bhrg 2008 girassol_flow_instabilities
TRANSCRIPT
Analysis of Multiphase Flow Instabilities in the Girassol DeepInstabilities in the Girassol Deep
Offshore Production System
Erich Zakarian & Dominique LarreyTotal E&P, Process Department, France
Multiphase Technology Banff, AB, Canada: 4-6 June 2008
Contents
The Girassol FieldThe Girassol FieldFluid dataSubsea production systemProduction data
Study Objectivesy j
Dynamic Simulation with OLGA®
In-depth validation against field dataIn-depth validation against field dataAnalysis of field stability tests
Conclusions
Multiphase Technology 2008
Conclusions
The Girassol fieldFluid data
Oil d it 861 870 k / 3 (32°API)Oil density ~ 861-870 kg/m3 (32°API)GOR ~ 110-130 Sm3/Sm3
Bubble point ~ 255-275 barWax appearance temp ~ 34 39°CWax appearance temp. ~ 34-39 COil visc. @ reservoir cond. ~ 1 cPOil visc. @ surface cond. ~ 7-35 cPPour point ~ -9°C
First oil: Dec. 2001
Initial reservoir dataPressure ~ 268 bar
Pour point 9 C
Pressure 268 bar Temperature ~ 58-69°C
Water depth ~ -1350 m
Multiphase Technology 2008
pSeabed temp. ~ 4°C
The subsea production systemp yRiser tower FPSO Wells
23 il d
Test separator
Manifold 23 oil producers
13 Water injectors2 Gas injectors
Topside Xmas tree
Umbilical
pchokes
Riser base gas-lift
For activation & stabilization
Bundle
JumperProduction loop for
hydrate preservation
Multiphase Technology 2008
p y p
2x8” production lines
Girassol production flowlines
Distance [m]-12800 2000 4000 6000 8000
p
Distance [m]
-1300
-1290
80
P50 loop
P20 loop
-1320
-1310
pth
[m]
P40 loopP20 loop
P30 loopGas-lift
injection line
1350
-1340
-1330
Wat
er d
ep
Riser
-1370
-1360
-1350 baseJasmim field
tie-back
P60 loop
P10 loop
Multiphase Technology 2008
-1380
1370 P10 loop
Production dataA large amount of production data was retrieved
in 2006 for an in-depth analysisMore than 1 billion transmitted values
Mainly pressures, temperatures, gas-lift rates, choke openings
Approx. 1,200 direct and multiple production well testsLi id fl t 250 8000 S 3/d ( t 3 ll fl li )Liquid flow rate: 250 8000 Sm3/d (up to 3 wells per flowline)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)
Multiphase Technology 2008
25 flow instabilities reported during normal operation
Study objectivesy jImprove reservoir simulations with updated flowline pressure drop tables to match field datapressure drop tables to match field data
Provide operators with a reliable tool to avoid hydrodynamic instabilities in production risers athydrodynamic 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 d ldevelopment
Using simulator default modelling settings NO TUNING!
