Review of Reservoir Fluid
Properties
Prof. Attia M. Attia
Lecture # 2 ,3
[PTRL02H02] Petroleum Reservoir Engineering
Review of Reservoir Fluid Properties
Five Reservoir Fluids
Phase Behavior
• Used to visualize the fluids production path from the reservoir to the surface
• To classify reservoir fluids
• Visualize miscible processes
Pressure vs. Temperature Diagrams
Why do we need to classify
Reservoir Fluids?
• Methods of the fluid sampling
• Types and size of surface equipment
• Calculation procedure for determining
OOIP or OGIP
• Techniques of predicting oil and gas
reserves
• The plan of depletion
• Selection of EOR methods
How can you confirmed the type of
reservoir fluid?
• Three properties are readily available in Lab.
• Initial gas oil ratio
• Gravity of the stock tank liquid
• Color of the stock tank liquid
There are five types of reservoir
fluid
1. Black oils
2. Volatile oils
3. Retrograde gas
( gas condensates – R G condensates)
1. Wet gas
2. Dry gas
• For all reservoir we study, what will happen
if the reservoir pressure decrease?
• Or
• What will happen in the production path?
• Or
• What is the effect of Pressure and
temperatures on the fluid behavior ?
Remember …..
Chemical Composition
Black oils
• Contains large , heavy nonvolatile molecules …… phases????
• Not reverse after separate C1
• So we have gas phase and liquid phase
Phase Diagram of a
Black oils or Low shrinkage crude
1-2 undersaturated
From figure
• 1 2 3 indicates the reduction in pressure
at constant temperature that occurs in
reservoir during production
• 1 2 oil is said to be undersaturated
• 2 the oil is at bubble point (said –
saturated) misnomer
• With reduction in pressure, release gas to
form a free gas phase in the reservoir
• 2-3 additional gas is evolved
Black oils are characterized !!! Or Classification of Reservoirs based on
Production and PVT data
• Initial producing G / O ratio of 2000 or less scf / STB
• Stock tank oil gravity below 45 API will slightly decrease with time
• Stock tank oil color is very dark indicating the presence of heavy hydrocarbon often black some times greenish or brown
• Oil formation volume factor 2 or less bbl / stb
Phase Diagram of a
Volatile Oil Reservoir OR High shrinkage crude
Volatile Oil Reservoir cont.
• We can not dealing with this type during
production as phases because is reversed
• Liquid gas liquid and so on…..
• So, We can dealing with this type using
composition only
Volatile oils
• Contain relatively fewer heavy molecules and more intermediates ( Ethan through hexanes) than black oils.
• For fluid to be volatile oil its critical temperature must be greater than reservoir temperature.
• G / O ratio 2000 – 3300 scf / STB increase with the production
• A
Volatile oils are characterized !!!
Or Classification of Reservoirs based on
Production and PVT data
• Initial producing G / O ratio of 2000- 3300
scf / STB
• Stock tank oil gravity greater than 40 API
increase during production
• Stock tank oil color usually brown ,
orange
• Oil formation volume factor 2 or less bbl /
stb
Retrograde condensates gas
Tr greater than Tc
less than Tcond
• Initially, the retrograde gas is totally gas in the
reservoir
• As reservoir pressure decreases the retrograde
gas exhibits a dew point
• As pressure is reduced , the liquid condense
from the gas to form liquid in reservoir
• The liquid will normally not flow and can not
produced as some low in pressure the liquid
begins to revaporize.( this occur in Lab.)
Phase Diagram of a
Retrograde Gas Reservoir
Classification of Reservoirs based on
Production and PVT data for retrograde
• Lower limit of G / O ratio of 3300- upper
not defined but observed at 150000 scf /
STB
• Stock tank oil gravity between 40 – 60
API increase during production
• Stock tank oil lightly b colored , brown ,
orange Or water- white
Wet gas
wet gas reservoirs are
characterized !!!
• The gravity of the Stock tank liquid does
not change during the life of the reservoir
( same range of gravity as the liquid from
retrograde gas)
• True wet gas have very high producing
G / O ratio, producing gas oil ratio will
remain constant during the life of wet gas
GO R more than 50000 scf/STB
Dry gas
• Dry gas is primarily methane with some intermediates
• No liquid is formed at the surface
• The word of dry indicates that the gas does not contain enough of heavier molecules to for hydrocarbon liquid at surface. Usually some of liquid water is condensed at the surface.
• Dry gas - gas reservoir
Typical Reservoir Fluid CompositionsComponent Black Oil Volatile Oil Gas Condensate Wet Gas Dry Gas
C1 48.83 64.36 87.07 95.85 86.67
C2 2.75 7.52 4.39 2.67 7.77
C3 1.93 4.74 2.29 0.34 2.95
C4 1.60 4.12 1.74 0.52 1.73
C5 1.15 3.97 0.83 0.08 0.88
C6 1.59 3.38 0.60 0.12
C7+
42.15 11.91 3.80 0.42
MwC7+
225 181 112 157
GOR 625 2000 18,200 105,000 -
Tank oAPI 34.3 50.1 60.8 54.7 -
Liquid
Color
Greenish
Black
Medium
Orange
Light
Straw
Water
White
-
Why different
?????
