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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

*[email protected],

[email protected],

[email protected]

,

[email protected],

[email protected],

[email protected]

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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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.

References

[1] Bouvier, J. D., Kaars-Sijpesteijn, C. H., Kluesner,D. F. and Onyejekwe, C. C., (1989): Three-

Dimensional Seismic Interpretation and FaultSealing Investigations. Nun River Field, Nigeria.AAPG bulletin. 73(11): 13971414.

[2] Burke, R. C., Desauvagie, T. F. J. and Whiteman,A. J., (1972): Geological History of the BenueValley and adjacent areas. University Press: Ibadan.

[3] Burke, R. C. and Whiteman, A. J., (1970): The

Geological History of the Gulf of Guinea.Scientific Committee on Oceanographic Research(SCOR) Conference, Cambridge University, Easter.

[4] Doust, H., and Omatsola, E., (1990): Niger Delta. Divergent/passive Margin Basins. AAPG

Memoir 48: 239-248.

[5] Etu-Efeotor, J. O., (1997): Fundamentals ofPetroleum Geology. Paragraphics: Port Harcourt,PH. [6]Evamy, B. D., Haremboure, J.,

[6] Kamerling, P., Knaap, W. A., Molloy, F. A., andRowlands, P. H., (1978): Hydrocarbon habitat ofTertiary Niger Delta.AAPG Bulletin. 62: 277-298.

[7] Rider, M. H., (1986): The Geological

Interpretation of Well Logs. 1st

ed. Halsted Press:New York, NY.

[8] Rider, M. H., (1996): The Geological Interpretationof Well Logs. 2

nded. Whittles Publishing: Caithness.

[9] Schlumberger, (1985): Well EvaluationConference, Nigeria. International HumanResources Development Corporation (IHRDC)

publication, Boston. 16-60.

[10] Schlumberger, (1991): Log InterpretationPrinciples/Applications. Schlumberger Wireline

and Testing, Texas, TX.

[11] Tuttle, M. L. W., Brownfield, M. E., andCharpentier, R. R., (1999): The Niger Delta

Petroleum System. USGS Science for a changingworld: Open File Report 99-50, 65p.

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