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Copyright 2008, NExT, All rights reserved
Basics of Reservoir Engineering Module I
I.1.A - Fundamentals of Reservoir Phase Behavior
Copyright 2008, NExT, All rights reserved
Understanding Phase Behavior
Naturally occurring hydrocarbon mixtures found in petroleum reservoirs are mixtures of organic compounds and few non-hydrocarbons that may exist in gaseous or liquid states.
Differences in the phase behavior of these mixtures over a wide ranges of pressures and temperature ultimately determine the production characteristics of hydrocarbon reservoirs.
Copyright 2008, NExT, All rights reserved
Why study Phase Behavior?
As oil and gas are produced from the reservoir, they are subjected to a series of pressure, temperature, and compositional changes.
Such changes affect the volumetric and transport behavior of these reservoir fluids and, consequently, the produced oil and gas volumes.
All reservoir performance equations (e.g., Darcys law, materialbalances) require the knowledge of fluid properties. It is impossible to correctly evaluate well productivity and reservoirperformance if fluid properties are not known.
Copyright 2008, NExT, All rights reserved
Phase Behavior - Pure Substance
LiquidSolid
GasVapor-p
ressure
line
Mel
ting-
poin
t lin
e C
T
TemperatureTc
pc
P
r
e
s
s
u
r
e
Copyright 2008, NExT, All rights reserved
Phase Behavior - Pure Substance
LiquidSolid
GasVapor-p
ressure
line
Mel
ting-
poin
t lin
e C
T
TemperatureTc
pc
P
r
e
s
s
u
r
e
Critical Point
Triple Point
Copyright 2008, NExT, All rights reserved
Phase Behavior - Pure Substance
Copyright 2008, NExT, All rights reserved
Phase Behavior - Pure Substance
400
500
600
700
800
900
1000
1100
1200
0 0.05 0.1 0.15 0.2 0.25
P
r
e
s
s
u
r
e
,
p
s
i
a
Specific volume, cu ft/lb
Two-phase region 60F
70F
80F85F
90F=Tc
95F
100F
110F
130F
160F
C
Copyright 2008, NExT, All rights reserved
Phase Behavior - Mixtures
Dewpoint
300 oF
350 oF
400 oF
425 oF
450 oF454 oF
Critical pointBu
bble
poin
t
400
300
200
0.1 0.2 0.3 0.4
P
r
e
s
s
u
r
e
,
p
s
i
a
Volume, cu ft/lb
Copyright 2008, NExT, All rights reserved
Phase Behavior - Mixtures
MIXTUREPURE SUBSTANCE
Copyright 2008, NExT, All rights reserved
Phase Behavior - Mixtures
Pressure, p
Temp, T
CP
The less alike the molecules,
the farther apart BP and DP Curves!
BP Curve
DP Curve
L + V co-existence
T > TcGAS
T < TcLIQUID
There is no real transition!
Copyright 2008, NExT, All rights reserved
Phase Diagrams of Mixtures of Ethane and n-Heptane
10
987
6
5
4
3
2
1
No. Wt % ethane1 100.002 90.223 70.224 50.255 29.916 9.787 6.148 3.279 1.25
10 n-Heptane
Composition
1000
400
600
800
200
0200 300 400 500100
P
r
e
s
s
u
r
e
,
p
s
i
a
Pure nC7
Pure C2
1400
1200
Temperature, F
Copyright 2008, NExT, All rights reserved
Phase Diagram of a Reservoir Fluid
Temperature, F
-200 -150 -100 -50 0 50
14001300120011001000900800700600500400300200100
0
P
r
e
s
s
u
r
e
,
p
s
i
a
Criticalpoint
100%
Liq
uid
1
102
520
50
Copyright 2008, NExT, All rights reserved
The Five Reservoir Fluids
Black Oil
Criticalpoint
P
r
e
s
s
u
r
e
,
p
s
i
a
Bubbl
epoint
line
Separator
Pressure pathin reservoir Dewpoint line
9080
907060
5040
10
30
20
% Liquid
Temperature, F
Black Oil
The Five Reservoir Fluids
P
r
e
s
s
u
r
e
Temperature
Separator
% Liquid
Bubb
lepoin
t line
Dewpoint line
Dewpoint line
Volatile oil
Pressure pathin reservoir
3
2
1
5
10
30
20
40
5060
708090
Criticalpoint
Volatile Oil
The Five Reservoir Fluids
3
3020
15
10
40
Separator
% Liquid
Pressure pathin reservoir
1
2Retrograde gas
Criticalpoint
Bubb
lepoin
t line
Dewp
oint li
ne
50
P
r
e
s
s
u
r
e
Temperature
Retrograde Gas
P
r
e
s
s
u
r
e
Temperature
