Girassol field experience (OLGA UGM Paris, 2008)

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


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


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


-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)


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!


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


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


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


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


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




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 = 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


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


124

a]

Gas-lift rate = 70 kSm3/d124

a]



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


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


122

124

ra]


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!


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


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


Opening of the wellhead chokes was kept constant during the whole test (80%)

Dynamic simulation with OLGA®yMeasured pressure at 2nd manifold


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



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:


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


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


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)


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


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


Back-up slidesp


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 )


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


70

75

80

0

10

20


Oscillation time period~ 50 min.


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


Pressure drop across topside riser head choke

40

45

50

ning

[%]

20

25

30

essure drop a



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


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]


121

122

123

Pr

50

100

m3/d]


time period ~ 15 min.


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


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


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


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


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


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


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


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


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


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

Girassol field experience (OLGA UGM Paris, 2008)

Documents

Transcript of Girassol field experience (OLGA UGM Paris, 2008)