Petrophysical Characterization of Agbada Formation

Volume 2021, 18 pages | Article ID : IJPGE-2107082112366

International Journal of Petroleum and Geoscience Engineering

Journal homepage: www.htpub.org/ijpge/

ISSN: 2289-4713

Petrophysical Characterization of Agbada Formation Reservoirs, In Well U4, Offshore, Eastern Niger Delta Basin, Nigeria

Christopher M. Agyingi*, Alex-Abbas T. Ngassa, Anatole E. D-Lordon, Victor L. Wotanie

Petroleum Research Group, Department of Geology, University of Buea, P.O. Box 63 Buea Southwest Region Cameroon

Article

Abstract

Article history: Received: 27 May 2021 Received in revised form: 03 July 2021 Accepted: 09 July 2021

Well U4 is located offshore, in the eastern part of the Niger Delta Basin in Nigeria. A conventional suit of wireline logs including caliper log, gamma ray log, density log, neutron log, photoelectric effect log, sonic logs (shear and compressional) and resistivity logs were acquired for petrophysical evaluation of reservoirs in the well in order to assess their hydrocarbon potentials. The results show that the lithological succession of the reservoir zones in the well corresponds to the Agbada Formation within the depth interval of 2302m and 3246m, where fourteen hydrocarbon reservoir Zones (A to N) have been delineated. Eight of these reservoirs have thicknesses ranging from 11m to 32m, while six have thicknesses ranging from 2m to 9m. Neutron-density plots and neutron-density crossover patterns indicate that 12 of these reservoirs are gas-bearing sandstones, but with Zone D having gas, oil and water, while Zone E is saturated with gas and oil. Average reservoir porosities range from 0.160 to 0.300 and average permeability range from 255.2md to 1708.8md. The low shale volumes values (0.033 to 0.161) obtained from calculations indicate that almost all of these reservoirs have shale volume values below the limit of 15% that can affect water saturation and the free flow of fluids. Average water saturations are low, consequently, high hydrocarbon saturations with values ranging from 0.553 at Zone D, to 0.906 at Zone B. This well shows significant gas columns within the reservoir intervals. With large reservoir thicknesses, suitable reservoir qualities and high hydrocarbon saturation values, this area is a good natural gas prospect.

Keywords: Niger Delta, Reservoir porosity, Reservoir permeability, Fluid saturation

1. Introduction

The increasing demand for petroleum has caused reservoirs of low prospect to be reviewed and re-

characterized with the help of modern logging instruments with higher resolution; which provide

improved information about reservoirs. This information has helped in the discovery of new reservoirs

and revitalization of some “low prospect” reservoirs. With a better understanding of the petrophysical

and petrochemical properties of reservoirs, appropriate well completion and production methods,

which could improve the actual recovery, can be used. Logging tool responses and core data are often

*Corresponding author at: Petroleum Research Group, Department of Geology, University of Buea, P.O. Box 63 Buea Southwest

Region Cameroon

Email address: [email protected]

http://www.htpub.org/ijpge/

C.M. Agyingia et al., IJPGE, Vol. (2021), Article ID: IJPGE-2107082112366, 18 pages

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used to draw inferences about lithology, depositional environments and fluid content [1]. Reservoir

characterization is undertaken to determine its capability to both store and transmit fluid.

All studies carried out in this delta by several researchers, point to the Agbada Formation as the

main hydrocarbon habitat in the Niger Delta Basin [2-5]. Qualified and quantified reservoirs of some

wells in the basin, i.e. they determined the depth and thickness, lithology, gas bearing sands, porosity

and production potential.

This delta is the largest petroleum oil province in Africa with 574 discovered fields (481 oil fields

and 93 gas fields) [6] and any information on the reservoir geology is very important for further

exploration and exploitation of hydrocarbon in the basin. The overall objective of this work was to carry

out petrophysical interpretation of wireline log to qualify and quantify reservoirs of the Agbada

Formation in Well U4 (Fig 1), in order to assess their hydrocarbon potentials.

1.1. Geologic Setting

The Niger Delta is ranked among the world’s major hydrocarbon provinces. It is the most important

in the West African continental margin [7]. This basin is situated in the Gulf of Guinea, on the West

African continental margin lies between latitudes 4o and 7oN and longitudes 3o and 9oE (Fig 1). It

underlies the coastal plain, continental shelf and slope of Nigeria, western Cameroon and northern

Equatorial Guinea west of Bioko Island. The part of the Delta in western Cameroon and Equatorial

Guinea is known as Rio del Rey Basin. The depo-belts of this basin form one of the largest regressive

deltas in the world with an area of some 300,000 km2 [8], a sediment volume of 500,000 km3 [9] and a

sediment thickness of over 10 km in the basin depo-centers [10]. These deposits have been divided into

three large-scale lithostratigraphic units: the basal Paleocene to Recent pro-delta facies of the Akata

Formation (about 6,000m thick), Eocene to Recent, paralic facies of the Agbada Formation (more than

3,700m thick), and Oligocene-Recent, fluvial facies of the Benin Formation (about 2,000m thick) [11-

13]. These formations represent prograding depositional facies that are distinguished mostly on

the basis of sand-shale ratios. Petroleum occurs throughout the Agbada Formation of the Niger Delta,

where oil and gas are mainly trapped in rollover anticlines and fault closures.


