Shale volume (Vsh) estimation has been carried out on three selected reservoirs (Nan.1, Nan.2, and Nan.4) distributed across four wells (01, 03, 06, and 12) in Nantin Field, using petrophysical analysis and reservoir modeling techniques with a view to understanding the reservoir elastic properties. Materials utilized for this research work include: Well Log data (Gamma Ray Log, Resistivity Log, Sonic Log, Density Log, Neutron porosity log), and a 3-D Seismic volume were used for the study. Sand and shale were the prevalent lithologies in Nantin Field. Nan. 1 reservoir was thickest in Nantin well 12 (29.7ft), Nantin 2 reservoir was thickest in Nantin Well 12 (30.9ft) while Nantin 4 reservoir was thickest in Well 3 (72ft). Correlation well panel across the Field showed that Nantin 4 reservoir, was thicker than Nan 1 and Nan 2 Reservoir respectively. Normal and synthetic Faults were also mapped, the trapping system in the field includes anticlines in association with fault closures. The thicknesses and lateral extents of these reservoirs were delineated into three zones (1, 2, and 3) which were modeled appropriately. Petrophysical and some elasticity parameters such as Poisson ratio (PR), Acoustic Impedance (AI), and Reflectivity Coefficient (RC) were evaluated for the wells. The results from elasticity evaluation showed a high Poisson Ratio of 0.40 in Nantin 2 reservoir of Well 12 based on high shale volume distribution of 0.70 indicating high stress level and possible boundary to hydraulic fracture. The lowest Poisson Ratio was evaluated in Nantin reservoir of Well 1 with lowest shale volume of 0.18 which indicates weak zones and may not constrain a fracturing job. Results from Acoustic impedance showed a high AI value of 7994.3 in Nan 2 Reservoir compared to Nan.1 which has the least AI value of 7447.3 because of low shale volume. A higher Reflectivity Coefficient of 0.01 was recorded in Nan.2 reservoir indicating bright spot while a lower RC of -0.00023 was recorded in Nan.4 Reservoir indicating dim spot. Hydrocarbon volume estimate of the three reservoirs showed 163mmstb in Nan.1 reservoir, 169mmstb, in Nantin 2 reservoir and 115mmstb in Nan. 4 Reservoir. The reservoirs encountered were faulted and laterally extensive. Nantin 2 reservoir was more prolific with a STOIIP of 169 mmstb compared to Nan. 1 with a STOIP of 163 mmstb and Nantin.4 with a STOIP of 115 mmstb, because of its good petrophysical values, facies quality and low shale volume distributions.

1. Eje, E. O and Ideozu, R. U
Presented At the Nigerian Mining and Geosciences Society
International Conference Holding at Bayero University Kano
(New Campus)
Date: March 18 to March 23 2018
EFFECTS OF SHALE VOLUME
DISTRIBUTION ON THE ELASTIC PROPERTIES OF
RESERVOIRS IN ‘NANTIN’ FIELD, NIGER DELTA.

2. PRESENTATION OUTLINE
• INTRODUCTION
• MATERIALS AND METHODS
• RESULTS
• DISCUSSION
• SUMMARY
• CONCLUSION

3. INTRODUCTION
BACKGROUND TO STUDY:
Niger Delta basin:
 One of the most prolific basin in the world has both offshore and onshore fields.
 Area of about 295,000 km2
.
 Estimated reserve of about 35 billion barrels of oil and 2.5 billion cubic feet of gas.
 Petroleum is one the world’s major source of energy and is a key factor
in the continued developments of world’s economy in spite of the current
global economic melt down.
 It is essential that, planners, future planners, government cooperation's
and international Oil Companies doing business in Nigeria have a clear
assessment and management of already discovered reserves in order to
optimise production.
Hence, the elastic properties of the reservoirs in Nanti Field and shale
volume distribution cannot be overlooked.

