Wgc 2009 shtokman flow assurance rev07_no_backup

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, Russia2 Gazprom VNIIGAZ, Russia

Contents• The Shtokman field• Shtokman Development AG• Offshore challenges • Field development - Phase 1 - FEED

• Offshore facilities

• Flow Assurance• Risk identification & management

• Conclusions

The Shtokman field• Two main sandstone reservoirs: J0 & J1• Sweet & lean gas• 3.8 trillion Sm3 of natural gas (130 TCF)• 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

650 k

m

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

• 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

Offshore challenges

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• 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

Flow Assurance risk managementInfield subsea production system

0

50

100

150

200

250

-30 -20 -10 0 10 20 30 40 50 60

Pres

sure

[bar

a]

Temperature [°C]

Hydrate & ice management

Infield subsea operating envelope

J1J0

Hydrate dissociation curveRaw natural gas

Hydrate dissociation curve60 wt% MEG in water

(freezing point < -50°C) Shut-in conditions

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)

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)

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/sCarbon 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

Liquid management• Liquid holdup

• Despite the roughness of the seabed, liquid accumulation in flowlines is minimized by several factors:

Low liquid loadingHigh flowing velocitiesShort 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)

Flow Assurance risk managementFluid transfer to shore

Trunklines to shore

• Dry two-phase flow Robust alternative to 3-phase flowSmall impact on ΔP vs. 1-phase flow (very low liquid loading) No requirement for offshore condensate storage

• Two trunklines Flexible fluid transfer to shore

Gas is commingled with condensate after dehydration and exported to shore

via 2 x 36” trunklines

• Detailed pipeline profile from seabed bathymetry survey (2008)• Free span analysis and seabed intervention taken into account

110,467 points

-400

-300

-200

-100

0

100

200

0 100 200 300 400 500Distance [km]

Elev

atio

n [m

]

Trunkline profile‐285

‐280

‐275

‐270

‐265

50 51 52 53 54 55 56 57 58 59 60

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

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

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

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