MODUs as MOPUs: Low cost field development using hybrid risers

MODUs as MOPUs: Low cost field development using hybrid risers Pedro Viana 2H Offshore

Contents Objectives Background Typical Arrangements for FPU / Riser Free Standing Hybrid Risers key aspects Proposed Alternative(s) MODU as FPU: Drilling & Completion, Production & Installation Historical Precedence & Current Scenario Comparison: Converted MODU vs. TLP Installation Method Conclusions & Closing Remarks 2

Objectives Describe how the conversion of Mobile Offshore Drilling Unit (MODU) into a Floating Production Unit (FPU), keeping drilling and adding installation capabilities, can be a complete and cost effective solution when considered in association with a Free Standing Hybrid Riser (FSHR). Present how previous industry experience and current market conditions turns it into an timelly opportunity. 3

Background 4

Background Typ. Arrangements for Floating Production Unit and Risers (and 2H areas of expertise) Risers & Well Conductors Engineering Drilling Risers Top Tensioned Risers Rigid & Flexible Risers Hybrid Risers 5

Background Free Standing Hybrid Risers (FSHR) key aspects Buoyancy Tank Not highly sensitive to environmental loading or FPU motions Low payload on platform and moorings Large diameters; any water depth Pre-Installable decouples installation from FPU and flowlines schedule Flow assurance flexibility Large insulation thicknesses Pipe-in-Pipe CRA lined pipe Opportunities for Local Content (Africa, Brazil) Unique seabed contact point Lower installation cost by installing from the MODU $60MM to $25MM per installed riser To FPU Flexible Jumper Base Jumper Tether Upper Riser Assembly (URA) Standard Riser Joints Lower Riser Assembly (LRA) Foundation 6

Proposed Alternative MODU as MOPU 7

Proposed Alternative Options Option A: MODU re-purposed as FPU only Minimal or full processing facility Fluid processed at MODU before export Future drilling & intervention by a different MODU Option B: MODU repurposed as FPU + drilling & workover + FSHR installation Drill initial or future wells Install production risers - avoid costly heavy lift installation vessel Production fluids offloaded to FPSO Workover & intervene - maximize reservoir recoverability Permanent installation over field life new requirements 8

Proposed Alternative Drilling & Completion, Production & Installation - OVERVIEW FPSO Mooring Transfer System (s) (mid water or FSHR-flowline-Riser) Converted Semi-Sub: Drilling Production Installation Mooring Free Standing Hybrid Riser(s) (FSHR) Flex Jumper Drilling Riser Subsea Tree Flowline Manifold Subsea Umbilical 9

Proposed Alternative Field Layout Arrangement Rationale Constraints Accommodated: Subsea Tree - MOPU motions do not allow for dry tree Top Tensioned Risers FSHR minimizes riser load even in deepwater Production transfer to FPSO - minimizes additional payload and deck space and allows the drilling rig to be maintained Subsea trees located under drilling vessel to enable through life drilling/workover access Offloads to leased FPSO providing overall low CAPEX solution Improved and alternate from TLP-FPSO Solution (W Africa, SE Asia and Brazil) 10

Proposed Alternative Applications & Additional Benefits Particular value for: Fields that would otherwise need a substantial production and drilling host (PDQ) Marginal fields Early production / extended well test. But valuable for any (applicable) field: Long lead-time and expensive TLP/FPU can be avoided. Heavy construction vessel can be avoided 11

Historical Precedence & Current Scenario 12

Historical Precedence FSHR s to Date Type Field Status Bundle Single Line Green Canyon 29 Garden Banks 388 Owner/Field Operator Placid Oil Comp/ Ensearch Yr. Installed Region (ft) Water Depth (m) Vessel 1988/1994 GoM 1,529/2,096 466/639 Semi-Submersible Girassol Operating Total Elf 2001 Angola 4,430 1,350 Spread Moored FPSO Rosa Operating Total Elf 2007 Angola 4,430 1,350 Spread Moored FPSO BP Greater Plutonio Operating BP 2007 Angola 4,300 1,311 Spread Moored FPSO Kizomba A & B Operating Exxon 2004/2005 Angola 3,330-4,200 1,006 to 1,280 Spread Moored FPSO Block 31 / PSVM Operating BP 2012 Angola 6,890 2,100 Turret Moored FPSO P-52 Operating Petrobras 2007 Macondo Cascade/ Chinook Decommissioned Decommissioned Campos Basin 5,906 1,800 Semi-Submersible BP 2010 GoM 5,000 1,515 DP FPSO Operating Petrobras 2010 GoM 8,531 2,600 Turret Moored FPSO Block17/ CLOV Operating Total 2014 Angola 3,600-4,600 1,100-1,400 Spread Moored FPSO Block32/ Kaombo Construction Total TBC Angola 4,675-6,315 1,425-1,925 Turret Moored FPSO Note: bold indicates 2H involvement in FEED or Detailed Design 13

