Primary funding is provided by
The SPE Foundation through member donations
and a contribution from Offshore Europe
The Society is grateful to those companies that allow their
professionals to serve as lecturers
Additional support provided by AIME
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
Understanding and Checking the
Validity of PVT- reports
Klaus Potsch
Consultant, EC&C
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
PVT report – an old hat?
 Yes
 Decades of experiments
and reports
 But with new feathers:
 Improved equipment
 Improved reporting
 Needs new quality control
 People forgot how to wear it
 General ignorance about
how fluid properties are
determined and reported
3
Outline
 Sampling
 Black Oil systems
 Gas Condensate systems
 Flow assurance
 Summary
4
Motivation
Formation of a gas cap
Condensate dropout
Fluid – Fluid Interaction -> EOR
= Enhanced Oil Recovery
To know the fluid properties
from the reservoir
to the facilities
Drilling mud invasion
Bottom hole sampling
to the refinery
Gas coning
Water coning
Condensate banking
5
What are the data good for?
 Reservoir engineer:
 simulation (black oil or compositional),
 well models
 Facility engineer:
 designs surface installations (simulation with process SW),
 design of transportation routes
 Economics:
 reserves;
 commodities (quality = price) stock tank oil, NGL,
condensate, gas
6
Starting point = reservoir fluid samples
 Laboratory work starts with good, representative samples.
 Impossible to get good results from non representative
samples (garbage in, garbage out).
Goal: information about the composition and quality
Essential, whether bottom hole sample (BHS) or
surface sample (SS):
 Reservoir conditions (p,T,depth)  experiments
 Sampling conditions (p,T,V=rates)  experiments
Sample only single phase streams
Sample only a conditioned well = clean and stable flow
Sample as early as possible
7
Bottom hole sampling
Danger: OBM mixed with reservoir fluid  decontamination
Tracers help!
Artificial mud
Diesel
single carbon number
single carbon number
10
20
1.01
OBM
clean
30
0
40
10
20
30
40
mol%
concentration
0
8
Separator sampling
 What is the flow rate and the retention time (size of the
separator)?
 Is carry-over or carry-under significant?
 Are the rates stable?
 How high is the pressure?
 How many phases are recorded?
gas + carry over
inlet
oil + carry under
water
9
Separator sampling, cont‘d.
Where is the reservoir in the phase diagram?
Gas phase is at a dew point
Liquid phase is at a bubble point
sat
sat
 pliquid
 pvapor
res fluid
sep gas
sep liquid
separator
condition
temperature
absolute pressure




10
Separator samples
Reservoir
Surface separator
separator gas
psep,Tsep,yk
reservoir
fluid
pres,Tres,zk
gas 1
pamb,Tamb,yyk
liquid 1
pamb,=Tamb,yxk
GLR 1
Kyk=yyk/yxk
GLRsep,Kk=yk/xk
separator liquid
psep,Tsep,xk
BHS
Laboratory
gas 2
pamb,Tamb,xyk
liquid 2
pamb,Tamb,xxk
GLR 2
Kxk=xyk/xxk
SS
11
Samples (SS), validity checks
 Was a valve leaking?
 Liquid: Determinig psat at ambient condition and recalculating
to sampling condition.
 Gas: p.V/T should be the same at ambient and sampling
conditions
12
Samples (SS), analyses
Analyses by gas and liquid
chromatography
earlier times 
now 
scn
Component
scn
Component
H2
0
Hydrogen
6
Benzene
H2S
0
Hydrogen
Sulphide
6
Cyclohexane
CO2
0
Carbon Dioxide
7
Heptanes
N2
0
Nitrogen
7
Methyl-CycloHexane
C1
1
Methane
7
Toluene
C2
2
Ethane
8
Octanes
C3
3
Propane
8
Ethyl Benzene
iC4
4
iso Butane
8
Meta/Para-Xylene
nC4
4
normal Butane
8
Ortho-Xylene
neo
C5
5
neo-Pentane
9
Nonanes
iC5
5
iso Pentane
9
1,2,4-Tri-MethylBenzene
nC5
5
normal Pentane
10
Decanes
C6
6
Hexanes
6
Methyl-CycloPentane
C7
C8
C9
C10
…..
C36
+
Hexatriacontanes
Plus
13
Quality check of sample compositions
via equilibrium- or K-values (Wilson, Hoffman, etc) versus
characterization factor, e.g.
