Overview of Liwan 3-1 Deepwater
Subsea Tieback Gas
Development
Weiqiang Liu, Chief Engineer South China Sea Deep Water Gas Development PMT
CNOOC Limited
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CONTENTS
Introduction to Liwan 3-1 Deepwater Gas Development Selection of Deepwater Development Concepts Liwan 3-1 Development Progress Report
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The Geographical Location of LW3-1 Gas Field
Pan Yu 34-1/35-2/35-1 Water Depth 200-378m
Li Wan 3-1 Water Depth 1500m
Pan Yu 30-1 & Hui Zhou 21-1 (Existing) Water Depth 200m
Liu Hua 34-2 Future Tieback Water Depth 1146m
Liu Hua 29-1 Future Tieback Water Depth 720m
LW3-1 deepwater field subsea tieback to a shallow water central production platform; A large processing capacity reserved for future tieback developments in the vicinity.
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The Geographical Location of LW3-1 Gas Field
The Continental Shelf o Approximately 250km
distance from shore to the water depth of 200m, small slope;
o Less than 100km from the water depth of 200m to 1500m, deep slope.
Gas Resources o Li Wan 3-1 Deepwater Field o Pan Yu34-1/35-1/35-2 Shallow
Water Fields o Liu Hua 29-1/34-2 Deepwater
Fields o Short Tieback Distance
between all the fields above
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Introduction to Liwan 3-1 Gas Development
The Liwan 3-1 Gas Field located in South China Sea, the first deepwater development in China
CNOOC & Husky Production Sharing Contract (PSC) for Block 29/26 signed in 2004
The Gas Field discovered in 2006 and located approximately 310 km Southeast of Hong Kong
The subsea facilities lie in water depths ranging from 1,350 to 1,500 meters and subsea tie-back 79km to a shallow-water central production platform located in 189.5m water depth then further tieback 261km to an onshore gas plant
The deepwater subsea facilities operated by Husky China while the shallow water and onshore facilities operated by CNOOC
The First Gas Production targeted for 4th Quarter 2013 for Liwan 3-1 Gas Field and 3rd Quarter 2014 for Panyu 34-1/35-1/35-2 Gas Fields
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Potential Resources in the Vicinity of LW3-1 Field
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Phase Developments & Process Capacity
LW3-1 Subsea
LW3-1 Central Platform
PY35-1 Subsea
PY34-1 Central Platform
LH29-1 Future
LH34-2 Future
Operator - Husky
Operator - CNOOC
Facilities Design Process Capacity
LW3-1 Central
Platform
Phase 1 Process: 8.0 BCM/Year Boosting: 10.0BCM/Year
Phase 2 Process: 12.0 BCM/Year
Export Pipeline
Shallow Water
Export: 12.0 BCM/Year (BCM = Billions Cubic Meters)
Onshore Gas Plant
Phase 1 Process: 8.0 BCM/Year
Phase 2 Process: 12.0 BCM/Year
Future Process: 20.0 BCM/Year
Gaolan Onshore Terminal in Zhuhai
Operator-CNOOC
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Liwan 3-1 Subsea Tieback Gas Development
10 ×Subsea wells in water depth ranging from 1,350 to 1,500 meters 2×Manifolds and 1×PLEM 2 ×ø22” ×79 km Main Deepwater Flowlines and 79 km Subsea Umbilical & MEG Supply Line from PLEM to Platform 1 ×ø30” ×261km shallow-water export pipeline to onshore gas plant 1 ×Central Production Platform w/Separation, Gas Dehydration, Compression & MEG Systems, 200 Person Living Quarters, located in water depth of 189.5m 1 ×Onshore Gas Plant with an area of 1.45 millions m2 located at the Gaolan Island in Zhuhai next to Macao
West Manifold
Pipeline End Manifold (PLEM)
Central Platform (CEP)
Main Flowlines
East Manifold
Liuhua 34-2
Onshore Gas Plant
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PY34-1/35-1/35-2 Subsea Tieback Gas Development
The Pan Yu 34-1 Central Production Platform located in water depth of 190.2m 14ˮ×31.3 km shallow water subsea pipeline to receive mixed fluids consisting of dry gas and dewatering condensate from PY34-1 Platform Panyu 35-1 and 35-2 with 7 subsea wells tied back to PY34-1 Platform LW3-1 Platform receives and boost dry gas from PY34-1 Platform.
