OWC:13025
Not atirreducible
L
13410-13525
115 7.8 16.0
11.8 17.52 7.61 3.92 11.76 96.08 0.68 OilandGas
GUT:13375GOC:13425OWC:13510
Irreducibleat 0.7%BVW
Table 7: Summary of reservoir sand properties at KONGA Well 04
Sand Depth
(ft)
Thi
ckn
ess
% Vsh (%) K (mD) Sw
(%)
Swirr Sh
(%)
BV
W
(%)
Fluid
Type
Fluid contact
/ Column
Nature of
formation
waterRange Aver
H
11380-12000
620 10.34-72.41
32.04 24.39 233.49 20.64 8.82 79.36 4.95 Oiland
Gas
GUT:11375GOC:11475
OWC:11625
Not atirreducible
I
12050-12350
300 3.45 44.83
21.63 20.27 21.30 18.28 10.27 81.72 3.75 Oil OUT:12050OWC:12300
Irreducibleat 3%
BVW
J
12605-12810
205 17.24-72.41
42.91 18.64 18.64 16.22 11.27 83.78 3.00 Oiland
Gas
GUT:12600GOC:12635
OWC:12800
Not atirreducible
K
12910-
13275
365 2.07
72.41
18.76 19.26 13.97 15.78 10.69 84.22 3.07 Oil
andGas
GUT:12900
GOC:12975ODT:13200WUT:13050
Not at
irreducible
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Table 8: Summary of reservoir sand properties at KONGA Well 05Sand Depth
(ft)
Thick
ness
% Vsh (%) K (mD) Sw
(%)
Swirr Sh
(%)
BV
W
(%)
Fluid
Type
Fluid contact
/ Column
Nature of
formation
waterRange Aver
H
11400-11962
562 0.9 28.1
7.2 26.22 119.27 24.68 7.66 75.32 6.48 Oil ODT:11775OWC:11775
Not atirreducible
I
12025-
12375
350 0.9
8.3
5.0 25.65 70.39 23.65 7.69 76.35 6.05 Oil
andGas
GUT:12025
GOC:12050ODT:12150WUT:12100
Not at
irreducible
J
12575-12810
235 0.9 28.1
11.8 27.11 102.13 14.94 7.23 85.06 4.08 Oiland
Gas
GUT:12525GOC:12600
ODT:12725WUT:12650
Not atirreducible
K
12875-
13175
300 0.9
57.6
7.1 27.14 111.04 9.68 7.31 90.32 2.50 Oil
andGas
GOC: 12925
OWC:13050
Not at
irreducible
L
13425-
13600
175 1.8
57.6
22.8 27.31 127.17 8.13 7.43 91.87 2.13 Oil
andGas
GUT:13400
GOC:13475OWC:13535
Not at
irreducible
12.Qualitative Interpretation of WellLogs
The examination of the wireline logs reveals thatthe reservoir sand bodies in each of the five wells arecyclically inter-bedded with shales (clays / siltstones)of varying thickness. These reservoirs contain gasand/or oil, and water as revealed by deep resistivity;neutron and density logs (see Figure 3). Though thegeometry of these sand bodies could not beaccurately ascertained, the gamma ray logs reveal a
cylindrical / blocky shape with flat top and funnelshaped base for reservoir sand H indicating
deposition in a fluvial / tidal flood plain, channel,deltaic distributary, deltaic front and shoreface. SandsI, J, and L showed serrated / saw-teeth shape in allwells, indicating rapid alternation of thin beds ofshale with sandstones implying deposition underalternating low and high energy regimes, possibly atbarrier bars and/or distributaries mouth bars, storm-
dominated shelf and distal marine slope. Sand Kshowed a symmetrical hour glass shape implying
deposition in a tidal flattidal channel and shoreface proximal offshores. Figure 4 shows types ofgamma ray log shape and their stacking patternsalong with interpreted depositional environment.
Gamma ray logs also show a combination of serratedfunnel and bell log shapes correspondingly indicatingcoarsening and fining upward stacking patterns,implying deposition in deltaic environment of tidalflats, fluvial channels and/or deltaic distributaries.
