IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page i of xxvi Rev. 0 EXECUTIVE SUMMARY Objective
The objective of this study is to deliver an assessment of oil and gas technology that may be applied to cold regions of the United States Oute r Continental Shelf (O CS). Advances in harsh environment offshore exploration and production technology have made it economically and technically feasible for proj ects to proceed in ice-covered waters.
This study assesses the current state of o ffshore technology in ar ctic and sub-arctic regions. The results of this assessment are then used to provide insight and guidance into existing/future exploration and development tec hnologies that might be applied on the US OCS, in particular those areas in t he Beaufort, Chukchi and Bering Seas.

The work covers exploration structures , bottom-founded and fixed production concepts, floating production concepts, termi nals, pipelines and subsea faci lities, and also touches on other technologies that might be relevant to Alaskan OCS exploration and development.

Assessment Methodology
This study draws on a review of current stat e-of-practice and state- of-the-art used in, or proposed for, arctic and su b-arctic offshore developm ent areas. Assessments of exploration and production options are primar ily based on technical feasibility. As appropriate, other aspects have also been cons idered, including constructability, capital costs, environmental considerations, oper ations, maintenance a nd repair, abandonment and decommissioning.
Given the large geographic area enc ompassed by the Beaufort, Chukchi and Bering Seas, location scenarios were adopted to help focu s the assessments. These locations were chosen based on current and historic activity and interest (including l ease sales, drilling, studies, projects, etc.) and water depths (given t he general differences in offshore facilities configuration with water depths). Overall applic ability of the technol ogy to the region of interest was also considered.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page ii of xxvi Rev. 0 Technical Feasibility

Bottom-Founded Structures
In multi-year ice areas of the Alaskan OC S, there are bottom-founded, e.g., gravity base structure (GBS), solutions that would be considered safe and economical up to around 250 ft (75 m) water depths when foun dation properties ar e good, and up to around 200 ft (60 m) water depths when foundation properties are relatively weak.
There are no known bottom-founded platform des ign solutions for water depths greater than 330 ft (100 m) that could be deemed workable or proven for multi-year ice areas

. In the more southern areas, where multi-year ice is absent and only first-year consolidated ridge loadings are possible, bottom-founded solu tions out to 500 ft (150 m) water depths are potentially viable.
Jacket & Jack-up Structures
The ice reinforced jacket platform was first succe ssfully used in sea ice in the mid 1960’s for Cook Inlet, Alaska developments. Pr evious studies have suggested that jacket structures are suitable for areas of the Bering Sea. However, these studies did not consider the vibration responses associ ated with the dynamic ice load ing. Jacket type structures could likely be made to work in light first- year ice and in water depths less than 200 ft (60 m). However, the jacket structure’s potentia lly poor response to dynamic loading and the need for conductor system protection are signific ant design issues for application in the Bering Sea.
Current design practices and understanding of jacket desi gn make their application unsuitable for the Beaufort and Chukchi Seas.

Developments in jack-up technology and the advancement of ice maintenance programs indicate that the operating r ange and season of jack-up explor ation could potentially be extended in the Bering Sea.

Ice Islands
Grounded ice islands have been used successfully as exploration drilling structures in nearshore areas of the US and Canadian Beaufort Sea. In prac tice, operational ice islands have been employed in water depths of up to 25 ft (7.6 m) in the Beaufort Sea.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page iii of xxvi Rev. 0 Based on work sponsored by the MMS, t he use of operational ice islands might be achieved in water depths of up to approxim ately 30 ft (9 m). The MMS Ice Island Study (2005) suggests that “incremental improvem ents in equipment ca pacity with higher productivity would allow islands to be constr ucted into deeper water and it is considered that 40 ft (12 m) water depth s hould not present a problem”.

The use of ice islands in t he nearshore Chukchi would likel y be infeasible due to the unstable and unreliable landfast, or contiguous, ice zone. Ic e islands would be generally infeasible for Norton Sound due to its warmer and shorter winte r season. However, definite conclusions can only be reached through more detailed study.

Gravel Islands
Although not a “high tech” technology, gravel islands have been successfully used in the Beaufort Sea for decades and continue to be viewed as a candidate structure for exploration and/or production in this area of the Alaskan OCS.
Since no gravel island struct ure has been used in the Chuk chi Sea, a more detailed assessment would be required to determine feasibility. Due c onsideration would need to be given to the fact that t he nearshore Chukchi Sea ice env ironment may be more dynamic than the Beaufort Sea. In the nearshore Bering Sea, gr avel islands may be subject to higher waves and larger wave loads, which would need to be taken into consideration during detailed assessment.
Floating Structures
There are only a limited number of floating expl oration or production st ructures that have been used in ice environments. Seasonal exploration can be carried out in the Alaskan OCS using drillships and drilling barges and, in areas without multi-year ice, semisubmersibles or a TLP. However, for exploration, the only loca tion that a floating structure might be capable of staying on station year-round might be t he Bering Sea under light ice conditions. A Semi-rigid Floater structure might work year-round under first-year ice conditions but would need to have the ability to disconnect and leave station in the event of potentially higher loads.
Floating production systems for the Beaufort Sea, Chukchi Sea and North Bering Sea are not considered to be technically feasible, even with continuous ice management. No floating production structures could be economically designed to stay on station with multi-IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page iv of xxvi Rev. 0 year ice loads found in the Beaufort and Chukchi Seas, and possibly northern Bering Sea depending on local ice conditions. Floating syst ems may have some merit in southern Alaskan OCS areas, however.

Subsea Solutions
In some cases, there may not be a requirement for a production island or platform offshore. If the wellhead is located in water of suffici ent depth, protection from ice would not be necessary. In areas with water depths less t han the maximum ice keel depth, glory holes may need to be considered to protect the subsea facilities from ice ridge keels.
Improvements in the area of subsea facilities and processing have been made in recent years in the pursuit of resour ces in harsh and remote environm ents. As a result of these improvements, fields requiri ng longer, deeper subsea tiebacks are now becoming much more technically and economically feasible . Gas tiebacks have reached 105 miles (170 km) and oil tiebacks have reac hed 40 miles (65 km).
Subsea facilities can potentially be consider ed for any development on the Alaskan OCS. However, there are limitati ons on which technology should be or would need to be considered. Glory holes would only offer prot ection from gouging keels. Where active ridge building is taking place or t here are grounded ridges present, there is the potential for a ridge keel to be pushed into an open glory hole as the ridge keel is being formed. Beyond the zone of active gouging, subsea facilities might be placed directly on the seabed (depending on the ice gouging regime).
Pipelines & Flowlines
Pipelines have been designed, constructed and are op erational in the ar ctic, but these are in relatively shallow water depths and relative ly close to shore. Pushing the limits to developments further offshore in deeper water will require that additional consideration is given to aspects related to des ign, construction and operation.
Some of the main considerations with respect to pipeline design in the arctic are strudel scour, thaw settlement of permafrost, upheaval buck ling and ice gouging. It is generally felt that the first three considerations can be de signed for on future proj ects. However, pipeline burial for protection in water depths from ap proximately 65 to 130 ft (20 to 40 m) will be a challenge given the more severe gouging in these water depths and the fact that the pipeline can likely not be installe d from the ice in winter. While trenching from the ice to aIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page v of xxvi Rev. 0 certain water depth has been proven on projects in the nearshore B eaufort Sea, trenching and pipeline installation from floati ng vessels has not yet been attempted.

Export Terminals
The technical feasibility of marine terminals in arctic areas has been established through successful experience in a wide r ange of port facilities. A gener al review of experience in operation of high-latitude oil and gas marine terminals indicates that existing technology of port structures design and construction is suffi cient to support operati ons in the Alaskan OCS.
While technically feasible, no tanker tra ffic has been proposed in the EIS for upcoming Beaufort or Chukchi lease sales. Regulator y requirements would require the use of pipelines (if economically feasib le) rather than barging or tanker ing production to shore. An exception may be gas export by LNG or CNG.
Other Technologies

Advancing technologies such as extended reach drilling, well intersection method and pilot hole to pilot hole HDD installations might be considered for arctic developments.

Recommendations
It is generally agreed that environmental conditi ons (especially waves and ice conditions) are changing in the arctic. Bu t no one knows definitively by how much, nor is there a compilation of current information (that the St udy Team could find) that provides the information necessary to draw upon. It has been suggested by st akeholders that the MMS might consider a future study to compile , collect and/or generat e ice, metocean and meteorological information to be used by interested parties in screening studies.
In carrying out this study, the Study Team ident ified additional informa tion that would be “valuable to have” for future work. In addition, some technological areas were identified where advancements should be pursued, and thes e are also captured in this report.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page vi of xxvi Rev. 0 TABLE OF CONTENTS EXECUTIVE SUMMARY .......................................................................................i 1.0 Introducti on ................................................................................................................ 1 1.1 Introduction & Overview......................................................................................... 1 1.2 Backgroun d............................................................................................................ 1 1.3 Study Technical Objectives.................................................................................... 3 2.0 Arctic Stru ctures ........................................................................................................ 4 2.1 Evolution of Arctic Stru ctures & Fa cilities............................................................... 4 2.2 Primary Design & Operat ion Consider ations.......................................................... 8 2.2.1 Ice Loads ........................................................................................................ 8 2.2.1.1 Full-Scale Ice Load Measurements ......................................................... 8 2.2.1.2 Geotechnical M onitori ng.......................................................................... 8 2.2.1.3 First-Year Ice Loads ................................................................................ 9 2.2.1.4 Hans Island Experiments & Multi-year Ic e Impac ts.................................10 2.2.1.5 Pipeline Consi derations..........................................................................11 2.2.2 Wave Loads...................................................................................................11 2.2.3 Earthquak e ....................................................................................................12 2.2.4 Foundation Reac tion L oads...........................................................................12 2.2.5 Facilities Functiona l Consider ations ..............................................................12 2.2.5.1 Deck Ar ea...............................................................................................13 2.2.5.2 Oil Storage & Tr ansportati on ..................................................................13 2.2.5.3 Dry Stor age ............................................................................................14 2.2.5.4 Environmenta l Safe ty..............................................................................14 2.2.6 Ice Gouge E ffects ..........................................................................................14 3.0 Review of Exploration & Development Options .................................................... 16 3.1 General .................................................................................................................16 3.2 Analogue Area Se lection ......................................................................................17 3.2.1 Selected Areas ..............................................................................................17 3.2.1.1 Cook In let ...............................................................................................17 3.2.1.2 Canadian High North ..............................................................................19 3.2.1.3 Canadian East Coast..............................................................................19 3.2.1.4 Offshore Gr eenland ................................................................................20 3.2.1.5 Eastern Russia (Sak halin Isla nd)............................................................20 3.2.1.6 Russian Arctic (Barents, Kara s, Pechora, and Baltic).............................21 3.2.2 Screened Ar eas .............................................................................................24 3.2.2.1 North Casp ian.........................................................................................24IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page vii of xxvi Rev. 0 3.2.2.2 Other Areas ............................................................................................25 3.3 Analogue Exploration & De velopment Op tions .....................................................25 3.3.1 Bottom-Founded & Fixed Structures..............................................................25 3.3.1.1 Sakhalin Island .......................................................................................25 3.3.1.2 Russian Ar ctic.........................................................................................33 3.3.1.3 Canadian East Coast..............................................................................36 3.3.1.4 Cook In let ...............................................................................................42 3.3.1.5 Jack-up Drilli ng Rigs ...............................................................................46 3.3.2 Floating Stru ctures.........................................................................................48 3.3.2.1 Canadian East Coast..............................................................................48 3.3.2.2 Canadian High Arctic..............................................................................62 3.3.2.3 Russian Ar ctic.........................................................................................66 3.3.2.4 Sakhalin Island .......................................................................................67 3.3.2.5 Offshore Gr eenland ................................................................................69 3.3.2.6 Semi-rigid Float er Conc ept .....................................................................71 3.3.2.7 Monocone Arctic Pl atform (M CAD).........................................................73 3.3.2.8 Conventional Floating Expl oration Stru ctures.........................................74 3.3.2.9 Henry Goodr ich.......................................................................................77 3.3.3 Subsea Solu tions...........................................................................................78 3.3.3.1 Canadian East Coast..............................................................................78 3.3.3.2 PanArctic Drake......................................................................................79 3.3.3.3 Russian Ar ctic.........................................................................................80 3.3.4 Pipelin es ........................................................................................................80 3.3.4.1 PanArctic Drake......................................................................................80 3.3.4.2 Polar Gas Project....................................................................................83 3.3.4.3 Baydaratskaya Ba y (Russi a) ..................................................................89 3.3.4.4 Nord Stream Pipel ine (Ru ssia) ...............................................................90 3.3.4.5 Canadian East C oast Flow lines..............................................................92 3.3.4.6 Sakhalin Island .......................................................................................95 3.3.5 Export Termi nals............................................................................................96 3.3.5.1 Canadian Ar ctic ......................................................................................96 3.3.5.2 Russia .....................................................................................................97 3.3.6 Extended Reach Drilling ..............................................................................104 3.3.7 Other Technological Advancements ............................................................104 3.3.7.1 Well Intersecti on Method ......................................................................104 3.3.7.2 Pilot Hole to P ilot Hole HDD .................................................................105IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page viii of xxvi Rev. 0 3.3.7.3 Arctic Offshor e Vessels ........................................................................106 3.4 Alaska OCS Exploration & Development Options...............................................108 3.4.1 Bottom-Founded & Fixed Structures............................................................108 3.4.1.1 General.................................................................................................108 3.4.1.2 Tarsiut Cai ssons...................................................................................112 3.4.1.3 SSDC & SSDC/MAT ( now SDC) ..........................................................112 3.4.1.4 CRI – Caisson-Reta ined Isl and ............................................................113 3.4.1.5 Molikpaq Mobile Arctic Caisson (MAC).................................................114 3.4.1.6 Concrete Island Drilling System (C IDS)................................................114 3.4.1.7 Barge Struct ures...................................................................................116 3.4.1.8 GBS Struct ures.....................................................................................118 3.4.2 Jacket Struct ures .........................................................................................119 3.4.3 Ice & Gravel Isl and Structur es .....................................................................119 3.4.3.1 Grounded Artificial Ice Isl ands ..............................................................120 3.4.3.2 Gravel Is lands....................................................................................... 126 3.4.4 Floating Stru ctures.......................................................................................134 3.4.4.1 Drillships ...............................................................................................134 3.4.4.2 Semi-Submers ibles...............................................................................137 3.4.4.3 FPSO....................................................................................................138 3.4.5 Subsea Solu tions.........................................................................................138 3.4.6 Pipelines ......................................................................................................138 3.4.6.1 BP Alaska Nort hstar .............................................................................138 3.4.6.2 Pioneer O ooguruk.................................................................................143 3.4.6.3 Nikaitchuq .............................................................................................145 3.4.6.4 BP Alaska Li berty .................................................................................145 3.4.6.5 Chukchi Sea Pipel ine Studi es...............................................................146 3.4.6.6 Bering Se a............................................................................................148 3.4.6.7 Mackenzie Delta (Dome, Esso, Gulf Canada) ......................................148 3.4.6.8 Amauligak .............................................................................................149 3.4.6.9 East & West Amaulig ak Pipelin es.........................................................150 3.4.7 Extended Reach Drilling ..............................................................................150 3.5 Summary - Exploration & Deve lopment Options Review ....................................151 4.0 Assessment of Options ......................................................................................... 153 4.1 Approach .............................................................................................................153 4.2 OCS Scenar ios ...................................................................................................153 4.3 Metocean/Ice Cons iderati ons..............................................................................155IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page ix of xxvi Rev. 0 4.3.1 Beaufort and Chu kchi Seas .........................................................................155 4.3.2 Bering Sea and South..................................................................................155 4.4 Geotechnical Cons iderati ons ..............................................................................156 4.5 Bottom-Founded Stru ctures................................................................................157 4.5.1 Ice and Wave s .............................................................................................157 4.5.2 Foundation Condi tions.................................................................................158 4.5.3 Location Scenarios for Pr oposed Struct ures................................................159 4.5.4 Technical Feasibility of Struct ures ...............................................................162 4.5.4.1 Ice Loads ..............................................................................................162 4.5.4.2 Foundations ..........................................................................................164 4.5.4.3 Steel vs. C oncrete ................................................................................166 4.5.4.4 Wave Load s..........................................................................................167 4.5.4.5 Gravity & Foundation Reaction L oads ..................................................170 4.5.4.6 Vibratory Loads .................................................................................... 171 4.5.4.7 Seismic Lo ads ......................................................................................171 4.5.4.8 Fatigue Loading, Brittle Fracture , & Temperature Effects.....................172 4.5.4.9 Oil Storage E ffects................................................................................172 4.5.4.10 Platform Conc epts ................................................................................173 4.5.5 Constructabi lity ............................................................................................183 4.5.5.1 Foundation I ssues ................................................................................184 4.5.5.2 Weather Window ..................................................................................184 4.5.6 Capital Co sts ...............................................................................................184 4.5.7 Environmental Cons iderati ons.....................................................................190 4.5.8 Operations, Maintenanc e, & Repai r.............................................................191 4.5.9 Abandonment & Deco mmissioning ..............................................................191 4.6 Jacket & Jack-up St ructures ...............................................................................192 4.6.1 Technical Feas ibility.....................................................................................193 4.6.1.1 Arctic Jacket Structure De sign Consider ations.....................................193 4.6.1.2 Arctic Jacket Struct ure Enhancem ents.................................................196 4.6.1.3 Assessment of Jacke t Platfo rm ............................................................196 4.6.2 Constructabi lity ............................................................................................198 4.6.3 Capital Co sts ...............................................................................................198 4.6.4 Environmental Cons iderati ons.....................................................................198 4.6.5 Operations, Maintenanc e, & Repai r.............................................................199 4.6.6 Abandonment & Deco mmissioning ..............................................................199 4.6.7 Commentary on Jack-ups ............................................................................200IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page x of xxvi Rev. 0 4.7 Ice Isl ands........................................................................................................... 203 4.7.1 Technical Feas ibility.....................................................................................203 4.7.1.1 Feasibility of Sele cted Scenar ios..........................................................208 4.7.2 Constructabi lity ............................................................................................211 4.7.3 Capital Co sts ...............................................................................................214 4.7.4 Environmental Cons iderati ons.....................................................................215 4.7.5 Operations, Maintenanc e, & Repai r.............................................................216 4.7.6 Abandonment & Deco mmissioning ..............................................................216 4.8 Gravel Is lands .....................................................................................................217 4.8.1 Technical Feas ibility.....................................................................................218 4.8.1.1 Feasibility of Sele cted Scenar ios..........................................................222 4.8.2 Constructabi lity ............................................................................................223 4.8.3 Capital Co sts ...............................................................................................224 4.8.4 Environmental Cons iderati ons.....................................................................225 4.8.5 Operations, Maintenanc e, & Repai r.............................................................226 4.8.6 Abandonment & Deco mmissioning ..............................................................226 4.9 Floating Stru ctures..............................................................................................227 4.9.1 Technical Feas ibility.....................................................................................228 4.9.1.1 Ice Loads ..............................................................................................229 4.9.1.2 Wave Load s..........................................................................................231 4.9.1.3 Dynamic Positi oning .............................................................................234 4.9.1.4 Mooring.................................................................................................235 4.9.1.5 Steel vs. C oncrete ................................................................................236 4.9.1.6 Seismic .................................................................................................237 4.9.1.7 Oil Stor age............................................................................................237 4.9.1.8 Floating Platform Concepts ..................................................................237 4.9.1.9 Assessment by Ala skan OCS Ar ea ......................................................238 4.9.2 Exploration Operability in the Alask an OCS.................................................239 4.9.2.1 Beaufort Sea O perability .......................................................................239 4.9.2.2 Chukchi Sea O perability .......................................................................240 4.9.2.3 Southern Bering Sea Operabilit y ..........................................................240 4.9.3 Constructabi lity ............................................................................................241 4.9.4 Capital Co sts ...............................................................................................241 4.9.5 Environmental Cons iderati ons.....................................................................242 4.9.6 Operations, Maintenanc e, & Repai r.............................................................242 4.9.7 Abandonment & Deco mmissioning ..............................................................242IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xi of xxvi Rev. 0 4.10 Subsea Solu tions................................................................................................243 4.10.1 Technical Feas ibility.....................................................................................243 4.10.1.1 Subsea Tie backs ..................................................................................243 4.10.1.2 Glory Holes & Pr otection ......................................................................244 4.10.1.3 Feasibility of Applicati on of Subsea Technology at Location Scenarios .... ..............................................................................................................246 4.10.2 Constructabi lity ............................................................................................249 4.10.3 Capital Co sts ...............................................................................................249 4.10.4 Environmental Cons iderati ons.....................................................................250 4.10.5 Operations, Maintenanc e, & Repai r.............................................................250 4.10.6 Abandonment & Deco mmissioning ..............................................................251 4.11 Pipelines & Fl owlines ..........................................................................................251 4.11.1 Technical Feas ibility.....................................................................................252 4.11.1.1 Design I ssues .......................................................................................252 4.11.1.2 Feasibility of Sele cted Scenar ios..........................................................260 4.11.2 Constructabi lity ............................................................................................267 4.11.2.1 Winter Construction vs. O pen Water Constr uction ...............................267 4.11.2.2 Permafrost & Tr enchability ...................................................................268 4.11.2.3 Trenching Equi pment............................................................................268 4.11.2.4 Pipeline Insta llation ...............................................................................272 4.11.2.5 Trenching & Ba ckfill..............................................................................273 4.11.3 Capital Co sts ...............................................................................................274 4.11.4 Environmental Cons iderati ons.....................................................................275 4.11.5 Operations ...................................................................................................276 4.11.6 Maintenance & Repair .................................................................................277 4.11.6.1 Monitoring & Main tenance ....................................................................277 4.11.6.2 Repair...................................................................................................277 4.11.7 Abandonment & Deco mmissioning ..............................................................279 4.12 Export Termi nals.................................................................................................279 4.12.1 General Require ments.................................................................................279 4.12.2 Technical Feas ibility.....................................................................................280 4.12.3 Constructability & Capital Co sts...................................................................282 4.12.3.1 General Marine Terminal Concepts for Arctic & Sub-Arct ic Conditions 282 4.12.3.2 Offshore TLU Alte rnatives ....................................................................283 4.12.4 Environmental Cons iderati ons.....................................................................285 4.12.5 Operations ...................................................................................................286IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xii of xxvi Rev. 0 4.12.6 Maintenance & Repair .................................................................................287 4.12.7 Abandonment & Deco mmissioning ..............................................................288 4.13 Other Technol ogies.............................................................................................288 4.13.1 Extended Reach Drilling ..............................................................................288 4.13.1.1 Technical Feas ibility .............................................................................288 4.13.1.2 Constructabi lity .....................................................................................290 4.13.1.3 Capital Co sts ........................................................................................290 4.13.1.4 Environmental Cons iderations..............................................................290 4.13.1.5 Operations, Maintenanc e, & Repai r......................................................291 4.13.1.6 Abandonment & Deco mmissioning .......................................................291 4.13.2 Well Intersection Me thod (WIM )...................................................................291 4.13.2.1 Technical Feas ibility .............................................................................291 4.13.2.2 Constructabi lity .....................................................................................292 4.13.2.3 Capital Co sts ........................................................................................293 4.13.2.4 Environmental Cons iderations..............................................................293 4.13.2.5 Operations, Maintenanc e, & Repai r......................................................293 4.13.2.6 Abandonment & Deco mmissioning .......................................................293 4.13.3 Pilot Hole to P ilot Hole HDD ........................................................................293 4.13.3.1 Technical Feas ibility .............................................................................293 4.13.3.2 Constructabi lity .....................................................................................294 4.13.3.3 Capital Co sts ........................................................................................294 4.13.3.4 Environmental Cons iderations..............................................................294 4.13.3.5 Operations, Maintenanc e, & Repai r......................................................294 4.13.3.6 Abandonment & Deco mmissioning .......................................................295 5.0 Summary, Conclusions a nd Recommendat ions ................................................. 296 5.1 Overview .............................................................................................................296 5.2 Assessment Me thodology ...................................................................................296 5.3 Summary & Conc lusions.....................................................................................297 5.3.1 Bottom-Founded Stru ctures.........................................................................297 5.3.1.1 Design Consi derations..........................................................................298 5.3.1.2 Technical Feasibility of Struct ures ........................................................298 5.3.1.3 Capital Co sts ........................................................................................300 5.3.2 Jacket & Jack-up St ructures ........................................................................300 5.3.3 Ice Isl ands....................................................................................................301 5.3.3.1 Technical Feas ibility .............................................................................301 5.3.3.2 Constructi on .........................................................................................302IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xi ii of xxvi Rev. 0 5.3.3.3 Capital Co st ..........................................................................................303 5.3.4 Gravel Is lands..............................................................................................303 5.3.4.1 Technical Feas ibility .............................................................................303 5.3.4.2 Feasibility of Sele cted Scenar ios..........................................................304 5.3.4.3 Constructabi lity .....................................................................................304 5.3.5 Floating Stru ctures.......................................................................................305 5.3.5.1 Exploration............................................................................................305 5.3.5.2 Production ............................................................................................305 5.3.5.3 Alaskan OC S ........................................................................................306 5.3.6 Subsea Solu tions.........................................................................................307 5.3.6.1 Subsea Tie backs ..................................................................................307 5.3.6.2 Subsea Facilities Protecti on .................................................................308 5.3.7 Pipelines & Fl owlines ...................................................................................308 5.3.7.1 Design ..................................................................................................309 5.3.7.2 Installati on ............................................................................................310 5.3.7.3 Operati ons ............................................................................................310 5.3.8 Export Termi nals..........................................................................................311 5.3.8.1 Technical Feas ibility .............................................................................311 5.3.9 Other Technol ogies .....................................................................................312 5.3.9.1 Extended Reach Dr illing (E RD) ............................................................312 5.3.9.2 Well Intersection Me thod (WIM ) ...........................................................312 5.3.9.3 Pilot Hole to P ilot Hole HDD .................................................................313 5.4 Recommendat ions ..............................................................................................313 5.4.1 Ice and Metocean In formation .....................................................................313 5.4.2 Perceived Gaps ...........................................................................................313 6.0 Acknowledgeme nts ............................................................................................... 315 7.0 Referenc es.............................................................................................................. 316 Appendix A: Metocean & Ice Data Appendix B: Geotechnical Considerations Appendix C: Drilling Activities in the Alaskan OCS & Canadian Arctic Appendix D: Environmental Conditions & Operations: Contemporary Russian ExperienceIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xiv of xxvi Rev. 0 LIST OF FIGURES
Figure 2-1: Arctic Caiss on Drilling St ructures....................................................................... 4 Figure 2-2: Evolution of Arctic Structure Loads and Fo undation Requi rements................... 6 Figure 2-3: Evolution of Ice Loads on Arctic Structure ......................................................... 7 Figure 2-4: First-Year Ice Loads (Blanchet and K ennedy, 199 6) ........................................10 Figure 3-1: Oil and Gas Fields of Barent s and Kara Seas (Ima yev et al ., 2005).................22 Figure 3-2: Orlan Platform off of Sak halin (from PennWell Publishing , 2007).....................26 Figure 3-3: The Molikpaq Platform as part of the Vityaz Production Complex (Calitz and Mercer, n.d.).................................................................................................................2 7 Figure 3-4: Sakhalin Island, PA-A, PA- B and Lun-A (Sakhalin Energy, 2007) ....................28 Figure 3-5: The Piltun Astokh-A (SPG Media Limi ted, 2007f) .............................................30 Figure 3-6: Installation of PA-B Platform, Sakhalin 2 (JSC Gazpro m, 2007a).....................31 Figure 3-7: LUN-A Platfo rm (JSC Gazp rom, 2007a) ...........................................................3 2 Figure 3-8: Prirazlomnoye Platform (Mads lien, 2006) .........................................................36 Figure 3-9: Hibernia Drilling and Produc tion Platform with OLS (Bot t, 2004) ......................37 Figure 3-10: Hibernia Pl atform (HM DC, 2007) ....................................................................38 Figure 3-11: Steel Stepped Grav ity Base St ructure ............................................................40 Figure 3-12: Cook Inlet Infr astructure (C IRCAC, 2007).......................................................42 Figure 3-13: Conventional Ja cket Structure (OOP, 2007)...................................................4 3 Figure 3-14: Cook Inlet Jacket Structure (CIR CAC, 2007 )..................................................43 Figure 3-15: Ice Resistant Jack-up Arktiche skaya 6500 / 10-30 (JSC Gazprom, 2007b)....48 Figure 3-16: Grand Banks Field De velopments (H owell, 2007) ..........................................49 Figure 3-17: Terra Nova Field De velopment (Petro -Canada, 2007a)..................................5 0 Figure 3-18: Open Glory Ho le (Petro-C anada, 2007a) ........................................................51 Figure 3-19: Terra Nova F PSO (Petro-C anada, 2007a)......................................................5 2 Figure 3-20: Comparison of Mooring Capabilities (fro m PERD, 1998)................................54 Figure 3-21: White Rose Field Deve lopment Schematic (Clarke, 2001) .............................55 Figure 3-22: Typical White Rose Glory Hole ( Lochte, 2007) ...............................................56 Figure 3-23: SeaRose FPSO (Hu sky, 2007a) .....................................................................56 Figure 3-24: SeaRose Offloading to S huttle Tanker (H owell, 2007)....................................58 Figure 3-25: Design Concept of Drillships “Pelic an”, “Pelerin”, “Petrel”, “BenOcean Lancer”, and “Neddrill 2” (Gusto MSC, n.d.)................................................................................60 Figure 3-26: Additional Design Details of “Pe lican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, and “Neddrill 2” (Gusto MSC, n.d.)................................................................................61 Figure 3-27: SPAR Concept for O ffshore Canada (from Murray, 2004)..............................63IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xv of xxvi Rev. 0 Figure 3-28: Disconnected SPAR (from Murr ay, 2004) .......................................................63 Figure 3-29: Cross-Section of Cape Alison Fl oating Spray Ice Pad (Masterson et al., 1987)

............................................................................................................................... ......64 Figure 3-30: “Smit Sakhalin” Connected up to SALM Production Buoy Preparing for Winter Lay Down Operations (C ourtesy of DC Marine)...........................................................68 Figure 3-31: SALM Buoy Ice Up After St orm Event (Courtesy of DC Marine).....................68 Figure 3-32: FSO “Okha” Connected up to Production SALM Buoy, Late Season (Courtesy of DC Ma rine) ...............................................................................................................69 Figure 3-33: Atammik and Lady Franklin Ex ploration Licenses (Cooper, 2005)..................70 Figure 3-34: Potential Devel opment Scenario Offshore West Greenland (Cooper, 2005) ..70 Figure 3-35: Arctic Se mi-rigid Fl oater..................................................................................72 Figure 3-36: MCAD Pla tform (Paganie, 2007).....................................................................73 Figure 3-37: “Vidar Viking” Equipped with Co mpact Drill Rig, in the Central Polar Pack (Keionen et al., 2007) ...................................................................................................75 Figure 3-38: Eirik Raude (Ocean Rig AS A, 2007) ...............................................................76 Figure 3-39: Henry Goodr ich (Toolpusher , 2007)................................................................77 Figure 3-40: Drake Proj ect Locati on Map............................................................................80 Figure 3-41: Drake Flowline B undle (Palmer et al., 1979)...................................................8 1 Figure 3-42: Polar Gas Channel Crossings (modified from K austinen, 1981).....................86 Figure 3-43: Ice Island Bottom Pull Method (from K austinen, 1981) ...................................87 Figure 3-44: Ice Hole Bottom Pull Method (from K austinen, 1981) .....................................88 Figure 3-45: Polar Gas Foreshore T unnel Concept (from Kaustinen, 1981) .......................89 Figure 3-46: Proposed Pipeline Location (N ord Stream , 2007)...........................................90 Figure 3-47: The Average Ice Extent duri ng Mild, Normal, and Severe Winters, Respectively (Nor d Stream , 2006) ...............................................................................92 Figure 3-48: Terra Nova Flowline Prot ection (Courtesy of Tideway, 2007).........................94 Figure 3-49: Technical and Economi c Evaluation of Alternatives for Oil Transportation from Timano-Pechora Province, Kryl ov Institute Development (K rylov Institute, n.d.) .........98 Figure 3-50: Varandey TLU, General Conc ept (Krylov Instit ute, n.d.) ...............................102 Figure 3-51: New Oil Terminals in the Gulf of Finland (Panin and Rode, 2003)................103 Figure 3-52: Buckinghorse River Valley Crossing (from Sm ith, 2004). .............................105 Figure 3-53: “Tempera” in Icebreaking Mode (SPG Media Li mited, 2007h)......................107 Figure 3-54: Tarsiut Concrete Caissons dur ing Installation an d in Service .......................112 Figure 3-55: SSDC (left), MAT Substructure (Top Right), SSDC/MAT (Bottom Right)......113 Figure 3-56: Esso’s Caisson- Retained Island (CRI)..........................................................114 Figure 3-57: Molikpaq in the Beaufort Sea and as-Modified fo r Sakha lin..........................115IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xvi of xxvi Rev. 0 Figure 3-58: CIDS in t he Beaufort and Under Tow to Sakhalin Island ..............................115 Figure 3-59: Niglintgak Barge Processing Facilit y (from Mackenzie Gas Project, 2004)...117 Figure 3-60: Proposed Placement of Niglintgak Gas Processing Facility on Seasonal Flood Plane (from Mackenzie Gas Projec t, 2006)................................................................117 Figure 3-61: Taglu Field Development (f rom Mackenzie Gas Project, 2006)....................118 Figure 3-62: Statfjord C under Construction (Sta toil ASA, 2007) ......................................119 Figure 3-63: Four plus Four Template Jacke t (modified from PMB S ystems Engineering et al., 1983) ....................................................................................................................1 20 Figure 3-64: Tarsiut Relief Spra y Ice Island (ICE TECH, 2008) .........................................122 Figure 3-65: Mars Spray Ic e Island (C-COR E, 2005) ........................................................123 Figure 3-66: Cost Comparison between Grav el and Ice Islands (C -CORE, 2005)............124 Figure 3-67: Alaskan Beaufort Sea Manmade Is lands (modified from US Army Corps of Engineers, 1999) ........................................................................................................128 Figure 3-68: Basic Designs for Granular Fill Artificial Islands in the Canadian Beaufort ...130 Figure 3-69: Imperial Oil’s Arnak L-30 S eptember 1976 Showing Wave Action on the Sacrificial Beach Island Design (fro m Croasdale and Marce llus, 19 77).....................131 Figure 3-70: Northstar Producti on Island (Thomas , n.d.) ..................................................132 Figure 3-71: Oooguruk Producti on Island (INT EC, 2007) ..................................................133 Figure 3-72: Endicott Production Island (Thomas, n.d.) ....................................................133 Figure 3-73: “Nort hern Explorer II” (formerly the C ANMAR Explorer II and Explorer II) (WorldOil, 2000) .........................................................................................................134 Figure 3-74: Kulluk (Cour tesy of DC Ma rine) ....................................................................135 Figure 3-75: The Kulluk - Oper ations with Icebreaker Support (Courtesy of DC Marine)..136 Figure 3-76: Ocean Odyssey (N ationMaster, 2005).......................................................... 137 Figure 3-77: Northstar and Liber ty Project Location Map (from Lanan et al., 2001)..........139 Figure 3-78: Approximate Locations, Mackenzie De lta Developm ent ...............................149 Figure 4-1: Assessment Study Areas wit h 2007-2012 Proposed Fina l Program Areas (modified from MMS , 2007c) ......................................................................................154 Figure 4-2: Wave Load Comparison of Hibernia-type GBS vs. Stepped-style GBS (Fitzpatrick and K ennedy, 1997) ................................................................................170 Figure 4-3: Drawing No.1, Option No.1 – Pla tform and Foundation for 33 ft (10 m) of Water

............................................................................................................................... ....177 Figure 4-4: Drawing No.2, Option No.4 – 660 ft (200 m) Plus Mobile Exploration Concept

............................................................................................................................... ....178 Figure 4-5: Drawing No.3, Option No.5 – Pl atform and Foundation for 100 ft (30 m) of Water .........................................................................................................................1 79IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xvii of xxvi Rev. 0 Figure 4-6: Drawing No.4, Option No.9 – 445 ft (135 m) Stepped St eel Structure............180 Figure 4-7: Drawing No.5, Option No.10 – 330 ft (100 m) Stepped Steel Structure..........181 Figure 4-8: Drawing No.6, Option No.11 – 100 ft (30 m) Storage Hu ll Transverse Section and Design Part iculars...............................................................................................182 Figure 4-9: Estimated 2007 Installed Platform Co sts (USD), Platform Only Contracted to Shipyard, Exclusive of Topsi des ................................................................................190 Figure 4-10: Unocal's Monopod Jacket Platform, Cook Inlet (Courtesy of CIRCAC, 2007)

............................................................................................................................... ....193 Figure 4-11: Sea Ice Loading a Jacket Leg, C ook Inlet (Courtesy of CIRCAC, 2007) ......195 Figure 4-12: Gorilla Class Jack-up (LeTourneau Technolo gies, 2007) .............................200 Figure 4-13: Positioning of Leg Hori zontals to Avoi d Sea Ic e............................................201 Figure 4-14: Typical Ice Thickness Growth for Canadian Beaufort Sea (Modified from CCORE, 200 5) .............................................................................................................204 Figure 4-15: Spray Ice Island Potential Failur e Modes (Modified from C-CORE, 2005)....206 Figure 4-16: Spray Ice Production - Thetis Ice Island Project (C-COR E, 2005) ................212 Figure 4-17: Cost of Ice Island vs. Gravel Islands (Reproduced from C-CORE, 2005).....215 Figure 4-18: Northstar Island dur ing Summer (Cola ska, 2007) .........................................217 Figure 4-19: Northstar Production Island Ic e Protection Design (BPXA, 2005 ).................219 Figure 4-20: Ice Clearing on Nort hstar Island (Col aska, 2007) .........................................220 Figure 4-21: Basic Designs for Gr anular Fill Artificial Islands used in the Canadian Beaufort (drawn with an approximate vertical exagger ation of 3 times) (also presented in Section 3.4.3.2 as Figure 3- 68)..................................................................................221 Figure 4-22: Proposed Liberty Production Island Slope Protection Design (dimensions are approximate) (M MS, 2002) ........................................................................................221 Figure 4-23: Peak Loads in Managed Ice - Effect of Ice Concentration on Various Structure Types (Reproduced from Co mfort et al ., 2001)..........................................................232 Figure 4-24: 100 year Return Wave Conditi ons in Area of Study; Grand Banks added for Comparis on................................................................................................................233 Figure 4-25: Approximate Desi gn Wave Loads - FPSO Basis (N ote: wave loads for the Beaufort and Chukchi are for summer condit ions and are not meant to imply year round FPSO operat ions) ............................................................................................234 Figure 4-26: Rough Comparison of selected Vessel Mooring S ystems; with selected Ice Breaker Bollard Thrust for compar ison (Comfort et al., 2 001)....................................236 Figure 4-27: Glory Hole (Fro m Coflexip St ena, 2000) .......................................................247 Figure 4-28: Mechanical Subsea Facilities Prot ection Concept for Water Depths to 30 m in the Canadian Beauf ort Sea........................................................................................247IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xvi ii of xxvi Rev. 0 Figure 4-29: Ice Gouge and S ubgouge Deformat ion.........................................................254 Figure 4-30: Subsea Pipeline Upheaval Buckling (After Pa lmer et al ., 1990)....................257 Figure 4-31: Strudel Scour (Courtesy of Minerals Management Service) .........................258 Figure 4-32: Ice Gouge Depth vs. Water De pth, Combined New & Unknown Age Gouge Data from the Alask an Beaufort Sea..........................................................................264 Figure 4-33: Ice Gouge Depth vs. Water Depth, Known Age Gouge Data from the Alaskan Beaufort Se a ..............................................................................................................265 Figure 4-34: Ice Gouge Depth vs. Water De pth, Unknown Age Gouge Data from the Chukchi Se a...............................................................................................................266 Figure 4-35: Typical Subsea Plow (Cour tesy of SMD Hydrov ision, 2007).........................270 Figure 4-36: Typical Jet Sled (Cour tesy SMD Hydrovis ion, 2007) ....................................271 Figure 4-37: Typical Subsea Mechanical Trencher (Courtesy of Rocksaw International, 2004).......................................................................................................................... 272 Figure 4-38: Ice Breaker “Smit Sibu” Providi ng Ice Management Operations for SALM Buoy Lay Down Operations on Sakhalin 2 (Courtesy of Don Connelly)..............................284 Figure 4-39: The Sakhalin 1 Fixed Tower SPM Sits 61 m above the Seabed (Courtesy of PennWell Publis hing, 2007) .......................................................................................284 Figure 4-40: Icebreaker and Tanker Trials at Sakhalin (Court esy of PennWell Publishing, 2007).......................................................................................................................... 287 Figure 4-41: Well Reach vs. Time (Department of Natura l Resources, 1999)...................289IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xi x of xxvi Rev. 0 LIST OF TABLES
Table 2-1: SDC Drilling Locati on Ice Loads (Hewi tt et al ., 1994).......................................... 9 Table 3-1: Analogue Areas Selected for Review .................................................................18 Table 3-2: Sakhalin Fact Sheet (source EIA, 2007) ............................................................21 Table 3-3: Summary of Cook In let Platforms (C IRCAC, 2007)............................................45 Table 3-4: LeTourneau Super Gorilla O perating Parameters (from LeTourneau Technologies , 2007) .....................................................................................................47 Table 3-5: Floating Ice Pads Constr ucted in the Canadi an High Ar ctic...............................65 Table 3-6: Grand Banks Canada Glory Hole Dimensions (Technip, 2001) .........................79 Table 3-7: Deployments of Bottom-Founded Struct ures in the Beaufort Sea (by year).....110 Table 3-8: Deployments of Bottom-Founded Struct ures in the Beaufort Sea (by name)...111 Table 3-9: Summary of Grounded Artifi cial Ice Island Co nstructi on ..................................125 Table 3-10: Exploratory Drilling Islands used in the Canadian Beaufort Sea (from Timco, 1998).......................................................................................................................... 127 Table 3-11: Summary of Arctic and Cold Regi ons Exploration & Development Options...151 Table 4-1: Location Scenarios – Bottom-Founded Stru ctures...........................................161 Table 4-2: Approximate Ice Load R anges, Beaufort and C hukchi S eas............................164 Table 4-3: Table of Wave and Ice Loads Us ed in Materials and Co st Estimation .............169 Table 4-4: Platform Particul ars Options 1 to 4...................................................................174 Table 4-5: Platform Particul ars Options 5 to 8...................................................................175 Table 4-6: Platform Particul ars Options 9 to 12.................................................................176 Table 4-7: Estimated 2007 Installed Platform Co sts, in Millions of USD, Exclusive of Topsides Costs if Platform Only is Cont racted to Shipyard, Op tions 1 to 4................186 Table 4-8: Estimated 2007 Installed Platform Co sts, in Millions of USD, Exclusive of Topsides Costs if Platform Only is Cont racted to Shipyard, Op tions 5 to 8................187 Table 4-9: Estimated 2007 Installed Platform Co sts, in Millions of USD, Exclusive of Topsides Costs if Platform only is Contra cted to Shipyard, Op tions 9 to 12 ..............188 Table 4-10: Historic Bering Sea Wells Dri lled by Jack-up Platfo rms (MMS, 2007a)..........202 Table 4-11: Comparative Feasibility of Ic e Island Construction in the Beaufort Sea and Norton Soun d.............................................................................................................209 Table 4-12: Construction Times for O perational Islands (C-CORE, 2005)........................213 Table 4-13: OCS Gravel Island Assessment – Approximately 33 ft (10 m) Water Depth..222 Table 4-14: Feasibility of Applicable Fl oating Technologies in Study Ar eas......................239 Table 4-15: Project Capital Costs for Select ed Developments at Time of Completion or Proposal (U SD)..........................................................................................................242IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xx of xxvi Rev. 0 Table 4-16: Overall Glory Hole Dimensions (Tec hnip, 2 001) ............................................248IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xxi of xxvi Rev. 0 LIST OF ACRONYMS

3D: Three Dimensional
ACEX: Arctic Coring Expedition

AGPPT: Alaska Gas Pr oducers Pipeline Team

API: American Petroleum Institute

AZIPOD: Azimuth Thruster

BAT: Best Available Technology

Bbl: Barrel

BCF: Billion Cubic Feet

BOP: Blowout Preventer
BOPB: Barrels of Oil per Day

Bpd: Barrels per Day

BPXA: British Petroleum Exploration Alaska

CAC: Canadian Arctic Class
CALM: Catenary Anchor Leg Mooring

CANMAR: Canadian Ma rine Drilling Ltd.
CGB: Concrete Gravity Base
CIDS: Concrete Island Drilling System
CNG: Compressed Natural Gas

CRI: Caisson Retained Island

CSA: Canadian Standards AssociationIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xxii of xxvi Rev. 0 CSO: Coflexip Stena Offshore

DAT: Double Acting Tankers

DNV: Det Norske Veritas
DP: Dynamically Positioned
DP3: Class 3 Dynamic Positioning System

DWT: Deadweight Tonnage

EIS: Environmen tal Impact Statement

ERD: Exten ded Reach Drilling
FEIS: Final Environmental Impact Statement
FOIRLT: Fixed Offshore Ice Resistant Loading Terminal
FPSO: Floating Production Storage and Offloading
FS: Factor of Safety (or Safety Factor)
FSO: Floating Storage and Offloading
FSU: Floating Storage Unit

ft: Foot
GBS: Gravity Base Structure

GTM: Gas Transfer Module

HDD: Horizontal Directional Drilling

IACS: International Associat ion of Classification Societies

IMO: International Maritime Organization

in: InchIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xxi ii of xxvi Rev. 0 KBPD: Thousand Barrels per Day
kg: Kilogram

Kips: Kilopound

km: Kilometer

kPa: Kilopascal
ksf: Kilopound per Square Foot
ksi: Kilopound per Square Inch
LNG: Liquefied Natural Gas

Lun-A: Lunskoye A

m: Meter

MAC: Mobile Arctic Caisson

MAOP: Maximum Allowabl e Operating Pressure

MBM: Multiple Buoy Mooring

MCAD: Monocone Arctic Platform

MD: Measured Depth

mm: Millimeter

MM: Million

MMbbls: Million Barrels
MN: Meganewton
MPa: Megapascal
MMS: Minerals Management ServiceIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xxiv of xxvi Rev. 0 MMSCF: Million Standard Cubic Feet

MMSCFD: Million Standar d Cubic Feet per Day

MODU: Mobile Offs hore Drilling Unit

MOU: Memorandum of Understanding

MV: Motor Vessel
MW: Megawatt

n.d.: No Date
NDT: Non-Destructive Testing

OCS: Outer Continental Shelf
OLAC: Online Accelerated Cooling
OLS: Offshore Loading System
OSER: Operational Safety and Engineering Research
OSR: Oil Spill Response

PA: Piltun-Astokhskoye

PA-A: Piltun Astokh-A

PA-B: Piltun Astokh-B

PIP: Pipe-in-Pipe
psi: Pounds per Square Inch
R&D: Research and Development
RFP: Request for Proposal
ROV: Remotely Operated VehicleIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xxv of xxvi Rev. 0 SALM: Single Anchor Leg Mooring
SCADA: Supervisory Control and Data Acquisition
SDC: Steel Drilling Caisson
SET: Solid Expendable Tubular
SPM: Single Point Mooring
SSDC: Single-Steel Drilling Caisson
SSGB: Steel Stepped Gravity Base
STL: Submerged Turret Loading
TA&R: Technology Assessment and Research
TAPS: Trans Alaska Pipeline System

TCF: Trillion Cubic Feet
TLP: Tension Leg Platform

TLU: Tanker Loading Unit

Ton: Short Ton

Tonne: Metric Tonne

TVD: True Vertical Depth

USD: United States Dollar (Currency)

VCG: Vertical Ce nter of Gravity

VIV: Vortex-I nduced Vibration
VLCC: Very Large Crude Carrier

WIM: Well Intersection MethodIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page xxvi of xxvi Rev. 0 W.T.: Wall ThicknessIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 1 of 339 Rev. 0 1.0 INTRODUCTION

1.1 Introduction & Overview

Offshore hydrocarbon exploratio n and production requires a bottom-founded platform, an artificial island, or a float ing structure plus subsea equi pment including pipeline/riser systems. Transportation of produced hydrocarbons to market is also an essential aspect of any development. An added complexity when hy drocarbon resources are located in arctic regions is the presence of firs t-year and/or multi-year ice duri ng a significant part of the year. Global climate changes may also result in longer open water seasons in the future, which may lead to more significant storm events that must be considered in the design of full-field offshore development concepts for arctic regions.

This study has been carried out in response to t he United States Departm ent of the Interior, Minerals Management Service Request for Proposal (RFP), MMS Technology Assessment and Research (TA&R) Program, Operational Sa fety and Engineeri ng Research (OSER) Broad Agency Announcement Solicitation 0106RP39786. Specifical ly, Objective #4, “Conduct a technology assessment for Outer Cont inental Shelf, Oil and Gas Operations in the Cold Regions to determine what may be tec hnically feasible -given both ice-challenges, and also open water with large fetches and waves.”
A number of “cold regions” offshore developments have been carried out or are planned worldwide, including the east coast of Cana da (Hibernia, Terra Nova, White Rose), Sakhalin Island (Russia), Kashagan (Caspian), Shtokman (Barents Sea) as well as in the Beaufort Sea (Northstar, PanArctic Drake). An understanding of these analogue projects, as well as those already oper ational or planned fo r the United States (e.g., Northstar and Oooguruk), can provide insight and guidance in to potential explorat ion and development technologies that might be applie d to cold regions of the Un ited States Outer Continental Shelf (OCS).

1.2 Background

Principal factors governing the design of offshore exploration, production, and transportation facilities in arctic regions include:

• Environmental loads, prim arily ice, with waves, cu rrents and seismic effects also playing significant roles;IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 2 of 339 Rev. 0 • The platform/island/structure itself (whether exploration or development), together with its functional requirements which consis t of providing sufficient topsides space and the ability to be mobilized to site with significant consumables on board (as required);

• Available foundation/ mooring resistance;

• Protection of pipelines and subsea equipment; and,

• Transport of produced hydrocarbons.
The combined effect of these principal factor s dictates the geometry and material quantities required for exploration and production structur es. Ice loads are clearly the governing design load for Beaufort and Chukchi Sea ex ploration and production structures. As a result of the oil and gas industry’s limited arct ic offshore exploration activity over the past 20 years, ice loads research has kept a lo w profile. Even so, through the 1990’s and to the present day, there ha ve been significant advancements in fundamental ice mechanics and analysis of full-scale ice load measurements. B eginning in the early 1990’s, for example, Canadian Marine Drilling Ltd. (C ANMAR ) began promoting probabili stic predictive models based on the use of full-scale ice load m easurements, such as the Hans Island Experiments. C ANMAR ’s models suggested that design ice loads were some 15 times lower than the estimates of the 1980’s. Other res earchers have followed suit and ice loads currently developed by internationally recogniz ed ice experts are now consistent with these lower figures. At the same time, advancements in structural steel research combined with these more realistic ice load predictions, led to improvements in economic feasibility of arctic offshore facilities.

There are also many challenges associated wi th the design and installation of offshore pipelines and subsea facilities in arctic environments. These include the evaluation of environmental data (such as ice gouge data), evaluation of geotechnical data, design for these environmental and geotechnical conditions , and construction or installation planning for an environment characterized by a limited construction season and harsh environmental conditions. Some unique aspect s of arctic designs include en vironmental loadings (e.g., ice gouge, thaw settlement and strudel scour) and th e effective use of limit state pipeline design for extreme loading conditions, such as those resulting from ice gouge and thaw settlement.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 3 of 339 Rev. 0 The transport of produced hydroc arbons from the arctic to ma rket is also a significant consideration whether it be by pipeline, tanker or LNG/CNG ca rrier; each with its specific challenges.

1.3 Study Technical Objectives

The objective of this study has been to deliv er an assessment of oil and gas technology that may be applied to cold regi ons of the United States Ou ter Continental Shelf (OCS). Advances in harsh environment offshore ex ploration and producti on technology have made it economically and technically feasible for similar projects to proceed in northern icecovered waters. This study examines the current state of offshore technology in the Arctic or similar regions. These results are then used to provide insight and guidance into existing/future exploration and development tec hnologies that might be applied on the US outer continental shelf, in particular those ar eas within the Beaufort, Chukchi, and Bering Seas. The work covers exploration st ructures, bottom founded and fixed production concepts, floating production concepts, terminal s, pipelines, and subsea facilities, and also touches on some other technologies which mi ght be relevant to Alaskan OCS exploration and development.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 4 of 339 Rev. 0 2.0 ARCTIC STRUCTURES

2.1 Evolution of Arctic Structures & Facilities

Exploration drilling for oil and gas in the Beau fort Sea began from gravel islands in shallow Alaskan State Waters in the la te 1960’s and similarly in the Canadian Beaufor t Sea in the early 1970’s. With time, activities progressed into deeper waters. In 1976, ice reinforced drillships were first utilized in Canadian wate rs, followed in 1981 by the first use of a bottom-founded caisson system. Exploration ac tivities commenced in Beaufort OCS regions in 1982 using gravel islands, ice islands, bottom-founded stru ctures and drillships. Examples of bottom-founded structures deploy ed in the Beaufort Sea are presented in Figure 2-1.

Figure 2-1: Arctic Cais son Drilling StructuresIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 5 of 339 Rev. 0 These bottom-founded structures were conceived pr imarily to extend the depth capability of granular islands. The caisson-retained islands were formed by building an underwater berm and then backfilling the caisson systems with a core of dredged material. Compared to conventional island-building up to that time, t he amount of fill required to achieve stability was significantly reduced. As well, the effects of wave and current erosion during the open water season were reduced. However, these structures still required significant field operations to construct the berms, deploy, backf ill, densify the core (Molikpaq requirement), decommission and move. Although touted as “mobi le” structures, the caisson structures were not truly “MODU’s” (mobile offshore drilling units).
The SSDC was the first MODU-type structure in the Beaufort Sea, coming into service in 1982, and with the additi on of the MAT remains the only ac tive bottom-founded exploration structure in the ar ctic offshore.
In the early 1980’s, it was thoug ht that an exploration (not production) structure for a 200 ft (60 m) water depth in the Beaufort Sea (Figur e 2-2) had to be protected by a sand berm around 0.6 mile (1 km) in diamet er and 100 ft (30 m) thick. At that time, ice features around 100 ft (30 m) thick were thought to deliver a load of about 3.3 million kips (1.5 million tonnes) to the exposed neck of a platfo rm. These huge loads resulted from the extrapolation of small-sca le tests directly to full-scale scenarios.
However, the combination of operational ex perience and full-scale re search programs has resulted in a global design load reduction factor of around 15 (F igure 2-3). This obviously has a direct bearing on the globa l size and cost of arctic pr oduction structures. A reduction factor of around two for local loading on a 10.8 ft 2 (1 m 2 ) area has resulted primarily from using more realistic strain rates and treating the load in a probabilistic manner rather than as the absolute maximum possible crushing pressure.

The principles outlined in the technical paper State-of-the-art of Bottom-Founded Arctic Steel Structures (Fitzpatrick, 1994) have been used to pr edict the size, shape and weight of many arctic structures, incl uding the following examples:

• The MAT base for the SD C (which carries an enormous imposed gravity load) was estimated to require 40,800 tons ( 37,000 tonnes) of steel. Final as-built weight was 39,700 tons (36,000 tonnes).

• The “Champ” MODU structure was esti mated at 69,500 tons (63,000 tonnes) of steel. After one year’s engineering of detailed scantlings and third-partyIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 6 of 339 Rev. 0 verification, the weight takeoff from the drawings was 66,000 tons (60,000 tonnes).

• An ice-strengthened catamaran transport barge was estimated at 27,500 tons (25,000 tonnes). This was later verified by a Dutch engineering firm.

• A large GBS structure for the Grand Ba nks was estimated to require 93,700 tons (85,000 tonnes) of steel. After two years of finite element engineering analysis, two independent engineering firms - one in Edmonton and the other affiliated with The Universi ty of Manchester - estimated the final required steel weight at 95,900 tons (87,000 t onnes) and 92,600 tons (84,000 tonnes), respectively (see Fitzpatrick and Kennedy, 1997).

Figure 2-2: Evolution of Arctic St ructure Loads and Fou ndation RequirementsIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 7 of 339 Rev. 0 Figure 2-3: Evolution of Ic e Loads on Arctic Structure

While the use of subsea pipelines in an offshore arctic or sub-arctic environment has been contemplated for several decades, only a handful of production or pilo t pipeline projects have been constructed (e.g., PanArctic Drake, Northstar, Oooguruk, Sakhalin Island). In some cases, developments have been propos ed without an offshor e structure (e.g. PanArctic Drake). Several ar e planned to be constructed in coming years (e.g. North Caspian) while a number are being consid ered for the Beaufort Sea and other areas.

Early work considered the need to place the pipeline below the design ice gouge depth; however, it was not until the mid 1990’s that there was greater recognition that soil movements and pressures transmitted through the soil to the pipeline had to be considered in design. Early projects, such as the PanA rctic Drake and Polar Gas projects, explored innovative methods to protect the pipeline against ice gouging. Ongoing industry and research community work continues to progre ss offshore arctic pipeline design with regards to design gouge depths, subgouge deformation, and allowable pipeline strain limits.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 8 of 339 Rev. 0 2.2 Primary Design & Operation Considerations

2.2.1 Ice Loads
2.2.1.1 Full-Scale Ice Load Measurements

It is well-documented that extr apolating small–scale laboratory tests to full-scale scenarios greatly overestimates global ice l oads on structures. This is due to the fact that ice fails non-simultaneously, and not at a uniform pressure , during an interaction. Hence, the only reliable method to determine global ice loads has been from measurements and observations of full-scale interactions. The mo st effective technique, and the most telling, has been monitoring the global response of the structure’s foundation.
2.2.1.2 Geotechnical Monitoring

Pressure panels installed on t he loaded face of an arctic struct ure or in the surrounding ice were a traditional method of m easuring ice loads. But it is impractical and expensive to outfit the entire width of a lar ge arctic structure with instrum entation, so only very small portions were instrumented, if at all. The “l ocal” pressures measured on these small contact areas were often averaged across the entire c ontact width, which assumed that the peak pressures at the instrumented locations o ccurred at the same time and also between instrumented locations. This ty pe of analysis led to overestima tion of the peak global ice load in much the same manner as extrapolation to the full scale from very small-scale laboratory tests.
A more effective technique is to monitor the global response of the structure’s foundation to ice loading. The global ice load can then be in ferred from the measured deformation using finite element techniques. C ANMAR reviewed eight (8) case histories in which foundation responses of arctic offshore structures were monitored and analyzed and, in all cases, only small (if any) foundation deformations were obser ved. Global ice loads interpreted from ice instrumentation were found to be 2.0 to 3.5 times higher th an those interpreted from geotechnical responses (see Hewitt et al., 1994) as indicated in Table 2-1.
Determination of ice loads from the geotechnical response of arctic structures has proven to be very useful in placi ng an upper bound on ice loads. Mo re importantly, it is the response of the foundation as compared to its maximum possible deformation that ultimately dictates the safety of a structure. Geotechnical response can also be useful inIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 9 of 339 Rev. 0 “ground-truthing” and discounting the apparently very high ice loads determined from smallscale ice instrumentation (Hewitt, 1994).
Table 2-1: SDC Drilling Location Ice Loads (Hewitt et al., 1994)

SDC Drilling Location Ice Load Interpreted from Ice Instrumentation, tons (tonnes) Ice Load Interpreted from Geotechnical Response, tons (tonnes)
Uviluk 8820 (8000) < 3300 (< 3000) Kogyuk < 11,025 (< 10,000) < 11,025 (< 10,000) Phoenix 7715 (7000) 2200 (2000) Aurora 7715 (7000) < 3860 (< 3500) Fireweed N/A (no instrumentation) < 1325 (< 1200)

Cabot N/A (no instrument ation) < 550 (< 500)

2.2.1.3 First-Year Ice Loads
First-year ice interactions with offshore stru ctures are nominal, common loading events in the Beaufort Sea and other arctic regions. C ANMAR compiled a database of measurements that included over 14,000 data points determined from re-analysi s of 16 separate ice load data sets dating from as far back as 1966. Mo st of the data sets were collected during dedicated ice monitoring programs on Beaufort Sea structures and, in some cases, include load measurements in grounded ic e rubble fields (see Blanchet and Kennedy, 1996). The advantage of using full-scale info rmation is that natural effects such as ice temperature and the distribution of cracks and flaw s are included in the data set.
An “envelope curve” was developed from these maximum data points to provide a deterministic method to estimate first-year ice loads on wide arct ic structures for a variety of scenarios. The approach was used to secure drilling permits from MMS for year-round drilling operations for the SDC (forme rly SSDC) in the Beaufort Sea.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 10 of 339 Rev. 0 Figure 2-4: First-Year Ice Loads (Blanchet and Kennedy, 1996)
2.2.1.4 Hans Island Experiments & Multi-year Ice Impacts

Research programs have also made major cont ributions to the under standing of ice loads. The landmark Hans Island Multi-year Impact Experiments of the early 1980’s investigated the loads generated by collisions with multi-year floes at full- scale. Results from the first Hans Island research program were initially very surprising. Global ice forces generated by high velocity impacts of 20 ft (6 m) thick mu lti-year floes, determined from floe deceleration, were significantly lo wer than anticipated.