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Figure 1. Map showing the study area

Figure 2. Stratigraphy of the East Niger Delta Basin [14]

2. Methodology

The wire-line logs used in this research comprise of a caliper log, gamma ray log, photoelectric effect

log, density log, neutron porosity log, sonic logs (shear sonic and compressional sonic) and a resistivity

log (deep and shallow resistivity log). This study involves the interpretation of the logs to delineate the

potential zones of hydrocarbon in the Agbada Formation. The logs were manually interpreted through

a systematic approach to determine the lithologic succession in the well and petrophysical properties

of the zones of interest. The parameters of log interpretation were determined directly or inferred

indirectly. Rock properties or characteristics that the study was based on and that affect logging

measurements are: lithology, porosity, mineralogy, permeability and water saturation.

2.1. Determination of Lithology

The gamma-ray log was used to delineate the lithology using a quick-look interpretation method.

The American Petroleum Institute (API) values range from sandstone line 0 API to shale line 125 API.

As the signature of the log moves towards the higher values, the formation becomes shalier. Then, the

lithological sequence of the formation of the study area was established. The caliper log was also used

for lithologic purposes; the critical data are caliper readings relative to bit size.

2.2. Petrophysical Analysis

2.2.1. Shale and Clay Volume

The gamma ray was used to calculate the volume of shale in the porous reservoirs. To calculate the

shale volume, the gamma ray index (IGR) is needed.

𝐼𝐺𝑅 = (𝐺𝑅𝑙𝑜𝑔 − 𝐺𝑅𝑚𝑖𝑛)

(𝐺𝑅𝑚𝑎𝑥 − 𝐺𝑅𝑚𝑖𝑛) (1)

where,


4

IGR = Gamma ray index

GRlog = Gamma Ray Log reading of formation

GRmin = Gamma Ray Matrix (Clay free zone)

GRmax = Gamma Ray Shale (100% Clay zone)

For this study, 24GAPI and 164GAPI were picked from the log for minimum and maximum gamma

ray values respectively. Then, the non-linear equation [15] for Tertiary rocks was used to calculate the

shale volume:

[15] Non-linear equation:

𝑽𝒔𝒉 = 𝟎. 𝟎𝟖𝟑(𝟐𝟑.𝟕(𝑰𝑮𝑹) − 𝟏) (2)

2.2.2. Porosity

Porosity was determined from the formulas:

∅ =∅𝑁 + ∅𝐷

2, (for liquid saturation) (3)

∅ = √∅𝑁

2 + ∅𝐷2

2, (for gas saturation) (4)

where,

∅𝑁 = neutron porosity, obtained from the neutron log

∅𝐷 = density porosity, determined from Wyllie equation as follows:

∅D = (δma − δb)

(δma − δfl) (5)

where,

∅𝐷 = porosity derived from density log

δma = matrix (or grain) density

δb = bulk density (as measured by the tool and hence includes porosity and grain density)

δfl = fluid density.

The effective porosity was estimated according to Eq. (6)

∅e = [(δma − δb)

(δma − δfl)] − [Vsh ∗ (

(δsh − δb)

(δsh − δfl))] (6)

i.e., ∅𝑒 = ∅ − 𝑉𝑠ℎ . ∅𝑠ℎ

where,

∅e = Effective porosity

δ𝑠ℎ = Density of shale

Vsh ∗ ((δsh − δb)

(δsh − δfl)) = Shale Bound Water

(δma = 2.65g/cc, δw = 1.0g/cc, δsh = 2.6g/cc, δg = 0.6g/cc, δoil = 0.8g/cc)

2.2.3. Water Saturation


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Water saturation was determined using Pickett plot and the accuracy of the values was verified using

Archie Equation for water saturation as shown in Eq. (7) and the Indonesian Equation was used to

calculate the effective water saturation as shown in Eq. (8).

Sw = √(a. R𝑤

∅m. R𝑡

)n

(7)

Swe = √

1

(V𝑠ℎ

2

Rt𝑠ℎ⁄ ) + (

∅𝑒m

a. R𝑤⁄ ) ∗ R𝑡

n (8)

(a = 0.81, m = 2, n = 2, Rtsh= 2.5)

where,

Rtcl = Deep resistivity in clay (read from log)

Rt = Deep Resistivity

Rw = Down hole water resistivity

Фe = Effective porosity

Sw = Water saturation

Swe = Effective water saturation

a = Archie’s exponent (tortuosity factor)

m = Cementation factor

n = Saturation exponent, it is the gradient of the line defined on the Pickett plot.

