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Marine Pipelines - Hydraulics 3a

Ormen Lange Flowlines - Start-up and Operation

Gert van Spronsen - Pipelines

Shell Global Solutions International (SGSI) - Rijswijk

Email : Gert.vanSpronsen@shell.com Tel : +31 70 447 3427

2009 Shell Global Solutions International B.V. All rights reserved. Do not distribute without consent of copyright owner

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Ormen Lange Location West of Norway

Subsea to beach gas & condensate 850 m water depth,

120 km to onshore plant at Nyhamna

Irregular topography, steep inclines

Sub-zero sea bed temp. 1.7 C

Recoverable reserves 400 billion sm3 dry gas

30 million m3 condensate

Export capacity 70 Msm3/d gas- 2.5 Bscf/d

Export pipeline to UK 1200km- Langeled - Worlds longest

20% of the UK supply at peak

Start-up September 2007

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Ormen Lange Offshore. Initial DevelopmentOnshore facilities Slugcatchers (2x1500 m3) Gas backflow and circulation MEG regeneration facilities Pipeline monitoring system MEG injection control and monitoring system

Ormen Lange

Flow Assurance

2x6 MEG injection lines Redundancy

Manifolds with dual headers Wells may be routed to either

of the two manifolds

Pigging loop

Subsea chokes Balance/control well production Control slugcatcher pressure

Subsea MEG distribution system MEG dosage unit Wet gas metering Formation water detection

2x30 multiphase production pipelines Turndown and swing flexibility Reduced slug volumes Increased availability

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Ormen Lange Subsea Layout

Towa

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MULTIPHASE PRODUCTION LINEMEG LINEUMBILICAL

MULTIPHASE PRODUCTION LINEMEG LINEUMBILICAL

In-line Tees

20 spools

Pigging loop

NN

AA BB

HUBS for future

hot-tap tees

HUBS for future

hot-tap tees

HUBS for future

hot-tap tees

HUBS for future

hot-tap tees

30 PLET30 PLET

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Wells & Subsea Data

Wells: Upto 24, Max. well production 10 MSm3/day (350 Mscf/d)

Templates: 2 x 8-slot templates (initial)

Production flowlines: 2 x 30, 120 km multiphase flowlines

Umbilical: 2 hydraulic-electrical umbilical

Slug catchers: 2 x 1500 m3 surge capacity 1 slug catcher associated with each 30 flowline

MEG delivery lines: 2 x 6, 120 km

Valving and instrumentation: 6-position MEG Dosage Valve

Wet Gas Meter and MEG flow meter

Template branch valves allow fluid to Pipeline A or B

Several sets of temperature & pressure sensors

200-position production choke valve

StoreggaSlide

Uneven Seabed Topography

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Pre Start-up Dewatering & Gas Filling

Sleipner gas (via Langeled) to drive pig train Pigs:- into A-line subsea loop out of B-line

Non-stop pigging at ~ 0.8 m/s 4 cleaning pigs & 5 dewatering pigs Pigging achieved:

Remove water from the flowlines

Remove seawater salts

Remove solid corrosion products

4 cleaning pigs before dewatering train 2 km filtered & treated sea water 5 pigs in dewatering train

100 m3 freshwater pig 1-2

3 x 50 m3 MEG pigs 2-3-4-5

Water discharge at Nyhamna Fine black solids returned

Bi-directional cleaning pigs Dewatering pigs from B flowline8

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Pre Start-up MEG Injection & Distribution

MEG into 2 x 30 lines hydrate inhibition flowline A 1,500 m3 MEG from onshore

flowline B 2,500 m3 MEG via well injection

Commissioning procedure: Sleipner gas 15 Msm3/d (High velocity recirculation)

MEG return time onshore - 32 hours (expectation)

MEG volume injected - 7000 m3 (expectation)

Gas recirculation planned at 14.4 Msm3/d. Sleipner gas lighter actual rate only 11 Msm3/d

MEG injection continued at 850 m3/d

Start up experience: MEG to return onshore - 89 hours

MEG in the flowlines - 8100 m3

Challenges:

MEG hold up & distribution depend on gas

recirculation rate & sequence.

