spe distinguished lecturer series spe … dist lec 03 ver 3_oslo_jan.pdf · spe distinguished...
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SPE DISTINGUISHED LECTURER SERIESis funded principally
through a grant of the
SPE FOUNDATIONThe Society gratefully acknowledges
those companies that support the programby allowing their professionals
to participate as Lecturers.
And special thanks to The American Institute of Mining, Metallurgical,and Petroleum Engineers (AIME) for their contribution to the program.
SPE Lecture - Deep Water Facilities Concept Selection
Richard Snell BP Exploration
Lecture Content
Fundamental factors - Location, reservoir etc
Field development concepts
Design Issues and technology development
Technical Risk
Fundamental FactorsLocation
Environment - wave climate and water depth
Reservoir characteristics
Primary Deep Water Locations of Interest to the Oil Industry
GoMW AfricaBrazilNorwayWest of Shetlands/Fearoes
But watch other locationsEgypt (E Med) S ChinaIndiaAustralia/Indonesia
Location Proximity to Market & Infrastructure
GoMclose to existing infrastructure and market for both oil & gas
NW Europe close to market for oilneed big gas finds to justify export pipelines
Brazil Campos Basin close to oil market
Other primary locations distant from market and limited or no infrastructure
Comparative Metocean CriteriaGulf of Mexico(Hurricane / Loop)
Wind 42.0m/s
20 50
Surface Current 1.10 m/s / 2.57m/s
Max Temp = 30.0°C
Min Temp = 4.0°C
Waves
Hmax 23.2mHs 12.5m
Water Depth3000m
Hmax 9.0mHs 4.9m
Wind 30.9m/s
Seabed Current 0.1 m/s / 0.51 m/s
Submerged Current 1.1 m/s
Surface Current 1.75m/s
Seabed Current 0.49m/s
Max Temp = 14.0°C
Min Temp = -1.5°C
Waves
Hmax 30.0m
Hs 15.7m
Water Depth1500m
West Africa
Wind 25.0m/s20 50
Northern NorwayVoringplateau
Wind 38.5m/s20 50
Atlantic FrontierFaeroe - Shetland Channel
Wind 40.0m/s20 50
Surface Current 1.50m/s
Seabed Current 0.50m/s
Max Temp = 30.0°C
Min Temp = 4.0°C
Waves
Hmax 7.5mHs 4.0m
Water Depth2000m
Surface Current 1.96m/s
Seabed Current 0.63m/s
Max Temp = 18.5°C
Min Temp = -1.5°C
Waves
Hmax 32.7m
Hs 18.0m
Water Depth1000m
0m
1000m
2000m
3000m
Sea State Effect
Wave Vessel Mooring FatigueHeight Motions ForceHs ∝ (Hs) ∝(Hs)2 ∝(Hs/3)3
W Africa 5m 5 25 4.66
Brazil 8m 8 64 19.0
Egypt 10m 10 100 37.0
GoM 12m 12 144 64.0
NWE 18m 18 324 216
What is “Deep” Water?1990 1995 2000 2005
PompanoSubsea TB
FoinavenSchiehallion
FPSO
MarsTLP
UrsaTLP
GirassolFPSO
HooverSPAR
Holstein
MarlinTLP
Ram/PowellTLP
ThunderHorse
King’s Peak
SS TB
Atlantis
Nakika
0
300
600
900
1200
1500
1800
2100
2400
Metres
Current DevelopmentsProducing
Deep Water Experience Summary
500m wd off N W Europe
1000m wd off Brazil
1300mwd off W Africa
1900m wd in GoM
Reservoir CharacteristicsKey issues
Oil or GasWell productivityReservoir Area - accessed from a single facilityor multiple locationsWell intervention frequency
Oil or Gas
Oil Easily transportable by pipeline or tankerTiming of development not market sensitive.Can be traded worldwideReserves < 500 m bbl can be marginal
Gas Export in LNG form or by pipeline Timing depends on finding a marketNeed large reserves or adjacent infrastructure.Often re-injected for pressure support
Well Productivity
Drilling and completing the wells may account for 30 to 50% of field cost.