CLASSIFICATION OF RESERVOIRS
AND RESERVOIR FLUIDS
Cap Rock
Reservoir
Rock
Oil Gas Water
Reservoir Fluids
1. Oil Reservoirs due to reservoir conditions (P & T)
Undersaturated (Pr>Pb)Saturated (Pr≤Pb)
With bottom
water
Without
bottom water
Depletion Gas
CapBottom
water
Drive
Combination
Gas Reservoirs
Dry gas
reservoir, no
condensate
Wet gasRetrograde gas
condensate
reservoir
Revision 1. Define oil specific gravity and define oil gravity in API
2. Define oil bubble point pressure, pb.
3. Define oil formation volume factor, Bo,
4. Define solution gas/oil ratio, Rs,
5. Define the coefficient of isothermal compressibility of oil,
co.
6. Define oil density, o,
7. Define oil viscosity, o,
8. Field Data for Correlations….
Specific Gravity of Oil
• Both densities measured at the same
temperature and pressure,
usually 60F and atmospheric pressure
• Sometimes called o (60/60)
w
oo
API Gravity of Oil
5.1315.141
APIo
Phase Diagram - Typical Black Oil
Black Oil
Criticalpoint
Pre
ssure
, psia
Separator
Pressure pathin reservoir
Dewpoint line
% Liquid
Temperature, °F
Bubble-Point Pressure
The bubble-point pressure pb of a hydrocarbon system is defined as
the highest pressure at which a bubble of gas is first liberated from the
oil.
The empirical correlations for estimating the bubble-point pressure
Standing
Vasquez and Beggs
Glaso
Marhoun
Petrosky and Farshad
Reservoir Pressure > Oil Bubblepoint
Pressure
Oil
res bbl oil
STBBo =
Se
pa
rato
r
Stocktank
p > pb
res bbl
STB
scf
scf
Formation volume factor
• The change in volume of a reservoir fluid
undergoing production is normally
expressed in terms of the formation
volume factor
In general terms , the formation volume factor (B)
is the volume of the reservoir fluid (Vres) required
to produce a slandard volume of a surface product
relative to that surface volume (Vsur)
Oil Formation Volume Factor
• Definition - volume of reservoir oil at
reservoir conditions required to produce
one standard volume of stock tank oil
• Units - res bbl/STB
• Symbol - Bo
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. Temperature decrease from reservoir
temperature to 60F
3. Expands - pressure decreases from
reservoir pressure to atmospheric
pressure
Typical Shape -
Oil Formation Volume Factor
1
2
0 6000p
Bo
pb
Reservoir Pressure > Oil Bubblepoint Pressure
Oil
res bbl oil
STBBo =
Se
pa
rato
r
Stocktank
p > pb
scf
STBRsb =
res bbl
STB
scf
scf
Solution Gas/Oil Ratio
• Definition - volume of gas which comes
out of the oil as it moves from reservoir
temperature and pressure to standard
temperature and pressure.
• Amount of gas that will dissolve in a
certain amount of oil (Rs,or GOR)
• Units - scf/STB
Typical Shape -
Solution Gas/Oil Ratio
0
2000
0 6000p, psig
Rs, scf/S
TB
pb
Reservoir Pressure < Oil Bubblepoint Pressure
res bbl gas
MscfBg =
Gasres bbl
scf
Oil
res bbl oil
STBBo =
Se
pa
rato
r
Stocktank
p < pb
scf
STBRsb =
STB
scf
scf
res bbl
Typical Shape - Oil Formation
Volume Factor
1
2
0 6000p, psig
Bo, re
s b
bl/S
TB
pb
Typical Shape - Solution
Gas/Oil Ratio
0
2000
0 6000p, psig
Rs, scf/S
TB
pb
Coefficient of Isothermal
Compressibility of Oil - p > pb
Definition, orT
op
V
V
1c
T
o
oo
p
B
B
1c
Oil
Hg
Oil
Hg
Coefficient of Isothermal
Compressibility of Oil - p < pb
T
s
o
g
T
o
oo
p
R
B
B
p
B
B
1c
Hg
Hg
Oil
Oil
Gas
)](1[
1.
//
/
1
..........
1
1
bxoobox
obbx
oxob
xb
STBSTBob
STBob
o
xb
oxob
o
o
PPC
PP
PP
VVoxVV
VVC
STBthebyDividing
PP
VV
Vob
dp
dv
VC
Typical Shape - Oil
Compressibility
0
500
0 6000p, psig
co, p
si-1
x 1
06
pb
Oil Density
• Units - lb/cu ft or ft
psi
ftsq/insq144
ftcu/lb
39
47
0 6000p, psig
o, lb
/cu
ft
pb
Oil Viscosity
• Definition - the resistance to flow exerted
by a fluid,
• i.e., large values = low flow rates
• Units: centipoise
Typical Shape - Oil Viscosity
0.3
1.1
0 6000p, psig
o, cp
pb
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
• gSP of separator gas required in most
correlations - get from gas sales data
• Reservoir temperature, T - get from well logs
or other sources
Production/Pressure History of Typical Black Oil
3000
6000
9000
100
75
50
25
4000
3000
2000
1000
019791978 19811980
Time
Pro
ducin
ggas/o
il ra
tio
Oil
pro
ducin
gra
te,
MS
TB
/dR
eserv
oir
pre
ssure
, psia
Compressibility factor
BEHAVIOR OF REAL GASES
• At higher pressures, the use of the ideal
gas equation-of-state may lead to errors
as great as 500%, as compared to errors
of 2–3% at atmospheric pressure.
