Basics of Reservoir Engineering –Module I
I.1.A I.1.A - Fundamen Fundamentals tals of of Reservoir Reservoir Phase Phase Behavi Behavior or
Understanding Phase Behavior Naturally occurring hydrocarbon mixtures found in petroleum reservoirs are mixtures of organic compounds and few nonhydrocarbons 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.
Understanding Phase Behavior Naturally occurring hydrocarbon mixtures found in petroleum reservoirs are mixtures of organic compounds and few nonhydrocarbons 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.
Why study Phase Behavior ? • As oil and gas are produced from the reservoir, res ervoir, 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., (e .g., Darcy’s law, material balances) require the knowledge of fluid properties. It is impossible to correctly evaluate well productivity and reservoir performance if fluid properties are not known.
Phase Behavior - Pure Substance
pc
e r u s s e r P
e in l t Solid in o - p g in lt e M
C Liquid
n e i l r e u s s e r - p r o Gas V a p
T
Temperature
Tc
Phase Behavior - Pure Substance
Critical Point pc
e r u s s e r P
e in l t Solid in o - p g in lt e M
T
C Liquid
n e i l r e u s s e r - p r o Gas V a p
Triple Point Temperature
Tc
Phase Behavior - Pure Substance
Phase Behavior - Pure Substance 1200 1100 a i s p , e r u s s e r P
1 6 0 ° F
1000
1 3 0 ° F
900
1 1 0 ° F 1 00 ° F
800
9 5° F
C
700
9 0 °F = T c
85°F 80°F
600
70°F
Two-phase region
500
60°F
400 0
0.05
0.1
0.15
0.2
Specific volume, cu ft/lb
0.25
Phase Behavior - Mixtures
Critical point
400 a i s p , e r u s s e r P
300
t n i o p e l b b u B
4 4 5 0 o 5 4 o F F
4 25 o F 4 00 o F
D e w p o i n t 3 50 o F
200 3 00 o F
0.1
0.2
0.3
Volume, cu ft/lb
0.4
Phase Behavior - Mixtures
PURE SUBSTANCE
MIXTURE
Phase Behavior - Mixtures There is no real transition!
Pressure, p
T < Tc “LIQUI D”
BP Curve
L + V coexistence
T > Tc “GAS” CP
The less alike the molecules, the farther apart BP and DP Curves!
DP Curve Temp, T
Phase Diagrams of Mixtures of Ethane and n-Heptane Composition
1400 4
1200
a i s p 1000 , e r u 800 s s e r 600 P
5
3
No. 1 2 3 4 5 6 7 8 9 10
Wt % ethane 100.00 90.22 70.22 50.25 29.91 9.78 6.14 3.27 1.25 n-Heptane
2
Pure1 C2
6 7 8
400
9 10
200
Pure nC7 0
100
200
300
400
Temperature °F
500
Phase Diagram of a Reservoir Fluid 1400 1300 1200 1100 1000 a i s p , e r u s s e r P
900 800 700 600 500 400
Critical point d i u i q L % 0 0 1 5 0 0 2
0 1
5
2 1
300 200 100 0 -200
-150
-100
-50
0
50
The Five Reservoir Fluids The Five Reservoir Fluids Dewpoint line
Critical 1 point
Pressure path in reservoir
Pressure path in reservoir a i s p , e r u s s e r P
Dewpoint line
Critical point
The Five Reservoir Fluids
Black Oil
9 0 8 0
e l i n i n t o e l p b b B u
0 0 9 7
% Liquid
0 6
0 5
2
0 9
Volatile oil
0 4 0 3 0 2
e r u s s e r P
0 0 7 8 0 6
0 5
e i n t l i n o p l e b b u B
0 4
% Liquid
0 3 0 2
1 0
3
5
0 1
Separator Separator
t l i n e p o i n D e w
Temperature, °F Temperature
Black Oil
Volatile Oil
Pressure path in reservoir Retrograde gas
e r u s s e r P
b u B
1