Large well counts also incur higher facilities capex/opex.
Ideally need about 25 million barrels per well recovery for an economic development.
Well productivity is critical
Reservoir Area
Is it?Single compact reservoir with limited faultingHighly faulted Several adjacent small reservoirs
Few fields economic with multiple surfacefacilities. Usually a surface facility in combinationwith subsea wells.
Long subsea tie backs bring flow assurance concerns
Dry Wellheads on Host - note combination with subsea
Well Intervention Frequency
Need to maintain completion systems, mechanical components & access other parts of the reservoir. Problems are erosion, corrosion, sand fill, scaling.
Remote subsea wells require mobilisation of a semifor major intervention. Production impact possiblyas high as 10% of recoverable reserves.
Frequent intervention requires surface facility.
Subsea Remote Wellheads
Subsea Locally Accessable Wellheads
Lecture Content
Fundamental factors - Location, reservoir etc
Field development concepts
Design Issues and technology development focus
Technical Risk
Field development concepts
Primary considerations
ExportPipeline Tanker - size of export parcel
Number of wellsMotion constraints for riser integrityEnvironmentInstallation
ConceptsSubsea wellhead
FPSOTurret mooredDirectionally moored
SemiConventional (surface wells in calm areas)Deep draft for surface wellheads
Surface wellheadsTLP
Multi legSingle column
SparClassicTruss
Subseaalone or in combination with a surface concept
FPSO
Semi
TLP
•• • ••
Spar
Subsea - producing to FPSO
Subsea Production
Gravity Separator
WI Pump
Pump VSD
Degasser Desander Deoiler
Controls
Lecture Content
Fundamental factors - Location, reservoir etc
Field development concepts
Design Issues and technology development
Technical Risk
Outline Cost Distribution
Example FPSO with Subsea wells field off W Africa
FPSO topsides $600mFPSO hull & Moorings $150mSubsea equipment $400mRisers & flowlines $1000mWells $1000m
Technical Maturity
Can provide a floating solution for most applications Floater technical development focussed on
reducing costreducing technical riskimproving operability/durabilitynot actively looking for new hull forms
Priority areas for technical development areflexible, SC and tower riser technology flow assurance subsea production subsea equipment installation system integration
Top Tensioned Risers
Waves
Current
Motions
High Performance Materials (e.g. Titanium)
Motion Suppression Systems
Impact Resistant Coatings
Fatigue Life Prediction and Improvement
Motion Modelling and Clashing Prediction
Catenary Risers
Waves
Current
Motions
Motion Suppression Systems
High SpecArticulation Elements
Global MotionPrediction
AlternativeConfigurations
Fatigue Life"Hot-spot"
Improve WeldFatigue Life
Behaviour at Seabed Touchdown
Flow Assurance
Geometry
Risk of slug flow. Influenced by fluid composition and geometry of flowlines/risersControlled by line level and slug catchers
Pressure/Temperature
Risk of blockage of flowlines/risers by formation of hydrates andwax deposition.Controlled by use of chemical inhibitors and line insulation orheating.
Subsea Production
Troll C Pilot demonstrates viabilityWork in progress on
Power distributionControlsSand ManagementFeasible depth of gravity separators
Next step tie backs and de-bottlenecking
Possibly 5 years before perceived risk and commercial issuesallow full field development in very deep water.
Steel Wire Capability
Integration - DesignFixed platforms allowed compartmentalised design.Floaters require highly integrated design
Trade off between:-Hull size & motion on topsides & risersDamaged condition offset and stabilityCoupled hull/riser/mooring behaviourFlow assurance on process systemCombined process and marine control systemDeck flexureMaintenace of cargo & ballast handling systems
The hull is one of the lowest cost elements and can be sizedto reduce other discipline design problems often to net benefitin overall cost
Integration - Construction
No longer routinely using offshore yards
Topsides build - modular or piece small.
Topsides installation, hook up and commissioning - at site, near shore or in a construction or ship yard.