Multiphase Technology 2008
Data comparison with OLGA®
Measured pressure drop vs. OLGA®
From the closest subsea manifold to the topside production choke inlet
p
From the closest subsea manifold to the topside production choke inlet
90
100
110
bara
] E. Zakarian & D. LarreyPaper IPTC 11379 P60
Average error
60
70
80
90
ure
Dro
p [b
P10
Dubai - Dec. 2007
P40
P50
40
50
60
ulat
ed P
ress P10
P20P30P40P50
P20
P30
10
20
30
Cal
cu P60+/- 10%+/- 20%
Production well tests Jan. 2005 - Aug. 2006 0% 10% 20% 30%
P10
U l d i
Multiphase Technology 2008
10 20 30 40 50 60 70 80 90 100 110
Measured Pressure Drop [bara]
Usual design margin (10%)
Field stability testsyThe hydraulic stability of two production flowlines
l t t d i 2004was purposely tested in 2004To collect relevant data for gas-lift optimisation
B th i d d d d l i fl liBoth in upward and downward sloping flowlinesThrough connection to a test separator for an accuratemeasurement of phase flow rates
To achieve relevant flowing conditions for analysisStep-by-step turn-down of the gas-lift rateStep-by-step riser-head choking to keep constant back-pressureFixed wellhead choke opening
Multiphase Technology 2008
Fixed wellhead choke opening
P50 loop stability test
130 190130 190
p yFlow is unstable at gas-lift rate between 100 and 70 kSm3/d
120
125
130
170
190
G
Gas-lift rate
120
125
130
170
190
G
Gas-lift rateOscillation time period ~ 3h
105
110
115
e [b
arg]
130
150
Gas-lift ra
105
110
115
e [b
arg]
130
150
Gas-lift ra35 bar
95
100
105
Pres
sure
90
110
te [kSm3/95
100
105
Pres
sure
90
110
te [kSm3/
85
9070
90 /d]Flowline pressure at subsea manifold M501
85
9070
90 /d]Flowline pressure at subsea manifold M501
Riser induced
Multiphase Technology 2008
8013-mai-04 5:16 13-mai-04 17:16 14-mai-04 5:16 14-mai-04 17:16 15-mai-04 5:16
508013-mai-04 5:16 13-mai-04 17:16 14-mai-04 5:16 14-mai-04 17:16 15-mai-04 5:16
50Riser-induced slugging
P50 loop stability testp y
50 50P5011 wellhead choke
opening50 50P5011 wellhead choke
opening
45 40
45
C
opening
P t t id45 40
45
C
opening
P t t id
40
e [b
arg]
25
30
35
Choke ope
Pressure at topside riser head choke inlet
40
e [b
arg]
25
30
35
Choke ope
Pressure at topside riser head choke inlet
35
Pres
sur
15
20
25 ening [%]
35
Pres
sur
15
20
25 ening [%]
25
30
0
5
10Topsides riser head
choke opening25
30
0
5
10Topsides riser head
choke opening
Multiphase Technology 2008
2513-mai-04 5:16 13-mai-04 17:16 14-mai-04 5:16 14-mai-04 17:16 15-mai-04 5:16
02513-mai-04 5:16 13-mai-04 17:16 14-mai-04 5:16 14-mai-04 17:16 15-mai-04 5:16
0
Dynamic simulation with OLGA®yCalculated pressure at closest manifold
Q =3146 Sm3/d - GOR=102 Sm3/Sm3 - Water cut=53% - P =37 barg
124
]
Gas-lift rate = 70 kSm3/d
Gas lift rate = 80 kSm3/d
124
]
Gas-lift rate = 70 kSm3/d
Gas lift rate = 80 kSm3/d
QLiq=3146 Sm /d - GOR=102 Sm /Sm - Water cut=53% - Pout=37 barg
1 h
120
122
M50
1 [b
ara] Gas-lift rate = 80 kSm3/d
120
122
M50
1 [b
ara] Gas-lift rate = 80 kSm3/d
6 bar Oscillation
116
118
at m
anifo
ld M
116
118
at m
anifo
ld M6 bar Oscillation
time period~ 8 min.
112
114
Pres
sure
112
114
Pres
sure
Multiphase Technology 2008
110
Gas-lift rate = 90 kSm3/dGas-lift rate = 100 kSm3/d
110
Gas-lift rate = 90 kSm3/dGas-lift rate = 100 kSm3/d
Model extension to the wellbore Calculated pressure at closest manifold
Q =3146 Sm3/d - GOR=102 Sm3/Sm3 - Water cut=53% - P =37 barg
124
a]
Gas-lift rate = 70 kSm3/d124
a]
Gas-lift rate = 70 kSm3/d
QLiq=3146 Sm /d - GOR=102 Sm /Sm - Water cut=53% - Pout=37 barg
1 h
120
122
d M
501
[bar
a Gas-lift rate = 80 kSm3/d
120
122
d M
501
[bar
a Gas-lift rate = 80 kSm3/d
8 bar Oscillation
116
118
e at
man
ifold
116
118
e at
man
ifold8 bar Oscillation
time period~ 45 min.