1
2
e i n t l n i p o w e D Critical e i n point t l n i 0 0 4 p o 3 0 l e 2 b
Pressure path in reservoir
Pressure path in reservoir
1
e r u s s e r P
e n i l t n i o p w e D
Wet gas
% Liquid
1 5 3 0 1
Separator
5 0
Temperature
Retrograde Gas
% Liquid Critical t point n i o p 2 l e e n 0 5 b l i b 3 2 5 1 u B Separator
Temperature
Wet Gas
e r u s s e r P
e n i l t n i o p w e D
Dry gas
% Liquid 2 0 5 2 5
1
Separator Temperature
Dry Gas
Phase Diagram of a Typical Black Oil An Oil Reservoir: Tr < Tc ( Bubblepoint Oil )
a i s p , e r u s s e r P
Pressure path in reservoir Critical point
Dewpoint line
Black Oil
e i n L i n t o e - p l b b u B
9 0 0 % Liquid 8 0 7
0 6 0 5 0 4 0 3 0 2
Separator
Temperature, °F
0 1
Phase Diagram of a Typical Volatile Oil An Oil Reservoir: Tr < Tc ( Bubblepoint Oil ) Pressure path 1 in reservoir
Dewpoint line
Critical point
2 Volatile oil e r u s s e r P
e n i l t i n o e p l b b u B
0 9
0 0 7 8 0 6
0 5 0 4
% Liquid 0 3 0 2
3 Separator
Temperature, °F
1 0 5
t l i n e n i o p D e w
Phase Diagram of a Typical Retrograde Gas A Gas Reservoir: Tr > Tc (dewpoint system) Pressure path in reservoir 1 Retrograde gas
e r u s s e r P
e i n l t n i p o w e D
2
e Critical point i n
t l n i o 0 0 p 4 e 3 0 l b 2 b 1 5 u B
% Liquid
3
1 0
Separator
5
Temperature
0
Phase Diagram of Typical Wet Gas A Gas Reservoir: Tr > Tc Pressure path in reservoir 1
e r u s s e r P
e n i l t n i o p w e D
% Liquid
Critical point
t n i o p l e e n 0 b l b i 3 u B
Wet gas
2 5 2
5
1
Separator
Temperature
Phase Diagram of Typical Dry Gas A Gas Reservoir: Tr > Tc Pressure path in reservoir 1
e r u s s e r P
e n i l t n i o p w e D
Dry gas
% Liquid 2 0 5 5 2 1
Separator
Temperature
Field Identification of Reservoir Fluids The Concept of GOR scf
r o t a r a p e S
scf
Stock tank STB
Gas res bbl
res bbl
Oil
GOR =
scf STB
Components of Naturally Occurring Petroleum Fluids Component Hydrogen sulfide Carbon dioxide Nitrogen Methane Ethane Propane i-Butane n-Butane i-Pentane n-Pentane Hexanes Heptanes plus
Composition, mole percent 4.91 11.01 0.51 57.70 7.22 4.45 0.96 1.95 0.78 0.71 1.45 8.35 100.00
Properties of heptanes plus Specific Gravity 0.807 Molecular Weight 142 lb/lb mole
Initial Producing GOR Correlates With C 7+
100000 B T S g / f n i c c s , u o d i t o r a p r l d a i i u t i q n i l I / s a g
80000 60000 40000 Dewpoint gas Bubblepoint oil
20000 0 0
10
20
30
40
Heptanes plus in reservoir fluid, mole %
50
Initial Producing GLR Correlates With C 7+ Dew point gases 100000 B g T / n S i f c c 10000 u s d , o o r i t p a l r a l 1000 i i t o i / n s I a g
100 0.1
1
10
Heptanes plus in reservoir fluid, mole %
100
Initial Producing GLR Correlates With C 7+ Bubblepoint oils 10000 B T S g / f n i c 1000 c s , u o d i t o r a p r l d a i 100 i u t i q n i l I / s a g
10
0
20
40
60
80
Heptanes plus in reservoir fluid, mole %
100
Initial Producing GLR Correlates With C 7+
50000 Wet gas
Dry B gas g T / n S i f c c u s d , o o r i t p a l r a l i i t o i / n I s a g
Retrograde gas
Volatile oil
Black oil
Dewpoint gas Bubblepoint oil