2.2.4. Determination of Hydrocarbons Saturation

Hydrocarbon Saturation, Sh, is the percentage of pore volume in a formation occupied by

hydrocarbon. It can be determined by subtracting the value obtained for water saturation from 1, i.e.

Sh = 1 − Sw (9)

2.2.5. Calculation of Permeability

Permeability, K is the property of a rock to transmit fluids. For each identified reservoir,

permeability (K) was calculated using [16] equation [27]:

𝐾 = (250 ∗ ∅3

𝑆𝑤 𝑖𝑟𝑟

)

2

, (medium − gravity oils) (10)

𝐾 = (79 ∗ ∅3

𝑆𝑤 𝑖𝑟𝑟

)

2

, (dry gas) (11)

where,

Φ = porosity

Swirr = irreducible water saturation

where Swirr was calculated using [17] equation


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𝑆𝑤 𝑖𝑟𝑟 = 𝐶

∅

where,

C = constant (for sandstone, C = 0.02 to 0.10)

2.2.6. Bulk Volume Water

This is the product of the formation water saturation (Sw) and it porosity (ϕ)

𝐵𝑉𝑊 = 𝑆𝑤 ∗ ∅ (12)

The grain size of the reservoir was obtained from BVW by the use of a comparative chart (Table 3.4).

2.2.7 Pay Zone

The pay zone thickness was determined by subtracting the non-hydrocarbon section from the

reservoir’s thickness.

2.2.8 Cross-Plots

The neutron-density plot was used to determine the rock type and fluid saturation type. The Pickett

plot was used to confirm the interpretation from the quick-look method and for the determination of

formation water resistivity (Rw), water saturation (Sw) and irreducible bulk volume water. The Buckles

plot was used to determine whether the reservoirs are at irreducible water saturation or not.

3. Results and Interpretation

3.1. Lithologic units and reservoir zones

The interval of Well U4 evaluated shows from the depth tracks that this well is a directional well,

having a general trendline with gradient of 1.3 and makes and angle of 41.40 with the vertical. The true

vertical depth (TVD) interval ranges from 1970m to 3335m. The evaluated log interval has two major

lithological units based on gamma ray log, and neutron-density lithology plot, namely: shale and

sandstone. According to [18], this depth interval corresponds to the Agbada Formation. A cut off value

of 73API was determined using the gamma ray log and values below it are sandstones while those above

it are shale. Added to the above mentioned methods is the caliper log which was used to identified zones

of mudcake formation (permeable zones) and cave-in zones (impermeable zones; shale), by the

reduction and increase in borehole diameter respectively. Forty two reservoirs were delineated with

different thicknesses, but fourteen (14) of them are of interest to this study, because of their thickness

and fluid saturation type. These reservoir bodies were marked as Zone-A to Zone-N (Fig. 3, 4, & 5).

The density porosity was calculated using 2.65g/cm3 grain density, 1.0g/cm3water density,

0.8g/cm3oil density and 0.6g/cm3 gas density [19]. The porosities are generally very good according to

[20] porosity classification.

Table 1. Porosity classification

Porosity (%) Retarding Theory

0-5 Negligible

5-10 Poor

15-20 Good

20-30 Very good

>30 Excellent

Many gas-bearing zones have been identified in this well by negative crossing over of Density and

Neutron logs at the reservoir zones. These reservoirs generally have low water saturations, which


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invariably are indications that hydrocarbon saturations are high. There is a general decrease in grain

size determined from BVW) from Zone A (at shallower depth) to Zone N (at greater depth).

Figure 3. Wireline log for Well U4 with interpreted

lithology and fluid saturation type

Figure 4. Wireline log for Well U4 with interpreted

lithology and fluid saturation type (continuation of Fig. 4)

Figure 5. Wireline log for Well U4 with interpreted lithology and fluid saturation type (continuation of Fig. 5)

Three reservoir scenarios were encountered along this well and Zone B, D and E are used as

examples to illustrate how all the reservoirs were characterised.

3.1.1. Zone-B

This reservoir is a sandstone bed with a thickness of 22m and occurs at a vertical depth interval of

2457m and 2479m. It has an average shale volume of 0.050 (5.0%), which is below the limit of 15%.