112
114
Pres
sure
112
114
Pres
sure
Multiphase Technology 2008
110Gas-lift rate = 90 kSm3/dGas-lift rate = 100 kSm3/d
110Gas-lift rate = 90 kSm3/dGas-lift rate = 100 kSm3/d
Gas-lift modelling gCalculated pressure at closest manifold
Q =3146 Sm3/d - GOR=102 Sm3/Sm3 - Water cut=53% - P =37 barg
122
124
ra]
QLiq=3146 Sm /d - GOR=102 Sm /Sm - Water cut=53% - Pout=37 barg
1 h
118
120
122
fold
M50
1 [b
ara
8 bar Gas-lift rate70 kS 3/d
114
116
118
ssur
e at
man
if 70 kSm3/d
No instability
110
112
Pres
Mass source at riser base & manifoldGas-lift line & mass source at manifold
No instability with mass sources!
Multiphase Technology 2008
0 1 2 3
Time [h]
Gas-lift line & mass source at manifoldWellbore & mass source at riser baseWellbore & gas-lift line
P10 loop stability test
136
p y
0 5 h
Hydrodynamic/terrain slugging
133
134
135
136
ssur
e [b
arg]
Flow is unstable at minimumgas-lift rate (50 kSm3/d)
0.5 h
138
139
140
250
300
131
132
3-juin-0419:12
3-juin-0419:40
3-juin-0420:09
3-juin-0420:38
3-juin-0421:07
3-juin-0421:36
Pres
Time delay ~ 2 h
135
136
137
ssur
e [b
arg]
150
200
Gas-lift rate [kS
Flowline pressure at subsea manifold M102
Time delay ~ 2 h
131
132
133
134
Pres
50
100
Sm3/d] 4 bar
Multiphase Technology 2008
1303-Jun-04
0:003-Jun-04
2:243-Jun-04
4:483-Jun-04
7:123-Jun-04
9:363-Jun-04
12:003-Jun-04
14:243-Jun-04
16:483-Jun-04
19:123-Jun-04
21:364-Jun-04
0:00
0Gas-lift rate
P10 loop stability test55 31
T id i h d
p y
45
50
g]
29.5
30
30.5
Riser c
Topside riser head choke opening
35
40
ress
ure
[bar
g
28.5
29
choke openin
25
30
P
27
27.5
28
ng [%]Pressure at topside
riser head choke inlet
Opening of the wellhead chokes was kept constant
203-Jun-04
0:003-Jun-04
2:243-Jun-04
4:483-Jun-04
7:123-Jun-04
9:363-Jun-04
12:003-Jun-04
14:243-Jun-04
16:483-Jun-04
19:123-Jun-04
21:364-Jun-04
0:00
26.5
Multiphase Technology 2008
Opening of the wellhead chokes was kept constant during the whole test (80%)
Dynamic simulation with OLGA®yMeasured pressure at 2nd manifold
Gas-lift rate = 50 kSm3/d
134
135
136
137
138
134
135
136
137
138
134
135
136
137
138
arg]
130
131
132
133
134
130
131
132
133
134
130
131
132
133
134
Pres
sure
[b
Calculated pressure Calculated pressure Calculated pressure 128
129
3-juin-0419:12
3-juin-0419:40
3-juin-0420:09
3-juin-0420:38
3-juin-0421:07
3-juin-0421:36
128
129
3-juin-0419:12
3-juin-0419:40
3-juin-0420:09
3-juin-0420:38
3-juin-0421:07
3-juin-0421:36
128
129
3-juin-0419:12
3-juin-0419:40
3-juin-0420:09
3-juin-0420:38
3-juin-0421:07
3-juin-0421:36
pGL rate = 40 kSm3/d
Sl T ki ti i i d t di t h d li i t bilit
pGL rate = 20 kSm3/d
pGL rate = 30 kSm3/d
Slug Tracking option is required to predict hydraulic instabilityInstability is predicted at a gas-lift rate between 40 and 30 kSm3/dResults are consistent with a recent on-site investigation:
Multiphase Technology 2008
gmeasurement uncertainty on the minimum gas-lift rate can be 30%
Flow stability vs. liquid flow ratey qCalculated pressure at 2nd manifold
Gas-lift rate=50 kSm3/d - GOR=103 Sm3/Sm3 - Water cut=43% - P =35 bargGas-lift rate=50 kSm /d - GOR=103 Sm /Sm - Water cut=43% - Pout=35 barg
150
160
[bar
a] Minimum pressure at manifold M102 [bara]
Maximum pressure at manifold M102 [bara]
130
140
fold
at M
102
Hydrodynamic slug growth?