Sleipner gas was 3.4 Msm3/d less than reported Lower density of dry Sleipner gas

Gas compression trips unstable gas rate

Liquids flow back down inclined sections when

gas recirculation tripped delays in first gas

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MEG Arrival time: 12 September 2007 13:00

Start Gas Recirculation: 8 September 2007 20:00

First Gas: 13 September 2007 11:00

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MEG Injection & Distribution Key Findings

MEG hold up & distribution time

highly sensitive to recirculation gas rate

strongly effected by onshore compressor trips

MEG inventory tracking is essential

8100 m3 of MEG in the pipelines

Only 2.5 days MEG onshore at current injection rates

MEG volumes onshore to cater for uncertainty in pipeline hold-up

MEG properties for pure MEG or 90% MEG has a significant

impact on simulations results

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Ormen Lange First Gas 13 Sept 2007 at 11:00 start up of well A2

Wells A3 & A7 started up on the 14 Sept 2007

Liquid hold-up managed by Gas recirculation rate (kept above 23 Msm3/d)

Gas recirculation was stopped on 25 November 2007

Production rate reached 27 Msm3/d

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Export Gas RateTotal W ell Production

Stop Gas Recirculation:25/11/07

First Gas 13/9/07 11:00

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First Gas & Change in Liquid Hold-up

Discrepancy field data &

modelling

Model predicted MEG return earlier than experienced in the field

2000 m3 MEG return predicted by model before actual MEG return

Model adjustment

Simulation adjusted by 2000 m3 to allow comparison of predicted times and volumes

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Sep-12 Sep-19 Sep-26 Oct-03 Oct-10 Oct-17 Oct-24 Oct-31

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Estimated FieldData (corrected)

Olga Simulation

First Gas 13/9/07 11:00

MEG hold-up reduces quickly once gas production starts

MEG Liquid Inventory in Flowlines after Start-up (m3)

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Current Steady State Operation Pressure Drop v Gas Rate in 30" Flowlines

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Steady State Pressure Drop in Flowline ASC Pressure 90SC Pressure 100Steady State Pressure Drop in Flowline B

Liquid hold-up:

Flow Assurance System (FAS) Online, real time simulation of liquid hold-up condition in flowlines

Calculates hold-up of 2600 m3 at 27 Msm3/d gas, of this 1000 m3 is aqueous phase

Modelling predicted 1900 m3 total liquid hold-up for 27 Msm3/d gas

Higher actual hold-up aligns with higher pressure drop seen in the field

Pressure Drop:

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Successes & Lessons Learnt

What went well:

Robust system design is key for successful start up and managing FA risks: Dual production flowlines with pigging loop

Capacity for gas recirculation & redundancy in MEG injection system

On-site engineering support and use of modelling tools: Flow Assurance, Subsea and Process Engineers working onsite throughout start-up

Multi-phase modelling capability on site to predict operating conditions

Lessons Learnt:

Onshore plant trips impact on subsea commissioning and start-up

Need for float in commissioning schedules When relying on liquid returns from large multiphase system

Consider impact of unstable operating conditions!

Sensitivity of multi-phase calculations to fluid physical properties Pure MEG vs. 90% MEG (high concentration, high P, low T)

Large impact on hold up predictions

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Conclusions

A significant achievement for the project team and operations

Overall performance of Ormen Lange subsea systems and flowlines is excellent

System started up on time and without incident

No hydrate or liquid handling related problems

Versatile system design allows flexibility during start-up and operations

Adequate site team to monitor & advise on flowline ops contributed to success

Continuous multi-phase modelling to reflect the real operational conditions

allowed better decisions

Need for float in commissioning schedules when relying on liquid returns from

large multiphase subsea systems

Acknowledgements:

Norske Shell, Ormen Lange Operator & StatoilHydro, Project Team

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Shell Global Solutions is a network of independent technology companies in the Shell Group. In this presentation the expression 'Shell' or 'Shell Global Solutions' is sometimes used for convenience where reference is made to these companies in general, or where no useful purpose is served by identifying a particular company.