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Shtokman: the Management of Flow    Assurance Constraints in Remote          Arctic EnvironmentErich Zakarian 1, Henning H...
Contents• The Shtokman field• Shtokman Development AG• Offshore challenges• Field development - Phase 1 - FEED  • Offshore...
The Shtokman field• Two main sandstone reservoirs: J0 & J1• Sweet & lean gas                                              ...
Shtokman Development AG• Special-purpose company for the integrated development ofthe Shtokman gas-condensate field - Phas...
Offshore challenges• Sensitive ecosystem     preserve the environment• Extreme weather conditions      winterization• Ice ...
Field development - Phase 1Front End Engineering and Design      Offshore facilities
Flow Assurance risk identification • Hydrate & ice formation    • Gas is saturated with water at reservoir conditions    •...
Flow Assurance risk management  Infield subsea production system
Hydrate & ice management                      250                                                           J0     J1Hydra...
MEG loop design• Subsea MEG injection   • Required MEG concentration in produced water = 60 wt% (rich MEG)   • Injection r...
Corrosion and scale management• Injection of film forming corrosion inhibitor at wellhead   • Commingled with regenerated ...
Sand and solids free erosion-corrosion• Sand control   • Lower well completion includes open hole gravel pack and sand scr...
Liquid management• Liquid holdup     • Despite the roughness of the seabed, liquid accumulation in flowlines is       mini...
Flow Assurance risk management      Fluid transfer to shore
Trunklines to shore        Gas is commingled with condensate      after dehydration and exported to shore                v...
Trunkline profile                             ‐265                                              ‐270                      ...
Pipeline profile discretization • Two discretization methods were specially designed during FEED • Essential characteristi...
Liquid management• Onshore finger-type slug catcher   • Total condensate buffer capacity = 2500 m3   • Designed for safe t...
Hydrate and corrosion management• Fluid dehydration   • To avoid the presence of free water and the need for chemical inhi...
Conclusions• The development of remote gas resources in the Arctic willrequire specific engineering• A robust design is pr...
Wgc 2009 shtokman flow assurance rev07_no_backup
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Shtokman: the Management of Flow Assurance Constraints in Remote Arctic Environment

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Wgc 2009 shtokman flow assurance rev07_no_backup

