This document summarizes a study of flow instabilities in the Girassol deep offshore oil production system. Dynamic simulations using OLGA were able to accurately match field data from the system and predict instabilities observed at certain gas lift rates. The simulations identified slug tracking as key to predicting instabilities between gas lift rates of 40-30 kSm3/d, consistent with on-site investigations. Liquid flow rate was also found to impact stability. The study validated dynamic simulators for optimizing gas lift rates to avoid riser instabilities.

1. Analysis of Multiphase Flow
Instabilities in the Girassol Deep
Offshore Production System
Erich Zakarian & Dominique Larrey
Total E&P, Process Department, France
Multiphase Technology
Banff, AB, Canada: 4-6 June 2008

2. Contents
The Girassol Field
Fluid data
Subsea production system
Production data
Study Objectives
y j
Dynamic Simulation with OLGA®
In-depth validation against field data
Analysis of field stability tests
Conclusions
Multiphase Technology 2008

3. The Girassol field
Fluid data
Oil density
d it ~ 861 870 k / 3 (32°API)
861-870 kg/m
GOR ~ 110-130 Sm3/Sm3
Bubble point ~ 255-275 bar
Wax appearance temp
temp. ~ 34 39°C
34-39 C
Oil visc. @ reservoir cond. ~ 1 cP First oil: Dec. 2001
Oil visc. @ surface cond. ~ 7-35 cP
Pour point ~ -9°C
9C
Initial reservoir data
Pressure ~ 268 bar
Temperature ~ 58-69°C
Water depth ~ -1350 m
p
Seabed temp. ~ 4°C
Multiphase Technology 2008

4. The subsea production system
p y
Test Riser tower
FPSO Wells
separator
23 oil producers
il d
Manifold 13 Water injectors
2 Gas injectors
Topside
p
chokes Xmas tree
Umbilical
Riser base
gas-lift
For activation & stabilization
Bundle
Production loop for
Jumper
p hydrate p
y preservation
2x8” production lines
Multiphase Technology 2008

5. Girassol production flowlines
p
0 2000 4000 6000 8000
-1280
80 Distance [m]
-1290 P50 loop
-1300
P20 loop
-1310 P40 loop
Gas-lift
Water dep [m]
-1320 P30 loop injection line
pth
-1330
-1340
Riser
-1350
1350
P60 loop base
-1360 Jasmim field
-1370
1370
tie-back
P10 loop
-1380
Multiphase Technology 2008

6. Production data
A large amount of production data was retrieved
in 2006 for an in-depth analysis
More than 1 billion transmitted values
Mainly pressures, temperatures, gas-lift rates, choke openings
Approx. 1,200 direct and multiple production well tests
Liquid fl
Li id flow rate: 250
t 8000 S 3/d (up to 3 wells per flowline)
Sm ( t ll fl li )
GOR: 100 5000 Sm3/Sm3 (gas is re-injected into reservoir)
Water cut: 0 70%
Gas-lift rate: zero and 50 300 kSm3/d
2 flow stability tests (field experiments)
25 flow instabilities reported during normal operation
Multiphase Technology 2008

7. Study objectives
y j
Improve reservoir simulations with updated flowline
pressure drop tables to match field data
Provide operators with a reliable tool to avoid
hydrodynamic instabilities in production risers at
minimum gas-lift rate
So far OLGA® had failed to reproduce observed flow instabilities
Perform an exhaustive validation of dynamic simulators
Consolidate usual design margins in deepwater oil field
development
d l
Using simulator default modelling settings NO TUNING!
Multiphase Technology 2008