0 0
30 Heptanes plus in reservoir fluid, mole %
Field Identification
Initial Producing Gas/Liquid Ratio, scf/STB Initial StockTank Liquid Gravity, API Color of StockTank Liquid
Black Oil <1750
Volatile Oil 1750 to 3200
Retrograde Gas > 3200
Wet Gas > 15,000*
Dry Gas 100,000*
< 45
> 40
> 40
Up to 70
No Liquid
Dark
Colored
Lightly Colored
Water White
No Liquid
*For Engineering Purposes
Laboratory Analysis
Phase Change in Reservoir Heptanes Plus, Mole Percent Oil Formation Volume Factor at Bubblepoint
Black Volatile Retrograde Oil Oil Gas Bubblepoint Bubblepoint Dewpoint
> 20%
20 to 12.5
< 12.5
Wet Gas No Phase Change < 4*
< 2.0
> 2.0
-
-
*For Engineering Purposes
Dry Gas No Phase Change < 0.8*
-
Primary Production Trends
Black Oil
Volatile Oil R O G
R O G
Time
I P A
R O G
Time
Time
Wet Gas R O G
Time
I P A
I P A
Time
Retrograde Gas
R O G
Time
I P A
Time
Dry Gas
Time
I P A
Time
No liquid
No liquid
Time
Exercise 1 Determine 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 54° API stock-tank liquid at a gas/oil ratio of about 23,000 scf/STB. During July 1969, the well produced 1987 STB of 58° API liquid and 78,946 Mscf of gas. By May 1972, the well was producing liquid at a rate of about 30 STB/d of 59 ° API liquid and gas at about 2,000 Mscf/d. What type of reservoir fluid is this well producing?
Plot of Exercise 1 Data
B T S / f g c n s i , c o u i d t a r o r l P i o / s a g
100000
60
90000
59
80000
58
70000
57
60000
56
50000
55
40000
54
30000
53
20000
52
10000
51
0
50 72
0
12
24
36
48
60
Months since start of 1967
l i q u i S d t g o r c a k v t a i t y n , k A P I
Exercise 2 Determine 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 51.2° API. Classify this reservoir fluid. Laboratory analysis of a sample from this reservoir gave the following composition: Component Composition, mole fraction CO2 0.0218 N2 0.0167 C1 0.6051 C2 0.0752 C3 0.0474 C4’s 0.0412 C5’ 0.0297 C6’s 0.0138 C7 0.1491 1.0000 Properties of heptanes plus Specific Gravity 0.799 Molecular Weight 181 lb/lb mole
Exercise 3 Determine 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? Date 9/86 10/86 11/86 12/86 1/87 2/87 3/87 4/87 5/87 6/87 7/87 8/87
Stock-Tank Liquid Gravity’ ° API 29 28 28 28 28 28 28 28 28 28 28 28
Oil, STB 4,276 16,108 15,232 15,585 15,226 14,147 15,720 15,885 15,434 12,862 14,879 15,192
Gas, Mscf 1,165 5,270 4,800 4,960 4,650 4,335 4,707 4,904 4,979 4,339 4,814 4,270
Plot of Exercise 3 Data 500 B T S / f g c n s i , c o u i d t a o r r l P i o / s a g
400
300
200
100 0
2
4
6
8
10
Months since start of production
12
Plot of Exercise 3 Data Three-Month Running Average 500 B T S / f g c n s i , c o u i d t a o r r l P i o / s a g
400
300
200
100 0
2
4
6
8
10
Months since start of production
12
Exercise 4 Determine 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 Date Apr 1984 May 1984 Jun 1984 Jul 1984 Aug 1984 Sep 1984 Oct 1984 Nov 1984 Dec 1984 Jan 1985 Feb 1985 Mar 1985
Stock-Tank Liquid Gravity ° API 55 55 55 55 54 55 56 56 56 56 56
Oil, STB
Water, STB
112 1,810 2,519 3,230 3,722 2,780 3,137 2,291 2,108 1,799 1,422 1,861