Hans Island is a natural rock outcrop in the Kennedy Channel between Greenland and Ellesmere Island and it is im pacted regularly by large ic e features. The largest load recorded during the tests was during the summer of 1983 and resulted from a 20 ft (6 m) thick multi-year ice floe, several miles in di ameter, moving at 4 feet per second when it hit the vertical base of the rock is land. This impact was a signific ant milestone event in the ice engineering community. It was certainly an im portant event to study member John Fitzpatrick’s understanding of ice-st ructure interaction, as he was present on Hans Island and was responsible for developing the analytical methodology for calculating the ice load.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 11 of 339 Rev. 0 Several methods were used to estimate the ice crushing force. The simplest, and most accurate, was to determine how the mass slowed down and then, by the use of Newton’s law, the global force imparted to the island . This force proved to be about 49,500 tons (45,000 tonnes) over a contact length of about 1000 feet (3050 m). Prorating this 49,500 tons (45,000 tonnes) to a 65 ft (20 m) thick ice floe (an extreme Beaufor t Sea ice feature) on a 230 ft (70 m) wide production structure woul d yield an ice load of 33,000 to 44,000 tons (30,000 to 40,000 tonnes).

2.2.1.5 Pipeline Considerations
Arctic offshore pipeline design issues relate d to ice gouging, strudel scour, frost heave / thaw settlement, upheaval buckling and sediment transport drive pipeline architecture and pipeline trenching requirements in terms of depth of cover and backfill thickness. Pipeline protection from ice in arctic environments is normally derived from both lowering the top of the pipe below the surrounding seabed (depth of cover) and burial (backfill thickness).

In sub-arctic and arctic areas, consideration mu st also be given to the design, installation and protection of subsea equipment such as we llheads and manifolds. Protection scenarios include placing the equipment be low the maximum ice keel dept h, as was the case on the Drake PanArctic pilot project (Watts and Masterson, 1979), or placement of subsea equipment in large excavated holes in the seabed (glory holes) which place equipment below the maximum ice gouge depth (McKenna, Crocker and Paulin, 1999).

2.2.2 Wave Loads In the early 1990’s, a typical maximum design wa ve (100-year return per iod) of 30 ft (9 m) was used for the Beaufort Sea (Fitzpatrick, 1994). More recently, other investigators have suggested a 40 ft (12 m) maximum wave. Functi onally, the deck level for a bottom-founded production structure in the Beaufort Sea should be set to pr ovide 9.8 ft (3 m) of clearance to green water when the structure is hit by a 40 ft (12 m) wave with a 3.3 ft (1 m) storm surge. However, for bottom-founded structures in the Beaufort, the design wave load will be very low compared to the desig n ice load, and will not govern the design. However, it does dictate a certain minimum freeboard above sea leve l which, in turn, influences the float-in stability requirements of the unit (the higher the center of gravit y of the topsides, the more difficult the issue).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 12 of 339 Rev. 0 Wave loads are also a consid eration for any floating type structure and subsea equipment, although such equipment has been designed for significant wa ve loads in other parts of the world.

2.2.3 Earthquake Earthquake loads are also a consideration fo r bottom-founded structures and foundations. The SDC’s topsides, for example, were desi gned for operation in the Alaskan Beaufort Sea at an acceleration of 0.25 g. It is likely that a nominal acceleration of at least this number will be required for topsides of any potential production platform concepts. This is not an overly onerous design condition, but it will be the prevailing la teral design condition for the topsides. Any shallow or “squat” platform which has the strength to resist an ice load on the order of 110,000 tons (100, 000 tonnes) is not going to be affected by a moderate earthquake. However, that same platform will def initely have the ability to transfer its base accelerations up to the topsides. The question that must be asked is, “Will the structure dynamically amplify its base shears to a degree that is very onerous to the topsides?” This must be considered in the asse ssment of platform concepts.
Earthquake effects on pipelines and other subsea equipment (for example, seismic wave propagation) must also be considered.

2.2.4 Foundation Reaction Loads
Foundation reaction loads are sometimes trivia lized and their significance often ignored. Experience has shown that even when the soils are soft, very high local pressures can build up locally against the base of an offshore structure. Such pressures are of the same order as ice load pressures, i. e., the structure base needs as much strengt h as the vertical sides. This is an important considerat ion for bottom-founded platform concepts.

Foundation capacity associated with other concept s such as floating structures and their associated mooring systems must also be properly assessed.

2.2.5 Facilities Func tional Considerations
Functional considerations must also be addressed when designing/ evaluating islands, platforms or other structures.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 13 of 339 Rev. 0 2.2.5.1 Deck Area
In the North American Arctic, re-supply is expensive during the frozen-in period. To a similar degree, other arctic areas have costly winter re-supply problems. Throughout the development phase, as production wells are being drilled, large storage areas are required in order to offset winter re-supply costs. Wh ile the amount of space required is site and project specific, many investigat ions over the past years result in a fairly consistent top deck requirement of about 110,000 ft 2 (10,000 m2). For very little additional cost, this can be matched with a similar closed in deck about 16 to 26 ft (5 to 8 m) below. This 110,000 ft 2 (10,000 m2) area, particularly in the US and Canadian Beaufort Sea, w here design loads are in the 110,000 tons (100, 000 tonnes) region, seems to fit quite reasonably with the structure size necessary for stability. No extensive deck cantileverage is required.

2.2.5.2 Oil Stor age & Transportation
Many structures will be required to store oil in significant quantitie s particularly where product transportation is by ice breaking t ankers. If use is made of the wet storage principle, i.e., either oil or wa ter is present in the holding t anks at all times, and this seems to be the most preferable option , then the designer needs to be cognizant of the fact that there is a certain amount of stor age capacity that is “free”, so to speak. This is because the presence of significant environmental loads requi res a certain minimum size of structure for stability alone. Whether or not it achieves its weight as a re sult of oil or water ballast does not make a great difference (dry storage is diffe rent; there is no “free” dry storage). This minimum size structure varies a great deal according to region al location. In the Canadian sector this free storage can amount to around 2 MM bbls, and in the US typically around 1.5 MM bbls. In deep water In the Sea of Okhotsk (460 ft (140 m)) it can be as high as 3 or 4 MM bbls, while in the relative ly mild Pechora Sea it is perhaps somewhat less than a few hundred thousand bbls. Defining this maximum free storage capacity is a good place to start the design of a pr oduct transportation system.
In general, the minimum storage capacity is rela ted to the off-loading cycle time. The offload quantity within each cycle is of course equal to the unfac tored storage capacity. Where the free storage capacity is great er than this minimum, then us e of this knowledge can be made to optimize further the tanker pow er, cycle times and carrying capacity.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 14 of 339 Rev. 0 2.2.5.3 Dry Storage

Where dry storage is required this adds significant expense to th e basic structure. In many instances the premium can be around 30% or more of the basic platform cost. For many reasons, it should be av oided if possible.
2.2.5.4 Environmental Safety
The product storage area, for environmental r easons, should not be immediately inside the outer face. All the concepts shown have double bottoms, double tops and at least 33 ft (10 m) of plain water ballast tank between the oute r face and the storage area. Approximately, this gives sufficient energy absorption capacity to resist penetration to the oil storage area by large icebreaking tanker trave ling out of control at high speed.
2.2.6 Ice Gouge Effects It is generally accepted that ar ctic pipelines would need to be trenched to some depth below the mudline to protect t he pipeline from ice keels. Ice gouging of the seafloor is a near-shore feature for most of the northern continents where t hese ice keels intrude into water with depths less than the ice keel dr aft and form a gouge in the seafloor soils.
Early arctic offshore concepts were such that the design burial depth was sufficient to reduce the probability of ice contact with the pipeline to an acceptable level. The concept of subgouge deformation below moving ice keel s in contact with the seabed was not recognized as an important design issue until the late 1980’s and, therefore, does not appear to have been considered in the design of the pipelines.
A pipeline on the seafloor in such an environment may not be able to withstand the ice contact loadings and typically must be buried bel ow the predicted extreme ice keel gouge depth for protection. As an ice keel passes over any point in the seabed, vertical and lateral stresses are applied to the soil at the keel base, resulting in some distribution of vertical and lateral soil displacements with depth beneath the ice keel . This is typically termed subgouge deformation of the seabed beneath the gouging keel (Figure 4-29). This deformation can impose forces on the pipe body and result in deformation of the pipeline.
The configuration of the pipeline after gouging, and henc e the strain in the pipeline, depends on the pipeline properties, the soil charac teristics, the depth of the design ice gouge, and the depth of the pi peline below the mudline. Th e pipe must be trenched sufficiently beneath the influence zone of soil displaced below the ice keel to limit pipelineIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 15 of 339 Rev. 0 strains to within acceptable limi ts. If the pipeline is trenched be low the zone of significant soil movement, it will experience increased so il pressure but not high bending due to the relatively small soil displacements. If the pipel ine is trenched within the zone of significant soil movement, it may experience plastic strains. Therefore, the soil displacements induced at the pipeline depth due to ice gouging and resu lting strains in the pipeline must be calculated and evaluated. The e ffect of this soil displace ment and the loading on the pipeline can be evaluated through non- linear finite element analysis.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 16 of 339 Rev. 0 3.0 REVIEW OF EXPLORATION & DEVELOPMENT OPTIONS

3.1 General

Offshore oil and gas exploratio n and production activities hav e been carried out and/or considered for a number of Arct ic and cold ocean regions. A revi ew of these activities may provide insight into options and technology, which are suitable for use in areas of the Alaska OCS; in particular, areas of the Beaufort, Chukchi, and Bering Seas.
As a starting point for this review, the projec t team identified cand idate analogue areas based on experience and an initial review of Arctic and cold region exploration and production activities. Candidate areas were then studied in suffici ent detail to allow screening and subsequent sele ction of analogue areas to carry forward in this study. In general, screening was based on area environmental (i.e. metocean and ice) conditions, water depths, and structure types / technologie s considered in this study, including:

• Ice Islands

• Gravel Islands

• Bottom-Founded Structures

• Fixed Structures

• Floating Structures

• Subsea Solutions

• Pipelines & Flowlines

• Export Terminals

• Other Technologies

Discussion regarding the selectio n/screening of candidate areas is provided in Section 3.2. Review of the selected analogue areas is carried out in Section 3.3.
Of direct relevance to this study are those adv ances in exploration and production activities that have taken place in the Beaufort, Chukch i, and Bering Seas; these are reviewed belowIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 17 of 339 Rev. 0 in Section 3.4. Note that the US and Canadian Beaufort Seas ar e typically discussed together in this report due to similarity in environments and structures/technologies used.

3.2 Analogue Area Selection

3.2.1 Selected Areas Selected analogue areas are pres ented in Table 3-1. The table also highlights some of the most significant activities undertaken, or considered, in each ana logue area, along with the associated structure types and technologies.
Subject areas of the Alaska OCS are included for completene ss and have been reviewed in the same manner as the analogue areas. Furthermore, structures and/or technology used in one particular area of the OCS may be consi dered for application in another area of the OCS.
The following sub-sections pr ovide discussion on selected a nalogue areas. It should be noted that metocean and ice data considered in the following sub-sections and throughout the remainder of this report can be found in Appendix A; they are generally not referenced directly in the main body.

3.2.1.1 Cook Inlet
Cook Inlet is a 180-mile (290 km) long estu ary stretching southwest from Anchorage to the Gulf of Alaska. Oil was first discovered in Cook Inlet in 1963 an d development commenced shortly thereafter.
Infrastructure used to develop Cook Inlet’s offshore oil resources consist of fixed jacket offshore platforms connected to land based st orage and distribution facilities via subsea pipelines. These structures are subject to firs t-year ice conditions ranging from 20 to 79 inches (0.5 to 2.0 m) thick.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 18 of 339 Rev. 0 Table 3-1: Analogue Areas Selected for Review

Region Previous Exploration Program, Study, Project Structures / Facilities US Beaufort Sea Northstar Gravel Island / Pipeline Liberty Gravel Island / Pipeline Oooguruk Gravel Island / Pipeline Nikaitchuq Gravel Island / Pipeline Chukchi Sea Chukchi Sea Feasibility Studies Fixed Structures / Pipelines / Tankers Bering Sea Conceptual Studies Floater, Fixed Structures, Pipeline Cook Inlet (Alaska) Various Fixed Structures Canadian Beaufort Tarsiut/Kopanoar/Issungnak Gravel Island / Pipeline Amauligak Caisson Retained Island / Pipeline West Amauligak Subsea / Pipeline Canadian High North Drake PanArctic Pipeline and wellhead
Polar Gas Subsea manifolds / pipelines Davis Strait/West Greenland Conceptual Studies Floater, Subsea & Flowlines Canadian East Coast Hibernia Concrete GBS / Storage
Terra Nova Floater, Flowlines & Subsea
White Rose Floater, Flowlines & Subsea BP Amoco West Bonne Bay Steel GBS / Storage Eastern Russia Sakhalin 1 CIDS / Pipeline

Sakhalin 2 Molikpaq / Lunskoye / Piltun-Astokhskoye-B / Pipeline Sakhalin 4 Bottom-Founded, Pipeline Sakhalin 5 Bottom-Founded, Pipeline
Barents Sea Shtokman Floater, Subsea & Flowlines Pechora Sea Prirazlomnoye Fixed Structure, Tankers Karas Sea (Gulf of Ob) Conceptual Studies Fixed Structure, Pipelines Baltic Seas Kravtsovskoye Jacket, PipelineIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 19 of 339 Rev. 0 3.2.1.2 Canadian High North
A limited number of projects were proposed for the Canadi an High North including the Drake PanArctic gas project and the Polar Gas project. A Canadian co mpany, PanArctic Oil Ltd., sponsored the Drake Field subsea comple tion which was located in the Canadian High Arctic off of Melville Island. The world’s first arctic subsea flowline began transporting gas in April 1978, from a subsea wellhead to production facilities onshore (Palmer et al., 1979). The three-year program to design, fabricate and cons truct was part of a test program to evaluate the performance of t he field development concept and demonstrate the feasibility of such an offshore arctic development.

Polar Gas was a consortium of American and Canadian companies formed in 1972 that investigated the possibility of bringing natura l gas southward by pipeline from the Canadian Arctic Islands (Houlding, 1976) . Considerable design work and a research program was undertaken to look at the feasibility of laying pipelines in extreme low temperatures and through the ice in t he Canadian Arctic.

3.2.1.3 Canadian East Coast
The East Coast of Canada currently has several producing oil and gas fields. These fields are located off the coast of Newfoundland and Nova Scotia. Furthermore, significant exploration activity has been undertaken in these areas and on the Labrador Shelf.

The fields located offshore Newfoundland are the Grand Banks developments; Hibernia, Terra Nova, and White Rose. These development s use structures that are designed (at least to some degree) to withstand sea ice and iceberg loads.
Although the Labrador Shelf d oes not have a production project to date, significant exploration has been carried out on the shelf and, in recent ye ars, consideration has once again been given to potential gas production from the area. In terms of sea ice and icebergs, the Labrador shelf is subject to a much harsher environment than the Grand Banks.
The Sable Energy Project, which lies offs hore Nova Scotia (near Sable Island), experiences very little sea ice, and icebergs are rare. The likeli hood of sea ice from the Gulf of St. Lawrence encroaching on the Sable development is ve ry low; less than 1 percent based on 30 years of observations (CAEE, 2005) . Furthermore, only one iceberg has beenIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 20 of 339 Rev. 0 reported in the Sable developm ent area in the last 60 years, and the probability of future iceberg occurrences is low (ExxonMobil, 2007).

3.2.1.4 Offshore Greenland
Offshore petroleum exploration has taken plac e off the east, north, and west coasts of Greenland; however, drilling has only been conduc ted offshore west Greenland. Initial exploration offshore west Greenland took place between the early to mid 1970’s with extensive seismic surveys. Following this per iod, five wells were drilled between 1976 and 1977; however, interest in furt her exploration was curtailed when well results had indicated that the wells were dry (Geological Survey of Denmar k and Greenland, 2005).
Throughout the 1990’s, interest in offshore we st Greenland began to grow and in 1997 additional processing of well data suggested t hat the Kangamiut-1 (drilled in 1976) showed hydrocarbons (Geological Survey of Denmar k and Greenland, 2005). In 2000, the sixth exploration well (Qulleq-1) wa s drilled. No further explorat ion drilling has taken place; however, offshore exploration licenses were awarded for licensing rounds held in 2002, 2004, and 2006.
In general, a significant portion of the west coast of Greenland experiences sea ice each year during the winter and early spring and, depending on location, icebergs can be encountered frequently (Mosbech et al., 2007). So me consideration and preliminary study work with respect to potential development options has been carried out and is discussed later in this report.
3.2.1.5 Eastern Russia (Sakhalin Island)
Sakhalin Island is a large elongated island in the North Pacific, nor th of Japan, which is part of Russia. Projects currently producing oil offshore Sakhalin Island include Sakhalin 1 (ExxonMobil) and Sakhalin 2 (Shell) directly o ff the east coast of Sakhalin. These projects have been developed using retrof itted gravity base platforms fr om the US Beaufort (CIDS) and the Canadian Beaufort (Molikpaq). Future pr oposed projects include Sakhalin 5 which will be off of the northeast coast of the island.
The east coast of Sakhalin Island is an area characterized by storm winds, fog, freezing temperatures in winter, intense snowstorms, sea ice and pressure ridges, and ice gouging. Table 3-2 presents information on some of the Sakhalin Island proj ects currently being considered.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 21 of 339 Rev. 0 Table 3-2: Sakhalin Fact Sheet (source EIA, 2007)

Name Sakhalin I Sakhalin II Sakhalin III Sakhalin IV Sakhalin V Sakhalin VI

Primary Field/Block Names Odoptu [Northern and Southern] (onshore), Chayvo (onshore and offshore), Arkutun-Dagi Sakhalin Energy Investment Company: Piltun-Asto kskoye, Lunskoye (will provide most of the LNG, 34 kb/d of oil) Kirinskii, Veninskaya, Vostochno-Odoptu, Aiyashkii Pogranichny Block, Okruzhnoye fld KaiganskoVasyukansk (active drilling) Pogranichny

Oil Reserve Estimate 975 million bbl, (Source: IHS Energy) 1.0-1.2 billion bbl (Source: Shell) Total: 4-5 billion bbl Veninsky Block: 830 million bbl (Source: IHS) 880 million bbl 4.4-5.7 billion bbl 600 million bbl

Natural Gas Reserve Estimate 11 Tcf, (Source: IHS Energy) 17.3 Tcf (Source: Shell) Total: 27-38 Tcf Veninsky Block: 11 Tcf (Source: IHS) 19 Tcf 15.2-17.7 Tcf n/a

Net Total Investment Phase 1: $5 billion Phase 1: $4.5 billion, Phase 2: $20 billion over next 4-5 yrs. $13.5 billion expected (ExxonMobil- $80m in geological studies) $2.6 billion expected $3-5 billion expected n/a

Current & Expected Prod'n Level Max oil production from Chayvo field achieved in Feb. 2007 at 250 kb/d. Commercial gas prod'n expected in 2008 Current: 80,000 bbl/d for 6 months, Phase II: 180,000 bbl/d, year-round oil production expected in Dec. 2007, LNG prod'n expected in Summer 2008 n/a n/a n/a n/a

Primary Project Developers Exxon Neftegaz (30%), in conjunction with consortium members SODECO (30%), ONGC Videsh (20%), Rosneft (8.5%), Sakhalinmorneftegaz (11.5%), and RN Astra (8.5%) Gazprom (50%+), Sakhalin Energy Investment Company: Shell (27.5%), Mitsui (25%), Mitsubishi (20%) Rosneft is primary developer. Veninsky Block: Rosneft (49,8%), Chinese Sinopec (25.1%) and Sakhalinskaya Neftyanaya Kompaniya (25.1%) BP (49%), Rosneft (51%) Elvary Neftegaz: BP (49%), Rosneft (51%) Petrosakh, Alfa Eco

Status/Notes Mode of gas export still up for negotiation. Exxon prefers pipeline exports to China (cheaper). Other shareholders, Gazprom prefer piping to LNG terminal at Sakhalin II. Oil production began in 1999; Processing terminal under construction which will have capacity of 66,000 bbl/d of oil, 1.8 bcf/d of gas Lukoil possibly in cooperation with Gazprom will probably take part in new tenders for Kirinskii and Vostochno blo cks. Rosneft undertaking 3D seismic, to be complete by Oct. 2006. Rosneft undertaking 3D seismic.BP/Rosneft drilled 3 successful wells during 2006. 3 blocks in Sakhalin VI have not been awarded April 2007 

### Sakhalin Fact Sheet

Sakhalin Island, a former penal colony located off Russia's eastern shore (see map), is home to six oil and gas projects. The f ive projects are currently in different stages of development, and two of the projects, Sakhalin I and Sakhalin II, aim to bring oil and natural gas production online in the near term. Both projects have targeted Asian markets. Three blocks after Sakhalin VI have not been awarded yet.

Source: Project Homepages (see links section), IH S Energy, Interfax, Russian Energy Monthly ( www.easternblocenergy.com), FSU Oil and Gas Monitor, Pipeline & Gas Journal
3.2.1.6 Russian Arctic (Barents, Karas, Pechora, and Baltic)
Technology developments in the Russian Arctic are driven by the same challenges that exist in the American and Canadi an Arctic; the hydrocarbons are to be extracted from shelf reserves which are located in areas of adverse environmental conditions, and they are to be safely delivered to markets in lower latit udes. If there is any difference, it probably manifests in conditions for tr ansportation, and in the available infrastructure which, in the Russian case, may be more challenging.

The routes from the main Ru ssian Arctic fields to European and American consumers are fairly long and are through remo te areas both in the sea and on land. A map showing theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 22 of 339 Rev. 0 location of the main fields of the Russian Arct ic is presented in Figure 3-1 (Imayev et al., 2005). As can be seen, large offshore and oil and gas reserves are located east of Novaya Zemlya archipelago, in the Kara Sea and near the Yamal Peninsula coast. While a number of future offshore exploration projects are planned for this area, information on work carried out to date is limited. Description s of Arctic offshore projects included in this Section are primarily related to work that has been carried out in the Russian sector of the Barents Sea.

Figure 3-1: Oil and Gas Fields of Bar ents and Kara Seas (Imayev et al., 2005)
A significant part of the world’s oil and gas reserves are believed to be in the Russian sector of the Arctic Ocean Shelf. Many of the prospective fields were discovered east of the Ural Mountains, along the Siberian coast (Ob and Taz Bays, Yamal Offshore); however, more recently activity has been progre ssing along the European coast (Barents Sea, Pechora Sea). According to some recent public ations (Snieckus et al., 2007), questions still surround ultimate recovery calculations and what will be required to bring the gasdominated production to the market. However, t he pace of technological developments forIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 23 of 339 Rev. 0 exploration in the Russian Arctic remains hi gh. These developments are expected to be dominated in the near future by the explorat ion of the giant Shtokman (or Shtokmanskoye) gas and gas condensate field in the Barents Sea. Located approximately 373 miles (600 km) offshore, in 985 to 1150 ft (300 to 350 m) of water, with ice conditions that include twoyear ridges and icebergs, the Shtokman field development wil l apparently stay at the forefront of contemporary Arct ic development technology.
Technical information on explorati on in the Russian Arctic is not widely available. However, a cross-referenced search through multiple promotional briefs, news summaries and pressreleases on the internet gives, in many cases, somewhat of a picture of the basic technology components planned for development projects. Some information on the general scope of the Russian Arctic technol ogy projects was collected during an information gathering trip to Moscow and St. Pete rsburg in April, 2007. This information has been mainly included in Secti on 3.3 and within Appendix D.
The meeting with the spec ialists of Krylov Shipbuilding Res earch Institute in St. Petersburg was particularly informative. Krylov is one of the largest technological and research centers in Russia. The company has more than 2000 employees and a wide range of research installations and scientific/design groups. One of the largest areas of activities in Krylov now is development of technical means (ships , platforms and marine technology) for oil and gas exploration. The promoti onal manual prepared by the Instit ute lists over 200 projects and contains brief descriptions of approximately 75 of them (Krylov Inst itute, n.d.). It is interesting to note that 70 percent of these projects are directly associated with exploration on the Russian Arctic shelf. This clearly indicate s the significance of Ar ctic development in the overall scope of oil and gas explor ation technology work in Russia.
Informative discussions during the information gathering trip to Russia were also conducted with the specialists of VNIIGAZ (All-Union R&D Instit ute of Natural Gases) in Moscow. Presently, VNIIGAZ is a leading scientific instituti on of Gazprom (the largest Russian oil and gas enterprise). The technology resear ch is conducted in the VNIIGAZ Offshore Oil and Gas Fields Center (Gaz prom and VNIIGAZ, n.d.).
Information on development in the Russian Arctic is also contained in reviews prepared by foreign companies and in publi shed results of their joint st udies with Russian companies and institutions (Frant zen and Bambulyak, 2003).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 24 of 339 Rev. 0 A number of pipelines have been considered fo r the Russian Arctic, including pipelines across the Baltic Sea, Baydaratskaya Bay, t he Pechora region, and the Barents Sea. Most activity currently being planned for the Bare nts Sea seems to be for the western part which is essentially ice free.

3.2.2 Screened Areas
In addition to the areas discusse d above, the following list of ar eas were initially considered candidate analogues. However, upon further c onsideration they, along with offshore Nova Scotia, were not carried forward in this study:

• North Caspian Sea

• Greenland Sea

• Yellow Sea

• Norwegian Sea

• North Sea

• Laptev Sea

• East Siberian Sea
3.2.2.1 North Caspian
The North Caspian Sea is ice covered for 3 to 5 months per year. Level ice thickness has been observed up to 36 inches (90 cm) and the ex tent may reach the coastal regions as far south as Aktau. Ice movements are purely wind driven which leads to three main types of deformed ice features: rafted ice, ridges and st amukhi. Rafted ice regularly reaches over 3.3 ft (1 m) in thickness in the early ice s eason and has been observed locally to over 9.8 ft (3 meters). A unique aspect of Caspian rafted ice is that it has been consistently observed where it is made up of over 10 layers. Ridges and stamukhi cause pitting and gouging of the seabed across the entire northern area. Ice ride-up and pileup are also a concern for exploration and production islands.

For exploration and appraisal drilling, AKCO has used the MODU Sunkar which has water ballast onto a submerged rock berm as well as a man-made island. The shallow waterIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 25 of 339 Rev. 0 depth of the North Caspian is favorable to the use of man -made islands (gravel/rock) for production facilities.
While, the Caspian has ice related problems si milar to the Alaskan OCS areas, the major differences are the thickness of the ice and the water depths. Th erefore, this region is not carried forward as an analogue area.

3.2.2.2 Other Areas
Baffin Bay is considered to have good potential for gas and oi l (Indian and Northern Affairs Canada, 1995) as there is evid ence of active oil seeps and petroleum source rocks in the area. Only one well has been drilled in Baffin Bay between 1976 and 1977, and no development concepts were discovered as par t of this study, Baffin Bay is not being considered further in this study.

Ice resistant structures have been consider ed for the northern Yellow Sea. However, environmental conditions in that region are not considered to be analogue to those areas of interest in the Alaskan OCS. As the Nort h Sea and Norwegian S ea are not subject to regular seasonal ice coverage or multi-year ice intrusions, t hey are not considered further. No significant discoveries in the Laptev and East Siberian Sea have been identified and therefore these regions are also not considered further.

3.3 Analogue Exploration & Development Options

3.3.1 Bottom-Founded & Fixed Structures
3.3.1.1 Sakhalin Island

Sakhalin 1
The Sakhalin 1 project acquired the Concrete Island Drilling System (CIDS) from the US Beaufort Sea (Section 3.4.1.6) and renamed it the Orlan Pla tform (Figure 3-2). Compared to the cost of a newbuild, the cost to purc hase, refurbish and upgrade an existing structure was attractive to the project (PennWell Publishing, 2007).

The CIDS structure had been built in 1983 and was designed for year-round drilling in Arctic waters up to about 50 feet water depth. At the ti me of purchase, it had been mothballed off the north slope of Alaska. Refurbishment started in 2001 and includedIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 26 of 339 Rev. 0 installing a wave deflector sh ield, and strengthening the platform base to resist earthquake effects (PennWell Publishing, 2007).

Figure 3-2: Orlan Platform off of Sak halin (from PennWell Publishing, 2007)

Sakhalin 2
The first phase of the Sakhalin developmen t began with the Molikpaq platform producing oil from the Astokh feature of t he Piltun-Astokhskoye field back in 1999. The Molikpaq is the first offshore oil production platform in the Ru ssian Federation. It is located on the Astokh feature of the Piltun-Astokhskoye (PA) reservoir offshore Sa khalin. Sakhalin Energy has been successfully producing oil from the Vity az Complex since July, 1999. Up until 2007, production from a floating stor age and offloading unit was limite d to the summer ice-free

season.
The Vityaz Complex consists of the Molikpaq production platfo rm (Section 3.4.1.5), a single anchor leg mooring buoy ( SALM) and the Okha floating stor age and offloading (FSO) unit (Figure 3-3). During the ice season, follo wing the disconnection from the Okha FSO, the SALM is ballasted down on the sea bottom thus completing preparations for the winter.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 27 of 339 Rev. 0 Figure 3-3: The Molikpaq Platform as part of the Vityaz Production Complex (Calitz and Mercer, n.d.)
Sakhalin Energy plans to conv ert the Molikpaq to a year round production cycle at year end 2007, once the platform has been connected to the new pipeline system (Phase 2).
Scheduled to begin full operations in 2008, the Sakhalin 2 Phas e 2 project is the second stage in plans to develop the P iltun-Astokhskoye oil field and the Lunskoye gas field. Together, the Piltun Astokhskoye and Lunskoye fiel ds hold more than 1 billion barrels of crude oil and more than 17.5 tcf (500 billion cubic meters) of natural gas, making them among the largest oil and gas rese rves under development in the world (Sakhalin Energy, 2006b).
Once extracted, the oil and gas will be pi ped onshore for processing. It will then be transported via two 497 mile (800 km) pipelines to the LNG plant and o il export terminal that has been constructed in Prigorodnoye, in the south of Sakhalin Island. The sea at Prigorodnoye is nearly ice-free and allows exports all year.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 28 of 339 Rev. 0 The permanent offshore infrastructure install ed for Sakhalin 2 includes a network of offshore pipelines and three bottom-founded pr oduction structures; the Piltun Astokh-A (PA-A) or Molikpaq, the Pi ltun Astokh-B (PA-B), and t he Lunskoye A (Lun-A). These platforms are designed to operat e in six-month frozen seas, severe storms, significant seismic loading, and a combination of sea ice, wind and wave loads.

The Sea of Okhotsk is characterized as an ar ea with air temperatures that can reach 102°F (39°C) in the summer and -38°F (-39°C) during the winter, wave s that can reach a 100-year maximum height of around 65 ft (20 m), an d ice pressures of 0.6 psi (4 kN/m 2 ) (Snieckus, 2002).

Figure 3-4: Sakhalin Island, PA-A, PA-B and Lun-A (Sakhalin Energy, 2007)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 29 of 339 Rev. 0 The Piltun Astokh-A

The PA-A drilling and production platform (Figure 3-5) was m ade from the conversion and refurbishment of the mobile bottom-founded arct ic drilling rig, the Molikpaq. The Molikpaq was an octagonal-shaped steel ca isson structure designed to operate in the severe ice conditions of the Canadian Beau fort Sea in water depths of 50 to 65 ft (15 to 20 m) (Offshore News, 2007).

The main conversions and refurbishments to the Molikpaq included the introduction of a 50.5 ft (15.4 m) spacer, earthquake reinforc ing, and the introduction of large wave deflectors (Van Hoorn and Kim, 1999). The main purpose of the spacer is to address the deeper water depths in the Sea of Okhotsk.

At its base, the PA-A platform measures 36 5 x 365 ft (111 x 111 m) and reduces to 285 x 285 ft (87 x 87 m) at the top deck. The cai sson supports a 240 x 240 ft (73 x 73 m) box girder deck structure, which ca rries the topsides and drilling fa cilities. The substructure has a weight of 41,362 tons (37,523 tonnes) (Hydrocarbons Technology, 2007).

The PA-A platform is ballasted with 9,820,000 ft 3 (278,000 m 3 ) of sand which permanently anchors it to the seabed 10 miles (16 km) off the coast of Sakhal in Island in 100 feet (30 m) of water (SPG Media Limited, 2007f).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 30 of 339 Rev. 0 Figure 3-5: The Piltun Astokh-A (SPG Media Limited, 2007f)
The Piltun Astokh-B (PA-B)

The PA-B platform (Figure 3-6) is slightly la rger then the Lun-A platform described in the next Section; it carries topsi des of 30,865 tons (28,000 tonnes ) in a water depth of 105 ft (32 m) and is located 7.5 miles (12 km) offshore (SPG Media Limited, 2007f).

The PA-B concrete gravity base (CGB) consists of a caisson base and f our cylindrical legs that support the topsides. It has a substructure weight of 99,210 tons (90,000 tonnes). The caisson base is 308 x 300 ft (94 x 91.5 m) and 38 ft (11.5 m) high. The diameter of each leg measures more than 79 ft (24 m) at the base and are approximately 128 ft (39 m) high. The total height of the substructure is 174 ft (53 m) (SPG M edia Limited, 2007).
This platform supports drilling facilities, accommodations, processing, and power generation facilities. It has the capacity to produce 70,000 barrels of crude oil per dayIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 31 of 339 Rev. 0 (11,000 m 3 ) and up to 92 million standard cubic feet (2.6 million Sm 3 ) of gas per day (SPG Media Limited, 2007).

Figure 3-6: Installation of PA-B Platform, Sakhalin 2 (JSC Gazprom, 2007a)

The Lunskoye A (Lun-A)

The Lun-A platform (Figure 3-7) is located 9.3 miles (15 kilometers) offshore, operates in a water depth of 157 ft (48 m), carries a topsi des of 24,200 tons (22,000 tonnes), and has an estimated substructure weight of 113, 500 tons (103,000 tonnes) (Rigzone, 2005).

The Lun-A consists of a rect angular-shaped base caisson toppe d with four legs. The base caisson is 344 x 289 ft (105 x 88 m) and 44 ft (13.5 m) high. The diameter of each leg measures more than 65 ft (20 m) wide and 184 ft (56 m) high. The total height of the concrete substructure is 228 ft (69.5 m) (Rig zone, 2005). The concrete thickness ranges between 1.6 and 2.5 ft (0.5 and 0.75 m) and is steel reinforced throughout.

The Lun-A platform has a production c apacity of 1.77 tcf (50 million m 3 ) of gas per day and 50,000 barrels of condensate per day (Sakhalin Energy, 2006).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 32 of 339 Rev. 0 Figure 3-7: LUN-A Platform (JSC Gazprom, 2007a)

Piltun Astokh-B (PA-B) and Lunskoye A (Lun-A) Platforms

The PA-B and the Lun-A platforms are four-legged gravity base substruc tures, operating in the Sea of Okhotsk. The PA-B and the Lun-A platforms were or iginally designed as steel structures which was later revis ed to concrete (Snieckus, 2002).

The PA-B and the Lun-A platforms are designed to resist a 200-year strength earthquake and a 3,000-year ductility leve l earthquake (Beckman, 2004). At the top of the concrete gravity base legs, friction pendulum bearings c onnect the topsides to the substructure. These bearings isolate the t opsides from severe earthquak e motions by employing the characteristics of a pendulum to lengthen the st ructure’s natural period. When activated by a seismic shock, the convex bearing, or arti culated slider, moves along the concave plate underneath, causing the topsides to move with small pendulum motions. In the event of a vertical movement, the top plat e on which the topsides rest can twist, but the concave plate can also restore its own position and the topsides’ equilibrium (Beckman, 2004).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 33 of 339 Rev. 0 PA-B and Lun-A have been constr ucted with an unusually large 95 ft (29 m) air gap between the deck and the substructure, which co mpares with 62 to 72 ft (19 to 22 m) for a typical North Sea structure (Beckman, 2004). Th is air gap was necessary to guard against large ice blocks that get thrown against t he structure by waves during the annual melt.
Installation of these platforms was a two part process. The bases were towed to site and ballasted to the seabed in the open water seas on. In the subsequent open water seasons the topsides were floated to site and installed by float over.

3.3.1.2 Russian Arctic
Prirazlomnoye Field
Prirazlomnoye oil field is the largest natural reserve on the Russian Arctic Shelf which is presently in an advanced stage of developmen t. Consequently, it will become the first oil producing offshore reserve on t he European coast of the Arct ic Ocean. The first oil production was originally planned for 2005 (Fr antzen and Bambulyak, 2003), but now the field is expected to become operational in 2008 (PRINT-EXPO Co. Ltd, 2007). The various stages of Prirazlomnoye devel opment may be traced through the series of projects executed by the Krylov institut e (Krylov Institute, n.d.) and in information available on the internet from various sources (see, for example, Frantzen and Bambulyak, 2003; Luff, 2006; SPG Media Limited, 2007a; PRINT-EXPO Co. Ltd, 2007; Chernov, 2005; Madslien, 2006; Offshore Media Group, 2007; Dolphin Exhi bitions Transtec Neva Exhibitions JSC, 2007).

The field, discovered in 1989, is located in the Pechora Sea (southeast Barents), 37.3 miles (60 km) offshore in a water depth of appr oximately 65 ft (20 m) (see Figure 3-1). The estimated oil reserves at Prirazlomnoy e are 610 million barrels over an expected production life greater than 20 years. Initially, the field was planned to be developed by an international consortium with participation of Norway’s Stat oil and Norsk Hydro. However, in 2002, after several variations in the pr ospective ownership, the operational license was issued to Sevmorneftegaz, led by the conglomerate of subs idiaries of Rosneft and Gazprom (all Russian).
The operational concept for the field is based on using a single platform with 40 directional wells; 19 for production, 16 for injection and 5 reserved. The process technology to be used during operation at Prirazlomnoye is descri bed in Chernov (2005). The Arctic engineering aspects of the project became a focus of interest and research activities of the leadingIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 34 of 339 Rev. 0 Russian organizations began more than 10 y ears ago. It should be noted, that while western companies are actively involved in Pr irazlomnoye, from the very beginning this development was geared towards maximizi ng the participation of leading Russian engineering companies and fabrication (shipbuilding) facilities.

The relatively shallow water depth at the site made the possible use of a gravity caisson for the platform an obvious choice. The specialist s of the Krylov inst itute conducted model tests of a gravity caisson for Prirazlom noye back in 1996, long before the actual contemporary platform configurat ion was developed (Krylov Instit ute, n.d.). At that time, Krylov, on the orders from Rosshelf, were in vestigating the wave and ice loads on the caisson, including the ice pile-up formation at ca isson walls. The work for the same client continued in 2000. By this time, Krylov rese archers were interested in evaluation of scour effects generated by an AZIPOD-equipped tanker which was to be tied to the Prirazlomnoye platform.
The most recent stage of dev elopment began in 2002, when Sevmorneftegaz (final field operations license owner) purchased the Norwegi an TLP Hutton platform. The concept was to use the Hutton’s topsides as the Prir azlomnoye platform drilling rig (Frantzen and Bambulyak, 2003). Krylov developed temporary anchorage for Hutton in the Kolsky Bay and the support systems required for separation of the topsides from the hull and for the subsequent long-term positioning of Hutton’s s uperstructure on two temporary barge floats (Krylov Institute, n.d.). The topsides modifications and caisson fabrication were implemented at the Sevmash and other yards in the area.

The steel caisson was assembled from four “super-blocks” (PRINT-EXPO Co. Ltd, 2007). Cast-in-place concrete was used for stiffening of the caisso n structure and its ballasting. Installation of modified Hutt on topsides on the caisson substructure was originally scheduled for July-August, 2006. The complete pl atform was planned to be towed from the Kolsky Bay to location in the South-East Barents in September , 2007 (PRINT-EXPO Co. Ltd, 2007).

The schematic view of the Pr irazlomnoye platform is shown in Figure 3-8. The topsides weight is 42,990 tons (39,000 tonnes) and the weight of the caisson is 106,925 tons (97,000 tonnes) SPG Media Limi ted (2007a). The caisson’s footprint is 413 x 413 ft (126 X 126 m). The platform has 14 oil storage tan ks with the total capacity of 710,000 barrels (113,000 m 3 ) and 2 water tanks with the total c apacity of 7,400,000 gallons (28,000 m 3 ). A single derrick will service 40 well slots.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 35 of 339 Rev. 0 The protection berm will be placed around the caisso n after the initial settlement at the site. The platform will be equipped with two offloading systems with capacities up to 353,000 ft 3 /hr (10,000 m3/hr) (SPG Medi a Limited, 2007a). The only in formation available on the design ice criteria is that t he Prirazlomnoye platform will be abl e to safely resist the ice pressure generated by the ridge with a 11.5 ft (3.5 m) thick co nsolidated layer (Central Design Bureau for Marine Engi neering (Rubin), n.d.).
Medynskoye Field Platform
A gravity caisson platform is also considered fo r the Medynskoye oil field, which is located in the same general area as Prirazlomnoye (Figur e 3-1). The field is closer to shore and the design water depth there is appr oximately 49 ft (15 m). The M edynskaya Center platform proposed for this field is an all-purpose st ructure (drilling, production, storage and offloading [Krylov Institute, n.d.]). The pl atform will have 38 wells and a storage capacity of 99,000 tons (90,000 tonnes). The DWT 44,000 tons (40, 000 tonnes) tankers will be used in offloading operations. The caisson substructure is 279 x 279 ft (85 m x 85 m) at the deck, and 335 x 335 ft (102 m x 102 m) at the seabed leve l. The total substructure weight is 130,000 tons (118,000 tonnes). T he topsides consist of seven functionally completed modules with a total weight of 15,800 tons (14,300 tonnes) (Krylov Institute, n.d.).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 36 of 339 Rev. 0 Figure 3-8: Prirazlomnoye Platform (Madslien, 2006)

3.3.1.3 Canadian East Coast
Presently, the only permanent bottom-founded stru cture employed offshore Newfoundland and Labrador is the Hibernia pl atform. However, according to recent news, the Hebron project, which will also empl oy a fixed structure, may soon be underway (The Telegram, 2007a; The Telegram, 2007b).

Hibernia

The Hibernia oil field is loca ted approximately 196 miles (315 kilometers) east-southeast of St. John’s. The field was discovered in 1979 and first oil was achieved in November 1997 (Department of Natural Resour ces, 2007). Current recoverabl e reserves for Hibernia are estimated to be 1.244 billion barrels (Depar tment of Natural Resources, 2007). Hibernia field development capital expenditures amounted to $5.8 billi on (Howell, 2007).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 37 of 339 Rev. 0 The Hibernia platform (Figure 3-9, Figure 3-10) , a gravity base structure (GBS) equipped with topsides producti on and drilling facilities, was employed for field development (Department of Natural Resources, 2007). The pl atform has a design production capacity of approximately 230,000 bopd and has an oil storage capacity of 1.3 million barrels (HMDC, 2007). Hibernia oil is lig ht sweet crude with a gr avity of about 32°-34° API (SPG Media Limited, 2007d).
For development drilling, the Hibernia platform is equipped with two derricks, allowing the simultaneous drilling of wells (HMDC, 2007). In 2004, one of the world’s longest extended reach wells, measuring 30,698 ft (9357 meters), was drilled from the Hibernia platform (Industry Canada, 2007).

Figure 3-9: Hibernia Drilling and Produc tion Platform with OLS (Bott, 2004)
Oil is exported from the Hibernia platform to shuttle tankers via a redundant Offshore Loading System (OLS). The OLS is comprised of a subsea pipeline, sub-surface buoy, and flexible loading hoses (HMDC, 2007). As a meas ure of safety, the tank er loading point is located 1.25 miles (2 kilometers) aw ay from the pla tform (HMDC, 2007).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 38 of 339 Rev. 0 Hibernia utilizes 3 custom-built shu ttle tankers for oil transport – the Kometik, Vinland, and Mattea . These shuttle tankers have storage c apacities of 850,000 barrels, are doublehulled and have double bottoms wit h additional strengthening (par ticularly at the waterline). They are bow-loaded and are capable of qui ckly disconnecting from the OLS (HMDC, 2007).
The Hibernia platform has a tota l height of 735 ft (224 m) and weig hs 1.32 million tons (1.2 million tonnes) (HMDC, 2007). Platform height is made up from the 279 ft (85 meter) caisson, 436 ft (133 meters) of to psides facilities, and 85 ft (26 meters) from the shafts that protrude through the GBS roof to support the topsides (H MDC, 2007). The four shafts (a utility, riser, and 2 drilling) each measure 56 ft (17 meters) in diameter (HMDC, 2007).

Figure 3-10: Hibernia Platform (HMDC, 2007)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 39 of 339 Rev. 0 The Hibernia GBS is a one-off design. To allow year-round production, the Hibernia platform is designed to withstand impact fr om sea ice and iceber gs (HMDC, 2007). Specifically, the platform is capable of withs tanding the impact of a 1. 1 million ton (1 million tonne) iceberg (1-in-500-year event) (SPG M edia Limited, 2007d), without sustaining damage, and a 6.6 million ton (6-million tonne iceberg) (1-i n-10,000-year event), with repairable damage (HMDC, 2007). Although the prob ability of an iceberg colliding with the platform is low, Hibernia still employs an aggressive ice management strategy (HMDC, 2007).
The Hibernia GBS is constructed of high-str ength reinforced and pre-stressed concrete, which is reinforced with steel (rebar) and pr e-stressed tendons (SPG Media Limited, 2007d). The GBS caisson, which measures 348 ft (106 m) in diameter, consists of an exterior 4.6 ft (1.4 m) thick ice-wall with 16 t eeth intended to distribut e iceberg loads over the entire structure (H MDC, 2007). Furthermore, the GBS has an ice-belt, which includes the ice-wall, measuring 49 ft (15 m) thick (HMDC, 2007).

Hebron

The Hebron oil field, discovere d in 1981, is located appr oximately 220 miles (350 km) offshore Newfoundland in close proximity to the Hibernia, Terra Nova, and White Rose developments.
Hebron is a heavy oil field containing an esti mated 400-700 million barrels of resources (Chevron, 2007). With close-neighboring fiel ds, Ben Nevis and West Ben Nevis, the Hebron/Ben Nevis Complex has a reserve estimate of 731 million barrels of oil (Department of Natural Resources, 2007).

Field development has not yet commenced. However, with the signing of a memorandum of understanding (MOU) in August 2007, it has been indicated that constr uction is expected as early as 2010 (Calgary Herald , 2007), and that the field may ac hieve first oil as early as 2015 (The Telegram, 2007a). A prelim inary cost estimate of $4 billion to $5 billion was reported for field developm ent (The Telegram, 2007a).

Although several options have been evaluated (subsea tieback, FPSO with subsea wells, new generation GBS, and FPSO with wellhead platform (Depar tment of Natural Resources, 2007)), the Hebron field development will be based on the use of a GBS similar to that of Hibernia (The Telegram, 2007b). The Hebron GBS, however, will be sma ller then Hibernia, requiring less concrete and being easier to build (The Telegram, 2007b).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 40 of 339 Rev. 0 Other Proposed Grand Banks Structures
The Steel Stepped Gravity Ba se (SSGB) shown in Figur e 3-11 was developed for application on the Grand Banks of Newfoundland in water depths of around 330 ft (100 m) (Fitzpatrick and Kennedy, 1997). The SSGB concept represents a departure from traditional cylindrical concrete gravity base production platforms with respect to shape, material and method of construction.

Figure 3-11: Steel Stepped Gr avity Base StructureIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 41 of 339 Rev. 0 The principal criteria affect ing the design of an offshor e platform in the Grand Banks environment is icebergs, wave s and foundation strength para meters. The design iceberg for the Grand Banks is estimated at a mass 4.4 million tons (4 million tonnes). A berg of this mass can impart a shear force of 100,000 tons (90,000 tonnes) and a mom ent of 23 million ton-ft (6.3 million tonne-m) into a gravity base structure. This ice load can be applied from any direction and at any elevati on. A structure capable of resist ing such an ice load has to be monolithic or non-wave-transparent.
Ideally the design wave load would be very clos e to the ice load. The SSGB achieves this by reducing the diameter of t he structure as it pr ogress upwards through the water column. The stepping process reduces the wave shear force to 110,000 tons (100,000 tonnes) and a moment of 18 million ton-ft (5 million tonne-m) which is very close to the ice load.
In specific terms, the base of the SSGB must minimally have an area capable of resisting the shear and overturning moments created by the ice or wave loads. The foundation parameters in conjunction with the wave and ice load determine the necessary base area of the structure to be 140,000 ft 2 (13,000 m 2 ). The SSGB has been reviewed for deployment at several locations on the Grand B anks. Parameters chosen for the foundation design are considered representative of some of the weaker strength sites. Thus, the structure base area is unlik ely to increase no matter w here the structure might be considered for deployment.
By optimizing the SSGB’s shap e the designer has been able to:

• Converge the global loads;

• Minimize material use to 93,700 tons (85,000 tonnes) of steel and a ballast weight of 220,500 t ons (200,000 tonnes);

• Provide free storage capacity. The stru cture needs a minimum footprint and size to resist the applied loads. This mi nimum size provides “free space”. This free space provides a storage capac ity of 750,000 to 1,000,000 bbls;

• Provide hydrostatic stability. Steel stru ctures have a low vertical center of gravity (VCG) and the VCG of a steel pyramid shape can be further lowered by the use of solid ballast. This low VC G offers stability under towing and as a result the structure can be safely tow ed to site when loaded with up to 33,000 tons (30,000 tonnes) of topsides; and,IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 42 of 339 Rev. 0 • Minimize setup time. All solid ballast has been insta lled prior to tow out. Water ballast is added to hold the structure in place.
The SSGB provides an economical solution to the challenges of exploration and hydrocarbon production in iceberg infested waters.

3.3.1.4 Cook Inlet
To date, a total of 16 jacket st ructures have been installed at t he Inlet using three structural concepts; the monopod, the tr ipod and the quadpod. The first of these structures was installed in 1964 and the last in 1986.

Figure 3-12: Cook Inlet Infr astructure (CIRCAC, 2007)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 43 of 339 Rev. 0 The fixed jacket structures designed for Cook In let’s environment diffe r from conventional jacket structures in several ways:

• Partially constructed fr om low temperature steel;

• The jacket systems are composed of ve ry large ice reinforced legs with diameters in excess of 14 ft (4.3 m);

• The jacket bracing is located several f eet below the water line. This protects the bracing from ice impacts and prevents ice bridging; and,

• The jackets use an X-bracing system rat her then K type bracing (Figure 3-13 and Figure 3-14). This provides additi onal load paths in the event of a member failure.

Figure 3-13: Conventional Jacket Structure (OOP, 2007) Figure 3-14: Cook Inlet Jacket Structure (CIRCAC, 2007)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 44 of 339 Rev. 0 The Inlet’s jacket structures have been designed using a variety of ic e loads, wave heights and water depths:

• Ice thickness varying from 2.8 to 6 ft (0 .9 to 1.9 m) with a cr ushing strength of 300 psi (2.1 MPa);

• Design wave heights from 28 to 41 ft (8.5 to 12.5 m); and,

• Design depths from 62 to 183 ft (19 to 56 m).

The load variation is dependent on the structure’s spec ific location, the designer’s interpretation and applicat ion of the available meto cean data, and the designer’s understanding of jacket structural responses to sea ice loading. An online database of the Inlet’s structures can be accessed from the C ook Inlet Regional Citize ns Advisory Council website (CIRCAC, 2007).IMVPAProject No. C-0506-15Arctic Offshore Technology Assessmentof Exploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 45 of 339 Rev. 0Table 3-3: Summary of Cook Inlet Platforms (CIRCAC, 2007)Summary of Cook Inlet PlatformsWavePlatformNameTypeDesignIceThick,ft (m)Height,ft (m)Period(Sec)WindVelocity,MPH(km/h)Earthquake(g)Current,ft/s (m/s)LegDia.,ft (m)WaterDepth,ft (m)Year DesignerJacketWt,tons(tonnes)DeckWt,tons(tonnes)Anna Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 77 (23.5) 1966 Earl & Wright1515(1374)1200(1089)A Quadpod 6 (1.8) 41.5 (12.6) 10.8 65 (105) 0.15 10 (3) 14.6 (4.5) 83 (25) 1964 Earl & Wright N/A N/ABaker Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 102 (31) 1965 Earl & Wright2533(2298)N/ABruce Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 62 (19) 1966 Earl & Wright1415(1284)1200(1089)C Quadpod 3.5 (1.1) 28 (8.5) 8.5 65 (105) 0.06 12 (3.7) 15.5 (4.7) 73 (22) 1967 Earl & Wright N/A N/AGranite Point Quadpod 5 (1.5) 28 (8.5) N/A N/A N/A 13.5 (4.1) 17 (5.2) 75 (23) 1966 Brown & Root3400(3084)N/AGrayling Quadpod 6 (1.8) 28 (8.5) 8.5 100 (161) 0.1 10 (3) 17 (5.2) 125 (38) 1967 Brown & Root3550(3221)N/AKing Salmon Quadpod 3.5 (1.1) 28 (8.5) 8.5 65 (105) 0.06 12 (3.7) 15.5 (4.7) 73 (22) 1967 Earl & Wright1585(1438)1200(1089)Monopod Monopod 6 (1.8) 28 (8.5) 8.5 100 (161) 0.06 10 (3) 28.5 (8.7) 66 (20) 1966 Brown & Root6000(5443)N/ASpark Tripod 3.5 (1.1) 28 (8.5) 8.5 60 (97) N/A 10 (3) 13 (4.0) 62 (19) 1968 McDermott N/A N/ASpurr Tripod 3.5 (1.1) 28 (8.5) 8.5 60 (97) N/A 10 (3) 13 (4.0) 67 (20) 1968 McDermott N/A N/ASteelhead Quadpod 4.2 (1.3) 28 (8.5) 8.5 80 (129) N/A 12.6 (3.8) 18 (5.5) 183 (56) 1986 McDermott N/A N/ATyonek Quadpod 2.8 (0.9) 27.5 (8.4) 8.5 80 (129) 0.110.1 (3.1) 14 (4.3) 100 (30) 1968 McDermott N/A N/ADillion Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 92 (28) 1967 Earl & Wright1585(1438)1200(1089)Dolly Varden Quadpod N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/AOsprey N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/AN/A Not AvailableIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 46 of 339 Rev. 0 The Inlet’s current metocean data characteri zes it as an area with large temperature fluctuations of 51°F (11°C). Strong 13 ft/sec (4 m/s) currents, 22 ft (7 m) spring tides, variable size first-year ice floes of 6.5 ft (2 m) thick and pressure ridges as thick as 20 ft (6 m) are common to the area. Refer to Appendix A for a summary of Cook Inlet’s metocean data.
3.3.1.5 Jack-up Drilling Rigs
The jack-up rig was first introduced to the offs hore industry in the mid 1950’s. The jack-up rig was developed to provide a fixed base drill rig capable of operating in harsh environments (wave only) with the flexibility to relocate to alternate drilling locations.
A jack-up drilling rig consists of a hull, legs a nd a lifting system. A wide variety of hull styles, legs and lifting systems exist. The variation is primarily a result of the trade off the designer must make between drilling st ability and buoyancy stability.
Rig installation involves a wet or dry tow to site. Wet tows usually occur over short distances. Under wet tows, the ri g provides its own buoyancy. Dr y tows typically occur over large distances. During dry tow, the rig is carried on a barge or on the deck of a transporter. Once on site, the rig’s legs are lowered to the seabed and the hull is elevated to provide a stable work deck. The rig is no w ready to begin drilling operatio ns. Removal of the rig is the reverse of the installation.

A modern drilling jack-up is capa ble of working in wave heights of 79 ft (24 m), in winds of 100 knots, in water depths appr oaching 500 feet (152 m) and to drill depths of 35,000 ft (10,700 m) (BASS and OTD/KeppelFels, 2005). Jack-up platforms have been constructed for numerous ocean environments; yet none have been constructed to operate in sea ice conditions.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 47 of 339 Rev. 0 Table 3-4: LeTourneau Super Gorilla O perating Parameters (from LeTourneau Technologies, 2007)
Environmental Criteria 504 feet of Leg, Elevated Weight of 28,550 Kips

Water Depth Feet (Meters) Wind Speed Knots (Meters/Sec.) Wave Height Feet (Meters) Air Gap Feet (Meters) 450*(137.2) 100*(52) 69* (21.0) 50*(15.2) 400*(121.9) 100*(52) 71* (21.6) 50*(15.2) 328 (100.0) 100 (52) 81 (24.7) 55 (16.8) 300 (91.4) 100 (52) 82 (25.0) 60 (18.3) 250 (76.2) 100 (52) 87 (26.5) 60 (18.3) 200 (61.0) 100 (52) 88 (26.8) 60 (18.3) 150 (45.7) 100 (52) 88 (26.8) 65 (19.8)
504 feet of Leg, Elevated Weight of 31,810 Kips

Water Depth Feet (Meters) Wind Speed Knots (Meters/Sec.) Wave Height Feet (Meters) Air Gap Feet (Meters) 328 (100.0) 100 (52) 72 (21.9) 55 (16.8) 300 (91.5) 100 (52) 73 (22.3) 60 (18.3) 250 (76.2) 100 (52) 75 (22.9) 60 (18.3) 200 (61.0) 100 (52) 76 (23.2) 60 (18.3) *Specifications when using 604-F oot (184.1 meter) leg length. Dynamic effects included

A study by CKJ Engineer ing (CKJ Engineering, 1997), the development and implementation of a jack-up dr illing program on the Grand Bank s of Newfoundland (Bagnel, 2007) and the anticipated cons truction of a new Russian ic e-resistant jack-up rig are indicative that the operating range of jack-up drilling rigs ca n be marginally expanded to include areas of seasonal sea ice and of marginal sea ice concentration.
CKJ Engineering’s study (CKJ Engineering, 1997) involved brie f investigations into the structural feasibility of using jack- up Rig SX during freeze-up in Sakhalin.
The successful development and implementati on of a jack-up drilling program on the Grand Banks of Newfoundland, Canada, was accomplis hed by the understanding of the ice-free season and implementation of an ice management program (Bagnel, 2007).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 48 of 339 Rev. 0 The ice-resistant jack-up rig Arkticheskaya (F igure 3-15) is under construction at the Severodvinsk Shipyard, Russia. It is being constr ucted to operate in Arctic water depths of up to 330 feet (100 m) and in ice flows of 1. 6 feet (0.5 m) thi ck (MNP Global, 2007).
In light of CKJ’s study, the successful im plementation of a jack-up drilling program in Newfoundland, the anticipated construction of ice-resistant jack-ups and the continued development of jack-up rig technology, an ex tension of a traditio nal seasonal jack-up drilling program may be consid ered for the Bering Sea.