Construction specifications for long term offshoreduty to be implemented by shipyards.
Integration - Installation
A deep water field can have complex flowline, risers and moorings constrained within a limited space
Long ocean tows of very large objects
3 body motion considerations for topsides installation infield
GoM Example Schematic Layout
Long Distance Transport
Spar Upending
Spar Topsides Installation
Spar Topsides Installation
Lecture Content
Fundamental factors - Location, reservoir etc
Field development concepts
Design Issues and technology development focus
Technical Risk
Industry Understanding of Risk
Investment decisions tend to be madeusing financial models that consider project execution risks but not the full range of facilities technical risk.
Risk is technical failure, cost & schedule overrunsand low operability.
Is the Industry taking a higher facilities technical risk as it moves increasingly towards floating production in deepwater?
Risk Baseline
Baseline facility for Industry appreciation of facilities risk is the fixed steel platform.
-More than 7000 installed worldwide.-Developed over 50 years.-Established design and construction practices.-Reasonable understanding of failure frequency and causes which have mostly been addressed in practices.-Many unmanned.-Many with very low hydrocarbon inventories.
Fixed Platform Risk
Risk
1950 2000
Recognise where the risk is
Small benign environment FPSO’s, not a problem.
Large throughput floaters have not usually met budget and schedule expectations. No single reason but some lessons.
Scale & Complexity
The big throughput floaters are very large scale complex projects compared to most prior experience. They are being executed in part outside our traditional supply chain.
Even the drilling contractors who had a very good project management track record have run into problems with the new generation deep water rigs.
Have we been over optimistic on ability to manage scale?
Examples of Recent Design Problems
FPSO hull fatigueFPSO topsides fatigueGreen waterBow slamMooring connectorsMooring hawse pipeBallast control systemsFPSO swivel failuresSpar riser “stick/slip” in guides and at keel joint
Examples of Recent Construction Problems
Missing components in stiffened plate structuresWeld quality control in large stiffened plate structuresTolerances in rotating componentsTopsides piping integrityAdhesive systems connecting VIV suppression to pipeRiser tower buoyancy fit up Control umbilical superduplex tubing quality
Examples of recent Installation Problems
Damage to outer sheath of flexible risersDamage to wire and polyester mooringsDropped liftsFailure of reeled tube assembliesHigh dynamic loads in deep subsea equipment deploymentsErrors in pre-tension in moorings
Examples of Operations Risk
Ballast controlHeading controlImpact from offtake tankerOverpressuring cargo or ballast tank Decision complexity when responding to incident
FPS Risk
2003?
Risk
1950 2000
Conclusions
The industry has solutions for many deep water requirements
2000m wd in reasonably benign fatigue environment is feasible Today. We plan to go much deeper.
The key areas for technology development to enable deeper/cheaper fields are risers, subsea and installation
Floater development is still needed - focussed on cost and risk reduction
Need around 500mmbbls recoverable for an economic Development
High well productivity is critical
GoM Example Elevation View
Current Deployment Capability
Degradation of Vessel Lift Capability with Deployment Depth
0
1000
2000
3000
4000
0.0 0.2 0.4 0.6 0.8 1.0
Lift Capacity as proportion of Surface Lift Capacity (-)
Dep
loym
ent D
epth
(m)
New Monohull DCV, 400 Tesurface lift
Established HL monohull,1400 Te surface lift
New semi-sub DCV, 190 Tecapacity traction A&R winch
Established SSCV, plannedupgrade
Subsea Equipment Installation
Ship Deployment Systems
Ship Motions at Surface
Varying Current
Rope strength &varying Tn with depth
Slow winchesEnvt. may change during deployment
ROV umbilical tangle with loweringline
ROV thrust capability & control
Current load on umbilical
2 axis pendulum& twist motions
Seabed positioningsystem capability
Object settlement and tilt on seabed
Added mass
Lift System
StorageReel
HeaveCompensator
Traction Winch
Load
Large area reservoir - Multiple drill centres with subsea wells