12,090 180 240 279 248 270 210 217 203 196 186
Gas, Mscf 3,362 54,809 64,104 94,419 119,151 100,235 113,359 80,083 71,412 60,279 57,626 60,330
Plot of Exercise 4 Data Three-Month Running Average 37000 B T S / f g c n s i , c o u i d t a o r r l P i o / s a g
28000 0
13
Months since start of production
Exercise 5 Determine reservoir fluid type from field data
Here we present the GOR plot based on three month running average data for Exercise 4. Annual Production Stock-Tank Date Liquid Gravity ° API 1982 46 1983 50 1984 47 1985 48 1986 50 *1987 51 *through August 1987
Oil, STB 4,646 2,606 1,350 1,430 1,662 1,110
Water, STB 1,484 1,177 1,215 932 1,122 665
Gas, Mscf 462,265 342,075 241,048 221,020 267,106 178,951
Plot of Exercise 5 Data
200000
55
B T S / f g c n s i , c o u i d t o a r r l P i o / s a g
I P A k , y n t i a t - v k a c r o g t d S i u q i l
50000 1981
40
Year
1988
1981
Year
1988
Exercise 6 Determine reservoir fluid type from field data The following liquid yield production data is available for a given reservoir. Can you identify the fluid? 200 175 f 150 c s M125 M / B T 100 S , d 75 l i e Y
50 25 0
0
24
48
72
96
120
Basics of Reservoir Engineering
Natural Gas Properties
Phase Behavior Relationship between conditions (Pressure, Temperature, Volume) and phases (liquid, gas, solid)
Ideal Gas Equation Of State The simplest PVT model: the ideal gas. pV = n R T pV = pv =
m
R T
M R T
Assumptions of the ideal model: Volume occupied by molecules is insignificant compared to volume of gas No attractive or repulsive forces between molecules
Real Gas Equation of State p V = z n R T p V = z p v =
m
R T
M z RT
z is called “compressibility factor”:
z
=
V real V ideal
Also called gas deviation factor, supercompressibility, or z-factor . V ideal V real
n R T =
p z n R T
=
p
=
z V ideal
Typical Shape of z-Factor
t n t a s n o z approaches 1.0 c = r e u a t r p e m e T
z , r o t c1.0 a f y t i l i b i s s e r p m o C
0
Actual V less than ideal V
0
Pressure, p
Actual V greater than ideal V
z-Factors For Methane Methane 1.1 404
342 320 262 240
212
0.9
170
5000
140 104 44
-84 -70 -54 -40 -22 -4
Z
p VM RT
4000
32
0.7
1.6
32
-4
44
-22 -40
0.5
104 140 170 212 240 262 320 342 404
3000
-54 -70
2000
1.4
Z 1.2
-84
0.3 1.0 0.1
0
1000
6000
8000
10000
p VM RT
z-Factors and Corresponding States By defining reduced conditions Tr = T/Tc; Pr= P/Pc, z-factor isotherms for different substances tend to collapse to a universal z-factor curve: 1.0 Tr = 1.5
V T p R = z 0.8 , r o t c 0.6 a f y t i l i b i 0.4 s s e r p 0.2 m o C 0
C5H12 C3H8
Tr = 1.3 C H C 4 3 H
CH4 C5H12
Tr = 1.2
C3H8 CH4
8
C 5 H
Tr = 1.0 Tr = 0.9
1 2
C6H14
C5H12 C 6 H
C3H8 Tr = 1.1
1 4
CH4 C5H12 C3H8 CH4
CH4 C3H8 C5H12
0
0.6
1.2
1.8
2.4
3.0
z-Factors for Naturally Occurring Gas Mixtures Pseudoreduced pressure, ppr 1.1
1.0 z , 0.9 r o t c 0.8 a f 0.7 y t i 0.6 l i b 0.5 i s s 0.4 e r p 0.3 m0.25 o 1.1 C 1.0 1.6
0
1
2
3
4
5
6
7
1.1
Pseudoreduced Temperature 3.0 2.8 2.6 2.4 2.2 2.0 1.9 1.8 1.7 1.6 1.5 1.45 1.4 1.35
1.0 5 1 . 0 1 . 1 1 . 2 3 1 .