Figure 3-15: Ice Resistant Jack-up Arkticheskaya 6500 / 10-30 (JSC Gazprom, 2007b)
3.3.2 Floating Structures
3.3.2.1 Canadian East Coast
Currently there are 3 produci ng fields in operation offs hore Newfoundland within the Grand Banks Jeanne d’Arc Basin (Figur e 3-16). Two of these fields , the Terra Nova and White Rose, have employed FPSO (Floating Produc tion Storage and Offloading) vessels for field development.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 49 of 339 Rev. 0 Figure 3-16: Grand Banks Field De velopments (Howell, 2007)

Terra Nova
Discovered in 1984 by Petro-Canada, the Te rra Nova field is currently the 2 nd largest producing field off the east coast of Canada. Furthermore, the Terra Nova was the first ‘harsh environment’ developmen t in North America to utilize a FPSO vessel (Petro-Canada,2007a). The Terra Nova field is located approximately 220 miles (350 kilometers) eastsoutheast of St. John’s. Field water depths range from 295 to 330 ft (90 to 100 meters) (SPG Media Limited, 2007e).

Production from the $2.8-billion Terra No va project began in Ja nuary, 2002 (Bott, 2004). Field recoverable oil reserves have been estimated at 440 millio n barrels and life of field is estimated to be 19-21 y ears (Petro-Canada, 2007a).
As shown in Figure 3-17, a variety of equipm ent, vessels, and subsea infrastructure are employed for the development and operat ion of the Terra Nova field.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 50 of 339 Rev. 0 Figure 3-17: Terra Nova Field De velopment (Petro-Canada, 2007a)

Through an integrated subsea and topside production system, oil is produced, stored, and subsequently offloaded to shuttle tankers. Produc tion from subsea wells/trees is gathered by subsea manifolds and conveyed topside (to the FPSO) via flex ible flowlines and risers. More then 25 miles (40 km) of flexible flowlines , control umbilicals, and dynamic risers were required for the project (Furlo w, 1998). Flowline and riser in ner diameters ranged between 5 and 10 inches (125 and 250 mm), while the umbilicals used were the largest ever manufactured at the time, with an outside diamet er of 10.4 inches (265 mm) (Cottrill, 2000).

To protect against potential iceberg gouging, subsea equipment is located in excavated seafloor pits, called open glory holes (Figur e 3-18). Glory holes us ed for the project are approximately 38 ft (11.5 m) deep and base dimens ions range from 53 ft x 53 ft (16 m x 16 m) to 184 ft x 53 ft (56 m x 16 m) (Furlow, 1998) . Excavation of the glory holes was carried out by a giant trailer suction dredger, t he Queen of The Netherlands (Cottrill, 2000)

. Although considered sacrif icial and equipped with ‘weak links’ to protect wellhead equipment, flowlines were trenched and buried in the seabed to prov ide stability, insulation, and afford some measure of protection from iceberg gouging. The in itial plan was toIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 51 of 339 Rev. 0 provide 5 ft (1.5 meters) of cover, however, due to trenching difficultie s some flowlines were rock-dumped instead (Cottrill, 2000).

Figure 3-18: Open Glory Hole (Petro-Canada, 2007a)

To avoid icebergs and severe s ea ice conditions, the Terra Nova FPSO is equipped with an internal disconnectable turret system. During a disconnect, the spider buoy, along with its attached risers and moorings, is released allo wing the FPSO to move off station and sail out of harms way. Once released, the spider buoy sinks to a mid-wate r equilibrium depth of 115 ft (35 meters) (measured from surfac e to buoy top) (Cottrill, 2000).

A planned disconnect, which entails well shut-in, depressurizati on, flowline flushing, etc., can be executed in under 4 hour s, while in an emergency si tuation, disconnect can be achieved in approximately 15 minutes (Sof ec, 2007). Up until the final moment of disconnect (i.e. prior to mechanical connector re lease), the sequence is reversible (Furlow, 1998). The turret system is designed to re connect in a matter of hours with normal operations support (Furlow, 1998) . Reconnect can be accomplished in up to 7 ft (2.1 meter) significant wave heights (Cottrill, 2000).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 52 of 339 Rev. 0 In June 2007, the Terra Nova FPSO underwent its first planned disconnect when it left the field to undergo several months of maintenance work in the Keppel Verolme shipyard in Rotterdam, the Netherlands. The Terra Nova arrived back in the field on September 25 th and was reconnected to it’s moorings on October 1 st (Petro-Canada, 2006).
There were a number of design challenges for the Terra Nova disconnectable turret system; severe weather and storm conditions, re latively shallow wate r, a large vessel, a significant number of risers, a hea vy mooring system and the ability to disconnect/reconnect. At time of design, the Terra Nova turret was quoted “as the most sophisticated and complicated turret ever ” to be constructed (Furlow, 1998).
At the heart of the development and production system is the Terra Nova FPSO, shown in Figure 3-19. The Terra Nova measures 959 ft (292.2 m) long by 149 ft (45.5 m) wide and more than 18 stories high from keel to helid eck (Petro-Canada, 2007a). During operation, it has a draft of approximately 43 to 62 ft (1 3 to 19 m) and a maximum displacement of 213,000 tons (194,000 tonnes) (Fletcher and Clark, 2001). The Terra Nova has a production rate of 180,000 bp d (Howell, 2007) and an integr ated storage capacity of 960,000 barrels of oil.

Figure 3-19: Terra Nova FPSO (Petro-Canada, 2007a)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 53 of 339 Rev. 0 The Terra Nova FPSO is pur pose built for the harsh envir onment experienced on the Grand Banks. In addition to a disconnectable tu rret, the Terra Nova is equipped with a double-hull, 3,300 tons (3,000 t onnes) of additional steel to provide ice strengthening (Petro-Canada, 2007a), and a thruster-assi sted mooring system (Cottrill, 2000).
As a result of ice strengthening, the Terra No va is capable of withst anding the impact of a 110,000 ton (100,000 tonne) iceberg tr aveling at 1-knot (Cottrill, 2000). Furthermore, it can operate in moderate to high pa ck ice concentrations (5 to 8/10ths) and is capable of maintaining station in concentrati ons of 8 to 9/10ths (PERD, 2002).

The thruster-assisted mooring system is desi gned based on 100-year storm conditions; sea ice loads do not govern mooring design (Cottr ill, 2000). The mooring system is comprised of a nine-leg group catenary chain with a heavy excursion limiter system (Sofec, 2007) and 5 thrusters with a combined capability of 33, 500 hp (25 MW) (Cottrill, 2000). During 100- year storm conditions, thrusters are fully utilized to maintain station (Cottrill, 2000).
Figure 3-20 below (PERD, 1998 ) has been included to illustrate Terra Nova’s significant mooring capabilities and provid e comparison to other FPSO’s as well as mooring system designs dominated by sea ice loads.

Crude oil is offloaded from the Terra Nova to ice strengthened shuttle tankers. The Terra Nova is equipped with a tandem offloading system, which is designed for connection/disconnection in up to 16 ft (5 m) significant wave heights (Furlow, 1998).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 54 of 339 Rev. 0 Rough Comparison of Vessel Mooring System Capab ilities

0 500 1000 1500 2000 2500 Canmar Drillship Kulluk Drilling Unit

Petrojarl 1 FPSO Captain FPSO Terra Nova FPSO

Approximate Mooring System Capacity (tonnes)

Figure 3-20: Comparison of Moori ng Capabilities (from PERD, 1998)

White Rose
The White Rose field (Figure 3-21) is lo cated approximately 220 miles (350 km) east of Newfoundland’s Avalon Peninsula and about 31 miles (50 km) fr om the Terra Nova field (Clarke, 2001).

Discovered in 1984, White Rose is the th ird major oil field on the Grand Banks. Development commenced in 2002 and, with a pre- production cost of $2.35 billion, the field achieved first oil in November 2005 (Howell, 2007).

Current estimated oil reserves for the Whit e Rose field are 283 million barrels (CNLOPB, 2007a), and total production life is estimat ed to fall between 12 and 15 years (Husky, 2007). White Rose oil quality is 30 degrees API (Husky, 2007a).
The White Rose field is situated in approximat ely 395 ft (120 meters) of water, and like its predecessor, the Terra Nova, field developm ent was based on employing an integrated production system. The system is comprised of subsea wells and associated equipment, flexible flowlines, dynamic risers, and a FPSO facility (Clarke, 2001).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 55 of 339 Rev. 0 Figure 3-21: White Rose Field Deve lopment Schematic (Clarke, 2001)

At each drill center, subsea we lls and equipment are clustered together and located in open glory holes to protect against potential iceberg gouging. White Ro se glory holes, shown in Figure 3-22, are excavated to a maximum depth of 36 ft (11 me ters) to ensure that the top of equipment (critical to well integrity) is loca ted a minimum of 6.6 to 9.8 ft (2 to 3 meters) below the surrounding seabed (Husky, 2001a). Glory holes have been excavated by two methods; a ROV assisted gr ab excavation system (Boskalis Offshore bv, 2003) and a trailing suction hopper dredge (Husky, 2006).

The White Rose field uses over 25 miles (41 km) of flexible flowlines, risers, and umbilicals (Husky, 2007a). Flowlines are laid on the s eafloor and are insulated for temperature maintenance (Husky, 2006). To afford a meas ure of iceberg protec tion, flowlines and umbilicals are equipped with weak link technology (Husky, 2006).

Similar to the Terra Nova, White Rose fi eld development is ce ntered around the FPSO facility, the SeaRose (Figure 3-23).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 56 of 339 Rev. 0 Figure 3-22: Typical White Rose Glory Hole (Lochte, 2007)

Figure 3-23: SeaRose FPSO (Husky, 2007a)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 57 of 339 Rev. 0 The SeaRose has a production capacity of 140,000 bopd (Husky, 2007b) and can store up to 940,000 barrels of processed oil (Husky 2007). In overall length, the SeaRose measures 876 ft (267 m). The hull measures 151 ft (46 m) in breadth and is 87 ft (26.6 m) deep (SPG Media Limited, 2007b). The SeaR ose has a design draft of 59 ft (18 m) and a displacement of 206,200 tons (187,100 tonnes) (SPG Media Limited, 2007b).

The SeaRose, like the Terra Nova, is desi gned and purpose-built for the Grand Banks harsh environment. It is double-hulled, ice strengthened, and equipped with a disconnectable internal turret mooring syst em. The SeaRose hull form is based on a proven Grand Banks shuttle tanker design (SPG Media Limited, 2007b) . Modifications to the tanker design included deep ening the hull by 13 ft (4 m) and making changes to the bow (SPG Media Limited, 2007b).

The SeaRose hull and moorings are designed to withs tand the impact of a 110,000 ton (100,000 tonne) iceberg; in the event that an (unmanageable ) iceberg of greater mass approaches, the SeaRose will disconnect from its moorings (Husky, 2001a). Ice loading criteria, presented elsewhere in the White Rose development pl an, also indicates that the SeaRose is likely designed to withstand the impact of such an iceberg moving at 1.6 ft/s (0.5 m/s) (Husky, 2001a). The development plan also indicate s that the SeaRose is likely capable of withstanding 1 ft (0.3 m) thick pa ck-ice with coverage of up to 50% (Husky, 2001a).
In addition to ice strengthening, the SeaRose is designed to remain connected to its moorings during 100-year storm conditions (Cla rke, 2001). Furthermore, production can be maintained during 1-year storm conditions and in moderate sea ice coverage up to 50% (Clarke, 2001).

A notable difference from the Terra Nova is that the SeaRose employs a passive mooring system; that is, thrusters ar e not employed for station keeping (Clarke, 2001). The SeaRose mooring system is comprised of 3 gr oups of chain/wire mooring lines (Clarke, 2001). In the event that the SeaRose disconnected from its moorings, it would avail of its main (ship) engines for propulsi on to move off station.

Oil is offloaded from the SeaR ose via a 395 ft (120 m) long, 20 inch (508 mm) diameter, flexible loading hose (SPG Media Limited, 2007b) to purpose-built double-hulled shuttle tankers (OilOnline, 2005). Shu ttle tankers are bow-loaded, as shown in Figure 3-24, and can connect to the SeaRose’s mooring hawser in significant wave heights of 16 ft (5 m)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 58 of 339 Rev. 0 (Husky, 2001a). The hawser bas ed mooring system has emerge ncy disconnect capability and during the offloading hawser tension is continually monitored (Husky, 2001a).

Figure 3-24: SeaRose Offloading to Shuttle Tanker (Howell, 2007)

Labrador

From the onset of the 1970’s, and continuing until 1985, t he Labrador shelf experienced significant exploration activi ty. During this time period, 26 exploration and 2 delineation wells were drilled. Five ‘significant disco veries’ were made with total reserves of approximately 4.2 tcf of natural gas (120 billion m 3 ) (CNLOPB, 2007b) and 123 MMbbls of natural gas liquids (Wagner, 2003).
In recent years, interest and activity offshor e Labrador has increased. During a seminar in 2003, Labrador Gas Revisited: Technologies for Development , Fluor Canada presented several options for gas production (Wagn er, 2003). Based on the harsh environment characteristic of the Labrador Sh elf region, the use of floating structures was considered on a seasonal basis.

Fluor indicated that a comb ined production option employing a FPSO with CNG carriers for gas export, or solely the use of CNG carriers (with minimum on-ship processing), would be technically feasible (Wagner, 2003). However, as a result of short production season duration (ranging from four to six months), these options ma y not be economically viable and further analysis would be required (Wagner, 2003). To date, although progress has been made, a commercial CNG so lution has yet to emerge.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 59 of 339 Rev. 0 Drillships

As aforementioned, the Labrador Sea off the Canadian East Coast experienced an active drilling campaign in the 1970’ s and 1980’s. Water depths r anged up to 1900 ft (580 m) and averaged around 655 to 985 ft (200 to 300 m). Wells took approx imately 53 to 84 days to reach depths of 6900 to 10,500 ft (2100 to 3200 m). Frequently, we lls had to be re-entered in the next drilling season to test the well or properly suspend/abandon the well. The drilling season was considered to be 110 to 120 days, at best.
During this era (circa 1970 – 1980 ), the dynamically positioned (D P) drillships utilized in the Labrador Sea were state-of-the-art vessels. The “Pelican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, and “Neddrill 2” were all used ext ensively (Figure 3-25 and Figure 3-26). The “Sedco 445”, another DP drillship which drilled t he Snorri J-90 well in 1975, was the first rig in the industry to operate on a well in fu ll DP mode in 1971 offshore Brunei. One of their main advantages over moored vessels was enhanc ed mobility to disconnect if required and avoid icebergs or pack-ice in the early part of the Labrador drilling season.
Many of these drillships also offered reinforced hulls for protection from ice impact and large storage capacity a llowed great self sufficiency in th is remote location. However, advantages offered by the ship-shape design became a disadvantage in the months of October and November. It is known that ship-s hape hulls are subject to poor heave, pitch, and roll motions that prevent effi cient drilling/completion/testing operations. For this reason, semi-submersible designs would be best in th e later months of the Labrador drilling season, from a motion standpoint.
The design of the “Pelican” seri es drillships has evolved over the years. The first units, “Pelican”, “Havdrill” and “Petrel” laid t he foundation for the enhanced design of the next series of “Pelerin”, “Polly Bristol”, “Ben Ocean Lancer” and “Pacnorse I”. In the early 1980's the “Pelican” design was further enhanced to c onstruct the ice-class drillships “Valentin Shashin”, “Mihail Mirchink ” and “Viktor Muravlenko”.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 60 of 339 Rev. 0 Figure 3-25: Design Concept of Drillships “Pelic an”, “Pelerin”, “Petrel”, “BenOcean Lancer”, and “Neddrill 2” (GustoMSC, n.d.)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 61 of 339 Rev. 0

Figure 3-26: Additional Design Details of “Pe lican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, and “Neddrill 2” (GustoMSC, n.d.)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 62 of 339 Rev. 0 Orphan Basin

The use of a SPAR under ice conditions on the east coas t of Canada has been proposed (Murray, 2004), albeit for deeper water conditions.

At the time, twelve SPARS had been installed with the deepest being at 5,400 ft (1645 m). Some of the features of a concrete spar we re identified as being a traditional structure, 95% of the structure could be fabricated using slipforming operations, it would have a relatively fast construction time, and it was suitable for a harsh environment.

The proponents indicate t hat the structures can be built either out of steel or concrete. The structure can also be used fo r drilling and work over and c an be used for oil storage. A configuration with bottom tensioned risers was proposed along with a disconnect feature (see Figure 3-27 and Figure 3-28).
The location looked at for the structure (Or phan Basin) could have a significant wave height of 52.5 ft (16 m) and potentiall y pack ice conditions. The di sconnect feature would permit the SPAR to move off station in the event of the approach of a significant ice feature.
3.3.2.2 Canadian High Arctic

Floating Ice Drilling Pads
It should be noted that the complete Section that follows has been extracted from MMS Project No. 468 (C-CORE, 2005). Minor modifications to the text have been made.
The use of ice as a support material for offs hore oil and gas explorat ion began in 1973 at the Hecla exploration well in the Canadian High Arctic. T he floating drilling pad used artificial thickening of the nat ural ice sheet by flooding with seawater. Build-up rates were dictated by the time required to freeze thin la yers of water, which were repeatedly added to the frozen core. Close to 40 floating ice pads were successfully used between 1973 and 1986 in the Canadian High Arctic using flooding and freezing tec hniques in water depths up to 1640 ft (500 m) (Masterson et al., 1987).

A total of 38 wells were drilled from float ing ice pads (see Figure 3-29) between 1973 and 1986 (Masterson et al., 1987). Table 3-5 sh ows a chronological list of sites.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 63 of 339 Rev. 0 Figure 3-27: SPAR Concept for Offshore Canada (from Murray, 2004) Figure 3-28: Disconnected SPAR (from Murray, 2004)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 64 of 339 Rev. 0 Figure 3-29: Cross-Section of Cape Alison Fl oating Spray Ice Pad (Masterson et al., 1987)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 65 of 339 Rev. 0 Table 3-5: Floating Ice Pads Constr ucted in the Canadian High Arctic

Structure Dates Original Thickness, ft m) Design Thickness, ft (m)
Hecla N-52 1973/74 6.2 (1.9) 17.4 (5.3) Resolute Bay Test 1974

East Drake I-55 1974/5 6.6 (2.0) 16.4 (5.0) NW Hecla M-25 1975/76 7.9 (2.4) 16.4 (5.0) Jackson Bay G-16 & 16A 1975/76 3.9 (1.2) 18.0 (5.5) W. Hecla P-62 1975/76 6.2 (1.9) 14.8 (4.5)

Drake F-76 1977/78 3.3 (1.0) 23.3 (7.1) Roche Point O-43 1977/78 6.2 (1.9) 17.1 (5.2) & Cape Grassy I-34 1977/78 2.95 (0.9) 17.4 (5.3)

Hazen Strait F-54 1978/79 6.9 (2.1) 21.3 (6.5)

Whitefish H-63 1978/79 20.7 (6.3) 21.0 (6.4) Whitefish H-63A 1979/80 22.6 (6.9) 23.6 (7.2) Char G-07 1980 Baleana D-58 1980

Cisco B-66 1980/81 ~39.5 (~12) MacLean I-72 1980/81 18.4 (5.6)

Cisco C-42 1982/82 18.7 (5.7) Cape Mamen F-24 1981 15.1 (4.59) 21.0 (6.4) Sculpin K-08 1981/82 33.1 ( 10.1) 33.8 (10.3) Seal Island Floating Road 1981/82 3.6 (1.1) 9.2 (2.8) Whitefish A-26 1981/82 21.7 (6.6) 23.3 (7.1) Cisco K-58 1982/83 Grenadier A-26 1982/83 4.3 (1.3) 22.6 (6.9) Skate C-59 1982/83 20.0 (6.1) E Drake L-06 1982/83 20.3 (6.2) N Buckingham N-69 1982/83 21.7 (6.6) Cisco M-22 1983/84 18.0 (5.5) 23.0 (7.0) Cape Alison 1984/85 2.95 (0.9) 22.6 (6.9) N Cornwall N-49 1985/86 2.95 (0.9) 23.3 (7.1)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 66 of 339 Rev. 0 Ice pads were constructed by pumping water ont o the ice in thin laye rs, and allowing them to freeze in place to increase the thickness of the ice sheet at the drilling location. The majority of the drilling pads were built on level first-year ice of t he order of 3.3 to 6.6 ft (1 to 2 m) thick. A number of pads were built on thick multi-year ice, for which flooding was used to provide a smooth surface ra ther than to increase the thickness. Construction of the platform took between 20 and 75 days, with an average build-up rate of approximately 2.8 inches/day (70 mm/day). Build-up rates varied significantly as a func tion of temperature, wind speed and equipment used. The platform w ould generally be ready to accept the rig during January or February, allo wing up to 100 days of drilling.

The main structure construct ed was the drilling pad to s upport the rig and associated equipment. Other important infras tructure included a relief pa d for use in the event of blowout and an airstrip for both Twin Otter and Hercules aircraft.
Movement of the landfast ice sheet was not a gr eat concern in the arct ic islands, based on a number of years of hi storical data and the landlocked nature of th e ice. The deep water depth provided some allowance fo r relative horizontal movem ent between the platform and seabed without over stressing the riser.
Spray ice started to be used for the constructi on of the floating Arctic island platforms in 1984/85 at Cape Alison and 1985/86 at North Co rnwall. High pressure, high volume pumps and monitors were used to enhance the freezing rate of seawater to build up the ice platform thickness.

3.3.2.3 Russian Arctic

Shtokman
The Shtokman (Shtokmanskoye) gas field was discovered in 1988 and appraised between 1990 and 1995. The field is loca ted in the Barents Sea, appr oximately 373 miles (600 km) offshore, in water depths of 1080 to 1150 ft (330 to 350 m) (see Fi gure 3-1). Detailed information on the environmental and operating conditions at Shto kman field is contained in Zubakin et al. (2004b), Naumov (2004), Buzi n (2004a), Buzin (2004b), Zubakin et al. (2004c) and highlights of these p ublications are pres ented in Appendix A of this report. The summary of basic information about Shtokman is presented in Luff (2006). The Shtokman gas reserves are estimated at 112 to 116 tcf (3.2 to 3.3 trillion cubic meters), and the condensate reserves at 220 million barrels. This is the fourth largest gas field ever found. The expected production rate is 10 Bcf (283 million m 3 ) and more than 150 wells will beIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 67 of 339 Rev. 0 required. First production is expected in 2012, with a subsequent field life of 50 years. The estimated total development cost is USD 20 b illion. It was widely expected that western oil companies would have a substantial share of the Shtokman development, but presently it is anticipated that Gazprom will be the sole operator.
Both subsea and platform development concepts have been considered for the field. The subsea development case is described further in Section 3.3.3.3.
In the platform scenario, Gazprom is consider ing three tension leg platforms (TLP’s) with topside weights of 55,000 tons (50,000 tonnes) and a total wei ght of 204,000 tons (185,000 tonnes). Forty subsea wells will be required (Luff, 2006). The three-platform scenario for Shtokman is mentioned in other sources as well, for example, Gazprom and VNIIGAZ (n.d.). Several concepts are being developed for the transportation and transshipment of hydrocarbons from the field. The search for t he most efficient supply base location for the Shtokman exploration and production activities is also underway (see Section 3.3.5 below for more details).

3.3.2.4 Sakhalin Island

Sakhalin 2
The Sakhalin 2 project utilizes a floating st ructure for offloading oil produced at the Molikpaq structure. Oil produced from the Molikpaq platform is ex ported via a 12-inch subsea pipeline to a Floating Storage and Offl oading (FSO) vessel, the Okha supertanker, located 1.2 miles (2 km) away, and which is anchored to a Single Anchor Leg Mooring (SALM) (Figure 3-30 and Figure 3- 31). Oil is then loaded onto t ankers for export (Figure 3-32) (SPG Media Limited, 2007c).

Due to severe climatic conditions in the S ea of Okhotsk, Molikpaq production is currently limited to a six-month period when the sea is free of ice. In the winter months when production is shut-in, the SALM unit is lowered to the seabed and the Okha FSO is chartered out to transport oil for other parties ( Rigzone, 2007a).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 68 of 339 Rev. 0

Figure 3-30: “Smit Sakhalin” Connected up to SALM Production Buoy Preparing for Winter Lay Down Operations (Courtesy of DC Marine)

Figure 3-31: SALM Buoy Ice Up After Storm Event (Courtesy of DC Marine)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 69 of 339 Rev. 0 Figure 3-32: FSO “Okha” Connected up to Production SALM Buoy, Late Season (Courtesy of DC Marine)

3.3.2.5 Offshore Greenland

Recent petroleum explorati on licenses awarded offshore Gr eenland lie in two general areas, West of Disko Bay, and roughly West of Nuuk, the capital of Greenland.
Licenses West of Nuuk, Atammik and Lady Franklin (shown in Figure 3-33 below), are owned by EnCana and its partner Nunaoil A/S. The Atammik license is located approximately 125 miles (200 km) from shore and its water depths range from 660 to 3300 ft (200 to 1000 m) (Geological Survey of D enmark and Greenland, 2002). The Lady Franklin license lies approxim ately 156 miles (250 km) from shore and has water depths ranging from 2500 to 5700 ft (7 50 to 1750 m) (BMP, 2006).
As shown in Figure 3-34, in 2005 EnC ana presented a potential development scenario which involved the use of an FPSO and integrated subsea produc tion system (Cooper, 2005). The potential scenario was based on a locati on in the Eastern Davis Strait in a water depth of approximately 3800 ft (1150 m). The FPSO was an ice strengthened 250,000 DWT tanker with a production capa city of 165,000 bbls/d (Cooper, 2005).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 70 of 339 Rev. 0 Figure 3-33: Atammik and Lady Franklin Ex ploration Licenses (Cooper, 2005)

Figure 3-34: Potential Development Scenar io Offshore West Greenland (Cooper, 2005)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 71 of 339 Rev. 0 Ice conditions in Eastern Davis Strait are fairly benign; typi cally only first-year ice is encountered and south of 65 to 67°N the seas are predominated by ice-free areas year round (Mosbech et al., 2007).

The aforementioned conditions are much less se vere then those experienced further North in the West Disko Bay area. This area is typi cally covered by sea ice during the winter and early spring and icebergs are much more frequent ly encountered and in larger sizes then would be typically experienced south of 65 to 67°N; in Disko Bay there are always hundreds of icebergs present (Mosbech et al., 2007).
In 2003, a feasibility study carried out to asse ss field development concepts for the West Disko Bay area concluded that t he most feasible solution woul d be to utilize a subsea to beach development scheme (Mosbech et al., 2007; BMP, 2006). FPSO development schemes were considered; however, the assessment indicated that they would only be able to achieve an annual upt ime in the range of 40 to 65% (B MP, 2006). Husky Oil Operations, Esso Exploration Greenland, and Nunaoil A/S hold interest in exploration licenses for this area (Husky, 2007c).
3.3.2.6 Semi-rigid Floater Concept
The semi-rigid floater structure shown in Figure 3-35 was originally designed for Sakhalin Island. The structure combines the buoyancy pr operties of a conventional buoy with tension leg platform concepts (CKJ Engineering Ltd., 2005). The semi-rigid floater was developed primarily to provide an exploration solution for sea ice environments in water depths ranging from 260 to 1640 ft (80 to 500 m); however, depending on severity of ice conditions, it may also be consider ed for a year round production solution.
The structure consists of a circular floating hull, three cable groups and three anchors. The floating hull is circular and c onsists of a series of decks. The top deck is approximately 330 ft (100 m) in diameter with a centrally placed 49 ft (15 m) diameter moonpool. The lower deck accommodates the unit’s cable and winching systems.
A procedure has been developed fo r the installation and reloca tion of the structure using the assistance of tugs. This system involves deploying and individually positioning all the anchors. When all anchors are in position, they are balla sted and the cable groups are winched in until the unit is centrally located between th e anchors. Deballasting of the upper hull then commences until the force in each cable group is about 16,500 tons (15,000 tonnes). The structure is then r eady to begin drilling operations.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 72 of 339 Rev. 0 Preparing the structure for relocation is essentia lly the reverse of the installation process. Depending on whether or not t he unit is being moved to shallower or deeper water, the cable lengths can be adjusted as required for site-specific conditions.
The semi-rigid floater concept is designed to carry 16,500 tons (15,000 tonnes) of topsides and can operate in 16,500 tons (15,000 tonnes) of ice loading with wave heights of 49 ft (15 m) without being subject to fatigue issues. W hen disconnected, the structure has floating stability when its anchors are free of the sea floor in waves up to 26 ft (8 m). Stability is maintained by adjusting the amount of water ballast.

Figure 3-35: Arctic Semi-rigid FloaterIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 73 of 339 Rev. 0 3.3.2.7 Monocone Arctic Platform (MCAD)
The Monocone Arctic Platform (MCAD) wa s presented at the 2007 Offshore Mechanics and Arctic Engineering Conf erence as a solution to production and drilling in Arctic sea ice environments with water depths of up to 410 ft (125 m) (Paganie, 2007).
The MCAD is a cone-shaped floating hull cons isting of an upper and lower section. The upper section provides the st ructure’s buoyancy and ice breaking features. The lower section consists of a heavy stee l ballast that can be lowered to adjust the unit’s vertical center of gravity. The unit ma intains its position by the use of a steel mooring system. The mooring system consists of 32 chains connected to 16 driven anchor pile s. The 16 piles are expected to be 9.8 to 13.1 ft (3 to 4 m) in di ameter with an embedment of 151 to 180 ft (46 to 55 m) (Paganie, 2007).

Figure 3-36: MCAD Platform (Paganie, 2007)
The installation and relocation of the unit requi res the assistance of tugs and pile driving services. Anchor piles are driven at the planned drilling location prior to the unit’s arrival. Upon arrival, the unit’s mooring system is c onnected to the anchor piles and the ballast section is lowered. The structure is now r eady to begin drilling oper ations. Preparing the structure for relocation is the reverse of t he installation process. The MCAD’s mooring system is only partially mobile, so each installa tion and relocation of th e unit requires the installation of new anchor piles.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 74 of 339 Rev. 0 The MCAD is designed to operate under ice l oads of 13,200 tons (12,000 tonnes) in wave heights of 46 ft (14 m). The MCAD has capacit y to carry 26,500 tons (24,000 tonnes) of topsides. The estimated construction cost of the MCAD is $500 to $600 Million USD (Paganie, 2007).

3.3.2.8 Conventional Floatin g Exploration Structures
Conventional floating exploratio n structures, drillships and se mi-submersibles, have been used in areas subject to seasonal/marginal ic e cover including the east coast of Canada, offshore Greenland, the Russian Arctic, and o ffshore Sakhalin Island. Drilling with these structures is generally carried out during summe r months when seas are ice free. However, there are drilling units which are ice strengthened/classed fo r operation in light/managed ice cover. Furthermore, there ar e other drilling units, such as the Vidar Viking, which have shown that drilling in ice well beyond light/managed ice is possible.
The purpose of this section is to highlight some notable technology and drilling units employed in analogue areas.
Vidar Viking
The Vidar Viking is an ice br eaking (Class DNV IBICE10, 4.3 ft (1.3 m) ice) anchor handling, tug and supply vessel complete with a full dynamic positioning system.
The vessel was outfitted with a moon pool and a co mpact drill rig for deep sea drilling in summer of 2004. This upgrade was performed to al low the Vidar Viking to serve as the drilling vessel for the Arctic Coring Expe dition (ACEX) project (ALIAS, 2007). In the summer of 2004 as part of the ACEX, the Vi dar Viking successfully gathered cores from under the central polar ice pack. Ocean floor co re sampling was carried down to the full target depth, to bedrock on t he Lomonosov ridge, at 1440 ft (438 meters) of core length (Keionen et al., 2007). Prior to this date no co re drilling had taken place under the central polar ice pack.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 75 of 339 Rev. 0 Figure 3-37: “Vidar Viking” Equipped with Co mpact Drill Rig, in the Central Polar Pack (Keionen et al., 2007)

This drilling program was possible as a re sult of the many lessons learned in ice management, ice intelligence and evaluations, forecasting drift, risk assessments and icebreaker operations by the Sovetskiy Soyu z and Oden to defend the stationary Vidar Viking vessel in moving pack ice. This progr am allowed the vessel to remain on station for days at a time in difficult ice and weather conditions.

The station keeping operation ha d an allowable movement duri ng operation of about 5% of water depth. The Vidar Viking was able to keep station at the c entral polar pack in approximately 10 tenths of 8.2 to 8.9 ft (2.5 to 2.7 m) thick mult i-year ice drifting at about 0.19 knots (Keionen et al., 2007).

This accomplishment has proven that it is possible to keep a vessel in the central polar pack stationary for a significant length of time. It is likely that station keeping in thick ice can be reached beyond what has been achieved by the Vidar Vi king with the app lication of the latest azimuth propulsion icebreaker technology.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 76 of 339 Rev. 0 Eirik Raude
The Eirik Raude (Figure 3-38) is a 5 th generation harsh environment, dynamically positioned semi-submersible. Th e Eirik Raude is 390 feet long by 280 feet wide (119 m long by 85 m wide). It can handle a variable deck load of 7129 tons (6467 tonnes) in operation and 4867 tons (4415 tonnes) in transit. The platform weighs 52,552 tons (47,675 tonnes), has a lifting capacity of 1002 tons ( 909 tonnes), and can handle up to 32,800 feet (10,000 m) of drill pipe (O cean Rig ASA, 2007).

Figure 3-38: Eirik Raude (Ocean Rig ASA, 2007)
The rig is operational in wate r depths of 230 to 10,000 ft (70 to 3050 m). In depths of 230 to 1600 ft (70 to 488 m), position is maintained by use of the mooring system. Beyond this depth, position is maintained by the class 3 dynamic positioning system (DP3) and the unit’s six computer controll ed thrusters (Ocean Rig ASA, 2007). This DP3 system is capable of holding the rig on position in vi olent storms. In the fall of 2003, the rig maintained position over a well off the east coast of Newfoundland in 120-knot (62 m/s) winds and 79 foot (24 m) wave s (Goa, 2003). Furthermore, Goa (2003) indicated that the Eirik Raude encountered ice while drilling on location off the east coast of Canada.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 77 of 339 Rev. 0 Quick disconnect features allow the Eirik R aude to disconnect from, and secure, a well in 35 seconds. The quick disconnect feature makes it possible fo r the rig to operate in areas prone to icebergs (Goa, 2003).
3.3.2.9 Henry Goodrich
The Henry Goodrich (Figure 3- 39) is a harsh environment 4 th generation semi-submersible, and has been used year round on the Grand Banks. The Goodrich has carried out the majority of development drilli ng for the Terra Nova field.

Figure 3-39: Henry Goodr ich (Toolpusher, 2007)
The Henry Goodrich is ice-classed and c an withstand significant storm conditions (TransOcean, 2007):

• Operating Conditions: Maximum wave 45 ft (14 m), significant wave 25 ft (8 m), period 13 seconds, wind 50 knots (26 m/s), current 2 knots (1 m/s); and

• Storm Conditions: Maximum wave 105 ft (3 2 m), significant wave 56 ft (17 m), period 15 seconds, wind 60 knots (31 m/ s), current 2.5 knots (1.3 m/s).
The Henry Goodrich’s classification (by DNV) is +1A1 Column Stabilized Drilling Unit, HELDK, POSMOOR TA , DRILL N, ICE TL.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 78 of 339 Rev. 0 3.3.3 Subsea Solutions Advancement in subsea technologies are allo wing for faster production, longer tiebacks, deeper water solutions, and tiebacks to land without the use of offshore structures. Notable developments in non-arctic environments include Ormen Lange and Snøhvit. The Ormen Lange tieback to shore is 75 miles (120 km) long and originates at 3300 ft (1005 m) water depth. The Snøhvit project, which has rec ently come online, ha s subsea equipment in approximately 820 to 1150 ft (250 to 350 m) water depth located approximately 93 miles (150 km) offshore.
Subsea solutions (no structure) have been used and/or consider ed in arctic and sub-arctic type areas as described below.

3.3.3.1 Canadian East Coast
On the Grand Banks, the biggest c oncern with respect to subsea infrastructure is icebergs. Free floating and (seabed) gouging icebergs may pose a risk to subsea structures that extend above the seabed. If the structure is placed below t he mudline, the hazards posed by free floating icebergs are eliminated. If t he structure is located a sufficient distance below the mudline, the risks due to gouging ice keels are minimized.

Protection of subsea structures from gouging icebergs on the Grand Banks is achieved by placing the equipment in excavated pits known as glory holes. Alternative strategies have been looked at during previous pr oject design; however, open glory holes were identified as the optimum solution for east coast Canada pr ojects requiring protection. Similar issues would exist for subsea infrastructure that would be placed in wate r depths approximately less than approximately 1000 ft (300 m) on the Labrador Shelf.

There are only two known projects in the world which use glor y holes to protect wellheads and associated equipment from pot ential ice impacts. Petro C anada’s Terra Nova field and Husky’s White Rose field located on the Grand Banks of Newfoun dland (see Section 3.3.2.1). The Terra Nova development utilizes 5 glory holes in water depths ranging from approximately 312 to 330 ft (95 to 100 m) water depth while the White Rose development requires only 3 glory holes in water depths rangi ng from approximately 3 95 to 410 ft (120 to 125 m).

As an indicator of the dimensions associ ated with these east coast developments, Table 3-6 provides a summary of the overall glory hole dimensions.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 79 of 339 Rev. 0 Table 3-6: Grand Banks Canada Glory Hole Dimensions (Technip, 2001)

Field Glory Hole Base Dimensions, ft (m) Depth, ft (m) Side Slopes Ramp Slope Southeast 82 x 82 (25 × 25) Northwest 82 x 82 (25 × 25) Northeast 147.6 x 82 (45 × 25) Southwest 213.3 x 82 (65 × 25) 32.8 (10) Terra Nova

Far East 141.7 x 76.1 (43.2 × 23.2) 33.8 (10.3) 1:3

White Rose Southern 190.3 x 145.7 (58 × 44.4) 29.5 (9) 1:1.8 1:5

3.3.3.2 PanArctic Drake
The world’s first arctic subsea flowline began tr ansporting gas in April 1978, from a subsea wellhead to production facilities onshore (Palmer et al., 1979). A Canadian company, PanArctic Oil Ltd., sponsored th e Drake Field subsea completi on which was located in the Canadian High Arctic off of Mellv ille Island (Figure 3-40). The three-year program to design, fabricate and construct the flo wline was part of a test program to evaluate the performance of the field development concept and demonstrate the feasibility of such an offshore arctic development.

The well location was chosen such that the top of the wellhead was deep enough to avoid contact by ice keels (predominantly less than 150 feet (46 m) deep). Another requirement was that the flowline bundle lengt h be minimized (4000 ft or 1220 m).

The water depth at the well location was 181 feet (55 m) and the well was drilled from the floating ice using an onshore rig modified for o ffshore drilling (Watts and Masterson, 1979). The Christmas tree assembly which was inst alled was equipped wit h diverless remote hydraulic flowline connectors which were used to tie-in the flowlines. Diverless pipeline bundle connections were made by using the def lect-to-connect method (Palmer et al., 1979).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 80 of 339 Rev. 0 

### Melville Island Drake Project Location

Figure 3-40: Drake Pr oject Location Map

3.3.3.3 Russian Arctic

Subsea solutions have been consi dered in the Russian Arctic, including Shtokman. In the subsea development case, subsea separation an d compression technology will be used. If the subsea method is chosen, technology a pplied during development of the Ormen Lange field in Norway will be tak en as a prototype (SPG Media Limited, 2007a). The gas will be transported from the well th rough a pipeline and liquefied onshor e. The specialists of JSC GiproSpetsGaz (Gazprom affiliate) and VNIIGAZ, together with Norwegian companies are investigating the feasib ility of this concept.

3.3.4 Pipelines
3.3.4.1 PanArctic Drake

Overview

The Drake Field subsea well test experience is inst ructive, since it show s the effort required for pipeline bundle construction in the arctic. T he implication is that the schedule lengthens considerably over that which would be an ticipated from a more conventional pipelineIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 81 of 339 Rev. 0 configuration. The gas was produced to a test flare for several m onths and then shut-in and, years later, the well and flowline bundle were abandoned.

Pipelines

The flowline bundle is illustrat ed in Figure 3-41. The flowline bundle contained two 6-inch (152 mm) flowlines with heat trac ing. One flowline was insulated with a layer of expanded polyurethane foam. In addition to the flowli nes, the bundle contained one 2-inch (50 mm) annulus access line and f our 1-inch (25 mm) lines for methanol injection, two for hydraulic control and one spare. There were also electrical cables for strain gauging and pressure and temperature measurements. The pipes and cables were made into a bundle and enclosed in the carrier pipe, where they were held in place by aluminum spacers. In addition to a methanol injection line for hydrate control, each of the two pipelines was heat traced using different methods. An 18-inch (457 mm) carrier pi pe was used to contain the bundle of seven pipelines and various cables.

Figure 3-41: Drake Flowline B undle (Palmer et al., 1979)
Project Design Challenges & Highlights
Ice gouging was a major concern for the flo wline bundle. The deepest ice island keel depth expected for the area was 148 ft (45 m). The depth at which t he wellhead was to be located was based on this maximum expected keel depth. A relatively steep shore crossing was located which would minimize the length ov er which the flowli ne would need to be protected from sea ice. The sea ice at the site was found to be a mixt ure of first-year andIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 82 of 339 Rev. 0 multi-year ice with average and maximum thi cknesses of 9.8 ft (3 m) and 57 ft (17.4 m), respectively.
A 13 ft (4 m) deep trench backfilled with rock was in itially planned to pr otect the pipeline. However, due to the weak characteristics of the seabed soils, it was determined that digging a trench with steep side slopes was not possible and it would collapse under its own weight.
An evaluation of alternative protection tec hniques was therefore carried out. The solution which was selected was to protect the pipel ine with frozen soil. The pipeline would be placed in a 5 ft (1.5 m) deep trench, backfilled wi th gravel, and the soil frozen around the carrier pipe, thus creating a protective cyl inder around the flowline system. The frozen soil would have a significantly gr eater strength than the surroundi ng soil and also increase the lateral resistance of the pipeline to movement.
The 18-inch (457 mm) casing pipe was itself put inside a 24-inch ( 610 mm) casing pipe. A methanol-water mixture at - 22°F (-30°C) was circulated offshore through the annulus between the 18 and 24-inch (4 57 and 610 mm) lines and returned via a small diameter return flowline in the annulus. The system was designed to grow the frozen soil bulb to a minimum diameter of 9.8 ft (3 m) after being in operation for 40 days.
When completed and operational, the frozen so il bulb would extend from 50 ft (15 m) onshore to 919 ft (280 m) offshore at 65 ft (20 m) water depth. Additional protection was afforded the pipeline in the nearshore zone out to 16 ft (5 m) water depth through the construction of a grounded ice berm.
Pipeline Construction / Construction Planning Challeng es & Highlights
The presence of sea ice was determined to be a significant factor in the schedule. Sea ice begins to form in the area in September, can s upport light equipment by November, and can support heavy equipment from January to May. Natural ice thicknesses could reach 6.6 ft (2 m). Therefore, the decision was made to ar tificially thicken the ice where additional thickness was needed and install the pipeline from the ice.

Nearshore, the trench was excavated by a clamshell crane supplemented by blasting through permafrost. Offshore, the 5 ft (1.5 m) deep and 820 ft (250 m) long trench was made in 30 minutes using a specially des igned large trenching plow. The plow wasIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 83 of 339 Rev. 0 specifically designed for t he soft soils encountered and was also designed to be disassembled and air freighted to the site (Brown and Palmer, 1985).

Fabrication occurred on Melville Island during the wi nter of 1977 – 78. A “stove pipe” technique was employed for pipe string and bund le make-up under a temporary shelter. This necessitated a significant staging area for pipe handling. The outer jacket pipe was pulled over the inner bundle of pipes, tubing and power cabl es. Even though the pipeline was only 4000 feet (1220 m) long , the pipe bundle make-up lasted four and a half months, not including pipeline installation.

In the nearshore area, a plow la unch hole was cut in the ice. A 1 ft (0.3 m) wide slot was cut through the ice from shore to the ice isl and drilling platform using an ice saw mounted on a crawler tractor. A cable connected to a winch offshore was dropped through the slot and connected to the plow. The plow was then dropped through the launch hole and pulled offshore.
The flowline bundle was to be pu lled into place using the same ice-based winch. When the bundle was complete and on the onshore launchway , the subsea completion manifold was welded to the leading edge of the bundle. Once the plow created the trench and was retrieved, the cable was re-lai d through the slot in the ice a nd the pipe pulled from shore into the trench. The pipeline was then tied into the wellhead using a diverless connection method; the deflect-to-connect method (Palmer et al., 1979). The leading sections of the flowline bundle were made positively buoyant by using floatation devices and a number of additional winches used to cont rol the flowline bundle position du ring the tie-in procedure.
Logistically, PanArctic had a permanent site on Mellville Island (Rea Point) that could be reached by ship during open water season. The site was approximately 31 miles (50 km) southeast of the Drake shore crossing loca tion. A portable camp and runway were established for the Drake work and equipment/s upplies were airlifted in from Rea Point.
3.3.4.2 Polar Gas Project

Overview

Polar Gas was a consortium of American and Canadian companies formed in 1972 who investigated the possibility of bringing natura l gas southward by pipeline from the Canadian Arctic Islands (Houlding, 1976) . Considerable design work and a research program wasIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 84 of 339 Rev. 0 undertaken to look at the feasibility of laying pipelines in extreme low temperatures and through the ice in the Canad ian Arctic (Figure 3-42).

Pipelines
The overall pipeline system was envisioned to consist of 3100 miles (4990 km) of 48-inch (1220 mm) pipeline down the west side of Hudson Bay. Offs hore pipelines were planned to be dual 36-inch (914 mm) lines. The pipelines bri nging gas from the is lands were planned as a phased approach. The first pipelines being considered were thos e running south from Melville Island. Subsequently, pipelines woul d be built to the islands further north.
Project Design Challenges & Highlights
Major problems associated with pipelines for the project were identified. This included the duration of the open water season as channels co uld remain ice covered for as much as 50 weeks/year and this could limit the use of laybarges. In addition, little was known about bathymetry, currents, and bottom conditions, and, given the ice conditions, the pipeline would need to be protected from the ice.

The conclusion with regards to ice gouging wa s that ice masses large enough to cause serious problems to the pipeli ne would not be experienced alon g the pipeline route due to the protection afforded by the surrounding islands and the preva iling currents. The maximum water depth for gouging from ice islands or large pieces of ice was considered to be less than 148 ft (45 m).
Pipeline Construction / Construction Planning Challeng es & Highlights

The main challenge with regards to the pipelines was to insta ll pipelines across deepwater channels between the Arctic islands. Logistics were also identified as a significant issue; 15 staging areas would be required to move almo st 5.5 million tons (5 million tonnes) of equipment, material s, and supplies.
A number of channel crossing methods were look ed at for the Polar Gas project, including:

• Lowering the pipeline from the surface of the ice or by conventional laybarge;

• Pulling the pipe from shore-to-shore, from the ice surface or from a vessel; and,IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 85 of 339 Rev. 0 • Tunneling.
All were considered feasible. The primary solu tion was to use the ice as a working platform for installation and logistics.
A 100-day construction period would take place between Febr uary and May when daylight hours were available and the ice wa s thick (up to 6 feet (1.8 m)) and stable. At that time, the ice island bottom pull concep t (Figure 3-43) was consider ed the most promising and cost effective solution where the availab ility of an open water season could not be guaranteed. The plan was to build up artificial ice platforms in the channel, mount large winches, and conduct a number of shore-to-shore (or ice platfo rm to ice platform) pulls. An ice strengthened pull ship or pull barge was considered for use in areas where an open water season could be expected. One or mo re mid-line tie-ins could be expected during construction and would be carried out by lifting the pipeline to the surface (ice or water) and welding the pipeline segments to gether, or by carrying out hyperbaric welded tie-ins.
A second route was later investigated (Figure 3- 42) as the result of technological advances at the time, that took the pi pelines south across M’Clure Stra it, over Victoria Island, and across Dolphin and Union Strait. Surveys done in these Straits in 1979 indicated these crossings to be technically feasible (Kaustinen, 1981).
The crossing location of M'Clure Strait was 75 miles (120 km) wid e, extending to a depth of 1640 ft (500 m). The ice could vary from 6.6 to 40 ft (2 to 12 m) in thickness with an average natural ice thickness of approximately 9.8 ft (3 m). However, the ice did contain ridges and the ice hole method (Figure 3-44) was therefore proposed for this crossing as this technique was less dependent on having long flat ice surfac es along the pipeline right of way. Tie-ins between pipelin e strings would be made at the ice surface or using a 1-atmosphere welding technique to weld the pipelines on the seabottom.
The crossing location of the Do lphin and Union Strait was 19 miles (30 km) wide and 361 ft (110 m) deep. A laybarge or pu llbarge method of installing t he pipe was considered to be preferable as the channel was determined to be ice-free in August and September of each year. In shallow water (less than 79 ft (24 m)) at the shore crossings of Dolphin and Union Strait, the pipelines were to be installed in tunnels to protect the pipe line from ice gouging (Figure 3-45). At M’Clure Strait, the pipelines would be installed in a tunnel to a water depth of 180 ft (55 m).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 86 of 339 Rev. 0 Figure 3-42: Polar Gas Channel Crossi ngs (modified from Kaustinen, 1981)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 87 of 339 Rev. 0 Figure 3-43: Ice Island Bottom Pull Method (from Kaustinen, 1981)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 88 of 339 Rev. 0 Figure 3-44: Ice Hole Bottom Pull Method (from Kaustinen, 1981)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 89 of 339 Rev. 0 Figure 3-45: Polar Gas Foreshore T unnel Concept (from Kaustinen, 1981)
3.3.4.3 Baydaratskaya Bay (Russia)
Gas transportation schemes from the Yamal Pe ninsula include pipelines crossing the Baydaratskaya Bay of the Kara Sea over a di stance of approximately 37 to 44 miles (60 to 70 km). Maximum water depths across potential pipeline routes are less than 82 ft (25 m) and, therefore, ice gougi ng is a concern. Ice is present from approximately November to July.
Studies of ice gouging in the Baydaratskaya Bay began in the 1980’s. Extreme ice gouge depths of 5 to 6.6 ft (1.5 to 2 m) have been measured. Maximum widths up to 165 ft (50 m) have been measured while widths averaged 33 ft (10 m). Such gouges have been observed to have happened over 100’s of feet in length (Marchenko et al., 2007). Most of the gouges measured have been located in water depths less than 50 ft (15 m).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 90 of 339 Rev. 0 The presence of ice gouging of the seabed will require pipe line to be buried to resist subgouge deformations induced in the seabed by the ice keels. Early work had indicated that 6.6 to 9.8 ft (2 to 3 m) of pipeline cover might be requi red to protect the pipeline.

3.3.4.4 Nord Stream Pipeline (Russia)
The planned Nord Stream pipe line (Figure 3-46) will consist of two 48-inch (1220 mm) lines running 750 miles (1200 km) from Vyborg, Russia, to Germany’s northeast coast (PennWell Corporation, 2007). This line, when constructed, wil l be the first pipeline installed in the Baltic Sea. The maximum water depth along the pipeline rout e will be 690 ft (210 m) and the pipeline will have wall thi cknesses ranging from 1.2 to 1.8 inches (30 to 45 mm). Trenching of the pipeli nes will occur in the nearshore areas where there is excessive wave and current action. The pipeline will also be trenched where ther e is a risk of ice gouging, ship grounding, etc. At a minimum, it is ex pected that the pipeline s shall be trenched and backfilled at the landfall points, and at shallow water at Vyborg, Russia, and at Greifswald, Germany. If the trenches requir ed backfilling, the project will reuse native materials as much as possible (PennWell Corporation, 2007).

Figure 3-46: Proposed Pipeline Location (Nord Stream, 2007)
There will be a service platform approximately 56 miles (90 km) to the northeast of Gotland Island. The platform will be 98 x 98 ft (30 x 30 m) square and it will rise approximately 115 ft (35 m) above the water. The platform will be used for maintenance and service of the pipelines, including launch and reception of testing and diagnostic equipment, control of gas parameters, and placement of valves (Nord Stream, 2007)
The following information has been r eproduced from Nord Stream (2006).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 91 of 339 Rev. 0 “The ice conditions in the Baltic Sea show a high degree of va riance in time and space and are strongly related to the severity of the win ters. During the 1980s the ice coverage varied between 13 and 98 %. The Baltic Sea is ice covered for 0 to 3 months per year. In the northern regions the ice cover usua lly lasts for 5 to 6 months.”
“The Bothnian Bay, the eastern part of the Gulf of Finland and some Archipelago areas are frozen over every winter. The 50% probability contour crosses the open sea in the northern Baltic proper. In t he open area in the Cent ral part of the souther n Baltic proper, the probability of ice occurrenc e is less than 10%. The ice cover is more frequent in the coastal area. Along the coast, the 90% probability zone is covering the Finnish coast, including the Archipelago Sea and the Swedish coast (Gävle , Stockholm, Nyköbing) as far South as Västervik. The 75% probability zone covers areas as far south as Karlskrona on the Swedish Coast and the areas around Rügen (south coast of Meck-lenburger Bucht, Greifswalder Bodden, Pommerche Bucht) on the German Coast. In the areas at the entrance to the Baltic Sea (Ystad) the probability is less than 50%.”

The average ice extent during m ild, normal and severe winters, respectively, is shown in Figure 3-47.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 92 of 339 Rev. 0 Figure 3-47: The Average Ice Extent duri ng Mild, Normal, and Severe Winters, Respectively (Nord Stream, 2006)

3.3.4.5 Canadian East Coast Flowlines

Terra Nova

The Terra Nova development utilizes approximatel y 20 miles (33 km) of flexible flowlines and dynamic risers to convey produced hydrocar bons from the subsea wells to the riserIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 93 of 339 Rev. 0 base manifold and then to the FPSO (Petro -Canada, 2007b; Cottrill, 2000). The total installed subsea flowline length is 16 miles (26 km), with design temperatures ranging from 131 to 212°F (55 to 100°C) and design pressures ranging from 4. 2 to 6.6 ksi (29 to 45.2 MPa) (Tveit et al., 2000). The flowline internal diam eters range from 5 to 10 inches and are located in approximately 310 ft (95 m) water depth. The flexible flowlines enter the FPSO via a quick disconnect spider buoy which serves as the mooring point for the FPSO and the route for all produced fluids flowing between the FPSO and the reservoir (see Terra Nova of Section 3.3.2.1). The Terra Nova spider buoy is one of t he largest quick disconnect turret moorings ever built (Petro-Canada, 2007b).
Technip Canada Ltd. (formerly Technip CS O Canada Ltd., formerly Coflexip Stena Offshore Newfoundland Ltd.) supplie d and installed all flexible fl owlines, risers, umbilicals, and jumpers for the Terra Nova development proj ect (Technip, 2007). The flexible flowlines and risers were manufactured by Coflexip St ena Offshore Newfoundland Ltd. (CSO) in Le Trait, France (Alexander’s Gas & Oil Connections, 2007a).
Terra Nova flowlines were originally planned to be trenched 5 ft (1.5 m) below the seabed using CSO’s TM9 trenching mach ine, but difficulties in trenc hing the hard glacial seabed led to the use of rock dumping on some of t he flowlines (Cottrill, 2000; Lever et al., 2001). Tideway’s Seahorse and Van Oord ACZ’s Trollness dynamically positioned fall-pipe vessels were thus used to dump some 155,000 tons (140,000 tonnes) of rock and sand for stabilization, protection agai nst gouging icebergs, thermal insulation to reduce wax deposition, and rectification works (Tideway , 2007; Cottrill, 2000). Figure 3-48 provides a schematic of the trenched and/ or rock-dumped flowlines.

In addition to these subsea prot ection measures, flowlines used on the Terra Nova project are considered sacrificial and c ontain weak-link connections to wellhead equipment (for protection of the wellhead if the flowline is im pacted by a gouging ice keel) (Cottrill, 2000).
The flowline design maintains pr oduction fluid temperatures well outside of the hydrate formation region during normal operations, wit h predicted cool down times (to below hydrate formation temperatur es) ranging from 5 to 6 hours during shutdown, depending on shut-in pressures and production flui d composition (Stephens et al., 2000).

Refer to Terra Nova of Section 3.3.2.1 of this report for further discussion of the Terra Nova development.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 94 of 339 Rev. 0 Figure 3-48: Terra Nova Flowline Pr otection (Courtesy of Tideway, 2007)

White Rose

Similar to the Terra Nova development, the White Rose project FPSO (the SeaRose) utilizes a disconnectable turret moori ng system, as discussed in White Rose of Section 3.3.2.1 of this report. Technip Canada Ltd. supplied and installed 26 miles (42 km) of risers, flowlines, and umbilicals for the project (Tec hnip, 2007). As with Terra Nova, the flexible flowlines were manufactured in Le Trait, Fr ance (Alexander’s Gas & Oil Connections, 2007b). Subsea construction was completed by CSO’s Constructor and Marianos vessels.

Flexible flowlines enter t he FPSO via a riser buoy and qu ick disconnect geo-stationary turret which serves as the mooring point for the FPSO and the route for all produced fluids flowing between the F PSO and the reservoir (see White Rose of Section 3.3.2.1). The installed water depth ranges from 377 to 427 ft (115 to 130 m).
As with Terra Nova, flowline weak links are utilized at wellhead connections for protection of the wellhead if the flowli ne is impacted by a gouging ice keel (Husky, 2001a). The flowlines are designed to be fail-safe to mi nimize harmful environmental consequences should a flowline fail or become damaged (H usky, 2001b). Flowlines may be flushed and purged of all internal production fluids to mitigate environmental risk associated with potential ice keel im pact (Husky, 2001b).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 95 of 339 Rev. 0 3.3.4.6 Sakhalin Island
Sakhalin 1 Pipelines
Two pipelines connect the Orlan platform locat ed in approximately 82 ft (25 m) water depth to shore approximately 6 miles (10 km) away. Fr om there, the lines carry on to the Chayvo Onshore Processing Facility. These pipelines are a 36-inch (914 mm) full wellstream line and a 24-inch (610 mm) gas re-injection line. Both pipelines are buried to a depth sufficient to protect them from ice gouge and long term effe cts of sediment trans port (loss of cover).
Connecting Sakhalin Island to mainland Russia is a 24-inch (610 mm) export line. This line must go through the Tatar Strait which is covered with first-year ice in winter. Water depths range from 16 to 72 ft (5 to 22 m) through the channel and 0 to 16 ft (0 to 5 m) across the flats on either side. Given t he presence of ice and ridging, and the fact that sediment transport is actively ongoing, t he pipelines are buried for protec tion from ice keels (Baranov et al., 2007).

