Introducing the UNFC Why classify our resources? David MacDonald, Vice President Segment Reserves 27 September, Mexico City
Outline History of resource classifications Fundamental purpose of resource classification Capital value chain at work in the North Sea How the UNFC can facilitate development 2
Resource Classification is not a new Problem! 3
Purpose of Resource Classification External Influencers Internal preparers Internal Stakeholders Internal users Governance and Assurance External user 4
Capital Value Chain 5
Adding Value 6
Development needs a Plan The UNFC can help to define that development plan 7
Improving recovery factors in the North Sea
BP North Sea - Executing a Resource Led Strategy Strong incumbent position in North Sea Strategy Deliver 6 major projects (both field redevelopments and green field projects) Execute targeted E&A programmes, informed by Catchment Area Reviews around all Hubs Grow Recovery Factor in existing fields Recovery Factor Theme RF technical limit (RTL) review of all fields Assess optimal life of field depletion plan that could deliver RTL Define activity set to pursue technical limit Monitor & optimise reservoir management for value Long term seismic plans for each Hub Seismic technology solution integrated with depletion plans Portfolio Management Deepened in Valhall, Quad 16 (Andrew Area) Sales of Wytch Farm and Southern Gas 9
Resource progression BP North Sea portfolio Resource tube 31% RF 36% RF 38% RF 42% RF Technical Limit 52+% RF Produced Reserves Online New Activity Funded Planned Options Options with technical barriers Optimising base production New infill drilling Enhanced oil recovery Extending facility life Life of Field Depletion Plan 10
Integrating subsurface description with operational activity depletion planning Describing the habitat of the remaining hydrocarbon Technical limit seismic imaging Forensic reservoir description Accurate description of historical drainage & sweep Appropriate recovery mechanisms for later field life Modifying pore-scale process through EOR e.g. WAG, polymer Depressurisation (blow-down) Ensuring the facilities are fit-for-purpose and have appropriate life Increased water & gas handling; changing fluid chemistries (H 2 S) An integrated depletion plan to optimise infill drilling, wellwork & effective reservoir management 11
Magnus ongoing redevelopment to maximise recovery factor
Magnus pushes recovery factor 60%+ Very successful initial waterflood development recovered initial sanction volumes Subsequent phases of development will increase recovery to 50-65% Subsea water injection added to debottleneck water injection well constraint WAG EOR scheme using stranded gas from WoS fields involved new import gas pipeline, additional compressor and recompletion of injection wells Platform slot constraint reduced by adding 4 new slots with splitter technology to side of platform providing 8 new wells Field life extension from 2008 to 2030 through ongoing CAPEX on facilities upgrades Enabled by substantial jacket & platform drilling package to reach field extents Full field seismic OBC coverage just been acquired (August 2011); 4D seismic for WAG surveillance 13
Magnus Development phases Magnus Hub Oil Production Rate (mstbd) 160 140 120 100 80 60 40 20 Evolution of Magnus Field Production Profiles Magnus Field Recoverable oil (mmstb) 1100 1000 900 Current Recovery of 820mmstb 800 700 600 500 1982 - Initial Sanction 1986 1987 1991 1994 1995 2000 2005 2010 Proved 2011 Depletion Plan 2011 Depletion Plan 2010 Proved 2005 2000 1995 1994 1991 1987 1986 1982 - Initial Sanction Actual (Historical profiles - Annex B revisions) 0 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 LKCF development Infill drilling to utilise 20 slots South Magnus subsea tie-back Phase I and Phase II infill drilling programmes Options for further WAG patterns and Extended EOR scheme to progress remaining CR volumes Increase off-take to 140mbd Revised petrophysical interpretation Miscible WAG EOR scheme for MSM and LKCF brownfield mods 8 new platform slots Magnus Full Field Recovery Factor 7 subsea & 15 platform wells MSM only WF development plant PW de-bottlenecking 20 additional wells Subsea injectors (SWIFT) North West Magnus satellite development from platform 30% 40% 50% 60% 70% Produced Infill Ph2 Max EOR & Blowdown Base Infill Ph3 Left in ground 14