Caliper logs in Well 01 and Well 05 (see Figure3) show the reservoir sands as having smooth profile,implying mud cake build-ups and their being porousand permeable. Only reservoir sands H and I caved in
and washed out at certain intervals at Well 05,indicating zones of very high porosity andpermeability within the sands.
13.Chronology of the Lithologic FaciesThe analysis of biofacies data from KONGA
well 01 reveals that KONGA wells penetrated theP784 and P788 (corresponding to top - base depthrange of 7150ft 11950ft and 6250ft 6490ft,respectively), and F9600 and F9620 (correspondingto top - base depth range of 6030ft 11990ft and10750ft-10750ft, respectively) biofacies zones.
From the Niger Delta Cenozoic Geological Chart(Figure 5), both the pollen and foraminifera fossilzones indicate that the sediments penetrated byKONGA wells were deposited in the Oligocene - lateMiocene times.
Based on the pollen and foraminifera zones,three (3) sedimentary/ stratigraphic sequences areidentified: sequence I (F9600) 11.5 7.4Ma,sequence II (P780) 10.8 9.7Ma and sequence III(P820) 9.3 7.4Ma. They correspond to thesedimentary facies deposited in the Coastal Swamp
depobelt. They also constitute the unit of upperAgbada Formation. Below this are sedimentary faciescharacterized by Alabamina-1 and Bolivina-26which is interpreted as belonging to the sedimentaryfacies of the Greater Ughelli depobelt and CentralSwamp depobelt, respectively. This set of rock unitsconstitutes the lower Agbada Formation. It is richedin pollens and devoid of forams, indicating their
formation in the brackish / fluvio-deltaicenvironments in the Oligocene early Miocene
times.
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Figure 4: Gamma ray log motifs / shapes of reservoir sands, their stacking patterns, and depositionalenvironments.
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Figure 5: Niger Delta Cenozoic Geological chart
14.DiscussionThe evaluated sands showed little reduction in
porosity with increase in depth. The porosity of theupper unit (Sands H and I) is generally higher thanthose of the lower unit (Sands J, K, and L). This,according to Schlumberger (1985), is due to theunconsolidated nature of the Niger Delta. Compactionand diagenetic processes therefore, seemed to havevery little or no effect on the porosity of the field incontrast to the depositional processes and
environments of deposition. This is evident on the
gamma ray log motifs of the sands of the lowerAgbada (sand unit J, K and L) deposited in the openshelf or shelf slope. The low energy of thisenvironment had very little or no influence on thereworking of the sands, hence the decrease in porosity.
This contrasts with the sediments of the upper Agbadaunit (sand unit H and I) deposited in high energyenvironment of tidal plain and the deltaic front where
strong waves influence reworked on the sands.
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The lateral variation in porosity might have beencaused by changes in the depositional environment and
the gradual deepening of the depth of deposition due tothe progradation of the coastline and the shift indepobelts southerly and seaward. This finding isconsistent with the reports of Evamy et al (1978) andBouvier et al (1989).
Permeability values though highly varied bothlaterally and vertically, were moderate to good. Thehigh permeability of the reservoir sandstones in thefield would result in rapid water and hydrocarbonflow. However, the wide variations in the bulk volumewater (BVW) indicate that some zones were not at
irreducible water saturation. These zones wouldproduce wet hydrocarbons (that is, wet gas and oil)whereas the zones where the BVW were at irreduciblewater saturation would produce water-freehydrocarbons. The
water-free hydrocarbon production zones varylaterally along the reservoir sand units and also acrossthe different reservoir units in the field. Of all the sand
units, Sand I and J were not irreducible. Thus, any wellscreened within these units would produce wet
hydrocarbon. The reservoir sands H, K and L withinthe field would produce high amount of water-freehydrocarbons.