At the DeKastri Export Terminal, a 48-inch (1220 mm) loading line is used to transport crude offshore to the single point mooring system from which t ankers are loaded. This line is buried and backfilled out to 50 ft (15 m) wate r depth for protection against first-year pressure ridge keels.
Sakhalin 2 Pipelines

The development of the Piltun-Astokhskoye and Lunskoye fields of the Sakhalin 2 project incorporates the use of five offshore pipe line systems that have been installed over two phases of the project.

Phase I of the offshore pipeline development in volved the installation of a 12 inch (305 mm) diameter, 1.25 mile (2 km) l ong pipeline from the PA-A platform to a single anchor leg mooring buoy (SALM) (SEIC, 2004). This pipeline allowed seasonal production from the PA-A platform for approximately 6 months of the year.

Phase II of the offshore pipeline development connects the three offshore platforms (PA-A, PA-B and Lun-A) to onshore pipeli nes. Phase II also connects the export terminal to the tanker loading unit in Aniva Bay. Details of the Phase II pipelines are as follows:IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 96 of 339 Rev. 0 • Two 14 inch (357 mm) pipelines from PA-A platform to landfall at Chayvo Bay. This line will allow year-round production from the PA-A platform.

• Two 14 inch (357 mm) pipelines from t he PA-B platform to landfall at Chayvo Bay.

• Two 4.5 inch (114 mm) pipelines from Lunskoye Platform (LUN-A) to land and one 30 inch (762 mm) pipeline from LUN-A to land.

• One 30 inch (762 mm) tanker loading line from the offshore ex port terminal to the tanker loading unit in Aniva Ba y (SPG Media Limited, n.d.).
The Sakhalin 2 offshore pipelines incorporate t he state-of-the-art in des ign and construction of pipelines. Offshore pipelines located in less then 100 ft (30 m) of water are installed in 6.5 ft (2 m) deep trenches and backfilled to protect against gouging. Sakhalin offshore pipelines are designed with burst strengths twice the factor normally applied by industry (SEIC, 2004). This results in approximately double the pipe wall thickness used in other jurisdictions. The offshore pipelines are cons tructed from API 5L X52 grade steel which remains ductile at low temper atures (SEIC, 2004). Cofferdams are installed at land fall to provide protection from sea ic e at the transition between offshore and onshore pipelines.

The Phase I offshore pipeline has been in s easonal operation since approximately early 2000 (approximately). Installation of over 187 miles (300 km) of offshore pipelines in water depths up to 164 feet (50 m) was completed in early 2006 (Sakhalin Energy, 2007).

3.3.5 Export Terminals
3.3.5.1 Canadian Arctic
Cameron Island is the only site in the Can adian Arctic Islands wh ich had been developed for commercial oil production (1985-1996). Light crude was shipped from Bent Horn in the southwest of the island to Montreal via the M.V. Arctic, a double-hu lled tanker. The field was abandoned in 1996 after producing a total of 2.8 million barrels of oil. The abandonment reflected the difficulties of exploi ting the resource in harsh environments. After abandonment, final clean-up occurred in 1999.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 97 of 339 Rev. 0 3.3.5.2 Russia
Export terminals in Russia, although perhaps to a lesser degree, have harsh natural conditions analogue to areas of interest for this study. Three major geo-political and economic factors are behind t he current development in the Southeast Barents and the Northeast Gulf of Finland (Baltic):

• Oil and gas development in the Southeast Barents area;

• Loss by Russia of year-round open water port s in the Baltic as a result of the disintegration of the Soviet Union; and,

• The need to create the infrastructure fo r the growing flow of Russian oil and gas to Western markets.
The single factor which affects all transportati on ideas proposed for the Barents is that the western sector of the sea (K olsky peninsula, Figure 3-1) is free from ice year-round. Consequently, the northern part of Kolsky peninsula, including t he major commercial port of Murmansk and nearby areas, are considered convenient transsh ipment locations for oil from the Timan-Pechora bas in and Prirazlomnoye fields (Varandey terminal in the southeast Barents is the loadin g point of these operations). The Kolsky peninsula is also considered to be the most pr obable loading point for the LNG produced from the Shtokman field reserves. An example of one of the Bar ents Sea oil and gas transportation concepts is presented in Figure 3-49.

A brief review of available information show s that marine transportation of hydrocarbon products is one of the main areas of developm ent in the Russian Arct ic. Major research & development and technology projects have been conducted at all levels; from global transportation concepts to the design of serv ice fleet vessels that will be required for execution of specific tasks under the conditions of arctic oil and gas exploration. Several examples of these projects are briefly described below.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 98 of 339 Rev. 0 Figure 3-49: Technical and Economi c Evaluation of Alternatives for Oil Transportation from Timano-Pechora Province, Krylov Institut e Development (Krylo v Institute, n.d.) MurmanskIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 99 of 339 Rev. 0 Southeast Barents
One of the most active projects in the Russian Arctic at this time is the development of the oil transportation link originati ng at the small island of Var andey, located in the southeast corner of the Barents Sea, al most directly south of Novaya Zemlya archipelago (Figure 3-1). The Varandey oil export terminal was devel oped to load oil recovered from the nearby Timan-Pechora fields on tanker s and deliver it either across the Barents to the non-frozen Murmansk area for transshipment, or direct ly to Western Europe and/or the USA.
An information search regarding the Varandey project indicate s that, with respect to the overall scale of plans and act ual developments along the Ru ssian coast of the Arctic Ocean, the Varandey project is only a “tip of the iceberg”. Terminals are now being considered all along the Europe an section of the coast, as we ll as in the Western Siberian section. A brief summary of the Varandey project is presented below, based on information included in the Krylov Institute projects cata logue as well as Fal ling Rain Genomics, Inc (2006), Lukoil-Kalinin gradmorneft (n.d.), Advanced Production and Loading AS (2006), Russian Maritime Register of Shipping (200 6), and Universal Solutions S.A.E. (2005).
At Latitude 68.82° north, Varandey is located r oughly at the latitude of King William Island in the Canadian Arctic and of Point Hope in Alaska (Figur e 3-1). A summary of operational conditions in general offshore ar eas of the Southeast Barents is presented in Appendix A of this report. No direct information on the ice thickne ss at the Varandey site is available, but it is reported that the land fast ice may grow down to the seabed in 5 to 6.6 ft (1.5 to 2.0 m) of water, and this may serve as so me indication of the possibl e ice thickness at the site.
In the initial stage of the terminal devel opment (1999 - 2000), offloading was done through a flexible hose (i.e. without loading structure) directly over the DWT 22,000 tons (20,000 tonnes) ice class tanker side manifolds. It wa s considered temporary (for Varandey “early oil”) and intended for summer season operations only (Krylov Institute, n. d.). These loading operations were conducted approx imately 2.5 miles (4 km) offs hore in approximately 36 ft (11 m) of water by a subsea pipeline connect ed to an onshore steel storage facility. The DWT 22,000 tons (20,000 tonnes) shuttle tankers would take the oil to Murmansk for transshipment to larger DWT tankers and subsequent export out of Russia, or directly to the port of destination.
In 2000 – 2001, the loading sys tem was upgraded for winter oper ations. In this case, the tanker to be loaded was tied to a specially equipped lar ge diesel/electric icebreaker.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 100 of 339 Rev. 0 Besides providing safer mooring for the t anker, this icebreaker also served as the operational facility for the di ving team personnel and equipmen t. The divers were required for handling the subsea manifold and lifting of t he flexible loading hose . Another icebreaker was permanently kept in the area for ic e management on an as-needed basis. Winter operations began in 2001 (Krylov In stitute, n.d.). The offloadi ng concept using a totally underwater terminal connection was consider ed for Varandey as well in 2005 (Krylov Institute, n.d.).
Later in 2002 the system was modified; an ar ctic underwater loading terminal (PLEM type) was installed on the seabed. The end of a flexible hose was equipped with a quickreleasing connection intended for operations wit h tankers having bow loading systems for cargo reception.
In 2001, Krylov, working together with Hallibur ton, performed a conceptual design of a bottom-founded terminal in Varandey for a deep wa ter (53 to 73 ft (16 to 22 m)) operation. At that time, four alternatives were considered for the termi nal (Krylov Institute, n.d.):

• Modified DWT 284,400 t ons (258,000 tonnes) Very Large Crude Carrier (VLCC). The terminal was designed to provide 691,900 barrels (110,000 m 3 ) oil storage. The 3.3 ft (1 m) double bottom space and 6.6 ft (2 m) space between the walls of the double hull we re to be filled with concrete.

• Modified Steel Drilling Caisson (SDC) platform. The conceptual sketches of the system show additional foundation sect ions (block) that would be twice as wide as the original platform, apparently to improve the stability of the platform/seabed interface. The pla tform was designed to maximum ice loading conditions of the Pechora Sea.

• TLU, Caisson Alternative. A steel caisson with a total on-site weight of 79,365 tons (72,000 tonnes) (includi ng the sand ballast). The dimensions were 167 ft (51 m) long at water level and 203 ft (62 m) maximum width at seabed with a total height of 107 ft (32.5 m).

• TLU, Tower Alternative. The system was a bottom-founded SPM (gravity structure) with a turret. The maximum di mension of tower substructure was approximately 43 ft (13 m) at water le vel (stem) and 125 ft (38 m) at the seabed (base). The height (to the deck level) was 107 ft (32.5 m).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 101 of 339 Rev. 0 The alternative shown in Figure 3-50 is apparently the closest to that actually constructed (Krylov Institute, n.d.). E ssentially, the TLU is based on the last concept described immediately above, but with some important modifications. Wi th an apparent goal to increase the ballast weight, a wider caisson-ty pe hull is being used. Twenty-four piles have been added to the design to ensur e the on-bottom stability of th e structure. The octagonalshape TLU is 115 ft (35 m) wide at the water line and has a 141 ft (43 m) base at the seabed. The total height is 184 ft (56 m) (131 ft (40 m) to the deck level). The design water depth is 71 ft (21.5 m). The substructure weig ht of the concept show n in Figure 3-50 is 14,330 tons (13,000 tonnes).

Tankers will be built to t he Russian Register ice-cla ss requirements and will be DWT 77,160 tons (70,000 tonnes) with a loaded dra ft of 46 ft (14 m). An AZIPOD propulsion system will allow for these tankers to operate in 5 ft (1.5 m) thick ice without an icebreaker support (Universal Solutions S.A.E., 2005).
The model tests (at 1:70 scale) we re conducted in Krylov in 2005 on the orders of the TLU working documentation developer (CKB “Corall”, Ukraine) (Kry lov Institute, n.d.). Both regular and irregular extreme wa ve conditions as well as maxi mum pressures that could be generated by the level and ridged ice were modeled in the tests (Krylov Institute, n.d.).
The TLU in its present conf iguration carries an acronym FOIRLT (Fixed Offshore Ice Resistant Loading Terminal). This project in general is al so called “Varandey II”. The terminal will have a loading capa city of 13.2 million tons (12. 0 million tonnes) per year. The heated oil will continuously circulate inside the “looped” underwater loading line. Loading pumps will be located onshore.

The TLU will have a turret, helipad, loading boom and accomm odations for 12 people (Lukoil-Kaliningradmorneft, n.d.). The swivel stack designed for arctic conditions is reportedly supplied by APL (Advanced Produc tion and Loading), which was their first stand-alone swivel stack deliv ery not part of a complete turret system (Advanced Production and Loading AS, 2006 ). The TLU was built at the Vy borg, Baltic and Kaliningrad shipyards and the TLU installation was sc heduled for September, 2007 (Russian Maritime Register of Shipping, 2006).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 102 of 339 Rev. 0 Figure 3-50: Varandey TLU, General Concept (Krylov Institute, n.d.)

Gulf of Finland

The loss of Estonian, Latvian and Lithuanian ports, coupled with the lack of space along the south coast of the Gulf, left only one relatively available stretch of the Russian coast in the Baltic for the direct export of oil and gas pr oducts to Europe; the Karelia Isthmus coast, specifically the northernmost par t of it, near the Finn ish border (Figure 3-51). A cluster of oil terminals have been built and more are being considered for the area, which include both crude and oil products terminals for conventional tankers over DWT 110,000 tons (100,000 tonnes) with ice-breaking escort. The two main locations are Primorsk (Transneft) and Vysotsk (Lukoil) with a planned capacity of 55. 1 million tons per year and 16.4 million tons per year (50.0 million tonnes per year and 14. 9 million tonnes per year), respectively.

The ice conditions are relatively mild compared with the Arctic; the sea is frozen up to four months each year and the av erage ice thickness is 1.6 ft (0.5 m). However, considering that no special ice-resistant or ice protecti on engineering measures are included into the terminal designs (Panin and Rode, 2003), the stru ctural designs in these cases may be ofIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 103 of 339 Rev. 0 certain interest in the current study. The w eak seabed soils require piles as the only reasonable option for pier and tr estle foundations in 49 to 59 ft (15 to 18 m) of water. Consequently, the main focus of t he structural design in this case is the ice/pile interaction. The working concept is to conservatively assume crushing of the ice on the outside piles while this load is distributed over the remaining piles.

Figure 3-51: New Oil Terminals in the Gu lf of Finland (Panin and Rode, 2003)

Prirazlomnoye
Substantial effort was dedicated to developm ent of the optimal ov erall logistics of exploration and production at Prirazlomnoye field. Accord ing to SPG Media Limited (2007a), the supply base for the platform will be in Arkhangelsk (large port at the White Sea), which indeed is probably the closest loca tion with well-developed infrastructure, butIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 104 of 339 Rev. 0 still approximately 621 miles (1,000 km) from t he field. The oil transportation concept for Prirazlomnoye described in avail able information sources varies in such details as the DWT of the ice-class tankers (from 77,000 tons (70,000 tonnes ) to 242,000 tons (220,000 tonnes)), and their propulsion syste m (AZIPOD or conventional). However, the general idea is the same; the shuttle tankers will take t he oil from Prirazlomnoye platform to the nonfrozen north-west fiords of the Kolsky peni nsula 684 miles (1,100 km) away, and from there, the commercial tankers (DWT 165,000 to 187,000 tons (150,000 to 170,000 tonnes)) will tanker it to Western Eu rope and/or America. The tran sshipment FSO “Belokamenka” with a storage capacity of 397, 000 tons (360,000 tonnes) is already operational in the Kolsky Bay (SPG Media Limited, 2007a; Madslien, 2006) . It is estimated that two 21,500 hp (16 MW) line icebreakers will be required for the shuttle route, and at least one multifunctional ice breaker will be used for ic e management at the platform, particularly during offloading operations (SPG Media Limited, 2007a).

3.3.6 Extended Reach Drilling World records with respect to extended r each drilling continue to be set in harsh environments. The push to extend the capabilitie s of extended reach drilling is driven in part by the significant reduction in offshore fac ilities if wells can be dr illed from shore or from existing structures to access reservoirs.
Within the last few years, t he Hibernia platform off the east coast of Canada successfully drilled a 31,000 ft (9450 m) measured depth (MD) o il producing well to access a reservoir 5.9 miles (9.5 km) away (Standing, 2006). In 2007, Exxon Neftegas Limited completed a well with a measured depth of 37,016 feet ( 11,282 m) or more than 7 miles (11.3 km) (Abraham, 2007). The well originated onshore Sakhalin Island and was the new world record for the longest measured- depth extended reach well. This beat the previous record established by BP at Wytch Farm which acco mplished 37,001 feet (11,278 m) and by Total at Tierra del Fuego at 36,693 feet (11,184 m) (Fischer and Schmidt, 2007).
3.3.7 Other Technological Advancements
3.3.7.1 Well Intersection Method
The Well Intersection Method, WIM, has not yet been utilized offshore or in arctic locations. However, it has been used once in an onshor e application where it was successfully employed in 2004 by Anadarko Petroleum (Smi th, 2004) in the Buckinghorse River Valley in the foothills of Northeaste rn British Columbia, Canada (Figure 3-52). In the Buckinghorse area, Anadarko encountered a de ep river valley that prevent ed the connection of a numberIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 105 of 339 Rev. 0 of gas wells on one side of the gorge to producti on facilities on the other side of the gorge. This gorge made conventiona l onshore pipeline construc tion both uneconomical and environmentally challenging. The river cr ossing design incorporated the drilling and intersecting of two conventiona l horizontal wells on both sides of the river valley. Surface well locations were approximately 1.75 miles (2 .8 km) apart. Both wells utilized a 13-3/8- inch (340 mm) surface casing followed by a 9- 5/8-inch (244 mm) casing string landed at 90 degrees (horizontal) at approxim ately 4700 ft (1433 m) TVD. An 8-3/4-inch (222 mm) hole was drilled and intersected dow nhole at TVD. Once connected, cased (using 7-inch (178 mm) casing) and cemented, both wells acted as a pipeline to transport gas across the river valley. Additional details on WIM can be found in Section 4.12.2.

Figure 3-52: Buckinghorse River Vall ey Crossing (from Smith, 2004).

3.3.7.2 Pilot Hole to Pilot Hole HDD
A relatively new development in the HDD industry has been to drill two pilot holes, from entry points at either side of the crossing, and intersect t hem underneath the crossing, rather than to drill a single pilot hole from entry to exit. One such pilot hole to pilot hole HDD project was completed in British Columbia, C anada in January, 2004. Two 9-7/8-inch (251 mm) pilot holes were intersected at approximat ely 200 ft (61 m) Total Vertical Depth (TVD) using rotating magnet ranging equipment. The cro ssing was slightly greater than 2600 feet (792 m). After the intersection, the hole was reamed and a pipe bundle (NPS 8, 6, and 2 in the bundle) pulled from the entry to exit point using standard HDD techniques (Osbak, 2004).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 106 of 339 Rev. 0 3.3.7.3 Arctic Offshore Vessels
The most advanced developments for Arctic offshore oil and gas development in Russia are associated with shipbuildin g because, traditionally, a wide scientific and technological base exists in this area. For example, the fo llowing is a list of deve lopment works presented in the Krylov Institute’ s project catalogue (Kry lov Institute, n.d.):

• Shuttle tanker, Russian ice class LU4 (3 .3 ft (1.0 m) ice), DWT 154,324 tons (140,000 tonnes) for oil product transportati on in the Northern areas and the Baltic, 2001;

• Shuttle tanker, German Lloyds ice class (3.3 ft (1.0 m) ice), DWT 71,650 tons (65,000 tonnes) for oil products transporta tion in the Northern areas and the Baltic, 2001;

• LU5 ice class port tug for service fleet operations at the Primorsk Oil Terminal (see Section 3.3.5.2), 2003;

• Icebreaker modification for services required during tanker offloading operations offshore (diving and OS R equipment units and helipad installation), 2004;

• Development of technical requirem ents for LNG carriers to be built for Shtokman field operations, 2005;

• 60-ton (54.4 tonne) lifting capacity hovercr aft for oil and gas exploration in the Yamal swampy areas (crane, fire fight ing and well services modifications), 2005;

• New generation nuclear Ar ctic icebreaker, DWT 26,50 0 tons (24,000 tonnes), 80,500 hp (60 MW), for year-round operation in 9.2 to 9.5 ft (2.8 to 2.9 m) ice, 2006;

• Mobile (Floating) Refinery Plan t, 132,000 tons/year (120,000 tonnes/year) maximum oil input capacity fo r the on-site diesel fuel generation in the remote Arctic exploration areas, 2000; and,

• Floating LNG plant for relatively small offshore reserves, where it is required to maintain the production efficiency of on-site operations, 2006.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 107 of 339 Rev. 0 Another advance in Arctic Offshore vessels is the use of Double Acting Tankers (DAT). Double acting tankers are built with “highly hydrodynamic shaped bows and sides” and thus travel forward in open water as do conventional tankers; however, in conditions requiring ice breaking, they travel aste rn to use their reinforced stern hull-form to break ice (SPG Media Limited, 2007h). Sumitomo Heavy Industries has built the first DAT, the Tempera, as shown in Figure 3-53).

Figure 3-53: “Tempera” in Icebreaki ng Mode (SPG Media Limited, 2007h)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 108 of 339 Rev. 0 3.4 Alaska OCS Exploration & Development Options

3.4.1 Bottom-Founded & Fixed Structures
3.4.1.1 General
Exploration drilling for oil and gas in the Beau fort Sea began from gravel islands in shallow Alaskan State Waters in the la te 1960’s and similarly in the Canadian Beaufor t Sea in the early 1970’s. With time, activities progressed into deeper waters. In 1976, ice reinforced drillships were first utilized in Canadian wate rs, followed in 1981 by the first use of a bottom-founded caisson system. Exploration ac tivities commenced in Beaufort OCS regions in 1982 using gravel islands, ice islands, bottom-founded stru ctures and drillships. In the authors’ view, the experience of bot tom-founded exploration stru ctures provides the best analogue to the operating conditions that will be experienced by future production structures in the Alaskan OC S. In total, five separate bottom-founded structures were deployed in the Beaufort Sea:

• Tarsiut Caisson-Retained Island or Ta rsiut Caissons (concrete caissons);

• Single-Steel Drilling Cai sson or SSDC (steel structur e) with later addition of steel MAT;

• Caisson-Retained Island or CRI (steel caissons);

• Molikpaq Mobile Arctic Caisson or MAC (steel caisson);

• Beaufort Sea I Concrete Island Drilling System or CIDS (concrete and steel structure).

These structures were conceived primarily to extend the depth ca pability of granular islands. The caisson-retained islands were formed by building an underwater berm and then backfilling the caisson systems with a core of dr edged material. Compared to conventional island-building up to that time, t he amount of fill required to achieve stability was significantly reduced. As well, the effects of wave and current erosion during the open water season were reduced. However, these structures still required significant field operations to construct the berms, deploy, backf ill, densify the core (Molikpaq requirement), decommission and move. Although touted as “mobi le” structures, the caisson structures were not truly “MODU’s” (mobile offshore drilling units).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 109 of 339 Rev. 0 The SSDC was the first MODU-type structure in the Beaufort Sea, coming into service in 1982 and with the addition of the MAT remains the only active bottom-founded exploration structure in the arctic offshore. The steel SSDC and the CIDS, a si milar concrete-steel hybrid concept which is now deployed offshore Sakhalin Island, are ballasted with water.
Table 3-7 summarizes the chronological drilling history of these five structures in the Beaufort Sea. The same data has been sort ed by structure name in Table 3-8.
In recent years, with additio nal gas discoveries in the Ma ckenzie Delta region and the revival of the Mackenzie Vall ey Pipeline, some companies have proposed constructing gas conditioning facilities support ed by barge structures. These barge structures are discussed following the review of the afor ementioned exploration structures.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 110 of 339 Rev. 0 Table 3-7: Deployments of Bottom-Founded Stru ctures in the Beaufort Sea (by year)

Year Drilling Unit Location Operator Prospect Water Depth (without berm), ft [m] Notes

1981-

82 CaissonRetained Island Canada Gulf Canada Tarsiut N-44 69 [21] On berm 1982-

83 SSDC Canada Dome/Texaco Uviluk P-66 105 [32] On berm 1983-

84 SSDC Canada Gulf Canada Kogyuk N67 92 [28] On berm 1983-

84 CRI Canada Esso Kadluk O-07 48 [14.5]

1984 Molikpaq Canada Gulf Canada Tarsiut P-45 74 [24.5] On berm 1984-

85 CRI Canada Esso Amerk O-09 85 [26] On berm 1985 CIDS USA Exxon Antares 49 [15] 1985 CIDS USA Exxon Orion 50 [15] 1985-

86 Molikpaq Canada Gulf Canada Amauligak I65 105 [32] On berm 1986 SSDC/MAT USA Tenneco Phoenix 60 [18] 1986-

97 CRI Canada Esso/Home Kaubvik I-43 59 [17.9]

1987-

88 SSDC/MAT USA Tenneco Aurora 66 [20]

1987-

88 Molikpaq Canada Gulf Canada Amauligak F-24 87 [26.5] On berm 1989-

90 Molikpaq Canada Esso/Gulf Isserk I-15 38 [11.5]
1990 SSDC/MAT USA Arco Alaska Fireweed 50 [15] 1991-

92 SSDC/MAT USA Arco Alaska Cabot 55 [17]
1997 CIDS USA Arco Alaska Warthog 35 [10.5] 2002-

03 SSDC/MAT (now SDC) USA EnCana McCovey 35 [10.5]

2005-

06 SSDC/MAT (now SDC) USA Devon Paktoa 43 [13]IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 111 of 339 Rev. 0 Table 3-8: Deployments of Bottom-Founded Stru ctures in the Beau fort Sea (by name)

Drilling Unit Year Location Operator Prospect Water Depth (without berm), ft [m] Notes

CaissonRetained Island 1981- 82 Canada Gulf Canada Tarsiut N-44 69 [21] On berm CIDS 1985 USA Exxon Antares 49 [15] CIDS 1985 USA Exxon Orion 50 [15] CIDS 1997 USA Arco Alaska Warthog 35 [10.5]
CRI 1983- 84 Canada Esso Kadluk O-07 48 [14.5]

CRI 1984- 85 Canada Esso Amerk O-09 85 [26] On berm
CRI 1986- 97 Canada Esso/Home Kaubvik I-43 59 [17.9]
Molikpaq 1984 Canada Gulf Canada Tarsiut P-45 74 [24.5] On berm Molikpaq 1985- 86 Canada Gulf Canada Amauligak I65 105 [32] On berm Molikpaq 1987- 88 Canada Gulf Canada Amauligak F-24 87 [26.5] On berm Molikpaq 1989- 90 Canada Esso/Gulf Isserk I-15 38 [11.5]

SSDC 1982- 83 Canada Dome/Texaco Uviluk P-66 105 [32] On berm
SSDC 1983- 84 Canada Gulf Canada Kogyuk N67 92 [28] On berm SSDC/MAT 1986 USA Tenneco Phoenix 60 [18]
SSDC/MAT 1987- 88 USA Tenneco Aurora 66 [20] SSDC/MAT 1990 USA Arco Alaska Fireweed 50 [15]
SSDC/MAT 1991- 92 USA Arco Alaska Cabot 55 [17]
SSDC/MAT (now SDC) 2005- 06 USA Devon Paktoa 43 [13]
SSDC/MAT (now SDC ) 2002- 03 USA EnCana McCovey 35 [10.5]IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 112 of 339 Rev. 0 3.4.1.2 Tarsiut Caissons
The industry’s first caisson-retained island wa s installed by Canadi an Marine Drilling Ltd. (C ANMAR ) at the Tarsiut location in the Canadi an Beaufort Sea. The Tarsiut Caissons comprised four concrete caissons (see Figure 3-54) set down on an underwater sand berm in 69 ft (21 m) of water, and t hen infilled and backfilled with dredged material to a freeboard of +23 ft (+7 m). The structure was used onl y for one drilling season, 1981 – 82, although the structure did serve as an ice engineering research platfo rm the following season. Based on the Tarsiut Caisson experience, C ANMAR saw the need for a fully-mobile year-round drilling platform, which led to the develop ment of the SSDC (see below). The Tarsiut Caissons were decommissione d near Herschel Island in the mid-1980’s, where they remain.

Figure 3-54: Tarsiut Concrete Caissons during Installation and in Service

3.4.1.3 SSDC & SSDC/ MAT (now SDC)

The experience with the Ta rsiut Caissons led C ANMAR to develop a fully-mobile, waterballasted concept for year-round drilling. The SSDC was fabricated by modifying the forward half of a Very Large Crude Carrier (V LCC) and the name “Sin gle-Steel Drilling Caisson” (SSDC) was adopt ed to differentiate it from the multiple concrete caissons used at Tarsiut. In 1986, the SSDC was modified to prepare it for depl oyment in the US Beaufort Sea. It was mated with a steel MAT 1 substructure to eliminate the need for foundation

1 The MAT structure carries the highest loads of any steel structure ever built.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 113 of 339 Rev. 0 preparation (subsea berms) and functioned as a single unit called the SSDC/MAT. In recent years, with a change of ownership, t he structure (including MAT) has been renamed the SDC. The structure is a MODU and all drilling and topsi des facilities are permanently affixed to the deck, resulting in simpler and fa ster mobilization for dr illing operations. Of the 19 deployments of bottom-founded structures in the US and Canadia n Beaufort Sea, 8 were those of the SDC.

Figure 3-55: SSDC (left), MAT Substructu re (Top Right), SSDC/MAT (Bottom Right)

3.4.1.4 CRI – Caisson-Retained Island

Similar to the Tarsiut Caissons, but built with steel instead of concrete, the CaissonRetained Island or CRI was conceived and built by Esso Resources Canada and first deployed in 1983. The CRI was developed to r educe the amount of dr edged material and was comprised of eight individual hinged steel ca issons placed in a ring and held together with steel wire cables. Like the Tarsiut Cai ssons, the core of t he CRI was filled with dredged material to provide the base for drilli ng operations and provide resistance to wave and ice loads. The CRI was deployed three ti mes in the Canadian Beaufort Sea from 1983 – 87. The structure has not been active since that time.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 114 of 339 Rev. 0 Figure 3-56: Esso’s Caisson-Retained Island (CRI)
3.4.1.5 Molikpaq Mobile Arctic Caisson (MAC)
The Molikpaq, developed by Gulf Canada Resources, took the Esso steel caisson-retained island concept one step further. The structure is a monolithic, water-ballasted steel annulus with a self-contained deck for dr illing and topsides facilities, but unlike the fully waterballasted SSDC and CIDS, Molikpaq relied on a densif ied sand core to provide the bulk of its resistance to environmental loads. Like t he Tarsiut Caissons and the CRI, Molikpaq is not a true MODU. The unit be gan operations in 1984 and drill ed four locations in the Canadian Beaufort Sea. It was mothballed in 1990 and later modified and redeployed in 1997 as a permanent production fac ility in the Sea of Okhotsk off Sakhalin Island, Russia. The only Beaufort Sea produc tion was from Amauligak with Molikpaq, when during extensive well testing they loaded a tanker and it offloaded in the south.
3.4.1.6 Concrete Island Drilling System (CIDS)

The CIDS, also known as the Glomar Beaufort Sea 1, was a steel-concrete hybrid structure consisting of a steel base toppe d by a concrete mid-section at the ice belt and two steel deck sections. Like the SDC, the unit was a MODU and was ballasted with water only. The CIDS was deployed at three locations in the US Beaufort Sea, t he last in 1997. In 2001, the structure was towed to Russia for refurbishm ent and (like Molikpaq) now operates as the permanent production platform Orlan in the Sea of Okhotsk, offshor e Sakhalin Island.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 115 of 339 Rev. 0 Figure 3-57: Molikpaq in the Beaufort Sea and as-Modified for Sakhalin

Figure 3-58: CIDS in the Beaufort and Under Tow to Sakhalin IslandIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 116 of 339 Rev. 0 3.4.1.7 Barge Structures
Niglintgak Barge

Shell Canada Ltd. has proposed to develop it s Niglintgak gas field (of the Mackenzie Gas Project) using barge-mounted pr ocessing and gas conditioning fa cilities which will be prebuilt prior to arriving on location at the Nigli ntgak site (Mackenzie Gas Project, 2004). The Niglintgak gas field is locat ed within the Mackenzie Delta of the Canadian Beaufort Sea, offshore of the North West Territories.
Shell proposed that the required processing fa cility topsides modules be transported via marine barge through the Beaufort Sea and into the Kumak Channel, where the barge would then serve as the foundat ion for the modules, as shown in Figure 3-59. Placement of the barge-mounted gas conditioning facility is pl anned for a naturally sheltered area on the seasonal flood plane of the Littl e Kumak Channel, near the Ken dall Island Bird Sanctuary (as shown in Figure 3-60). The barge will be grounded with minimal excavation and will not require a slip, thus minimizing permanent land deformation in the area. Easier reclamation activities are thus facilitat ed as the barge may be removed fr om the site for salvage or reuse (Mackenzie Gas Project, 2004). Several layers of naturally insulating soils are present in the area which will protect the bar ge from any potential permafrost. An alternate installation proposal placed the barge upon dr iven piles in the sheltered channel.
The preliminary design propos ed that a lightweight, 180 x 361 ft (55 x 110 m), ice strengthened steel barge be construc ted overseas and towed to its installation location in the Kumak Channel (Mackenzie Gas Project, 2004).

Taglu Barge
Imperial Oil Resources has al so considered utilizing barge- mounted gas conditioning facilities for its Taglu field development in th e Kuluarpak Channel, as shown in Figure 3-61 (Mackenzie Gas Project, 2004). Unlike the Nig lintgak barge, the proposed Taglu barge would require excavation of a slip for protec tion against ice and fast moving water in the narrow Kuluarpak Channel. Furthermore, the soils at Kuluarpak contain permafrost, thus making thaw settlement a potential hazard to the installation. Transportation of the barge to the Taglu site was expected to be more di fficult than transport of Shell’s proposed Niglintgak barge due to the relatively narrow width of the Kuluarpak Channel. For these reasons, among others, a land-based facility conc ept was ultimately chosen for the Taglu field (Mackenzie Gas Project, 2004).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 117 of 339 Rev. 0 Figure 3-59: Niglintgak Barge Processing Fa cility (from Mackenzie Gas Project, 2004)

Figure 3-60: Proposed Placement of Niglintgak Gas Processi ng Facility on Seasonal Flood Plane (from Mackenzie Gas Project, 2006)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 118 of 339 Rev. 0 Figure 3-61: Taglu Field Development (from Mackenzie Gas Project, 2006) Norton Sound Barge Concept
In an evaluation of structural concepts carri ed out for Norton Sound (Fluor Ocean Services, 1982), a concrete gravity barge structure was assessed for a water depth of 30 ft (9 m). The barge structure was of self-floating design for trans portation and installation, and therefore to minimize draft li ght-weight concrete was to be us ed where possible. Ballast for the barge consisted of grav el. The barge was designed to accommodate drilling and production facilities.

3.4.1.8 GBS Structures

A number of arctic GBS stru ctures have been considered fo r the Beaufort, Chukchi and Bering Seas as presented by Buslov and Krahl (1984).
In addition, PMB Systems Engineering et al. ( 1983) carried out a preliminary evaluation of a concrete gravity base structure for the south Bering Sea. Specif ic areas considered in the study were the St. George’s, Navarin and Nort h Aleutian Basins in water depths ranging from 300 to 450 feet (91 to 137 m). The c oncrete GBS evaluated was composed of a cellular base with a flared mat, steel skirts, and four main sh afts that project from the cellular base to the deck and topsides (PMB Systems Engineering et al., 1983). The GBS evaluated is similar to the North Sea platfo rm Statfjord C as shown in Figure 3-62.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 119 of 339 Rev. 0 Figure 3-62: Statfjor d C under Construction (Statoil ASA, 2007)

3.4.2 Jacket Structures Several jacket type structures have been evaluated for use in the south Bering Sea (PMB Systems Engineering et al., 1983) ; these being an eight leg template jacket, a four plus four template jacket, and a steel mono-tower jacket. T he evaluation identified the four plus four steel template as the most suitable jacket concept for the South Bering. Area considered were the St. George’s, Navarin and North Aleut ian Basins in water depths ranging from 300 to 450 ft (91 to 137 m).
The four plus four template jacket as show n in Figure 3-63 has eight legs complete with skirt piles. The four end le gs terminate beneath the surface giving the structure a clean water plane, which is expected to prevent ic e bridging of the legs. The four double walled legs are on a spacing of 10 0 x 140 ft (30 x 43 m) and contain the wells and risers (PMB Systems Engineering et al., 1983).

3.4.3 Ice & Gravel Island Structures Significant exploratio n drilling has been carried out from ice and gravel islands in the Beaufort Sea. Gravel islands have also be en used as production structures. Due to the inherent similarity of the Al askan and Canadian Beaufort Sea regions, with respect toIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 120 of 339 Rev. 0 environment and previous structure types us ed, both regions will be discussed together under this Section.

Figure 3-63: Four plus Four Template Jacke t (modified from PMB Systems Engineering et al., 1983)

3.4.3.1 Grounded Artificial Ice Islands
This complete section has been extracted fr om the major MMS Project No. 468 (C-CORE et al., 2005). Minor modifications to the te xt have been made. It should be noted thatIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 121 of 339 Rev. 0 floating ice drill pads were generally not consider ed in the Beaufort given the nature of the ice movement.
The first grounded flooded ice island was built by Union Oil in Harrison Bay, Alaska in 1976/77. Grounded ice islands have generally been constructed in less than 30 ft (9 m) water depth. The use of sprinkling and sprayi ng on experimental and re lief well pads has allowed these methods to be developed with lowe r risk to project schedules. Spray ice was also used to form protection structures around grounded drilling structures such as the CIDS platform offshore Alaska in the mid 1980s.

Grounded ice islands are constructed in a similar way to floating islands, in that artificial ice is built up on top of the natural ice sheet to increase its thickness until it becomes grounded on the seabed. However, since the water column is shallow, any movem ent of the island in relation to the seabed will damage the drill-stri ng, and so the design requirement is to eliminate any differential movement. The is land is therefore designed to withstand the horizontal force applied by the surrounding ic e sheet by providing resistance through contact with the seabed. An addi tional requirement is to mainta in the stability of the rig foundation, which will undergo creep settl ement of the ice under loading.
As with floating platforms, start of construction is limited by the formation of stable ice and access to the drilling location. Generally, to date, platform design has been performed using the natural ice to support equipment and personnel during construction.
The first grounded ice island to be used for expl oration drilling was co nstructed by Union Oil in Harrison Bay in 1977/78. It was grou nded in 9.8 ft (3 m) wate r depth using flooding techniques by applying thin layers of seawater to the ice surface and allo wing it to freeze in place. Generally, however, the re latively slow build-up rates achievable with flooded ice techniques limit the usefulness of these stru ctures as grounded ice platforms. It is more suited to the construction of roads, which require less ice thickness.
Spray ice islands have been used to stabilize r ubble fields and for potential use as relief drilling pads, such as at Tarsiut (Neth et al., 1983), Alerk (Weaver and Poplin, 1997), Kadluk (Kemp et al., 1988) and Isserk (Poplin and Weaver, 1992). Figure 3-64 shows the Tarsiut relief pad built next to the main caisson retained drilling island.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 122 of 339 Rev. 0 Figure 3-64: Tarsiut Relief Spray Ice Island (ICETECH, 2008)
The first use of an island built completely fr om spray ice for explor atory drilling was carried out by Amoco at Mars, Harrison Bay, in 1986. This island was built on the landfast first-year ice in 24.9 ft (7.6 m) water depth, to provide a completed freeboard of 24.6 ft (7.5 m). The 1083 ft (330 m) diameter platform require d 4 pumps to produce 35.3 million ft 3 (1 million

m 3 ) of ice during the 45 day construction progr am. Figure 3-65 shows the Mars ice island during drilling operations.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 123 of 339 Rev. 0 Figure 3-65: Mars Spray Ice Island (C-CORE, 2005)

The technical and financial succ ess of this platform led to sp ray ice becoming the material of choice for the construction of grounded platfo rms in shallow water in the Beaufort Sea. Construction cost savings on the order of 50% were quoted compared to sand and gravel islands previously used, as demonstrated in Figure 3-66. The construction of another 3 exploration spray ice islands in the 1980s at Angasak, Nipterk and Karluk reinforced the advantages of spray ice construction.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 124 of 339 Rev. 0 Figure 3-66: Cost Comparison between Gr avel and Ice Islands (C-CORE, 2005)
Operational spray ice islands we re used at the Thetis Field in 2002/03, where a number of innovative techniques were successfully used. Th is allowed the drilling of 2 wells using the same rig in the same season. A summary of grounded artificial ice island construction is presented in Table 3-9.IMVPAProject No. C-0506-15Arctic Offshore Technology Assessmentof Exploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 125 of 339 Rev. 0Table 3-9: Summary of Grounded Artificial Ice Island ConstructionNameOperatorLocationTechniqueUseDatesWaterDepth, ft (m)Union OilHarrison Bay, US Beaufort SeaFloodExperimental Island1977/809.8 (3)ExxonHarrison Bay, US Beaufort SeaFlood, SprayExperimental Island19799.8 (3)EssoCanadian Beaufort SeaSprayExperiment1980TarsiutGulf CanadaCanadian Beaufort SeaSprayRelief Pad1981/8263 (19.2) onBermAlerk islandEssoCanadian BeaufortSprayRelief Pad198238 (11.6)SSDC UvilukCANMARCanadian Beaufort SeaSprayExperimental ProtectionStructure1982/8398 (30)Kadluk 0-07EssoCanadian Beaufort SeaSprayRelief Pad1983/8444 (13.5)Sohio Rubble GeneratorSohioMcKinley Bay, Beaufort SeaSprayExperimental ProtectionStructure1983/8443 (13)Ice Island ExperimentExxonCanadian Beaufort SeaSprayExperimental Island1983/8445 (13.7)Big Gun Expt., MV KigoriakEssoMcKinley Bay, Beaufort SeaSprayExperimental ProtectionStructure1983/8446 (14)SSDC KogyukCANMARMcKinley Bay, Beaufort SeaSprayExperimental ProtectionStructure1983/8493 (28.4)CIDS Antares BarrierExxonAlaskan Beaufort SeaSprayOperational Protection Structure1984/8549 (14.9)Cape Alison C-47PanArcticEllef Ringnes Island, CanadianArcticSprayOperational Floating Island1984/85259 (79)MARS full-scale prototypeSohioHarrison Bay, US Beaufort SeaSprayExperimental Island1984/8530 (9.1)MarsAmocoHarrison Bay, US Beaufort SeaSprayOperational Island1985/8625 (7.6)Angasak L-03Imperial/EssoCanadian BeaufortSprayOperational Island1986/8718 (5.6)Nipterk P-32ImperialCanadian BeaufortSprayOperational Island1988/8923 (6.9)KarlukChevronUS BeaufortSprayOperational Island1988/8925 (7.6)lsserkl-15ImperialCanadian Beaufort SeaSprayRelief Pad1989/9038 (11.5)IvikPioneerThetis, Harrison Bay, AlaskaSprayOperational Island2002/039.8 (3)OoogurukPioneerThetis, Harrison Bay, AlaskaSprayOperational Island2002/0312 (3.7)NatchiqPioneerThetis, Harrison Bay, AlaskaSprayOperational Island2002/037.5 (2.3)Kashagan, Sunkar SiteAgip KCONorth Caspian SeaSprayOperational Protection Structure2002/03Kashagan, Aktote SiteAgip KCONorth Caspian SeaSprayOperational Protection Structure2003/04Kashagan, Kairan SiteAgip KCONorth Caspian SeaSprayOperational Protection Structure2003/04IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 126 of 339 Rev. 0 A review of the design criteria used in practi ce for spray ice islands suggests that the strength of the island itself is rarely critical in determini ng resistance to lateral ice loads, but rather the sliding shear forc e developed between the island an d the seafloor. The general practice has therefore been to adopt a safe, lower-bound strength prof ile and undertake a check that it is adequate

3.4.3.2 Gravel Islands
This section begins with an overview of grav els islands with a general focus on their use from an exploratory dr illing perspective. Following this, pr oduction projects utilizing gravel islands have been highlighted; further informa tion with respect to gravel islands can be found within the assessment section, Section 4.
Exploratory drilling for oil a nd gas commenced in the Mackenzie Delta area of Northern Canada in the mid-sixties. Afte r several years of extensive on -shore exploration, the first offshore Arctic well was drilled by Imperial Oil in the winter of 1973 - 74. This well was drilled from the artificial island, Immerk B- 48, where construction had started using a cuttersuction dredge in the summer of 1972. This is land was constructed at a fairly sheltered location in the offshore delta in a water depth of 43 ft (13 m). There wa s no drilling from the island during the first winter in order to de monstrate that the island could withstand the winter ice. This it did successfully, and after adding additional fill dur ing the next summer, drilling commenced (Croasdale and Marcellus, 1977).
As shown below in Table 3-10, 31 artificial gr anular islands have been built in water depths ranging to 62 ft (19 m) in the Canadian Beaufort Sea. Note t hat Table 3-10 is an excerpt from Appendix Table C-2, Over view of Drilling Activity in the Canadian Beaufort Sea.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 127 of 339 Rev. 0

Table 3-10: Exploratory Drilling Islands used in the Canadian Beaufort Sea (from Timco, 1998)
Date Island 1972 Roland Bay L-41

1973 Immerk B-48, Adgo F-28, Pullen E-17, Pelly B-35 1974 Unark L-24, Adgo P-25, Garry P-94

1975 Nerlerk B-44, Adgo C-15, Ikattok J-17, Nerlerk F-40

1976 Sarpik B-35, Kugmallit H-59, Unark L24A, Arnak L-30 1977 Kannerk G-42, Isserk E-27 1978 Garry G-07 1979 Adgo J-27 1980 Issungnak 2O-61 1981 Alerk P-23

1982 Issugnak O-61, West Atkinson L-17, Itiyok I-27 1984 Adgo H-29 Nipterk L-19

1985 Nipterk L-19A Adgo G-24 Minuk I-53 Ellice L-39 1986 Arnak K-06 1987 Angasak L-03 1989 Nipterk P-32 Notation Sacrificial beach island Sandbag retained island
Hauled island Spray ice islandIMVPAProject No. C-0506-15Arctic Offshore Technology Assessmentof Exploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 128 of 339 Rev. 0Figure 3-67: Alaskan Beaufort SeaManmade Islands (modified from US Army Corps of Engineers, 1999)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 129 of 339 Rev. 0 Between 1975 and 1990, 17 gravel islands were constructed in the Alaskan Beaufort Sea (refer to Figure 3-67). In 2001, Seal Island (k nown as Northstar now), initially used for exploration, was rebuilt by BPXA for the Northstar production project. Both Northstar and Endicott are production islands and will be discussed in greater detail below.
Land fast ice, ranging up to 6.6 ft (2 m) thick, covers the near-shore Beaufort Sea for about nine months of the year, and has a consider able influence on construction methods and island design. In the deeper wa ter areas, multi-year ice incu rsions have to be considered. Gravel islands need sufficient sliding stability to withstand the forces generated by moving ice and the possibility of ice ride-up also has to be considered.

Artificial islands have been built either during the winter by tru cking granular fill over the ice or in the short Arctic summer using dredges . Islands have been constructed of gravel, sand, silt and a mixture t hereof. Slope protection has been designed to match the measured and predicted sea-state, which al so influences the island freeboard needed to avoid wave over-topping. Slope protection met hods for artificial islands have included anchored poly-filter clot h and sandbags, concrete units, rock fill, and sacrificial beaches. Optimum granular artificial island designs have to account for constructional constraints, working area needed, ice action, wave action and geotechnical factors.

For exploratory drilling, a stable platform is required from which to drill. Drilling operations can last from about thirty to one-hundred and sixty days. The actual time will depend on the well depth, drilling factors, and whether any testing of discovered hydrocarbons is conducted.
In the early 1970’s, of the numerous offshore drilling conc epts which were considered, artificial granular fill islands we re selected to initiate Arctic offshore drilling. They had the advantage of short lead-time and t he use of proven technology. Al so they could be built to withstand the year-round environment and thus the drilli ng rig could stay ov er the well until it was completed. The main disadvantages of islands are the short period available for construction in the summer, and also the fact that in deeper water, the construction times and costs increase rapidly.
The design of artificial granular islands for ic e-infested waters is normally governed by the resistance of the structure to ice loads. It is also influenced by materials and techniques available for construction as a function of location and season. Figur e 3-68 shows the twoIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 130 of 339 Rev. 0 basic designs utilized in the Canadian Beaufort Sea for the cons truction of granular fill artificial islands.
Figure 3-68 is drawn with an approximate vertic al exaggeration of 3 times. The figure illustrates islands in 16 to 23 ft (5 to 7 m) water depth.

Figure 3-68: Basic Designs for Granular Fill Artifi cial Islands in the Canadian Beaufort
The deepest granular fill island was Issugnak O-61 in 62 ft (19 m) water depth. The island took 3 seasons to complete and required 176.6 million cubic feet (5 million cubic meters) of fill. The 1:15 – 20 sloped beach section shown for the sacrificial beach design would be approximately 3 times wider than that shown in Figure 3-68.
A photo of the first deepwater sacrificial beac h island, Arnak L-30, is shown undergoing wave action in 1976 in Figure 3-69. This photo shows a large amount of redistribution of the sand from the sacrificial beach to the lee side of the island. This sediment transport behavior was a feature of the design.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 131 of 339 Rev. 0 Figure 3-69: Imperial Oil’s Arnak L-30 S eptember 1976 Showing Wave Action on the Sacrificial Beach Island Design (f rom Croasdale and Marcellus, 1977)
Referring back to Table 3-13, of the 31 island s constructed in the Canadian Beaufort Sea, 13 were Sandbag Retained Islands, 13 were Sa crificial Beach Islands , 1 (Sarpik B-35) was protected by filter-cloth with concrete units attached (which proved to be problematic) and the remaining 5 were classified as hauled islands (shallow water islands not requiring significant erosion protection). The choice of design to a la rge extent was based on the availability (and cost) of construction equipment.

Northstar

The Northstar oil field was discovered in the Beaufort Sea in 1983 by Shell (SPG Media Limited, 2007g). Northstar Island is a 5 acre (20,200 m 2 ) manmade production island which was built upon an abandoned/deteriorat ed exploration island, Seal Island. It was chosen to utilize Seal Island because significant cost and time savings would be realized through rebuilding (and subsequent expa nsion) as opposed to starti ng from scratch and building a new island. Furthermore, based on ERD capabilities at the time, Seal Island was able to reach 95% of the reservoir (US Army Corps of Engineers, 1999).
Northstar Island is grounded in approximately 39 f eet (12 m) of water and is located about 6 miles (9.7 km) offshore. Seasonal access to the island is achieved via ice roads.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 132 of 339 Rev. 0 Figure 3-70: Northstar Produc tion Island (Thomas, n.d.)
Oooguruk
The gravel island was completed in 2006 in about 4.5 feet (1.4 m) of water and stands 23 feet (7 m) above the seafloor . An equivalent of 22,000 tru ckloads of gravel was used to construct the island (Wright, 2006). In the su mmer of 2006, side slopes were constructed on the island to resist ice loads ; slope protection is provided by gravel bags (8000 in total) (Quinn, 2007). Settlement of t he island has been estimated as a meter or so which will require maintenance of the isl and. Wick drains were install ed to speed up consolidation settlement from two and a half years to nine months (Knott, 2006). The project is scheduled for first oil in early 2008.

Endicott Island
Endicott Island was the first production island c onstructed. The Endicott oil field is located in the Beaufort Sea, about 8 miles (12.9 km) east of Prudhoe Bay. It was discovered in 1978 by the Sohio Alaska Petroleum Company and is currently operat ed by BP Exploration (Alaska).
This project pool has been developed from two ar tificial gravel islands that are located approximately 4 miles (6.4 km) offshore in 2 to 14 feet (0.6 to 4.3 m) of water. These islands are connected through a 5-mile (8 km) long gravel causeway, which supports the pipeline (shown in Figure 3-72).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 133 of 339 Rev. 0 The causeway was constructed in 1984-85. Endicott production began in July 1986. During the peak production years from November 1987 and October 1993, Endicott averaged about 104,250 barrels of oil per day (BOPD). Pr oduction has declined over the years to the point where during the last 8 months of 2004, production from Endicott was 17,600 BOPD.

Figure 3-71: Oooguruk Produc tion Island (INTEC, 2007)

Figure 3-72: Endicott Production Island (Thomas, n.d.)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 134 of 339 Rev. 0 3.4.4 Floating Structures 3.4.4.1 Drillships
The ice class drillship “Explorer II” and “Kulluk” were used in the Beaufort or Chukchi Seas for water depths in excess of 100 (30 m) in t he 1980’s and 1990’s. To the south, in Navarin Bay and St. George Basin, semi-submersibles we re used extensively due to the relatively ice-free environment for most of the year. The first drill ing operations undertaken by drillships in ice prone waters were primar ily intended for open water use, and normally drilled during the Beaufort or Chukchi’s summer and early fall seasons. However, with icebreaker support, they soon deve loped the capability to mainta in position in a variety of pack-ice conditions. This extended their oper ating season beyond the open water period, although they did not work extensively in hea vy ice. The Explorer II (see Figure 3-73) is a Donheiser Marine, Super Class 1AA design. Its mooring syst em is an eight point wire design and had a variable load capabilit y of 6,387 tons (5794 tonnes).

Figure 3-73: “Nort hern Explorer II” (formerly the C ANMAR Explorer II and Explorer II) (WorldOil, 2000)

The Kulluk was designed as a second generation drilling system that was purpose built to significantly extend the open water season, by beginning drilli ng operations in the spring break-up period and continuing unt il early winter. As a resul t, the Kulluk operated in a greater and more difficult range of pack-ice c onditions than drillships. In addition, “in-iceIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 135 of 339 Rev. 0 performance information” was systematically obtained during its operations. Because of this, the Kulluk’s experience base provides the best source of data for most considerations related to moored vessel stat ion-keeping operations in various pack-ice conditions.

Figure 3-74: Kulluk (C ourtesy of DC Marine)
The Kulluk (shown in Figure 3-74) was designed with a variety of features to enhance its performance capabilities in ice. Some of the primary techni cal challenges that were considered and accommodated in the Kulluk ’s design are highlighted as follows:

• Minimizing the icebreaking and clear ance forces that the vessel would experience from any direction, by pr oviding it with an “omni-directional capability” to resist ice action;IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 136 of 339 Rev. 0 • Developing a hull form that would “mi nimize” icebreaking forces, enhance ice clearance, and reduce the possibility of ice moving down the hull and under the vessel, where it could interfere with the mooring and riser systems, and enter the moonpool area;

• Providing a strong mooring system that could resist the “high” load levels associated with heavy pack-ice condit ions during extended season operations, with acceptable mooring line tensions and vessel offsets;

• Developing a submerged mooring system that would “elimin ate” the problem of ice entanglement with mooring lines at (or near) the waterline; and,

• Configuring an ice management system that would be ca pable of “protecting” the Kulluk in the more difficult ice conditions expected in the Beaufort’s extended drilling season.
Typically, the Kulluk was supported by two to four CAC 2 icebreakers during its operations in heavy pack-ice conditions. Although the vessel occasionally operated in unbr oken ice, it normally worked in managed ice conditions, w here the oncoming pack-ice cover had been pre-broken into relatively small fragments by the support icebreakers (shown below in Figure 3-75).

Figure 3-75: The Kulluk - Oper ations with Icebreaker Support (Courtesy of DC Marine)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 137 of 339 Rev. 0 3.4.4.2 Semi-Submersibles
Semi-submersibles are conventional floating ex ploration structures and have been used considerably in the south Bering Sea. Table C-1 locate d in Appendix C provides information on Alaska OCS drilling activity incl uding drilling rigs employed. In general, harsh environment winterized semi-submersibles have been used.
An example of a previously used semi-subm ersible; the Ocean Odyssey (Figure 3-76) was an advanced super-class unit designed to operat e in Arctic environments (OSTI, 2007). The Odyssey was capable of operating in winds greater than “100 knots (51.4 m/s) with its 4,500-ton (4100 tonne) deck-l oad without de-ballasting from its 80 ft (24.4 m) operating draft” (OSTI, 2007). Further, the Odyssey was constructed with reinforced columns and was equipped with a caged riser (Oil Rig Disasters, 2007). The Ocean Odyssey is now used as a mobile spacecraft launch pl atform (SPG Media Limited, 2007i).

Figure 3-76: Ocean Odyssey (NationMaster, 2005)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 138 of 339 Rev. 0 3.4.4.3 FPSO
To date, no floating production structure has been used in the Alaskan OCS; however, a feasibility assessment of a tanker-based FPSO system has been carried out for the southern Bering Sea (Brian Watt & Associates , 1985). A water depth of 250 ft (76 m) was used for the assessment and the FPSO concept was based on a 1 26,000 DWT tanker design with an ice strengthened hull. The assessment consider ed several mooring systems with both flexible and rigid risers. The fina l concept selection utilized a turret mooring system with flexible risers.

The assessment concluded that although the F PSO would require local ice strengthening, ice was not the governing global design load. Moreover, the assessment concluded that no significant advances in technology were requir ed at the time to develop a feasible system (Brian Watt & Associates, 1985).

3.4.5 Subsea Solutions As discussed previously in Section 3.3.3, subsea tiebacks to a platform and subsea solutions with no structure have been used/cons idered for ice environments. While no such production facilities have been built in the Alaskan OCS or t he Canadian Beaufort, glory holes have been considered for the Arctic to house the wellhead and associated equipment during exploration.

3.4.6 Pipelines
3.4.6.1 BP Alaska Northstar
The Northstar project was the first Arctic proj ect with a subsea oil pi peline. The Northstar project operated by BP Exploration (Alaska) Inc. included the design, construction and installation of the first offshore oil and gas produc tion pipeline in the U.S. Arctic (Lanan et al., 2001). The Northstar Unit is located appr oximately 8 miles (12.9 km) northwest of Prudhoe Bay, offshore approximately 6 miles (9.7 km), in a water depth of approximately 40 feet (12 m) (Figure 3-77).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 139 of 339 Rev. 0 0 5 10km SCALE ALASKA/FEDERAL WATERS BOUNDARY

TAPS PUMP STATION 1

BADAMI PIPELINE NORTHSTAR PROJECT SEAL ISLAND

GWYDER

BAY

PRUDHOE BAY WEST DOCK

ENDICOTT

TERN ISLAND
TIGVARIAK ISLAND McCLURE ISLANDS NO NAME ISLAND CROSS ISLAND MIDWAY ISLAND S

KUPARUK

RIVER

DEADHORSE SAGAVANIRKTOK RIVER LIBERTY PROSPECT NORTHSTAR PIPELINES BEAUFORT SEA

Figure 3-77: Northstar and Li berty Project Location Map (from Lanan et al., 2001)
A single drilling/pro duction structure with pipelines to shore was selected as the development plan. Seal Island, an exploration gravel island built by Shell in 1982, was enlarged and drilling/process fac ilities installed for oil production. Construction of the island and the pipeline were completed in 2000. Facilit ies were installed on the island through the summer of 2001 and production started that fall.

Pipelines
Seal Island is approximately 6 miles (9.7 km) o ffshore in 37 feet (11 m) of water. Production of the 65,000 bbl/day is from t he gravel island, with the oil tr ansported to shore and then to TAPS Pump Station 1 by a 10.75-inch (273 mm) diameter pipeline. A second 10.75-inch (273 mm) diameter pipeline supplies gas from Prudhoe to the island for fuel gas and reservoir pressure maintenance.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 140 of 339 Rev. 0 The 10.75-inch (273 mm) crude sales oil pipeli ne offshore segment was a 0.594-inch (15 mm) W.T., API 5L Grade X-52 based on pipe stability requirem ents during installation and compatibility with potentially hi gh operational strains (Lanan et al., 2001). The oil line is designed for a normal operating pressure of 850 psig (5860 kPa). The offshore gas pipeline has the same pipe specifications, wall thickne sses, and grade. The gas line is designed for a throughput of 100 MMSCFD (2 .8 million cubic meters per day) and a normal operating pressure of 1250 psig (8620 kPa). The oil and gas pipelines were bundled together over the offshore pipeline length and incorporat ed within the bundle was an external leak detection system.