  1. 1. Shtokman: the Management of Flow Assurance Constraints in Remote Arctic EnvironmentErich Zakarian 1, Henning Holm 1, Pratik Saha 1, Victoria Lisitskaya 1 Vladimir Suleymanov 2 1 Shtokman Development AG, Russia 2 Gazprom VNIIGAZ, Russia
  2. 2. Contents• The Shtokman field• Shtokman Development AG• Offshore challenges• Field development - Phase 1 - FEED • Offshore facilities• Flow Assurance • Risk identification & management• Conclusions
  3. 3. The Shtokman field• Two main sandstone reservoirs: J0 & J1• Sweet & lean gas km• 3.8 trillion Sm3 of natural gas (130 TCF) 0 65• 37 million tons of condensate • Water depth ~ 340 m • Rough seabed • Harsh metocean conditions • Possible packed ice and icebergs • Min. air temperature: -15°C / -38°C • Min. seabed temperature: -1.8°C
  4. 4. Shtokman Development AG• Special-purpose company for the integrated development ofthe Shtokman gas-condensate field - Phase 1• Joint venture between• Responsible for engineering, financing, construction andoperation of Phase 1 installations • Offshore facilities • Onshore processing plant (LNG + gas treatment)• Owner of infrastructures for 25 yearsAnnual production at wellhead = 23.7 billion Sm3 per year
  5. 5. Offshore challenges• Sensitive ecosystem preserve the environment• Extreme weather conditions winterization• Ice threats ice management & disconnection• Remoteness logistics constraints• Huge production capacity (~70 MSm3/sd)• Long-distance fluid transfer to shore
  6. 6. Field development - Phase 1Front End Engineering and Design Offshore facilities
  7. 7. Flow Assurance risk identification • Hydrate & ice formation • Gas is saturated with water at reservoir conditions • High reservoir pressure: approx. 200 bara in J0 and 240 bara in J1 • Low minimum ambient temperature: -1.8°C at seabed / -31°C onshore • Corrosion, salt precipitation and scaling • Corrosive agents (CO2, organic acids) and free water • Formation water could be produced beyond year 10 • Sand production and erosion-corrosion • Gas bearing sandstone reservoirs • High volume flow rates • Liquid accumulation and surges • Three-phase flow (gas, condensate, water) in infield flowlines • Dry two-phase flow (gas, condensate) in trunklines to shore
  8. 8. Flow Assurance risk management Infield subsea production system
  9. 9. Hydrate & ice management 250 J0 J1Hydrate dissociation curve 60 wt% MEG in water 200 Shut-in (freezing point < -50°C) conditions Pressure [bara] 150 100 Hydrate dissociation curve Raw natural gas 50 Infield subsea operating envelope 0 -30 -20 -10 0 10 20 30 40 50 60 Temperature [°C]
  10. 10. MEG loop design• Subsea MEG injection • Required MEG concentration in produced water = 60 wt% (rich MEG) • Injection rates include uncertainties from reservoir temperature, water saturation, MEG quality, flow measurement and distribution control• Topside MEG regeneration • Rich MEG from subsea is regenerated at 90 wt% (lean MEG) • 85 wt% for the sizing of umbicals, injection pumps and chemical dosage valves (CDV) to take account of MEG regeneration difficulties• Salt management • Rich MEG pre-treatment for low solubility salt removal (carbonates) • Partial reclamation (40% slip stream) for high solubility salt removal (chlorides)
  11. 11. Corrosion and scale management• Injection of film forming corrosion inhibitor at wellhead • Commingled with regenerated MEG at topsides• Injection of pH stabilizer at wellhead • Possible for adjustment of the inhibition strategy• Injection of scale inhibitor at wellhead • Required at start-up of new wells (back-production of drilling and completion fluids) • Required at formation water breakthrough if residual presence of pH stabilizer• No risk of top of Line corrosion (TLC) • Water condensation rate at top of line below 0.25 g/m2/s • Small content of organic acids in condensed water (< 2 mmole/L)
  12. 12. Sand and solids free erosion-corrosion• Sand control • Lower well completion includes open hole gravel pack and sand screens• Sand management and monitoring • Subsea choke modules are equipped with sand detector • Erosion & Momentum sensor at downstream of subsea chokes • Well choking or shut-in when sand production is detected (alarm levels) • Desanding system at MP separators• Droplet erosion and erosion-corrosion management • A maximum velocity is specified for each type of material Corrosion resistant alloys (CRA): 50 m/s Carbon steel (CS): Min (30 m/s, C/ρ1/2); ρ = fluid density; C =130 in US units • Actual velocities: 10-35 m/s in CRA; 10-20 m/s in CS
  13. 13. Liquid management• Liquid holdup • Despite the roughness of the seabed, liquid accumulation in flowlines is minimized by several factors: Low liquid loading High flowing velocities Short length of infield flowlines (~ 2 km) • Liquid holdup < 10 m3 in one flowline at the average flow rate of one well• Slug catcher • Adequate liquid surge capacity available within each inlet separator • Designed for safe transient operations (ramp-up, restart, pigging)
  14. 14. Flow Assurance risk management Fluid transfer to shore
  15. 15. Trunklines to shore Gas is commingled with condensate after dehydration and exported to shore via 2 x 36” trunklines• Dry two-phase flow Robust alternative to 3-phase flow Small impact on ΔP vs. 1-phase flow (very low liquid loading) No requirement for offshore condensate storage• Two trunklines Flexible fluid transfer to shore
  16. 16. Trunkline profile ‐265 ‐270 ‐275 200 ‐280 ‐285 100 50 51 52 53 54 55 56 57 58 59 60 Elevation [m] 0 -100 -200 -300 -400 0 100 200 300 400 500 Distance [km] • Detailed pipeline profile from seabed bathymetry survey (2008) • Free span analysis and seabed intervention taken into account 110,467 points
  17. 17. Pipeline profile discretization • Two discretization methods were specially designed during FEED • Essential characteristics of the original detailed pipeline profile are conserved: Length + Topography + Angle distribution + Total climb • The hydrodynamic behavior of the original profile is conserved despite significant data compression (2,500 points) • Both methods are generic and can be applied to other developments For more info: E. Zakarian, H. Holm and D. Larrey (2009), Discretization Methods for Multiphase Flow Simulation of Ultra-Long Gas-Condensate Pipelines, 14th International Conference on Multiphase Production Technology, Cannes, France, 16-19 June 2009
  18. 18. Liquid management• Onshore finger-type slug catcher • Total condensate buffer capacity = 2500 m3 • Designed for safe transient operations (ramp-up, restart, pigging)• Operating philosophy • The produced condensate is preferably allocated to the trunkline with the maximum throughput• Pipeline management system (PMS) • After first gas, operating procedures will be adjusted with the support from multiphase dynamic simulation
  19. 19. Hydrate and corrosion management• Fluid dehydration • To avoid the presence of free water and the need for chemical inhibitors• Ambient conditions • Offshore: sea temperature is about -1.8°C in winter (1°C in summer) • Onshore: minimum air temperature can be very low: -31°C• Insulation? • Offshore: NO to maintain fluid temperature close to ambient temperature • Onshore: YES to provide robust pipeline insulation and protection• Dehydration specification • Stringent specs for potential upset in condensate dehydration process • Gas: 5 ppm vol water • Condensate: 100 ppm vol water
  20. 20. Conclusions• The development of remote gas resources in the Arctic willrequire specific engineering• A robust design is proposed to manage Flow Assurancerisks in the 1st development phase of the Shtokman field• This work can serve as a reference for the development ofother remote resources in the Arctic

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