4. • Reservoir elasticity varies significantly from reservoir to
reservoir as a result of the complex nature of different
properties that make up this important component of the
petroleum system.
• One of the properties, is the shale volume distribution,
which imposes an elastic property on the reservoir (Crane
E, 2000).
• The elastic properties of reservoirs are strongly anisotropic
in most cases and the degree of this anisotropy is a function
of the volume of clay/shale, organic materials and the shale
fabric.
INTRODUCTION contd

5. •Shale volume in a reservoir, reduces Net To Gross - NTG - (tight
reservoir), total porosity and effective permeability.
•Existence of shale causes uncertainties in Formation evaluation and
proper estimation of oil and gas reserve. In addition the presence of
shale also causes well bore instability.
•When these volumes of Shale are correctly estimated, alternative
methods of reservoir management can be employed in order to
optimize productions.
• Available research has shown that, most of the reservoirs in
Nantin Field have experienced unprecedented decline in
production over time.
• Hence, the need to identify the cause of decline in
production hence this research.

6. Figure 1.1 Location map of the study area
modified from Mitchum, 2006
LOCATION OF THE STUDY AREA:
“NANTIN” Field is located within Coastal Swamp Depobelt of the Niger
Delta, between Longitudes 7o
to 8o
E and Latitudes 4o
to 4.5o
N
Figure 1.2: Base map of the study
area showing the Distribution of Wells
within the Nantin Field

7. STRATIGRAPHY OF THE STUDY
AREA
Figure 2: Stratigraphic column of the Niger Delta. After Shannon et al. and Doust et al
The geology of the Niger Delta is well
established, the stratigraphic and
structural framework and petroleum
geology (Doust and Omatsola, 1989,
1990; Reijers, 1996; Kulke, 1995;
Ekweozor and Daukoru, 1994;
Evamy et al, 1978)

8. MATERIALS AND METHODS
MATERIALS;
The following materials have been used in this research
• Base map of the study area,
• Well Header (ASCII)
• Petrel software 2010 version,
• Microsoft suite,
• Wireline log suits ( Gamma rays, resistivity and density
neutron combination) for four (4) wells,
• 3D seismic data

9. METHODS.
The following steps were taken;
• Loading of data into the appropriate software and carry out
quality control on the data
• interpretation of the various log suits and seismic sections
• Identify geologic features within the study area
• shale volume estimation and reservoir elasticity.
• Petrophysical evaluations such as Porosity, permeability,
Water saturation, Net to Gross etc.
• Volumetric estimation

10. FLOW CHART
Figure 1.4a; Shows the work flow for the job

11. 11
Figure 1.4b; Fish diagram that shows the relation between shale volume estimation
and elasticity properties

12. 12
Table 2: The functions of every log in petrophysical and rock
physics properties calculation and analysis
NAME USES
Gamma Ray (GR) Lithology interpretation, shale volume calculation, calculate clay volume,
permeability calculation, porosity calculation, wave velocity calculation,
etc.
Spontaneous Potential
(SP)
Lithology interpretation, Rw and Rwe calculation, detect permeable zone,
etc
Deep Resistivity ILD Lithology interpretation, finding hydrocarbon bearing zone, calculate
water saturation, etc.
Density (RHOB) Lithology interpretation, finding hydrocarbon bearing zone, porosity
calculation, rock physics properties (AI, SI, σ, etc.) calculation, etc
Nuetron Porosity (NPHI) Finding hydrocarbon bearing zone, porosity calculation, etc.
Sonic (DT) Porosity calculation, wave velocity calculation, rock physics properties
(AI, SI, σ, etc.) calculation, etc

13. PERMEABILITY
Where
K is the permeability,
φ is the porosity, and
Swirr is the irreducible water saturation (In this research work, 0.3 was used as for the
variable). From the formula above, it is assumed that if the irreducible water saturation is at 1,
then the permeability will be zero
K= 387+26552ɸ2
-34540( xSwir)ɸ 2
(Owolabi et al., 1994