% Liquid
2
1
Pressure pathin reservoir
Wet gas
Criticalpoint
Bubb
lepo
int
line
Separator
152530
Dew
poin
t lin
e
Wet GasP
r
e
s
s
u
r
e
Temperature
% Liquid
2
1
Pressure pathin reservoir
Dry gas
Separator
Dew
poin
t lin
e15
0Dry Gas
25
Copyright 2008, NExT, All rights reserved
Phase Diagram of a Typical Black Oil
Black Oil
Criticalpoint
P
r
e
s
s
u
r
e
,
p
s
i
a
Bubbl
e-poin
t Line
Separator
Pressure pathin reservoir
Dewpoint line
9080
7060
5040
10
30
20
% Liquid
Temperature, F
An Oil Reservoir: Tr < Tc ( Bubblepoint Oil )
Copyright 2008, NExT, All rights reserved
Phase Diagram of a Typical Volatile Oil
P
r
e
s
s
u
r
e
Temperature, F
Separator
% Liquid
Bubb
lepoin
t line
Dewpoint line
Dewpoint line
Volatile oil
Pressure pathin reservoir
3
2
1
5
10
30
20
40
5060
708090
Criticalpoint
An Oil Reservoir: Tr < Tc ( Bubblepoint Oil )
Copyright 2008, NExT, All rights reserved
Phase Diagram of a Typical Retrograde Gas
A Gas Reservoir: Tr > Tc (dewpoint system)
3
3020
15
10
40
Separator
% Liquid
Pressure pathin reservoir1
2Retrograde gas
Critical point
Bubb
lepoin
t line
Dewp
oint li
ne
50
P
r
e
s
s
u
r
e
Temperature
Copyright 2008, NExT, All rights reserved
Phase Diagram of Typical Wet Gas
A Gas Reservoir: Tr > TcP
r
e
s
s
u
r
e
Temperature
% Liquid
2
1
Pressure pathin reservoir
Wet gas
Criticalpoint
Bubb
lepo
int
line
Separator
152530
Dew
poin
t lin
e
Copyright 2008, NExT, All rights reserved
Phase Diagram of Typical Dry Gas
A Gas Reservoir: Tr > TcP
r
e
s
s
u
r
e
Temperature
% Liquid2
1
Pressure pathin reservoir
Dry gas
Separator
Dew
poin
t lin
e1
50 25
Copyright 2008, NExT, All rights reserved
Field Identification of Reservoir FluidsThe Concept of GOR
Gasres bbl Oil
S
e
p
a
r
a
t
o
r
Stocktank
scfSTB
GOR =
STB
scf
scf
res bbl
Copyright 2008, NExT, All rights reserved
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
Copyright 2008, NExT, All rights reserved
Initial Producing GOR Correlates With C7+
0
20000
40000
60000
80000
100000
0 10 20 30 40 50
Heptanes plus in reservoir fluid, mole %
I
n
i
t
i
a
l
p
r
o
d
u
c
i
n
g
g
a
s
/
l
i
q
u
i
d
r
a
t
i
o
,
s
c
f
/
S
T
B
Dewpoint gasBubblepoint oil
Copyright 2008, NExT, All rights reserved
Initial Producing GLR Correlates With C7+
100
1000
10000
100000
0.1 1 10 100
Heptanes plus in reservoir fluid, mole %
I
n
i
t
i
a
l
p
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
Dew point gases
Copyright 2008, NExT, All rights reserved
Initial Producing GLR Correlates With C7+
10
100
1000
10000
0 20 40 60 80 100
Heptanes plus in reservoir fluid, mole %
I
n
i
t
i
a
l
p
r
o
d
u
c
i
n
g
g
a
s
/
l
i
q
u
i
d
r
a
t
i
o
,
s
c
f
/
S
T
B
Bubblepoint oils
Copyright 2008, NExT, All rights reserved
Initial Producing GLR Correlates With C7+
0
50000
0 30Heptanes plus in reservoir fluid, mole %
I
n
i
t
i
a
l
p
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
Retrogradegas
Volatileoil
Wetgas
Drygas
Blackoil
Dewpoint gasBubblepoint oil
Copyright 2008, NExT, All rights reserved
Field Identification
Black Oil
Volatile Oil
Retrograde Gas
Wet Gas
Dry Gas
Initial Producing Gas/Liquid Ratio, scf/STB
3200 > 15,000* 100,000*
Initial Stock-Tank Liquid Gravity, API
< 45 > 40 > 40 Up to 70 No Liquid
Color of Stock-Tank Liquid
Dark Colored Lightly Colored
Water White
No Liquid
*For Engineering Purposes
Copyright 2008, NExT, All rights reserved
Laboratory Analysis
BlackOil
VolatileOil
RetrogradeGas
WetGas
DryGas
PhaseChange inReservoir
Bubblepoint Bubblepoint Dewpoint NoPhase
Change
NoPhase
ChangeHeptanesPlus, MolePercent
> 20% 20 to 12.5 < 12.5 < 4* < 0.8*
OilFormationVolumeFactor atBubblepoint
< 2.0 > 2.0 - - -
*For Engineering Purposes
Copyright 2008, NExT, All rights reserved