Andrew satellite tie-backs unlock deep gas recovery
Second lease of life for Andrew platform Andrew platform initially developed Andrew Palaeocene with dry trees; and subsea tieback of Cyrus Farragon subsea field later tied into Cyrus manifold Kinnoull discovery will be developed via 30km tieback via Arundel discovery to Andrew platform, with brownfield modifications for process module Enables development of Andrew Lower Cretaceous gas through both process capacity increase and CoP extension Enabled by aggressive catchment area review and increasing license position and operatorship 16
Andrew Hub depletion plan Andrew Hub Annualised Production (gross mboed) 100 90 80 70 60 50 40 30 20 10 0 1996 1997 1998 1999 2000 2001 2002 2003 2004 2003: Farragon discovery Platform sidetrack drilling program Farragon 2-well subsea tieback via Cyrus 2008: Kinnoull discovery 2006: Arundel discovery 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Additional Lower Cretaceous wells Andrew Lower Cretaceous gas online Solid: Base production Further subsea tie-ins oil gas Graded: Developments Speckled: Hopper options 2023 2024 2025 2026 2027 2028 2029 2030 Platform startup Cyrus 2-well subsea tieback Kinnoull 3-well tieback direct to Andrew Farragon 2-well subsea tieback via Cyrus 17
Schiehallion FPSO replacement for 2 nd phase of field life
Schiehallion and Loyal Current Production Schiehallion Clair OIL EOSPS Magnus Field discovered 1993; on stream 1998 FPSO (Floating Production, Storage, Offloading) Oil exported via shuttle tanker to SVT; x storage tanks Gas exported via 20 pipeline to SVT; treated and exported to Magnus Foinaven WOSPS SHETLAND ISLANDS Sullom Voe Peak production 184,000 bo/d 2010 Production c.22,000 boe/d Production to date c.400 million boe; estimated c.450 million boe still to produce (Base Case - new FPSO) Designed for 25 yr field life; already looking at field extension to 2035+. 19
Q204 Project Reservoir potential and production history requires a higher specification vessel fit for remaining field life Q204 project (new FPSO, enhanced subsea facilities, additional wells) sanctioned in July 2011 Ca. 3bn investment 270m long FPSO in same location as old vessel 130,000 bpd oil, 320,000 bpd liquids Oil export shuttle tanker to SVT; gas expected to Magnus via SVT 25 year design life New vessel is EOR polymer ready 20
Current challenges Maintaining wellwork & drilling activities on aging infrastructure significant PoB requirements for integrity & obsolescence projects Bringing 3 rd party opportunities across infrastructure Challenging brown field modifications required Activity set on existing fields keeps platforms at full activity capacity Some projects progressing: Centrica s Seven Seas project in Southern Gas Basin to West Sole BP s Devenick subsea tie-back to Brae Blowdown! Planned blowdown in many fields being deferred due to new opportunities being identified (oil vs. gas price differential reinforces) 21
Improving recovery factors in the North Sea Describing the habitat of the remaining hydrocarbon Technical limit seismic imaging Forensic reservoir description Accurate description of historical drainage & sweep Appropriate recovery mechanisms for later field life Modifying pore-scale process through EOR e.g. WAG, polymer Depressurisation (blow-down) Ensuring the facilities are fit-for-purpose and have appropriate life Increased water & gas handling; changing fluid chemistries (H 2 S) An integrated depletion plan to optimise infill drilling, wellwork & effective reservoir management 22
Sustainable and Efficient Development Securing affordable and sustainable energy requires a common standard for developing: Long sighted policies for the global markets Government resources management for security and efficiency Industry processes to develop new technologies and efficient project management Cost effective allocation of financial resources 23