Several technical issues were addressed during the design phase, including route selection, landfall site selection, ice goug e protection, permafrost and strudel current loadings, and construction methodology. The pipelines have been designed to withstand 100-year return period environment al conditions. The Northsta r development also utilized limit strain design criteria to meet the challenges of offshore arctic environments and marginal field economics.
Project Design Challenges & Highlights

Pipeline design challe nges and highlights associated with the Northstar development included:

• Ice keel protection;

• Strudel scour evaluation;

• Thaw settlement of permafrost;

• Upheaval buckling; and,

• Limit strain criteria.
Ice Gouging: The Northstar pipelines were designe d to avoid failure due to ice keel gouging of the seabed. The effect of sub-keel soil displacement inte raction with the pipelines has been considered in establishing the required depth of cover. A number of analyses were carried out by varying the ice keel width to determine the width that induced the largest strains in the pipeline for a 100-year ice gouge depth of 3.6 ft (1.1 m). This design ice gouge depth should be consider ed against the maximum dept h ice gouge measured fromIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 141 of 339 Rev. 0 10 years of gouge data which wa s determined to be 2.0 ft (0.6 m) (Lanan et al., 2001). The results indicate the pipeline bending strain s due to gouging would be safely less than maximum allowable levels for the burial depth selected.
Strudel Scour: The allowable pi peline free span lengths were evaluated for pipeline strain limitations and the prev ention of vortex shedding induced oscillations of the pipelines. Based on available and applicab le data, the value associat ed with the 100-year return period maximum horizontal dimension event was f ound to be 122 ft (37.2 m) at the seabed. By examining side slopes of scours, a maximum scour dimension of 84 ft (25.6 m) at the base of the pipe is estimated (for an 8 ft (2 .4 m) burial depth from seabed to bottom of pipe). A conservative strudel scour span di mension of 90 ft (27.4 m) was adopted for design (Paulin et al., 2002). This phenomenon has been found to not control the pipeline’s wall thicknesses or depth of cover requirements.
Permafrost Thaw Settlement: Ice bonded permafros t was found to be present along the pipeline route close to shore in water dept hs less than approximatel y 5 ft (1.5 m). The maximum thaw induced settlement potential in the ice-bonded permafrost region was found to be approximately 2 ft (0.6 m) close to t he onshore transition, within a few hundred meters from shore. A design value of 2 ft (0 .6 m) of settlement was used for the lagoon section of the offshore route (Paulin et al., 2002). The other location where thaw settlement appeared higher was on the outside of the barrier islands, just before the top of the permafrost drops deep below the seabed under t he influence of deeper water conditions. Here, the potential settlement was found to be gener ally less than 1.5 ft (0.46 m); a design value of 1.5 ft (0.46 m) was adopted and was assum ed to be differential settlement. An operational limit stat e bending strain criterion was used to confirm that the pipelines would be safe under the maximum predict ed differential thaw settlement.

Upheaval Buckling: Because the pipelines we re operated at a temper ature significantly higher than that at which they were insta lled, upheaval buckling was a design issue. A maximum allowable overbend vertic al curvature had to be defined for pipeline construction. A maximum 2 ft (0.6 m) variati on in pipeline elevation (trough to peak) over 302 ft (92 m) was considered reasonable give n the pipeline trenching/installation method (see Lanan et al., 2001). The results of the analyses indica te that a minimum backfill thickness of approximately 5 ft (1.5 m) of native soil (low submerged density and uplift resistance) was required over top of the pipelines.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 142 of 339 Rev. 0 Limit State Design: The pipelines need to be buried deep enough to withstand these environmental forces, but not so deep as to be impossible to construct or make the project uneconomical. The pipeline design is therefore based on strain rather than stress. The criteria have been included in the design for non- cyclic pipeline displacements (e.g. thaw settlement, sub-ice keel soil deformation, and island settlement). Northstar pipelines are designed at 1.2% operating bendi ng strain, with 1.8% strain fo r extreme events (Nogueira et al., 2000). Because these criteria ar e dependent on pipe behavior during extreme bending, full-scale bend tests were conducted to validate the limit state design methodology.
Shore and Island Approach: The design of the s hore approach at the landfall point included the consideration of coastline er osion effects on the stability of the pipelines as well as ice ride-up onshore. The shore approach at Point St orkersen extends approximately 180 feet (55 m) onshore of the receding coastal bluff line after which the pipelines then transition onto a gravel pad through a casing. At Seal Is land, the trench terminated at a vertically curved sheet pile slot in the island. The desi gn accounted for the effects of potential island settlement on the pipeline.
Burial Depth: As a result of all the environmental and operational loading conditions, the required depth of cover was determined to be 7 f eet (2.1 m) (original seabed to top of pipe) for water depths less than 33 feet (10 m) deep and 9 feet (2.7 m) for water depths greater than 33 feet (10 m) (Lanan et al ., 2001). Depth of cover is defined on this project as the distance from top of pipeline to the top of the original undi sturbed seabed. The trench was backfilled overtop of t he pipelines using the trenching spoils.
Pipeline Construction / Construction Planning Challeng es & Highlights
The overall construction strategy for the Northstar project was to use the winter construction season to its maximum advantage, allowing the use of conventional or adapted onshore construction equipment and tec hniques. The limited open water season in the Beaufort Sea combined with its remotene ss and reduced accessibility with respect to mobilizing marine equipment (e.g. pipe laying vessels and ocean-going barges) makes construction significantly more expensive, ex tends project execution schedules, and entails some risks with respect to equipment mobilization and construction windows.

Innovative construction methods were developed for the Northstar project such as on-ice and through-ice excavation and installation (Lanan et al., 2001). Ice-based construction hadIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 143 of 339 Rev. 0 been used successfully in arti ficial gravel island constr uction and, coupled with ice thickening, offered an attractive alternativ e to conventional marine pipeline installation methods in this area.
Construction of the offshore segment of the pi pelines included construction of ice roads, thickening of the sea ice to form a beari ng surface, making ice slots by cutting and removing ice blocks, excavation of an offshore trench into which the pipelines are lowered, and backfilling of the trench.
An eight-foot wide slot was cut in the ice and blocks removed using backhoes and moved to locations away from the work site to pr event excessive deflections of the ice in the working areas. Offshore trenching was conduct ed from the surface of the ice using modified backhoes equipped with extended reach booms.
Welding of the pipeline took pl ace to the side of the trench, where non-destructive testing (NDT) was also performed. The welds were t hen coated, the cathodic protection anodes attached to the pipelines, and the pipelines st rapped together to form a bundle. Sidebooms were used to lower the bundle through the slot and into the trench. All spoils were then placed back into the pipeline trench. The pipel ines were hydrotested using a water-glycol mix followed by an inspection pig run. Additional information on this project can be found in: Lanan et al. (2001); Nogueira et al . (2000); Paulin et al. (2002).
3.4.6.2 Pioneer Oooguruk

Overview

Pioneer Natural Resources Alaska , Inc. is developing the Ooog uruk Field, offshore Alaska. This field is located approximately 5.6 miles (9 km) offshore, near the mouth of the Colville River Delta, and 40 miles (64 km) west of Prudhoe Bay. The man-made gravel island is located in less than 5 ft (1.5 m) of water and stands 23 ft (7 m) in hei ght as measured from the seabed. First oil is scheduled for early 2008; by 2010 oil production is anticipated to peak at 15,000-20,000 bpd (Knott, 2006). Produced fluids are tr ansported to shore via a multiphase pipe-in-pipe system.

Pipelines

Production will be transpor ted to shore through a 5.6 mile (9 km) multiphase pipeline which will form part of a subsea bundle, including power to the isla nd, which will be unmannedIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 144 of 339 Rev. 0 during production operations. Th is line will be the first application of pipe-in-pipe (PIP) production flowline technology in the offshore Al askan Arctic (Knott, 2006). The bundle is an open bundle rather than bei ng enclosed in a single large pipe; individual pipes are strapped together which makes t he system lighter and less comp lex which translates to lower cost (Knott, 2006).
The open bundle consists of four pipelines including a 12.6 in ch (320 mm) diameter internal pipe within a 15.75 inch (400 mm) diameter external pipe (PIP) which transports the multiphase flow to shore. The remaining lines are a 5.9 inch (150 mm) diameter gas line, a 9.8 inch (250 mm) diameter water line and a 2 inch (50 mm) diameter diesel pipeline. The PIP system is API 5L gr ade X-52 materials or better. The pr esence of an annulus facilitates the use of an annulus vacuum monitoring or pr essure monitoring system for leak detection. The annulus between the exter nal and internal pipelines w ould also help contain any potential leakage in the event of an emergency.
Project Design Challenges & Highlights
A significant design issue was protection of the pipeline bundle against ice gouging. To protect the pipeline, it was trenched and backfilled. Trenches were planned to be 9 ft (2.7 m) deep affording 6.6 ft (2 m) of cover over t op of the pipeline (Kno tt, 2006). This backfill cover would also resist upheaval buckling of t he pipeline as it heats up during operations.
Another significant challenge associated with the Oooguruk pi peline was to design against the effects of strudel scour, where river overfl ood waters flow through holes or cracks in the ice sheet and erode the seabed. To monitor any erosion of soil cover over the pipeline, Pioneer planed to install a fiber optic temperature monitoring system with the pi peline. Such a system will detect any decrease in temperature, indicating loss of soil cover as the result of seabed erosion (Knott, 2006). Other desig n issues included thaw settlement of permafrost and upheaval buckling potential.
Construction was planned to be carried out from the ice. In preparat ion for construction planning, two 330 ft (100 m) long test trenc hes were excavated in 2006 (one near shore and one close to the island) to understand soil behavior during trenching (Knott, 2006). The three-phase pipe-in-pipe system was installed fr om the ice in the winter of 2007 (Nelson, 2007a).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 145 of 339 Rev. 0 3.4.6.3 Nikaitchuq
ENI is planning to develop th e Nikaitchuq Field offshore the coast of the North Slope of Alaska. The site is in the Beaufort Sea, n ear Spy Island and appr oximately three miles offshore Oliktok Point.
The project calls for a production pad at Oliktok Point and offshor e gravel islands inside the barrier islands, in the vicinity of Spy Island, in water depths of six to ten feet (Cashman and Nelson, 2005). The original concept called for a “pipe in pipe” design to provide secondary containment for the three-phase flow and an annular space for pipeli ne leak detection. Nikaitchuq will produce up to 40,000 bbls/day (OilVoice, 2007).

The pipeline was planned to be trenched from the ice in wint er. Initial engineering work included pipeline concept eval uation, flow assurance, pi peline mechanical design, trenching and installation studies, and design to protect against seabed ice gouging, permafrost thaw settlement, strudel scour , upheaval buckling and channel migration (INTEC, 2007).
3.4.6.4 BP Alaska Liberty
The BP Alaska Liberty project was planned to be developed in much the same way as the Northstar project (BPXA, 2000). The proposed arti ficial gravel island was to be located in Foggy Island Bay east of Endicott and was to be a self-contained dr illing and production facility. The island would have been constructed 6 miles (9.7 km) offshore inside the natural barrier islands in approx imately 21 feet (6.4 m) of water. The facilities were to be designed for production of 65,000 bbl/day.
The 12.75-inch (324 mm) crude sales oil pipelin e offshore segment design yielded a 0.688- inch W.T., API 5L Grade X-52 line based on pipe stability requirements during installation and compatibility with potentiall y high operational strains. T he oil line was designed for a MAOP of 1415 psig (9756 kPa). The oil pipel ine was designed for a maximum operating temperature (oil pipeline inlet) of 150°F (66°C) (INTEC, 1999).

Several technical issues were addressed during the design phase, including route selection, landfall site sele ction, upheaval buckling, ice goug e protection, permafrost and strudel current loadings, and construction me thodology. The pipelines were designed to withstand 100-year return period environmental conditions and utilized limit strain design criteria to meet t he challenges of offshore arctic environments.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 146 of 339 Rev. 0 The pipeline was designed to avoi d failure due to ice keel go uging of the seabed. Analysis indicated a 100-year ice gouge dept h less than 1.5 feet (0.5 m). A 3 foot (0.9 m) ice gouge depth was conservatively adopted for design.

The maximum thaw induced settlement potentia l in the ice-bonded permafrost region was found to be approximately 0.9 feet (27 cm). A design settlement of 1 foot (30 cm) was combined with an operational limit state bending strain criter ion to confirm the pipelines were adequately designed. The Liberty pipel ine was designed for a maximum 1.2% operating bending strain, with 1.8% st rain for extreme events (INTEC, 1999).
INTEC (1999) prepared a conc eptual engineering report to evaluate and present design alternatives for the Liberty pipeline. The report was intended to provide permitting and resource agencies information for evaluating al ternatives in the Liberty Environmental Impact Statement. The report revi ews four design alternatives:

• Single wall st eel pipeline;

• Steel pipe-in-pipe system;

• Single wall steel pipe inside HDPE (h igh-density polyethylene) sleeve; and,

• Flexible pipe system.
In order to fully evaluate these alternatives , the report covered project design criteria, installation methods, construction costs, operations and maintenance issues, system reliability, and leak detection.
The Liberty pipeline design was completed in 2000 but the project wa s cancelled in 2002. Since then, BP has been investigating the use of extended reach drilling to develop the project from shore (Nelson, 2005).

3.4.6.5 Chukchi Se a Pipeline Studies
In 1986, joint industry studies were undertaken to investigate the f easibility and cost of hydrocarbon transportation systems for the c entral and northern Chukchi Sea (INTEC, 1986). The technical feasibility and costs for transportation syst ems including pipelines and tankers were major considerations that had to be evaluated at the time , prior to exploration for potential oil reserves in the area.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 147 of 339 Rev. 0 Preliminary pipeline a nalysis was performed to define param eters that would significantly affect the technical feasibility and the cost s of offshore pipelines, including routing, hydraulics, trenching, and construction. In s ubsequent studies (INTEC, 1991), preliminary pipeline design requirement s were established for 8 pipeline routes. These lines ranged in length from approximately 110 to 210 miles (177 to 338 km) and from 16 to 44 inches (406 to 1118 mm) in diameter.
Water depths in the study area ranged from shor e to approximately 300 feet (91 m) in the northern portion. Sea ice within the study area and along potential tanker routes was identified as the dominant env ironmental condition affecti ng hydrocarbon transportation systems.
Survey data available at the time indicate d that the seabed was actively exposed to ice gouging to water depths of at least 165 feet (50 m). Maximum ice gouge depths were generally observed between water depths of 115 and 165 feet (35 and 50 m). A maximum observed ice gouge depth of 15 feet (4.5 m) wa s recorded at a water depth between 115 and 130 feet (35 and 40 m) and no ic e gouges were recorded in water depths greater than 190 feet (58 m).
As with other arctic areas, one of the pr imary design concerns was ice gouging. The required depths of cover der ived from statistical paramet ers of ice gouge frequency were determined to be between 6 and 14 feet (1.8 and 4.3 m) depending on the location.

A number of construction methods were ev aluated including laybarges, bottom tow, and bottom pull. For pipelines in water depths great er than 40 feet (12 m), a third generation laybarge was recommended as the method of insta llation. In water depths less than 40 feet (12 m), pipeline installation by bottom pull was considered practical. For nearshore loading lines and for short nearshore lines, t he bottom tow method was the recommended installation method.
The recommended pipeline trenching method in the offshore areas was a trailing suction hopper dredge or a linear trencher (dredge) concept. An evaluation of these two types of dredges indicated an economic adv antage for the linear trencher where the pipeline length was greater than 35 miles (56 km). In shallo w water nearshore, which was not accessible by the trailing hopper suct ion hopper dredge, a cutter suction dredge would be used to excavate the trench.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 148 of 339 Rev. 0 3.4.6.6 Bering Sea

A study carried out to look at production systems for the southern Bering Sea (PMB Systems Engineering et al., 1983) investigated issues with resp ect to offshore drilling and production structures, topsides requirements, crude oil pipe lines, and terminals. The study was carried out in advance of lease sales of the mid 1980’s.

Areas investigated included the Navarin Basin, the St. George Basin and the North Aleutian Shelf which were at the southern limit of a nnual ice cover. Open water was described as approximately eight months of th e year. Ice keels up to 10 feet (3 m) thick could be present in the Navarin Basin. Soil conditions in the area are described as silts and fine sands further offshore and sands to soft clays in the nearshore region.
Pipeline sizes ranging from 24- inches to 36-inches (610 mm to 914 mm) were adequate to transport 100 KBPD to 300 KBPD over distances of 65, 242, and 611 nautical miles (120, 448, and 1132 km) in a maximum water depth of approximately 600 feet (185 m). It appears that the D/t ratios (38 to 41) for the pipelines were select ed on the basis of withstanding combined stresses in the sa gbend during laying and not on the basis of environmental loadings.

Pipeline construction was not co nsidered an issue and the longest line could be completed in two seasons. Construction in the southern Be ring Sea was envisioned to be similar to the North Sea in terms of weather window for installation.

Nearshore trenching would be carried out to a water depth su fficient so that waves and currents would not affect the line. No unusual obstacles were anticipated over what might be expected for a North Sea installation.
3.4.6.7 Mackenzie Delta (Dome, Esso, Gulf Canada)
In the early 1980’s, hydrocar bon discoveries in the Canad ian Beaufort Sea convinced potential offshore operators to investigate offs hore pipeline options for the Mackenzie Delta Region. Dome Petroleum, Esso Resource s Canada, and Gulf Canada Resources evaluated pipelines and inter-i sland flowlines for development scenarios at the Tarsiut, Kopanoar, and Issungnak fields (Figure 3-78). The sites were envisioned to be developed using artificial islands (production and satellit e) in 65 to 200 ft (20 to 60 m) water depth to produce oil and gas.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 149 of 339 Rev. 0 Additional details on these studies are not in the public domain.

Figure 3-78: Approximate Locations , Mackenzie Delta Development 3.4.6.8 Amauligak

In 1989, Gulf Canada Resources Ltd carried out a study to progress preliminary design, develop a construction strategy, and prepare a cost estimate for the installation of two 20- inch (508 mm) pipelines from a caisson retained inland (CRI) at the Amauligak discovery to a landfall location at North Point on Richards Island in the Canadian Beaufort Sea (INTEC, 2007).

The proposed project involved the possible installation of two 30 mile (48 km) long pipelines in a common trenc h. These pipelines would transport crude oil from the Amauligak field to an onshore pump station. The water depth was approximately 102 ft (31IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 150 of 339 Rev. 0 m) at Amauligak and gradually decr eased towards shore, with the final ten miles in shallow water.

Additional details on this study are proprietary.
3.4.6.9 East & West Amauligak Pipelines

In the late 1980’s, Gulf Canada Resources carried out studies to investigate issues related to the installation of flowli ne bundles from the proposed futu re Amauligak caisson retained island (CRI) to developments at East and We st Amauligak which w ould be tied back into Amauligak.

Additional details on thes e studies are proprietary.

3.4.7 Extended Reach Drilling Several extended reach wells have been drilled onshore Alaska, including several record breaking horizontal lengths (Alvord et al., 2007). Based on these technological developments, the potential of using ERD for wells offshore is being recognized. To maximize access to the reservoir, the Alpi ne field has been develo ped using horizontal well technology (Alvord et al., 2007).
In the early part of the decade, the Liberty prospect was proposed to be developed using a gravel island and a pipeline to shore (approximat ely 6 miles (9.7 km) long). The project did not progress in that form but the current production plan f iled by BP proposes to use extended reach drilling t hat was not considered f easible 5 or 6 years ago. BP plans to drill six extended reach wells from Endicott Island which is located approxi mately 8 miles (12.9 km) to the west of Liberty (Fischer and Schmidt, 2007).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 151 of 339 Rev. 0 3.5 Summary - Exploration & Development Options Review

Based on the preceding review , a variety of exploration and development options have been employed or considered for use in the Arctic and other cold regions. Table 3-11 summarizes these options.
Table 3-11: Summary of Arctic and Cold Regions Exploration & Development OptionsRegionUS Beaufort SeaChukchi SeaBering SeaCook InletCan. Beaufort SeaCan. High NorthCan. East CoastOffshore WestGreenlandBarents SeaKara Sea(Gulf of Ob)Pechora SeaBaltic SeaSakhalin Island

Bottom-Founded & Fixed Type Structures GBS X X X X X X X X MobileBottomFounded X X X
Barge X X Jacket/ Monopod X X X Jack-up X X X X Gravel Island X X CRI X X Ice Island X X Floating Structures FPSO/FSO X X X SPAR X X TLP X X X Semi X X X X X Drillship X X X X X X Floating Ice Pad X Export and Infrastructure Offloading Buoy/ Terminal X X X X
Export Terminal X X X X X X X X Pipeline X X X X X X X X X Subsea/ Flowlines X X X X X X X X XIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 152 of 339 Rev. 0 The assessments of options pr esented in Table 3-11 are carried out in the following section (Section 4). In addition to the options abov e, advancing technologies (ERD, WIM, and Pilot Hole to Pilot Hole HDD) are also asse ssed as they have potential Alaskan OCS applications. Several options not carried forwar d for assessment include Caisson Retained Islands, Barges, and Floating Ice Pads.
Caisson retained islands are a subset of gravel islands. They were developed in response to requirements associated with drilling in deeper water in the Canadian Beaufort during the early 1980’s; CRI’s help reduce quantities requir ed (especially with sand islands) near the water line. However, CRI’s are an expensive solution for explorati on in comparison to mobile bottom-founded units and have been genera lly disregarded for use as production structures. In shallow water, sand bag or mat retained gravel islands are generally the most economical choice for production structures.
Barges have not been carried forward because of their similarity wit h other bottom-founded structures; both GBS and m obile bottom-founded structures are assessed.
Floating ice pads, like those used for explorati on drilling in the Canad ian High Arctic, have also been excluded from asse ssment. Although these are potentially economical seasonal exploration structures, the proj ect team is unaware of a location in the OCS study areas, which would permit their use (i.e. a location wit h adequate water depths and stable, or nonmoving, floating landfast ice).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 153 of 339 Rev. 0 4.0 ASSESSMENT OF OPTIONS

4.1 Approach

The results of the assessment of potential ex ploration and production options suitable for the northernmost regions of t he Alaska OCS (the Beaufort, Bering, and Chukchi Seas) are presented in the sect ions that follow.

In general, the assessment draws on the review of Alaskan OCS and analogue experience, current state-of-practice an d state-of-the-art. Assessments also consider bathymetry, metocean, ice and geotechnical conditions (where such data is available). This environmental data is included in Appendi x A (Metocean & Ice Data) and Appendix B (Geotechnical Considerations).
Assessments of exploration and production options are pr imarily based on technical feasibility. As appropriate, the following other considerat ions are also discussed:

• Constructability;

• Capital costs;

• Environmental considerations;

• Operations;

• Maintenance and repair; and

• Abandonment and decommissioning.

4.2 OCS Scenarios

Based on the number of pot ential options identified, and the large geographic area encompassed by the Beaufort, Chu kchi, the Bering Sea, locati on scenarios were created to help focus the assessments. Sc enario identification also fa cilitated the gathering of metocean, ice and geotechnical dat a. Scenario locations (shown below in Figure 4-1) were chosen based on current and historic activity/interest (i ncluding lease sales, drilling, studies, projects, etc.) and wate r depths (given the general diffe rences in structure types with water depths).IMVPAProject No. C-0506-15Arctic Offshore Technology Assessment ofExploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 154 of 339 Rev. 0Figure 4-1: Assessment Study Areaswith 2007-2012 Proposed Final ProgramAreas (modified from MMS, 2007c)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 155 of 339 Rev. 0 4.3 Metocean/Ice Considerations

4.3.1 Beaufort and Chukchi Seas
In coastal areas of the Beauf ort and Chukchi Seas, mean mont hly temperatures during the coldest month range from approximately -13°F to -23°F (-25°C to -31°C). Temperatures as low as -49°F to -50°F (-45°C to -46°C) have been observed.
Winds in the Beaufort prevail from the east, while the Chuk chi Sea winds on average are from the northeast. Nearshore 1/100 year winds in the Beaufort are hi gher then those found for the Chukchi and range from approximately 70 knots to 98 knots (36 m/s to 50 m/s). For the Chukchi, the 1/100 year wind va lue is about 62 knots (32 m/s).
Differing wave height values between the Beaufort and the Chukchi are due to the increased fetch that can often exist in the C hukchi. In the Beaufort, nearshore wave heights can reach up to approximately 20 ft (6 m) (U S Army Corps of En gineers, 1999). Further offshore, in water depths up to approximately 100 ft (30 m), a 30 ft (9 m) maximum wave height is plausible (Kennedy et al., 1994). For t he Chukchi Sea, 1/100 year significant wave heights have been predicted at 29 ft (8.8 m) (MMS, 1986).

Ice conditions in the Chukchi an d Beaufort have some similari ties; however, the ice in the Chukchi is much more dynamic than in the B eaufort. In particular, Chukchi landfast ice is typically unpredictably unstabl e and break-outs can occur at any time (MMS, 1990; MMS, 2007b). First-year level ice thicknesses in the Beaufort and Chukchi Seas range from approximately 5.9 to 6.5 ft (180 to 200 cm), and 3.9 to 4.9 ft (120 to150 cm), respectively.
Multi-year ice thicknesses for both the Beaufor t and Chukchi Seas range from 9.8 ft (3 m) upwards. Pressure ridge keels can be thick enough to gouge the seafloor and it is believed that modern gouging could occur out to appr oximately 165 ft (50 m) water depth in some

areas.
4.3.2 Bering Sea and South In general, the Bering Sea presents a much le ss severe ice environment compared to the Beaufort or Chukchi Seas. Howe ver, wave conditions and seis mic effects are more of a concern. Norton Sound has an average winter tem perature of between 10°F and 5°F (- 12°C and -15°C). Winds prevail from the north during the winter and the 1/100 year speed can reach 110 knots (57 m/s). T he 1/100 year significant wave height lies in the range of 29 to 37 ft (8.8 to 11.3 m), depending on water depth. Multi-year ice is essentially non-existentIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 156 of 339 Rev. 0 in the Bering Sea and is only present because of “break-out” of ice at the Bering Strait. First-year ice thicknesses can reach up to 4.9 ft (150 cm).
In the Southern Bering Sea lie the Navarin, St. George’s and the No rth Aleutian Basins. Temperatures for these areas are approximat ely the same; during February the mean temperature is approximately 35°F (2°C). Wi nds generally prevail from the north or northeast during the winter m onths. 1/100 year wind speeds for each area are as follows: 112 knots (Navarin); 112 knots (St. George’s); 106 knots (N. Aleutian). Of the 3 sub-regions contained within the South Beri ng Sea, St. George’s Basin is predicted to have the worst wave conditions, with a 1/100 y ear significant wave height of 45.6 ft (13.9 m) and a period of 15 seconds. From an ice perspective, the S t. George and North Aleutian Basins do not experience ice each year, however, the Navari n Basin is encroached by ice annually. The mean maximum ice thickness for St. George’s and North Aleutian is approximately 2 ft (60 cm). Navarin Basin’s mean maximum ice thi ckness is approximately 4 ft (120 cm).
A summary of metocean and ice conditions for these areas is incl uded in Appendix A.

4.4 Geotechnical Considerations

Areas of the Beaufort and Chukchi Seas are under lain by generally strong, competent soils. Soils are mostly “very stiff (2 to 4 ksf or 100 to 200 kPa) to hard (>4 ksf or >200 kPa) cohesive soils” or “dense to very dense granular soils”. Relatively weaker soils (firm (0.5 to 1 ksf or 25 to 50 kPa) to stiff (1 to 2 ksf or 50 to 100 kPa) s ilts and clays or loose to dense granular soils, ranging in thicknes s from 10 to 43 ft (3 to 13 m), are generally confined to a zone in shallower waters (less than 65 ft or 20 m) on the inner Beaufort Shelf. Seafloor soils are highly variable, partly as a result of ice gouging. Modern ice gouging may weaken seafloor soils to depths of typically 1.6 to 9. 8 ft (0.5 to 3 m) in water depths up to 165 ft (50 m). Additional information is presented in Appendix B.

While these soils in a geotechnical sense may be considered to be strong and competent, from a structure foundation per spective, they may not prov ide ideal foundation conditions and some excavation may have to take place in cases (and perhaps the soils replaced). Where weaker soils overlay competent soils, excavation may have to take place depending on the weak layer thickness.
For the Bering Sea, silts, s ands and gravels are present. Soil properties for St. George’s Basin, the North Aleutian Basin and the Na varin Basin have been adopted from PMB Systems Engineering et al. ( 1983) and are presented in Appendix B. It should be noted thatIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 157 of 339 Rev. 0 given the limited information available to the study team, thes e are significant generalizations based on informa tion from certain areas.

4.5 Bottom-Founded Structures

This Section of the report addresses the ty pes of bottom-founded structures that would be suitable for exploration dril ling and/or production developmen t. Only the support platforms up to the top deck are addressed; topsides fac ilities are not included in estimates of costs and quantities. However, the effe cts of the topsides facilities (weight, carrying capacity, stability, etc.) have been considered and allowed for.
In terms of global size, structure cost and geom etry, there is very li ttle difference between dedicated exploration platfo rms and dedicated production platforms. In fact, an arctic mobile drilling structure is o ften more expensive than a produc tion platform due to the fact that it must cater to a range of water depths, rather than a known set-down depth. Additionally, a mobile platform needs to be able to accommodate a range of foundation conditions including very weak clays. With production platforms, foundation characteristics are known and dredging of the top weak layers is an available option, but is often not practical in the case of short-term m obilization of an explor ation structure.

4.5.1 Ice and Waves In any location where substantia l multi-year ice can impact a st ructure, the loads resulting from this interaction become the primary des ign condition and the structure shape and scantlings 1 are dictated by both local a nd global ice loading intensit ies. In such locations, wave loads are small by com parison and do not have any real effect on the design. Where there are deck cantilevers involved, wave slam dynamics must be designed for.

In the deepwater, more southerly basin areas where only first- year ice occurs, the platform design is primarily governed by wave loads. In these areas, it is still necessary to employ solid monolithic type structures as ice loads are still too locally intensive to permit jacket or “water transparent” type structures. However, t he use of a monolithic type structure in order to eliminate local ice l oad effects, bridging and vibrations, results in relatively high global wave loads (an unfortunate “Catch 22” effect). In these areas, platfo rms similar to those proposed for the Sakhalin Island region would also be applicable.

1 Scantlings are the interior fram ing members of the structure.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 158 of 339 Rev. 0 After ice loads, there are two other parameter s that have a major ef fect on the global structure size optimization: water depth and foundation conditions. Generally, multi-year ice loads increase as the water depth increases, al though not in direct pr oportion. Between 30 ft and 100 ft (10 m and 30 m) water depths, multi-year ice loads tend to increase linearly. Beyond 100 ft (30 m), multi-year ice loads continue to increase, but at a much lower rate. Thus, water depth has a twofold influence in t hat the deeper the water, the greater the horizontal design load, and also that the structure must incr ease in height and, hence, cost.
In multi-year ice areas, ther e are gravity base structure (GBS) solutions that would be considered safe and economical up to around 250 ft (75 m) water depths when foundation properties are good, and up to around 200 ft (60 m) wate r depths when foundation properties are relatively weak. There are no known bottom-founded platform design solutions for the 330 ft (100 m) plus water dept h range that could be deemed workable or proven for multi-year ice areas . In the more southern areas, where multi-year ice is absent and only first-year consolid ated ridge loadings are possib le, bottom-founded solutions out to 425 ft to 500 ft (130 m to 150 m) wa ter depths are potentially viable.

4.5.2 Foundation Conditions
The last of the three most im portant parameters is that of foundation strength and capacity. Foundation types range from “tot ally inadequate” (in which la teral relocation, excavation and/or replacement will be necessary) to “strong enough” to si mply set-down directly on the seabed without any type of preparat ion. In the strong foundation category, there is often a thin weak layer of 3.3 to 9.8 ft (1 to 3 m) of soft, reworked cohesive material that needs to be removed. A structure can then be set-down directly onto the bottom of the shallow excavated pit. Where the so ft material is only 3.3 ft (1 m) or so in thick ness, it is possible to have a skirt system that will penetrate through to the stiffer material. Where the thickness of the weaker layer is 6.6 to 9.8 ft (2 to 3 m), excavation is the best solution as skirt systems that will transfer the shear from ice loads wi ll be much more expensive than excavation.
Foundations differ widely. Even within relatively small areas it is not possible to loosely generalize with respect to foundation strength parameters. The following foundation types can be found throughout the areas of interest. The solutions suggested relate to permanent or production type structures where mult i-year ice may impact the structure.

• Strong clay foundation to within 3.3 ft (1 m) of the sea bottom with an undrained shear strength of about 3 to 4 ksf (150 to 200 kPa) or greater.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 159 of 339 Rev. 0 Solution: Design structure with 6.6 ft (2 m) deep skirts and set directly on bottom or excavate weak layer and set-down in excavation hollow.

• Strong clay within 6.6 to 9. 8 ft (2 to 3 m) of sea bottom. Solution: Excavate and set-down in bottom of excavation.

• Sandy frictional foundation or sandy frictional foundation on top of a strong clay foundation: Solution: Set-down directly on bo ttom, but be prepared to have an on-bottom contact force of appr oximately twice that required for a purely clay or cohesive foundation.

• Moderately stiff clay (with possible soft upper layer) with shear strengths in the range of 1.5 to 3.0 ksf (75 to 150 kPa. Solution: Consider the trade off between excavation and repl acement and providing a very large base area to the structure.

• Weak clay foundation with shear st rengths less than 1.5 ksf (75 kPa). Solution: Excavate to a specific depth and backfill with a granular material. The depth to which it is necessary to excavate could range between 16 and 82 ft (5 and 25 m), depending on the in-s itu clay strength and the base area chosen for the structure. Other effects that influenc e the excavation depth are water depth and the magnitude of the design ice load.
With respect to foundation capaci ty for mobile drilling struct ures, the picture is somewhat different in that the structur e will only be on location for a relatively short period of time. This allows for a basic design based on impact from first-y ear ridged ice, together with an alerts system that allows for securing the well in the event that a very large multi-year floe threatens to impact the structure. Historically, this means that temporary or exploration type structures can operate on eith er sandy cohesionless soils or cohesive soils that are stronger than about 600 psf (29 kP a) undrained shear strength. This 600 psf (29 kPa) minimum is not a given; the figure can be ei ther higher or lower depending on the ratio of the water plane diameter to the base diameter of the structur e. Generally, a value of 1 ksf (50 kPa) at the skirt tips will su ffice for exploration drilling.

4.5.3 Location Scenarios for Proposed Structures
After a discussion on various factors that infl uence the choice of st ructures, ten (10) location scenarios are assessed with respect to t he types of structures that may provide aIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 160 of 339 Rev. 0 possible solution; in addition, two (2) general structures (one with oil storage and one for mobile drilling) are as sessed. Material quantities and approx imate installed costs are tabled and discussed. Quantities and costs are also gi ven for a platform in 100 ft (30 m) water depth with 331,000 tons (300,000 t onnes) of oil storage and for a typical mobile platform.

The location scenarios together with primary design assumptions are listed below in Table 4-1 and drawings for six possible solutions are included at the end of this Section.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 161 of 339 Rev. 0 Table 4-1: Location Scenarios – Bottom-Founded Structures

OCS Area Option Number and

(Drawing Number) Water Depth, ft (m) Approximate Distance Offshore, miles (km) Governing Design Parameters

1 (1) 33 (10) 6 (10) Multi-year Ice, Weak Foundations 2 100 (30) 25 (40) Multi-year Ice, Weak Foundation 1 3 195 (60) 50 (80) Multi-year Ice, Strong Foundation Beaufort Sea

4 (2) 655 (200) 2 55 (90) First-year Ridges and Small Multi-year Floes 5 (3) 100 (30) 45 (70) Multi-year Ice, Strong Foundation Chukchi Sea 6 195 (60) 235 (380) Multi-year Ice, Weak Foundation Bering Sea Norton Sound 7 33 (10) 20 (30) First-year Ice, Sand Foundation Norton Sound 8 65 (20) 25 (40) First-year Ice / Waves, Weak Foundation 3 Navarin Basin/St.

Georges Basin 9 (4) 445 (135) 660/230 (1060/370) Waves / Strong Foundation N. Aleutian basin 10 (5) 330 (100) 30 (50) Waves / Strong Foundation 2.2 million bbls (300,000 tonnes)

Permanent Oil Storage Beaufort/Chukchi 11 (6) 100 (30) Multi-year Ice Moderate Foundation

Mobile Drilling Platform all areas 12 33 to 115 (10 to 35) First-year Ice on Weak Foundations to Some

Multi-year When on Strong Foundations

1 Since the ice loading conditions in the Chukchi Sea ar e similar to the Beaufort Sea, the foundation types chosen are reversed for the 100 ft (30 m) and 200 ft (60 m) scenarios in both areas to avoid duplication of work. In the event that material quantities are requ ired for, say a 200 ft (60 m) weak foundation in the Beaufort, refer to the 200 ft (60 m) weak foundation in the Chukchi. 2 At present, there is no known practical solution fo r a bottom-founded structure for the 655 ft (200 m) water depth in the Beaufort Sea. A semi-rigid triangular pre- stressed TLP (Semi-rigid Floater) is proposed as a solution which would permit year roun d exploration or early dev elopment drilling. However, it would not have the capacity to stay on location under the 100-year mult i-year ice loading scenario and, hence, is not suitable for permanent production in multi-year ice areas. 3 In Norton Sound in the 65 ft (20 m) water depth ar ea, ice and wave loads are of the same order of magnitude. Wave loads will dominate the design from a poi nt of view of required weight on bottom and ice loads will dominate from the aspe ct of local strength design.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 162 of 339 Rev. 0 4.5.4 Technical Feasib ility of Structures
4.5.4.1 Ice Loads

In the Beaufort and Chukchi Se a areas, the 100-year design ice loading conditio n arises as a result of an interaction with th ick multi-year ice. The load re sulting from this interaction must be resisted with a factor of safety of about 1.5 with respect to the foundation (sliding and inclined bearing failure). Additionally, the stru cture should have a factor of safety of 1.0 against significant lateral move ment or tilting under a 1000- year scenario. This load and resistance philosophy is not specif ied rigidly in offshore codes, but it is one that is generally accepted throughout ice-dominated areas. In t he event that large quantities of oil are stored, then survivability or non-spillage may have to be dem onstrated under a 10,000-year loading condition.

Since the outer shell of all structures must be designed to resist high local loads and since these local loads from first-year and multi-year ice are not terribly dissimilar (even though there could be a factor of f our between the global load scenario s), the quantities of steel in a temporary drilling st ructure will not be much differ ent than those in a permanent production structure. In fact, as mentioned earlier, temporar y mobile structures may be more expensive due to having to cater to a set-down range rat her than a specified depth.
In the case of exploration dril ling, the historical approach is to establish foundation stability based on a deterministic first-year ice loadi ng scenario and then to establish an ”alerts system” which would secure the well in the event that a large multi-year floe threatened the structure. This system works relatively well in shallower water depths where it can be almost guaranteed that large fl oes cannot impact the structure after freeze-up. In waters deeper than 65 to 100 ft (20 to 30 m), this approach becomes more problematic and sitespecific. However, the probability of greater loads in deeper waters is often offset by a likely (but not guaranteed) increase in foundation strength that is typi cally observed as one goes farther offshore. Again, t hese arguments only apply to te mporary “one well” drilling structures that have to sit on re latively weak clay foundations.

Prior to 1980, there was no r eal understanding of the global ice loads that could be imparted to a bottom-founded structure in the B eaufort Sea or the Chukchi Sea. The only methodology used was to establish the crushing strength (pressure) of small samples of pristine ice in the laboratory and then extrapolat e directly to large contact areas. Most scientists recognized that, due to the br ittleness of ice, linear extrapolation was conservative, but they had no way of knowing by how much. In 1980, in a water depth ofIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 163 of 339 Rev. 0 around 100 to 130 ft (30 to 40 m), a 100-year ice load had an average consensus value of about 3,300,000 kips (1,500,000 metr ic tonnes or 15,000 MN).
Since that time, and particularly as a result of the Hans Island ex periments in the mid 1980’s, advances in the confidence of load estimation have been made. The evolution of ice load over time and with experience was pr esented in Figure 2-1. Today, ice scientists use probabilistic methods to determine 100-year (10 -2 ), 1000-year (10 -3 ) and 10,000-year (10 -4 ) loadings. In general, because of the slope of the ice load probab ility distribution curve, a factor of safety of 1.5 with respect to a 100-year load becom es the main criterion as it is more severe than survivability under the 1000-year load (and probably more severe than most 10,000-year scenarios). Such is not the case on the Canadia n east coast, where icebergs are the dominant loading condition. In these areas, the 10 -4 year loading can be up to 5 (five) times the 10 -2 event.

When probabilistic loads are assessed, all the re levant factors (ice st rength, floe size, etc.) with their individual probability distributions are fed into a Monte Carlo simulation. An important factor in this exerci se is the waterline diameter of the structure being impacted. Another factor that is consider ed important by some is whet her or not the structure has a sloping face. It is the authors’ opinion and that of others (some, but not all) that the introduction of a slope will not reduce the loads from a large mu lti-year ice impact. This is because large amounts of ice c an build up and crushing is then transferred to a pseudo vertical ice wall some distance back from the structure. For fi rst-year and relatively thin multi-year ice, a slope shoul d definitely reduce ice loads, but these scenarios do not govern the design. It is the authors’ opinion that any proposal to signifi cantly reduce the global load from a multi-year ice interacti on as a result of interacting wi th sloping sides (as opposed to vertical sides) be viewed with skepticism.

The waterline diameters of bottom-founded st ructures suitable for exploration and development can be optimized to around 250 to 300 ft (75 to 90 m). Global ice loads are affected by the magnitude of the water line diameter, but not nece ssarily in a directly linear fashion. Also, water depth affects global mult i-year loads. Betwe en 30 and 100 ft (10 and 30 m) water depth, loads are approximately lin early affected (thickness effect) and after 100 ft (30 m) in a more modest manner (interaction frequency effect).

In the Beaufort and Chukchi Sea areas, where multi-year ice can impact structures, Table 4-2 gives approximate load rang es that modern probabilistic methods would predict. With respect to the Chukchi Sea, load ranges are given with respect to the northernmost areas.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 164 of 339 Rev. 0 In southern areas, close to the Bering Strai t, loads can be expected to be approximately 30% less.

Table 4-2: Approximate Ice Load Ranges, Beaufort and Chukchi Seas

Water Depth, ft (m) Approximate Value of 100-Year Design Ice Loading. Factor of Safety of 1.5 Required in Addition when Checking Foundation, kips (MN) 33 (10) 65,000 to 115,000 (300 to 500) 65 (20) 135,000 to 200,000 (600 to 900) 100 (30) 200,000 to 295,000 (900 to 1300) 130 (40) 225,000 to 315,000 (1000 to 1400) 165 (50) 245,000 to 335,000 (1100 to 1500) 195 (60) 270,000 to 360,000 (1200 to 1600)

In the event that a temporar y deployment for an exploration structure is being considered, arguments as outlined above can be rationa lly developed such that the foundation only needs to resist first-year ice loading of the order of 45,000 to 90,000 kips (200 to 400 MN).

Local ice loading pressures are relatively independent of global desig n loads and they do not affect the overall external dimensions of t he structure. Depending on the degree of conservatism chosen, these local ice-loading pressures can greatly affect the outer shell quantity requirements. Additional ly, the outer shell design me thodology is very important and whether or not it is a def ormation-based design, as opposed to a stress-based design, can have an enormous effect. As an example, a typical local loadin g pressure could be about 435 psi (3 MPa) over approximately a 16 ft by 16 ft (5 m by 5 m) area (270 ft 2 or 25

m 2 ), with smaller areas havi ng greater intensities.

4.5.4.2 Foundations

The effect of foundation str ength has been discussed earlier and it must be restated that a strong foundation is a gr eat asset to any bottom-founded devel opment. How the structure is affected can be illustrated by the following brief example:

• Ice load: 225,000 kips (1000 MN);

• Water Depth: 155 ft (35 m) – a shallo w example is presented such that inclined bearing failure will not be an issue;IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 165 of 339 Rev. 0 • 13 ft (4 m) of cohesi onless sandy material ( φ =32 degrees) overlaying clay with an undrained shear strength of 3 ksf (150 kPa); and,

• Factor of safety against sliding: 1.5.
Because the top layer is frictional, resistance is a function of weight on bottom alone for this layer. The weight on bottom required is (Ice Load*FS)/(Tan φ ), or about 275,000 tons (240,000 metric tonnes). This is a significant force and, depending on the structure design, it is difficult to achieve wit hout solid ballast. Thus, even th ough cohesionless foundations are seen to be strong and desirable, they are not necessarily as good from an economic point of view as is a strong cl ay foundation. In this example, a less costly structure can be utilized if the 3 ksf (150 kPa) material came right to the surface, as approximately 165,000 tons (150,000 tonnes) only would be nec essary as an on bottom weight.
In this example, as long as the on bottom we ight exceeds 275,000 tons (240,000 tonnes), then the failure plane is lowered to the 3 ksf (150 kPa) interface. Now the criterion becomes one of base area contact and the base area requir ed is given by (Ice Load*FS)/(Soil Shear Strength), or about 110,000 ft 2 (10,000 m 2 ). If the structure base is a square chamfered shape or octagonal, then this is equivalent to a base diameter of about 360 ft (110 m).

There are, of course, various add itional checks that need to be verified (3D effects, inclined bearing, skirt effectiveness), but the basic requirements of 265,000 tons (240,000 tonnes) weight on bottom plus a base contact area of 110,000 ft 2 (10,000 m 2 ) need to be met for this example. A full 3D analysis could, howe ver, lessen the base area requirement by a small amount. But there are ot her reasons why having a base width much less than 300 ft (90 m) can be disadvantageous (see Section below on vibrations).
There is not a lot of variation with respect to in-situ sandy granul ar foundation types and rudimentary checks need to be made with respect to possible liquefaction, but this has never proved to be a problem. However, with res pect to the use of sand backfills, this is a different matter. Thus, stability can be achiev ed on all cohesionless foundations simply by means of weight alone.
However, in the event of a cohesive clay foundation, the structur e base area requirement grows proportionally to the ic e load and inversely as to t he shear strength of the clay foundation.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 166 of 339 Rev. 0 There are many other reasons why a base diameter in the 330 to 400 ft (100 to 120 m) range is considered desirable and, thus, a clay shear strength of about 3 ksf (150 kPa) fits quite well and does not become an overriding des ign criterion. If, however, the in-situ shear strength is only about 1 ksf (50 kPa) and is relatively deep, then the only solution is to excavate and backfill with a sandy material or increase the base area size. In the above example, the base area would need to go to 323,000 ft 2 (30,000 m 2 ) and the base diameter to approximately 625 ft (190 m). This diamet er would need to be achieved by an inverted cantilever design, but would nevertheless be extr emely difficult and costly to build. The only real practical solution in this case is to excavate down to 50 ft (15 m) or so (to be determined) and then backfill with sand. Then a structure with a base of about 360 ft (110 m) could be safely deployed. In the event that dredging an d backfilling are seen to be undesirable from an envir onmental or political point of view, then a weak foundation may well become an economic showstopper for a gravity base structure

.
4.5.4.3 Steel vs. Concrete

Conventional wisdom in the 1980 ’s was that concrete arct ic bottom-founded structures had the advantage over steel. At that time, loca l ice loads were thought to be phenomenally high, which favored thick-wall concrete as the c onstruction material of choice. As well, steel plastic catenary mechanisms were not well under stood, and this led to thicker steel “ice walls” with corresponding increa ses in steel weight and cost. Steel was also thought to have insufficient notch toughness for the ar ctic environment. Experience has proven, however, that steel is the pref erred construction material of choice for high arctic and subarctic GBS concepts.

There are many additional implicat ions with respect to the choice of steel versus concrete. For example, deepwater concrete concepts in the 330 to 460 ft (100 to 140 m) water depth range often attract greater wave loads due to their cylindrical shape and, thus, require greater weight on bottom (the wide cylindrical shape is required for draft and stability purposes). This greater bearing stress on the bottom will often be too severe for even moderately stiff foundations and, as a result, a greater base wi dth is subsequently required than that of a “lighter” steel GBS. It is the aut hors’ experience that, in arctic or sub-arctic conditions, a concrete GBS can ultimately be made to satisfactorily perform from a technical point of view. However, experience has demonstrated (at least to the authors) that in virtually all cases wher e ice is involved, concrete solu tions end up being close to two or more times the cost of steel solutions.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 167 of 339 Rev. 0 These cost factors of two or more are oft en not readily apparent and at first glance price differentials may not be obvious. For inst ance, a concrete structure can be designed relatively cheaply if it does not have to carry a full complement of topsides into the Arctic with load-out and hook-up bei ng performed after set-down (this can also lead to decommissioning issues). Steel solutions can ca rry up to 33,070 tons (30,000 tonnes) or more topsides into the Arctic due to their inherent ability to be more stable and draft insensitive.

Therefore, in the shallower Beaufort and Chukchi S ea areas with water depths in the 65 to 130 ft (20 to 40 m) range, the co mpounded problems of draft and t opsides floating stability requirements make concrete solutions very costly , as water line and flotation issues tend to govern the design.

There are additional subtleties with respect to t he steel versus concrete issue. On the east coast of Canada, it is well recognized that the choice of concrete for Hibernia was essentially politically based. Again, this is pe rfectly in order as long as all parties recognize the cost implications. However, one of the more subtle aspects of the steel/concrete arctic suitability issue is that of the existence (or nonexistence) of proponents of either material. Essentially, the major offshore concrete contractors endeavor (as they should) to promote the good name of concrete (and, again, the only thing that the authors will cite against concrete is that the final cost to do a co mparable job to steel in the Arctic will be significantly greater than that of steel). With respect to the ex istence of lobbyists for steel arctic construction, the shipyards of the world do not partake in promot ing their capabilities. In short, if a company requires a cost for a steel platform they must take a specific design to a shipyard and seek answers. While they c an construct the structure, shipyards do not have the ability to design them. Any type of design must be carried out by competent consultants. On the other hand, concrete c ontractors will often readily provide design, construction and cost estimating services.

4.5.4.4 Wave Loads

Wave loads in certain areas can become a prim ary design considerati on, although for the Beaufort and Chukchi Sea areas it is generally ice loads that govern stability. There are three subsets, however, that need checking. T he first is if a low cantilever overhang is included in the deck design, since wave slam can occur up to 50 ft (15 m) above the still water level. The second is the loss of on botto m contact force as the wave amplifies due to reflection at the front face of the st ructure. The third is shallow water.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 168 of 339 Rev. 0 As the water depth gets shallow, waves start to break when their height is about 80% of the water depth. Thus, in 33 ft (10 m) of water, t he design wave becomes a 26 ft (8 m) breaking wave. Such a wave can exert c onsiderably more force on a monolithic object than on its deep-water counterpart. Since ice loads are fair ly low in 33 ft (10 m) water depths, it is possible that equivalence or “c risscrossing” of dominant load e ffects will occur around this water depth. Also, buoyancy effects can be relatively more severe.
Once moderately substantial ice is present, such as rafted ice of 1 to 2 ft (30 to 60 cm) nominal thickness, it is likely that for this and other reasons (vibrations, fatigue) the most economic structure is a solid mo nolithic GBS. These GBS struct ures have dimensions that are a substantial fraction of the impacting wavelength and, as a result, the dominant wave loads are inertial rather than drag based. Generally, inertial loads are proportional to the displacement or volume of t he structure, a diameter squar ed function, while drag is proportional to diameter only. Furthermore, inertial loads are proportional to the maximum acceleration of the individual wave particle and maximum inertial loads t end to occur at still water, whereas maximum drag loads occur w hen the crest passes the structure. Since wave particle accelerations are greatest close to the water line and least at the seabed, it makes great sense to try and give a “pyramid” or conical shape to the structure in order to reduce inertial wave loads if th e structure is to be deployed in deepwater, e.g., 200 to 445 ft (60 to 135 m), particularly if the accompanying ice l oads are low. In shallower water where ice loads are high, there is no real benefit. However, in the US and Chukchi Sea areas, it makes sense (for other reasons) to start stepping the structure when the water depth reaches around the 165 ft (50 m) ma rk, if constructed of steel.

Accurate evaluation of wave loads involves the use of sophistica ted computer programs that take into account wave diffraction effect s on large structures of arbitrary shape. The final load is a function of wave height, wa ter depth, wavelength, wave period and, most importantly, the specific shape of the structure. This is a time consuming and iterative effort. However, it has been carried out with respect to several structures and extrapolations have been estima ted based on certain empirical rules. The loads shown in Table 4-3 below are approxim ate and are based on “pyramidal ” or stepped structures being used in the deeper areas of interest.
Changing the shape from cylindrical to conica l can have load reduction effects of 50% or more (this effect is graphically illustrated bel ow in Figure 4-2). Such conical shapes are easy to achieve with steel but costly for concre te, and since the vertical centre of gravity (VCG) of the steel conical shape can be lowere d by the use of solid ballast, very largeIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 169 of 339 Rev. 0 amounts of topsides can be carried due to its rela tively high hydrostatic stability. In the case of concrete, it is hard to lower the VCG without a very severe impact on the final draft and, hence, concrete solutions always tend to hav e issues relating to draft versus maximum topsides stability.
The following Table 4-3 illustrates approximate wave loading magnitudes in the location scenarios of interest. A very la rge variable is the shape or displacement of the structure itself. The maximum deep-water height input is assumed to be about 90 ft (28 m) in the southern basin areas and about 40 ft (12 m) in the Beaufort and Chukchi Sea areas. Structural shapes and displace ments are based on t he authors’ experience of what is appropriate.

Table 4-3: Table of Wave and Ice Loads Used in Materials and Cost Estimation

OCS Area Water Depth, ft (m) Approximate Distance Offshore, miles (km) Approximate Magnitude of 100- Year Wave Loading Base Shear on

Typical Steel GBS Structure with Approximate Median 100-Year Ice Load in Brackets for Comparison, kips [MN] 33 (10) 6 (10) 67,000 (90,000) [300 (400) 1 ] 100 (30) 25 (40) 90,000 ( 247,000) [400 (1100)] Beaufort Sea 200 (60) 50 (80) 135,000 (315,000) [600 (1400)] 100 (30) 45 (70) 90,000 ( 247,000) [400 (1100)] Chukchi Sea 200 (60) 235 (380) 135,000 (315,000) [600 (1400)]

Bering Sea Norton Sound 33 (10) 20 (30) 67,000 (67,000) [300 (300)] Norton Sound 65 (20) 25 (40) 90,000 (67,000) [400 (300)] Navarin Basin/St George 445 (135) 660/230 (1060/370) 281,000 (45,000) [1250 (200)]
North Aleutian Basin 330 (100) 30 (50) 225,000 (45,000) [1000 (200)]

1 While wave height is limited due to water depth the combination of storm surge and breaking waves can result in high loadsIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 170 of 339 Rev. 0 Figure 4-2: Wave Load Comparison of Hibernia-type GBS vs. Stepped-style GBS (Fitzpatrick and Kennedy, 1997)
4.5.4.5 Gravity & F oundation Reaction Loads

The foundation reacts to the structure and must have sufficient contact area to provide a factor of safety against sliding of 1.5 with respect to the 100-year (10 -2 ) design ice load and/or about 1.0 with respect to the 10 -3 to 10 -4 year load. Foundati on reaction loads for a GBS are often overlooked, triv ialized or their significance ignored. Reaction pressures possible on the bottom of a GBS are so varied in their intensity and location throughout the base area that it is useful to view the reaction pressures as “l oads” rather than “supports”. As detailed in Fitzpatrick (1994), the recomm ended approach is to design the base from a pressure-area curve, similar to the ice load envelope curves that are traditionally used to establish the outer she ll strength requirements.

Experience has shown that, even when soils ar e soft, very high local pressures can build up locally against the base of an offshore structure. These pre ssures are of the same order of magnitude as ice load pressu res, which means that the structure base needs to be “as strong” as the vertical sides. This is an im portant consideration for GBS concepts in the areas of interest and makes such concepts sensitive to site-specific geotechnics. Once again, foundation conditions can be a significant factor in the technical and economic feasibility of GBS platforms.

For an exploration or mobile stru cture, skirt systems that cater to varying soil conditions are virtually mandatory. In some instances in mobile structures, where the skirts have beenIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 171 of 339 Rev. 0 specifically designed for a range of soil conditions, complete penetration may not be achievable where soils are toug h. Generally, skirts on mobile arctic structures need to be about 6.6 ft (2 m) high to cater to varying c onditions. For permanent structures, the skirts can be designed to site-specific conditions. Ho wever, full penetration must be assured as differential settlements over the years could be a problem. Skirts are necessary in order to penetrate to undisturbed clay and, in the case of sandy foundat ions, to ensure sand particle to sand particle frictional resistance. Genera lly though, skirts for pe rmanent structures will be thin to ensure complete penetration and will on ly need to be about 3.3 ft (1 m) or so in height.
4.5.4.6 Vibratory Loads
GBS structures are very large-based massive structures. The resulting presence of significant radiation damping available from the foundation – provi ded the base is greater than 330 ft (100 m) – plus the lar ge mass, minimizes vibrational effects to a level of around 5 to 10% of gravity with a to tal system frequency on the order of 1 Hz. Potential vibratory effects from, for example, cont inuous first-year light ice are therefore of minor concern.
Radiation damping plays a signific ant role in eliminating the dy namic amplification of forced vibrational effects from ice. It is a comp licated phenomenon, but its effects grow in accordance with a power law function of the bas e diameter of the st ructure. With a base diameter in the region of 165 to 200 ft (50 to 60 m), serious vibrations from even light firstyear ice should be anticipated. With base di ameters in the region of 330 ft (100 m), experience to date shows that sufficient damping is available such that dynamics will not be amplified to a level that would cause concern fo r stability or operations. While the platform is relatively unaffected, the topsides should be designed for seismic events or about 0.2 g due to vibration, unless it can be rigorously dem onstrated that lesser levels are permissible.

4.5.4.7 Seismic Loads
The general Chukchi and Beaufor t Sea regions may be categorized as those of relatively low seismicity. The Camden Bay area could be described as low to moderate. The base acceleration levels are so low so as not to be a design condition for the GBS structure itself. However, in most areas (and also because of low level ice vibrat ions) all topsides will require some lateral stiffening requirements.

However, towards the southern areas of interest close to the Aleutians, seismic activity will be a major design concern. Even though structur es are to be designed for the very highIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 172 of 339 Rev. 0 seismic loads in these locations, these loads will not significantly affect the overall size or cost of the basic platform, but rather will requi re greater attention to foundation capacity. Additionally, some dynamic amplif ication will result in greater topsides st iffening or isolation requirements.

With a steel GBS, the VCG in deepwater seismic areas is ve ry low (due to the enormous amount of concrete ballast required) and dynam ic amplification of base shear through to the topsides is minimized. With a concrete GBS, the VCG is higher and greater vibratory effects (rocking) may well be sensed at the t opsides location. There are cut-off points with respect to allowable vibrational levels and, in some instances, topsides isolation mechanisms may be deemed necessary. However, th is last point is a relatively subtle technical difference between the two materials.