Primary Production TrendsG
O
R
G
O
R
G
O
R
G
O
R
G
O
R
Time Time Time
TimeTimeTimeTimeTime
TimeTime
Noliquid
Noliquid
DryGas
WetGas
RetrogradeGas
VolatileOil
BlackOil
A
P
I
A
P
I
A
P
I
A
P
I
A
P
I
Copyright 2008, NExT, All rights reserved
Exercise 1Determine reservoir fluid type from field data
One of the wells in the Merit field, completed in December 1967 in the North Rodessa formation, originally produced 54API stock-tank liquid at a gas/oil ratio of about 23,000 scf/STB. During July 1969, the well produced 1987 STB of 58API liquid and 78,946 Mscf of gas. By May 1972, the well was producing liquid at a rate of about 30 STB/d of 59API liquid and gas at about 2,000 Mscf/d.
What type of reservoir fluid is this well producing?
Copyright 2008, NExT, All rights reserved
Plot of Exercise 1 Data
00 12 24 36 48 60 72
505152535455
6059585756
10000090000800007000060000500004000030000
1000020000
Months since start of 1967
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
Stock-tankliquid gravity, A
PI
Copyright 2008, NExT, All rights reserved
Exercise 2Determine reservoir fluid type from field data
A field in north Louisiana discovered in 1953 and developed by 1956 had an initial producing gas/oil ratio of 2,000 scf/STB. The stock-tank liquid was medium orange and had a gravity of 51.2API. Classify this reservoir fluid. Laboratory analysis of a sample from this reservoir gave the following composition: Component Composition,
mole fractionCO2 0.0218N2 0.0167C1 0.6051C2 0.0752C3 0.0474C4s 0.0412C5 0.0297C6s 0.0138C7 0.1491
1.0000Properties of heptanes plusSpecific Gravity 0.799Molecular Weight 181 lb/lb mole
Copyright 2008, NExT, All rights reserved
Exercise 3Determine reservoir fluid type from field data
The reported production from the discovery well of the Nancy (Norphlet) field is given below. How would you classify this reservoir fluid? Why?
DateStock-Tank
Liquid GravityAPI
Oil,STB
Gas,Mscf
9/86 29 4,276 1,16510/86 28 16,108 5,27011/86 28 15,232 4,80012/86 28 15,585 4,9601/87 28 15,226 4,6502/87 28 14,147 4,3353/87 28 15,720 4,7074/87 28 15,885 4,9045/87 28 15,434 4,9796/87 28 12,862 4,3397/87 28 14,879 4,8148/87 28 15,192 4,270
Copyright 2008, NExT, All rights reserved
Plot of Exercise 3 Data
100
200
300
400
500
0 2 4 6 8 10 12
Months since start of production
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
Copyright 2008, NExT, All rights reserved
Plot of Exercise 3 Data Three-Month Running Average
Months since start of production
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
100
200
300
400
500
0 2 4 6 8 10 12
Copyright 2008, NExT, All rights reserved
Exercise 4Determine reservoir fluid type from field data
The Crown Zellerbach No. 1 was the discovery well in the Hooker (Rodessa) field. The reported production during the first year of production is given below. How would you classify this reservoir fluid? Why?
Monthly Production
DateStock-Tank
Liquid GravityAPI
Oil, STB Water, STB Gas, Mscf
Apr 1984 - 112 - 3,362May 1984 55 1,810 12,090 54,809Jun 1984 55 2,519 180 64,104Jul 1984 55 3,230 240 94,419
Aug 1984 55 3,722 279 119,151Sep 1984 54 2,780 248 100,235Oct 1984 55 3,137 270 113,359Nov 1984 56 2,291 210 80,083Dec 1984 56 2,108 217 71,412Jan 1985 56 1,799 203 60,279Feb 1985 56 1,422 196 57,626Mar 1985 56 1,861 186 60,330
Copyright 2008, NExT, All rights reserved
Plot of Exercise 4 DataThree-Month Running Average
28000
37000
0 13
Months since start of production
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
Copyright 2008, NExT, All rights reserved
Exercise 5Determine reservoir fluid type from field data
Here we present the GOR plot based on three month running average data for Exercise 4.