8. Data comparison with OLGA®
p
Measured pressure drop vs. OLGA®
From the closest subsea manifold to the topside production choke inlet
110 Average error
E. Zakarian & D. Larrey
bara]
100 P60
Paper IPTC 11379
90
ulated Pressure Drop [b
Dubai - Dec. 2007 P50
80
70 P40
60 P10
P20 P30
50 P30
P40
40 P20
P50
Calcu
30 P60
P10
Production well tests +/- 10%
20
Jan. 2005 - Aug. 2006 +/- 20%
0% 10% 20% 30%
10
10 20 30 40 50 60 70 80 90 100 110 Usual design
U ld i
Measured Pressure Drop [bara] margin (10%)
Multiphase Technology 2008

9. Field stability tests
y
The hydraulic stability of two production flowlines
was purposely tested in 2004
l t t di
To collect relevant data for gas-lift optimisation
Both i
B th in upward and downward sloping flowlines
d dd d l i fl li
Through connection to a test separator for an accurate
measurement of phase flow rates
To achieve relevant flowing conditions for analysis
Step-by-step turn-down of the gas-lift rate
Step-by-step riser-head choking to keep constant back-
pressure
Fixed wellhead choke opening
Multiphase Technology 2008

10. P50 loop stability test
p y
Flow is unstable at gas-lift rate between 100 and 70 kSm3/d
130 190
Oscillation time period ~ 3h
125 Gas-lift rate
170
120
Gas-lift rate [kSm3/
Gas-lift rate [kSm3/
G
G
115 150
Pressure [barg]
110
130
35 bar
e
105
110
100
95 90
/d]
/d]
90 Flowline pressure at
subsea manifold M501 70
85
80 Riser-induced
Riser induced
50
13-mai-04 5:16 13-mai-04 17:16 14-mai-04 5:16 14-mai-04 17:16 15-mai-04 5:16 slugging
Multiphase Technology 2008

11. P50 loop stability test
p y
P5011 wellhead choke
50 opening 50
45
45 40
Pressure at topside
P tt id
Choke ope
Choke ope
C
C
35
Pressure [barg]
riser head choke inlet
40 30
25
ening [%]
ening [%]
35 20
15
30 10
Topsides riser head
5
choke opening
25 0
13-mai-04 5:16 13-mai-04 17:16 14-mai-04 5:16 14-mai-04 17:16 15-mai-04 5:16
Multiphase Technology 2008

12. Dynamic simulation with OLGA®
y
Calculated pressure at closest manifold
QLiq=3146 Sm3/d - GOR=102 Sm3/Sm3 - Water cut=53% - Pout=37 barg
124 Gas-lift rate = 70 kSm3/d 1h
Gas-lift
Gas lift rate = 80 kSm3/d
Pressure at manifold M501 [bara]
]
122
120
M
6 bar Oscillation
118
time period
~ 8 min.
116
114
112
Gas-lift rate = 90 kSm3/d
Gas-lift rate = 100 kSm3/d
110
Multiphase Technology 2008

13. Model extension to the wellbore
Calculated pressure at closest manifold
QLiq=3146 Sm3/d - GOR=102 Sm3/Sm3 - Water cut=53% - Pout=37 barg
124 Gas-lift rate = 70 kSm3/d 1h
a]
Pressure at manifold M501 [bara
122 Gas-lift rate = 80 kSm3/d
120
8 bar Oscillation
d
118
time period
116
~ 45 min.
e
114
112
Gas-lift rate = 100 kSm3/d Gas-lift rate = 90 kSm3/d
110
Multiphase Technology 2008

14. Gas-lift modelling
g
Calculated pressure at closest manifold
QLiq=3146 Sm3/d - GOR=102 Sm3/Sm3 - Water cut=53% - Pout=37 barg
124 1h
ra]
fold M501 [bara
122
120
8 bar Gas-lift rate
118
70 kS 3/d
kSm
ssure at manif
116
114 No instability
Pres
112
with mass
sources!
110
Mass source at riser base & manifold
Gas-lift line & mass source at manifold
0
Wellbore &1 mass source at riser base
2 3
Wellbore & gas-lift line
Time [h]
Multiphase Technology 2008

