A special course by IFP Training for PDVSA
Gas Fields Reservoir Engineering & DevelopmentFluids Characterization and SamplingSalvatore Zammito
EP ‐ Fluids characterization & sampling
©2014 ‐IFP
Training
©2014 ‐IFP
Training
Fluids classification
EP ‐ Fluids characterization & sampling 3
©2014 ‐IFP
Training
Pressure
Temperature
Tres, Pres
Critical point
Tc
p2
p1
Separator
C
Dry gas
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Dry gas
Dry gas is virtually puremethane
The two‐phase envelope issmall and lies below reservoirconditions and to the left ofsurface condition
The fluid is theoretically gasboth in the reservoir and atthe surface
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Wet gas
The composition of a wet gas containsstill fewer heavy molecules. Since, thephase diagram covers a much smallertemperature range; the pressuredepletion path in the reservoir does notenter the two‐phase region
The composition of a wet gas containsstill fewer heavy molecules
Since, the phase diagram covers a muchsmaller temperature range; the pressuredepletion path in the reservoir does notenter the two‐phase region
The reservoir fluid is gas throughout thelife of the reservoir
However, separator conditions lie withinthe two‐phase envelope, indicating thatsome liquid will condense at the surface
EP ‐ Fluids characterization & sampling 6
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Pressure
Temperature
Tres, PresCritical point
Tc
p2
p1
Separator
C
Wet gas
EP ‐ Fluids characterization & sampling 7
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Training
Wet gas
The composition of a wet gas containsstill fewer heavy molecules. Since, thephase diagram covers a much smallertemperature range; the pressuredepletion path in the reservoir does notenter the two‐phase region
The composition of a wet gas containsstill fewer heavy molecules
Since, the phase diagram covers a muchsmaller temperature range; the pressuredepletion path in the reservoir does notenter the two‐phase region
The reservoir fluid is gas throughout thelife of the reservoir
However, separator conditions lie withinthe two‐phase envelope, indicating thatsome liquid will condense at the surface
EP ‐ Fluids characterization & sampling 8
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Training
Dry gas
Dry gas is virtually puremethane
The two‐phase envelope issmall and lies below reservoirconditions and to the left ofsurface condition
The fluid is theoretically gasboth in the reservoir and atthe surface
EP ‐ Fluids characterization & sampling 9
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Training
Condensate gas
Retrograde gases have even fewerheavy molecules than volatile oils
The critical point shifts to left anddownward in the phase diagram and thecritical temperature is usually less thanreservoir temperature
Retrograde condensate appears in thereservoir pore spaces at pressure belowthe dew point pressure. Throughoutmost of the reservoir, since the amountof liquid in the pore space is usually lessthan critical oil saturation the effectivepermeability to this condensate is zeroand little is produced
Along line 2 to 3, the condensate buildsup at first and then revaporizes at thelower pressures
This behavior is typical for constantcomposition expansion type application
At reservoir conditions can we see re‐evaporation?
EP ‐ Fluids characterization & sampling 10
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Condensate gas
Retrograde gases have even fewer heavymolecules than volatile oils
The critical point shifts to left anddownward in the phase diagram and thecritical temperature is usually less thanreservoir temperature
Retrograde condensate appears in thereservoir pore spaces at pressure belowthe dew point pressure. Throughoutmost of the reservoir, since the amountof liquid in the pore space is usually lessthan critical oil saturation the effectivepermeability to this condensate is zeroand little is produced
Along line 2 to 3, the condensate buildsup at first and then revaporizes at thelower pressures
This behavior is typical for constantcomposition expansion type application
At reservoir conditions can we see re‐evaporation?