Historical Precedence MODU Conversions to FPU 15 conversions were carried out in last major oil downturn between 1986-1999 Mostly semi-submersibles Typical water depths < 1,000m Subsea developments using flexible risers Ref: Deegan, Loffman, Odufuwa, The conversion of Mobile Offshore Drilling Units to Floating Production System Issues, Opportunities and Challenges, DOT 2014 Vessel Field Startup Region Water Depth (m) Argyll FPU Argyll Oil Field 1975 UK North Sea 150 Buchan A Buchan oil field 1981 UK North Sea 160 P-09 Corvina Oil Field 1983 Brazil 230 P-15 Pirauna 1983 Brazil 243 P-12 Linguado / Badejo Oil Field 1984 Brazil 100 P-21 Badejo / Salema Oil Fields 1984 Brazil 112 Argyll & Duncan Oil Deepsea Pioneer FPU Fields 1984 UK North Sea 150 P-22 Morela 1986 Brazil 114 P-07 Bicudo Oil Field 1988 Brazil 207 Veslefrikk B Veslefrikk Oil Field 1989 Norwegian Sea 175 AH001 Ivan Hoe Rob Roy Oil Field 1989 UK North Sea 140 P-20 Marlim 1992 Brazil 625 P-08 Marimba Oil Field 1993 Brazil 423 P-13 Bijupira / Salema Oil Field 1993 Brazil 625 P-14 Coral / Esrela / Caravela Oil Fields 1993 Brazil 195 Nan Hai Tiao Zhan Luihua 1995 South China Sea 300 P-25 Albacora II Oil Field 1996 Brazil 252 P-27 Voador 1996 Brazil 533 Tahara PY-3 1997 Indian Ocean 339 P-19 Marlim 1997 Brazil 770 Janice A Janice Oil Field 1999 UK North Sea 80 P-36 Roncador 2000 Brazil 1360 SS-11 Coral 2003 Brazil 145 P-40 Marlim Sul 2004 Brazil 1080 ATP Innovator Gomez Oil Field 2006 Gulf of Mexico 914 Originally Galley Oil Northern Producer Field now at Don Oil FPF Field 2009 UK North Sea 350 14

Historical Precedence - Case Example Liuhua Field Development Production and Drilling Background: 300m water depth, South China Sea Marginal field, low recovery, high water cut Extend well tests Adjustable drilling & intervention requirements Solution: Converted MODU: production and drilling capability Converted FPSO On seabed transfer from manifold to FPSO Solution made development economically viable Ref: Hall, Sheng, Krenek, Douglas, Macfarlane, Liuhua 11-1 Development Subsea Production System Overview, OTC 1996, Paper 8175 15

Current Scenario Worldwide Rig Count (Ref: HIS, Q3 2015) Opportunity for using idle low cost drilling vessel instead of new build TLWP w/ drilling rig Take advantage of current Learn more overcapacity at www.2hoffshore.com in the drilling vessel market 16

Converted MODU vs. TLP/TLWP 17

Converted MODU vs. TLP/TLWP Key MODU Advantages over TLP or Spar CAPEX Schedule RISKEX - saving of up to 50% vs. TLWP/Spar - first oil anticipated by one year or more - lower installation risk compared with TLP and Spar installations Maintain life of field workover capability for maximum reservoir recoverability Manage reservoir uncertainty Maximum end of life well count is not a driver for drilling vessel selection - flexibility Can also be an early production system Subsea architecture is organically expandable using the drilling vessel and a support vessel (MSV) to install more trees, risers, flowlines and jumpers Vessel and riser system can be readily retrieved and relocated 18