Annual Production
DateStock-Tank
Liquid GravityAPI
Oil, STB Water, STB Gas, Mscf
1982 46 4,646 1,484 462,2651983 50 2,606 1,177 342,0751984 47 1,350 1,215 241,0481985 48 1,430 932 221,0201986 50 1,662 1,122 267,106
*1987 51 1,110 665 178,951*through August 1987
Copyright 2008, NExT, All rights reserved
Plot of Exercise 5 Data
50000
200000
1981 1988Year
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
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r
a
t
i
o
,
s
c
f
/
S
T
B
40
55
1981 1988
S
t
o
c
k
-
t
a
n
k
l
i
q
u
i
d
g
r
a
v
i
t
y
,
A
P
I
Year
Copyright 2008, NExT, All rights reserved
Exercise 6Determine reservoir fluid type from field data
0
25
50
75
100
125
150
175
200
0 24 48 72 96 120
Months since start of 1966
Y
e
i
l
d
,
S
T
B
/
M
M
s
c
f
The following liquid yield production data is available for a given reservoir. Can you identify the fluid?
Copyright 2008, NExT, All rights reserved
Basics of Reservoir Engineering
Natural Gas Properties
Copyright 2008, NExT, All rights reserved
Phase Behavior
Relationship between conditions (Pressure, Temperature, Volume) and phases (liquid, gas, solid)
Copyright 2008, NExT, All rights reserved
Ideal Gas Equation Of State
The simplest PVT model: the ideal gas.
Assumptions of the ideal model:
Volume occupied by molecules is insignificant compared to volume of gas
No attractive or repulsive forces between molecules
MTRpv
TRMmpV
TRnpV
=
==
Copyright 2008, NExT, All rights reserved
Real Gas Equation of State
z is called compressibility factor:
Also called gas deviation factor, supercompressibility, or z-factor.M
RTzvp
TRMmzVp
TRnzVp
=
==
ideal
real
VVz =
idealreal
ideal
VzpTRnzV
pTRnV
==
=
Copyright 2008, NExT, All rights reserved
Typical Shape of z-Factor
Pressure, p
Actual V greater than ideal V
Actual V less than ideal VCo
m
p
r
e
s
s
i
b
i
l
i
t
y
f
a
c
t
o
r
,
z
1.0
z approaches 1.0
0 0
Temp
eratur
e = co
nstan
t
Copyright 2008, NExT, All rights reserved
z-Factors For Methane
0 1000
Methane1.1
0.9
0.1
0.7
0.3
0.52000
3000
4000
5000
1000080006000
1.0
1.2
1.4
1.6
-84
-70
-54
-4
-22
-40
140104
44
32
212 170
240
-84 -70-54 -4-22-40
32
140104
44
212170
240
262342 320404
262320
404342
RTVpZ M=
RTVpZ M=
Pressure, psia
Copyright 2008, NExT, All rights reserved
z-Factors and Corresponding States
By defining reduced conditions Tr = T/Tc; Pr= P/Pc, z-factor isothermsfor different substances tend to collapse to a universal z-factor curve:
Reduced pressure, pr
C
o
m
p
r
e
s
s
i
b
i
l
i
t
y
f
a
c
t
o
r
,
z
=
p
V
R
T
3.01.80 1.2 2.40.60
1.0
0.6
0.8
0.4
0.2
Tr = 0.9Tr = 1.0
Tr = 1.1
Tr = 1.2
Tr = 1.3
Tr = 1.5
C5 H
12C
6 H14
C3 H
8
CH4
C6H14
C5H12
C5H12
C5H12
C5H12
CH4
CH4
CH4
CH4
C3H8
C3H8
C3H8
C3H8
C5H12
CH4C3H8
Copyright 2008, NExT, All rights reserved
z-Factors for Naturally Occurring Gas Mixtures
0.9
1.1
7 8 9 10 11 12 13 14 15
Pseudoreduced pressure, ppr
C
o
m
p
r
e
s
s
i
b
i
l
i
t
y
f
a
c
t
o
r
,
z
1.0
0.4
0.25
0.5
0.3
0.6
1.1
1.0
0.70.80.9
1.01.11.21.31.4
1.71.61.5
1.01.1
0 1 4 6 7 82 3 5Pseudoreduced pressure, ppr
1.05
1.1
1.151.2
1.251.3
1.351.41.451.51.61.71.81.9
2.0 2.22.42.6
2.83.0Pseudoreduced Temperature
1.1
1.21.31.41.5
1.61.7 1.8
1.92.0 2.2
2.42.63.0
1.051.11.2
1.41.71.81.92.02.22.4
3.0
2.6
1.6 1.3
1.05
2.8
C
o
m
p
r
e
s
s
i
b
i
l
i
t
y
f
a
c
t
o
r
,
z
Copyright 2008, NExT, All rights reserved
Molecular Weight Calculation
The apparent molecular weight of a natural gas is calculated as the weighted average of the molecular weight of all its components:
= jja MyM
Copyright 2008, NExT, All rights reserved
Physical Constants