This reservoir has an average porosity value of 0.300, which according to Rider (1986) classified; it is

“very good”. The effective porosity is also excellent (0.280) and this is due to the very small shale volume


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present in the reservoir. This zone has low average water saturation value (0.094), with very high

average hydrocarbon saturation value (0.906). This reservoir has an average permeability value of

1328.9md, which can permit a very free flow of fluid. According to [20] permeability classification, this

permeability is classified as “excellent”. The density curve reads much higher porosity than the neutron

log: “crossover‟ [19], combined with the neutron density plot (Fig. 6a) and very high true resistivity

values at this zone, indicate that this zone is entirely a gas-bearing sandstone reservoir. A fairly constant

porosity value with depth can be identified from the porosity values in Table 1. This could be as a result

of the very low shale volume, it’s even distribution and the well sorted nature of the sands in the

reservoir. The average BVW value of 0.028 indicates that this sandstone is medium-grained. The

computed petrophysical parameters for this reservoir are presented in Table 1.

A Pickett plot (Fig. 6b) of true resistivity against porosity for this zone indicates that all the points

plot below 0.2 water saturation line; which is a good indication of high hydrocarbon saturation. This

plot also shows that all the points plot below the irreducible BVW line. Also, from the Buckles plot (Fig.

6c) all the points cluster around a BVW line slightly below the irreducible BVW hyperbolic curve;

indicating that the zone is at irreducible water saturation. Therefore, hydrocarbon cans be produced

from this zone with no water. This plot also confirms the fact that this zone is saturated with

hydrocarbons.

3.1.2. Zone-D

This reservoir occurs at a vertical depth interval of 2512m and 2540m, with a thickness of 28m. This

huge sandstone reservoir has an average porosity value of 0.229 and an average effective porosity value

of 0.223. It has an average permeability value of 314.3md, which can permit a very free flow of fluid.

According to [20] porosity and permeability classification, this porosity is considered as “very good” and

permeability as “very good”. The average shale volume in this zone is 0.038 (3.8%), which is very much

below the limit of 15% that can affect the water saturation value and fluid flow in the reservoir [9].The

calculated average water saturation for this reservoir is 0.447 and average hydrocarbon saturation

value of 0.553. The neutron-density plot (Fig. 7a),the crossover pattern of density and neutron log,

combined with the high resistivity values at this reservoir indicate that this reservoir is saturated with

gas at the upper section, oil below the gas zone and water at the base of the reservoir. The gas/oil contact

is suspected at the depth of 2522m and the oil/water contact at the depth of 2526m. The BVW values

indicate that the hydrocarbon saturated zone is made of very fine grains, while the water saturated zone

is made of silt. The permeability of this water saturated zone is not as good as that of the zone above it,

which is saturated with hydrocarbon. The computed petrophysical parameters for this reservoir are

presented in Table 2.

A Pickett plot (Fig. 7b) for water saturation, with BVW values, shows a cluster of points that are

closely plotted around the 0.6 water saturation line; indicating a water saturated zone while the rest of

the points cluster around the 0.2 water saturation line; indicating hydrocarbon saturation. Buckles plot

(Fig. 7c) shows that the water saturated points cluster around a BVW hyperbolic curve which is slightly

above the 0.15 BVW value, indicating that the zone is at irreducible water saturation. The rest of the

points cluster around several BVW hyperbolic curves, indicating that the zone is not at irreducible water

saturation and therefore, hydrocarbons will be produced with some water.

3.1.3. Zone-E

This sandstone reservoir occurs at a vertical depth interval of 2615m to 2647m, with a thickness of

32m. This huge reservoir has an average porosity value of 0.288, with an effective porosity value of

0.256. According to [20] porosity classification, this porosity is classified as very good. It also has an

excellent permeability of 1708.8md, which can permit the free flow of fluid. The average shale volume

for this reservoir stands at 0.141 (14.1%), which is slightly below the limit of 15% that can affect the


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water saturation and fluid flow in the reservoir [9]. The calculated average water saturation for this

reservoir is 0.122 and average hydrocarbon saturation value of 0.878. The neutron-density plot (Fig.

8a),the crossover pattern of density and neutron log, combined with the high resistivity values at this

reservoir indicate that this reservoir is saturated with gas at the upper section and oil at the base. The

gas/oil contact is at 2645m depth. The average BVW value (0.029) for this reservoir indicates that the

sandstone is medium-grained. The computed petrophysical parameters for this reservoir are presented

in Table 3.

3.2. Petrophysical parameters and fluid saturation

A Pickett plot (Fig. 8b) for water saturation, with lines for BVW value, shows that the entire points

plot below the 0.4 water saturation line, but with majority plotting below the 0.2 water saturation line.

These low water saturation values are indications of high hydrocarbon saturation. It can be seen from

Fig. 8c (Buckles plot) that the points do not plot along any BVW hyperbolic curve, indicating that the

formation is not at irreducible water saturation. Therefore, hydrocarbons will be produced with some

amount of water.