14. SOME ELASTICITY EQUATIONS
• Acoustic Impedance (AI),
• AI =ρ x Vp
• RC = AI2 –AI1
• AI2 + AI1
• Poisson Ratio (σ), etc. and most of them depend on the wave velocity
and density.
PR = 0.125 x Vsh+0.27 Crane E. R. (2000)
Where:
Ρ = Density

15. 15
S/N FORMULA Definitions of parameters
1 IGR= (GRlog-GRmin)
(GRmax-GRmin)
IGR is the gamma ray index,
GRlog is the gamma ray response in the zone of interest,
GRmin is the gamma ray response in cleanest formation,
GRmax is the gamma ray response in shale layer.
2 Vsh = 0.083(23.7 X
IGR-1)
The shale volume (Vsh) can be calculated from the gamma ray
index proposed by Larionox 1969 for Tertiary rock
3 Φd = ρmatrix – ρlog
ρmatrix - ρfluid
ρmatrix is the matrix density (the value depends on the
lithology on using Haliburton reference table), ρfluid is the fluid
density,
ρlog is the density log reading,
φd is the density-derived porosity,
4 Sw = 0.082
ᶲ
Sh = hydrocarbon saturation
Sw= water saturation
1= Unity
Sh = (1-Sw)
Table 2; Some petrophysical formula

16. 16
RESULT AND INTERPRETATION
Well Correlation
Well correlation involves the splitting of potential reservoir zones from non reservoir zones
across the field.
fig. 2.0; well correlation across Nantin Field
N

17. 17
Lithologic Analysis
Lithologic results from well logs indicate sand and shale as two principal lithologies
predominant in NANTIN Field
Sand Analysis and Correlation
Three (3) reservoirs of interest were correlated in the field. They are NAN 1, Nan. 2 and Nan.
4
Reservoirs Well 1 (ft) Well 3 (ft) Well 6(ft) Well 12 (ft)
Nan. 1 16.1 20.3 27.2 29
Nan. 2 30 26.5 30.9 21
Nan. 4 40 72 44 52
Table 3; Reservoir Thickness correlation results

18. 18
Fault Interpretation
Fifteen (15) faults were identified in the field trending NW/SE directions were mapped from the
seismic section with series of colours. The NANTIN Field has is a complex NW/SE dipping
anticlinal structure with small scale antithetic and synthetic faults, typical of the Niger Delta fault
system. (figure 2.2)
Figure 2.2; Interpreted Faults and Horizons
reflecting Nan. 1, 2 and 4 Reservoirs
Figure 2.3 Interpreted faults on Z-Line
(Realized)

19. 19
Well-to-seismic tie
•Well to seismic tie is used to linked information from well logs to the seismic section.
•It involves forward modelling of a synthetic seismogram from sonic and velocity logs,
•then matching that synthetic to seismic reflection data thereby producing a relationship
between the logs (measured in depth) and the seismic (measured in time)
Figure 2.4 Unmatched synthetic
seismogram
Figure 2.5; Matched synthetic seismogram for
NANTIN FIELD

20. 20
TWT AGAINST DEPTH
To check velocity anomaly.
Figure 2.4, A plot of time versus depth of the checkshot

21. 21
Figure 2.5; Nan. 1 reservoir time surface map
Figure 2.6; Nan. 2 time reservoir surface map
Figure 1.7; Nan.4 time reservoir surface map

22. 22
Figure 2.7; Nan 1 reservoir depth surface map
Figure 2.8; Nan.2 reservoir depth surface
Figure 2.9; Nan.4 reservoir depth surface

23. 23
Reservoir Models
Reservoir modelling in the IOC’s is aimed at facilitating the evaluation of a field for optimal
production. Hence, a field evaluation is necessary only where it provides the most ideal
model of the reservoir. In this research, reservoir model was generated for petrophysical
and elasticity parameters like porosity, permeability, Net-to-gross, water saturation etc. The
three horizons interpreted were grouped into three (3) zones.
Figure 3.0; Nan. 1 fluid distribution model
Figure 3.1; Nan.2 fluid distribution model
Figure 3.2; Nan.4 fluid distribution model
High