Physical constants of single components are tabulated! Critical Constants
Compound Formula Molar Mass, molecular weight
Pressure, psia
Temperature, F
Methane CH4 16.043 666.4 -116.67 Ethane C2 H6 30.070 706.5 89.92 Propane C3H8 44.097 616.0 206.06 Isobutane C4H10 58.123 527.9 274.46 n-Butane C4H10 58.123 500.6 305.62 Isopentane C5H12 72.150 490.4 369.10 n-Pentane C5H12 72.150 488.6 385.8 Neopentane C5H12 72.150 464.0 321.13 n-Hexane C6H14 86.177 436.9 453.6 2-Methylpentane C6H14 86.177 436.6 435.83 3-Methylepntane C6H14 86.177 453.1 448.4 Neophexane C6H14 86.177 446.8 420.13 2,3-Dimethylbutane C6H14 86.177 453.5 440.29 Hydrogen sulfide H2S 34.08 1300. 212.45 Carbon Dioxide CO2 44.010 1071. 87.91 Nitrogen N2 28.0134 493.1 -232.51 Argon A 39.944 704.2 -188.53 Oxygen O2 31.999 731.4 -181.43
Copyright 2008, NExT, All rights reserved
Exercise 7Calculate Apparent Molecular Weight of Gas Mixture
Dry air is a gas mixture consisting of nitrogen, oxygen, and small amounts of other gases. Compute the apparent molecular weight of air given its approximate composition.
Component Composition,mole fraction
Nitrogen 0.7809Oxygen 0.2095Argon 0.0093Carbon dioxide 0.0003
1.0000
Copyright 2008, NExT, All rights reserved
Specific Gravity Of Gas
29g
air
g
air
gg
M
TRMpTRMp
===
Gas specific gravities are calculated as the ratio of gas density to the density of air, both measured at the same temperature and pressure, usually 60F and atmospheric pressure
air
gg
= , which becomes:
Copyright 2008, NExT, All rights reserved
Exercise 8Calculate Specific Gravity of Gas Mixture
Component Composition, molepercent
hydrogen sulfide 0.00carbon dioxide 0.00nitrogen 0.00methane 96.13ethane 1.50propane 0.88iso-butane 0.15n-butane 0.16iso-pentane 0.08n-pentane 0.06hexanes 0.10heptanes plus 0.94
100.00
Properties of Heptanes PlusDensity, gm/cc @ 60F 0.798Molecular weight 164
Copyright 2008, NExT, All rights reserved
Gas Density
Calculated as a function of Z:
Units - lb/cu ft
or
TRzMp
g =
ftpsi
ftsqinsqftculbg =
/144/
0
0.15
0 10000
g
,
p
s
i
/
f
t
p, psia
Copyright 2008, NExT, All rights reserved
Gas Formation Volume Factor (Bg)
Definition - volume of gas at reservoir conditions required to produce one standard volume of gas at the surface
Units - rcf/scf (res cu ft/scf)res bbl/scfres bbl/Mscf
Symbol - Bg
res bbl gasMscfBg =Gas
res bblS
e
p
a
r
a
t
o
r
Stocktank
STB
scf
scf
Copyright 2008, NExT, All rights reserved
Gas Formation Volume Factor (Bg)
Equation:
or
sc
Rg VVB =
scfftcures
pTz
TpBsc
scg =
Mscfbblres
pTz
Tp
ftcubbl
MB
sc
scg
=
615.51000
0
40
0 10000B
g
,
r
e
s
b
b
l
/
M
s
c
f
p, psia
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Gas Viscosity
Definition - The resistance to flow exerted by a fluid, i.e., large values = low flow rate. Units - centipoise or centistoke
0
0.05
0 10000
g
,
c
p
p, psia
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Gas Viscosity
Gas Viscosity Correlation Equation (Lee-Gonzalez)
whereA = f(Ma, T)B = f(Ma, T)C = f(Ma, T)
Thusg = f(g, Ma, T) or g = f(z, Ma, T)
( ) ( )Cgg BEXPA 410=
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Coefficient of Isothermal Compressibility of Gas(Gas Compressibility)
0
7000
0 10000p
c gx
106
Tg p
VV
c
= 1Definition
Ideal Gas
Real Gas
pcg
1=
Tg p
zzp
c
= 11
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Gas Properties - Summary
gaa
g MTRzMP 29, ==
pTz
TpBsc
scg =
( )TMf gag ,, =( )Tpzfc gg ,,,=
i.e., need z and Mai.e., need Tpc, ppci.e., need g
Thus the only gas property required to enter all gas property correlations is either gas composition or gas specific gravity.