V ll t l (BHRG 2005)
110
120
130
sure
at m
anif
Measured stability limit
Valle et al. (BHRG 2005)
100
110
0 2000 4000 6000 8000 10000
Pres
s
T i /h d d i
5404 Sm3/d
Multiphase Technology 2008
Liquid flow rate [Sm3/d]Terrain/hydrodynamic slugging
Conclusions
In Girassol the nature of multiphase flow instabilitiesIn Girassol, the nature of multiphase flow instabilities is strongly dependent on the geometrical profile of
the flowline laid on the seabed
In downward sloping flowlinesFlow is prone to riser-induced sluggingp gg g
In upward sloping flowlinesFlow is prone to hydrodynamic/terrain sluggingp y y gg gHydrodynamic slug growth seems possible at high flow rates although never observed
Multiphase Technology 2008
Conclusions
In downward sloping flowlines, instabilities areIn 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 flowlinesA significant time delay is required to reach fully developed flow or to achieve stabilizationdeveloped flow or to achieve stabilizationAn increase of the gas-lift rate can be detrimental to flow stability (see paper)
Multiphase Technology 2008
ConclusionsInstability onset with decreasing gas-lift rate is well predicted with OLGA® despite a poor prediction ofpredicted with OLGA despite a poor prediction of pressure oscillations (using default modelling settings)
Gas-lift line modelling and extension to the wellboreare recommended to catch flow instabilities in downward sloping flowlinesp g
Use of Slug Tracking is mandatory to capture hydrodynamic/terrain-slugging instabilities in
d l i fl liupward sloping flowlines
Pressure drop calculation: the usual 10% minimum design margin can be applied to deepwater oil
Multiphase Technology 2008
design margin can be applied to deepwater oil production system such as Girassol
Analysis of Multiphase Flow Instabilities in the y pGirassol Deep Offshore Production System
Erich Zakarian & Dominique LarreyTotal E&P, Process Department, France
[email protected]@total.com
Multiphase Technology 2008
Back-up slidesp
Multiphase Technology 2008
Minimum gas-lift rateg
EXAMPLE 1
P10 loop, QLiq=3000 bbl/d, GOR=500, WC=0%
Mi i G Lift t 30 kS 3/d (NO Sl T ki )Minimum Gas-Lift rate = 30 kSm3/d (NO Slug Tracking)
Minimum Gas-Lift rate = 70 kSm3/d (WITH Slug Tracking)
EXAMPLE 2
P10 loop, QLiq=20,000 bbl/d, GOR=200, WC=60%p, Liq , , ,
Minimum Gas-Lift rate = 10 kSm3/d (NO Slug Tracking)
Mi i G Lift t > 150 kS 3/d (WITH Sl T ki )
Multiphase Technology 2008
Minimum Gas-Lift rate > 150 kSm3/d (WITH Slug Tracking)
First example of instability (1/2)p y ( )Riser-induced slugging (P30 loop, Oct 28th 2005)
110
115
120
80
90
100
Gas-lift rate110
115
120
80
90
100
Gas-lift rate
100
105
e [b
arg]
60
70
Gas-lift rat
100
105
e [b
arg]
60
70
Gas-lift rat
85
90
95
Pres
sure
30
40
50
te [kSm3/d]85
90
95
Pres
sure
30
40
50
te [kSm3/d]
35 barOscillation
70
75
80
0
10
20
Flowline pressure at subsea manifold M301
70
75
80
0
10
20
Flowline pressure at subsea manifold M301
Oscillation time period~ 50 min.
