Post on 15-Apr-2017
The Five Reservoir Fluids
Black Volatile Retrograde Wet Dry
Oil Oil Gas Gas Gas
Objectives
The Five Reservoir Fluids
Phase Diagrams of Mixtures of
Ethane and n-Heptane
10
9
8
7
6
5
4
3
2
1
No. Wt % ethane
1 100.00
2 90.22
3 70.22
4 50.25
5 29.91
6 9.78
7 6.14
8 3.27
9 1.25
10 n-Heptane
Composition
1400
1200
1000
400
600
800
200
0 200 300 400 500 100
Pre
ss
ure
, p
sia
Temperature, °F
Phase Diagram - Typical Black Oil
Black Oil
Critical point
Pre
ssu
re,
psia
Separator
Pressure path in reservoir
Dewpoint line
% Liquid
Temperature, °F
Phase Diagram of a Typical Volatile Oil
Pre
ssu
re
Temperature, °F
Separator
% Liquid
Volatile oil
Pressure path in reservoir
3
2
1 Critical point
Phase Diagram of Near-Critical Fluid
Temperature, °F
Pre
ss
ure
, p
sia
50 100 150 200 250 300 350 0
1000
3000
2000
4000
5000
Dewpoint
line Bubblepoint
line
Estimated critical
point
15%
15%
10%
10%
5%
5% 0%
10 5
15 20
30 25
40 35
50
60
70 80 90
100
Phase Diagram of a Typical Retrograde Gas
3
Separator
% Liquid
Pressure path in reservoir
1
2 Retrograde gas
Critical point
Pre
ssu
re
Temperature
Phase Diagram of Retrograde Gas
Temperature, °F
Pre
ss
ure
, p
sia
50 100 150 200 250 300 350 0
1000
3000
2000
4000
5000
Dewpoint line
Estimated critical point
15%
15%
10%
10%
5% liquid
5% 0%
30%
40%
40%
10%
20%
Phase Diagram of Typical Wet Gas P
ressu
re
Temperature
% Liquid
2
1
Pressure path in reservoir
Wet gas
Critical point
Separator
Phase Diagram of Typical Dry Gas P
ressu
re
Temperature
% Liquid
2
1
Pressure path in reservoir
Dry gas
Separator
Phase Diagram of a Reservoir Fluid
Temperature, °F
-200 -150 -100 -50 0 50
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
Pre
ssu
re,
psia
Critical point
The Five
Reservoir
Fluids
Black Oil
Critical point
Pre
ss
ure
, p
sia
Separator
Pressure path in reservoir
Dewpoint line
% Liquid
Temperature, °F
Pre
ss
ure
Temperature
Separator
% Liquid
Volatile oil
Pressure path in reservoir
3
2
1 Critical point
3
Separator
% Liquid
Pressure path in reservoir
1
2 Retrograde gas
Critical
point Pre
ss
ure
Temperature
Pre
ss
ure
Temperature
% Liquid
2
1
Pressure path in reservoir
Wet gas
Critical point
Separator
Pre
ss
ure
Temperature
% Liquid
2
1
Pressure path in reservoir
Dry gas
Separator
Retrograde Gas Wet Gas Dry Gas
Black Oil Volatile Oil
The Five
Reservoir
Fluids
Black Oil
Critical point
Pre
ss
ure
, p
sia
Separator
Pressure path in reservoir
Dewpoint line
% Liquid
Temperature, °F
Pre
ss
ure
Temperature
Separator
% Liquid
Volatile oil
Pressure path in reservoir
3
2
1 Critical point
3
Separator
% Liquid
Pressure path in reservoir
1
2 Retrograde gas
Critical
point Pre
ss
ure
Temperature
Pre
ss
ure
Temperature
% Liquid
2
1
Pressure path in reservoir
Wet gas
Critical point
Separator
Pre
ss
ure
Temperature
% Liquid
2
1
Pressure path in reservoir
Dry gas
Separator
Retrograde Gas Wet Gas Dry Gas
Black Oil Volatile Oil
The Five
Reservoir
Fluids
Black Oil
Critical point
Pre
ss
ure
, p
sia
Separator
Pressure path in reservoir
Dewpoint line
% Liquid
Temperature, °F
Pre
ss
ure
Temperature
Separator
% Liquid
Volatile oil
Pressure path in reservoir
3
2
1 Critical point
3
Separator
% Liquid
Pressure path in reservoir