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Basics of Reservoir Engineering
Oil Properties
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Specific Gravity of Oil
w
oo
=
Specific gravity of a crude oil is defined as the ratio of the density of the oil and the density of water at specified pressure and temperatureconditions:
Both densities measured at the same temperature and pressure, usually 60F and atmospheric pressure
Sometimes called o (60/60)
Copyright 2008, NExT, All rights reserved
API Gravity of Oil
Besides specific gravity, it is customary in the petroleum industry to use another gravity scale known as API (American Petroleum Institute), which has been defined as:
5.1315.141 =o
API o
This definition gives hydrometers a linear scale for measurement. Based on API of crude oils, a gross classification of crude oils as light (high API), medium, heavy and extra heavy (low API) is used
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Phase Diagram - Typical Black Oil
Black Oil
Criticalpoint
P
r
e
s
s
u
r
e
,
p
s
i
a
Bubbl
epoint
Line
Separator
Pressure pathin reservoir
Dewpoint line
9080
7060
5040
10
30
20
% Liquid
Temperature, F
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Reservoir Pressure > Oil Bubblepoint Pressure
Oil
res bbl oilSTBBo =
Sepa
rato
r
Stocktank
p > pbres bbl
STB
scf
scf
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Oil Formation Volume Factor (Bo)
Definition - volume of reservoir oil at reservoir conditions required to produce one standard volume of stock tank oilUnits - res bbl/STBSymbol - Bo
Oil
res bbl oilSTB
Bo =
Sepa
rato
r
Stocktank
p > pb
res bbl
STB
scf
scf
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Oil Formation Volume Factor
Three things happen to reservoir oil as it is produced to surface1. Loses mass - gas comes out of solution on trip to
surface2. Contracts - temperature decrease from reservoir
temperature to 60F 3. Expands - pressure decreases from reservoir
pressure to atmospheric pressure
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Typical Shape -Oil Formation Volume Factor
1
2
0 6000p
Bo
pb
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Solution Gas/Oil Ratio (Rs)
Another important property of oils is the amount of gas in solution (Rs) available at every pressure level:
Definition - volume of gas which comes out of the oil as it moves from reservoir temperature and pressure to standard temperature and pressure
Units - cubic feet of total surface gas at standard conditions per barrel of stock-tank oil at standard conditions, scf/STB
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Reservoir Pressure > Oil Bubblepoint Pressure
Oil
res bbl oilSTBBo =
Sepa
rato
r
Stocktank
p > pb
scfSTB
Rsb =
res bbl
STB
scf
scf
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Typical Shape -Solution Gas/Oil Ratio
0
2000
0 6000p, psig
Rs,
scf/S
TB
pb
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Reservoir Pressure < Oil Bubblepoint Pressure
res bbl gasMscfBg =
Gasres bbl
scf
Oil
res bbl oilSTBBo =
Sepa
rato
r
Stocktank
p < pb
scfSTB
Rsb =
STB
scf
scf
res bbl
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Typical Shape - Oil Formation Volume Factor
1
2
0 6000p, psig
Bo,
res
bbl/S
TB
pb
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Typical Shape - Solution Gas/Oil Ratio
0
2000
0 6000p, psig
Rs,
scf/S
TB
pb
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Coefficient of Isothermal Compressibility of Oil p > pb
T
o
oo p
BB
c
= 1Definition, oro Vc = 1
TpV
Oil
Hg
Oil
Hg
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Coefficient of Isothermal Compressibility of Oil p < pb
Hg
Hg
Oil
OilGas
T
s
o
g
T
o
oo
pR
BB
pB
Bc
+
= 1
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Typical Shape - Oil Compressibility
0
500
0 6000p, psig
c o, p
si-1
x 10
6
pb
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Oil Density
Units - lb/cu ft or ftpsi
ftsq/insq144ftcu/lb =
39
47
0 6000p, psig
o, lb
/cu
ft
pb
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Oil Viscosity
Definition - the resistance to flow exerted by a fluid, i.e., large values = low flow rates. Units: centipoise.