24. 24
Figure 4.10; Nan. 1 Top structural map
Figure 4.11; Nan. 2 Top structural Map

25. 25
Figure 3.3; Nan.1 Volume of Shale (Vsh) model Figure 3.4 Nan.2 Volume of Shale (Vsh) model
Figure 3.5, Nan.4 Volume of Shale (Vsh) model
Low High

26. 26
Figure 3.5; Nan.1 Porosity model
Figure 3.6; Nan.2 Porosity model
Figure 3.7 Nan.4 Porosity model
Figure 3.8 Nan.1 Permeability model
Figure 3.9; Nan.2 Permeability model
Figure 4.0Nan.4 Permeability model
High
High
Low

27. 27
Figure 4.1 ; Nan.1 Water Saturation model
Figure 4.2; Nan.2 Water Saturation model
Figure 4.3; Nan.4 Water Saturation model
Figure 4.4 Nan.1 NTG model
Figure 4.5; Nan.2 NTG model
Figure4.6;Nan.4 NTG model
Low High
High Low

28. 28
PETROPHYSICAL INTERPRETATION
Hydrocarbon potentials of the identified reservoir sands were
discovered in their petrophysical properties. These properties
include ; Porosity, Permeability ,Water saturation , Net –to- gross
1 Porosity Model
Porosity is the measure of the void spaces in a rock. It is between 0 and 100%. The
porosity of a rock play a fundamental role when evaluating the potential volume
of water or hydrocarbon saturation in the reservoirs .Nan.1, Nan.2, and Nan.4
reservoirs have good to Very good porosity values as shown in the average
petrophysical values.
2 PERMEABILITY MODEL
This is a dynamic flow character of the model in the reservoir. The model below
shows that the permeability values in Nan.1. Nan 2 and Nan. 4 reservoir have very
good to excellent permeability with Nan.2 reservoir in well 3 having the highest
permeability values of (1742Md) while Nan. 4 reservoir in Well 6 have the lowest
permeability values of (1015Md) as shown in table

29. 29
4 WATER SATURATION
From the water saturation model, Nan. 4 reservoirs in Well 6 have higher water saturation
values of (0.56) Nan. 1 Well 6, Nan.2 Well 6 Nan.1 Well 6, Nan. 1 Well 12 and Nan 4 Well 12
have water saturations of (0.40) respectively depicting low water saturation in turn high
hydrocarbon saturation.
Reservoirs Thickness(ft) Vsh
(Fract)
Poro T
(Fraction)
Water
Sat(Fract)
Permeabilit
y
(MD)
NTG
(Fraction)
F
(Fract)
SH
Nan. 1 16.6 0.30 0.18 0.45 1205.71 1.00 24.45 0.55
Nan. 2 30 0.29 0.17 0.51 1024.96 0.96 31.74 0.49
Nan. 4 40 0.18 0.18 0.53 3544.21 1.00 39.80 0.47
Table 5 Average Petrophysical values for NANTIN WELL 1
Table 6; Average Petrophysical values for NANTIN WELL 3
Reservoir
s
Thicknes
s (ft)
Vsh
(Fract
)
Poro T
(Fract)
Water Sat.
(Fraction)
Permeabi
lity
(MD)
NTG
(Fract
)
F
(Fract
)
SH
Nan. 1 20.3 0.39 0.19 0.44 1377.99 0.4 23.94 0.56
Nan. 2 26.5 0.39 0.23 0.38 1742.05 0.32 18.14 0.62
Nan. 4 72 0.35 0.20 0.46 1392.10 0.41 27.33 0.55