EP ‐ Fluids characterization & sampling 11
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Training
Oil classification
API Definition
°API =
where d is the specific gravity of stock tank oil: relative to water at 60°F (15.6°C)
Condensate or very light oils: d < 0.80 (above 45°API)Light oil: 0.80 < d < 0.86 (33 to 45°API)Medium oils: 0.86 < d < 0.92 (22 to 33°API)Heavy oils: 0.92 < d < 1 (lower than 22°API)
131.5 d
141.5
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Petroleum fluids classification
Basic data characterizing well liquid effluent
1. Production data
• API gravity
• Gas oil ratio− GOR < 500 m3/m3 Oil
− 500 < GOR < 1000 m3/m3 Oil or gas condensate
− GOR > 1000 m3/m3 Gas condensate
− GOR > 15000 m3/m3 Wet gas
2. Chemical composition
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Fluids classification
Separator Density Composition
Well test GOR of STO C1 C2 C3 C4 C5 C6+
(Sm 3/m 3) (kg/m 3)
Heavy oil < 10 > 900 3 4 5 8 80
Standard oil < 500 800 ‐ 900 45 4 4 3 2 42
Critical fluid # 700 750 ‐ 850 55 10 8 5 6 16
Gas condensate 700 ‐ 800 700 ‐ 800 75 8 5 2 2 8
Wet gas > 15000 700 ‐ 800 90 4 3 1 1 1
Dry gas infinite 95 3 1 1
(mole %)
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Training
Gas properties
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UNDERSATURATED OIL RESERVOIRS
GAS- CONDENSATE RESERVOIRS
SINGLE PHASE
GAS RESERVOIRS
Phase envelope
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Training
Phase envelopes for various fluids
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Van der Waals EOS:
p =RT
(V‐b)
a
V2
Peng‐Robinson EOS:
p =RT
(V‐b)
aα
V(V+b)+b(V‐b)
Constants a and b are calculated based on the gas molar composition:
a = 0.45724 R2Tc2/pc and b = 0.07780 R Tc/pc α = α (TR, pR)
Equations of state
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p = pressure
V = volume
n = number of moles
R = gas constant (R = 8.314 kJ kgmole ‐1 K‐1 or 10.73 psia ft3 lbmole ‐1 R‐1 )
T = absolute temperature
z = compressibility factor
• Negligible molecular volume
• Negligible molecular attraction/repelling forces
pV = nRT
Ideal gas:
Real gas:
pV = znRT
Gas equation of state
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Function of:
gas composition
pressure
temperature
Ideal gas: z = 1
Real gas, S.C.: z = 1
Real gas, R.C.: z = 0.8 ‐ 0.9
IDEAL GAS
z
p
T
z = 1
p = 1 atm
Gas compressibility factor
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z
p
T=Tr
rnnn RTnzVp
scscscsc RTnzVp
r
sc
sc
n
sc
nn T
T
V
V
p
pz
For a generic pressure condition (n)
and reservoir temperature Tr:
nzRTpV
EOS for real gas:
z Determination
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For one molecular species:
• Reduced pressure
Critical pressurepr =
Absolute pressure
• Reduced temperature
Tr =Absolute temperature
Critical temperature
Natural gas, in the same pseudo‐reduced pressure and pseudo‐reducedtemperature conditions, present the same volumetric behavior and thus the same zvalue
Law of Corresponding States
z Factor
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For n‐ component gas
• Pseudo‐critical pressure
• Pseudo‐critical temperature
Molar fraction yi =Mol ith‐ component
Moltot
ppc =
n
1ii,ci py
Tpc =
n
1ii,ci Ty
z Factor
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Pseudo‐reduced pressure
Pseudo‐reduced temperature
ppr =Absolute pressure
Pseudo-critical pressure
p
ppc
=
Tpr =Absolute temperature
Pseudo-critical temperature
T
Tpc
=
z Factor
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Gas: determination of Tpc and Ppc
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Training
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Z Calculation
Exercise
Calculate the Z factor of a gacondensate
dg= 0.7 Pres= 450 b Tres= 150 °C
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Volume of free gas at reservoir conditions in m3 (or bbl) occupied by 1 m3 (or 1 scf) of the same gas measured at standard conditions
Bg =V(p,T)
Vsc
Bg =zpsc
pTsc
T
Bg
p
Bg =nzRT
p
psc
nzscRTscBg ranges between:
0.002 m3/sm3 (0.0004 rb/scf) 0.05 m3/sm3 (0.009 rb/scf)
