Shtokman: the Management of Flow Assurance Constraints in Remote Arctic Environment

1. Shtokman: the Management of Flow
Assurance Constraints in Remote
Arctic Environment
Erich Zakarian 1, Henning Holm 1, Pratik Saha 1, Victoria Lisitskaya 1
Vladimir Suleymanov 2
1 Shtokman Development AG, Russia
2 Gazprom VNIIGAZ, Russia

2. Contents
• The Shtokman field
• Shtokman Development AG
• Offshore challenges
• Field development - Phase 1 - FEED
• Offshore facilities
• Flow Assurance
• Risk identification & management
• Conclusions

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. Shtokman Development AG
• Special-purpose company for the integrated development of
the Shtokman gas-condensate field - Phase 1
• Joint venture between
• Responsible for engineering, financing, construction and
operation of Phase 1 installations
• Offshore facilities
• Onshore processing plant (LNG + gas treatment)
• Owner of infrastructures for 25 years
Annual production at wellhead = 23.7 billion Sm3 per year

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. Field development - Phase 1
Front End Engineering and Design
Offshore facilities

8. 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

9. Flow Assurance risk management
Infield subsea production system

10. Hydrate & ice management
250
J0 J1
Hydrate 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]

11. 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)

12. 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)

13. 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

14. 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)

15. Flow Assurance risk management
Fluid transfer to shore

16. 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

17. 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

18. 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

19. 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

20. 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

21. Conclusions
• The development of remote gas resources in the Arctic will
require specific engineering
• A robust design is proposed to manage Flow Assurance
risks in the 1st development phase of the Shtokman field
• This work can serve as a reference for the development of
other remote resources in the Arctic