30. 30
Reservoir
s
Thickness(ft
)
Vsh
(Frac)
Poro T
(Fract)
Water Sat.
(Fract)
Permeabilit
y
(MD)
NTG
(Fract)
F
(Fraction)
SH
Nan. 1 27.2 0.41 0.19 0.45 1320.00 0.45 28.14 0.55
Nan. 2 30.9 0.51 0.18 0.49 1168.95 0.25 30.61 0.51
Nan. 4 44 0.26 0.16 0.55 1015.38 0.70 52.63 0.45
Table 7 Average Petrophysical values for NANTIN WELL 6
Table 9. Average Petrophysical values for NANTIN WELL 12
Reservoirs Thickness
(ft)
Vsh
(Fract)
Poro T
(Fract)
Water Sat.
(Fract)
Permeabilit
y
(MD)
NTG
(Fract)
F
(Fraction)
SH
Nan. 1 29.7 0.47 0.22 0.39 11631.37 0.30 20.86 0.61
Nan. 2 21 0.68 0.19 0.45 1260.15 0.00 25.11 0.55
Nan. 4 52 0.38 0.21 0.40 1531.21 0.43 19.74 0.60

31. 31
Table 7.0 Average Comparison of Poisson Ratio and Shale Volume distribution for NANTIN
WELL 1
Reservoir Shale Volume Vsh Poisson Ratio
Nan 1. 0.30 0.31
Nan2 0.29 0.31
Nan 4 0.18 0.29
Table 7.1Average Comparison of Poisson Ratio and Shale Volume distribution for
NANTIN WELL 3
Reservoir Shale Volume Vsh Poisson Ratio
Nan 1. 0.39 0.32
Nan2 0.39 0.32
Nan 4 0.34 0.31
Table 7.2 Average Comparison of Poisson Ratio and Shale Volume distribution for
NANTIN WELL 6
Reservoir Shale Volume Vsh Poisson Ratio
Nan 1. 0.41 0.32
Nan2 0.51 0.33
Nan 4 0.26 0.30

32. 32
Table 7.3. Average Comparison of Poisson Ratio and Shale Volume distribution for NANTIN
WELL 12
Reservoir Shale Volume Vsh Poisson Ratio
Nan 1. 0.47 0.33
Nan2 0.68 0.40
Nan 4 0.38 0.32
Reservoir Vshale RC AI
Nan. 1 0.30 0.00089 7447.73
Nan. 2 0.29 0.01 7994.63
Nan. 4 0.18 -0.0002 80003.8
Table 2.3b: Average Acoustic Impedance and Reflectivity Coefficient

33. 33
Figure 1.5; Depth Vs Acoustic Impedance for Nan. 4 Reservoir
Figure 1.6; Depth Vs Acoustic Impedance for Nan. 4 Reservoir
Figure 1.33; Cross Plot between Depth Vs Acoustic Impedance (AI) for Nan. 1 Reservoir. The black circle shows the AI
anomaly

34. 34
VOLUME ESTIMATION
Volume estimation was done in the three Zones of both Nan.1, Nan.2 and Nan.4 reservoirs using the
following equations.
Bulk Volume (Bv) = Area x Thickness = reservoir thickness (m) x Area extent (m2
)
Where 1m3 = 6.29 oil barrels
Net Volume = NTG x Bv = Bulk volume x Net/Gross
Pore volume = Bv x x NTG = Bulk volume x Net/Gross x Porosityɸ
HCPV = Hs x Pv = Bulk volume x Net/Gross x porosity x Hydrocarbon Saturation
STOIIP = A x H x (1-Sw) x 7758 x NTGɸ
Bo
Where;
STOIIP = Stock Tank Oil Initially in Place
7758= barrels per foot
H = Reservoir Thickness in ft
Sh = (1-Sw) hydrocarbon saturation indecimals
Bo = Oil formation volume factors
GOR (Gas oil Ratio) = Gas oil in cubic feet
Oil in barrels
A= Drainage area in acres