1.3 1.25 1.2
4 1. 4
1. 5 1. 6 . 7 1. 8 1 7 1. 9
1.15
. 0 2 2 . 2 2 0
1.1
2. 6
0.9 7
1.7 1.6 1.5 1.4 1.3 1.2 1.1
2. 4
1 .2
. 2 0 2 2 2. 0 1. 9 1. 8 . 7 1 7
2.4 2.6 3.0
1.05
3.0
2.8
8
1 .4
1.0
1 .1 1.05 1.05
1.3
8
9
10
11
12
13
14
Pseudoreduced pressure, ppr
15
z , r o t c a f y t i l i b i s s e r p m o C
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:
M a
= ∑ y j
M j
Physical Constants Physical constants of single components are tabulated! Compound Methane Ethane Propane Isobutane n-Butane Isopentane n-Pentane Neopentane n-Hexane 2-Methylpentane 3-Methylepntane Neophexane 2,3-Dimethylbutane Hydrogen sulfide Carbon Dioxide Nitrogen Argon Oxygen
Formula CH4 C2 H6 C3H8 C4H10 C4H10 C5H12 C5H12 C5H12 C6H14 C6H14 C6H14 C6H14 C 6H14 H2S CO2 N2 A O
Molar Mass, molecular weight 16.043 30.070 44.097 58.123 58.123 72.150 72.150 72.150 86.177 86.177 86.177 86.177 86.177 34.08 44.010 28.0134 39.944 31.999
Critical Constants Pressure, Temperature, psia F 666.4 -116.67 706.5 89.92 616.0 206.06 527.9 274.46 500.6 305.62 490.4 369.10 488.6 385.8 464.0 321.13 436.9 453.6 436.6 435.83 453.1 448.4 446.8 420.13 453.5 440.29 1300. 212.45 1071. 87.91 493.1 -232.51 704.2 -188.53 731.4 -181.43
Exercise 7 Calculate 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 Nitrogen Oxygen Argon Carbon dioxide
Composition, mole fraction 0.7809 0.2095 0.0093 0.0003 1.0000
Specific Gravity Of Gas
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 60°F and atmospheric pressure ρ g , which becomes: γ g ρ air p M g
=
γ g
=
ρ g ρ air
=
R T p M air R T
=
M g 29
Exercise 8 Calculate Specific Gravity of Gas Mixture Component hydrogen sulfide carbon dioxide nitrogen methane ethane propane iso-butane n-butane iso-pentane n-pentane hexanes heptanes plus
Properties of Heptanes Plus Density, gm/cc @ 60°F Molecular weight
Composition, mole percent 0.00 0.00 0.00 96.13 1.50 0.88 0.15 0.16 0.08 0.06 0.10 0.94 100.00
0.798 164
Gas Density 0.15
Calculated as a function of “Z”: ρ g
=
p M
t f / i s p , g
z R T
Units - lb/cu ft 0 0
10000
p, psia
or
ρ g
lb / cu ft
144 sq in / sq ft
=
psi ft
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/scf res bbl/Mscf
Symbol - Bg
scf
r o t a r a p e S
scf
Stock tank STB
Gas
res bbl
res bbl gas Bg = Mscf
Gas Formation Volume Factor (Bg) 40
Equation: B g B g =
=
V R V sc
p sc z T res cu ft T sc p
scf
f c s M / l b b s e r , g B0 0
or
p sc 1000 bbl B g = M 5.615 cu ft T sc
10000
p, psia
z T res bbl p Mscf
Gas Viscosity Definition - The resistance to flow exerted by a fluid, i.e., large values = low flow rate. Units - centipoise or centistoke 0.05
p c , g
0 0
10000
p, psia
Gas Viscosity
Gas Viscosity Correlation Equation (Lee-Gonzalez) µ g
= A
10
−4
EXP B
where A B C
= = =
f(Ma, T) f(Ma, T) f(Ma, T)
Thus
µg = f(ρg, Ma, T) or µg = f(z, Ma, T)
C ρ g
Coefficient of Isothermal Compressibility of Gas (Gas Compressibility)
Definition
7000
∂ V c g = − V ∂ p T 1
6
Ideal Gas Real Gas
c g
=
1
p
0 1 x c
g
∂ z c g = − p z ∂ p T 1
1
0 0
1000
p
Gas Properties - Summary P M a
ρ g
=
B g
=
z R T
,
=
29
ρ g ,
T
M a
γ g
p sc z T T sc
p
µ g
=
f M a ,
c g
=
f
ρ g ,
z , p , T
i.e., need z and Ma i.e., need Tpc, ppc i.e., need γg
Thus the only gas property required to enter all gas property correlations is either gas composition or gas specific gravity.
