2. Rock Properties
▪ Porosity:
▸ The rock porosity is the space available for the
different fluids to occupy; oil, gas and water. The
porosity is defined as the pore or the void space in
the reservoir rock and is expressed as a percentage
of the total volume of the rock
▸ The OOIP and IGIP is proportional to the porosity
▸ Porosity types:
– Intergranular; common in sandstone, or
– Vugular, which is more common in carbonate
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5. Rock Properties
1. Effective Porosity:
The reservoir fluids, present in the pore space, can only be
produced if the pore space is connected. The volume of the
connected pore space is defined as the "effective porosity"
2. Ineffective Porosity:
Conversely, the percentage of the pore space that is not
connected (dead end) is defined as "ineffective porosity”
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6. Rock Properties
When porosity was developed ?
▸Primary porosity: Rock porosity developed during
the initial rock deposition
▸Secondary porosity: Rock porosity due to a
chemical reaction between the reservoir fluids and the
rock, which could occur for instance if some of the rock
minerals are dissolved by the formation water
(Leaching). This phenomena is called "Diagenesis"
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8. How is porosity determined ?
▸Open hole logs
– Sonic
– Neutron/density
▸Core samples
– Full core diameter
– Side-wall plugs
– Drilling cuttings
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9. Core Analysis
▸ Core plugs vs. full core
diameter (plug selection,
fractures, vugs)
▸ Overburden pressure
correction (for permeability
rocks)
▸ Core cleaning (humidity
oven)
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10. Rock Properties
Rock Permeability
▸Permeability is a measure of the fluid ability to flow
through the connected pores of the reservoir
▸The permeability is expressed in millidarcies or
darcies
▸The rock permeability is measured from core samples
(plugs or whole core) in the laboratory or it could also
be calculated from well testing
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12. Averaging of Permeability/Porosity Values:
▪ Arithmetic Average (parallel beds)
▪ Harmonic Average (beds in series)
▪ Geometric Average (cross flow)
K
K K K K
n
a
1 2 3 n
=
+ + +
K
n
1/K 1/K 1/K 1/K
H
1 2 3 n
=
+ + +
K (K K K K)
G 1 2 3 n
1
/n
= + + +
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13. Types of Permeability Definitions:
▸Absolute Permeability (kab):
▸Permeability is a measure of the fluid ability to flow
through the connected pores of the reservoir
▸Relative Permeability (kr):
▸measured in the laboratory for a specific fluid when a
core sample is saturated with more than one fluid
▸Effective Permeability (keff)
▸Permeability determined for the produced fluids from
“PTA”, or:
▸Keff = Kab x Kr
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15. Rock Properties
Relative Permeability is used to:
▸Determine flow characteristics under different wetting
fluid (water) saturations
▸Determine residual fluid saturations
▸Evaluate the efficiency of secondary and tertiary
E.O.R. schemes
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16. Hysteresis Phenomena
Drainage/Imbibition describes the
direction of saturation change of
the wetting phase
–Drainage: in oil/water system
describes the decrease in water
saturation
–Imbibition: in oil/water system
describes the increase in water
saturation
–Hysteresis Phenomena: effects only
the non-wetting fluids, due to fluid
trapping of the non- wetting fluid
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17. Rock Properties
Rock Wettability:
Rock Wettability reflects the rock’s
preferential tendency to adsorb oil or
water
Water wettability is favourable
- Oil flow is favoured
- Higher waterflood recovery factor is
expected
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18. Comparison of Rock Wettability
Water-Wet Rock
▪ Relative permeability curves cross-
over at Sw>50%
▪ Dressed profile of Krw (low value of
end-point Krw
▪ High initial Swi
Oil-Wet Rock
▪ Relative permeability curves
cross-over at Sw<50%
▪ Enhanced profile of Krw (low
value of end-point Krw
▪ Low initial Swi
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22. Rock Properties
Capillary Pressure (Pc)
Where:
T: Surface tension (fluid property),
dyn/cm
R: Radius (rock property k, ϕ), ft
θ: Contact angle (wettability fluid-rock)
ρ: Fluid density (fluid property), Ib/ft3
h: Fluid height, ft
P
T
r
g h
c = =
cosθ
ρ
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26. Rock Properties
Use of Capillary Pressure (Pc)
1. Determine height of transition zone, h
Where:
PcL: Capillary pressure in Laboratory, psi
PcR: Capillary pressure at reservoir condition, psi
h: Height above free water level, ft
P
P
T
T
cL
cR
L
R
=
( cos )
( cos )
θ
θ P P
T
T
cR cL
R
L
= .
( cos )
( cos )
θ
θ
h
P
P
T
T
cR
w o
cL
R
L
w o
=
−
=
−
(
.
( cos )
( cos )
(
) )
ρ ρ
θ
θ
ρ ρ
2. Determination of Connate Water Saturation, Swi
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27. Rock Properties
▪ As reservoir pressure declines (overburden pressure is constant)
rock porosity ϕ drops by 1/2% for ∆P = 1000 psi
Sandstone compressibility 3.5 to 5.0 10-6 psi-1
Limestone compressibility 3.8 to 10.0 10-6 psi-1
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28. Rock Properties
Rock Compressibility
▸Sandstone compressibility; (3.5 to 5.0) x 10-6 psi-1
▸Limestone compressibility; (3.8 to 10.0) x 10-6 psi-1
▸As reservoir pressure declines (overburden pressure is
constant) rock porosity drops.
▸ ϕ drops by 1/2% for ∆P = 1000 psi
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