Converted MODU vs. TLP/TLWP Key MODU Advantages over TLP/Spar Schedule CAPEX RISKEX - first oil anticipated by one year or more - saving of up to 50% vs. TLWP/Spar - lower installation risk compared with TLP and Spar installations Maintain life of field workover capability for maximum reservoir recoverability Manage reservoir uncertainty Maximum end of life well count is not a driver for drilling vessel selection - flexibility Can also be an early production system Subsea architecture is organically expandable using the drilling vessel and a support vessel (MSV) to install more trees, risers, flowlines and jumpers Vessel and riser system can be readily retrieved and relocated 19

Converted MODU vs. TLP/TLWP Schedule Comparison FEED - 20 Slot TLP Year 1 Year 2 Year 3 Year 4 Year 5 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Integrated Rig With TLP Integrated Rig with TLP Sanction & Detailed Design TLP Construction & Integration TLP Tendon Fabircation 1st Batch Riser Delivery (3 production and 1 drilling) Tendon Installation TLP Installation & Commissioning (Ready to drill or complete) First completion and first oil (1 well) X Producing (3 wells) X MODU Drilling (Batch set conductors and drill 4 wells) FEED Sanction & Detailed Design Puchase semi and conversion (w permanent moorings) 1st Batch 3 off Subsea Trees Delivery (w manifold, well jumpers and 1st Batch 1 off Riser Delivery (w surface and seabed jumpers) Mooring Pre Installation Semi Installation Semi-submersible with FSHR Semi-Sub with FSHR 1 st oil reduction over 1 year Drilling and completion from Semi (3 wells) FSHR Installation (1 off) Install flexibles and umbilicals (w flex lay vessel) First oil (with 3 wells) X 20

Converted MODU vs. TLP/TLWP CAPEX Comparison Integrated Rig With TLP Semi-submersible with FSHR FEED - 20 Slot TLP FEED - Sanction & Detailed Design TLP Construction & Integration TLP Tendon Fabircation 1st Batch Riser Delivery (3 production and 1 drilling) Tendon Installation TLP Installation & Commissioning (Ready to drill or complete) First completion and first oil (1 well) $90,000,000 $1,000,000,000 $90,000,000 $40,000,000 $25,000,000 $39,000,000 Producing (3 wells) - Install flexibles and umbilicals $7,500,000 (w flex lay vessel) MODU Drilling $93,250,000 (Batch set conductors and drill 4 wells) First oil (with 3 wells) - Total $1,377,250,000 $417,250,000 USD ~ 1.4 MM - Sanction & Detailed Design Puchase semi and conversion (w permanent moorings) 1st Batch 3 off Subsea Trees Delivery (w manifold, well jumpers and umbilical) 1st Batch 1 off Riser Delivery (w surface and seabed jumpers) Mooring Pre Installation Semi Installation Drilling and completion from Semi (3 wells) FSHR Installation (1 off) Total $35,000,000 $290,000,000 $35,500,000 $25,000,000 $5,250,000 $6,500,000 USD ~ 0.4 MM 21 - $12,500,000

Installation Method 22

Installation Method (key steps) Field Proven Foundation installed Aircan brought to moonpool Vertical riser run w/ LRA attached (at bottom) URA connected (at top) 23

Installation Method (key steps) Field Proven Aircan connected to top of URA, lowered into water and ballasted LRA landed and latched Aircan deballasted 24

Installation Method (key steps) Field Proven Vertical riser free-standing Light construction vessel pays out flexible jumper ROV attaches A&R wire and connects jumper to URA 25

Conclusions & Closing Remarks 26

Conclusions & Closing Remarks MODUs as MOPUs: Low cost field development using hybrid risers Solution achievable with a combination of field proven technical solutions Surplus rigs in the drilling market is an additional opportunity to reduce CAPEX by up to 50% and time to 1 st Oil by 1 year compared to an equivalent TLWP Subsea trees and freestanding risers enable a MODU to be repurposed as a permanent moored drilling and workover vessel for deepwater Arrangement provides expansion flexibility to minimize upfront CAPEX and protect against reservoir uncertainty Risers and vessels can be retrieved and relocated 27

Questions? Thank you for your attention Obrigado! Pedro Viana Technical Manager 2H Offshore +44 1483 775027 Pedro.Viana@2hoffshore.com 28

Murphy Azurite FDPSO 31