15. P10 loop stability test
p y
Hydrodynamic/terrain slugging
136 0.5
05h
Flow is unstable at minimum 135
ssure [barg]
gas-lift rate (50 kSm3/d) 134
133
Pres
140 132 300
139 131
3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04
250
19:12 19:40 20:09 20:38 21:07 21:36
138
Time delay ~ 2 h
Gas-lift rate [kS
137
200
ssure [barg]
136 Flowline pressure at
subsea manifold M102
135 150
Pres
Sm3/d]
134
100
133 4 bar
132
50
131
Gas-lift rate
130 0
3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 4-Jun-04
0:00 2:24 4:48 7:12 9:36 12:00 14:24 16:48 19:12 21:36 0:00
Multiphase Technology 2008

16. P10 loop stability test
p y
55 31
Topside i
T id riser head
h d 30.5
50
choke opening
30
Riser c
45
29.5
g]
Pressure [barg
choke openin [%]
40 29
35 28.5
ng
28
30
Pressure at topside 27.5
25
riser head choke inlet
27
20 26.5
3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 3-Jun-04 4-Jun-04
0:00 2:24 4:48 7:12 9:36 12:00 14:24 16:48 19:12 21:36 0:00
Opening of the wellhead chokes was kept constant
during the whole test (80%)
Multiphase Technology 2008

17. Dynamic simulation with OLGA®
y
Measured pressure at 2nd manifold
Gas-lift rate = 50 kSm3/d
138 138 138
137 137 137
136 136 136
135
Pressure [barg]
135 135
134 134 134
133 133 133
132 132 132
131 131 131
130 130 130
Calculated pressure
p Calculated pressure
p Calculated pressure
p
129 GL rate = 40 kSm3/d 129
GL rate = 30 kSm3/d 129 GL rate = 20 kSm3/d
128 128 128
3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04 3-juin-04
19:12 19:40 20:09 20:38 21:07 21:36 19:12 19:40 20:09 20:38 21:07 21:36 19:12 19:40 20:09 20:38 21:07 21:36
Slug T ki
Sl Tracking option is required to predict hydraulic instability
ti i i dt di t h d li i t bilit
Instability is predicted at a gas-lift rate between 40 and 30 kSm3/d
g
Results are consistent with a recent on-site investigation:
measurement uncertainty on the minimum gas-lift rate can be 30%
Multiphase Technology 2008

18. Flow stability vs. liquid flow rate
y q
Calculated pressure at 2nd manifold
Gas-lift rate=50 kSm3/d - GOR=103 Sm3/Sm3 - Water cut=43% - Pout=35 barg
160
fold at M102 [bara]
Minimum pressure at manifold M102 [bara]
150 Maximum pressure at manifold M102 [bara]
140 Hydrodynamic
slug growth?
130
Valle t l
V ll et al. (BHRG 2005)
sure at manif
120
Measured stability limit
110
Press
5404 Sm3/d
100
0 2000 4000 6000 8000 10000
Terrain/hydrodynamic
T i /h d d i Liquid flow rate [Sm3/d]
slugging
Multiphase Technology 2008

19. Conclusions
In Girassol, the nature of multiphase flow instabilities
Girassol
is strongly dependent on the geometrical profile of
the flowline laid on the seabed
In downward sloping flowlines
Flow is prone to riser-induced slugging
p gg g
In upward sloping flowlines
Flow is prone to hydrodynamic/terrain slugging
p y y gg g
Hydrodynamic slug growth seems possible at high flow
rates although never observed
Multiphase Technology 2008

20. Conclusions
In downward sloping flowlines, instabilities are
easily handled with an increase of:
gas-lift injection rate (immediate effect)
production rate (delayed effect)
topside back-pressure (delayed effect)
In upward sloping flowlines
A significant time delay is required to reach fully
developed flow or to achieve stabilization
An increase of the gas-lift rate can be detrimental to
flow stability (see paper)
Multiphase Technology 2008