Table 4 is a summary of results of the important petrophysical parameters utilized as variables to

determine reservoir quality. Considering these parameters across all the delineated reservoirs, there is

a decreasing trend with depth in the reservoirs’ average porosity (Fig. 9), with the values ranging from

0.160 to 0.300, indicating an outstanding reservoir quality and reflecting probably well sorted

sandstones with minimal cementation. This decreasing trend of porosity with reservoir depth can be

due to compaction caused by overburden pressure from overlying rocks. The reservoir units’ average

permeability value ranges from 255.2md to 1708.8md (Fig. 10). In the appraisal of a well's productivity,

the permeability of reservoir unit is an important parameter. The water saturations in the zones of

interest are generally very low, with average reservoir values ranging from 0.094 to 0.447 and an

increasing trend of these average water saturation values can be seen as we move from Zone A to Zone

N. The reservoirs show a decreasing trend in reservoir’s average hydrocarbon saturation values from

Zone A to N, with the values ranging from 0.553 to 0.906, but generally having very high hydrocarbon

saturation values. The occurrence of low shale volumes (0.033 to 0.161) in the reservoirs is another

important factor for the good porosity and permeability values. There is an increasing shale volume

trend with increasing depth. Fig. 11 shows an increasing trend in reservoir thickness from Zone A to

Zone E and an irregular pattern form Zone F to N. The resistivity values of formation water for the

various reservoir depths have a decreasing trend with depth. This might be due to increasing

temperature and salinity with depth.

From the reservoirs grain sizes determined from BVW values, a general shallow-up pattern

(coarsing-up pattern) can be seen, but in detail, there are some transgression and regression patterns.

Zone B, C, D, E, G, I, J, and N have thickness ranging from 11m to 32m, with Zone E being the thickest and

Zone A, F, H, K, L, and M have thicknesses below 10m, with Zone K being the smallest (2m thick). The

thick reservoirs indicate regressive sequences of sandstone and the shales, of up to 185m, represent the

transgressive sequences.

Table 2. Reservoir parameters obtained from parameters digitised from logs for Zone B

Depth (m)

Calculated

Porosity

(v/v)

Effective

Porosity

(v/v)

Shale

volume

(v/v)

Water

Saturation

(v/v)

Hydrocarbon

saturation

(v/v)

Permeability

(md)

Bulk

Volume

Water

2457.0 0.308 0.291 0.019 0.082 0.918 1271.6 0.025

2457.9 0.302 0.285 0.010 0.130 0.870 1088.0 0.039

2458.8 0.306 0.289 0.008 0.077 0.923 1207.1 0.024

2459.6 0.310 0.292 0.008 0.058 0.942 1317.4 0.018

2460.5 0.300 0.283 0.001 0.059 0.941 1035.7 0.018


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2461.4 0.310 0.293 0.004 0.055 0.945 1325.7 0.017

2462.3 0.293 0.275 0.008 0.055 0.945 850.3 0.016

2463.2 0.300 0.283 0.016 0.066 0.934 1023.7 0.020

2464.0 0.307 0.290 0.009 0.055 0.945 1246.1 0.017

2464.9 0.289 0.271 0.013 0.049 0.951 760.8 0.014

2465.8 0.317 0.300 0.011 0.043 0.957 1580.3 0.014

2466.7 0.319 0.302 0.006 0.043 0.957 1655.8 0.014

2467.6 0.321 0.304 0.002 0.043 0.957 1753.5 0.014

2468.4 0.319 0.302 0.013 0.052 0.948 1670.0 0.017

2469.3 0.310 0.293 0.033 0.120 0.880 1344.2 0.037

2470.2 0.319 0.302 0.008 0.104 0.896 1672.1 0.033

2471.1 0.304 0.287 0.008 0.095 0.905 1139.6 0.029

2472.0 0.254 0.236 0.058 0.061 0.939 273.7 0.015

2472.8 0.202 0.182 0.291 0.137 0.863 43.3 0.028

2473.7 0.168 0.148 0.217 0.187 0.813 10.1 0.032

2474.6 0.346 0.330 0.034 0.092 0.908 3194.0 0.032

2475.5 0.343 0.327 0.044 0.109 0.891 2984.0 0.037

2476.4 0.298 0.280 0.149 0.170 0.830 964.0 0.051

2477.2 0.298 0.281 0.141 0.176 0.824 975.4 0.053

2478.1 0.337 0.320 0.058 0.157 0.843 2570.1 0.053

2479.0 0.317 0.300 0.124 0.168 0.832 1593.9 0.053

Average 0.300 0.282 0.050 0.094 0.906 1328.9 0.028

Max. 0.346 0.330 0.291 0.187 0.957 3194.0 0.053

Min. 0.168 0.148 0.001 0.043 0.813 10.1 0.014

Table 3. Reservoir parameters obtained from parameters digitized from logs for Zone D

Depth (m)

Calculated

Porosity

(v/v)

Effective

Porosity

(v/v)

Shale

volume

(v/v)

Water

Saturation

(v/v)

Hydrocarbon

saturation

(v/v)

