Girassol field experience (OLGA UGM Paris, 2008)

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Analysis of Multiphase Flow
Instabilities in the Girassol Deep
Offshore Production System

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Girassol field experience (OLGA UGM Paris, 2008)

  1. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 23. Back-up slides p Multiphase Technology 2008
  24. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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

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