Basics of Reservoir Engineering
Oil Properties
Specific Gravity of Oil 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 temperature conditions:
γ o
=
ρ o ρ w
• Both densities measured at the same temperature and pressure, usually 60 °F and atmospheric pressure • Sometimes called γo (60/60)
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: o
API =
141.5
− 131.5
γ 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
Phase Diagram - Typical Black Oil
Pressure path in reservoir a i s p , e r u s s e r P
Critical point
Dewpoint line
Black Oil
n e i L n t i o p e l b b u B
9 0 0 8
% Liquid
0 7
0 6
0 5
Separator
Temperature, °F
0 4 0 3 0 2
0 1
Reservoir Pressure > Oil Bubblepoint Pressure scf r
ot a r a p e S
scf
Stock tank STB Bo =
res bbl
Oil
p > pb
res bbl oil STB
Oil Formation Volume Factor (Bo) Definition - volume of reservoir oil at reservoir conditions required to produce one standard volume of stock tank oil scf
Units - res bbl/STB
r
ot a r a p e S
Symbol - Bo
scf
Stock tank STB
res bbl
Bo =res bbl oil STB
Oil p > pb
Oil Formation Volume Factor
Three things happen to reservoir oil as it is produced to surface 1.
Loses mass - gas comes out of solution on trip to surface
2.
Contracts - temperature decrease from reservoir temperature to 60°F
3.
Expands - pressure decreases from reservoir pressure to atmospheric pressure
Typical Shape Oil Formation Volume Factor 2
B
o
1
pb
0 p
6000
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
Reservoir Pressure > Oil Bubblepoint Pressure
Rsb =
scf
scf STB
r
ot a r a p e S
scf
Stock tank STB Bo =
res bbl
Oil
p > pb
res bbl oil STB
Typical Shape Solution Gas/Oil Ratio 2000
B T S/ f
c s ,
s
R
0
pb
0 p, psig
6000
Reservoir Pressure < Oil Bubblepoint Pressure
Bg =
res bbl gas
scf
Mscf
Rsb =
scf
scf STB
r
ot a r a p e S
scf
Stock tank STB Bo =
Gas res bbl
res bbl
Oil
p < pb
res bbl oil STB
Typica Typ icall Shape Shape - Oil Forma Formatio tionn Volume Volume Fact Factor or
2 B T S/ l
b b s e r , B
o
1
pb
0 p, psig
6000
Typica Typ icall Shape Shape - Sol Soluti ution on Gas/ Gas/Oil Oil Rati Ratioo
2000
B T S/ f
c s ,
s
R
0
pb
0 p, psig
6000
Coefficient of Isothermal Compressibility of Oil – p > pb 1 ∂ Bo V ∂ Definition, co = − or co = − V ∂ p T Bo ∂ p T 1
Oil
Oil
Hg
Hg
Coefficient of Isothermal Compressibility of Oil – p < pb
∂ Bo co = − Bo ∂ p T B g ∂ R s + Bo ∂ p T 1
Gas Oil
Oil Hg Hg
Typical Shape - Oil Compressibility
500
6
1-
0 1 x i
s p ,
c
o
0
pb
0 p, psig
6000
Oil Density Units - lb/cu ft or
lb / cu ft 144 sq in / sq ft
psi ft
47
tf u c/ bl ,
o
39
pb
0 p, psig
6000
Oil Viscosity
Definition - the resistance to flow exerted by a fluid, i.e., large values = low flow rates. Units: centipoise. 1.1
p c ,
o
0.3
pb
0
p, psig
6000
Production/Pressure History of Typical Black Oil a i r s i o p , v r e e r s u e s s R e r p
9000
g d / n i B c T u S d o r M , p e t l i a O r
100
o i g t n a i r c l u i d o / o r s P a g
6000
3000
75
50
25 4000 3000 2000 1000 0