Multiphase Technology 2008
7028-Oct-05
16:4828-Oct-05
19:1228-Oct-05
21:3629-Oct-05
0:0029-Oct-05
2:2429-Oct-05
4:4829-Oct-05
7:1229-Oct-05
9:36
07028-Oct-05
16:4828-Oct-05
19:1228-Oct-05
21:3629-Oct-05
0:0029-Oct-05
2:2429-Oct-05
4:4829-Oct-05
7:1229-Oct-05
9:36
0
First example of instability (2/2)p y ( )Riser-induced slugging (P30 loop, Oct 28th 2005)
50
55
60
35
40
Pre
P3012 wellhead choke opening
50
55
60
35
40
Pre
P3012 wellhead choke opening
40
45
50
ning
[%]
20
25
30
essure drop a
Topside riser head choke opening
Pressure drop across topside riser head choke
40
45
50
ning
[%]
20
25
30
essure drop a
Topside riser head choke opening
Pressure drop across topside riser head choke
25
30
35
Cho
ke o
pen
10
15
across choke
topside riser head choke
25
30
35
Cho
ke o
pen
10
15
across choke
topside riser head choke
10
15
20
-5
0
5
[bar]
Pressure drop across P3012 wellhead choke
10
15
20
-5
0
5
[bar]
Pressure drop across P3012 wellhead choke
Multiphase Technology 2008
28-oct-0516:48
28-oct-0519:12
28-oct-0521:36
29-oct-050:00
29-oct-052:24
29-oct-054:48
29-oct-057:12
29-oct-059:36
28-oct-0516:48
28-oct-0519:12
28-oct-0521:36
29-oct-050:00
29-oct-052:24
29-oct-054:48
29-oct-057:12
29-oct-059:36
2nd example of instability (1/2)
129130129130
p y ( )
Hydrodynamic/terrain slugging
122123124125126127128
Pres
sure
[bar
g]
122123124125126127128
Pres
sure
[bar
g]
Hydrodynamic/terrain slugging P10 loop, Feb 27th 2005
Time delay 9 h
128
129
130
250
300
G
Gas-lift rate
120121
27-Feb-054:48
27-Feb-055:16
27-Feb-055:45
27-Feb-056:14
27-Feb-056:43
27-Feb-057:12
128
129
130
250
300
G
Gas-lift rate
120121
27-Feb-054:48
27-Feb-055:16
27-Feb-055:45
27-Feb-056:14
27-Feb-056:43
27-Feb-057:12
Time delay ~ 9 h
4 bar 124
125
126
127
ress
ure
[bar
g]
150
200
Gas-lift rate [kSm124
125
126
127
ress
ure
[bar
g]
150
200
Gas-lift rate [kSm
Oscillation time period4 bar
121
122
123
Pr
50
100
m3/d]
Flowline pressure at subsea manifold M101
121
122
123
Pr
50
100
m3/d]
Flowline pressure at subsea manifold M101
time period ~ 15 min.