4.5.4.8 Fatigue Loading, Brittle Fr acture, & Temperature Effects
The day-to-day loads from ice or waves induce only very low le vels of stress in these types of GBS structures. When the level of load gets moderately high, there are only a very small number of cycles. Experience with arctic structur es to date indicates that neither fatigue nor brittle fractures are governing design factors. Brittle fracture is, of course, a different phenomenon than fatigue, but because of the relative thinness of steel required and the great advances in cooling technology, the duc tility of modern steels can be guaranteed at temperatures down to -58°F (-50°C) without any great premium in cost.
The effects of temperature are considered secondary and are not driving factors in determining the size and geometry of steel struct ures. Differential temper atures of 100°F to 125°F (40°C to 50°C) across a structure can be easily ha ndled by steel. However, differential temperature stresse s, in combination with balla sting and differential settlement effects, can be a more serious concern for the long-term se rviceability of concrete, e.g., liquids tightness and crack control. For concre te, these effects can become a significant design condition and solutions may require very high levels of mult i-axial pre-stressing steel. The effects are more pronounced in relati vely shallow waters, 33 to 100 ft (10 to 30 m) where high shear stresses can build up in t he concrete due to differential settlements.
4.5.4.9 Oil Storage Effects
Depending on the water depth and the foundation type, a cert ain amount of potential oil storage capacity can be provided relatively c heaply. All oil storage c oncepts to date in the Arctic are of the oil/water type. Oil/air concepts become eno rmously expensive, are viewedIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 173 of 339 Rev. 0 as more dangerous and, to dat e, a concept that no one has c onsidered seriously. A certain amount of oil storage is generally considered to be r easonably “free” due to the other design and functional requirements of the structure.

In the event that the foundation is granular and great weight on bottom is required, then this initial amount of “free” storage can be higher than if the platform sits on a clay foundation, where much less weight is required on bottom.

This initial ”free” storage amount, therefor e, depends on the water depth, the foundation type, the structure volume and w hether or not solid ballast as opposed to water is used in the free space. This initial “f ree amount” is not entirely free, though, as double hulls must be provided. It would be reasonable to allow 5% of the basic structure cost as an addition to cater for the additional bulkheads. Again, this initial ”free” storage varies from concept to concept and can have values ranging from a few hundred thous and bbls up to 1.5 million bbls or more.
After this initial amount of relatively free storage, any additional ba rrels must be provided for by specifically increasing the volume of t he platform. This increase in volume requires a certain amount of steel, about 55 to 66 lb /bbl (25 to 30 kg/bbl) and this approximately translates to $125-$150/bbl capital cost. Not a tremendous amount if the extra volume is only about 100,000 bbls ($12.5 MM to $15 MM), but a considerable figure if one requires extra storage of about 1, 000,000 bbls which would cost around $125 MM to $150 MM extra.
Only one of the examples for which material quantities and costs are estimated in this report caters to oil storage; Option 11, Dra wing No. 6 which contains storage for 331,000 tons (300,000 tonnes) or 2,200, 000 million bbls of oil.
4.5.4.10 Platform Concepts
Platform concepts as the result of this study are reflected in Table 4-4, Table 4-5, and Table 4-6, and Drawings 1 to 6 provided in Figure 4-3 through Figure 4-8, respectively.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 174 of 339 Rev. 0 Table 4-4: Platform Particulars Options 1 to 4

Property/Site Beaufort Sea Drawing No 1 Beaufort Sea Beaufort Sea Temporary Drilling Only, in

Beaufort and Chukchi Seas Drawing No 2 Water depth, ft (m) 33 (10) 100 (30) 200 (60) 655 (200) plus Median Ice Load, kips (MN) 90,000 (400) 250,000 (1100) 315,000 (1400) 150 to 200
Wave load, kips (MN) 65,000 (300) 90,000 (400) 135,000 (600) Varies Foundation Conditions Weak Weak Strong Varies Base Diameter, ft (m) and [Base Area, ft 2 (m 2 )] 360 (110) [130,000 (12,100)] 427 (130) [151,000 (14,000)] 377 (115) [118,000 (11,000)] n/a
Overall Height from Tip of Skirts to Top of Main Deck, ft (m) 82 (25) 151 (46) 259 (79) n/a
Quantity of Steel Required (EH36 OLAC), tons (tonnes) 25,000 (23,000) 55,000 (50,000) 77,000 (70,000) 83,000 (75,000) Weight on Bottom. tons (tonnes) 121,000 (110,000) 303,000 (275,000) 165,000 (150,000) n/a

Excavation and [Backfill Quantities], ft 3 (m 3 ) 7,000,000 (200,000) [7,000,000 (200,000)] 53,000,000 (1,500,000) [58,000,000 (1,650,000)] 1,400,000 (40,000) 2 m soft n/a

Ballast Concrete Required SG 2.3, tons (tonnes) 41,000 (37,000) 66,000 (60,000) 165,000 (150,000) 132,000 (120,000) Steel Scrap Displacement Including 30,000 tonnes Topsides, tons (tonnes) 99,000 (90,000) 154,000 (140,000) 275,000 (250,000) n/a
Minimum Draft Including Topsides and Solid Ballast, ft (m) 30 (9) 65 (20) 100 (30) n/aIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 175 of 339 Rev. 0 Table 4-5: Platform Particulars Options 5 to 8

Property/Site Chukchi Sea Drawing No 3 Chukchi Sea Norton Sound Norton Sound Water Depth, ft (m) 100 (30) 200 (60) 33 (10) 65 (20) Median Ice Load, kips (MN) 250,000 (1100) 315,000 (1400) 65,000 (300) 65,000 (300)
Wave Load, kips (MN) 65,000 (400) 135,000 (600) 65,000 (300) 90,000 (400) Foundation Conditions Strong Weak Strong Sand Weak Base Diameter, ft (m)

and [Base Area, ft 2 (m 2 )] 360 (110) [110,000 (10,000)] 375 (115) [120,000 (11,000)] 360 (100) [110,000 (10,000)] Square Base 395 (120) [150,000 (14,000)] Overall Height from Tip of Skirts to Top of Main Deck, ft (m) 165 (50) 253 (77) 82 (25) 118 (36)
Quantity of Steel Required (EH36 OLAC), tons (tonnes) 44,000 (40,000) 77,000 (70,000) 22,000 (20,000) 44,000 (40,000) Weight on Bottom, tons (tonnes) 110,000 (100,000) 330,000 (300,000) 110,000 (100,000) 165,000 (150,000)
Excavation and [Backfill Quantities], ft 3 (m 3 ) 1,800,00 (50,000) 61,800,000 (1,750,000) [65,300,000 (1,850,000)] None 35,300,000 (1,000,000) [38,800,000 (1,100,000)] Ballast Concrete Required SG 2.3. tons (tonnes) 50,000 (45,000) 165,000 (150,000) 38,500 (35,000) 44,000 (40,000) Displacement Including 30,000 tonnes Topsides, tons (tonnes) 127,000 (115,000) 275,000 (250,000) 94,000 (85,000) 121,000 (110,000)

Minimum Draft Including Topsides and Solid Ballast, ft (m) 65 (20) 100 (30) 26 (8) 56 (17)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 176 of 339 Rev. 0 Table 4-6: Platform Particulars Options 9 to 12

Property/Site Navarin Basin Drawing No 4 North Aleutian

Basin Drawing No 5 Typical Platform with 300,000 tonnes of

Storage Drawing No 6 Typical Mobile Drilling Platform

Water Depth, ft (m) 445 (135) 330 (100) 100 (30) 33 to 115 (10 to 35) Median Ice Load, kips (MN) 45,000 (200) 45,000 (200) 295,000 (1300) Varies Wave Load, kips (MN) 280,000 (1250) 225,000 (1000) 100,000 (450) Varies

Foundation Conditions Strong Sand on Strong Clay Strong Sand With/Without Strong Clay Moderate See Discussion, Weak to Very Strong Base Diameter, ft (m)

and [Base Area, ft 2 (m 2 )] 475 (145) [185,000 (17,000)] 410 (125) [140,000 (13,000)] 330 (100) [110,000 (10,000)] Square Shape 425 (130) [150,000 (14,000)] Overall Height from Tip of Skirts to Top of Main Deck, ft (m) 560 (170) 445 (135) 245 (75) 185 (56)
Quantity of Steel Required (EH36 OLAC), tons (tonnes) 176,000 (160,000) 88,000 (80,000) 94,000 (85,000) 61,000 (55,000) Weight on Bottom, tons (tonnes) 496,000 (450,000) 386,000 (350,000) 303,000 (275,000) Varies

Excavation and [Backfill Quantities], ft 3 (m 3 ) None None 18,000,000 (500,000) [18,000,000 (500,000)] None

Ballast Concrete Required SG 2.3, tons (tonnes) 507,000 (460,000) 507,000 (460,000) None 11,000 (10,000) Displacement Including 30,000 tonnes Topsides, tons (tonnes) 717,000 (650,000) 628,000 (570,000) 127,000 (115,000) 83,000 (75,000 [Only 10,000t Topsides]) Minimum Draft Including Topsides and Solid Ballast, ft (m) 165 (50) 245 (75) 40 (12) 26 (8)IMVPAProject No. C-0506-15Arctic Offshore Technology Assessmentof Exploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 177 of 339 Rev. 0Figure 4-3: Drawing No.1, Option No.1 – Platform and Foundation for 33ft (10 m) of WaterIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 178 of 339 Rev. 0

Figure 4-4: Drawing No.2, Option No.4 – 660 ft (200 m) Plus Mobile Exploration ConceptIMVPAProject No. C-0506-15Arctic Offshore Technology Assessmentof Exploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 179 of 339 Rev. 0Figure 4-5: Drawing No.3, Option No.5 – Platform and Foundation for 100ft (30 m) of WaterIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 180 of 339 Rev. 0 Figure 4-6: Drawing No.4, Option No.9 – 445 ft (135 m) Stepped Steel StructureIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 181 of 339 Rev. 0 Figure 4-7: Drawing No.5, Option No. 10 – 330 ft (100 m) Stepped Steel StructureIMVPAProject No. C-0506-15Arctic Offshore Technology Assessmentof Exploration and Production Options forCold Regions of the USOuter Continental Shelf01/31/2008 Page 182 of 339 Rev. 0Figure 4-8: Drawing No.6, Option No.11 – 100 ft (30 m) Storage Hull Transverse Section and Design ParticularsIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 183 of 339 Rev. 0 4.5.5 Constructability In the early-1990’s, a Canadian firm (C ANMAR ) set the scope for, funded, and executed a major full-scale and partial-scale testing program for steel structures for use in ice-infested waters. The testing program was designed to quantify the degree of cons ervatism inherent in the state-of-the-art at that time and to demonstrate that si gnificant savings in steel weight (and cost) were possible.
Four basic types of tests on low temperature duct ile steel were conducted. The first two were plate and stiffener tests wit h hydrostatic pressure loading and the results were directly applicable to the outside wa ll and base of an arctic steel gravity structur e. The last two tests were in-plane loading tests, and the results were used to improve the design performance of internal bulkheads (the me mbers that transfer global lo ads through to the foundation). The testing program was carried out in Ed monton and demonstrated that steel weight savings of 25% to 30% were possible. When combined with increased ease of construction, total cost savings exceeded 30% compared to the best existing state-of-theart at that time.

A technical paper, State-of-the-art of Bottom-Foun ded Arctic Steel Structures (Fitzpatrick, 1994), discusses the underlying engineering prin ciples and the verification of these principles by the testing pr ogram. Additionally, CSA S473, the Canadian code for offshore steel structures in arctic regions, endorses the methodologies proven in that particular program.
The examples and steel quantities in this report incorporate the weight savings implied by the use of these latest design methodologies. The structures pr esented in this report could be constructed by a number of shipyards around the world.

Installation of a GBS structur e in the Alaskan OCS will not be dissimilar to installations on Sakhalin, on the Grand Banks and in the Nort h Sea. Weather and s easonal operational effects such as the presence of sea ice and freezing spray must naturally be taken into account, but structure draft, foundation preparation and decommissioning are considered to be more important issues.
Towing experience suggests that an average GBS pl atform can be towed at a speed of 3 to 4 knots. For a steel GBS, set-down at the site would be very rapid, taking only a few hours depending on the accuracy r equired. If the allow able location tolerance is around 16 to 33 ft (5 to 10 m), this could be achieved by floati ng vessels only. In the event that set-downIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 184 of 339 Rev. 0 accuracy of about 3.3 ft (1 m) is required, an anchored spread and a day or more of calm weather will be required. Ther e should be no reason for extreme set-down accuracy unless the unit is required to sit precisely over pre-installed seabed syst ems, e.g., wellhead templates, pipeli ne connection, etc.

4.5.5.1 Foundation Issues
Relief in the seafloor topography resulting from ice gouging coul d affect the final placement location of a bottom-founded stru cture, although this should be evident from site surveys early in the project. Large gouges in the seafloor may require attention, as the bottom of the GBS structure needs to “bridge” t hese gaps. However, a small lateral transfer is all that is necessary.
As discussed in Section 4.5.4, of greater concern for bottom-f ounded structures is the soil strength profile at the installation site and the possible need fo r foundation improvement. Sites with soft/weaker upper layers may require excavation of these layers to expose the stronger soils below. This will ei ther add to the overall heigh t of the platform or require backfilling of the excavation wit h more competent material.

4.5.5.2 Weather Window
During installation, there will be some sea st ate limitations, but these are fairly well understood and are not considered showstoppers. Because the structur es proposed have short skirt systems and are not relia nt on foundation grouti ng, basically all t hat is required is to get the structure on locati on within +/-33 ft (+/-10 m) and t hen flood quickly. Normally, it takes up to 24 hours to get the struct ure located and flooding started.

With the structures proposed in this study, it is assumed that there will be a 33 ft (10 m) lateral tolerance on the set-down area. Then, with a reasonable spread of tugs and cables, set-down should be achievable in approximately a sea state of 10 to 13 ft (3 to 4 m) or more. Wind can be a potential issue; a 20 knot wind is not a problem but if winds are in the 40 knot range, installation becomes more difficult.

4.5.6 Capital Costs
In 1997, a very thorough cost in vestigation was carried out wi th respect to a stepped steel GBS for 310 ft (95 m) of water on Canada’s east coast. These 1997 costs are included in brackets alongside today’s estimated costs for the suggested Nort h Aleutian Basin GBSIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 185 of 339 Rev. 0 solution, as it is similar in nature. It c an be seen that the tabul arized costs have been estimated as approximately twice the 1997 costs . There is no real justification for the large cost increases quoted ot her than that shipyards today ar e very busy with highly profitable facilities work and that they choose to ignore lower profitability work.

It is the author’s opinion that a steel GBS could be built for much less than that indicated in the Table 4-7 through Table 4-9 and that ship yards would still make a significant profit.

An important way to significantly reduce the t abularized costs is to allow the shipyard to engineer and fabricat e most of the facilities. As a resu lt, one will get a much better price for the basic GBS. The costs shown assume that one has gone to bid with at least three far eastern yards (China excluded) on an open mark et and that nothing el se other than the basic platform is being contracted. Chines e yards could be cheaper, but they are very unpredictable in their responses.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 186 of 339 Rev. 0 Table 4-7: Estimated 2007 Installed Platform Co sts, in Millions of USD, Exclusive of Topsides Costs if Platform Only is C ontracted to Shipyard, Options 1 to 4

Item Beaufort Sea Drawing No 1 Beaufort Sea Beaufort Sea Temporary Drilling Only in Beaufort and Chukchi Seas Drawing No 2 Steel Fabrication ($MM) 140 300 420 450

Concrete Ballast ($MM) 5 7 17 30 (Steel Ballast) Outfitting

($MM) 20 25 30 100
Foundation Excavation and Replacement if Necessary ($MM) 30 100 11 None

Towing to Site and Installation ($MM) 15 20 25 25
Engineering and Approvals

(GBS Only) ($MM) 15 20 25 30

Contingency ($MM) 35 98 132 65 Totals ($MM) 260 570 660 700

Site Water Depth, ft (m) 33 (10) 100 (30) 200 (60) 655 (200) Plus
Cost in $Millions/meter of Water Depth, $MM/ft ($MM/m) 7.9 (26) 5.7 (19) 3.3 (11) Less Than 1.1 (3.5)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 187 of 339 Rev. 0 Table 4-8: Estimated 2007 Installed Platform Co sts, in Millions of USD, Exclusive of Topsides Costs if Platform Only is C ontracted to Shipyard, Options 5 to 8

Item Chukchi Sea Drawing No 3 Chukchi Sea Norton Sound Norton Sound Steel Fabrication ($MM) 240 420 120 240

Concrete Ballast ($MM) 5 17 4 5 Outfitting

($MM) 25 30 20 20
Foundation Excavation and Replacement if Necessary ($MM) 11 110 0 75

Towing to Site and Installation ($MM) 15 30 10 15
Engineering and Approvals

(GBS Only) ($MM) 20 25 15 20

Contingency ($MM) 64 153 26 55 Totals ($MM) 380 785 195 430

Site Water Depth, ft (m) 100 (30) 200 (60) 33 (10) 65 (20)
Cost in $Millions/meter of Water Depth, $MM/ft ($MM/m) 3.8 (12.7) 3.9 (13.1) 5.9 (19.5) 6.6 (21.5)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 188 of 339 Rev. 0 Table 4-9: Estimated 2007 Installed Platform Co sts, in Millions of USD, Exclusive of Topsides Costs if Platform only is Cont racted to Shipyard, Options 9 to 12

Item Navarin Basin Drawing No 4 North Aleutian

Basin Drawing No 5 Typical Platform with 300,000 tonnes of

Storage Drawing No 6 Typical Mobile Drilling Platform

Steel Fabrication ($MM) 960 480 [280] 1 510 330

Concrete Ballast ($MM) 51 51 [25] 0 2 Outfitting

($MM) 50 50 [25] 75 20
Foundation Excavation and Replacement if Necessary ($MM) 0 0 45 0

Towing to Site and Installation ($MM) 70 60 [20] 15 10
Engineering and Approvals

(GBS Only) ($MM) 35 30 [25] 25 10

Contingency ($MM) 334 129 [25] 130 78 Totals ($MM) 1500 800 [400] 800 450

Site Water Depth, ft (m) 445 (135) 330 [100] 100 (30) 33 to 115 (10 to 35) Cost in $Millions/meter of Water Depth, $MM/ft ($MM/m) 3.4 (11.1) 2.4 [1.2] (8.0 [4.0]) 8.0 (26.7) 3.9 (12.9) [Based onMax. Setdown Depth]

1 Values and costs in brackets for North Aleutian Basin (Drawing No 5) are average values and costs obtained from 4 Shipyards in 1997 with respect to similar structure.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 189 of 339 Rev. 0 In Figure 4-9 below, 9 (nine) of the cost-estim ated options are plotted. The estimated cost (Y-axis) is in millions of USD per foot (and per meter) wate r depth and the water depth (Xaxis) is measured in feet (and meters). Options 1, 8, 2 and 6 represent structures on weak foundations. The remainder represent structures on strong foundations.
As an example of how the graph could be interpreted, consid er a 165 ft (50 m) water depth. For a weak foundation, a cost of about $15 million/m ca n be read from the figure. Similarly, for a strong foundation the appropria te value is $11.5 million/m.

The relationship with the constructing shipyard and whether or not that shipyard is also involved with topsides construction must be considered. This constitutes an approximate 0.75 possible reduction fa ctor for the platform.
Consider the following two permutations:

• 165 ft (50 m) water depth, good foundat ion and shipyard involved with topsides. The cost of a platform w ould then be $11.5 MM/m times 50 m times 0.75, which equals approximately $430 million.

• 165 ft (50 m) water depth, weak foundat ion and no shipyard relationship concerning topsides. The cost of pl atform would then be $15 MM/m times 50 m, which equals approximately $750 million.

Thus, even if the water depth and the ice loading conditions are perfec tly defined, there is still the possibility of a wide vari ance in cost. In this simple example, depending on just the variance of two parameters (shipyard relati onship and foundation conditions), the cost can vary between $430 million and $750 million.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 190 of 339 Rev. 0 Figure 4-9: Estimated 2007 Installed Platform Co sts (USD), Platform Only Contracted to Shipyard, Exclusive of Topsides

4.5.7 Environmenta l Considerations There will potentially be some envi ronmental considerations asso ciated with the installation of a bottom-founded structure in the Alaskan OCS. A primary consideration will be whether or not dredging and/or backfilli ng will be required to prepare the foundation for a permanent bottom-founded structure.
The amount of material to be dredged/replaced will be a function of the soil conditions and loads on the structure. Areas may be required for spoil disposal and sources of more competent material may be required. Dredging ( and backfilling, if requir ed) will create some turbidity and some habitat alteration associated with construction/installation activities. It is anticipated that coarse sediment would settle to the seafloor very ne ar the excavation, but that a plume of fine suspended sediment could drift several miles (MMS, 2003).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 191 of 339 Rev. 0 4.5.8 Operations, Maintenance, & Repair A significant operational consideration is trans port of production whether through a pipeline or by tanker. In the case of tanker transpor t, weather conditions are a key factor. Another key aspect of operations will be the safe ev acuation of personnel in the event of an emergency.
Marine operations will require a number of vessels. Depending on regulatory requirements, one vessel may be required to be standby compliant at all times. Support vessels will be used for personnel transfer, ic e management, bunkering, etc.
Maintenance and inspection shutdowns may be required for regulatory compliance. However, these shutdowns wo uld likely be planned around favorable weather conditions. A maintenance and inspection philosophy would be developed for any offshore asset but given the harsh and remote location of the Ala skan OCS, site-specific consideration needs to be given to the environment.

While a planned inspection and ma intenance program can be controlled to some degree, breakdowns occur. Consideration needs to be given to redundancy of critical equipment, spares philosophy and trans port of personnel/equipment.
Supply and personnel logi stics for operations wil l be an important cons ideration. A marine base will need to be establishe d which is accessible year round, has warehouse storage, and has fluids and bulk storage. Supply vessels capable of year round work will be required that will be able to load and bunker producti on chemicals, diesel, fresh water, equipment/materials and drilli ng/completion bulk fluids.

Helicopters and a heliport will be required to transport personnel to and from a GBS and also provide emergency response suppor t. Consideration needs to be given to environmental conditions such as freezing rain, snow and winter storms.
4.5.9 Abandonment & Decommissioning In general, decommissioning of offshore platforms is perceived as technically difficult, costly and posing a number of environmental and safe ty risks. Decommissioning procedures for offshore installations that hav e reached the end of t heir useful life are usually included in governing l egislation, e.g., C-NLOPB, No rwegian Petroleum Directorate, UK Oil and Gas Directorate. There are also international agreements relating to decommissioning that address removal and dee p-sea disposal. For example, theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 192 of 339 Rev. 0 International Maritime Organization (IMO) ha s developed Guidelines and Standards for the removal of Offshore Installations and sets out conditions to protect navigation and maintain safety.

In general, the requirements of the regulatory body over seeing decommissioning might include, among others, the conditions that the botto m-founded structure be designed so that it can be removed if the au thorities at that time so requi re and the requirement that the Certifying Authority reviews the suitability of the detai led design of the st ructure for eventual re-floating.

Based on these requirements, deco mmissioning will likely be an important consideration for any Alaskan OCS bottom-founded structure conc ept. The decommissioning experience of (and ongoing plans for) the North Sea has the most direct relevance to Alaskan OCS concepts.

As the fields in the North Sea have matured, the number of installations that require decommissioning in the near futu re has increased. The OSPAR Convention (1998), whose signatories include Norway and the UK, incl udes provisions relating to prevention and elimination of pollution from offshore instal lations. Recent amendments to this convention have essentially placed a ban on disposal at sea or abandonment in place for all installations. However, exceptions have been m ade for large concrete structures due to the “perceived complexity” of the operation. A recent example is the platforms in the North Sea’s Frigg field, which ended production in 2004. Steel jacket pl atforms in the field will be completely removed, but the Norwegian and UK authorities have granted their consent to abandon a concrete GBS substructure on site . A recent industry study commissioned by the International Associatio n of Oil and Gas Producers ( OGP, 2003) has also identified numerous issues related to decommissioning of concrete GBS structures, including structural integrity when platforms are rais ed from the seabed, and weight and buoyancy issues during re-float (if re-float is shown to even be feasible).

4.6 Jacket & Jack- up Structures

Jacket platforms are used as permanent produc tion structures. Jack-up platforms serve the offshore industry as an exploration structure. The jack-up combines the mobility of floating structure with the jacket platform’s proper ties of wave transparency and fixity.
The jacket structure is the most common fixed offshore platform in the world. It was first used in the Gulf of Mexico and has sinc e been adapted and modified fo r use all over theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 193 of 339 Rev. 0 world. It comes in a variety of styles from the single-legged (mono pod) to multi-legged structures.
The ice reinforced jacket platform was first successf ully used in sea ice in the mid 1960’s at the Cook Inlet developments (Figure 4-10). Three varieties of ice reinforced jacket structures have been used in the Inle t; the monopod, the tripod and the quadpod.

Figure 4-10: Unocal's Monopod Jacket Platform, Cook Inlet (Courtesy of CIRCAC, 2007)
Previous studies of the South Bering conduct ed by PMB Systems Engineering Inc. et al. (1983), the Norton Basin by Fluor Engineers In c. (1982), and the Nort h Aleutian Basin by Brian Watt Associates (1985) suggest that jacket structures may be suitable for use in the Bering Sea.

4.6.1 Technica l Feasibility
4.6.1.1 Arctic Jacket Struct ure Design Considerations

The main consideration for the design of any jacket structure is the payload the structure has to carry, the capacity of the foundation and the environmental loads the structure must resist. The loads unique to offshore Arctic stru ctures are temperature loading, sea ice staticIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 194 of 339 Rev. 0 loads and the accompanying vibration loads. In m any cases, the sea ice static and vibration loads are the controlling factor either globally or locally in the sizing of the structure members. Temperature is gener ally the controlling factor in material selection.
Sea ice in the Bering Sea has varying geometry, concentrations and mechanical properties. The structures in these areas have to be desi gned for the maximum ice load that results from three specific loading mechanisms.

• Momentum load is the load that resu lts from the ice fl ow impacting the structure.

• Ridge building load is t he pressure load the struct ure experiences as a ridge and rubble field builds.

• Pack-Ice loading is the t angential frictional loading t hat results from the ice flow passing by the ridge and rubble fiel d that has formed in front of the structure (Cammaert and Muggeridge, 1988).

The load imparted to a structur e by momentum, ridge building and pack ice loading relates to the width of the structure. In the case of a jacket structure, the load is a function of the jacket leg diameter (D) to distance between l egs (W) ratio (D/W). If this D/W ratio is maintained above seven, then Sanderson (1988) suggests that the legs of a jacket structure will behave independent ly and ice bridging will not occur between the jackets legs. When the legs of the jacket act independently, smaller gl obal loads are experienced by the structure. Sanderson ( 1988) does not indicate what t he maximum sea ice thickness for which this D/W ratio value of seven is appl icable. It is assumed that this D/W ratio is only applicable for non-rafted sea ice thickness of less than 3.3 ft (1 m). This conservative assumption is drawn from t he study of data on Cook Inlet jacket structures. Beyond a sea ice thickness of 3.3 ft (1 m), additional testing is required to determine what D/W ratio will produce independent behavior of the jackets legs.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 195 of 339 Rev. 0 Figure 4-11: Sea Ice Loading a Jacket Leg, Cook Inlet (Courtesy of CIRCAC, 2007)

In addition to handling static sea ice loads, t he jacket structure must handle the vibration loading resulting from the r andom ice edge hit, sudden ice load relaxation, unsystematic ice load level variations and continuous repeati ng ice load failures. Ice reinforced jacket structures are more susceptible to vibrat ion than conventional jackets because they have less damping ability and tend to amplify vibr ations similar to a portal frame.
The dynamic response of a jacket structure from sea ice is not fully understood. However, it is known that the vibration responses are proportional to the desi gn static load and the thickness of the ice. There are a number of ways to reduce the vibration response. First, the foundation can be made as rigid as possibl e to minimize the displacement resulting from the dynamic loading. Se cond, the structural mass and st iffness of the jacket can be changed to reduce the stru ctures resonance.

Another consideration is tem perature loading across the arctic jacket structure. However, the temperature differential of 104°F to 122° F (40°C to 50°C) can be addressed by using low temperature steel t hat is readily available in today’s market.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 196 of 339 Rev. 0 4.6.1.2 Arctic Jacket Structure Enhancements

Recent developments and lessons learned t hat should be used in the potential development of future jacket stru ctures in the Arctic include:

• The use of lower temperature steels to avoid brittle failures;

• The use of double walled ice reinforced jackets to avoid local failures and protect interior members;

• The location of leg bracing well below the sea ice flow. This prevents the collection of rubble and ice bridging under and in front of the structure, hence eliminating the possibility of ice dam age to the bracing system and reducing global and local loading; and,

• The use of X-bracing between jackets, rather then K-type bracing. The Xbracing jacket results in a safer des ign by increasing the redundancy of its members.

4.6.1.3 Assessment of Jacket Platform
The suitability of jacket struct ures has been assessed for t he Bering, Beaufort and Chukchi Seas based on comparison of analogue areas such as Cook Inlet, review of current metocean data for the various regions and the review of prior studies.
Suitability of Jacket Pla tforms in the Bering Sea
A review of metocean data, prior studies of t he South Bering, the Norton Basin, the North Aleutian Basin and George’s Basi n, along with an evaluation of the Cook Inlet jacket structures, indicates that ja cket structures potentially can be used in some areas of the Bering Sea. However, if oil storage is required, jacket stru ctures are limited by this requirement.
Previous studies of the 1980’s (PMB Sy stems Engineering Inc. et al., 1983; Fluor Engineers Inc, 1982; Brian Watt Associates, 1985) indicate that jacket structures are suitable in George’s Basin, Navarin Basin and the North Aleutian in water depths up to 600 ft (180 m). However, these studi es do not consider the dynamic loading of the sea ice on jacket structures.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 197 of 339 Rev. 0 In light of a previous jacket failure in the Gu lf of Bohai and the dysfunction of another as a result of ice induced vibrations (Camm aert and Muggeridge, 1988), there is a strong possibility that dynamic modeling, where ice is thicker than a few feet, may demonstrate that many low mass jacket platforms are unworkable and/or uninhabitable under modern vibration code limits.
Aside from the vibration problem s, jackets used in sea ice hav e significant challenges with the protection of the conductor system. Options for protecting the conductors are to locate the system in the jacket legs or exterior to the legs in a s eparate ice reinforced enclosure. Both solutions have challenges and increase jacke t platform costs. A combination of these solutions has been used in Cook Inlet.
If the conductor is located in the jacket legs and large production flows are required, the size of the legs will have to increase. A fl ow of 100,000 BOPD would require a leg diameter of 55 ft (17 m) (Brian Watt Associates, 1985). In tu rn, larger legs result in larger sea ice loads. The second problem with locating conductors in the jacket legs is that the piles that support the jacket legs are in close proximity to the conductor system and this reduces the effectiveness of the piles. This may result in the requirement of addi tional piles. Lastly, there are blowout concerns with regards to the well close to the jacket supporting piles and drilling incidents could damage the supporting piles.
If the conductor system is located outside of the legs, then it has to be reinforced to handle the local sea ice loading. This reinforcing, in turn, increases the global ice l oad and it also increases the possibility of ice bridging ac ross the conductor and the legs, which again further increases the ice loading.

Jacket type structures could likely be made to work in light first-ye ar ice and water depths less than 200 ft (60 m). The jacket structure’ s poor response to dynamic loading and the conductor system protection issues are a signific ant concern for application in the Navarin, St. George’s, North Aleutian and Norton Basins.
Suitability of Jacket Platforms in the Beaufort & Chukchi Seas
Current design practices and understanding of jacket desi gn make their application unsuitable for the Beaufort and Chukchi Seas. T he primary load case in both areas is ice. The Beaufort Sea commonly experiences thi ck multi-year ice floes and the Chukchi has been observed with enormous mult i-year ridges. The thickness of the ice not only significantly increases the load on the struct ure, but it also creat es problems with theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 198 of 339 Rev. 0 location of the jacket bracing. The bracing should be located below the underside of any ice features which could interact wit h the structure. Thick ice feat ures means that the effective length to radius of gyration ratio (KL/R) of t he jackets would significantly increase. The only way to deal with this increase in the KL/R ratio is to use larger jacket legs. If leg diameter is increased to compensate for t he greater unsupported column l ength, it will result in increased wave loads and drag on the structure. This proce ss becomes counter-intuitive, and one quickly arrives at the conclusion that alternative type structures would be more suitable to this loading scenario.
4.6.2 Constructability Arctic jacket structure construction is very simila r to typical jacket construction for the Gulf of Mexico, North Sea, etc. The only excepti on is that the procedur es used to weld low temperature steels are slightly differ ent than those for c onventional steels.

Jacket fabrication would take place onshore using conventio nal shipbuilding techniques and equipment. Suitable facilities exist nearby in the Western USA, Russia and Japan.
The fabricated jacket would be l oaded out on a barge and transport ed to site. Once onsite the jacket would be launched, u pended and seated in place. Pi les would then be driven through the jacket sleeves and installation would be completed with the loading and connecting of the deck and topsides at site. Ja cket structures are hydrostatically unstable and, therefore, no topsides coul d be on board during installation.
4.6.3 Capital Costs The capital costs associated with the platform des ign, fabrication, an d installation would be directly related to the water depth, environment al loading and topsides requirements. As an indicator, the costs per tonne for conventiona l piles and jackets can be estimated as follows: piles – $2,500 per ton ($2,800 per t onne); jackets – $7,300 per ton ($8,000 per tonne). These costs are in USD and cover the ma terial, fabrication labor, load-out and tiedown at the topsides fabricators quayside.

4.6.4 Environmenta l Considerations Installation of a jacket stru cture would have minimal environm ental issues associated with the activity. The major environmental consider ations for offshore platforms inclusive of jacket types consist of the following:IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 199 of 339 Rev. 0 • The presence of the platform: how will the presence affect the local ecosystem and industries such as comme rcial shipping and fish harvesting;

• The possibility of dischar ges from the platform;

• Platform noises, and the affect the noi se will have on the marine environment;

• Platform emissions and flaring; and,

• The disposal of the drilling cuttings and other platform waste. This can be achieved safely by decontamination and reinsertion.
The jacket platform mitigates many of these conc erns as a result of its small footprint and due to the fact that the topsides and jacket of the structure can be remo ved from the site at the end of its useful life.

4.6.5 Operations, Maintenance, & Repair Many of the operations, maintenance and repair issues are similar to those presented in Section 4.5.8 for bottom-founded structures. An asset integrity program would be an important part of the operation of a jacket type structur e in an ice environment. Inspection of a jacket structure would be different and depending on the severity of any particular season (in terms of waves or ice loads), addi tional inspections may be dictated. Physical inspections would be planned around open wate r as inspections in winter would be challenging.
4.6.6 Abandonment & Decommissioning Considerations regarding aban donment and decommissioning have also been presented in Section 4.5.9 for bottom-founded structures and many of the points made there are relevant to jackets as well.
Jacket structures have been successfully remov ed from the Gulf of Mexico and the North Sea. Jacket structures can be removed with minimal difficulty with the exception of the piles. The removal process is essentially the reverse of the installation process.

The topsides and the deck are removed by a sea crane and placed on a barge. The barge is transported back to land where the top si des and deck can be recycled or alternatively retrofitted and installed at an alternative location.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 200 of 339 Rev. 0 The next step in the demolition process is t he removal of the jacket. This is performed by cutting the jacket from the piles by the use of mechanical or the rmal cutters. In some situations, the jacket can be separ ated from the piles using expl osives. Once the jacket is separated from the piles, a s ea crane is used to lift the ja cket onto a barge where it is transported back to land. Back on land, the jacket is cut into small sections that can be handled by recycling and salvage yards.

Pile removal is possible. However, to dat e, a cost effective method has not been developed.
4.6.7 Commentary on Jack-ups The jack-up rig was first introduced to the offs hore industry in the mid 1950’s. The jack-up rig was developed to provide a fixed base drill rig capable of operating in harsh environments (wave only) with the flexibility to relocate to alternate drilling locations.
Most of the world’s jack-up fl eet can operate in water depths of 30 to 300 ft (10 to 90 m) and drill to depths of 20,000 ft (6100 m). The rec ent state of the art ja ck-ups can operate in water depths of up to 500 ft (150 m) and dr ill to depths of 35,000 ft (10,500 m).

Figure 4-12: Gorilla Class Jack-up (LeTourneau Technologies, 2007)
Jack-up platforms have been constructed for num erous ocean environments. As of yet, none have been constructed to o perate in sea ice environments. However, a study of jackups in ice for Sakhalin (CKJ Engineering, 1997), the development and implementation of a jack-up drilling program on the Grand Banks of Newfoundland and the anticipated construction of a new Russian ice-resistant jack-up rig are indicati ve that the operatingIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 201 of 339 Rev. 0 range of jack-up drilling rigs can be marginally expanded to include areas of seasonal sea ice and of marginal sea ice concentration.
CKJ Engineering’s study (CKJ Engineering, 1997) involved brie f investigations into the structural feasibility of using jack-up Rig SX during freeze up in Sakhalin. Rig SX is a triangular shaped hull configured wit h three jack-up legs consisting of four chords complete with spud cans. The preliminary conclusion of this work was that, structurally, Rig SX can be safely operated, lowered and re-floated in up to 1 ft (30 cm) of first-year ice with improvement to the structure an d reinforcing of the drilling riser. Improvements included positioning the rig such that the horizontals between the leg chords are situated to avoid any local ice loads and reinforcing the co nnections between the verticals and the leg chords.
Extrapolation of CKJ's study would suggest t hat a proportion of the world’s jack-up fleet have the structural potential to operate in ligh t early season first-year sea ice. A complete detailed structural and operational review of a particular rig would be required to determine the capabilities of each specific jack-up rig in sea ice.

Figure 4-13: Positioning of Leg Horizontals to Avoid Sea IceIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 202 of 339 Rev. 0 The successful development and the implementation of a jack- up drilling program on the Grand Banks of Newfoundland, Canada was acco mplished by the establishment of the understanding of the ice-fr ee season and an ice management program (Bagnel, 2007). Prior to the summer of 2005 a jack-up had not been used off the coast of Newfoundland (Bagnel, 2007). The ice-free season was identified by a statistica l analysis of the historic sea ice edge. The ice manage ment program was inclusiv e of a sea ice and iceberg monitoring system, emergency rig relocation procedures and iceberg towing strategies. A Rowan Gorilla jack-up drill rig successfully drilled three wells on the Grand Banks during the summer of 2005 (Bagnel, 2007).
The Ice-resistant jack-up rig Arkticheskaya, the firs t of its kind, is under construction at the Severodvinsk Shipyard, Russia. It is being constr ucted to operate in Ar ctic water depths of up to 330 ft (100 m) and in ice floes of 1.6 ft (0.5 m) thick (MNP Glob al, 2007). The rig is owned by Gazprom and is expected to be commissioned in 2008 (Rigzone, 2007b).

Recent advancements in jack-up drilling depths, the results of CKJ Engineering’s structural investigation, the successful development and implementation of a dr illing program on the Grand Banks – coupled with the previous use of jack-ups in the Norton Basin (see Table 4-10) – indicate that the oper ating range of jack-up drilling ri gs can be marginally expanded in the Bering Sea. The limit of this expansio n is dependent on the dev elopment of an icefree season, ice management progr ams and the study of indivi dual rigs to determine sea ice loading capabilities.
Table 4-10: Historic Bering Sea Wells Dr illed by Jack-up Platforms (MMS, 2007a)
HISTORIC BERING SEA WELLS DRILLED BY JACK-UP PLATFORMS
Location Year Spudded Water Depth, ft (m) Drilling Unit 1985 55 (17) Key Hawaii Jack-up 1985 55 (17) Key Hawaii Jack-up 1984 54 (16.5) Rowan Middletown Jack-up 1985 40 (12) Key Hawaii Jack-up 1984 35 (10) Rowan Middletown Jack-up Norton Basin
1984 65 (20) Key Hawaii Jack-up

Alternative drilling methods are recommended fo r exploration in the Beaufort and the Chukchi Seas due to the short ice-free season and the size and thickness of ice floes. These areas are better suited to alternative dr illing methods such as ice class drillships or bottom-founded structures, e.g., SDC.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 203 of 339 Rev. 0 4.7 Ice Islands

Grounded ice islands have been used as exploration drilling stru ctures in nearshore areas of the US and Canadian Beau fort Sea. Based on the current state-of-practice and technology, ice islands have been assessed with res pect to other areas of the Alaska OCS.
Please note that the following Section draws significantly on the MMS Report No. 468 – Ice Islands (C-CORE, 2005). References are made to Report No. 468 for further information.

4.7.1 Technica l Feasibility From a general perspective, the technical feas ibility of an ice isl and exploratory drilling platform is based on several fundamental r egional and site specific considerations:

• Meteorological environment;

• Water depth;

• Landfast ice characteristics; and,

• Geotechnical (seabed) conditions.

With respect to meteorology, the winter tem perature regime plays an important role. The temperature regime is important because of its influence on natural landfast ice thickness, spray ice construction process effect iveness and ice island/ road integrity.

Natural landfast ice must be stable and sufficient ly thick to permit mobilization of equipment and personnel for construction. Road constr uction and site pre paration using light equipment may proceed when ice thickness r eaches approximately 2.6 ft (80 cm) (CCORE, 2005). In the Beaufort S ea, freeze-up typically begins in mid-October and as shown in Figure 4-14 below, ice thickens by an av erage rate of approxim ately 0.4 in/day (1 cm/day) (C-CORE, 2005). Based on Figure 4-14, during a “normal” winter temperature regime, road construction could start by about mid-December.
Spray ice production generally increases at lower temperatures (C-CORE, 2005). Observations indicate that efficiency in sp ray ice production can be achieved below -4°F (- 20°C), but that the process becomes ineffect ive above 5°F (-15°C) (C-CORE, 2005). Wind speed also plays important role in spray ice production rates.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 204 of 339 Rev. 0 Figure 4-14: Typical Ice Thickness Growth for Canadian Beaufort Sea (Modified from CCORE, 2005)
Ice strength is a function of te mperature. Therefore, as the winter season draws to a close and temperatures begin rising above freezi ng, ice island/road integrity begins to deteriorate. Ice ablation also starts occurri ng when temperatures rise above freezing.

Ice roads must maintain adequate load c apacity to permit safe demobilization upon completion of drilling activities and, therefore, this deteriorati on directly impacts the extent of time available for drilling operations. In the Beaufort Sea, ice road closures vary from year to year and with geographic location, but general ly occur by late April to late June (CCORE, 2005). Ice road closures, therefore, ul timately dictate the cessation of drilling activities and subsequent demobilization, to ensure equipment and personnel reach established land based infrastructure safely.
From this brief account, when evaluating the feas ibility of an ice island, it is obvious that temperature regime is an import ant consideration and that lower temperatures and longer winter seasons are favorable. In the Beaufo rt Sea, temperatures below freezing are experienced more then 80% of the year and have been recorded in every calendar month (US Army Corps of Engineers, 1999).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 205 of 339 Rev. 0 Water depth is a fundamental fa ctor that must also be co nsidered when evaluating the feasibility of grounded ice isla nd structures. Generally, as water depth increases, island freeboard requirements increase as well and, in turn, influence construction time/cost. Practical limits on freeboard ar e governed by spray ice equipme nt capacity and time, i.e., environment temperatures and dur ations. Review of previous ice island usage shows that, in practice, operational drilli ng islands have not been utilized in water depths greater than 25 ft (7.6 m).

Related to water depth, an ice island must be grounded soundly on the seabed to resist ice loads imposed by the surroundi ng ice sheet. This requirement is critical because any appreciable movement of the island during drilling operations can cause damage to the drill-string.

Ice loads within the nearshore landfast ice zone are typically caused by thermal expansion of surrounding ice and are typically restricted to seasonal (total) movements on the order of meters (C-CORE, 2005). Ice load magnitudes are influenced by a number of factors, including, location, ice thickness, ice velo city, total seasonal movement and air and ice temperature (C-CORE, 2005).

Ice loads imparted on an ice isla nd will depend on the ice fail ure mode, rat her than on the driving force of the ice sheet. Ice failure can be defined with respect to the landfast ice sheet or the island itself. Of t he two modes which should be considered – crushing failure (of the surrounding ice sheet) and passive edge failure (of the ice island) – the crushing failure mode typically limits the upper bound of the force that can be imparted (C-CORE, 2005). The global resistance of the ice island must therefore be greater than this force by an appropriate factor of safety; previous operat ional ice islands used factors of 1.35 to 1.5. Figure 4-15 depicts the possible load limiting failure modes where the vertical scale is exaggerated by approximately five times.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 206 of 339 Rev. 0 Figure 4-15: Spray Ice Isl and Potential Failure Modes (Modified from C-CORE, 2005)
Ice island global resistance is governed by one of two failure mechanisms; sliding (along sea floor) or shear failure (through the island co re). Assuming that the shear capacity of soil beneath the island is less t hen than that of the ice island core , sliding resistance will be the governing failure mechanism. This is typical of the Canadian and Al askan offshore Arctic where soils are of relatively low strength (C-CORE, 2005).
The sliding resistance of an ice island is a f unction of contact area and soil strength, and can be found from the following expression:

s w si i u c
s gd gH c D R φ ρ ρ ρ π tan ) ) ( ( ( 4 2

− + + =
Equation 4-1 Where,

R s is the sliding resistance of the island; D c is the island core diameter; ρ i

is above water spray ice density; ρ si is below water spray ice density;IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 207 of 339 Rev. 0 ρ w is sea water density;

c u

is the bottom material cohesion; φ s is bottom material friction angle; H

is island freeboard; and, d

is water depth. A contact factor is sometimes incorporated in to Equation 4-1 where soils are predominantly cohesive to account for potential voids between the ice and soil due to uneven grounding. Contact values of 0.85 or 0.9 have been used (C-CORE, 2005).
Seabed soil type can significantly affect ice isl and sliding resistance. Differences in soil type must be considered in the ice island design.
If the seabed soil type is clay, the contact area between the island and seabed will govern sliding resistance. This is attri buted to the fact that the strength of a clay soil is defined by its undrained shear strength (co hesion) and is therefore indep endent of applied confining pressure when acting in an undr ained manner. C-CORE (2005) indicates that “The main aim in determining allowable shear resistance is to ensure adequate contact pressure to develop shear failure at the ic e/soil interface. A bear ing pressure of about 520 psf (25 kPa) is considered acceptable”.

If the seabed soil is cohesionless, ice island sl iding resistance is a f unction of the applied normal (vertical) stress and the soil internal angl e of friction. Increasing bearing stress, by increasing freeboard, wil l therefore cause a rise in shear re sistance at the soil/ice interface. This suggests that an optimized design can be obtained by reducing island diameter and increasing freeboard. However, as noted, there are practical limitations with respect to freeboard and adequate area must be maintained for drilling operations.

A more detailed discussion on design is beyond the scope of this document. The previous summarized paragraphs on design are intended to highlight design considerations and provide a fundamental level of understanding of ic e island design, which will aid in assessing this technology for other Alaska OCS regions. It s hould also be noted that the preceding design concepts are based on a simplified model in which the ice island is effectively considered a rigid body. C-CORE (2005) states “Thi s simplified model is convenient and has been shown to provide an acceptable level of confidence in design. However, it should be recognized that the isla nd is not rigid, but acts as a continuum in which compression and distortion occurs”. Fu rther information on ice island design, iceIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 208 of 339 Rev. 0 behavior, loading, failure modes, etc. can be found in the MMS Ice Islands report (CCORE, 2005).
4.7.1.1 Feasibility of Selected Scenarios

From the review of ice islands, it is clear t hat they present a prov en and economical option for exploration drilling st ructures in nearshore areas of the Beaufort Sea.

In practice, operational ice isl ands have been employed in water depths of up to 25 ft (7.6 m) in the Beaufort Sea. Howeve r, based on work reported in C-CORE (2005), the use of operational ice islands should be achievable in water depths of up to approximately 30 ft (9 m) (C-CORE, 2005). The MMS Ice Island st udy (C-CORE, 2005) suggests that “incremental improvements in equipment capacity with highe r productivity would allow islands to be constructed into deeper water and it is considered t hat 40 ft (12 m) water depth should not present a problem”.
Ice island feasibility will depend on winter season duration and temperatures, water depth, landfast ice conditions and ge otechnical considerations. Ba sed on these fundamental considerations, Beaufort Sea exper ience and state-of-p ractice, ice island structures can be assessed for other Alaska OCS study areas.
If the location scenarios and water depths pr esented in Figure 4-1 are specifically considered with respect to oper ational ice islands used in pr actice, all OCS study areas would be precluded from further assessment.
OCS study area scenarios were created to help guide assessments, however, and were not intended as single exam ination points. Therefore, based on general water depths, Norton Sound might be considered for ice island use. To characterize the Norton Sound environment and aid in further assessmen t, Table 4-11 has been created to capture parameters indicative of ice island feasibility.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 209 of 339 Rev. 0 Table 4-11: Comparative Feasibility of Ice Island Construction in the Beaufort Sea and Norton Sound
Parameter Beaufort Sea Norton Sound Mean Winter Temp., °F (°C) -13 to -20 (-25 to -29) +10 to +5 (-12 to -15) Typical Freeze-up Date Mid-Oct. 1 Sept. – Nov. 2

Typical Complete Ice Coverage Nov. – May ~ (Nov. – May)
FDD 3 5063 2875 Approximate Maximum Landfast Ice Thickness, ft (m) 6.6 (2.0) 4.9 (1.5) Maximum Extent (month) ~Mar. ~Feb.

Typical Break-up Date early to mid-Jun. mid-may or later

Although Norton Sound does experience significant landfast ice during the winter, the use of ice islands for drilling may not be feasib le as observed from Table 4-11. A primary reason for this assessment is that Norton So und’s average winter tem peratures will prevent spray ice construction from being consistently effective.

Furthermore, the time frame between mobiliza tion and demobilization will be shorter. From the table, break-up in Norton Sound can occu r up to one month ahead of that in the Beaufort Sea, and based on differences in ma ximum ice thickness and freezing degree days, one can draw the conclusion that “suffi ciently thick” ice needed to begin mobilizing will not exist until later into the winter season.
Also, since ice strength is a function of temp erature, the thickness needed for mobilization in Norton Sound should be greater than that required in the Beaufort. Similarly, ice creep will become more of a concern with warmer te mperatures and may resu lt in unacceptable settlement of the drilling rig during operations.

Based on these considerations, it appears that ice islands will not be feasible for Norton Sound; at least for comparable water depth lim its that are observed. However, without detailed analysis it is di fficult to rule them out definitivel y. Consideration of ice loads and associated stability requirements, the possi ble use of innovative techniques such as chipped ice and reducing ice loads, and possible use of rubble piles to initiate island construction, may allow an ice island to wo rk in very shallow nearshore water depths.

1 Shore ice forms in September. 2 “in shallow coastal bays and lagoons” (MMS, 1985) 3 Freezing degree days based on ice thic kness & empirical formula: h = 0.01x √ [(8N θ -501)] (Sanderson, 1988)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 210 of 339 Rev. 0 Nearshore areas of the Chukchi Sea (25 to 50 miles (40 to 80 km) from the coast) have been excluded from the upcoming l ease sale 193. This obviously precludes the use of any shallow water structure such as ice islands in the short term. However, examination of the Chukchi Sea landfast, or perhaps more appropr iately, contiguous ice zone, one can draw the conclusion that an ice island st ructure will likely not be feasible.

“The Chukchi Sea nearshore ice environment is much more dynamic and variable than that of the Beaufort Sea” (MMS, 1990a). In general , the term “contiguous ice” may be more appropriate then landfast because it is defined simply by ice c ontinuous to shore and does not necessarily indicate that the ice has “s tability inferred by the term fast ice” (MMS, 1990a). Contiguous ice is unreliable and “su dden break-aways” can occur (MMS, 1990a).

Beaufort Sea landfast ice is more stable than landfast ice that forms in the Chukchi Sea (MMS, 2007b). The mean occurrence date for the formation of stable landfast ice in the Chukchi Sea is around the 3 rd week of February, while t he Beaufort Sea can experience stable landfast ice conditions more than a m onth and a half earlier (MMS, 2007b). Also, as stated by MMS (2007b), “the growth of landfas t ice is not continuous and can involve formation break-up and reformation”.

In the Chukchi Sea, landfast ice movement s called “ice shoves” most commonly occur during freeze-up and break-up, however, they may occur at any time (MMS, 2007b). “Landfast-ice breakouts, where t he landfast ice breaks off from the shore, occur along the northern Alaska coast. Breakouts can occur at any time of the year” (MMS, 2007b). More information regarding the Chukchi Sea ice en vironment can be found in MMS (2007b) and MMS (1990a).
In light of the above descripti on of the contiguous/landfast ice present in the nearshore Chukchi Sea, it is difficult to conceive that an ice island may be suitable for the use as an exploration drilling structure. Additional analysis would be required to completely dismiss the concept.
If there were locations that would permit the use of an ice island drill ing structure, very nearshore Ledyard Bay or just nor th of Icy Cape might be possibilities for consideration. These areas are at least partially protec ted and would possibly experience less dynamic conditions due to the bay environment.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 211 of 339 Rev. 0 4.7.2 Constructability As discussed earlier in this report, the first ic e structures constructed for exploratory drilling were floating ice pads used in the Canadi an High Arctic during the 1970’s and 1980’s. The majority of these ice pads were constructe d by employing flooding techniques. Average build-up rates achieved were slow, amounting to less than 3 in/day ( only 70 mm/day). Also, using the flooding technique, Union Oil cons tructed the first grounded ice island during the winter of 1977-78 in Harrison Bay, Alaska. Simila rly, slow build-up rate s were experienced. Flooding is still used for ice road build-up and leveling.
Arctic winter drilling programs using land-based rigs are inherently time constrained and slow ice build-up rates were identified as a further limitation. The window of opportunity available to carry out such a drilling program is bound by the formation of stable landfast ice at the onset, and by the latest safe demobi lization date, prior to break-up. Within this timeframe (in addition to equipment mobilizati on, ice road and island construction), the drilling of a relief well may be required. If same-season relief we ll capability is required, a relief pad will need to be constr ucted and the drilling schedule must contain adequate time to permit relief well completion, prior to the latest safe demobi lization date. Need less to say, time is of the essence in su ch a drilling program. To maxi mize the potential operating window, the ice island must be constructed and r eady to accept the rig as early as possible (C-CORE, 2005).

Alternative methods of ice island constructi on were investigated an d through significant experimentation and study efforts spray ice te chnology was developed. All operational ice island drilling structures built in the US and Canadian Beaufort Sea (7 in total), employed this construction technique. Much higher build -up rates are achievable using spray ice.
In general terms, spray ice is produced by proj ecting a high pressure water jet into cold ambient air. The jet causes the airborne wate r to break into droplets thereby enhancing heat transfer, between the relatively warm seawater and the cold ambient ai r, as a result of increased surface area (C-CORE, 2005). This c an result in water droplets forming ice crystals prior to reaching the ice island surfac e. The proportion of ice formed from the water jet depends on several parameters including water droplet size, air temperature, velocity and time that droplets are airborne (C-CORE, 2005). Table 4-10 bel ow, taken during the Thetis Ice Island project in 2002-03, illustra tes the production/application of spray ice.
Spray ice is typically applied in layers to t he natural ice sheet. Over time, with continued application, the ice sheet will begin to sink as a result of the increased load and willIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 212 of 339 Rev. 0 eventually ground on the seabed (C -CORE, 2005). Spray ice production may continue until the design freeboard is reac hed. The rate at which the island ca n be built up is a function of the time required to freeze and cure the sp ray ice as it is applied (C-CORE, 2005).

Figure 4-16: Spray Ice Production - Thetis Ice Island Project (C-CORE, 2005)

Ice island construction time will vary dependi ng on the volume of spray ice needed, meteorological conditions (primarily am bient temperature and wind conditions) and equipment and construction methods employed (C-CORE, 2005). In some cases, equipment may be used to spread and level fresh ice cover and, in some cases, even compact ice. For example, this occurred during the construction of Nipterk Ice Island where ice was compacted and leveled by bulldozers (C-CORE, 2005).

As shown in Table 4-12, construction time required for previous operational ice islands ranged from approximately 20 to 60 days (C-CORE, 2005). The Thetis Ice Island project carried out in 2002-03 employed several innov ative measures to r educe ice island volume requirements and, hence, construction time:

• Reduction of design ice load (based on extrapolated maximum in-season ice thickness);IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 213 of 339 Rev. 0 • Further reduction of design ice load by reducing the thickness of the surrounding landfast sheet; and,

• Use of chipped ice, wh ich reduces the required freeboard because it has a higher density then spray ice.

Thetis ice islands were situated in Harrison Bay approximately 7 to 12 ft (2 to 3.5 m) of water. It should be noted that during constr uction periods of warmer than seasonal temperatures, spray ice produc tion was negatively impacted. Additional information on these islands can be found in C-CORE (2005).

Table 4-12: Construction Times for Operational Islands (C-CORE, 2005)
Island Name Start Date End Da te Construction Time (days) Mars 8-Jan-86 23-Feb-86 45 Angasak L-03 7-Dec-86 3-Feb-87 58

Nipterk P-32 28-Nov-88 20-Jan-89 53 Karluk 13-Dec-88 20-Jan-89 38

Ivik 24-Jan-03 17-Feb-03 24 Oooguruk 24-Jan-03 7-Mar-03 42

Natchiq 11-Feb-03 4-Mar-03 21

Ice island construction must be carried out in a timely fashion to allow maximum time for drilling. To that end, many different techniques and equi pment are employed to maximize ice accretion rates. Some examples of tec hniques used are continuous spraying and cyclic spraying/curing (C-CORE, 2005). “Procedures have also been developed to account for changes in temperature and wind speed in order to maintain optimum ice production” (CCORE, 2005).

Equipment-wise, there are tw o main pump types used: ski d mounted pumps, which are supported by the landfast ice, and larger pumps mounted on float ing or fixed structures (CCORE, 2005). The MMS Ice Island report (C -CORE, 2005) provides a comprehensive overview of equipment and techniques employed.

Monitoring throughout the ice isl and construction phase is requir ed in order to verify that design assumptions and specifications are co mplied with (C-CORE, 2005). Monitoring is also necessary to track schedule and identify any productivity issues (C-CORE, 2005). Upon construction completion, construction m onitoring data is reviewed and as-built geometry checks and ice strength tests may be performed (C-CORE, 2005).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 214 of 339 Rev. 0 4.7.3 Capital Costs Capital costs for an ice island structure will be directly proportional to the amount of ice needed, which generally depends on the ice l oads expected, water depth and soil conditions. Cost optimization may be realiz ed from considering several factors.
In general, the first and primary factor to be considered in cost optimization is simply minimization of the area required for drilling fac ilities. This is, of course, because reducing the diameter of t he island will reduce the amount of ice needed by a squared factor.