1978
1979
1980
1981
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 ratio pb is pressure at which pressure curve flattens - just before producing GOR starts to increase
Production/Pressure History of Typical Black Oil
B T S/ f
7000
,
6000
c s ai s p ,
e r u s s e r P
8000
oi t
a
5000
o/ s a g g ni c u d o r P
4000
li
r
3000 2000 1000 0
10
20
30
40
50
60
Cumulative oil production, MMSTB
70
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 vent gas must be added to get R sb, i.e., Rsb = RSP + RST Correlation
RST
= f ( API , γ gSP , o
pSP , T SP )
Field Data for Correlations
Accurate value of pb will improve accuracy of results of all correlations - otherwise use correlation for pb Rsb required in all correlations - derive from production data ° API of stock tank oil required in all correlations - get from oil sales data γgSP of separator gas required in most correlations - get from gas sales data
Exercise 9 Determination 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 246°F. Separator conditions are 150 psig and 75 °F. Determine and list all variables needed for estimating properties of the black oil.
Pressure/Production History for Niceoil Field AVAILABLE PRODUCTION DATA 4250
1000
a i s p , 3750 e r u s s e r 3250 p r i o v r 2750 e s e r e g 2250 a r e v A
) e g 900 a o r i t e v a r a 800 l i B o T / s S / 700 a f g c s g g 600 n n i c i u n d n 500 u o r r P o m400 3 (
1750
300 0
4
8
Cumulative oil production, MMSTB
12
0
2
4
6
8
Cumulative oil production, MMSTB
10
Exercise 9 Solution
4250
1000
a i s p , 3750 e r u s s e r 3250 p r i o v r 2750 e s e r e g 2250 a r e v A
) e g 900 a o r i t e v a r a 800 l i B o T / s S / 700 a f g c s g g 600 n n i c i u n d n 500 u o r r P o m400 3 (
Pb=2400 psia
1750
Rsp= 570 scf/STB
300 0
4
8
Cumulative oil production, MMSTB
12
0
2
4
6
8
Cumulative oil production, MMSTB
10
Exercise 9 Solution
Rsb
=
707 scf/STB
TR
=
246°F
γSTO = γg =
39.9° API
pb
2,400 psia
=
0.787
Exercise 10 Estimation 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 psia with increments of 500 psi above the bubblepoint pressure and increments of 200 psi below the bubblepoint pressure to a final pressure of 100 psia.
Exercise 11 Solution
1000 900
B T S / f c s , o i t a r l i o / s a g n o i t u l o S
800 700 600 data
500
correlation 400 300 200 100 0 0
1000
2000
3000
4000
5000
Exercise 11 Solution (continued) 1.50
B T 1.45 S / l b b 1.40 s e r , 1.35 r o t c 1.30 a f e 1.25 m u l o 1.20 v n o 1.15 i t a 1.10 m r o f l i 1.05 O 1.00
data correlation
0
500
1000
1500
2000
2500
3000
Pressure, psia
3500
4000
4500
5000
Exercise 11 Solution (continued) 0.35 0.34 0.33
t f / i 0.32 s p , 0.31 y t i s n 0.3 e d l i 0.29 O
data correlation
0.28 0.27 0.26 0
500
1000
1500
2000
2500
3000
Pressure, psia
3500
4000
4500
5000
Exercise 11 Solution (continued) 0.8 0.7
p 0.6 c , y t i 0.5 s o c s 0.4 i v l i O 0.3
data correlation
0.2 0.1 0
1000
2000
3000
Pressure, psia
4000
5000