0.3
1.1
0 6000p, psig
o, cp
pb
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Production/Pressure History of Typical Black Oil
3000
6000
9000
100
75
50
25
4000
3000
2000
1000
019791978 19811980
Time
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
O
i
l
p
r
o
d
u
c
i
n
g
r
a
t
e
,
M
S
T
B
/
d
R
e
s
e
r
v
o
i
r
p
r
e
s
s
u
r
e
,
p
s
i
a
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Field Data For Correlations
Field Data Needed: Plot producing gas/oil ratio v. cumulative oil production Plot measured average reservoir pressures v. cumulative oil production
Get: Rsb is initial producing gas/oil ratiopb is pressure at which pressure curve flattens
- just before producing GOR starts to increase
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Production/Pressure History of Typical Black Oil
1000
2000
3000
4000
5000
6000
7000
8000
0 10 20 30 40 50 60 70
Cumulative oil production, MMSTB
Pres
sure
, psi
aPr
oduc
ing
gas/
oil r
atio
, scf
/STB
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Field Data For Correlations
If producing gas/oil ratios are calculated using sales gas (the usual situation), an estimate of the quantity of stock tank ventgas must be added to get Rsb, i.e., Rsb = RSP + RSTCorrelation
),,,( SPSPgSPST TpAPIfR o=
Copyright 2008, NExT, All rights reserved
Field Data for Correlations
Accurate value of pb will improve accuracy of results of all correlations - otherwise use correlation for pbRsb required in all correlations - derive from production dataAPI of stock tank oil required in all correlations - get from oil sales datagSP of separator gas required in most correlations - get from gas sales data
Copyright 2008, NExT, All rights reserved
Exercise 9Determination of Black Oil Properties
The attached production graphs show stock tank oil sales and separator gas sales for Niceoil field. The stock tank oil produced at Niceoil field is 39.9 API and the sales gas has specific gravity of 0.787. Reservoir temperature is 246F. Separator conditions are 150 psig and 75 F.
Determine and list all variables needed for estimating properties of the black oil.
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Pressure/Production History for Niceoil Field
AVAILABLE PRODUCTION DATA
Cumulative oil production, MMSTB
A
v
e
r
a
g
e
r
e
s
e
r
v
o
i
r
p
r
e
s
s
u
r
e
,
p
s
i
a
1750
2250
2750
3250
3750
4250
0 4 8 12
Cumulative oil production, MMSTB
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
(
3
m
o
r
u
n
n
i
n
g
s
c
f
/
S
T
B
a
v
e
r
a
g
e
)
300
400
500
600
700
800
900
1000
0 2 4 6 8 10
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Exercise 9 Solution
Cumulative oil production, MMSTB
A
v
e
r
a
g
e
r
e
s
e
r
v
o
i
r
p
r
e
s
s
u
r
e
,
p
s
i
a
1750
2250
2750
3250
3750
4250
0 4 8 12
Cumulative oil production, MMSTB
P
r
o
d
u
c
i
n
g
g
a
s
/
o
i
l
r
a
t
i
o
(
3
m
o
r
u
n
n
i
n
g
s
c
f
/
S
T
B
a
v
e
r
a
g
e
)
300
400
500
600
700
800
900
1000
0 2 4 6 8 10
Rsp= 570 scf/STB
Pb=2400 psia
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Exercise 9 Solution
Rsb = 707 scf/STBTR = 246FSTO = 39.9APIg = 0.787pb = 2,400 psia
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Exercise 10Estimation of black oil fluid properties.
Estimate values of oil properties for Niceoil field. Required properties are oil formation volume factor, solution gas/oil ratio, oil density, oil viscosity, and oil compressibility. Create a table starting at 5,000 psiawith increments of 500 psi above the bubblepointpressure and increments of 200 psi below the bubblepoint pressure to a final pressure of 100 psia.