Multiphase Technology 2008
12026-Feb-05
14:2426-Feb-05
16:4826-Feb-05
19:1226-Feb-05
21:3627-Feb-05
0:0027-Feb-05
2:2427-Feb-05
4:4827-Feb-05
7:1227-Feb-05
9:3627-Feb-05
12:0027-Feb-05
14:24
0subsea manifold M101
12026-Feb-05
14:2426-Feb-05
16:4826-Feb-05
19:1226-Feb-05
21:3627-Feb-05
0:0027-Feb-05
2:2427-Feb-05
4:4827-Feb-05
7:1227-Feb-05
9:3627-Feb-05
12:0027-Feb-05
14:24
0subsea manifold M101
2nd example of instability (2/2)p y ( )Hydrodynamic/terrain slugging (P10 loop, Feb 27th 2005)
80
90
16
18
20
Pres
P1022 & P1031 wellhead choke opening
80
90
16
18
20
Pres
P1022 & P1031 wellhead choke opening
70
ning
[%]
12
14
ssure drop a
Pressure drop across topside riser head choke70
ning
[%]
12
14
ssure drop a
Pressure drop across topside riser head choke
50
60
Cho
ke o
pen
6
8
10
across choke Topside riser head50
60
Cho
ke o
pen
6
8
10
across choke Topside riser head
40
2
4
[bar]
Topside riser headchoke opening
40
2
4
[bar]
Topside riser headchoke opening
Multiphase Technology 2008
3026-févr-05
14:2426-févr-05
16:4826-févr-05
19:1226-févr-05
21:3627-févr-05
0:0027-févr-05
2:2427-févr-05
4:4827-févr-05
7:1227-févr-05
9:3627-févr-05
12:0027-févr-05
14:24
03026-févr-05
14:2426-févr-05
16:4826-févr-05
19:1226-févr-05
21:3627-févr-05
0:0027-févr-05
2:2427-févr-05
4:4827-févr-05
7:1227-févr-05
9:3627-févr-05
12:0027-févr-05
14:24
0
Field validation: GOR
1 9
2.0
1.6
1.7
1.8
1.9
red
DP
1 2
1.3
1.4
1.5
DP
/ Mea
sur
0.9
1.0
1.1
1.2
Pred
icte
d D
0.6
0.7
0.8
0.9P
Multiphase Technology 2008
100 1000 10000
Gas Oil Ratio [Sm3/m3]
Field validation: water cut
1.9
2.0
1.6
1.7
1.8
red
DP
1 2
1.3
1.4
1.5
DP
/ Mea
sur
0.9
1.0
1.1
1.2
Pred
icte
d D
0.6
0.7
0.8
Multiphase Technology 2008
0 10 20 30 40 50 60 70 80 90 100Water cut [%]
Field validation: gas-lift rateg
1.9
2.0
1.6
1.7
1.8
red
DP
1 2
1.3
1.4
1.5
DP
/ Mea
sur
0.9
1.0
1.1
1.2
Pred
icte
d D
0.6
0.7
0.8
P
Multiphase Technology 2008
0 50000 100000 150000 200000 250000 300000
Gas-lift Rate [Sm3/d]
Field validation: temperature
70
pMeasured temperature at riser production choke inlet vs. OLGA®
50
55
60
65re
[°C
]Production well tests Jan. 2005 - Aug. 2006
30
35
40
45
50
late
d Te
mpe
ratu
P10
P20
P30
P40
15
20
25
30
Cal
cul P40
P50
P60
+/- 10%
+/- 20%
1010 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-valuesf
Multiphase Technology 2008
This study focuses primarily on hydraulic issues such as pressure drop and flow instabilities
Field validation4.0
m/s
]
Selected well tests
3.0
3.5
ser B
ase
[m Selected well testsUnstable well tests (large pressure oscillation)Unstable well tests (OLGA)
2.0
2.5
ocity
at R
is
1.0
1.5
perfi
cial
Vel
0.0
0.5
0 2 4 6 8 10
Oil
Sup
Multiphase Technology 2008
Gas Superficial Velocity at Riser Base [m/s]
Field validation4.0
m/s
]
Selected well tests
3.0
3.5
ser B
ase
[m
Selected well testsUnstable well tests (large pressure oscillation)Unstable well tests (OLGA)
2.0
2.5
eloc
ity a
t Ris
1.0
1.5
perf
icia
l Ve
0.0
0.5
0 2 4 6 8 10
Wat
er S
u
Multiphase Technology 2008
0 2 4 6 8 10Gas Superficial Velocity at Riser Base [m/s]
Flow stability vs. liquid flow ratey qCalculated pressure
t li id t 6000 S 3/dCalculated pressure
t li id t 5000 S 3/d
140
145
150
at liquid rate = 6000 Sm3/d at liquid rate = 5000 Sm3/d
130
135
140
[bar
a]
115
120
125
Pres
sure
100
105
110
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5C l l t d
Multiphase Technology 2008
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5
Time [h]Calculated pressure
at liquid rate = 2000 Sm3/d