Gas Formation Volume Factor (FVF)
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Training
ρg =Mp
zRT
M
V=
ρair = 1.225 kg/m3
ρairG =
ρg
SC
Mair = 28.96
Mair
G =Mg
ρg(p,T) =ρg,sc
Bg
Gas density and gas gravity
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cg 1
p
dpVcg =
dV1‐
cg
p
cg = 2÷4 10-4 psi-1
cg = 1.5÷3.5 10-2 MPa-1
Gas compressibility
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cg =1
p
RT
pM
RT
M
dp
d
Substituting in
dp
dc
1
Ideal gas
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dz
dp‐
1
pcg =
1
z
zRT
pM
For constant temperature:
dp
dz
zRT
pM
zRT
M
dp
d2
1
dp
dz
z
p
zRT
M
dp
d1
Substituting in
dp
dz
z
p
zRT
M
pM
zRTc 1
dp
dc
1
Real gas
EP ‐ Fluids characterization & sampling 32
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Training
In dimensionless terms:
prpcprpcg dpp
dz
zppc
11
prprgpcr dp
dz
zpcpc
11
Pseudo‐reduced pressurep
ppr ppc
=
Real gas
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μg = 0.01 ÷ 0.02 cP (mPa s)
mg
p
T
Gas viscosity
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Assuming
• Porous medium saturated by a single fluid
• No interactions between matrix and fluid
• Laminar flow
dpkμ
q
A=
dzdL
+( )dLg ρ
pp+dp
dL
XY
ZL
Generalized Darcy’s law
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Training
The permeability is an intrinsic property of the porous medium,independent from the flowing liquid. It indicates how easily fluidscan flow through the rock
k permeability [L2]
1 μm2 = 10‐12 m2
1 Darcy = 0.987 10‐12 m2 1 μm2
Absolute permeability
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pm =p1+p2
2pmkg =
bkL 1 +( )
PER
MEA
BILITY
KL
1pm
Propane
Ethane
Methane
Klinkemberg effect
For increasing molecular weight, gases exhibit a behavior whichtends to that of liquids because – all other conditions being the same– the kinetic energy is smaller
EP ‐ Fluids characterization & sampling 38
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Training
ko
kwkeff
kg
water
oil
gas
0 < S 1
0 keff kabs
Effective permeability
When a second or third phase is introduced, the resultingpermeability to each phase is called “effective”
It represents the conductivity of each phase at a specificsaturation
It provides an extension of Darcy’s law to presence andmovement of more than a single fluid within the pore space
The fluids interfere with each other, and individual effectivepermeability of each phase as well as their sum is lower thanabsolute permeability
EP ‐ Fluids characterization & sampling 39
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Training
dpkg
μg
qg A= ( )dr
Oil
Water
Gas
mw
dpkwqw A= ( )dr
dpko
mo
qo A= ( )dr
Multiphase flow
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WATER SATURATION
RE
LA
TIV
E P
ER
ME
AB
ILIT
Y
Relative permeability: gas‐water system
EP ‐ Fluids characterization & sampling 41
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Training
Oil and gas behavior between the
reservoir and the surface
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Black‐Oil model
Definitions:
VGF
VHF
VGHS
VHS
VGS
BoVHFVHS
BgVGFVGS
RsVGHSVHS
T , PF F
T , Ps s
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VGF
VHF
VGHS
VHS
BoV
VBg
V
V
RsV
VRv
V
V
HF
HS
GF
GS
GHS
HS
HGS
GS
'
T PF F,
T Ps s,
VGS
VHGS
Extended Black‐Oil model
EP ‐ Fluids characterization & sampling 45
Definitions:
©2014 ‐IFP
Training
VGF
VHF
BoV
VBg
V
V
RsV
VRv
V
V
HF
HS
GF
GS
GHS
HS
HGS
GS
'
T PF F,
T Ps s,
VGS
VHGS
Gas Condensate model
EP ‐ Fluids characterization & sampling 46
Definitions:
©2014 ‐IFP
Training
Vgres
Bg = Vgstd
Pres x Vres = Z x R x Tres
Pstd x Vstd = 1 x R x Tstd
Pstd
Bg = Tstd
x Z x Tres
Pres
Field Units
Pstd = 14.7 psia Tstd = 520 ° R Bg = 0.028269 xZ x T
Pvol/vol
Metric Units
Pstd = 1.01325 barsa Tstd = 288 ° K Bg = 0.00352 xZ x T
Pvol/vol
SI Units
Pstd = 101325 Pa (a) Tstd = 288 ° K Bg = 351.8 xZ x T
Pvol/vol
Vol of 1 mole of gas at std conditions {1 atm, 288 K (15°C)} : 23.63 dm3
° R
psia
° K
bars a
Pa
° K
Eg = 1 / Bg
Vol of 1 mole of gas at normal conditions {1 atm, 273 K (0°C)} : 22.414 dm3
460 +60°F(T st.)