The second factor is soil condi tions and is also related to potential diameter reduction. As noted above, island sliding resistance for c ohesionless soils is not dependent on contact area; therefore, for cohesionl ess soil conditions, island di ameter should be minimized and freeboard increased to achieve r equired sliding resistance. C- CORE (2005) presents a good example, which demonstrates the sensitivity of island sl iding resistance with respect to sand and clay soil conditions.
The use of chipped ice in combination with spray ice can reduce fr eeboard requirements and therefore reduce cost as well. The reason for this is that the density of chipped ice is greater than that of spray ice.
Another factor which can reduce capital cost is design ice load reduction. This can be achieved in two ways as noted above. The firs t involves monitoring ice conditions prior to and during construction and comparing them wit h historical norms. If ice thickness in comparison with the historical norm is low for a certain time of season, extrapolation based on the amount of winter season remaining ma y allow reduction of ic e load. This premise was utilized during the construction of the T hetis ice islands (C-CORE, 2005). A second way that ice load reduction may be achiev ed is through physical reduction of the surrounding ice sheet thickness. This technique was also used during t he Thetis ice island project (C-CORE, 2005).
Comparatively, as shown in Figure 4-17 below , ice islands are far more economical than gravel islands, although it s hould be kept in mind that th e risks associated with the ice island drilling are higher, and grav el islands are more versatile with respect to water depths and ice loads.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 215 of 339 Rev. 0 Figure 4-17: Cost of Ice Island vs. Grav el Islands (Reproduced from C-CORE, 2005)

4.7.4 Environmenta l Considerations
The continued use of ice islands in the Beaufort, or potentially elsewhere in the OCS, does not appear to cause an environmental concern.
The MMS Ice Islands report (C-CORE, 2005), however, does comment that crack formation within the island should be monitored to ensure t hat it does not create a potential leak path for contaminants. In addition, C-CORE (2005) states that “T he risk of spillage of liquids such as drilling muds or fuel must also be mitigated with the use of strict handling procedures and containment devices such as drip trays.”IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 216 of 339 Rev. 0 4.7.5 Operations, Maintenance, & Repair As discussed throughout this assessment, time is a primary concern with respect to operations. However, drilling from ice island s has proven successful in the Beaufort Sea and, through continued optimizat ion of design and constructi on and implementation of efficient drilling programs, ri sks associated with schedule wi ll continue to be manageable and should be able to be reduced. Time available to carry out a drilling program from other areas in the Alaska OCS may be a limiting factor.
Movement, laterally and vertically (settlement), of ice islands must be prevented to avoid potential damage to the drill string. If island mo vement does occur, it may only do so within close tolerances. To monitor movement and gain insight into island integrity, “performance monitoring” is carried out. A monitoring program would inclu de the following parameters (CCORE, 2005):

• Natural ice thickness and movement;

• Island lateral movement and settlement;

• Ice temperature; and,

• Ice forces.

Ice islands may require maintenance to ensure that they perform as intended throughout their operational life. In addition to ensu ring the structure’s performance, proper maintenance and monitoring can allow the structure life to be extended (C-CORE, 2005).
The main points of interest from a maint enance perspective are ic e island temperature control, because the island’s structural integrity depends on it, and crack formation within the island (C-CORE, 2005). These are addressed further in C-CORE (2005).
4.7.6 Abandonment & Decommissioning Requirements for abandonment and decommissioni ng are not seen as a concern with respect to the feasibility of this structure. It is assumed that up on demobilization of drilling facilities that the ice island would be left in an acceptable state. Requirements for such a state would be set forth in the Operator’s drilling lease agreement and is outside the scope of this document.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 217 of 339 Rev. 0 4.8 Gravel Islands

Although not a “high tech” technology, gravel islands have been successfully used in the Beaufort Sea for decades, and continue to be viewed as a candi date structure for exploration and/or production (for ex ample, Northstar, Figure 4-18).

Figure 4-18: Northstar Island during Summer (Colaska, 2007)

In general, gravel islands remain attractive in that they are a proven technology, offer a short lead time, and are typically the most ec onomical structure type for shallow water depths. For the Beaufort Sea in particular, t he potential to re-use abando ned gravel islands, coupled with advancing extended-reach drilling (ERD) technology, may increase attractiveness considerably. As a result of recent increasing oil prices and increasing material and fabrication costs fo r other types of structures, it is not inconceivable that the current depths at which gravel is lands are used will be surpassed.

For these reasons and the renewed interest in the Arctic, it wa s considered appropriate to assess gravel islands. The applicability of this structure type elsewhere in the Alaska OCS is also considered.
This Section discusses artificial gravel isl ands, referred to as “gravel islands”. Caisson retained islands are not considered.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 218 of 339 Rev. 0 4.8.1 Technica l Feasibility The use of gravel islands for Arctic explor ation and production has been proven. A total of 49 gravel islands have been constructed in the Beaufort Sea, 18 of which were located in US waters. The first gravel island, Immerk B-48, was constructed in 1972 in a water depth of approximately 43 ft (13 m). Since then, grav el islands have been constructed in a range of water depths, from on the order of several f eet to over 60 ft. In theory, a gravel island has no depth limitation, but in practice it has been c onsidered unfeasible beyond approximately 65 ft (20 m) because of econom ics and logistics (US Army Corps of Engineers, 1999).
The technical (and maybe economic) feasibility of using gravel islands is also dependant on whether the island extends ab ove the waterline. The Tarsiut caisson was previously deployed in 65 ft (20 m) water depth but a gravel island was cons tructed to within 9.8 ft (3 m) of the water surface on which the caisson wa s founded. In deeper water, caissons might be considered to reduce the island footprint.
Based on the fact that gravel islands have been proven in the Arctic, the technical feasibility of gravel islands is not discu ssed in detail here. Instead, a su mmary and highlights of basic technical and design consi derations is presented.
Landfast ice, typically ranging up to 6.6 ft (2 m) thick, covers the nearshore Beaufort Sea for about nine months of the year and has a c onsiderable influence on island design and construction methods. In deeper water areas, multi-year ice incursions have to be considered and, in general, ice ride-up is more frequently encountered (Cammaert and Muggeridge, 1988).

As is generally the case with other arctic bottom-founded structures, the primary design requirement for a gravel island is that it mu st have adequate lateral stability to resist ice loads. A gravel island typically satisfies this r equirement by virtue of its make up. A gravel island is comprised of massive amounts of gravel fill – typically on the order of hundreds-ofthousands to millions of cubic meters – and its base area is much larger than its surface. Gravel islands have greater resistance to slid ing than other structures (US Army Corps of Engineers, 1999).
Gravel islands must also be capable of withstanding potential ice ride-up and wave conditions. Ice ride-up occurs when the surr ounding ice sheet is fo rced up the sloped sideIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 219 of 339 Rev. 0 of a gravel island. With respect to waves, both the resultant wave load, as well as the potential for over-topping, must be considered.

Although the return period and associated m agnitudes will differ, bot h exploratory drilling (short-term use) and production (permanent) gr avel islands must account for the above mentioned design considerations. For exploration gravel islands , design loads are generally based on 1/10 year events, whil e production island design loads are based on 1/100 year and, in some cases, 1/1000 year events.

In general terms, these environm ental loads are managed throug h gravel island geometry. Ice ride-up is impeded by the sl oped island sides due to fricti on and plowing forces and/or, in some cases, by discontinuity in slo pe (Cammaert and Muggeridge, 1988). Consideration also has to be given to ice fragments being driv en into the island duri ng storms. Figure 4-19 illustrates Northstar’s ice prot ection design. Waves begin to break as they reach the sloped island sides, thereby dissipat ing energy before they reach the working surface. Wave overtopping is dealt with by placing the wo rking surface above the design wave height and/or by placing a barrier around the worki ng surface perimeter. The Northstar production island incorporated such a wall into its design.

Figure 4-19: Northstar Production Isl and Ice Protection Design (BPXA, 2005)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 220 of 339 Rev. 0 In addition to design loads, the erosional effect of ice and waves (and potentially current) is another important consideration. A variety of methods/mater ials and combinations have been used to control gravel is land erosion, including sandbags, various filter cloths and fabrics, sheet piles and concrete mats.

Figure 4-20: Ice Clearing on No rthstar Island (Colaska, 2007)

Based on these considerations , the design of a production island will be more robust and typically more elaborate than that of an expl oration island. Figure 4-21 and Figure 4-22 show some additional exploration and production gravel island designs.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 221 of 339 Rev. 0 Figure 4-21: Basic Designs for Granular Fill Ar tificial Islands used in the Canadian Beaufort

(drawn with an approximate vertical exaggerati on of 3 times) (also presented in Section 3.4.3.2 as Figure 3-68)

Figure 4-22: Proposed Liberty Production Island Slope Protection Design (dimensions are approximate) (MMS, 2002)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 222 of 339 Rev. 0 4.8.1.1 Feasibility of Selected Scenarios

Based on the OCS location scenar ios identified in Section 4. 2, and considering practical water depth limitations, nearshore areas of t he Beaufort Sea, C hukchi Sea and Norton Sound can be considered for the use of a gr avel island. Other Be ring Sea location scenarios are excluded from assessment; however, this does not preclude the use of gravel islands in shallow coas tal areas of the Bering Sea.

Although nearshore areas of the Chukchi Sea (25 to 50 miles (40 to 80 km) from the coast) have been excluded from the upcom ing lease sale 193, future sales may open this area for leasing. Therefore, the nearshore Chukchi Sea will be assessed.

To carry out this assessment, a common water depth needed to be chosen and then a representative wave hei ght selected. However, wave height data found during collection of metocean information (Appendix A) were not nec essarily reported at consistent water depths. Therefore, in an attempt to be consis tent, the water depth and associated wave height was selected based on the water depth for which the most wave data was available, about 33 ft (10 m) water depth. No nearshore wave data for the Chukchi was found, however, for perspective, Chukchi Sea offshor e 1/100 year waves may reach upwards of 29 ft (8.8 m) based on maximum wind and fetch conditions.

Regarding multi year ice incurs ion; ridge keels would be depth limited in approximately 33 ft (10 m) of water for both the Beaufort and Chukchi Sea.

Table 4-13: OCS Gravel Island Assessment – Approximately 33 ft (10 m) Water Depth
Parameter Beaufort Chukchi Norton Sound Level first-year ice thickness, ft (cm) 6.6 (200) 4.9 (150) 4.9 (150) Level Multi-year ice

thickness, ft (cm) 9.8 – 16.4 (300-500) 9.8 – 16.4 (300-500) - Multi-year keel depth, ft (m) Depth limited Depth limited - Ice Movement/Velocity, ft/s (cm/s) 3.3 (100) 5.1 (154) 5.1 (154) Wave Height (100-yr), ft (m) 20 (6.1) 1 - 2 29 (8.8) 3

1 Wave height value for water depth of ~ 36 ft (~11 m) 2 No nearshore/shallow water wave height data available for comparison 3 Wave height value for water depth of ~ 30 ft (~ 9 m) (w/ storm surge of 13 ft (4 m))IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 223 of 339 Rev. 0 Based on the primary design condition for a grav el island (i.e. adequate lateral stability to resist ice loads), Norton Sound would be a feasible location fo r a gravel island. As noted below, increased wave conditions can be managed.
As described previously (Section 4.7.1.1), the nearshore Chukchi Se a ice environment is much more dynamic then the Beaufort Sea and, therefore, would require further consideration. Also, since no gr avel island structure has been used in the Chukchi Sea, a more detailed assessment would be required to determine feasibility. From a qualitative stand-point, however, considering the primary design requirement is lateral stability, it would seem reasonable that a gravel island could be made to work in the nearshore Chukchi Sea. If a typical Beauf ort Sea gravel island structur e size would not afford the necessary weight and seabed contact area to achieve required lateral stability, then a larger gravel island could be built.
Similarly, as necessary to prevent ice ride-up, island freeboard could be increased and sloped sides could be lengthened; these changes would also be required to manage increased wave loads and prevent over-topping. With respect to erosion and local damage due to increase ice loads, slope protection design and materials mi ght require further consideration.
The preceding assessment was based on a wa ter depth of approximately 33 ft (10 m) and considered nearshore ar eas of Norton Sound and the Chukch i Sea. Consider ing the use of gravel islands for use in OCS up to current limit s of practice (approximately 20 m or 65 ft), the assessment would be basically the same. Norton Sound would be feasible, but due to larger wave loads, island freebo ard and potentially slope side lengths would need to be increased. Chukchi Sea consider ations would also remain t he same, but with increasing water depth larger ridges w ould be encountered, and therefore larger ice loads would be expected.
4.8.2 Constructability There are basically two methods of construc ting gravel islands: the onshore (hauled) method or the offshor e (dredged) method.

The onshore method typically involves excavati ng material from onshore and transporting it to site via truck over ice roads. Material is dumped through a hole cut in the ice by conventional chain trenchers and backhoes. When using coarse materials, this method can “ensure very accurate placement and steep slopes of 1:3 (vertical-to-horizontal)”IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 224 of 339 Rev. 0 (Cammaert and Muggeridge, 1988). The majority of gravel islands constructed in the US Beaufort have used this method. During the su mmer season, material can alternatively be transported to site via barge.

The offshore method involves dredging material and transport ing it site via barge or pipeline. This method is typically used in deeper water where it is unfeasible to build ice roads or causeways. Islands constructed by dredging typically have side slopes “on the order of 1:15” (Cammaert and Muggeridge, 1988). Most gravel islands in the Canadian Beaufort were built using this method.

As discussed previously in the ice islands se ction (Section 4.7.1.1), the Chukchi Sea has a very dynamic ice environment and nearshore “l andfast” or ”contiguous” ice is highly unreliable. Therefore, the truck hauling method will likely be infeasible. As indicated earlier (Section 4.7.1.1), Norton Sound ice roads will have limited use in comparison to the Beaufort Sea, which wil l therefore limit the use of truck hauling.

When constructing a gravel island, consideration must be given to the fact that a pipeline will need to be brought onto t he island. The timing and met hod of pipeline installation should be such that interference with island c onstruction and/or facilities installation is minimized.
4.8.3 Capital Costs In comparison to other offshore structures, gr avel islands are usually the most economical (US Army Corps of Engineers, 1999). As a function of water depth and size, gravel island construction costs have typically ranged between approximately $10 mil lion and $40 million exclusive of topsides (US Army Corps of E ngineers, 1999). Figure 4-17, included in the ice island section (Section 4.7.3), provides grav el island capital cost information based on water depth and illustrates the cost differ ences between ice and gravel islands.
The most recently proposed use of a gravel island was for t he Liberty prospect located in the nearshore US Beaufort Sea. The propos ed island was to be constructed in approximately 22 ft (6.7 m) of water and have a 345 ft x 680 ft (105 m x 207 m) working surface. Located 15 ft (4.6 m) above sea le vel, the island was estimated at $50 million (MMS, 2002).
In general, the cost of a gravel island is dire ctly proportional to the volume of fill required (i.e., water depth and island size) and the distance to transport it. In practice, gravel islands have been viewed as unfeasible because of economics and logistics at water depths of 65IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 225 of 339 Rev. 0 ft (20 m) and greater (US Army Corps of Engi neers, 1999). With the current price of oil today and the renewed interest in the Arctic, it is not inconceivable that gravel islands might be considered for greater water depths.
In the Beaufort Sea, cost savings may be realized through re-use of gravel from abandoned islands. This was put into practice several years back when gravel from NW Milne Island was reused “to enlarge F Pad (Milne Point unit) into marine waters” (US Army Corps of Engineers, 1999).

Further cost savings may be realized in t he Beaufort Sea through the rehabilitation of abandoned gravel islands. This was also put into practice in 2001, when the abandoned Seal (exploration) Island wa s rehabilitated and turned into a production island for the Northstar project.
With regard to the Bering a nd Chukchi Seas, no cost sa vings based on the above are available. If a gravel island were eventually proposed for these areas, gravel sources would have to be found and transportation costs would ha ve to be carefully considered. Based on the assessment above, one hypothesis can be made regarding cost: gravel islands for these areas will likely cost mo re than an island for the Beaufor t Sea for a given depth (the $/m will be greater). This hypothesis stems from the constructability issues and environmental considerations (more severe ice and/or waves) discussed earlier.

4.8.4 Environmenta l Considerations
The main environmental considerations as sociated with the onshore construction method include the following:

• Gravel mine/pit development;

• Hauling of gravel;

• Gravel placement; and,

• Gravel mine/pit rehabilitation.

Some measures that that c an help mitigate environmental c onsiderations associated with construction are:

• Minimize facility/island size;IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 226 of 339 Rev. 0 • Locate island as close to shore as possible;

• Use filter fabric to minimize leaching of silt and fine particulate;

• Construct island during winter using ice roads; and,

• Use ice roads for seasonal access.
A more comprehensive listing of potential mitigation measures can be found in MMS (2002).
The Chukchi Sea and Norton Sound do not experi ence the same quality of landfast ice as the Beaufort Sea, therefore the ability to mitigate environm ental disturbances due to construction will be somewhat reduced.
During operations, “gravel islands are generally expected to dampen more noise than other types of structures” (US Army Corps of Engineers, 1999).

4.8.5 Operations, Maintenance, & Repair With respect to operations, a gravel island does not differ significantly from other bottomfounded or fixed facilities. However, one notabl e operational consider ation would be island access. During the winter season , access will be an issue if ice roads cannot be built or maintained. If ice roads cannot be built, c onsideration might need to be given to the construction of a causeway/gravel road for access.
The main concern for gravel islands with respect to maintenance and repair is, of course, erosion damage due to ice and wave action (and po ssibly due to current as well). However, “in contrast to other structures, gravel islands are relatively easy and inexpensive to repair” (US Army Corps of Engineers, 1999).

Annual inspections and mainten ance/repair are typically carried out on the island working surface and slope protection system.
4.8.6 Abandonment & Decommissioning Requirements for these activities will be set out in project-specif ic lease agreements. Following decommissioning of a fa cility, abandonment may fall within a range of activities from complete removal of facilities and structur e, to basically a shut down and preservation of the facilities for potential future use (US Army Corps of Engineers, 1999).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 227 of 339 Rev. 0 With respect to the structure, complete removal of a gravel island would pose much difficulty and many environment al considerations. Under a “complete removal” scenario, an alternative might be to remove all facilities, armor mats, barrier walls, etc. and allow the remaining gravel to deteriorate natura lly. This method of abandonment has been historically acceptabl e in Alaskan Beaufort.

4.9 Floating Structures

There are only a limited number of floating expl oration or production st ructures that have been used in ice envir onments. This Section of the report addresses the types of floating structures that might possibl y be considered for explorati on drilling and/ or production development. Topsides are not included in this analysis, except in consideration of the requirement of the floating st ructure to support topsides weight, and provide a sufficiently stable platform for operations. For the purposes of discussion, the term “vessel” is used to describe any floating structure.
During exploration in the Canad ian Arctic in the 1980’s, floating vessels (drillships) were used successfully with the support of icebr eaking ships for ice management. In particular, the Kulluk, a round drilling ba rge purpose built by Gulf O il to the Arctic Class IV specification, roughly equivalent to the moder n IACS Polar Class PC4, operated in the Canadian Beaufort Sea. This vessel coul d operate through the open water season until early December (at the latest) with intens ive ice management support. The Kulluk has recently been refurbished for exploration activities in the Alaskan OCS.
Historically, on the Grand Bank s of Newfoundland, FPSOs (F loating Production, Storage and Offloading) have been the choice of floating production vesse ls under potential sea ice (first-year) and iceberg conditio ns. The hulls of both of t he Grand Banks FPSOs (Terra Nova and White Rose) are designed to continue oper ations with light to moderate first-year pack ice (5 to 8 tenths) and can maintain their moorings in heavy first-year pack conditions (8 to 9 tenths). This ice cover would not hav e significant pressure ridges, nor would multiyear ice be present. Additionally, the hulls are designed to withstand the energy from a strike by a 110,000 ton ( 100,000 tonne) iceberg moving at 1 knot. This is an impact event and not a sustained load as might be found in t he Beaufort or Chukchi Seas. In heavy pack conditions, or in the event of the approac h of an unmanageable iceb erg, the FPSOs are designed to disconnect from their moorings and an emergen cy disconnect can be effected in approximately 15 minutes. No continuo us ice management support is required.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 228 of 339 Rev. 0 Modified spar, TLP (Tension Leg Platform) and semi-submersible designs have also been proposed for ice environments, although none have been built and there is much debate about the feasibility of these concepts in ice, particularly for Beaufort and Chukchi Sea applications. It is the authors’ opinion that floating producti on systems for the Beaufort and Chukchi Seas are currently not technically feasible, even wi th continuous ice management. Floating systems may have some merit in southern Alaskan OCS areas, however.
Floating production platforms proposed for ice/ iceberg areas are typically designed to be readily disconnected from their moorings an d are operated in managed ice conditions. The ability of floating platforms to leave station allows the vessels to avoid extreme ice loads and also provides the capability for operations on a seasonal basis.

In ice-covered waters or regions prone to icebergs, the geometry an d scantlings of the vessel must be chosen to handle ice loads. Any vessel will also need a mooring foundation design capable of handling env ironmental loads. Moored floatin g structures are typically used in water depths greater than 100 ft (30 m). However, yoke-moored FPSO’s have been used in depths as shallow as 60 ft (18 m) in light first-ye ar ice conditions (Bohai Bay).

4.9.1 Technica l Feasibility Seasonal exploration can be ca rried out using drillships and drilling barges and, in areas without multi-year ice, semi-subm ersibles or a TLP. However, for exploration, the only location that a floating struct ure might be capable of staying on station year-round might be the Bering Sea under light ice conditions. A Semi-rigid Floater structure like that presented in Section 3.3.2.6 (Fi gure 3-38) could work year-round under first-year ice conditions (loads ~ 22,000 tons (~ 20,000 tonnes)), but would nee d to have the ability to disconnect and leave station in the event of potentially higher loads.
No floating production structures could be economically designed to stay on station for the approximately 85,000 to 110,000 ton (75,000 to 100,000 tonne) multi-y ear ice loads found in the Beaufort and Chukchi Seas, and possibly northern Beri ng Sea depending on local ice conditions. In any design, an adequate factor of safety would need to be applied to the design load yielding an ultimate design load for the structure and moorings of something like 110,000 to 165,000 tons (100,000 to 150,000 tonnes).
In the southern Bering Sea, und er light ice conditions, a float ing structure might be feasible. However, additional informati on/data would be needed to fully assess the feasibility. Ice conditions in the Grand Banks are roughly analogous to operating conditions thatIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 229 of 339 Rev. 0 predominate in the Bering Sea, particularly sout h of approximately 57° north latitude. North of 57°, pack concentrations tend to be great er than on the Grand Banks. In addition, the Bering Sea, due to the higher general concentration of ice, has pressure ridges which are not present on the Grand Banks wh ich would need to be considered.

4.9.1.1 Ice Loads
In sub-arctic climates, with respect to managi ng ice loads, there are three approaches to the design and operation of a float ing production structure in ice covered water: passive, semi-active and active (Makr ygiannis et al., 2006).

The passive approach is to design the system to wit hstand interaction with all anticipated ice conditions (and other ice conditions). The semi-active approach is to design the system to withstand most environmental c onditions, but also design the facility to leave station in anticipation of environmental events beyond the design capabilitie s of the system. An active approach would, as with the semi-active approach, utilize a floating structure that could move off station if environmental conditi ons dictated. However, to modify and control the operating environment, an active progra m of ice management is undertaken. Ice management involves the use of ice capable sh ips to break-up ambien t ice conditions into small pans or rubble, or by m eans of towing, divert large ic e features from the operating

area.
In the Beaufort and Chukchi Seas, the des ign load event (~85,000 to 110,000 tons (~75,000 to 100,000 tonnes)) for a production struct ure would be the result of an interaction with a multi-year ice feature simila r to one of the following scenarios:

• 6.2 mile (10 km diameter), 65 ft (20 m) thick floe traveling at 0.5 ft/s (0.15 m/s) over a contact width of 330 ft (100 m);

• 1.9 mile (3 km) diameter, 50 ft (15 m) th ick floe traveling at 0.8 ft/s (0.25 m/s) over a contact width of 330 ft (100 m);

• Sustained load from a mult i-year ice floe pushed against a structure by pack ice.
It is extremely unlikely that floes of this magnitude can be resisted by a floating production structure or ice management te chniques used to bring the loads down to an acceptableIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 230 of 339 Rev. 0 level. With respect to the final point above, ice management techniques would not work for a year-round production scenario.
On the approach of unmanageable ice features , the production platform would need to disconnect from its moorings and leave station to avoid contact with these large features. If disconnection is required, the production pla tform will need to remain off station until ice conditions improve sufficiently for reconnect ion (this might possibly be until the spring season). As an example, this approach is us ed in Sakhalin for offloading, where the offloading buoy (SALM) remains in operati on in the early winter with active ice management. When ice management is no longer possible, the buoy is laid into a trench on the sea-floor and operations ar e suspended until the spring.
In the southern part of the Alas kan OCS, where only first-year sea ice is present, the most important criteria for ice load ing is the pack concentration (typ ically expressed as the ratio of ice to open water in tenths ). At pack concentrations of le ss than 8 tenths, the ice loads are typically 50% or less of the loads at 10 t enths (note that 10 tent hs ice denotes densely packed pans or blocks of ice, not an unbroken or refrozen sheet ice). However, this may not hold true if the ice pack concentrations le ss than 8 tenths contai n large free-floating floes. Above concentrations of 8 tenths, loads increase with increased ice thickness (below 8 tenths ice loads are relatively insensitive to ice thickness but this will depend on whether or not free-floating floes are c ontained in the pack). In pack or managed ice, the loads are also largely independent of th e drift speed of the ice (Comfort et al., 2001). These conclusions have been drawn from a wide range of model test da ta, with limited validation from operational experience. Fi gure 4-23 displays the effect of ice concentration on peak loads for various structure types in managed ice environments.
There is no known precedent for a moored st ructure operating in unmanaged continuous heavy ice conditions, but a wide range of model test experim ents have been conducted to evaluate this scenario (Comfort et al., 2001) . In general, ice loading will be greater in unmanaged ice than in managed ice. Ice thick ness and drift speed become important factors in the ice loading in unmanaged ice, primarily due t he need of the structure to break, as well as clear, the ice sheet. In particular, multi-legged semi-submersibles can experience loads disproportionate to the size of the individual column si zes if ice jams in between the legs of the structure.
Another significant potential is sue with regards to the use of a floating structure in heavy (greater than 8 tenths) ice cover is the behavior of the ice as it interact s with the structure. IfIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 231 of 339 Rev. 0 ice is forced under the structure, interact ion with the mooring and riser systems might be problematic.

4.9.1.2 Wave Loads
The 100 year return wave conditi ons for the areas of study are shown below in Figure 4-24. It can be generalized that the in tensity of the design wave c ondition decreases from south to north.
Wave loading on spar, semi-submersible or TLP designs tend to be lower than those acting on an FPSO design, due to reduced waterp lane area (and ther efore greater wave transparency) and by the nature that the natural response frequencies of these designs tend to be outside (faster or slower) the wave frequencies.

For illustrative purposes, Fi gure 4-25 illustrates approximat e design wave loads for a 214,000 ton (194,000 tonne) (displacement) F PSO based on the environmental conditions given in Figure 4-24. An FPSO in the southern parts of the Bering would be subject to lower wave loads than those encountered on the Grand Banks of Newfoundland.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 232 of 339 Rev. 0 Figure 4-23: Peak Loads in Managed Ice - Effect of Ice Concentration on Various Structure Types (Reproduced from Comfort et al., 2001)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 233 of 339 Rev. 0 100 year Return Wave Conditions

0 2 4 6 8 10 12 14 16 18 Norton Basin Navarin Bay St. George Basin North Aleutian Basin Grand BanksBeaufort Chukchi BeringNorthAtlanticGeographic Location

Significant Wave Height (m) or Peak Period (s) Significant Wave Height Spectral Peak Period

Figure 4-24: 100 year Return Wave Condition s in Area of Study; Grand Banks added for ComparisonIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 234 of 339 Rev. 0 Approximate Design Wave Loads Based on a 194,000 tonne FPSO

0 5 10 15 20 25 Norton Basin Navarin Bay St. George Basin North Aleutian Basin Grand BanksBeaufortChukchi BeringNorthAtlanticGeographic Location

Design Mooring Load (MN)

Figure 4-25: Approximate Desi gn Wave Loads - FPSO Basis (N ote: wave loads for the Beaufort and Chukchi are for summer conditions and are not meant to imply year round FPSO operations)

4.9.1.3 Dynamic Positioning
Dynamic positioning will typically be used by vessels acting in an exploration role, e.g. drillships and semi-submersibles, but dynamic positioning thrusters have also been used to supplement passive moorings on production pla tforms in marginal ice areas, e.g., Terra Nova on the Grand Banks.

The dynamic positioning systems installed in deepwater explorat ion vessels require significant thrust availability for sea-keepi ng in waves. These systems may also provide sufficient thrust for station keeping in broken first-year light ice conditions. There is the additional requirement that the vessel hulls be appropriately reinforced for operation in ice covered waters.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 235 of 339 Rev. 0 As a example of the technical (if not perhaps economic) feasibi lity of exploration at high latitudes, a drilling expedition was conducted in 2004 in the high-arctic where, with the icemanagement support of two heavy icebreakers , the dynamically positioned drillship Vidar Viking successfully maintained station for up to 8 days while drilling at 88° latitude in ice up to 9 ft (2.7 m) thi ck (Keinonen et al., 2006).

4.9.1.4 Mooring
Modern mooring systems can provide extrem ely robust anchoring systems for floating structures. In most areas of application, mooring systems for float ing structures are governed by wave loading.

In the Beaufort and Chukchi Seas, unfactored lo ads from first-year ic e will be on the order of 45,000 kips (200 MN) (on a fixed structure) while unfac tored loads from multi year ice can approach 225,000 kips (1000 MN) (on a fixed structure). Maximum ice loads in these areas are generally considered to range from 20 to 100 times t he wave loads. It is possible in the southern Bering, in light first-year ice, that the dominant design criteria of the vessel mooring system could be wave loading, depending on the mooring stiffness. However, this would need to be confirmed in any detailed evaluation process
To provide a frame of reference for the amount of restoring force provided to a moored vessel, the approximate design m ooring force for a selection of FPSOs and drillships is plotted 1 in Figure 4-26 with two icebreaking ships 2 to provide a comparison. The thrust or mooring system resistance available from such vessels is consider ably less than forces from design ice conditions for both year-round exploration (22,000 ton (20,000 tonne)) and production (110,000 ton ( 100,000 tonne)) conditions.

1 Adapted from Figure 4.1 of PERD (1998). 2 Thrust is estimated from published information of sh ip break-power, with the assumption of approximately 0.026 tonnes of thrust per kW break-power.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 236 of 339 Rev. 0 Rough Comparison of Vessels Mooring Systems Capabilities or Propulsive Thrust

0 5 10 15 20 25 Terra Nova FPSO Captain FPSO Petrojarl 1 FPSO Kulluk Drilling Unit

Canmar Drillship

50 Let Pobedy Terry FoxMoored FPSOsMooredDrillshipsIceBreakers

Thrust or Mooring Force (MN)

Figure 4-26: Rough Comparison of selected Vessel Mooring Systems; with selected Ice Breaker Bollard Thrust for com parison (Comfort et al., 2001)

4.9.1.5 Steel vs. Concrete
Steel has predominated as the construction material for floating structures (both for exploration and production) in ice covered waters. In general, this is due to the familiarity of ship builders and regulat ors with the material and its performance in ice from the experience with ice breaking ships.
Concrete has been proposed as a constructi on material for FPSO (Husky, 2001), Spar (Technip, 2004) and Semi-submersible designs of production structures. But, to date, no concrete floating structures have been installed in ice covered waters. These concepts have not been adopted due to the perceived novelty of t he design and uncertainty of fabrication methods and costs (Husky, 2001); however, a concrete spar design is believed to be among design options cons idered for the development of the Shtokman Field in the Barents Sea.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 237 of 339 Rev. 0 4.9.1.6 Seismic
Moored floating structures are not generally critically affect ed by seismic activity. The vessels will respond to pressure waves from nearby seismic events, but the frequency of seismic-induced pressure waves are such that the ship will not res pond with large motions, and so these pressure waves will not constitu te a design condition. There may be some foundation considerations with respect to seismic events.
Seismic event induced waves (tsunami) offshor e are of low amplitude and long wavelength, and again will not induce signific ant motions or loads of a moor ed structure in deep water. In the case of shoal water installations (or other bottom founded structures for that matter), the event of a tsunami may be a design consideration.
4.9.1.7 Oil Storage
FPSO and Spar designs have integral oil storage capability and could be used in conjunction with offloading shuttle tankers.
TLP and Semi-submersible based pr oduction facilities typically do not have integral storage and would require a pipeline connection for expor t. An FSO or direct loading of shuttle tanker can be used with a floati ng production platform without in tegral storage, but it is likely that a separate production platform and FSO would prove to be more expensive than a single FPSO of equivalent capacity (if a floating concept was feasible).
4.9.1.8 Floating Platform Concepts

Floating structure options include thos e presented in the fo llowing paragraphs. Their applicability for use in the Alaskan OCS would depend on whether or not the structure was permanent or temporary, ic e environment, water depth, et c. and would have to be evaluated during any detailed assessment. However, floati ng production systems for the Beaufort Sea, Chukchi Sea and possibly North Bering Sea are considered to be unfeasible. Floating production systems for the South Bering Sea may be found to be feasible.

Drillships are either turret moored and/or utilize dynamic positioning (DP) to maintain station. The turret or DP system allows th e vessel to weather-vane with the environmental loads. Moorings would tend to be used in shoal waters while DP would be used in deeper waters.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 238 of 339 Rev. 0 Drilling Barges can be designed to be insensitive to the direction of environmental loading and can therefore use a conv entional mooring arrangement.

Semi-submersibles will, like drillships, use moorin g and/or DP systems for station keeping. Semi-submersible designs can be used for exploration or production platforms, and have been used in the Bering Sea. Under anyth ing but very light ice conditions, there is the possibility of ice jamming in between the structure’s legs, thus creating th e potential for very large global ice loads. Semi-submersibles do not have storage capacity and must have either a pipeline connection, a connection to an FSO, or direct offloa ding to tankers.
Tension Leg Platforms ( TLP’s ) use taut moorings to mainta in station and can be round or conical in shape as to be insensitive to the di rection of environmental loading. As with semisubmersibles, TLP designs typically do not have storage capacity and will operate with a pipeline, FSO, or direct offloading to tankers.
Semi-rigid Floater which could work as an extended, possibly year-round, exploration platform in the Beaufort and Chukchi or south of the Bering as a y ear-round production and storage platform.
Floating Production Stor age and Offloading ( FPSO ) platforms will typically be turret moored to allow the vessel to weat her-vane with the environmental loads.

Yoke Moored FPSOs have been used in shoal waters (60 to 82 ft (18 to 25 m)). The yoke is itself a bottom-founded struct ure that allows the FPSO to weather-vane, and provides the connections from the production platform to the wells. This design r equires that the yoke penetrate the water’s surface, r equiring that the yoke structur e be capable of breaking ice. This system has been used in B ohai Bay where first-year ice thickness may reach 2.3 ft (0.7 m).
Spars are typically very deep draft vessels (~295 ft (~90 m)) which are suitable only for deep water installations. They have been proposed for developments in ice environments as the small water plane area and symmetrical shape will help to minimize ice loads. Spar designs also have integrated oil storage capacity.
4.9.1.9 Assessment by Alaskan OCS Area

Table 4-14 presents an overview of the possible use of float ing structures for seasonal exploration, year round expl oration and production in the Al askan OCS areas of study.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 239 of 339 Rev. 0 Floating structures have been and will continue to be used fo r seasonal exploration. A floating structure will likely be onl y able to carry out year round ex ploration operations in the south Bering Sea under light ic e conditions. However, a Semi -rigid Floater type structure that can handle a desi gn ice load of 22,000 t ons (20,000 tonnes) could be considered for year-round exploration. Based on current technology, no float ing type structures could operate as a production structur e in the most of the Alask an OCS areas under investigation in this study. It is possible that a production structure might work in the southern Bering under light ice conditions.
Table 4-14: Feasibility of Applicable Floating Technologies in Study Areas Seasonal Exploration

(July – November) Year Round Exploration Production
Beaufort Sea Y N 1 N Chukchi Sea Y N 1 N North Bering Y N 1 N South Bering Y P 1, 2 P 2 Notes: Y = can be carried out N = not feasible P = possible – further ice study and data collection needed
A significant consideration for any of the opti ons would be the potential interaction of ice with the risers and mooring system as ice mo ves around and under the floating structure.
4.9.2 Exploration Operab ility in the Alaskan OCS
An assessment has been made of floating exploration operability in the areas of Alaskan OCS covered in this study.

4.9.2.1 Beaufort Sea Operability
Due to significant ice coverage in the Beaufo rt Sea, drilling operations in water depths of 200 to 655 ft (60 to 200 m) using conventional te chnology and mobile offshore drilling units (MODU’s) available on today’s market can expect to operate from July to mid October. Ice management resources such as adequately equip ped and constructed vessels are required as well. Statistical wave data from the ar ea suggests that there are no extreme wave induced motions to contend with, such as wo uld be the case off Eastern Canada, for

1 Semi-rigid Floater or FPSO could work in 330 ft+ (100 m+) water depth – such a structure could handle a design load of 22,000 tons (20,000 tonnes) but may have to leave station in the event of anticipation of higher loads. 2 In light ice conditions.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 240 of 339 Rev. 0 example. An ice class drillship or specialty drilling units such as the Kulluk would likely be the most suitable rigs to utilize for drilling operations. Although a compromise in drilling efficiency is likely the case du e to infrequent use or outdat ed drilling packages, these rig designs offer some protection from ice crus h loads where others do not. Use of more modern drilling units without ice classification or design considerations would require detailed examination of risk and eventual agreement from the regulator.
4.9.2.2 Chukchi Sea Operability
Similar to the Beaufort, significant ice coverage in the Chukch i Sea means drilling operations in water depths up to 200 ft ( 60 m) using conventional technology and/or MODU’s available on today’s market can expect to operate from July to early October. Ice management resources such as adequately equip ped and constructed vessels are required as well. It is apparent from statistical wind/wave data t hat the Chukchi Sea has more extreme wave conditions, potentially making a “K ulluk-like” drilling unit unsuitable for this area. Therefore, an ice class dri llship would likely be the most suitable to utilize for drilling operations. A semi-submersible, due to its super ior motion characteristics compared to a drillship, could also be a suit able option. The main drawback to a semi-submersible is the lack of ice classified rigs available on today’s market. As pointed out earlier, use of more modern drilling units without ice classification or design considerations would require detailed examination of risk and eventual endorsement from the regulator.

4.9.2.3 Southern Be ring Sea Operability
The Southern Bering Sea study area includes St. George Basin, Navarin Bay, North Aleutian Basin, and Norton Basin.

It is clear from the location, metocean, and ice data that the Navarin Bay, St. George Basin, and North Aleutian Basin areas are relatively ice-free for approximatel y 8 months of the year. This being the case, thes e areas are more favorable fo r conventional drilling units such as semi-submersibles and drill ships on a seasonal basis. These areas are also subject to the greatest wind/wave conditions of the study ar ea. For example, wave data suggests 100-year significant wave height of almost 45 ft ( 14 m). This would place 100- year maximum wave height at approximately 60 ft (18 m), wit h potential for occasional occurrences higher than this. Historical data show s drilling activity in the Navarin Bay and St. George Basin with semi-submersibles with t he earliest spud in August and latest end in March. The extreme winds in the area of ap proximately 110 knots maximum precludes useIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 241 of 339 Rev. 0 of drillships if an extended dr illing program is envisioned in St. George Basin due to potential wind induced loads which could move the vessel off location past acceptable limits. In addition, there are areas in the world where year-r ound drilling activity has taken place in comparable conditions – the Grand Banks off Newfoundland.

The Norton Basin has had drilli ng activity in the past in sh allower waters where jack-ups can be utilized. In deeper waters, it is anticipated conditions are very similar to the Navarin Bay, St. George Basin, and North Aleutian Basin areas.
4.9.3 Constructability In all cases, the expect ed ice load will likely dominate the design of the floating structure’s hull, in terms of its ability to withstand local ice loading and in provid ing minimum resistance to passing through the ice.
The new IACS Unified Requirem ents for Polar Class Ships will be implemented in March 2008. Most classification societies and regulators will likely require the hulls of floating structures to comply with these requirements in Arctic waters, although Polar Class designation my not be required in the areas south of 60° north latitude.

With regards to commissioning and tow out, FPSO, semi-submersible and TLP designs offer the option of dock side installation of t he topsides units, and tow out of the assembled unit. Spar structures, due to t heir extreme draft, are norma lly towed out horizontally and upended on site, requiring the installation of topsides at the installation site.
4.9.4 Capital Costs Capital costs for all types of construction have risen rapidly world wide in the last three years. To provide a reference for potent ial development costs, the preproduction development costs of the two FPSO developm ents on the Grand Banks are presented in Table 4-15. Also presented ar e costs for two other proposed development concepts; an FPSO development in the Arctic waters off of Greenland (EnCana, 2005) and a proposed mobile Semi-rigid Floater system (CKJ Engineeri ng, 2005) intended for ex ploration in arctic waters (Section 3.2.2.6).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 242 of 339 Rev. 0 Table 4-15: Project Capital Costs for Select ed Developments at Time of Completion or Proposal (USD)

Source Project Year Total Preproduction ($ MM) Structure Only ($

MM) Completed Projects Husky Terra Nova FPSO 2002 2,800 n/a Husky White Rose Sea Rose FPSO 2005 2,400 n/a Proposed Projects EnCana Greenland FPSO 2005 1,000 430 CKJ Engineering Ltd. Se mi-rigid Floater 2005 n/a 500

4.9.5 Environmenta l Considerations Apart from the environmental considerations common to all offshore oil developments in arctic waters, the subsea environmental impact of a floating structure will be localized to the anchor and well sites (specific to the installati on of a moored structure in the Alaskan OCS).
4.9.6 Operations, Maintenance, & Repair Operations in ice covered waters impose additional requirements to normal offshore operating requirements. Ice forecasting, tr acking and management is a vital component of operations in ice covered water.
In addition to ice management at the exploration/ production site, ice management may be required for the shuttle tankers (if required), supply vessels, and for access to any onshore based facilities.
Evacuation of personnel from a floating platform (or in fact any platform beyond the landfast ice zone) in ice covered water remains a chal lenge for any development. Use of standard evacuation devices in ice, particularly in heavy concentrations of ice, is not possible. The primary challenge is to have an evacuation system that can function in such a wide range of environmental conditions, and while significant devel opments have been made recently in developing evacuation systems, much devel opment is still required in this field.
4.9.7 Abandonment & Decommissioning Decommissioning of production platforms in t he North Sea has resulted in legislated requirements for the platforms to be deco mmissioned as opposed to abandoned. Although many of the North Sea platforms were intended to be disposed of at sea (or left in place inIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 243 of 339 Rev. 0 the case of fixed structures ), regulators have virtually banned this practice and have required the removal of the floating structure fo r reuse or to be salvage d in other ways. For example, the Brent Spar in the North Sea was (with regu latory approval from UK authorities) to be sunk offshore, but public ou t-cry resulted in the platform being used as a ferry terminal.

Any development will most likely r equire the complete removal of the floating structure from the site to be re-commissioned at a different field, or salvaged or re-purposed if recommissioning is not possible or economical.

4.10 Subsea Solutions

4.10.1 Technical Feasibility In some cases, there may not be a requirem ent for an island/platform offshore. If the wellhead is located in water of sufficient dep th, protection from ice would not be necessary. This was the case for the Drake PanArctic pr oject in the 1970’s, wh ere the well location was chosen such that the top of the well head was deep enough to avoid contact by ice keels, predominantly less than 150 ft (45 m) deep in that area.

In areas with water depths less than the maximu m ice keel depth, glory holes may need to be considered to protect the subsea facilities fr om ice ridge keels. This is considered to be approximately 200 ft (60 m) water depth in areas subjected to ice gouging.

There is a lower limit to where such protection structures would be effective as well. Glory holes would only offer protecti on from gouging keels. Where acti ve ridge building is taking place (around 65 ft (20 m) water depth), there is the potential for a ri dge to be pushed into an open glory hole. Further site -specific analysis would be required to determine the appropriate water depths between which th is protection strategy could be used.

4.10.1.1 Subsea Tiebacks
Improvements in the area of subsea facilities and processing have been made in recent years in the pursuit of resour ces in harsh and remote environm ents. As a result of these improvements, fields requiri ng longer, deeper subsea tiebacks are now becoming much more technically and economically feasible . Gas tiebacks have reached 105 miles (170 km) (Statoil Snøhvit) and oil tiebacks have reac hed 40 miles (65 km) (Shell Expro “Penguin”).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 244 of 339 Rev. 0 Subsea processing could offer advantages to Ar ctic development due to potential distance between wellsites, the harsh envi ronmental conditions and wate r depths further offshore. Subsea processing has primarily evolved around the development of: subsea booster pumps, subsea compressors, subsea separat ors and subsea gas dewpointing and dehydration.

For subsea tieback options on the Alaskan OCS, production would be through remotelyoperated subsea facilities with pipelines running to offshore facilities and/or landfall. Offshore structures would not be required except during drilling of the wells a nd installation of the subsea equipment. Depending on the dev elopment, water depth, tieback distance and landfall location will vary . Technology has been develop ed (and continues to be progressed) which allows for separation and disposal of produced water subsea. This helps reduce flow assurance issues associated with pi pelines and flowlines, as well as minimizing above water or onshore facilities. However, fa cilities still may be required to allow for the injection of hydrate inhibitors into the subsea facilities/pipelines/flowlines.

One of the most notable subs ea projects is the Ormen Lange project. This project is comprised of subsea equipment located in 2800 to 3600 ft (850 to 1100 m) water depth and 75 miles (120 km) off Norway. The projec t will flow 2.5 Bcf/day (70 million m 3 /day) of gas and 500,000 bbl/day of condensate to an onshore processing facility. Work is also planned to advance/qualify technology incorporate a subs ea compression station in to the project to boost production starting in 2015, as opposed to build an offshore platform to house compression facilities (Offshore Engineer, 2007)
4.10.1.2 Glory Holes & Protection
The risk of impact with an ice keel is the primary driver for prot ection of subsea facilities in the Alaskan OCS, although secondary fact ors may come into play such as operational/maintenance issues or protection from fishing e quipment, ship anchors, etc. The type and degree of protection is usually determined through a site-specific risk assessment, which involves understanding t he probability of ice incursion and the consequences should an impact occur.
Glory holes (Figure 4-27) are excavations in t he seafloor into which subsea facilities can be installed for protection from scour ing ice keels. This applies, of course, if the discoveries on the Alaskan OCS are located in an active ice gouge zone out to about 165 to 200 ft (50 to 60 m) water depth, depending on acceptable risk.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 245 of 339 Rev. 0 Two existing projects use open glory holes to protect wellheads and associated subsea equipment from iceberg keel im pact. These are the Terra Nova and White Rose projects located on the Grand Banks (C anadian east coast) where, to da te, glory hole excavation has been the preferred method of subsea facilities protection.

The White Rose project uses three glory hole s in water depths ranging from 395 to 410 ft (120 to 125 m), whereas the Te rra Nova project uses five glory holes in water depths ranging from 310 to 330 ft (95 to 100 m). Table 4-16 presents a summary of the glory hole dimensions from these projects.
Other protection strategies have been consi dered for the Canadian east coast including cased glory holes, soil/rock berms and concrete structures. However, open glory holes have been identified as the optim um solution for protecting subsea facilities from gouging iceberg keels in this region (Offshore Maga zine, 2007). Again, depending on the water depth of development, this may not necessarily be the case in the Beaufort or Chukchi Seas.
A site-specific risk analysis of potential ice keel inte raction with subsea facilities in the Alaskan OCS was beyond the scope of this study , but the following opti ons would likely be considered:

• Do nothing, i.e., the risk analysis may s uggest that discrete subsea facilities (not pipelines) placed directly on the seafloor, with no add itional protection, will be acceptable (dependant on water depth);

• Reduce the probability of ice keel impact by pl acing subsea facilities in a glory hole, such as on the Grand Banks; and

• Reduce the probability (and/or consequ ences) of ice impact through some sort of additional mechanical prot ection of the subsea facilities.
The use of other methods, such as cased glor y holes, may have some potential for smaller footprints like single wellheads.
Figure 4-28 is a sketch of a mechanical subsea facilities protection concept for the Canadian Beaufort Sea for water depths up to around 100 ft (30 m). In this concept, a steel caisson is floated in and set-down in a glory hole, and then the glory hole is backfilled. The upper caisson is sacrificial and will shear away during impact with a scouring ice feature.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 246 of 339 Rev. 0 The robust “ice lid” provides pr otection of the subsea facilities from the scouring ice above. This system has potential for the Canadian Be aufort because a more pressing need for mechanical protection is perceived by industry. For example, ridge-building activity in firstyear ice conditions may form a grounded ri dge inside the glory hole area. Pack ice movement could then cause this grounded ridge to move and threaten subsea facilities.
Excavation of a glory hole is required to in stall this system anyway and in deeper water (100 ft (30 m) plus maybe) the gl ory hole alone may provide su fficient protection from ice keels. Again, for small footprint subsea fac ilities (< 33 ft or 10 m diameter), a backfilled caisson may offer some protection against fishing equipment or undue silt ing-in of the glory hole, but for larger footprints (> 100 ft or 30 m), glory hole excavation alone may be the preferred method (dependi ng on water depth).
4.10.1.3 Feasibility of App lication of Subsea Technol ogy at Location Scenarios
The use of subsea production faci lities is another method of production for areas subject to ice gouging and can be envisioned as a viable alternative in certain cases on the Alaskan OCS. As presented previously, the technol ogy has been used for long, deep tiebacks and in harsh environments subject to ice.
Subsea facilities can potentially be used at any of the location scenarios considered in this study. These facilities would need to be locat ed in glory holes within the zone of gouging but could be placed directly on the seabed in areas of minimal risk.
Conceptually, where a subsea to beach option is not c hosen, artificial gravel islands might be considered for water depths less than 50 ft (15 m), bottom-founded platforms from 50 ft (15 m) to some water depth where they are no longer technically or economically feasible, and, in deeper water, subsea solutions to shor e or a platform in shal lower water might be considered. When evaluating a subsea tiebacks solution, access to hydrocarbons might first be considered through extended-reach drilling followed by subsea wells tied back to the main production platform.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 247 of 339 Rev. 0 Figure 4-27: Glory Hole (Fro m Coflexip Stena, 2000)

Figure 4-28: Mechanical Subsea Facilities Prot ection Concept for Water Depths to 30 m in the Canadian Beaufort SeaIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 248 of 339 Rev. 0 Table 4-16: Overall Glory Hole Dimensions (Technip, 2001)

Field Glory Hole Base Dimensions, ft (m) Depth, ft (m) Side Slopes Ramp Slope Southeast 82 x 82 (25 × 25) Northwest 82 x 82 (25 × 25) Northeast 148 x 82 (45 × 25) Southwest 213 x 82 (65 × 25) 33 (10) Terra Nova

Far East 142 x 76 (43.2 × 23.2) 34 (10.3) 1:3

Southern 190 x 146 (58 × 44.4)

Central 191 x 163 (58.3 × 49.7) White Rose Northern 125 x 56 (38 × 17) 30 (9) 1:1.8 1:5

For the location scenarios in water depths le ss than 65 ft (30 m), the use of subsea to beach or subsea tiebacks might be considered. Howe ver, this is in a region of grounded ice and ridge building. Therefore, a cover would likel y be required to protect the facilities from ice keels entering the glory holes.
Open glory hole concepts may be sufficient in areas with greater t han 100 ft (30 m) and less than 200 ft (60 m) water d epth for subsea to beach or subsea tie back concepts. However, site-specific analyses would need to be carried out to assess the risk of an ice keel entering the glory hole and damaging facilities. At the 200 ft (60 m) water depth locations, depending on the ice gouging regime, it may be po ssible to put the subsea facilities directly on the seafloor.

Deeper water location scenarios will likely requi re some type of subsea facilities on the seabed, whether they are part of a subsea to beach option or tied into a central production facility.

The other aspect with regards to a subsea to beach option (or a tieback option, for that matter) is the distance to shore or to a pl atform. Recent records were approximately 30 miles (50 km) for oil and 100 m iles (160 km) for gas. Therefore, some of the location scenarios will require additional technological devel opment or facilities for distances greater than these.
In all cases, the overall depth of the glor y hole (where used) and t he requirement for tie back flowline burial would need to be det ermined through appropriate risk analyses.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 249 of 339 Rev. 0 4.10.2 Constructability Installation of subsea equipment will require a number of dedicated vessels for the installation activities, as well as ice managem ent capabilities. Installation may also require diving and ROV operations. Final seabed leveling using specialized equipment may be required to aid in positioning the seabed equipment. Other ve ssels would be required for ice management, survey, support, supply, etc. A ll would be required to be suitable for Arctic work.
Flowlines between subsea facilities, to a platfo rm or to shore are given many of the same considerations as pipelines discussed in Section 4.11.

With regards to glory holes, there may be some uncertainty with regards to soil conditions in the Alaskan OCS. Geotechni cal and geophysical informati on would need to be obtained to support an excavation. The mi x and strength of soils can vary within a single excavation and the presence of boulders, cobbles, etc., will be difficult to identif y before the start of excavation.
Equipment capable of digging glory holes will depend on water dept h and could include cutter suction dredges, trailing suction hopper dredges, clamshell dredges , large drills, and other ROV based subsea excavators. Because of the uncertainty and variability about soil conditions, glory hole excavation methods t hat are less sensitive to soil conditions are preferable. There is considerable experience with the use of large “drill bits” to excavate well cellars (glory holes) in fairly challenging soil conditions.

4.10.3 Capital Costs
Subsea tieback costs are well established in the offshore oil and gas industry. Costs associated with long subsea to b each projects can be put in pers pective by looking at some of the large subsea projects including Tord is, Snøhvit and Ormen Lange. Costs associated with wells, subsea booster pumps, subsea compression, subsea separation and subsea gas dewpointing and dehydrati on may need to be considered.
The selection of excavation equipment will depend on a number of variables including R&D/field trials of sele cted equipment, schedule, weat her, presence of ice during construction, availability of equi pment that is Jones Act compliant and required upgrades to equipment to work in an Arctic environment.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 250 of 339 Rev. 0 Excavation costs using a floating dredge c an be estimated based on a current cost of $250,000 for a large dredger, plus mobilization/dem obilization costs. Actual production rates would depend on the depth of glory holes required and site-specific soil conditions. Other vessels would be required for ice management, survey, support, supply, etc.
If a steel caisson was required in the glory hole, the additional cost to install and backfill a steel caisson is not prohibitive . A small caisson could be constr ucted for around $2 to $3 million USD and larger caissons for up to $30 m illion USD (excluding costs to backfill). At this cost, caissons could be attractive for op erational/maintenance reasons or for additional “peace of mind” for facilities operated remotely from shore.

4.10.4 Environmental Considerations As with dredging for pipeline trenches, glory holes will be required to be trenched to approximately 165 to 200 ft (50 to 60 m) water dept h in areas subjected to ice gouging. The overall size and depth of the gl ory hole will be a function of t he number of wells, height of the subsea equipment and required clearance between the bottom of the ice keel and the top of the equipment.
By the nature of excavating a glory hole, some seabed disturbance wil l take place. Areas will be required for spoil disposal. Trenching and disposal will create some turbidity and some habitat alteration. It is anticipated that coarse sediment would settle to the seafloor very near the trench, but that a plume of fine suspended sedi ment would drift several miles (MMS, 2003).
The placement of subsea facilities which do not require a glory hole will have minimal environmental considerations. Glory hole or not, a pipeline/flowline will be required to transport the produced hydroc arbons from the well site.

4.10.5 Operations, Maintenance, & Repair A significant consideration for operation of subsea facilities will be flow assurance. Depending on the nature of the development, hydrate inhibi tion will need to be considered which may require an inhibi tor injection and recovery system be installed on the platform/island or onshore.

Asset integrity management, scheduled main tenance and asset reviews will be an important aspect of the operati on of subsea facilities. Subs ea systems will require that periodic inspection, maintenance and repair activities be carried out which will require theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 251 of 339 Rev. 0 deployment of working and support vessels. Ic e management capabilities may be required to support these activities. An ROV or dive rs may also be deployed to accomplish these tasks. Having critical spares on hand will al so need to be considered given the remoteness of the region.
An important aspect of the use of subsea facilit ies remote from shore or an island/structure is intervention. Unplanned interventions during open water may be handled with a construction vessel or support vessel. Any interv ention work that needs to be done in winter would be very difficult and may require an ice class vessel with a moon pool and a work ROV. One of the big c hallenges will be equipment and personnel logistics.
4.10.6 Abandonment & Decommissioning Decommissioning procedures for offshore insta llations that have reached the end of their useful life are usually included in governing legislation. There are also international agreements relating to decommi ssioning that address removal and deep-sea disposal. For example, the International Maritime Organi zation (IMO) has developed Guidelines and Standards for the removal of Offshore Installa tions and sets out conditions to protect navigation and maintain safety.
Some general requirements in other jurisdic tions with regards to decommissioning include designing all subsea facilities such that, upon termination of production, they will be capable of being covered or remo ved so that the area is retu rned to a fishable condition. This may require that glory holes be filled in after the completion of a project. Based on these requirements, decommissi oning will likely be an important consid eration for any Alaskan OCS development project that uses subsea technology.

4.11 Pipelines & Flowlines

There are a number of issues to be considered with regards to the protection of pipeline and flowlines in arctic environments such as the Alaskan OCS, over and above what might normally be considered for pipeline design. These include issues surrounding design, construction, operations, main tenance and repair whic h are addressed in this Section. Pipelines have been designed, constructed and are operational, but these are in relatively shallow water depths and relatively close to shore. Pushing the lim its to developments further offshore in deeper wate r will require additional consideration be given to some of these aspects.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 252 of 339 Rev. 0 4.11.1 Technical Feasibility 4.11.1.1 Design Issues
Surveys & Data Collection

It is accepted that a certain am ount of data will need to be collected in support of arctic offshore pipeline design and construction plann ing; more than what would normally be collected for a pipeline in more temperate climates or above ground arctic pipelines. In general, it might be expected that the following be carried out:

• Detailed Bathymetric Survey;

• Ice Gouge Data Collection;

• Detailed Geotechnical Survey / Labor atory Testing (including permafrost testing);

• Sediment Transport Studies;

• Detailed Shore Crossing Survey and Evaluation of Shor eline Erosion;

• Ice Surveys.
Several years of data might be expected to support pipeline design and construction planning. It should be consider ed that data collection effort s may be hampered by ice or lack thereof in any particular year and that se veral seasons may be required to successfully gather all the data necessary for design and construction planning.

Geotechnical Conditions
Geotechnical information (field and labora tory) needs to be collected and analyzed to determine soil properties which wil l be used in design and the ev aluation of potential thaw settlement. The results of t he geotechnical testing/analysis, along with the pipeline design analyses, can also be used to determine or conf irm trenching and backfilling requirements, thaw settlement or frost heave.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 253 of 339 Rev. 0 Pipeline Routing

Given the cost of arctic offshor e pipelines, potential ro uting of offshore arctic pipelines is primarily evaluated based on minimizing length of pipeline and minimizing the potential loading from environmental co nditions. Also of significant importance is minimizing the impact on the environment and maximizing use of existing infrastructure.

Metocean Conditions

The characteristics of the Ar ctic environment include ice- free summer ocean conditions during which waves and currents achieve t heir maximum values, partial ice cover conditions during spring break-up and fall ice freeze-up, which dampen wave generation and propagation, and extremely cold winter conditions when larg e expanses of open water generally do not exist, thereby precluding wave generation.
Meteorological factors import ant to the design and construc tion of the arctic facilities include wind, temperature, pr ecipitation, barometric pressu re and visibility. Ocean currents are normally of secondary importance, as ot her loadings will likel y govern. However, currents can cause seabed erosion which could ex pose the pipeline or a ffect its stability. Water level fluctuations caused by tides, storm surge, winds, etc. must be considered in pipeline design. Waves must be c onsidered in various aspects of the pipeline design, most notably sediment transport and pipeline stability.

All of these factors must be considered when ev aluating constructability as they can create potential operational di fficulties during periods of offs hore summer construction, marine vessel transport, maneuvering and docking.

