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Properties of Reservoir Fluids
as function of
PVT
Pressure
Volume
Temperature
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Main Reservoir Fluids:
Black Oil p>pb Bo, o, co are ASSUMED constant
Solution-Gas Drive ppd Bg, g, cg = f(p)
PVT Behaviour
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Schematic Phase Diagrams Generic (single and multi-component cases) Black Oil Solution-Gas Drive Dry Gas
Black Oil (p>pb) Properties: Bo, o, co (ASSUMED constant)
Solution-Gas Drive (ppd) Properties: Bg, g, cg
Summary of Fluid Properties and Sources
Reservoir Fluids
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Pressure - Volume Behaviour
Single Component System
Liquid
Gas
Pressure
Volume
Bubble
point
FIRST BUBBLE
OF GAS
LAST DROP
OF LIQUID
Dew
point
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Pressure vs Temperature
Single Component System
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3D Phase Diagram
Single Component System
Liquid
Gas
Pressure
VolumeTe
mpera
ture
Liquid
GasCritical
point
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Pressure - Volume Behaviour
Two Component System
Liquid
Gas
Pressure
Volume
Bubble
point
FIRST BUBBLE
OF GAS LAST DROP
OF LIQUID
Dew
point
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P - T Behaviour
2 Component System
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Note the "Bubble Point" and "Dew Point" lines.
Location of critical point determines fluid type.
Diagram for a
Mult i-Component System
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Hydrocarbon Reservoir Fluids types
Reservoir Fluids
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Black Oil :
o>40o API, (GOR)i
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Volatile Oil:
o
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Retrograde Gas :
45
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Wet Gas: (GOR)i >50,000 scf/STB.
Reservoir Fluids
Wet Gas p-T Diagram
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Dry Gas
Reservoir Fluids
Dry Gas p-T Diagram
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Formation Volume Factor: Bo,g,w
The Formation Volume Factor"converts" surfacevolumes to downhole conditions.
Typical values:Oil: 1.2 to 2.4 RB/STBGas: 0.003 to 0.01 rcf/scf
100 to 333 scf/rcf (=expansion factor)
Bo,g,w =Fluidvolume at standard conditions
Fluid volume at reservoir conditions
Reservoir Fluids
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Formation Volume factors
BoBw
Bg
Reservoir conditions
Surface conditions
GasWaterOil
OilGas
Solution
gas
Water
Solutiongas
Rs Rsw
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Retrograde Gas Condensate
Bg
Reservoir conditions
Surface conditions
Gas
Gas
Condensate
GLR
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Viscosity: o,g,w
Is a measure of a fluid's internal resistance to flow,- the proportionality of shear rate to shear stress- a sort of internal friction.
Fluid viscosity depends on pressure, temperature and fluidcomposition.
Typical values:
Oil: 0.2 to 30 cpGas: 0.01 to 0.05 cp
Reservoir Fluids
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Compressibility
Important reservoir parameters:
drained area
permeability
reservoir thickness
porosity
compressibility
Of importance is the TOTAL system compressibility:
ct = chc.Shc + cw.Sw + cf
HC: hydrocarbon, w: water, f: formation
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Hydrocarbon Compressibility: co,g
Oil
Typical values p > pb 5 to 20 x10-6 psi-1
p < pb 30 to 200 x10-6 psi-1
Gas
Typical values 50 to 1000 x10-6 psi-1
dp
dR
B
B
dp
dB
Bc so
o
go
oo +=
1
dp
dB
Bc
g
gg
1=
Compressibility
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Water
Typical values 3 to 5 x10-6 psi-1
Formation
Typical values: 2 to 10 x10-6 psi-1 normal
10 to 100 x10-6 psi-1 very high
dp
dR
B
B
dp
dB
Bc sw
w
gw
ww +=
1
dp
dcf
1=
Compressibility
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Rs/pb Bo o co
Standing ; ; - -
Lasater - - -
Vasquez and Beggs - ;
Glaso -
Lasater- Standing - - -
Petrosky and Farshad -
Beggs and Robinson - ; -
Beal - - -
; generally used as default)
Oil PVT Correlations used in Topaze or Saphir
Fluid Correlations
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z-factor g
Dranchuk, et al. -
Beggs and Brill ; -
Hall and Yarborough -
Lee, et al. - ;
Carr, et al. -
; generally used as default
Gas PVT Correlations used in Topaze or Saphir
Gas compressibility (cg) is computed fromthe z-factor using:
dp
dz
zpdp
dB
Bc
g
gg
111==
Gas Correlations
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Black Oil PVT Properties: (general behavior, pb=5000 psia)
General Oil Properties
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Oil Reservoir below Bubble Point:
"Solution-Gas Drive"
1. Pressure above Bubble Point. Wells
produce oil and associated gas.
2. Pressure drops below Bubble Point.
Bubbles of solution gas form in
reservoir.
3. Critical gas saturation reached.
Gas is now mobile.
4. Gas flows towards producing wells.
Wells now produce oil, associated gas
and solution gas.
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1. As fluid is produced, the reservoir pressure drops towards abandonment.
2. The Oil production is high at first, rapidly dropping off as more gas is produced.
3. At critical gas saturation, the Gas-Oil ratio rises rapidly to a maximum, then
falls as the lower gas compressibility offsets the increased gas mobility.
Oil Reservoir below Bubble Point:
"Solution-Gas Drive"
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Dry Gas
In terms of equations solutions the main difference betweenthe oil and gas case is that the gas properties are highlypressure dependent.
Viscosity g and Compressibility ctare function of thepressure
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Dry gas
In order to keep the liquid flow equations linear, the variationsin gas properties are accounted for by the real gas pseudo-pressure function
( )( ) ( )
m pp dp
p z pp
p
= 2
0
.
.
Pseudo-pressure function is then substituted forpressure in the analysis.
To take into account the varying mgcg a pseudo- time can beused in the analysis.
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References
1. Fundamentals of Reservoir Engineering Calhoun (1953).
2. Properties of Petroleum Fluids McCain (1990).