21. Conclusions
Instability onset with decreasing gas-lift rate is well
predicted with OLGA® despite a poor prediction of
pressure oscillations (using default modelling
settings)
Gas-lift line modelling and extension to the wellbore
are recommended to catch flow instabilities in
downward sloping flowlines
p g
Use of Slug Tracking is mandatory to capture
hydrodynamic/terrain-slugging instabilities in
upward sloping flowlines
d l i fl li
Pressure drop calculation: the usual 10% minimum
design margin can be applied to deepwater oil
production system such as Girassol
Multiphase Technology 2008

22. Analysis of Multiphase Flow Instabilities in the
y p
Girassol Deep Offshore Production System
Erich Zakarian & Dominique Larrey
Total E&P, Process Department, France
Erich.Zakarian@total.com
Dominique.Larrey@total.com
Multiphase Technology 2008

23. Back-up slides
p
Multiphase Technology 2008

24. Minimum gas-lift rate
g
EXAMPLE 1
P10 loop, QLiq=3000 bbl/d, GOR=500, WC=0%
Minimum Gas-Lift rate = 30 kSm3/d (NO Sl
Mi i G Lift t kS Slug Tracking)
T ki )
Minimum Gas-Lift rate = 70 kSm3/d (WITH Slug Tracking)
EXAMPLE 2
P10 loop, QLiq=20,000 bbl/d, GOR=200, WC=60%
p, , , ,
Minimum Gas-Lift rate = 10 kSm3/d (NO Slug Tracking)
Minimum Gas-Lift rate > 150 kS 3/d (WITH Sl T ki )
Mi i G Lift t kSm Slug Tracking)
Multiphase Technology 2008

25. First example of instability ( )
p y (1/2)
Riser-induced slugging (P30 loop, Oct 28th 2005)
120 100
115 90
110
Gas-lift rate 80
Gas-lift rat [kSm3/d]
Gas-lift rat [kSm3/d]
105 70
Pressure [barg]
100 60
te
te
e
95 50
90 40
35 bar
85 30
Oscillation
80 time period 20
75 Flowline pressure at ~ 50 min. 10
subsea manifold M301
70 0
28-Oct-05 28-Oct-05 28-Oct-05 29-Oct-05 29-Oct-05 29-Oct-05 29-Oct-05 29-Oct-05
16:48 19:12 21:36 0:00 2:24 4:48 7:12 9:36
Multiphase Technology 2008

26. First example of instability ( )
p y (2/2)
Riser-induced slugging (P30 loop, Oct 28th 2005)
60
P3012 wellhead choke 40
opening
55 35
Pre
Pre
essure drop a
essure drop a
50
30
Topside riser head
ning [%]
45
choke opening 25
40 Pressure drop across
20
Choke open
topside riser head choke
across choke [bar]
across choke [bar]
35
15
30
10
25
5
20
15 Pressure drop across 0
P3012 wellhead choke
10 -5
28-oct-05 28-oct-05 28-oct-05 29-oct-05 29-oct-05 29-oct-05 29-oct-05 29-oct-05
16:48 19:12 21:36 0:00 2:24 4:48 7:12 9:36
Multiphase Technology 2008

27. 2nd example of instability ( )
p y (1/2)
130
Hydrodynamic/terrain slugging 129
128
Pressure [barg]
127
P10 loop, Feb 27th 2005 126
125
124
123
122
130
Time delay ~ 9 h 121
300
120
27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05
129 4:48 5:16 5:45 6:14 6:43 7:12
Gas-lift rate 250
128
Gas-lift rate [kSm
G
127
200
ressure [barg]
126
125 150 Oscillation
4 bar 124
time period
m3/d]
Pr
100
123
~ 15 min.
122
50
121 Flowline pressure at
subsea manifold M101
120 0
26-Feb-05 26-Feb-05 26-Feb-05 26-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05 27-Feb-05
14:24 16:48 19:12 21:36 0:00 2:24 4:48 7:12 9:36 12:00 14:24
Multiphase Technology 2008