273+15(Tst)
Main gas properties
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Main gas properties
Definitions for gas
Gas Specific Gravity
(air =1) = gas/air = Mwgas/Mwair
= Mwgas /28.978
Gas density
gas = Mwgas/Vair(molar) = Mwgas/ 23.645
Vair(1 mole of air) = 23.645
gas = * 1.225 kg/m³
Air density
Mwair = 28.9784
air =28.9784/23.645 =1.225 kg/m³
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Reservoir fluid sampling
Sampling objectives
Bottom hole sampling
Surface sampling
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Sampling objectives
The objective is to obtain a sample of fluid that is identical(representative) to the reservoir fluid
Those samples are needed to
• Determine the fluid type
• Estimate Hydrocarbons in place and reserves
• Measure or estimate the fluid characteristics that will be used todesign the production facilities or used in numerical models topredict reservoir performance
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Pwf
Separatorgas
oil
Production tubing
Vo Reservoir : Pr, Tr
Psep. ‐ Tsep.Pt
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Bottom hole sampling
This type of sampling is preferred since it guarantees the bestfluid representativity
Disadvantage: high cost
Various tools are used
• MDT (modular dynamic formation tester)
• SRS (single phase reservoir sampler)
• MFE (multiple flow evaluator)
• PCT (pressure controlled test system)
• APR (annulus pressure responsive tool)
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Surface sampling
Oil and gas samples are collected from separator, at surface
These samples are recombined in the laboratory, based on themeasured gas/oil ratio, in order to make up a reservoir fluid asrepresentative as possible
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Surface sampling
Psep, Tsep
gas
GORsep = Qgas/Qoil
Psto, TstoGORsto
Tank oilambient conditions
Reservoir fluidPr, Tr
Gas sampling bottle
Oil sampling bottle
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PVT studies
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Constant Composition Expansion (Oil)
Differential Vaporization (Oil)
Separator test/Flash Liberation (Oil)
Constant Composition Expansion (Condensate Gas)
Constant Volume Depletion (Condensate Gas)
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PVT experiment: constant volume depletion for a
condensate gas
Objective
• Simulation of reservoir production for condensate gas and volatile oil
Main properties derived from this experiment
• Liquid drop out curve
• Volumetric factor of the wellstream during depletion
• Wellstream composition during depletion
Remarks
• Be sure to have vapor and liquid at each step
• Problems imply negative calculated liquid compositions.
• Plot Ki(P) = Yi(P) / Xi(P)− All lines monotonic and smooth, No crossing, Ordered with volatilities
• Use the Hoffman‐Crump‐Hocott plot:− Log(KiP) is linear regarding B(1/Tbi‐1/T) with B=(log(Pci) –log(Pref)) / (1/Tbi‐1/Tci)
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Constant volume gas depletion
Gas
Oil
P1 = Psat P3
V sat
P2 < Psat
V 2
V 3
P3 < P2P2P2
V sat
Steps 0 1 2 3 1 2
Steps
0: Measure reference Volume Vsat à P1=Psat
1: Decrease P to P2<P1 lowering the piston, condensation occurs
2: Reset the cell volume to Vsat, pushing up the piston
3: Measure Oil and gas volumes
1: Decrease P to P3<P2, …
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PVT experiment: constant volume depletion for a gas
condensate Objective
• Simulation of reservoir production
Main properties derived from this experiment
• Liquid drop out curve
• Volumetric factor of the wellstream during depletion
• Wellstream composition during depletion
P1 = Psat P3
V sat
P2 < Psat
V 2
V 3
P3 < P2P2P2
V sat
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PVT experiment: constant mass expansion for a gas
condensate
Temperature
Pressure
T res.