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Typical Deepwater Gas Development Scenarios in GOM
The Subsea Mensa Field in 1610m water depth tie-back 109km to a platform at West Delta 143 in 112m water depth; The Red Hawk Cell Spar in 1615m water depth tie-back 96km to Baldpate Platform, designed as a floating alternative to a long-distance tieback; The Canyon Express Fields, TLP Ram-Powell tieback to Platform Virgo, Neptune Spar & TLP Marlin tieback to Canyon Express Pipeline.
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Deepwater Development Scenarios for LW3-1 Gas Field
Scenario A: Spar/TLP/SEMI to Shallow Water Platform then export
to Onshore Gas Plant
Scenario B: Subsea Facilities tieback to Shallow Water Platform
then export to Onshore Gas Plant
Scenario C: Spar/TLP/SEMI directly export to Onshore Gas Plant
Scenario D: Subsea Facilities directly tie-back to Onshore Gas
Plant
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Criteria for Selection of Scenarios
Gas Sale Market and Production Rate
Location Selection for Shallow Water Platform
Location Selection for Onshore Gas Plant
Flow Assurance from Subsea Wells to Surface Facilities
Investment and Development Schedule
Future Developments in the vicinity
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Options of Floating Production Units (FPU)
TLP –Tension Leg Platform
SEMI – Semisubmersible Platform
Spar – Deep Draft Caisson Vessel
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Main Driving Factors for LW3-1 Gas Development
Avoid a long distance tie back, therefore subsea tieback to a shallow water platform Use mature and reliable technology of subsea facilities and shallow water jacket platform A short development period about 3 years An easy tieback to future developments of the gas fields in the vicinity.
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Final Selection of Liwan 3-1 Subsea Tieback Gas Development
LW 3-1 Field: 10×Subsea Wells, 1×PLEM, 2×Manifolds, etc. Central Production Platform: o Located in Water Depth of 190m; o Phase I: 8.0 billion m3/a o Phase II: 12.0 billion m3/a
Deepwater Tieback: o 2×22” ×79km main flowlines o 1×7” ×79km umbilical o 1×6” ×79km MEG supply line
Shallow Water Export: o 1×30”×261km export line o 12.0 billion m3/a including future
developments
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Gaolan Onshore Gas Plant Under Construction
Mechanical Completion: September 2013 Commissioning with Gas: October 2013 Gas Commercial Sale: End of 2013
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Gaolan Onshore Gas Plant Under Construction
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Anchorage
Gas Processing Area / Spherical Tanks Main Process Area
Condensate (30,000m3) / Firewater Tanks (10,000m3)
Slug Catcher (175m x 85m); 7,000m3
Jetty (415m Long) Seawall (1km) Enclosing EL+6.0m Platform
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Completion of Laying ø30×261km Shallow Water Export Pipeline
COOEC’s Shallow Water Pipe-Lay Vessel HYSY202
Global’s Newbuilt Shallow Water Pipe-Lay Vessel G1201
Slope Section at Gaolan Landfall at EL+50m Platform
Normand Clough to Complete SSIV and SP on Jul 28, 2013
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Marine Spread for Deepwater Pipelay & Construction
FDS2 to lay 2nd 22” Main Flowline, CRA Infield Lines. PLEM, Manifolds, etc.
HYSY 201 to lay 6” MEG Line
Normand Cutter to Lay Umbilical, Jumpers, Flying Leads, etc.
Normand Baltic to Perform Pipeline Testing & Commissioning, etc.
FDS1 to lay 1st 22” Main Flowline & CRA Infield Lines, etc.
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32,000Te LW3-1 CEP Jacket Construction & Installation
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Anchorage
Jacket Fabrication from Dec 2010 to Jul 2012
HYSY229 w/ CEP Jacket Sailaway July 27, 2012 Jacket Launch August 30, 2012
Loadout onto T-Shaped Launch Barge HYSY229 July 18, 2012
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Anchorage
26,000Te LW3-1 CEP Topsides Construction & Floatover Installation with 4,888Te Deck Support Frame (DSF)
Topsides Fabrication from Jun 2011 to April 2013
HYSY229 w/ CEP Topsides Sailaway on May 5, 2013 The Most Challenging Floatover Installation May 23, 2013
Loadout onto T-Shaped Launch Barge HYSY229 April 10, 2013
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Concluding Remark
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Anchorage
OSHA incident rate: 0.042
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Near Miss
6341
Safety Observations
5 Lost time accidents
0 Death
Safety: 28 Millions manhours so
far;
Schedule: Gas Commercial Sale by
end of 2013;
Cost: within ODP Budget;
Quality: No major quality issues.
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Anchorage
Thank You! Any Question?
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