1
2 Retrograde gas
Critical
point Pre
ss
ure
Temperature
Pre
ss
ure
Temperature
% Liquid
2
1
Pressure path in reservoir
Wet gas
Critical point
Separator
Pre
ss
ure
Temperature
% Liquid
2
1
Pressure path in reservoir
Dry gas
Separator
Retrograde Gas Wet Gas Dry Gas
Black Oil Volatile Oil
Components of Naturally
Occurring Petroleum Fluids Component Composition,
mole percent
Hydrogen sulfide 4.91Carbon dioxide 11.01Nitrogen 0.51Methane 57.70Ethane 7.22Propane 4.45i-Butane 0.96n-Butane 1.95i-Pentane 0.78n-Pentane 0.71Hexanes 1.45Heptanes plus 8.35
100.00Properties of heptanes plusSpecific Gravity 0.807Molecular Weight 142 lb/lb mole
Initial Producing GLR
Correlates With C7+
0
20000
40000
60000
80000
100000
0 10 20 30 40 50
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
ga
s/liq
uid
ra
tio
, s
cf/
ST
B
Dewpoint gas
Bubblepoint oil
Initial Producing GLR
Correlates With C7+
10
100
1000
10000
100000
1000000
0.1 1 10 100
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
ga
s/liq
uid
ra
tio
, s
cf/
ST
B
Dewpoint gas
Bubblepoint oil
Initial Producing GLR
Correlates With C7+
100
1000
10000
100000
0.1 1 10 100
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
gas/o
il r
ati
o, scf/
ST
B
Initial Producing GLR
Correlates With C7+
10
100
1000
10000
0 20 40 60 80 100
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
gas
/liq
uid
rati
o, scf/
ST
B
Initial Producing GLR
Correlates With C7+
0
10000
20000
30000
40000
50000
0 5 10 15 20 25 30
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
gas/o
il r
ati
o, scf/
ST
B
Dewpoint gas
Bubblepoint oil
Retrograde Gases and Volatile
Oils - What’s the Difference?
2000
3000
4000
5000
10 11 12 13 14 15
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
gas/liq
uid
rati
o, scf/
ST
B
Oils and Gases - What’s the
Difference?
2000
3000
4000
5000
10 11 12 13 14 15
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
gas
/liq
uid
rati
o, scf/
ST
B
Oils and Gases - What’s the
Difference?
2000
5000
10 11 12 13 14 15
Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
gas/liq
uid
rati
o, scf/
ST
B
3200
Oil
res bbl oil
STB Bo =
Se
pa
rato
r
Stock tank
p > pb
scf
STB Rsb =
res bbl
STB
scf
scf
res bbl gas
Mscf Bg =
Gas res bbl
scf
Black Oils and Volatile
Oils-What’s the Difference?
Jacoby and Berry Calculations
Volatile oil material balance (1)
Conventional material balance
2400 1600 800 0
2000
0
4000
6000
Pre
ssu
re,
psia
Stock-tank oil production, MSTB
Volatile oil
method
Conventional
method
0 3000 6000 0
50
100
Pressure, psia
Gas s
atu
rati
on
%
po
re s
pace
Stock-tank oil production, MSTB
0
120000
0
40000
160000
Volatile oil material balance (1)
Conventional material balance
80000
1000 2000
Se
pa
rato
r g
as
/oil
ra
tio
scf/
ST
B
Jacoby and Berry Calculations -
Compared With Actual Production
Stock-tank oil production
0
120000
0
40000
160000
Volatile oil material balance (1)
Conventional material balance
80000
1 2
Sep
ara
tor
gas/o
il r
ati
o
scf/
ST
B
Actual performance
Volatile oil material balance (1)
Conventional material balance
2400 1600 800 0
2000
0
4000
6000
Pre
ssu
re,
psia
Stock-tank oil production
Actual
performance
Three Gases - What Are the
Differences?