characterization factor F
-6
-4
-2
0
2
4
6
8
8
6
ln K
4
2
0
-2
-4
-6
-8
experimental data
Wilson's estimates
regression
14
Reservoir fluid: composition
 BHS: mathematical recombination
 SS: mathematical and physical recombination
Reservoir fluid: properties
 Experiments, that mimic the flow process
 Correlations for Black Oil (BO)
 EOS
15
Experiments, mimicking the flow process
Black Oil (BO):
Gas Condensate (GC):
 Gas gets out of solution, moves
upward, forms a gas cap
 Formation of a condensate bank, in case of
lean condensate immobile well stream
composition  reservoir composition
 2phase flow into the well bore,
different mobilities, GLR
questionable
CCE
 Rich condensate: 2-phase flow into the well
bore, different mobilities,
GLR questionable
CCE
DLE
CVD
16
Constant composition expansion (CCE)
BO:
p1 >
p2 >
p3=pb > p4 >
p5
>
p6 >
p7
Test: Y(p)=(p/psat-1)/(Vt /Vsat-1) linear in p
GC:
p1
>
p2 > p3=pd > p4 >
p5 >
p6 >
p7
17
Constant composition expansion (CCE)
Determination of saturation pressure
GC
2ph
pdew
pb
1ph
p.V/Z1ph
ln (cell volume)
BO
2ph
1ph
experiment
theory
absolute pressure
 dV/dp is discontinuous 
saturation pressure pb
 p>pb: compressibility
Cp=O (10-3) [MPa-1]
absolute pressure
 d(pV/Z1ph)/dp is discontinuous 
saturation pressure pd
 Z1ph from overall-composition
 SPE36919
18
BO: Differential liberation experiment (DLE)
Principle:
19
BO: Differential liberation experiment (DLE)
Gas in solution – Rs(p) determines the volumetric behavior
Bo
Test 1: Bo(Rs(p)) almost linear in Rs
Rs
20
BO: Differential liberation experiment (DLE)
Test 2:
Ct = Bo(patm)-1 =
= O (10-3) [K-1]
21
BO: Differential liberation experiment (DLE)
Test 3: Y-function, use Vg,lib(p) for Vt, (not in textbooks) and Zg
(check with REFPROP from NIST)
Y
2.6
2.4
Y_CCE
2.2
Y_DLE
2.0
1.8
1.6
1.4
1.2
0.0
0.2
0.4
pr
0.6
0.8
1.0
22
BO: Differential liberation experiment (DLE)
ln(µo(p_atm/µo(p))
Test 4: ln(µo(patm)/µo(p)) similar shape as Bo(p), (not in textbooks)
Bo(p) -Bo(p_atm)
23
BO: Differential liberation experiment (DLE)
Test 5: well stream composition, concentation of light components
(N2, C1, possibly CO2 and C2 are convex, the rest is concave)
ln concentration
abs.pressure
CO2
N2
C1
C2
C3
iC4
nC4
iC5
nC5
C6
24
BO: Production process
 Combination of DLE (reservoir) and CCE (tubing)
 Flash (CCE) Bof,Rsf < diffferential (DLE) Bod,Rsd
p  pb :
Rsd
Rsfb
Rsd-Rsf
Rsf
Rsf
Rsd
 const.
Rsd,Rsf
Rsf_ lit
CCE
0
abs.pressure
25
BO: Production process
Bod
Bofb
Bof
Bof_lit
Bod-Bof
p  pb :
Bod  Bof
Bod,Bof
Rsd  Rsf
 const.
CCE
1
abs.pressure
26
GC: Constant volume depletion (CVD)
Principle
27
GC: Constant volume depletion (CVD)
Test 1: VlCCE(p) > VlCVD(p) …liquid drop out
25
CCE
Vl/Vd%
20
CVD
15
10
5
0
0
100
200
300
400
500
600
p abs [bar]
28
Constant volume depletion (CVD)
Test 2: Y-function, using 1+Vwell stream(p) slightly curved, close to YCCE,
(not in textbooks)
1.75
1.70
1.65
Yv
1.60
1.55
1.50
Yv_CVD
1.45
Yv_CCE
1.40
1.35
1.30
100
200
300
400
p abs [bar]
29
Correlations
 Estimates for Black Oil – tables
 General form:
 pb = fb(Tres,rSTO,rSTG,Rs)
 Bo = fB(Tres,rSTO,rSTG,Rs)
 µo = fµ(Tres,rSTO,rSTG,Rs)
 µg calculated from Gonzales, Eakin
 Zg from REFPROP (developed by NIST)
30
Equations of State - EOS





input = composition
try to match the experiments
prerequisite: C6+ modeling
 reveals the inconsistencies
mind the errors of the field measurments
best
worst
monophasic BHS
0%
invalid
separator GOR
5%
25 %
human or equipment failure
0%
invalid
BHP
 0.01  1 %
3%
BHT
 0.25  1 %
5%
31
Flow Assurance
 Gas hydrates: gas composition necessary
 Paraffins
 Saturates, aromates, resins, asphaltenes
 SARA or PNA analysis
 Heavy end  liquid chromatography
 Wax appearance temperature (WAT)  cold finger test
 Asphaltenes
 SARA or PNA or IP44
 Flow test with capillary
32
Summary
 Starting point for determination of fluid properties:
quality-sampling
 Tools exist to check the laboratory data
 Estimates can be gained via correlations or EOS
33
Further reading
 Ahmed, T.; Hydrocarbon Phase Behavior. Gulf Publishing Co,
1989.
 Bon J., Sarma H., Rodrigues T., Bon J.; Reservoir-Fluid
Sampling Revisited – A Practical Perspective, SPE101037.
 Danesh, A.; PVT and Phase Behaviour of Petroleum
Reservoir Fluids; Elsevier 2008.
 Michelsen, M.L.; Mollerup, J.M.; Thermodynamic Models,
Fundamentals and Computational Aspects; Tie-Line
Publications, 2004.
 Moffat B.J.; Williams J.M.; Identifying and Meeting the Key
Needs for Reservoir Fluid Properties. A Multidisciplinary
Approach, SPE49067.
34
Further reading
 Pedersen, K.S.; Fredenslund, A.; Thomassen, P.; Properties
of Oils and Natural Gases. Gulf Publishing Co, 1989.
 Prausnitz, J.M.,Lichtenthaler, R.N.,Gomez de Azevedo, E;
Molecular Thermodynamics of Fluid Phase Equilibria.
2nd edition, Prentice Hall, 1985.
 Riazi, M.R.;Characterization and Properties of Petroleum
Fractions, ASTM manual series MNL50; 2005
 Whitson, C.H.; Brulé, M. R.; Phase Behavior;
SPE Monograph, volume 20, 2000.
35