35. 35
Table 8.0 Nan.1 Reservoir Volume estimation

36. 36
Table 8.2; Nan.2 Reservoir Volume estimation

37. 37
Table 8.3; Nan.4 Reservoir Volume estimation

38. 38
Table 8.4; Volume Comparison
Reservoirs Zones STOIIP (*10^6STB)
Nan 1 Zone 1 38
Zone 2 48
Zone 3 56
Zone 4 20
163
Nan 2 Zone 1 83
Zone 2 56
Zone 3 29
169
Nan 3 Zone 1 93
Zone 2 18
Zone 3 4
115

39. 39
SUMMARY AND CONCLUSION
Well Correlation
Three reservoirs units (Nan. 1, Nan. 2 and Nan. 4) were correlated in NANTIN Field
with Spontaneous potential and Gamma Ray logs. Nan. 1 reservoir was thickest in
Nantin well 12 (29.7ft), Nan. 2 sand was thickest in Nantin well 12 (30.9ft) while
Nan. 4 sand was thickest in well 3 (72ft). Correlation well panel and sand analysis
shows that, Nan. 4 reservoir was thicker than Nan 1 and Nan 2 Reservoir in the
Field.
Seismic Interpretation
Interpretations from the seismic section gave an insight into the structural
configuration of NANTIN Field. The Field was charactized by anticlines and fault
closures. These are good structures for hydrocarbon accumulation.
Elasticity Evaluation
The result from elasticity evaluation shows a high Poisson Ratio of (0.40) in Nan. 2 reservoir
of well 12 as result of the highest shale distribution of (0.70) that was recorded in the Field,
which indicates high stress level which in turns indicates possible boundary to hydraulic
fracture. The lowest Poisson Ratio was evaluated in Nan. 4 reservoir of Well 1 with the
lowest shale volume of (0.18) which indicate weak zones which may not constrain the
fracturing job.

40. 40
Petrophysical Evaluation
The result obtained from petropysical evaluation showed that, good to very good effective
porosity values as obtained in the three reservoir across the field shows some level of
variations due to different estimated volume of shale in the their reservoir. The permeability
in this field was ranked as good while water saturation of 0.30 to 0.50 across the reservoir is
an indicative of higher quantity of hydrocarbon in Nan.2 reservoir than water in Nan. 4
reservoir. The Net-to-Gross was high in Nan.1 due to low shale volume. These results are
inadequate for the two reservoirs to be excellent and producible.
Facies Analysis and Depositional Environment
Result from facies interpretation shows that, three log facies were recognized in the study
area. They are bell, cylindrical and funnel motifs which indicated paleoenvironment of
prograding Delta, Delta distributary channel turbidite (submarine channel). The prograding
Delta and the Delta distributary channel belong to the deltaic system and were interpreted
as the reservoir of Agbada Formation. The prograding submarine channels belonged to the
deep marine setting which may be a deposit of upper Akata Formation. The presence of
submarine channels suggest that stratigraphic traps are inherent in Nantin field and hence
favour hydrocarbon accumulation (Pettingill and Weimer, 2002)
Petrophysical Modelling
Petrophysical modeling results reveal that, reservoir sand with high shale volume is tight
hence has low permeability compared to other reservoir the same field

41. 41
Conclusion
The following conclusions were made from this study.
1. Sand and shale were the two key lithologic units identified in the study area.
2. Three Reservoirs (Nan. 1, Nan. 2 and Nan. 4) were delineated in “NANTIN” Field.
The reservoirs encountered were faulted and laterally extensive. Nan. 2 reservoir
was more prolific with a STOIIP of (169 mmstb) compared to Nan. 1 and Nan. 4
due to its good petrophysical values and facies quality
3. The petrophysical properties of the delineated reservoirs were good to very
good except in well 12 due to high shale volume distribution of (0.70) and the
resulting high poisson ratio of (0.40). The STOIIP in thisreservoir is (115 mmstb)
which the lowest.
4. Fault closures and roll over anticlines were the major trapping configuration in
NANTIN Field.
5. Petrophysical modeling showed NANTIN prospecting zone towards North West
Zone

42. 42
THANKS