• Dry gas - gas at surface is same as gas
in reservoir
• Wet gas - recombined surface gas and
condensate represents gas in reservoir
• Retrograde gas - recombined surface
gas and condensate represents the gas
in the reservoir But not the total
reservoir fluid (retrograde condensate
stays in reservoir)
Compressibility Factors of a Rich Gas-
Condensate as Functions of Pressure
Gas-phase
Two-phase
0 1000 2000 3000 4000
Pressure, psia
0.5
0.6
0.7
0.8
0.9
1.0 C
om
pre
ss
ibilit
y f
ac
tor,
z
Two-Phase Compressibility Factor as a Function of
Pseudoreduced Pressure for All Available Data
0 0.0
4 8 12 16 20 24
0.5
1.0
1.5
2.0
Ac
tua
l tw
o-p
ha
se
Z f
ac
tor
Pseudoreduced pressure
Two-Phase Compressibility Factor as a Function of
Pseudoreduced Pressure for Data Set 1
0 0.0
4 8 12 16 20 24
0.5
1.0
1.5
2.0
Ac
tua
l tw
o-p
ha
se
Z f
ac
tor
Pseudoreduced pressure
Two-Phase Compressibility Factor as a Function of
Pseudoreduced Pressure for Data Set 2
0 0.0
4 8 12 16 20 24
0.5
1.0
1.5
2.0
Ac
tua
l tw
o-p
ha
se
Z f
ac
tor
Pseudoreduced pressure
0
50000
0 30Heptanes plus in reservoir fluid, mole %
Init
ial p
rod
uc
ing
ga
s/o
il r
ati
o, s
cf/
ST
B
Retrograde
gas
Volatile
oil
Wet
gas
Dry
gas
Black
oil
Dewpoint gas
Bubblepoint oil
Field Identification
BlackOil
VolatileOil
RetrogradeGas
WetGas
DryGas
InitialProducingGas/LiquidRatio, scf/STB
<1750 1750 to3200
> 3200 > 15,000* 100,000*
Initial Stock-Tank Liquid
Gravity, API
< 45 > 40 > 40 Up to 70 NoLiquid
Color of Stock-Tank Liquid
Dark Colored LightlyColored
WaterWhite
NoLiquid
*For Engineering Purposes
Laboratory Analysis
BlackOil
VolatileOil
RetrogradeGas
WetGas
DryGas
PhaseChange inReservoir
Bubblepoint Bubblepoint Dewpoint NoPhase
Change
NoPhase
Change
HeptanesPlus, MolePercent
> 20% 20 to 12.5 < 12.5 < 4* < 0.8*
OilFormationVolumeFactor atBubblepoint
< 2.0 > 2.0 - - -
*For Engineering Purposes
Primary Production Trends G
OR
GO
R
GO
R
GO
R
GO
R
Time Time Time
Time Time Time Time Time
Time Time
No
liquid
No
liquid
Dry
Gas
Wet
Gas
Retrograde
Gas
Volatile
Oil
Black
Oil
A
PI
A
PI
A
PI
A
PI
A
PI
Exercise 1
Determine reservoir fluid type from
field data.
Plot of Exercise 1 Data
0 0 12 24 36 48 60 72
50
51
52
53
54
55
60
59
58
57
56
100000
90000
80000
70000
60000
50000
40000
30000
10000
20000
Months since start of 1967
Pro
du
cin
g
ga
s/o
il r
ati
o, s
cf/
ST
B
Sto
ck
-tan
k
liqu
id g
ravity, A
PI
Exercise 2
Determine reservoir fluid type from
field data.
Exercise 3
Determine reservoir fluid type
from field data.
Plot of Exercise 3 Data
100
200
300
400
500
0 2 4 6 8 10 12
Months since start of production
Pro
du
cin
g
ga
s/o
il r
ati
o, s
cf/
ST
B
Plot of Exercise 3 Data
Three-Month Running Average
Months since start of production
Pro
du
cin
g
gas
/oil r
ati
o, scf/
ST
B
100
200
300
400
500
0 2 4 6 8 10 12
Exercise 4
Determine reservoir fluid type
from field data.
Plot of Exercise 4 Data
Three-Month Running Average
28000
37000
0 13
Months since start of production
Pro
du
cin
g
gas/o
il r
ati
o, scf/
ST
B
Exercise 5
Determine reservoir fluid type
from field data.
Plot of Exercise 5 Data
50000
200000
1981 1988Year
Pro
du
cin
g
gas/o
il r
ati
o,
scf/
ST
B
40
55
1981 1988
Sto
ck-t
an
k
liq
uid
gra
vit
y, A
PI
Year
Exercise 6
0
25
50
75
100
125
150
175
200
0 24 48 72 96 120
Months since start of 1966
Ye
ild
, S
TB
/MM
sc
f
Exercise 7
0
50000
0 24Months since start of production
Pro
du
cin
g
ga
s/o
il r
ati
o, s
cf/
ST
B