Copyright 2008, NExT, All rights reserved
Exercise 11 Solution
0
100
200
300
400
500
600
700
800
900
1000
0 1000 2000 3000 4000 5000Pressure, psia
S
o
l
u
t
i
o
n
g
a
s
/
o
i
l
r
a
t
i
o
,
s
c
f
/
S
T
B
datacorrelation
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Exercise 11 Solution(continued)
1.00
1.05
1.10
1.15
1.20
1.25
1.30
1.35
1.40
1.45
1.50
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000Pressure, psia
O
i
l
f
o
r
m
a
t
i
o
n
v
o
l
u
m
e
f
a
c
t
o
r
,
r
e
s
b
b
l
/
S
T
B
datacorrelation
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Exercise 11 Solution(continued)
0.26
0.27
0.28
0.29
0.3
0.31
0.32
0.33
0.34
0.35
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Pressure, psia
O
i
l
d
e
n
s
i
t
y
,
p
s
i
/
f
t
datacorrelation
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Exercise 11 Solution(continued)
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0 1000 2000 3000 4000 5000
Pressure, psia
O
i
l
v
i
s
c
o
s
i
t
y
,
c
p datacorrelation
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References and Further Reading
McCain, W., The Properties of Petroleum Fluids, Pennwell, 1990.
Whitson, C. and Brule, M., Phase Behavior, SPE Monograph Volume 20, Henry Doherty Series, 2000.
Danesh, A., PVT and Phase Behaviour of Petroleum Reservoir Fluids, Developments in Petroleum Science v. 47, Elsevier, 1998.
Basics of Reservoir Engineering Module IUnderstanding Phase BehaviorWhy study Phase Behavior?Phase Behavior - Pure SubstancePhase Behavior - Pure SubstancePhase Behavior - Pure SubstancePhase Behavior - Pure SubstancePhase Behavior - MixturesPhase Behavior - MixturesPhase Diagrams of Mixtures of Ethane and n-HeptanePhase Diagram of a Reservoir FluidThe Five Reservoir FluidsPhase Diagram of a Typical Black OilPhase Diagram of a Typical Volatile OilPhase Diagram of a Typical Retrograde GasPhase Diagram of Typical Wet GasPhase Diagram of Typical Dry GasField Identification of Reservoir FluidsThe Concept of GORComponents of Naturally Occurring Petroleum FluidsInitial Producing GOR Correlates With C7+Initial Producing GLR Correlates With C7+Initial Producing GLR Correlates With C7+Initial Producing GLR Correlates With C7+Field IdentificationLaboratory AnalysisPrimary Production TrendsExercise 1Determine reservoir fluid type from field dataPlot of Exercise 1 DataExercise 2Determine reservoir fluid type from field dataExercise 3Determine reservoir fluid type from field dataPlot of Exercise 3 DataPlot of Exercise 3 Data Three-Month Running AverageExercise 4Determine reservoir fluid type from field dataPlot of Exercise 4 DataThree-Month Running AverageExercise 5Determine reservoir fluid type from field dataPlot of Exercise 5 DataExercise 6Determine reservoir fluid type from field dataPhase BehaviorIdeal Gas Equation Of StateReal Gas Equation of StateTypical Shape of z-Factorz-Factors For Methanez-Factors and Corresponding Statesz-Factors for Naturally Occurring Gas MixturesMolecular Weight CalculationPhysical ConstantsExercise 7Calculate Apparent Molecular Weight of Gas MixtureSpecific Gravity Of GasExercise 8Calculate Specific Gravity of Gas MixtureGas DensityGas Formation Volume Factor (Bg)Gas Formation Volume Factor (Bg)Gas ViscosityGas ViscosityCoefficient of Isothermal Compressibility of Gas(Gas Compressibility)Gas Properties - SummarySpecific Gravity of OilAPI Gravity of OilPhase Diagram - Typical Black OilReservoir Pressure > Oil Bubblepoint PressureOil Formation Volume Factor (Bo)Oil Formation Volume FactorTypical Shape - Oil Formation Volume FactorSolution Gas/Oil Ratio (Rs)Reservoir Pressure > Oil Bubblepoint PressureTypical Shape - Solution Gas/Oil RatioReservoir Pressure < Oil Bubblepoint PressureTypical Shape - Oil Formation Volume FactorTypical Shape - Solution Gas/Oil RatioCoefficient of Isothermal Compressibility of Oil p > pbCoefficient of Isothermal Compressibility of Oil p < pbTypical Shape - Oil CompressibilityOil DensityOil ViscosityProduction/Pressure History of Typical Black OilField Data For CorrelationsProduction/Pressure History of Typical Black OilField Data For CorrelationsField Data for CorrelationsExercise 9Determination of Black Oil PropertiesPressure/Production History for Niceoil FieldExercise 9 SolutionExercise 9 SolutionExercise 10Estimation of black oil fluid properties.Exercise 11 SolutionExercise 11 Solution(continued)Exercise 11 Solution(continued)Exercise 11 Solution(continued)References and Further Reading