P1 > Psat
P2 = Psat (retrograde)
P3
P4
P5
P6
P7< P sat (normal)
C
P1 > Psat P6P2 = Psat P4P3 < Psat P5 P7
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CCE – Gas condensate
Gas condensateReservoir Temperature : 105°CBubble point pressure : 286.72 abs bar
CCE
Bo = (Vol Liq at P,T)/(Vol Liq tank at 1b, 15)CGRres = (Vol Liq(PT)/Bo)/(VolVap(PT)/B'g) (CGR of liquid of CCE)CGRvap = Vol Liq(1,15)/Vol Gas Export Std (CGR of vapor of CCE)
Pressure Liquid CGR res CGR vap Gas Z factor Gas FVF Bg Gas viscosity Liq viscosity Liquid FVF Tank liquid STD gasdrop out B'g (P,T) (P,T) Bo density Sp Gravity Z'
(abs bar) (% DPPV) (Sm3/Sm3) (Sm3/Sm3) (m3/Sm3) (m3/Sm3) (cP) (cP) (m3/Sm3) (kg/m3)300 0,00000 0,000335 0,9371 0,00437 0,00410 0,0306 0,0000 736,5542 0,66771 0,99955
286,72 0,00000 0,000000 0,000335 0,9234 0,00451 0,00423 0,0296 0,3958 1,50266 736,5513 0,66771 0,98497280 0,18990 0,000006 0,000330 0,9169 0,00458 0,00430 0,0290 0,3950 1,49726 734,8984 0,66767 0,97764260 0,72054 0,000022 0,000313 0,8992 0,00483 0,00454 0,0273 0,3897 1,48252 730,2538 0,69179 0,95741240 1,21693 0,000038 0,000297 0,8839 0,00514 0,00483 0,0255 0,3804 1,46926 726,0515 0,69163 0,93979220 1,69928 0,000053 0,000281 0,8716 0,00552 0,00520 0,0238 0,3688 1,45612 722,2864 0,69147 0,92519200 2,18046 0,000069 0,000265 0,8626 0,00600 0,00566 0,0221 0,3582 1,44088 718,9011 0,69130 0,91407180 2,65607 0,000085 0,000247 0,8576 0,00661 0,00625 0,0205 0,3525 1,42099 715,8132 0,69112 0,90694160 3,10163 0,000101 0,000230 0,8568 0,00742 0,00703 0,0190 0,3549 1,39472 712,9628 0,69095 0,90420140 3,48253 0,000117 0,000212 0,8604 0,00849 0,00807 0,0177 0,3679 1,36180 710,3388 0,69081 0,90609120 3,76650 0,000130 0,000197 0,8683 0,00998 0,00950 0,0165 0,3937 1,32326 707,9747 0,69073 0,91270100 3,92883 0,000140 0,000184 0,8803 0,01213 0,01155 0,0156 0,4355 1,28072 705,9404 0,69073 0,9240180 3,94906 0,000145 0,000176 0,8963 0,01542 0,01470 0,0148 0,4989 1,23578 704,3532 0,69082 0,9400260 3,79928 0,000145 0,000175 0,9160 0,02102 0,02003 0,0142 0,5957 1,18974 703,4348 0,69102 0,9608540 3,41620 0,000135 0,000184 0,9394 0,03239 0,03082 0,0137 0,7569 1,14332 703,7007 0,69129 0,9869720 2,61173 0,000108 0,000215 0,9668 0,06694 0,06384 0,0133 1,1156 1,09628 706,7299 0,69162 1,019991 0,76071 0,000033 0,000300 0,9981 1,39472 1,33172 0,0130 3,4851 1,03850 720,5066 0,69192 1,06264
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CVD gas condensate
CVD
Bo = (Vol Liq at P,T)/(Vol Liq tank at 1b, 15)CGRres = (Vol Liq(PT)/Bo)/(VolVap(PT)/B'g) (CGR of liquid of CCE)CGRvap = Vol Liq(1,15)/Vol Gas Export Std (CGR of vapor of CCE)
Pressure Liquid CGR res CGR vap Gas Z factor Gas FVF Bg Gas viscosity Liq viscosity Liquid FVF Tank liquid STD gasdrop out B'g (P,T) (P,T) Bo density Sp Gravity
(abs bar) (% DPPV) (Sm3/Sm3) (Sm3/Sm3) (m3/Sm3) (m3/Sm3) (cP) (cP) (m3/Sm3) (kg/m3) z'300 0,00000 0,000335 0,9371 0,00437 0,00410 0,0306 0,0000 736,5542 0,66771 0,99955