The information from gamma ray log motifsrevealed reservoir sands H, I and J as barrier bars, tidalchannel and deltaic flat deposits which can becollectively grouped as fluvio-deltaic plain deltaicfront environments whereas sands K and L were
deposited in prodeltaic to shelf margin/slope. Thiswide depositional environments account for variation
observed in the porosity and permeability of the rockunits. It is established that porosity and permeability of
sandstones depend on grain size, sorting, cementationand compaction (Schlumberger, 1991, Etu-Efeotor,1997; Rider, 1986, 1996). These variables undoubtedlyare functions of the sedimentary environment anddepositional processes. The reservoir sands J, K and Ldeposited in a low energy marginal deltaic and shelfmargin / slope have slightly reduced porosity andpermeability due to high volume of clays (shales) and
silts (siltstones) often associated with such
environments. To the contrary, high porosity andpermeability obtained for reservoir sands H and I aredue to their deposition in the deltaic plain / front,which is a high energy environments associated withfluvial and fluvio-marine processes which enhancessorting and reduces heterolithic conditions in
sediments. As explained by Tyler (1988), fluvial(channel) and fluvio-marine (barrier bar) processes
would generate better quality reservoirs as againstmarine processes which tend to decrease reservoirquality by producing less sorted heterolithiclithologies. Hence, the difference in quality ofreservoir sand units in terms of porosity and
permeability is, to a greater extent, related to thedegree of sorting of sandstone which is fundamentally
controlled by depositional environments andprocesses, as well as the volume of shale in each unit.
In this regard, the average volumes of shale werefound to be highest in Sand J, followed by Sands L and
K (all three classified as lower Agbada), while Sands Iand H (both classified as upper Agbada) were the least.
The variation in depositional processes and
environments of deposition of sandstones mostprobably account for the observed trends in transittimes / velocities, porosity, permeability, bulk volumewater and formation water saturation whereasvariations in acoustic impedance, reflection coefficientand transmission coefficient seem to depend on rockporosity, density (implicitly its hardness), type andnature of bounding surfaces as well as type and
amount of fluid present within the rock unit.
Biofacies data shows vertical subdivision ofKONGA Field into three broad facies units. The upperunit with depth range of 0 - 6,000ft is characterized
with pollen (P) and foraminera (F) of undistinguishedzone; the middle unit with depth range 6,010
11,990ft is associated with P784 P820 and F9600
F9620 fossil zones; and the lower unit of 12,040 13,300ft depth is associated with undifferentiated P-fossil zones.
15.Summary and ConclusionThe detailed and systematic evaluation of the rock
units has enabled the actualization of the setobjectives. From the analysis of the wireline logs offive (5) wells (KONGA 01- 05), it is observed that fiveof the reservoir sand units across the field werehydrocarbon riched. These units were characterized by
porosity, permeability and acoustic impedance valueswhich compared closely with that obtained for sandsof other Niger Delta fields.
This variability was controlled by the deposition
of the sediments in different environments. The resultsof gamma ray log motif and seismic attributes analyses
revealed the sandstones to have been deposited in abroad environment of fluvio-deltaic plain, deltaic frontand open-shelf margin / slope. The fluvio-deltaic anddeltaic front facies were deposited as point bar andtidal channel sands of the lower upper shoreface.Conversely, the shale units were deposited at the shelf
margin / slope in association with changes in sea level.
Reservoir Sands I and J were not at irreduciblewater saturation. Much water and wet hydrocarbonswould be produced by wells bored through these units.Some other sand units, namely Sand H, K, and L, wereat irreducible water saturation at some well locations
and not at irreducible at other well locations. Thesereservoir zones would produce water-freehydrocarbons. .
The rock properties of the KONGA Field arevariable due to environmental influence and depth of
burial. The environments of deposition had a controlover the properties of the rock units. Sand units have
good and quality properties as reservoir rocks whilethe shale units function both as source rocks and seals.The porosities of the reservoir sands are good to verygood; their permeabilities moderate to good. Oil and
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gas accumulation is high and widespread throughoutthe field. Though some wells and reservoir sand units
would produce wet hydrocarbons, zones where water-free hydrocarbons are producible are wide spreadthroughout the field. The hydrocarbon resources canbe exploited at profit.
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