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Floating Production Platform Selection for Developing Deepwater Gas Fields off North West Australia
Jinzhu XiaFebruary 2013
Agenda
• Introduction • Proven Floating Platform Designs• Field Development Drivers • Regional Conditions and Drivers • Risk-Based Field Development Selection• Concluding Remarks
2
The Deepwater Frontier
3
Field Development Planning Process
4
SanctionFirst
ProductionDiscovery
Creating ValueSelecting the “Right” Project
Value RealizationDoing the Project “Right”
Acquire Explore Appraise Select Define Execute Operate
ValueGood Definition
Poor Definition
Good Execution
Good Execution
Poor Execution
Poor Execution
InformationGatheringTo ReduceReservoir
Uncertainties
Proven Floating Platform Designs
5
Spar TLP Semisub FPSO
Functionality
Dry/Wet Trees; Surface BOP drilling, completion, intervention
Dry/Wet Trees; Surface BOP drilling, completion, intervention
Wet Trees; Subsea BOP drilling, completion, intervention
Wet Trees; integrated liquid product storage
Limitations Water Depth Not for shallow
water
Tendons to ~1,500 m; Not for shallow water
No limits No limits
Topsides Payload
< 20,000 tons dry weight No limits No limits No limits
Riser Types
SCR, TTR and flexible risers; (Dual Barrier HP production riser to ~1,500 m)
SCR, TTR and flexible risers
Flexible risers, hybrid riser towers and SCRs for deepwater
Flexible risers and hybrid riser towers; very limited SCR applicability
Offshore Installation, Integration, Commissioning
Complex operations; high execution risk
Relatively complex; moderate execution risk
Relatively simple operations; low execution risk
Simple operations; low execution risk
Platform Capability Comparison
6
Floating Production Platform Distribution
7
Total GoM NSea Brazil Africa Asia AUS OtherFPSO 158 3 23 31 43 38 15 5Semi 50 10 15 21 1 3 0 0TLP 24 16 3 0 4 1 0 0Spar 19 18 0 0 0 1 0 0
* Year 2010
Offshore WA
• Many FPSOs deployed in this region
• No Semisub, TLP or Spar production facilities
• Gas developments heading into deepwater
• Calling for floating platforms other than FPSOs
8
Business Drivers
• Gas (LNG) is low priced and less fungible commodity
• Involving large capital investments and long-term sales contracts
• Stringent supply requirements• Maintaining plateau LNG production• Standardization; Contracting flexibility; Market
conditions
9
Reservoir Depletion Drivers
10
Drilling, Completion, …
Reservoir Size/Geometry Drill Centers
Wet or Dry Tree
Development
Drilling, Workover or Production Rig
Small Single Wet Production only
Medium, stacked or compact Single Dry Workover
Large, stacked or compact Single Dry Drilling
Large, areally extensive Multiple Wet Production
only
Multiple, sub‐economic Multiple Wet Production
only
11
Impact of Reservoir Properties
Key Reservoir Fluid Properties Unit
Estimated Range of Values
Impact on Gas Production Facility Requirements
Process Flow Assurance
Secondary Recovery
Subsea, Flowlines, Risers
Low Shut‐in Pressure psi < 5000 psi Med High High Low
High Shut‐in Pressure psi > 15,000
psi Med Low Low High
Low Temperature °C < 65°C Med Med High Low
High Temperature °C > 120°C Med Low Med High
Associated Water
bbl/ MMscf
> 2‐5 bbl/MMscf High Med Med Low
12
Regional Conditions and Drivers
• Unique Metocean Conditions• Geotechnical Conditions• Remoteness/Infrastructure• High Availability/Reliability Requirements• 10,000y Survival • Installation as a Driver
13
Extreme Metocean Conditions Compared
14
0
5
10
15
20
25
1 10 100 1000 10000
Hs
(m)
Return Period (year)
West of ShetlandGulf of MexicoNorth West Shelf
Swell (NWS)
0
0.5
1
1.5
2
0 10 20 30
Wav
e En
ergy
Den
sity
(m2 /s
)
Wave Period (s)
Sea (NWS)
Operational Metocean Conditions
• Persistent swellsStructural fatigueResonant FPSO roll
15
Wave Effects - Example
• Southern Ocean Swell Period: 12 – 18 Sec
• VLCC Converted FPSO Roll Natural Period: ~15 Sec
16
Wave Spectrum
(NWS)
Resonant FPSO Roll
RAO
Optimal FPSO Roll
RAO
0
5
10
0
1
2
0 10 20 30R
oll R
AO
(deg
/ m
)
Wav
e En
ergy
Den
sity
(m2 /s
)
Wave Period (s)
Geotechnical Conditions
• Calcareous soil with high variability• Low shaft friction for driven piles• Tendency to weaken and liquefy under
cyclic loading• Impact subsea layout and platform
location• Impact platform foundation design and
platform concept selection
17
Risk-Based Field Development Selection
18
Ensuring Platform Performance
19
Field development and platform selection fundamentals:• Business objectives• Reservoir depletion objectives • Regional differentiators• Technical enablers
Concluding Remarks
20
21
Some KBR Milestones
Hutton TLPConocoPhillips
Hoover SparExxonMobil
Agbami FPSOChevron
Thunder Horse SemiBP
Acknowledgements
Granherne colleagues, in particularRichard D’Souza, for input and support
22