286,72 0,00000 0,00000 0,000335 0,9234 0,00451 0,00423 0,0296 0,3958 1,50266 736,5527 0,66771 0,98497280 0,18990 0,00001 0,000330 0,9169 0,00458 0,00430 0,0290 0,3950 1,49726 734,8984 0,66767 0,97764260 0,71165 0,00002 0,000313 0,8992 0,00483 0,00454 0,0273 0,3897 1,48251 730,2536 0,66752 0,95741240 1,17507 0,00004 0,000297 0,8839 0,00514 0,00483 0,0255 0,3807 1,46906 726,0471 0,66738 0,93979220 1,60059 0,00006 0,000281 0,8716 0,00552 0,00520 0,0238 0,3701 1,45531 722,2668 0,66722 0,92520200 1,99701 0,00008 0,000264 0,8628 0,00600 0,00566 0,0221 0,3617 1,43877 718,8485 0,66705 0,91411180 2,35475 0,00011 0,000246 0,8579 0,00661 0,00625 0,0205 0,3595 1,41694 715,7107 0,66687 0,90704160 2,65082 0,00015 0,000227 0,8572 0,00742 0,00703 0,0190 0,3669 1,38848 712,8026 0,66671 0,90436140 2,86316 0,00019 0,000209 0,8609 0,00850 0,00807 0,0177 0,3864 1,35365 710,1205 0,66659 0,90628120 2,98103 0,00023 0,000193 0,8689 0,00998 0,00950 0,0165 0,4201 1,31392 707,6961 0,66654 0,91288100 3,00630 0,00030 0,000180 0,8809 0,01213 0,01156 0,0156 0,4713 1,27121 705,5845 0,66662 0,9241380 2,94877 0,00038 0,000172 0,8966 0,01542 0,01471 0,0148 0,5448 1,22730 703,8681 0,66687 0,9400860 2,81934 0,00052 0,000171 0,9160 0,02102 0,02003 0,0142 0,6485 1,18359 702,6973 0,66736 0,9610140 2,62107 0,00076 0,000187 0,9387 0,03242 0,03080 0,0137 0,7978 1,14097 702,4529 0,66821 0,9880420 2,32134 0,00145 0,000250 0,9650 0,06735 0,03089 0,0133 1,0369 1,10000 704,6793 0,66965 1,026231 1,22196 0,01788 0,000944 0,9966 1,51858 0,03124 0,0122 2,3203 1,05053 733,4063 0,67168 1,157016
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Liquid drop out
0,00000
0,50000
1,00000
1,50000
2,00000
2,50000
3,00000
3,50000
4,00000
4,50000
0 50 100 150 200 250 300 350
CCE
CVD
PRESSURE
Liquid drop out %
EP ‐ Fluids characterization & sampling 63
©2014 ‐IFP
Training
CVD – Comparison Z and Z’
0,6000
0,7000
0,8000
0,9000
1,0000
1,1000
1,2000
0 50 100 150 200 250 300 350
Z CVD
Z' CVD
PRESSURE
Z factor
EP ‐ Fluids characterization & sampling 64
©2014 ‐IFP
Training
PVT experiment: constant mass expansion
Fluide initialP = Pgis. (450 bar)
EP ‐ Fluids characterization & sampling 65
©2014 ‐IFP
Training
P = Dew point press – 100 mbar358 bar
PVT experiment: constant mass expansion
EP ‐ Fluids characterization & sampling 66
©2014 ‐IFP
Training
P = Dew point pressure – 3 bar5% liquid drop out
PVT experiment: constant mass expansion
EP ‐ Fluids characterization & sampling 67
©2014 ‐IFP
Training
During the depletion
PVT experiment: constant mass expansion
EP ‐ Fluids characterization & sampling 68
©2014 ‐IFP
Training
Near the maximum liquid drop out
PVT experiment: constant mass expansion
EP ‐ Fluids characterization & sampling 69
©2014 ‐IFP
Training
Maximum liquid drop out:41% P = 205 bar
PVT experiment: constant mass expansion
EP ‐ Fluids characterization & sampling 70