Permeability

(md)

Bulk

Volume

Water

2512.0 0.209 0.197 0.062 0.375 0.625 56.4 0.078

2512.7 0.324 0.319 0.018 0.168 0.832 1910.8 0.054

2513.5 0.357 0.350 0.020 0.169 0.831 4123.4 0.060

2514.2 0.312 0.305 0.024 0.147 0.853 1401.0 0.046

2514.9 0.283 0.280 0.014 0.238 0.762 649.5 0.068

2515.7 0.196 0.182 0.082 0.279 0.721 34.0 0.055

2516.4 0.261 0.255 0.025 0.238 0.762 338.3 0.062

2517.2 0.270 0.263 0.025 0.246 0.754 434.3 0.066

2517.9 0.257 0.252 0.022 0.278 0.722 295.8 0.071

2518.6 0.246 0.241 0.023 0.297 0.703 208.9 0.073

2519.4 0.244 0.240 0.017 0.308 0.692 193.2 0.075

2520.1 0.210 0.206 0.020 0.262 0.738 58.5 0.055

2520.8 0.225 0.220 0.025 0.268 0.732 102.0 0.060

2521.6 0.210 0.207 0.017 0.262 0.738 59.1 0.055

2522.3 0.189 0.184 0.032 0.258 0.742 25.7 0.049

2523.1 0.216 0.211 0.025 0.288 0.712 74.3 0.062

2523.8 0.197 0.192 0.026 0.266 0.734 35.1 0.052

2524.5 0.199 0.194 0.029 0.200 0.800 38.2 0.040

2525.3 0.201 0.198 0.017 0.363 0.637 41.8 0.073

2526.0 0.219 0.215 0.017 0.634 0.366 82.2 0.139

2526.7 0.222 0.220 0.012 0.672 0.328 93.2 0.149

2527.5 0.237 0.234 0.011 0.662 0.338 152.9 0.156

2528.2 0.225 0.222 0.016 0.654 0.346 103.3 0.147

2528.9 0.237 0.234 0.012 0.655 0.345 154.9 0.155

2529.7 0.233 0.231 0.010 0.643 0.357 134.1 0.150

2530.4 0.225 0.215 0.049 0.713 0.287 103.1 0.161

2531.2 0.223 0.213 0.048 0.672 0.328 95.0 0.150


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2531.9 0.237 0.234 0.014 0.626 0.374 153.9 0.148

2532.6 0.231 0.228 0.013 0.774 0.226 125.8 0.179

2533.4 0.236 0.232 0.019 0.719 0.281 147.9 0.169

2534.1 0.162 0.128 0.242 0.529 0.471 7.3 0.086

2534.8 0.205 0.195 0.055 0.500 0.500 48.5 0.103

2535.6 0.224 0.220 0.022 0.515 0.485 99.2 0.115

2536.3 0.246 0.243 0.013 0.727 0.273 206.0 0.178

2537.1 0.245 0.241 0.018 0.731 0.269 205.3 0.179

2537.8 0.227 0.223 0.022 0.654 0.346 110.7 0.148

2538.5 0.224 0.220 0.018 0.666 0.334 97.4 0.149

2539.3 0.209 0.201 0.043 0.579 0.421 56.1 0.121

2540.0 0.060 0.049 0.290 0.207 0.793 0.0 0.012

Average 0.229 0.223 0.038 0.447 0.553 314.3 0.101

Max. 0.357 0.350 0.290 0.774 0.853 4123.4 0.179

Min. 0.060 0.049 0.010 0.147 0.226 0.0 0.012

Table 4. Reservoir parameters obtained from parameters digitized from logs for Zone E

Depth

(m)

Calculated

Porosity

(v/v)

Effective

Porosity

(v/v)

Shale

volume

(v/v)

Water

Saturation

(v/v)

Hydrocarbon

saturation

(v/v)

Permeability

(md)