28. 2nd example of instability ( )
p y (2/2)
Hydrodynamic/terrain slugging (P10 loop, Feb 27th 2005)
90 P1022 & P1031 wellhead 20
choke opening
18
Pres
Pres
80
16
ssure drop a
ssure drop a
Pressure drop across
ning [%]
14
70 topside riser head choke
12
Choke open
across choke [bar]
across choke [bar]
60 10
8
50
6
Topside riser head
choke opening 4
40
2
30 0
26-févr-05 26-févr-05 26-févr-05 26-févr-05 27-févr-05 27-févr-05 27-févr-05 27-févr-05 27-févr-05 27-févr-05 27-févr-05
14:24 16:48 19:12 21:36 0:00 2:24 4:48 7:12 9:36 12:00 14:24
Multiphase Technology 2008

29. Field validation: GOR
2.0
1.9
19
1.8
Predicted DP / Measur DP
1.7
red
1.6
1.5
1.4
1.3
D
1.2
12
1.1
1.0
0.9
P
0.8
0.7
0.6
100 1000 10000
Gas Oil Ratio [Sm3/m3]
Multiphase Technology 2008

30. Field validation: water cut
2.0
1.9
1.8
Predicted DP / Measur DP
1.7
red
1.6
1.5
1.4
1.3
D
1.2
12
1.1
1.0
0.9
0.8
0.7
0.6
0 10 20 30 40 50 60 70 80 90 100
Water cut [%]
Multiphase Technology 2008

31. Field validation: gas-lift rate
g
2.0
1.9
1.8
Predicted DP / Measur DP
1.7
red
1.6
1.5
1.4
1.3
D
1.2
12
1.1
1.0
0.9
P
0.8
0.7
0.6
0 50000 100000 150000 200000 250000 300000
Gas-lift Rate [Sm3/d]
Multiphase Technology 2008

32. Field validation: temperature
p
Measured temperature at riser production choke inlet vs. OLGA®
70
65
60
Production well tests
lated Temperatu re [°C]
55
Jan. 2005 - Aug. 2006
50
45
P10
40
P20
35 P30
30 P40
Calcul
P50
25
P60
20 +/- 10%
+/- 20%
15
10
10 15 20 25 30 35 40 45 50 55 60 65 70
Measured Temperature [°C]
Heat transfer through pipe wall is simulated with design U-values
This study f
focuses primarily on hydraulic issues such as pressure drop
and flow instabilities
Multiphase Technology 2008

33. Field validation
4.0
m/s]
Selected well tests
perficial Velocity at Ris Base [m
3.5 Unstable well tests (large pressure oscillation)
Unstable well tests (OLGA)
3.0
ser
2.5
2.0
1.5
1.0
Oil Sup
0.5
0.0
0 2 4 6 8 10
Gas Superficial Velocity at Riser Base [m/s]
Multiphase Technology 2008

34. Field validation
4.0
m/s]
Selected well tests
elocity at Ris Base [m
3.5 Unstable well tests (large pressure oscillation)
Unstable well tests (OLGA)
3.0
ser
2.5
2.0
Water Superficial Ve
1.5
1.0
0.5
0.0
0 2 4 6 8 10
Gas Superficial Velocity at Riser Base [m/s]
Multiphase Technology 2008

35. Flow stability vs. liquid flow rate
y q
Calculated pressure Calculated pressure
at liquid rate = 6000 Sm3/d
t li id t S at liquid rate = 5000 Sm3/d
t li id t S
150
145
140
135
Pressure [bara]
130
125
120
115
110
105
100
Calculated pressure 1.5
C l l t d0.5
0 1 2 2.5 3 3.5 4 4.5 5
Time [h]
at liquid rate = 2000 Sm3/d
Multiphase Technology 2008