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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