Bulk

Volume

Water

2615.0 0.176 0.141 0.230 0.316 0.684 14.7 0.056

2615.7 0.262 0.197 0.266 0.307 0.693 341.8 0.080

2616.4 0.301 0.259 0.148 0.143 0.857 1042.5 0.043

2617.1 0.224 0.137 0.425 0.223 0.777 100.1 0.050

2617.8 0.204 0.116 0.480 0.292 0.708 46.3 0.060

2618.5 0.251 0.196 0.238 0.290 0.710 246.8 0.073

2619.2 0.158 0.117 0.303 0.357 0.643 6.2 0.057

2619.9 0.169 0.124 0.301 0.335 0.665 10.3 0.057

2620.6 0.273 0.203 0.277 0.198 0.802 487.3 0.054

2621.3 0.167 0.107 0.409 0.289 0.711 9.3 0.048

2622.0 0.171 0.132 0.262 0.347 0.653 11.4 0.059

2622.7 0.157 0.127 0.219 0.237 0.763 5.7 0.037

2623.3 0.311 0.269 0.144 0.131 0.869 1369.7 0.041

2624.0 0.321 0.263 0.193 0.102 0.898 1775.0 0.033

2624.7 0.334 0.296 0.121 0.084 0.916 2436.2 0.028

2625.4 0.350 0.328 0.066 0.076 0.924 3478.4 0.027

2626.1 0.345 0.310 0.107 0.070 0.930 3147.4 0.024

2626.8 0.333 0.295 0.121 0.069 0.931 2379.9 0.023

2627.5 0.328 0.288 0.127 0.071 0.929 2090.2 0.023

2628.2 0.345 0.297 0.145 0.069 0.931 3126.2 0.024

2628.9 0.329 0.306 0.074 0.061 0.939 2137.9 0.020

2629.6 0.325 0.301 0.076 0.062 0.938 1926.9 0.020

2630.3 0.336 0.316 0.063 0.059 0.941 2519.9 0.020

2631.0 0.338 0.313 0.078 0.053 0.947 2642.5 0.018

2631.7 0.333 0.311 0.071 0.061 0.939 2385.5 0.020

2632.4 0.332 0.300 0.101 0.059 0.941 2322.0 0.020

2633.1 0.307 0.282 0.085 0.060 0.940 1222.5 0.018

2633.8 0.342 0.310 0.096 0.067 0.933 2906.8 0.023

2634.5 0.329 0.308 0.069 0.064 0.936 2143.0 0.021

2635.2 0.352 0.337 0.044 0.057 0.943 3640.8 0.020

2635.9 0.353 0.336 0.050 0.052 0.948 3739.0 0.018

2636.6 0.339 0.326 0.040 0.047 0.953 2691.8 0.016

2637.3 0.353 0.343 0.030 0.040 0.960 3797.3 0.014

2638.0 0.344 0.334 0.031 0.044 0.956 3031.9 0.015

2638.7 0.340 0.332 0.024 0.040 0.960 2760.8 0.014

2639.3 0.304 0.295 0.032 0.034 0.966 1138.1 0.010


12

2640.0 0.286 0.283 0.014 0.031 0.969 706.1 0.009

2640.7 0.229 0.222 0.036 0.036 0.964 119.7 0.008

2641.4 0.361 0.353 0.023 0.036 0.964 4507.7 0.013

2642.1 0.351 0.345 0.018 0.044 0.956 3568.7 0.015

2642.8 0.352 0.344 0.025 0.043 0.957 3677.4 0.015

2643.5 0.356 0.349 0.018 0.047 0.953 3985.7 0.017

2644.2 0.261 0.229 0.134 0.103 0.897 335.7 0.027

2644.9 0.225 0.203 0.107 0.101 0.899 101.2 0.023

2645.6 0.237 0.211 0.121 0.121 0.879 157.5 0.029

2646.3 0.185 0.137 0.295 0.091 0.909 21.5 0.017

2647.0 0.137 0.103 0.292 0.191 0.809 1.9 0.026

Average 0.288 0.256 0.141 0.122 0.878 1708.8 0.029

Max. 0.361 0.353 0.480 0.357 0.969 4507.7 0.080

Min. 0.137 0.103 0.014 0.031 0.643 1.9 0.008


13


14

Figure 6a. Neutron-density plot for the determination of

lithology and saturation type, for Zone B

Figure 7b. Pickett plot (saturation crossplot or resistivity-porosity crossplot, with BVW) illustrating water-bearing

and hydrocarbon-bearing zones and BVW for Zone B

Figure 8c. Buckles plots of water saturation against porosity in determining BVW and irreducible water

saturation for Zone B


lithology and saturation type, for Zone D


and hydrocarbon-bearing zones and BVW for Zone D


saturation for Zone D

0.01

0.1

1

0.01 0.1 1 10 100 1000

po

rosi

ty, v

/v

Resistivity, Ωm

Pickett Plot with BVW

Sw = 1

Sw =0.8

Sw =0.6

Sw =0.4

Sw =0.2

BVW =0.05

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

Po

rosi

ty, v

/v

Sw, v/v

Buckles Plot - Linear

BVW=0.05

BVW=0.07

BVW= 0.1

BVW=0.15

0.01

0.1

1

0.01 0.1 1 10 100 1000

po

rosi

ty, v

/v

Resistivity, Ωm


Sw =1

Sw =0.8

Sw =0.6

Sw =0.4

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

Po

rosi

ty, v

/v

Sw, v/v

Buckles Plot - Linear

BVW =0.05

BVW =0.07

BVW =0.1

BVW =0.15

BVWirr= 0.04

Data


15


lithology and saturation type, for Zone E


and hydrocarbon-bearing zones and BVW for Zone E


saturation for Zone E

Figure 9. A Chart showing the variation of porosity,

formation water resistivity, water saturation and hydrocarbon saturation from Zone A to Zone N