Z = f (Pr, Tr)
• Pseudo-reduced pressure
• Pseudo-reduced temperature
Example
A gas reservoir has the following gas composition: the initial reservoir
pressure and temperature are 3000 psia and 180°F, respectively.
Calculate the gas compressibility factor under initial reservoir conditions.
Pc and Tc from the table
Solution
Determine the pseudo-critical pressure
Calculate the pseudo-reduced pressure and temperature
Determine the z-factor from Figure
z = 0.85
Example
Using the data in the last example and assuming real gas behavior, calculate the
density of the gas phase under initial reservoir conditions. Compare the results
with that of ideal gas behavior.
Solution
Calculate the apparent molecular weight
Ma = 20.23Determine the pseudo-critical pressure
Ppc = 666.38Calculate the pseudo-critical temperature
Tpc = 383.38Calculate the pseudo-reduced pressure and temperature
Determine the z-factor from Figure
z = 0.85Calculate the density
Calculate the density of the gas
assuming an ideal gas behavior
Determination of Z factor when gas composition is not available
For Miscellaneous Gases
GAS FORMATION VOLUME FACTOR
Assuming that the standard conditions are represented by psc =14.7
psia and Tsc = 520, the above expression can be reduced to the
following relationship:
In other field units, the gas formation volume factor can be expressed
in bbl/scf, to give:
The reciprocal of the gas formation volume factor is called
the gas expansion factor and is designated by the symbol
Eg, or:
ExampleA gas well is producing at a rate of 15,000 ft3/day from a gas reservoir at an
average pressure of 2,000 psia and a temperature of 120°F. The specific gravity is
0.72. Calculate the gas flow rate in scf/day.
Solution
Calculate the gas flow rate in scf/day by multiplying the gas flow
rate (in ft3/day) by the gas expansion factor Eg as expressed in
scf/ft3:
Gas flow rate = (151.15) (15,000) = 2.267 MMscf/day
Two phase formation volume factor
go
STB
insolutiongasremaininginsolutiongasoriginalof
STBSTB
insolutiongasoil
STB
insolutiongasoil
t
RsRsi
V
VVo
V
gasVfree
V
V
V
gasVfreeV
][
..
..
...........
....
....
Relation between oil formation volume factor ,Solution
GOR and gas deviation factor with reservoir pressure
Example
. Acylinder is fitted with a leak –proof piston and calibrated so that the volume
within the cylinder can be read from a scale for any position of the piston .
The cylinder is immersed in a constant temperature bath , maintained at
160 F , which is the reservoir temperature of X field. Forty-five thousand cu
cm of the gas , measured at 14.7 psia and 60 F, is charged into the cylinder.
The volume is decreased in the steps indicated below , and the
corresponding pressures are read with a dead weight tester after
temperature equilibrium is reached.
V,cu cm 2529 964 453 265 180 156.5 142.2
P,psia 300 750 1500 2500 4000 5000 6000
Calculate..
1. Calculate and place in tabular form the ideal volumes
for the 45000 cu cm, at 160 F at each pressure, and the
gas deviation factor
2. Calculate the gas volume factors at each pressure, in
units of cubic feet of reservoir space per standard cubic
foot of gas and also, in units of standard cubic feet per
cubic foot of reservoir space .
3. Plot the deviation factor and the gas volume factors
calculated in part 2 versus pressure on the same graph.
4. Express the gas volume factor at 2500 psia and 160 F in
units of cuft/SCF/cuft, bbl/SCF, and SCF/bbl.
14.7 45000 620@300 2629
520 300
o oi i
i o
PVPV
T T
x xPsia Vi cc
x
The same , we can get Vi at each pressure
@750 psia = 1052 cc
@1500 Psia = 525.8 cc
@........
Z
• Gas deviation factor = Actual volume /
ideal volume
Both volumes at the same conditions of
temperature and pressure.
Z@300 Psia = 2529/2629 = 0.962
Z@750 Psia = 964/1052 =0.916
Gas volume factors at each
pressure• Bg=ZnRT/P
• N=(1/379.4) for one scf
• Bg= (Z/P)x(1/379.4)x10.73x620
• = 17.53 (Z/P)
• @300 psia Bg= 17.53 x (0.962/300)=
• = 0.0562 cuft/scf
• @750 psia…..and so on..
• Plot the deviation factor Z and the gas
volume factors Bg calculated in part 2
versus pressure on the same graph.
• Express the gas volume factor at 2500
psia and 160 F in units of cuft/SCF,
SCF/cuft, bbl/SCF, and SCF/bbl.