Figure 10. A graph of permeability variation from Zone A

to Zone N

Figure 11. Chart showing the variation of the various

reservoirs thicknesses and pay zones thicknesses

0.01

0.1

1

0.01 0.1 1 10 100 1000

po

rosi

ty, v

/v

Resistivity, Ωm


Sw = 1

Sw =0.8

Sw =0.6

Sw =0.4

Sw =0.2

0

0.2

0.4

0.6

0.8

1

0 0.5 1

Po

rosi

ty, v

/v

Sw, v/v

Buckles Plot - Linear BVW=0.05

BVW=0.07

BVW= 0.1

BVW=0.15

BVWirr =0.04

Data

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2

23

02

-231

0

24

57

-247

9

24

91

-250

9

25

12

-254

0

26

15

-264

7

27

14

-272

2

29

06

-291

7

29

26

-293

5

29

80

-299

4

30

12

-302

4

30

28

-303

0

30

91

-309

8

32

22

-322

6

32

31

-324

6

Reservoir Interval (m)

Variation of Petrophysical Parameters with Reservoirs Depth Porosity

Water Sat.

HC Sat.

Shale Volume

Rw

Trendline forporosityTrendline forWater Sat.Trendline forHC Sat.Trendline forVshTrendline forRw

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

1800.0

230

2-2

310

245

7-2

479

249

1-2

509

251

2-2

540

261

5-2

647

271

4-2

722

290

6-2

917

292

6-2

935

298

0-2

994

301

2-3

024

302

8-3

030

309

1-3

098

322

2-3

226

323

1-3

246

Pe

rmea

bili

ty (

md

)

Reservoir interval (m)

Variation of Permeability with Reservoirs Depth

Permeability

0

5

10

15

20

25

30

35

A B C D E F G H I J K L MN

Reserv

oir

's t

hic

kn

ess (

m)

Reservoir zone

Reservoir zones vs Gross, Net thicknesses

Gross thickness

Pay zone's thickness


16

4. Discussion

This study reveals that Well U4 consists of sandstone beds alternating with shales, which

corresponds to the Agbada Formation [12]. Generally, the reservoirs’ average shale volumes are very

low (ranging from 0.033 to 0.161), and similar values were determined by [21]. The resistivity values of

formation water for the various reservoir depths are similar to those of [22]. This research also reveals

that all the reservoirs studied at depth intervals of 2302m and 3246m, are saturated with hydrocarbons

and all, except two reservoirs are saturated entirely with natural gas. The high occurrence of gas in the

study area could be attributed to the remigration induced by tilting of reservoir beds during the latter

history of deposition within the down dip portion of the depo-belt, up dip flushing of accumulations by

gas generated at higher maturity, and/or heterogeneity of source rock type, as speculated by [14].

Natural gas is derived from Type III kerogen which is formed from terrestrial materials, with origin from

fibrous and woody plant fragments and structure less colloidal humic matter [23], and since the Agbada

Formation is made of paralic sediments, i.e. mixed continental, brackish water and marine deposits, the

Agbada Formation might be the source of this high occurrence of gas. The occurrences of oil in Zone D

and E are small relative to the gas-bearing zones in the two reservoirs. This is also an indication of

terrestrial origin of the hydrocarbons. The water saturations are relatively low, consequently giving the

reservoirs high hydrocarbon saturations; ranging from 55.3% to 90.6%. This low water saturation can

be due to tilting nature of the traps as speculated by [12] and also be attributed to the fact that where

there is the generation of Type III kerogen, there is little liquid hydrocarbon generating capacity [23].

These source rocks (shale) must have been subjected to maturation temperatures (> 175ºC) for a

considerable length of time for gas generation [24]. Possible hydrocarbon sources include variable

contributions from the marine interbedded shale in the Agbada Formation and the marine Akata shale,

and Cretaceous shale [2, 3, 11, 14, 25-27].

5. Conclusion

The results of the petrophysical evaluation show that delineated reservoir units have average

porosities ranging from 16.0% to 30.8%, reservoir’s average permeability values from 255.2md to

1708.8md, and very low shale volume values; which are indications of suitable reservoir qualities.

Hydrocarbon saturations range from 55.3% to 90.6%, implying high hydrocarbon potential. In addition

to the petrophysical parameters, the thicknesses of the reservoirs ranging from 2m-32m, suggest high

hydrocarbon potential. Therefore, with these suitable reservoir conditions and high hydrocarbon

saturations, this area seems satisfactory for hydrocarbon (gas) exploitation. Despite these favorable

reservoir conditions, decisions on economic production of hydrocarbon should not be based solely on

wireline logs.

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Documents

Petrophysical Characterization of Agbada Formation