Ice can be characterized as landfast ice, t he transition or shear z one, seasonal pack ice, first-year and multi-year pressure ridges, ice islands and icebergs. In the Arctic, heavy ice ridging typically happens at t he edge of the landfast ice zone. In the Arctic, the average length of the ice coverage season could be approximately 300 days.
Ice Gouging
It is generally accepted that offshore arctic pi pelines would need to be trenched to some depth below the seabed to protec t the pipeline from the effect s of pressure ridge ice or iceberg keels. Gouging of the s eafloor is a nearshore feature for most northern continentsIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 254 of 339 Rev. 0 where ice is present and where ice/iceberg keels travel into water with depths less than the keel draft, forming a gouge mark on the seafloor.
An offshore pipeline in such an environment ma y have a requirement that it not come in contact with ice and, therefore, it must be buried below the design ice keel gouge depth for protection. However, as the ic e keel passes over any point in the seabed, vertical and lateral stresses are applied to the soil at the k eel base, resulting in some distribution of vertical and lateral soil displacements with depth beneath the ice keel. This is typically termed “subgouge deformation” of the seabed beneat h the gouging keel (Figure 4-29). This soil movement can impose forces on the bur ied pipeline and result in deformation. The configuration of the pi peline after gouging, and hence the stra in in the pipe line, depends on the pipeline properties, the soil characterist ics, the depth of the design ice gouge and the depth of the pipeline below t he undisturbed seabed surface.
The pipe must be trenched suffi ciently beneath the influence zone of soil displaced below the ice keel to limit pipeline strains to withi n acceptable limits. Anal yses must be carried out to understand the soil displaceme nts induced at the pipeline depth due to ice gouging and resulting strains in the pipeline evaluated , possibly through non-linear finite element analysis.

Figure 4-29: Ice Gouge and Subgouge DeformationIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 255 of 339 Rev. 0 Geophysical surveys of the seabed are conduc ted and high-resolution bathymetry data taken to measure the depths and widths of individual ice gouges. Side-scan sonar records are also used to help identify the individual gouges and to measure t he gouge orientation. Gouges on the seabed are altered by other gouge occurrences, sedim entation (infill) and sediment transport. Shallow areas exposed to waves and currents during the open water season could have all bathymetric traces of ice gouging destroyed by the end of each summer season. These issues, which could tend to mask the potential im plications of ice gouging, would need to be appropriate ly accounted for in design.

Thaw Settlement & Frost Heave
In arctic areas, permafrost can be found thr ough the pipeline shore crossing area and in shallow water. Thawing of ice-rich permafrost can result in loss of soil strength, excessive settlement, freestanding water and accelerated surf ace erosion onshore at shore crossings.

Differential settlement or frost heave is possible along a pipeli ne route due the fact that soil conditions or permafrost may not be continuous and uniform and the pipeline is not at a constant temperatur e along its length.
Analyses can be carried out to predict the thaw bu lb extent, the thaw strain potential of the permafrost and the strains imposed on the pipe line. There are a numb er of ways to deal with the issue of thaw settlement, including in corporation of mitigative measures, avoiding excessive thawing by insulating the pipeline a nd designing the pipeline to take the strains.
If a pipeline is operated at a temperature lower than the fr eeze point of the surrounding soil’s pore fluid, then the so il surrounding the pipeline coul d freeze, potentially subjecting the pipeline to frost heave. Al ternatively, even if the pi peline were not operated below freezing, the active layer of the soil surrounding the pipeline could fr eeze, forming ice and pushing the soil surface upward. Analytical and numerical tools can be used to determine the behavior of pipelines undergoing fros t heave in discontinuous environments.
Upheaval Buckling & Thermal Expansion

When a buried steel pipeline is operated at a temper ature (and pressure) higher than that experienced during installation, it will try to expand longitudinally (thermal expansion). A long buried pipeline is not free to expand due to the restrain t provided by the surrounding soil, and thus will dev elop a locked-in axial compressive force. If the buried pipeline has some residual vertical curvature, possibl y due to trench bottom irregularities duringIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 256 of 339 Rev. 0 installation, the effect of the axial force near the high points of these trench irregularities will attempt to buckle the pi peline upward at these locations. If the upward force exceeds the downward force, then the pi peline will move upward and ma y become exposed above the seabed. This phenomenon is known as “upheaval buckling” (Figure 4-30).

While this is a design issue not unique to the arctic, pipeli nes in such environments are normally installed at lower ambient temperat ures and therefore will experience a larger temperature change when operating under steady state conditions.
The immediate effect of upheaval buckling for arct ic offshore pipelines is that the pipeline could become exposed at the seabed, which in creases the risk of impact by ice keels. Problems associated with upheaval buckling may in clude high bending st resses and loss of protective soil cover but may not directly c ause a leak or exceed other limit states. However, upheaval buckling is a limit state t hat is an undesired cond ition and which must be designed against.
Minimum backfill thickness that must be placed over the pipeline for the selected design parameters and maximum allowable vertical variance (prop or im perfection) of the installed pipeline profile must be determined in design. The backfill on top of the pipeline is expected to provide the resistance needed to hold the pipeline in the installed position.
The larger temperature difference between t he installation and operating temperatures experienced in arctic regions wi ll also result in larger potent ial thermal expansions at the ends of unrestrained pipelines. This expansion must be accommodated through offshore or onshore expansion loops or by the risers at the shore crossings and the offshore island/platform.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 257 of 339 Rev. 0 Figure 4-30: Subsea Pipeline Upheaval Buckling (After Palmer et al., 1990)

Strudel Scour

Nearshore arctic zones typically develop a botto mfast ice sheet during the winter season. If an onshore river flow encounters such an area dur ing the spring breakup, the river water will overflow the bottom-fast ice sheet in t he nearshore zone. This overflow water will spread offshore and drain through tidal and therma l cracks or seal breathing holes in the ice sheet. High velocity currents caused by t he draining water at the seafloor can scour seabed sediment leaving a circular or linear scour in the seabed, which can potentially expose and impose high current loads on a pipeline (Figure 4-31 ). These phenomena are known as “strudel scours” and they usually occur in 6 to 30 ft (2 to 9 m) of water offshore from river deltas.
If a strudel scour happens on top of a pipeline a lignment, there is the possibility that the scour could result in an unacceptable pipeline span. In extreme condi tions, the pipeline span could possibly experience vo rtex-induced vibration (VIV) due to the water velocity of the strudel flow. An analysis to assess the pi peline span can be carried out using analytical or finite element methods.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 258 of 339 Rev. 0 Figure 4-31: Strudel Scour (Courte sy of Minerals Management Service)
Ice Ride-Up, Grounding, Pounding & Wallowing

Sheet ice at the coastline c an be driven ashore and ride up ont o the beach. Shoreline pileup can also occur, created by the rafting/stacki ng of the failed ice blocks onto each other. The design of a buried offshor e pipeline which transitions to an aboveg round pipeline should account for the setback distance as the result of ice encroachment.

Ice keels can be driven ashore and become grounde d over a pipeline or rubble piles can form in place over a pipeline. “Ice pounding” refe rs to the occurrence of a small ice features bouncing up and down on the seabed in dynamic response to wave loadings. “Ice wallowing” is described as local seabed erosion around gr ounded ice features due to current flow disturbances and wave-induced moti on of the ice feature displacing water and sediment. These potential loading scenarios should be considered dur ing pipeline design.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 259 of 339 Rev. 0 Shoreline Erosion & Sediment Transport

Shoreline erosion must be cons idered in the determination of the setback distance of the point where a buried offshore pipeline tran sitions to an aboveground pipeline. Average long-term shoreline erosion rate, as well as the maximum short-te rm rates, should be considered. Gravel backfill, surcharge and re-vegetation may be required to prevent accelerated erosion at the shore crossing.

While sediment transport is not a design issue unique to arctic environments, it may result in an undesirable pipeline condition. The loss of backfill could result in larger ice keels intruding into an area where the water dept h has been increased or it may become susceptible to upheaval buckling. In extreme cases, the pipeline c ould become exposed, either through upheaval buckling or loss of soil cover, which puts the pipeline at increased risk of damage from ice. The pipeline design s hould consider the long- term stability of the seabed/backfill.
Trenching & Backfill

Design issues related to ice gouging, str udel scour, frost heave / thaw settlement, upheaval buckling and sediment transport will determine pipe line trenching requirements in terms of depth of cover and backfill thickness. Pipeline protection is derived from both lowering the top of pipe below the surrounding seabed (depth of cover) and burial (backfill thickness).
Backfill materials, optimally, will consist of the soil (non-froz en) excavated from the trench. When native soil is used as bac kfill, it will be remolded and wi ll be a composite blend of different materials excavated bet ween the mudline and the base of the trench. This must be accounted for in the pipeline design, especially in the consideration of upheaval buckling and sediment transport potential. Se lect backfill, gravel, gravel filled bags or concrete mats may be considered in predetermined location s where native backfill is not adequate.

Limit State & Pr obabilistic Design
Offshore arctic pipelines, which rely on trenchi ng and backfilling for protection, need to be deep enough to withstand environm ental design conditions, e.g., ice gouging, but not so deep as to be impossible to construct or make the project uneconomical. A solution, therefore, is to design the pipeline based on strain rather then stress.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 260 of 339 Rev. 0 Limit state design is an approa ch whereby the various potent ial failure mechanisms are evaluated. The pipeline failure mechanism that has the lowest initiati on strain is then selected as the governing condition and will dict ate the design strain. Limit state strain criteria can be used in the design for non-cyc lic pipeline displacements, e.g., thaw settlement, subgouge soil deformation and island se ttlement). It is apparent that if the pipeline strain can exceed that allowed by a stress-based des ign, the pipeline would not need to be buried as deep to meet design criteria during ice gouge events (for example), as it can be subjected to higher loads.
Probabilistic based design procedur es can be used to optimize pipeline design. Elements of this type of design could include, for ex ample, ice contact risk, ice gouge dimensions, soil properties, subgouge deformations, etc. to assess the pipeline loading. The pipeline resistance or strength could also be defined in terms of probability distribution functions associated with pipe dimensions and material properties.

Leak Detection
The use of thick walled pipe, omission of s ubsea valves and fittings and a we ll-planned inspection program minimize the potential for offshore pipeline leaks in the Arctic. Small leaks, however unlikely, whic h might normally be detectable on the open water surface during personnel/supply transport to and from the island/platfo rm, could go undetected for several months under ice cover. Therefore, it might be expected t hat the pipeline system would be required to include a leak detection system to alert the operators of a possible pipeline leak. Such a leak detection system ma y be required to meet a minimum detection threshold over a set period of time to be in accordance with codes and standards and/or to meet federal or regi onal requirements.
Pipeline / Flowline Architecture
The pipeline/flowline configurat ion can significantly affect design, construction planning, operations, maintenance, and repair. Configurations can include a single wall steel pipeline, pipe-in-pipe system, a flowline bundle (open or closed bundle system), insulated pipelines and flexible pipelines.
4.11.1.2 Feasibility of Selected Scenarios

The main considerations with respect to a pi peline design in the Arct ic are strudel scour, thaw settlement of permafrost, upheaval buckling and ice gouging.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 261 of 339 Rev. 0 The first two design issues happen over very limited distances of t he nearshore portion of the pipeline and have been addre ssed in existing pipeline design, e.g. Northstar and Oooguruk. The third issue, upheav al buckling, can happen in any region of the pipeline if conditions are conducive to buckling. Insta llation procedures have been implemented on past projects (Northstar) to minimize the risk of upheaval bu ckling (considered limits on installed pipeline profile, use of select backfill or additional weight over imperfections). Therefore, it is generally felt that these three considerations can be designed for in future projects and for any of the selected location scenarios.

Strudel Scour

As indicated earlier in the r eport, a number of site-specific strudel scour surveys have been conducted for and in the vicinity of the Nort hstar Project (see, for example, Coastal Frontiers Corporation, 1999). Sp an analysis indicated that t he pipeline remained elastic and within design code limits in the ca se of a strudel scour event t hat exposed the pipeline. The potential for vortex-induced vibrat ions of the Northstar bundle wh en exposed to a current jet resulting from the strudel was also evaluated and found to be nonexistent.
The change in strudel scour regime after st artup of operations ha s been investigated by Leidersdorf et al. (2006). Annual monitoring of the strudel scour s formed in the vicinity of the Northstar pipelines indicate that pipeline operations may locally in crease the probability of scour formation. Circular scours up to 14 ft (4.3 m) deep and up to 105 ft (32 m) in diameter were recorded in t he Northstar area. The maximu m linear scour was 276 ft (84 m), but this scour only had a dept h of 1.6 ft (0.5 m). Maximum scour depths were found in the 6.5 to 13 ft (2 to 4 m) wa ter depth range. The potential ca use of the increase in the frequency of scour formation over the pipelines may be the local thinni ng of the ice sheet above a buried warm pipeline in shallow wa ter depths (Leidersdorf et al., 2006).
Pipelines from any of the Alaskan OCS location scenarios would need to pass through shallow water on a shore approach and could pot entially be subject to strudel scour (depending on proximity to rivers and the overfl ood limits for a particular area). However, indicators are that this can be accommodated in design and operations as in the case of the Northstar pipelines.

Thaw Settlement
Thawing of ice bonded permafrost, if present al ong the pipeline rout e, can result in differential thaw settlement which could s ubject the pipeline to high strains. On theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 262 of 339 Rev. 0 Northstar project, the maximum thaw induc ed settlement potential in the ice-bonded permafrost region was found to be approximately 2 ft (0.6 m) close to the onshore transition within a few hundred feet from shore (Paulin et al., 2002). An operational limi t state bending strain criterion was used to confirm the pipelines would be safe under the maximum predicted differential thaw settlement.
Pipelines from any of the Alaskan OCS location scenari os could potentially pass through zones of ice bonded permafrost. Using the Norths tar pipeline as an ex ample, differential settlement up to a certain magnitude can be accommodated in design and operations. If the differential settlement is beyond a certai n value, other design solutions might be considered, such as overexcavation of ice rich soil under the pipeline, pipeline insulation, etc.
Ice Gouge

Ice gouge is an issue that has been studied or c onsidered in conceptual pipeline design for decades. A number of buried offs hore pipelines are being succ essfully operated in ice gouge environments, including projects in th e Alaskan OCS (Northstar, Oooguruk).
Trench depths will increase in areas of more se vere gouging. In nearshore zones (less than 30 ft (9 m) water depth), pipelines might be expected to be buried not as deep as in deeper water due to the less severe gouging. In t he 65 to 130 ft (20 to 40 m) water depth range, ice gouging might be the most si gnificant and result in the dee pest burial. In deeper waters, the gouge depths begin to taper off, as do the bur ial depth requirements. Offshore pipelines will be required to be trenched to approximat ely 165 ft (50 m) water depth in areas subjected to ice gouging.
Ice gouging is only one factor in the overa ll determination of buri al depth and must be examined in conjunction with ot her factors such as thaw settlement, upheaval buckling, strudel scour, pipeline stability and flow assur ance. However, as mentioned above, these other aspects can likely be acco mmodated, given successful oper ation of projects in the shallow waters of the Beaufor t. The ice gouging issue warrant s further discussion (below).

Ice gouge depth distributions can be estimat ed using ice gouge data, e.g. depths and widths. Annual ice gouge recurrence rates can al so be estimated where repetitive mapping surveys have been carried out. If r epetitive mapping surv ey data is not available, the age of gouges cannot be determined and data may not accu rately represent the current ice gouge regime. The same can be said for the location from which data is used. If site-specific dataIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 263 of 339 Rev. 0 is not available, the use of ic e gouge data from other regions may not accurately reflect the conditions at the area of interest.

However, in an initial screeni ng study where there might not be adequate site-specific data, insight may be gained by looking at regional ice gouge datasets. Unfortunat ely, most of the published information from the Alaskan OCS is over 20 years old and there has been little attempt (except for specific projects) to collect data which might be used during screening studies.
A review of existing public domain ice goug e data available in pub lic domain study/survey reports from the Beaufort, Chukchi and Beri ng Seas has been carried out. No statistical gouge data was found applicable to the Bering Sea. Information found included gouge data of known and unknown age and, where availa ble, generalized discussions of ice gouge processes and observances. Ice gouge depths were generally observed to increase with increasing water depth, with the deeper ice gouges occurri ng beyond the 65 ft (20 m) isobar. Analysis of ice gouge width/depth relati onships and distributions from the study areas has indicated a general trend of decreasing gouge wi dth with increasing gouge depth.

Beaufort Sea
Summary plots of ice gouge depth vs. water depth for combined k nown and unknown age data and known age gouge data only are pres ented in Figure 4-32 and Figure 4-33 respectively, from ice gouge data reported from the Alaskan Beaufort Sea. References for the data used in these plots include Barnes et al. (1978), Rearic and McHendrie (1983) and Weber et al. (1989).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 264 of 339 Rev. 0 Ice Gouge Depth vs. Water Depth - Alaskan Beaufort Sea - Combined New & Unknown Age Data

0 1 2 3 4 5 6

0 10 20 30 40 50 60 70 Water Depth (m)Gouge Depth (m)

Figure 4-32: Ice Gouge Depth vs. Water De pth, Combined New & Unknown Age Gouge Data from the Alaskan Beaufort Sea
The data from Figure 4-32 are of unknown age and, therefore, it is not known if the ice/gouge regime at the time of creation is comparabl e to what it is today. Based on this information, gouges up to 18 ft (5.5 m) dee p have been surveyed. Most gouges in water depth within 65 ft (20 m) are less than 6.6 ft (2 m). Beyond this water depth, as expected, gouge depths then increase signific antly up to about 130 ft (40 m) water depth. After this point, ice gouge depth decreases with increasing water depth to near zero at 200 ft (60 m) water depth.
New gouge data available for the Beaufort is lim ited to less than appr oximately 80 ft (25 m) water depth. Of the data available, gouge dept hs are generally less than 5 ft (1.5 m).
Pipeline burial depth for this ar ea (any of the location scenarios) would be a function of not only gouge statistics, but also design return period, pipe line geometry, line pipeIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 265 of 339 Rev. 0 characteristics, allowable strain limits, soil properties and assumed subgouge deformation field.

Ice Gouge Depth vs. Water Depth - Alaskan Beaufort Sea - New Gouge Data Only

0 0.5

1 1.5

2 2.5

3 3.5

0 5 10 15 20 25 30 Water Depth (m)Gouge Depth (m)

Figure 4-33: Ice Gouge Depth vs. Water Depth, Known Age Gouge Data from the Alaskan Beaufort Sea

Chukchi Sea

There are less data available in the public domain for the Chukchi Sea as compared to the Beaufort Sea, where inner s helf ice gouge data and reports have been reviewed as part of the current study. All of the data found was for gouges of unknown age. Figure 4-34 provides a summary plot of unknown age ice gouge depth vs. wate r depth data for gouge observances in the Chukchi S ea. References for the data presented in this plot include Toimil (1978) and Phillips et al. (1988)
The data from Figure 4-34 are of unknown age. Again, significant gouges (up to 15 ft or 4.5 m) have been identified. Gouges in water depth within 65 ft (20 m) are less than 8 ft (2.5 m) deep. Beyond this water depth, as expected, gouge depths increase up to about 130 ft (40IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 266 of 339 Rev. 0 m) water depth. After this point, ice gouge dept h decreases with increasing water depth to near zero at 200 ft (60 m) water depth. Pipelin e burial would be a function of the same parameters as presented above in the Beaufort Sea Section.

Ice Gouge Depth vs. Water Depth - Chukchi Sea - Unknown Age Gouge Data Only

0 0.5

1 1.5

2 2.5

3 3.5

4 4.5

5

0 10 20 30 40 50 60 70 Water Depth (m)Gouge Depth (m)

Figure 4-34: Ice Gouge Depth vs. Water Dept h, Unknown Age Gouge Data from the Chukchi Sea
Bering Sea
Research of references in the public domain has limited ice gouge information relevant to the Bering Sea. No statistical /tabulated ice gouge data was found.
A review of geophysical records from a 1981 survey has indicated the presence of thousands of scours on the north Aleutian shelf of the Beri ng Sea (Molnia et al., 1983). Bering Sea gouge observations indicate depths up to 16 ft (5 m), widths which range from a few meters to greater than 820 ft (250 m) and lengths in excess of 985 ft (300 m) for gouges of unknown age (Molnia et al., 1983). Gouge orientations have been found to vary from shore-parallel to s hore-perpendicular and vary in gouge trajectory. Ice gouges areIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 267 of 339 Rev. 0 observed in the northeastern Be ring Sea in water depths rangin g from 16 to 100 ft (5 to 30 m) (Thor and Nelson, n.d.).
Various ice gouge features have also been identif ied in Norton Sound of the eastern Bering Sea, including single, ice isl and and pressure ridge raking (mu ltiplet) gouges. Single-keeled (solitary) ice gouges have been observed to ubiquitously dominate within Norton Sound, where gouge depths are r eported to a maximum of 2.5 ft (0 .75 m) deep (Thor et al., 1977). Single-keeled ice gouge widths have been observ ed to range from 16 to 200 ft (5 to 60 m), although the 49 to 82 ft (15 to 25 m) gouge width is most common (Thor et al., 1977). Ice island gouge widths of 250 to 330 ft (75 to 100 m) are reported, while pressure ridge raking formations were observed to ran ge from 165 ft (50 m) to several kilometers wide (Thor et al., 1977). The maximum density of ice gouges o ccurs in central Norton Sound near the Yukon Delta in water depths rang ing from 33 to 50 ft (10 to 15 m) (Thor et al., 1977; Thor and Nelson, n.d.). Ice gouge dens ities of up to 195 gouges/mile 2 (75 gouges/km 2 ) have been observed near the Yukon Delt a. Little ice gouging is obser ved in water depths less than 33 ft (10 m) or greater t han 65 ft (20 m) (Thor and Nelson , n.d.). Gouge orientation trends in Norton Sound occur in both the general north – south and east – west directions (Thor et al., 1977; Thor and Nelson, n.d.). The age of these observances is unknown.
Pipeline burial would be a f unction of the same parameters as presented above in the Beaufort Sea Section.
4.11.2 Constructability
4.11.2.1 Winter Construction vs. Open Water Construction
Offshore Arctic equipment and logistics require ments for summer and winter construction are quite different. Construction methods fo r summer (open water) and winter construction (from ice) need to be evaluated to identif y the best potential method with respect to probability of success, logistics cost and schedule.

Winter construction is primar ily affected by the ice envi ronment. Construction cannot commence until the ice is of sufficient thickne ss and stability to support the weight of the equipment required to begin ice thickening. Ice ridges within t he ice sheet could also affect construction. However, winter construction elim inates some of the environmental issues associated with summer construction. Given the requirement for a stable landfast ice surface from which to work, the distance offshore that winter construction might be applicable is restricted.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 268 of 339 Rev. 0 During an open-water construction scenario, acti vities and their timing may be primarily affected by considerations for environmental prot ection and the seasonal extent of ice-free water (which varies from year to year). To protect the tundra, onshore work is not typically planned for the summer which restricts access to shore-based staging areas from the sea or air. Offshore activities may be restrict ed due to environmental concerns. However, marine activities are permitted if care can be taken to avoid effects on wildlife (this often includes a conflict avoidance agreement with local sustenance activities). Any summer construction season will be short in duration and there could be ice incursions into the construction area during open water, which requires a management plan.
When considering open-water activities, consi deration also needs to be given to the Jones Act or Coastwise Laws and potential requi rements for US owned, operated and flagged vessels for the Alaskan offshore. This law coul d significantly influence decisions regarding the preferred construction scenari o for projects off of Alaska.
4.11.2.2 Permafrost & Trenchability
The general assumption is that Arctic offs hore pipelines will need to be trenched for protection and seabed trench excavati on will be a critical activity for the pipeline installation schedule. Given the nature of t he arctic environment, there is a possibility that permafrost could be encountered during tr enching, regardless if a su mmer trenching or winter trenching program is planned. Either way, the trenching te chnique must be capable of trenching through permafrost.

Soil conditions must be cons idered when evaluating trenching options to come up with the most cost effective trenching spread configur ation. The presence of high strength silts and clays or dense sands will affe ct trenching production rates. It is important that the trench remains open until the pipeline is placed in t he trench, regardless of whether winter or summer construction is carried out.
4.11.2.3 Trenching Equipment
Trenching equipment must be com patible with arctic condition s. The equipment must be robust and able to operate in a summer or winter arctic environment, depending on the execution plan, and able to creat e a suitable trench profile in site-specific soil conditions.

Ice-based excavation could be carried out usi ng hydraulic backhoes, clamshell buckets or similar methods. Conventional excavation is a proven but time-consuming method. TheIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 269 of 339 Rev. 0 reach of an extended or long-reach backhoe is limited practically to a combined water and trench depth of approximately 50 ft (15 m). Special consideration may need to be given to areas where ice-rich or bonded pe rmafrost may be encountered.

Most of the excavated trench soil would need to be temporarily stored on the ice before backfilling. The material excavated from fl oating ice would be trucked off and stored temporarily on bottomfast ice in a designated ar ea. If stored on floating ice, consideration must be given to sinking or creep (deflection) of the ice. Once a sect ion of the pipeline is installed in the trench, and its profile verified, backfilling usi ng recently excavated trench spoils would commence.
Generally, floating trenching equipment has not been desig ned for arctic conditions. Floating vessels used in trenching or in support of trenching during open water may be subject to ice incursions. Equipment that is not designed for such an environment may be subject to damage under these conditions. Ice wh ich does not come in direct contact with floating equipment could still affect constructi on if the ice were to come in contact with anchor lines. The need for ice management vesse ls in support of tren ching operations will need to be considered during construction planning.
Several trenching techniques could be used during the summer. Some are applicable only to pre-trenching, i.e., before t he pipeline is installed, whereas others are best suited to postpipeline installation. These methods include, but are not limited to:

• Conventional excavation (hydraulic backhoes, clamshell buckets, etc);

• Hydraulic dredging (cutter suction dredges and trailing suction hopper dredges);

• Plowing;

• Jetting; and,

• Mechanical trenching.
Cutter suction dredges would have a water dept h limitation of approxim ately 115 ft (35 m), while a large trailer suction hopper dredge could reach to approximately 460 ft (140 m). Protection of the installed pipe line could be provided by pre- or post-trenching techniques. However, pre-trenching or post-trenching immedi ately following installation would mostIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 270 of 339 Rev. 0 likely be required for arctic conditions, sinc e the pipeline would otherwise rest on the seabed and be potentially exposed to the ac tion of ice moving into the area.
Historically, plows (Figure 4-35) have achiev ed a trench bottom depth on the order of 5 to 6 ft (1.5 to 1.8 m) with an average plowing speed on the order of 660 ft/hr (200 m/hr) (Brown and Palmer, 1985). Some multiple-pass plows have been fabricated that should have the capability of achieving a trenc h depth of 6.6 ft (2 m) if the soils are soft enough to allow plowing but strong enough to rema in stable until the pi peline touches down in the bottom of the trench. Multiple-pass plows capable of excavating a trench 13 ft (4 m) deep have been investigated and tested on a small scale, but fu ll-scale plows with this capability have not been fabricated. Brown and Palmer (1985) have indicated that multi-pass plows for arctic pipelines capable of trenching 13 to 20 ft (4 to 6 m) are feasible, depending on geotechnical conditions. Generally, plows tend to be quite la rge; approximately 110 to 330 tons (100 to 300 tonnes) dry weight and 30 to 90 ft (9 to 27 m) in length. Several plows have been fabricated for previous pipeline projects and t hese may be available for lease or purchase for arctic projects. The shore and island approaches would need to be excavated using other means and special consi deration may need to be given to areas where ice-rich or bonded permafrost may be encountered.

Figure 4-35: Typical Subsea Plow (C ourtesy of SMD Hydrovision, 2007)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 271 of 339 Rev. 0 Jetting (Figure 4-36) involves pulling a sled along the top of a pipeline after it has been installed. Water under high pressure is used to li quefy the soil, and air is used to lift it from under the pipeline. The pipeline lo wers itself to the bottom of the trench as the jet sled advances.
To achieve a depth of cover of 9.8 ft (3 m) in most soil conditions, the jetting sled would have to be towed over the pipeline several time s, thereby increasing the risk of damage to the pipeline. Due to the very large fluidized sediment load created, env ironmental concerns may be a significant issue. Another issue with jetting is the managem ent of the excavated material. The spoils are in a fluidized form and if they must be returned to the trench to meet the design backfill requir ements, soil may need to be barged in to backfill the pipeline.

Figure 4-36: Typical Jet Sled (C ourtesy SMD Hydrovision, 2007)
Mechanical trenching is commonly used for burying cables and umbilicals, and has been used on multiple pipeline trenching projects. Ty pically, this method is used in open water conditions and supported by a large marine vessel. The trenchers typically rely on hydraulic power to propel the caterpillar tracks (Figure 4-37) used for propulsion and to operate the cutting equipment. The hydraulic power require ments make these trenchers very large, often requiring large buoyancy tanks to keep t he trencher from sinkin g into the soil and collapsing the trench, and to facili tate handling of the machine.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 272 of 339 Rev. 0 Mechanical trenching to achieve a depth of cover of 6.6 to 9.8 ft (2 to 3 m) is considered to be at the limit of what present installation equipment can achieve for soft soils. Another potential issue with mechanical trenching is the management of the excavated material. If it must be returned to the trench to meet t he backfill requirements, soil may need to be barged in to backfill the pipeline.

Figure 4-37: Typical Subsea Mechanical Trencher (Courtesy of Rocksaw International, 2004)

4.11.2.4 Pipeline Installation

Installation equipment must be suitable for use under the appropriate environmental conditions regardless if summer construction or winter constructi on is planned. Similar general considerations apply as noted fo r trenching equipment operations.
Winter construction using a through-ice me thod relies on techniques and equipment that are proven. Ice-strengthening and ice-cutting techniques are well understood and have been applied on the Northstar and Oooguruk projects for pipelin e installation. Backhoes are used universally for land and ma rine trenching within the limits of their capabilities. A potential disadvantage is that fl oating ice has a limit to its load bearing capacity and the combined weight of equipment and pipe must be considered before electing to use this method. This technique requires a relatively stable ice sheet and the combined water and trench depth is limited to appr oximately 50 ft (15 m).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 273 of 339 Rev. 0 During installation, the pipe is welded together into a conti nuous pipe string, either onshore or along the ice slot. If strings are made up onshore or in the nearsh ore, after they are welded they are towed over the ice and posi tioned alongside the ice slot. Tie-in welds would be made to join the pipeline strings toget her into a continuous length before it is lowered into the trench through the slot. Tie-in welds would be X-rayed or ultrasonically inspected before the field joint coating is applied.

Floating pipelay vessels have almost exclus ively been designed for ice-free operation. Floating vessels used for installation or in suppor t of installation in an arctic environment may be subject to ice incursions or damage. A pipeline off the end of a stinger or coming off a reel during laying may also be subj ect to potential damage from ice.
Ice conditions in the Beaufort Sea are highly variable. In some years, open water may exist for half the year, while in other years the ice does not recede at all. In addition, there are no safe havens in Alaskan waters into which a ve ssel can retreat from severe ice conditions. The decision may be taken that all vessels used on a particular project be of Ice Class, capable of navigating in ice under their own power and over-wintering in the Arctic.
4.11.2.5 Trenching & Backfill
After laying the pipeline in the trench, the pl acement of backfill mate rial in the trench and over the pipe may be required. This is a normal activity associated with pipeline construction and typically returns the trench exca vation spoils back into the pipeline trench.

In a winter construction scenario, where the trenc h is excavated through a slot in the ice, the trenching spoils will be brought to the ice surface. As the backhoe digs soil out of the trench, it will place these spoils to the side of the ice slot or directly into a dump truck for transport to an appropriate location.
Backfill should be placed over the pipelines as soon as pr actical after installation, which minimizes the amount of time the spoils are exposed to fr eezing temperatures. Frozen spoils create some challenges for construc tion as they may not spread easily over the pipeline trench cross-section or large pieces of frozen spo il may damage the pipeline.
In the simplest cases, the soil from the tr ench is left along both sides of the trench and is available for a backfill plow to pull the material back into the trench over top of the pipe. If the trench has been excavated using conventiona l excavation or a trailing-suction hopper dredge, the excavated material can be stored and reclaimed for backf ill. However, the useIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 274 of 339 Rev. 0 of a cutter suction dredge for digging the tr ench may create a problem for the backfill operation, as these dredges normally either “rai nbow” material from the trench or discharge it through a floating hose. However, it possibly could be stockpiled and retained for backfill.
If other mechanical trenching te chniques are considered for trenching the pipeline, the excavated material may or may not be availa ble for backfilling. If the pipeline has been jetted-in, the majority of the excavated ma terial will be dispersed and may necessitate importing backfill.
If the trenching is conducted post-lay, after the pipeline installation backfilling can be accomplished by plowing, jetting or mechanical trenching. In the case of these methods, consideration needs to be given to the ability to move the backfill from the trenching machine back over top of the trenched pipeline.
The backfill on top of the pipeline is expected to provide the resistance needed to hold the pipeline in the installed positi on. The critical locations for the backfill thickness along the aslaid pipe profile are near the crests of local high points or overbends to resist upheaval buckling. If backfilling with native material wil l not meet requirement s in terms of uplift resistance at a prop/overbend, the pipeli ne may need to be lowered or gravel/gravel bags/concrete mats used to provide additional uplift resistance.

4.11.3 Capital Costs Capital costs of an offshore pi peline would effectively be made up of material costs and installation costs. Material co sts would be based on the market price of line pipe, coatings and so on.
For relatively short pipelines located nearshore, installation from the ice would be based on costs of spreads to thicken ice, excavate a trench, weld up the pipel ine, lay the pipeline and backfill the trench. Such activities have been carried out on previous projects (Northstar, Oooguruk). Costs could be obtai ned from contractors in Alaska experienced in such construction activities.
Open water installation costs are less definitive and will depend on the trenching/installation/backfill methods select ed. There are other variables that will potentially affect capital cost, including R&D /field trials of selected equipment, schedule, weather, presence of ice during construction, av ailability of equipment that is Jones Act compliant, and required upgrades to equipment to work in an Arctic environment.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 275 of 339 Rev. 0 Installation costs can be estimated based on a best-case scenario, assuming that equipment can be found that is su itable for use in the Alaskan OCS. Again, it is stressed that is highly likely that that there would be additional cost s associated with getting this equipment ready for an Arctic deployment. In the worst case, new equipment may have to be designed and built in order to exec ute projects in the Alaskan OCS.
Pipeline trenching costs using a floating dre dge can be estimated based on a current cost of $250,000 per day for large dredger (plus mo bilization/demobilizati on costs). Actual production rates would depend on the depth of trench requir ed and site-specific soil conditions. Rates of 0.3 to 0. 6 miles per day (500 m to 1 km per day) may be typical, extending to 1.2 miles (2 km) per day for sha llow trenches in relatively soft soils. Rates of 165 ft/hr (50 m/hr) might be typical for a pl ough, jet sled or a mechanical cutter.
A trenching spread could vary from as simple as a tug to as complex as a lay barge. A typical spread day rate could approach $200, 000 per day (plus mobilization/demobilization costs). Anchored lay barges could cost $250,000 per day, while a DP (dynamic positioning) vessel could approach $400,000 to $500,000 per day . Other vessels would be required for ice management, survey, support, supply, etc.

4.11.4 Environmental Considerations Offshore pipelines will be required to be trenc hed to approximately 165 ft (50 m) water depth in areas subjected to ic e gouging (see Ice Gouging of Section 4.11.1 .1). The overall depth of the trench will be a function of the ice gouge protecti on and other design requirements, diameter of pipeline and an y overdig to ensure pipeline position below mudline.

Pipeline construction could o ccur either during the summer open-water season or from ice during winter, when landfast ice has stabilized. The actual construction execution plan would depend on the length and location of the pipeline, project schedule, available equipment, etc. Due to the natur e of burying a pipeline, some seabed disturbance will take place along the right of way. Depending on the met hodology used, areas may be required for spoil storage or excess spoil disposal. Trenching and backfilling will create some turbidity and some habitat alteration associ ated with offshore pipe line construction and installation activities. It is anticipated that coar se sediment would settle to the seafloor very near the trench, but that a plume of fine su spended sediment would drift several miles (MMS, 2003).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 276 of 339 Rev. 0 4.11.5 Operations Pipeline leak detection monitoring is an import ant aspect of pipeline operations that will need to meet regional requirement s. The State of Alaska requi res all transmission pipelines to subscribe to a “best available technology” ( BAT) evaluation regardin g leak detection. The criteria for a BAT evaluation ar e prescribed by the Alaska Department of Environmental Conservation and include availability (i.e., prov en technology), compatibility with existing SCADA and hardware, transfer ability, effectiveness, etc.
There are a number of different approaches that could be used to monitor an oil or gas pipeline for leaks. Pipeline int egrity checking and leak detecti on for arctic subsea pipelines can generally be categorized as follows (with no implied orde r of preference):

• Volumetric flow measurement;

• Pressure monitoring;

• Pressure measurement with computational analysis;

• External (adjacent to pipe) oil detection;

• Remote sensing (airborne or satellite);

• Geophysical sensing techniques;

• Pressure or proof testing;

• Pipe integrity checking (i.e., smart pigging);

• Visual inspection; and

• Through-ice borehole sampling.
Many of these are consider ed proven technology and other s are under development. There are many variants of the above that are either experimental or are being developed. In addition to the principal leak detection methods cited above, there ar e other possible leak detection strategies that involve remote sens ing techniques, fiber optic sensors, acoustics and electrical detection devices.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 277 of 339 Rev. 0 4.11.6 Maintenance & Repair 4.11.6.1 Monitoring & Maintenance
A pipeline monitoring/inspection philosophy is important to the succe ssful operation of an arctic offshore pipeline. A go od inspection plan optimizes the amount of useful information that can be gained from inspection surveys and pigging runs, and ta kes into account the criticality of the various system s. If inspection results are sati sfactory, it can generally be inferred that the system is fit for service. W hen degradation is discov ered, these areas may be designated for further evaluation or the situation may be severe enough to warrant immediate corrective repairs.
During detailed engineering, a recommended inspection plan and schedule should be developed. As the result of inspection, a pi peline’s condition may be characterized as follows: conditions that require no action; conditions that require more rigorous monitoring schedules; or conditions that require imm ediate intervention. Such conditions are determined based on pigging test data and route survey data.
As suggested earlier in this report, annual moni toring of strudel holes formed in the ice sheet may be an important inspection activity . Annual monitoring of the strudel scours formed in the vicinity of the Northstar pipelines indicate that pipeline operations may locally increase the probability of scour formation. The potential cause may be the local thinning of the ice sheet above a buried, warm pipeline in shallow water depths.

4.11.6.2 Repair
The logistics for pipeline repairs largely depends on the season and sea ice conditions. Detailed repair procedures should be develo ped during detailed design and should consider scenarios that could occur at any time of the year. Envisioned repair techniques for offshore sections of arctic pipelines draw upon conventional offshore pipeline repair techniques and construction techniques used for conventional and arctic offshore pipelines.

Normally, it is assumed that welded perm anent repairs would be the desired repair strategy, given the potential for high strain loading events. Mechanical pipeline repair systems may be used is if ther e is not enough time available during the remainder of the summer or winter season to make a permanent welded repair. In this case, a temporary repair might be carried out in order to avoid a long shutdown period.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 278 of 339 Rev. 0 In developing pipeline repair strategies, consi deration also needs to be given to the potential location of the leak, and the extent (length) of damage. A repair to a leak under the bottomfast ice or damage which is localiz ed will be easier to repair than damage in deeper water or which extends over one or more pipe joint. Depending on the extent of the damage, a temporary repair may be the first step with a permanent repair made when environmental conditions are more suitable.

Seasonal considerations must also be taken into accoun t. Given the circumstances, temporary repairs may have to be made, fo llowed by a permanent repair when ice and weather conditions have improved. In general , repairs could be conducted during open water using a repair barge or shallow-draft vessel, or during winter from the ice or using Ice Class vessels.

Most repair techniques can be used both from marine equipment and, wi th modificati ons, from a stable ice sheet of sufficient thickness. However, so me repair techniques are compatible only with specific support equipment. Repair meth ods may generally be categorized as follows:

• Welded repair with cofferdam or berm;

• Hyperbaric weld repair;

• Surface repair;

• Tow-out of replacement string (welded in place or mechanical connectors);

• Spool piece with mechanical connectors; and,

• Split sleeve or other mechanical repair device.

Although mechanical repair devices have been used worldwide for permanent pipeline repairs, they have not been proven for a pe rmanent arctic offshore repair where the pipeline may subsequently be subjected to signifi cant strains. The short term and long-term acceptability of mechanical r epair systems should be evaluat ed during detailed design. However, mechanical repair devices have the advantage that they are relatively easily deployed compared to a pipeline cut out and replacement.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 279 of 339 Rev. 0 4.11.7 Abandonment & Decommissioning Decommissioning procedures for offshore inst allations that have reac hed the end of their useful life are usually inclu ded in governing legislation. There are also international agreements relating to decommissioning that address removal and d eep-sea disposal. For example, the International Ma ritime Organization (IMO) ha s developed Guidelines and Standards for the remo val of Offshore Insta llations and sets out conditions to protect navigation and maintain safety.
As per the Northstar development EIS (MMS, 1999), abandonment of development and production facilities could range from complete remo val of all facilities to a requirement that most facilities be left in place for future us e. Actual requirements would not be stipulated until near the end of t he project, when potential future uses can be better identified. Buried offshore pipelines would be difficult to remove and activities associated with removal may have environmental considerati ons. Therefore, the decision might be made to pig the pipeline of any residual hydroc arbons and abandon the line in place.

4.12 Export Terminals

4.12.1 General Requirements For the purposes of this report, a marine terminal is defined as a comp lex of structures and equipment for loading of hydroc arbon products, either pumped to a tanker from a storage facility located onshore or direct ly from a processing facility.
In most cases, marine transportation of hy drocarbon products starts with large storage facilities located onshore. The land-based components of these facilities (tank farms, loading pump stations, treatment plants, etc.) in the Arctic ar e basically the same as those in the moderate climate. The ma in difference is primarily in providing the conditions and the process equipment to allow continuous operation under low temperatures, icing and snowfall conditions. Flow assurance is a crit ical consideration for arctic and sub-arctic locations. Consequently, to ensure smooth operations , an important aspect of any terminal concept is the need for proper insulation and heat-tracing tec hnology on piping and pipelines.
Hydrocarbons may be loaded on tankers at sea or in the vici nity of production platforms, either from the platform storage tanks or from a FSU (Floating Storage Unit). The FSU may also be used in the nearshore for temporary st orage or trans-shipment loading. Several recent applications of these c oncepts in the Arctic were descr ibed in Section 3.2.1.2 (theIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 280 of 339 Rev. 0 production platform offloading at Prirazlomnoy e field and the FSU in Kolsky Bay in the Barents Sea, Russia).

Particularly challenging in t he Arctic is the offloading of pr oducts to tankers because this operation will need to be conducted in floating ice if year-r ound operations are going to be conducted.
4.12.2 Technical Feasibility The technical feasibility of marine terminal s in Arctic areas has been established through successful experience in a wide range of port facilities (Tsinker, 1995). These include the port structures and terminals in Nome, Cook Inlet, Anchorage and Valdez (Alaska), Godthab and De Long (Greenland), Nanisivik (N orth Baffin Island, Canada), St. David de Levis and Caps Noirs (Quebec, C anada), Norwegian and Russian ports in the Barents Sea (Murmansk, Arkhangelsk), and Magadan and Petropavlovsk (Ok hotsk Sea, Russia). The most recent examples are t he large Oil Terminal in DeKast ri and the LNG Terminal in Prigorodnoye (Sea of Japan), Russia.
The common specific feature, as well as t he main challenge in all of these ports and terminals projects, is that the marine struct ures are to be operated and maintained under adverse ice conditions:

• Very large lateral loading may be g enerated during float ing ice/structure interaction both in the crushing and in the impact mode.

• Significant uplift and/or additional compression loads may be generated during tide variations due to ic e adfreeze to the structure.

• The accelerated build-up of ice occurs on the structure due to tidal action, as well as due to wind- or wave-generated icing.

• The moving ice causes abrasion of stru ctural members. In addition, concrete is subjected to cycles of freeze-and- thaw deterioration and steel to the potentially adverse effects of low temperatures.

• Floating ice not only directly affect s the terminal structures, but also significantly complicates vessel operations:IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 281 of 339 Rev. 0 • Ship traffic is to be restricted to ce rtain lanes, offshore, in the approach channel and inside the port maneuvering areas. However, this protection measure may become insufficient duri ng occasional winter and spring breakups when large masses of floating ice ent er the limits of ice-free shipping lanes.

• Berthing operations ma y become potentially hazardous because ice growth on the fenders eliminates their ability to deflect and absorb berthing energy.

• Large quantities of brok en ice may create conditions where the vessel is unable to approach the dock unless floating ice is removed from the berthing

area.

• The application of conventional (and a ffordable) floating navigation aids (buoys) becomes virtually impossible in heavy ice conditions. The problem is usually resolved by installation of more expensive onshore navigation systems.
The loads generated through ice/stru cture interaction, in most cases, govern the design of Arctic ports and terminal structures.
A general review of experienc e in operation of high-latit ude oil and gas marine terminals indicates that existing technology of port struct ures design and construction is sufficient to support operations in the Alaskan OCS. Ne w technology development s will be required in shipping operations, primarily by providing the hi ghest level of safety of tanker operations in ice-infested waters and by maximizing t he efficiency of ice management systems.
While technically feasible, no tanker tra ffic has been proposed in the EIS for upcoming Beaufort lease sales (MMS, 2003). Regulatory requirements would r equire pipelines, if economically feasible in co mparison with barging or tank ering production to shore. Because the EIS stipulates a pr eference to pipelines for trans port, this suggests that MMS may consider tankering of hydrocarbons fr om the Chukchi OCS a less likely scenario (MMS, 2007b).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 282 of 339 Rev. 0 4.12.3 Constructability & Capital Costs 4.12.3.1 General Marine Terminal Concepts for Arctic & Sub-Ar ctic Conditions

At locations where the natural water depth is sufficient for berthing of large tankers and transport vessels, marine terminals can be built near shore. However, most of the coastal areas in the Arctic are sha llow water, lagoon or beach formati ons, where the required 50 to 65 ft (15 to 20 m) water depth may be found only hundreds of meters offshore. Contemporary port engineering offers three solutions to this problem (as separate alternatives or combinations thereof):

• Approach trestle (access roadway);

• Approach (dredged) channel; and,

• Offshore TLU (Tanker Loading Unit) with underwater loading line.
Feasibility studies for marine hydrocarbon termi nals designed for moderate climates often suggest that the approach trestle solution is t he most expensive. This conclusion becomes more certain for the Arctic and sub-Arctic condi tions because the relatively light structural supports for a trestle need to be increas ed significantly to resist ice loads.

The dredged channel option is also quite expe nsive and may have negative environmental impacts (disposal of dredge spoil). Two main co st-escalating factors in the Arctic are the short summer dredging season and the need for equipment mobilization to remote areas. Besides high costs, the dredged channel alternative is frequent ly rejected due to the long time required for its execution and, more frequently, because of the potential for environmental damage. In some Ar ctic coastal areas, storm wave action, prevailing current and long-shore sediment transport processes cause an accelerat ed siltation of the dredged channels.
The difficulties and high costs associat ed with access roadway and dredged channel alternatives apparently are the main reasons behind the decisions to construct offshore TLU’s in several recent projects where operations nee d to be conducted in the floating ice, e.g. Sakhalin 1 DeKastri export terminal in the Sea of Japan and Va randey Terminal in the Barents Sea, Russia (see Section 3.2.7).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 283 of 339 Rev. 0 4.12.3.2 Offshore TLU Alternatives
The main advantage of offshore berthing is t hat the TLU may be sited at the required natural water depth without dredging or wit hout construction of an expensive access roadway. One possible alternative is the sea island . This is essentially a traditional oil jetty arrangement (loading platform with breasting and mooring dolphins), except the whole loading structure is moved offshore and the o il is delivered through a subsea pipeline. For arctic conditions, the sea island is a reasonable solution because it may be constructed as a gravity-type structure (or group of gravity structures) which offer resistance to ice loads.

The other TLU alternative which has potential for arctic conditions is the bottom-founded SPM or Single Point Mooring. Other possible SPM arrangements, such as the Catenary Anchor Leg type (CALM buoy), Single Anc hor Leg type (SALM buoy) and Multiple Buoy Mooring (MBM) cannot be used in the Arctic fo r year round operations. These solutions are vulnerable to damage from fl oating ice and hose handling is not conducive in sub-freezing temperatures. In addition, the CALM, SALM and MBM will not be able to sustain floating ice operational conditions. A SALM buoy has been us ed on the Sakhalin 2 project but tanker loading was halted in the winte r (Figure 4-38). This type structure has suffered damage during severe weather and is scheduled to be r eplaced by a permanent pipeline to shore (Platts, 2007). For year-round operation in arct ic and sub-arctic conditions, a bottomfounded SPM with a boom-supported hose string may be a viable option (Buslov et al., 2004).

There are two ways to ensure the lateral stabili ty of a bottom-founded SPM in floating ice. It may de designed as a gravity stru cture (both of a caisson type or a tower type) or it may derive the necessary resistance to the ice loading from piles driven through sleeves attached to its base. For instance, accordi ng to available informa tion, the Varandey oil terminal in the Barents Sea (Russia) is a wi de turret tower with a cai sson gravity base and a group of piles to supplement the lateral resi stance (Section 3.2.7). The Sakhalin 1 SPM of the DeKastri terminal is a relatively slender to wer with piles driven ov er the perimeter of a wide base. This structure also has a large ic e-breaking cone at the water level intended to reduce the lateral ice load (Figure 4-39). The Sakhalin 1 SPM is the world's largest fixed tower structure of its kind. It weighs 3500 t ons (3200 tonnes) and sits 200 ft (61 m) above sea level. It can handle tankers up to 110,00 0 DWT and is designed for year-round loading in the ice-infested Tatar St rait between Sakhalin Isl and and the Russian mainland (PennWell Publishing, 2007).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 284 of 339 Rev. 0 Figure 4-38: Ice Breaker “Smit Sibu” Providi ng Ice Management Operations for SALM Buoy Lay Down Operations on Sakha lin 2 (Courtesy of Don Connelly)

Figure 4-39: The Sakhalin 1 Fixed Tower SPM Sits 61 m above the Seabed (Courtesy of PennWell Publishing, 2007)IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 285 of 339 Rev. 0 The application of ice-breakin g cones is not without contro versy. Some experts have warned that ice adfreeze resulting from tidal variations may create conditions under which the cone becomes totally inefficient. Moreover , the ice block frozen to the cone may generate higher loading in the ic e crushing mode than the towe r stem without a cone. This premise is similar to that presented in Secti on 4.5.4.1 with respect to the use of a slopedsided structure for a GBS production structure.
Conceptual evaluations of structures for sub-ar ctic conditions, with level ice less than 3.3 ft (1 m), showed that the increase of the wall thickness of the st eel pipe piles at the zones of maximum bending moment is a more cost efficient solution than the app lication of cones at the water level. In these cases, the cost fo r fabrication and installation of ice-breaking cones is higher than the cost of the extra steel required to provide the necessary strength of piles at the points of maximum stress.
Collapsible (articulated) and submerged SPM systems have also been proposed for application in the floating ic e conditions (Tsinker, 1995).

4.12.4 Environmental Considerations Hydrocarbon transport marine terminals are cons idered by countries having access to the Arctic seas as potentially having an impact on the environmen t. For instance, the maximum allowable level of hydrocarbon products in seaw ater in the Russian Federation is barely achievable by the best oil/ water separators. Proposed soluti ons require the application of additional stormwater treatment technology. Other stringent r equirements have resulted in the creation of Water Conserva tion Zones, where many industrial activities are disallowed.

Terminal concepts where tankers are loaded offshore require a su bsea loading line as a key component of the overall facility design (for example, Sakhalin 1 DeKastri Export Terminal). The protection of this pipeline from ice gouging nearshore and at landfall is an important aspect of the overall terminal design.
One of the most challenging co mponents of the operations of a marine terminal in arctic conditions is Oil Spill Response (OSR) in float ing ice conditions. Solutions are developed through creation of detailed action scenarios and potential application of OSR personnel teams, vessels and available equipment.
To reduce the potential of oil sp ills from tankers, there has been a mandatory phase-in of double-hulled tankers, bette r navigational systems and t anker escorts (MMS, 2003).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 286 of 339 Rev. 0 Another consideration is that the use of tank ers would result in air emissions from the tankers’ engines during loading o perations, transit and unloading.
4.12.5 Operations Safe vessel operation in ice (Fig ure 4-40) is usually ensured by providing special ice control and ice management support/technology, such as ice breaking by terminal and escort icebreakers, ice suppression by thermal di scharge, bubbler systems and ice dusting, and ice diversion by small islands, cells and dolphins. A ll of these inevitably increase the costs of terminal development in the Arctic and impos e a range of requirements to the layout of the terminal facilities and their structural design.
The key component of vessel operat ions in ice in the vicini ty of marine terminals is maintaining the operational areas (approach channels, m aneuvering zones and turning circles, anchorages, etc.) free of ice as long as possible with minimal ice management. This particular requirement makes the design and t he layout of arctic marine terminals more site-specific than any other initial investment cost consideration. Fo r instance, it may be more cost efficient (in the l ong run) to extend the loading li ne further offshore beyond the required minimum water depth if it would allow placement of the TLU at the location where, based on the multi-year observati ons, the “polyniya” (area of sea free of ice) is most frequently observed.

The same considerations govern the location and the layout of the oil piers and TLU’s with regard to the movement of ice under prevailing winds and ti dal currents. The shoreline geometry, and particularly the nat ural rocks and islands, may be efficiently used to reduce the interaction of the structures with particula rly large ice features. More than one approach channel may be maintained through the winter to ma ke sure that at l east one will remain free of ice if the wind changes . Lower cost breakwater and be rthing front configurations may be sacrificed in favor of an alternative solution which provides better ice clearing conditions in the harbor.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 287 of 339 Rev. 0

Figure 4-40: Icebreaker and Tanker Trials at Sakhalin (Cour tesy of PennWell Publishing, 2007)

4.12.6 Maintenance & Repair A maintenance program for arctic terminal s includes three types of inspections:

• Regular inspections performed at least once a year to identify the need for repairs;

• Detailed pre-construction inspections c onducted if the decisi on to execute the repairs has been made. These inspections have a goal to identify the scope of the repair; and,

• Special inspections (investigations) may be required if the causes of existing damage are not immediately cl ear. Special inspections normally include some kind of in-situ testing (coring, sampling or NDT).
The specific features of all surveys to be performed on arctic st ructures are normally associated with damage caused by exposure to low temperatures, alternate freezing and thawing cycles and ice loading (pressure and impact). The most serious concern is normally associated with the pot ential damage from the ice l oading: static and dynamic overstressing, bending, cracking and break age of support components, etc.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 288 of 339 Rev. 0 Depending on the approach channel infill rate s, dredging may need to be carried out periodically to ensure vessel access.
4.12.7 Abandonment & Decommissioning Decommissioning procedures for offshore insta llations that have reached the end of their useful life are usually included in governing legislation. There are also international agreements relating to decommi ssioning that address removal an d deep-sea disposal. For example, the International Maritime Organi zation (IMO) has developed Guidelines and Standards for the removal of Offshore Installa tions and sets out conditions to protect navigation and maintain safety.
Some general requirements in other jurisdic tions with regards to decommissioning include designing facilities such t hat, upon termination of production, they can be removed or mothballed for future use.

4.13 Other Technologies

4.13.1 Extended Reach Drilling
4.13.1.1 Technica l Feasibility
The Liberty FEIS (MMS, 2002) defines extende d-reach wells as wells having departure ratios (or horizontal reach to vertical depth) of greater than 1.5. Such wells are increasingly being considered as a reservoir access option to reduce overall development footprint size and eliminate the need for offshore facilities.

As noted in Section 3.2.8, records continue to be set using extended reach drilling (ERD) technology. Application of the technology in Al aska also continues to grow (Figure 4-41) and has been used to increase access to the Al pine development reservoir (Alvord et al., 2007).
A long-reach US record for horizontal directi onal wells was set by BP in 1998 with a reach of 19,804 ft (6036 m) in the Niakuk Field (see Fi gure 4-41). While the we ll cost $6 million, the use of extended reach technology result ed in a cheaper solution over other drilling alternatives such as the construction of an ar tificial gravel island (Department of Natural Resources, 1999).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 289 of 339 Rev. 0 Figure 4-41: Well Reach vs. Time (Depar tment of Natural Resources, 1999)
An evaluation of extended drilling technology was carried out by the MMS as part of the Liberty FEIS (MMS, 2002). That evaluation discusses extended-reach drilling in other settings, both on the North Slope of Alaska and elsewhere. The reader is referred to that document for additional details.
Only a few years ago, it was not considered feasible to dev elop the Liberty prospect using ERD (MMS, 2002). However, currently, the plan is to access the Liberty reservoir using this technology from Endicott Island where existing infrastructure exists. This will take the technology to distances of 40,000 to 45,000 ft (12,100 to 13,700 m) (Nelson, 2007b).
Current industry achievements have reac hed 37,000+ ft (11,300+ m) measured depth and reservoirs within this range should be reac hable depending on site-specific conditions. Each development might be expected to contai n a unique set of geologic conditions that affect drilling costs and long-term operations.

Therefore, ERD from s hore is considered technically feasib le for location scenario closest to shore presented in this study. While not s pecifically feasible for the other location scenarios, it is evident that the technology could be applied wher e the right conditions exist.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 290 of 339 Rev. 0 The use of ERD offshore could be considered fo r any of the other scenarios that would utilize a platform and on which the equipment could be mounted.
4.13.1.2 Constructability

Indications are that the technology exists to drill a 37,000+ ft (11,300+ m) well depending on site-specific conditions. In cases such as the Liberty prospect and the Sakhalin 1 fields, purpose built rigs may be required.
4.13.1.3 Capital Costs
Being able to drill fr om onshore or access additional rese rvoirs offshore from existing facilities should be less expensive than considering an offshore platform or gravel island.
The costs of drilling using extended reach tec hnology, while not present ed here, should be established within the industry. However, in cases new equipment may be needed. The Liberty prospect will require a new bigger drill rig as equipment on the North Slope does not have the capability to drill the wells. This rig would not be readily mobile and would be specifically designed for the Liberty project (Nelson, 2007b). An evaluation of extended drilling technology was carried out by the MMS as part of the Liberty FEIS (MMS, 2002). That evaluation discusses exte nded-reach drilling in other settings, both on the North Slope of Alaska and elsewhere and also pr esents some information on costs.
The Sakhalin 1 Project uses w hat is believed to be the world’s largest land based drilling rig (Abraham, 2007). As an indication of drilling time, the 37,016 ft (11,282 m) Z-11 well drilled on Sakhalin Island was drilled in 61 days (Abraham, 2007), demonstrat ing that experience will cut drill times (and costs). The Sakhalin 1 project has increased drilling rates from 330 ft (100 m) per day in the first-year of operations to 660 ft (200 m) per day in recent wells, cutting the drilling time of ERD by 50% (PennWell Publishing, 2007).

It should be noted that each development project might be expected to contain a unique set of geologic conditions that affect drilling costs.

4.13.1.4 Environmental Considerations

Environmental considerations associated with drilling of wells are well understood and managed throughout the world includi ng remote areas. The use of extended reach drilling, where feasible, should help minimize the overa ll footprint of faciliti es in Alaska, both onshore and in the OCS region.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 291 of 339 Rev. 0 4.13.1.5 Operations, Maintenance, & Repair
Operations associated with drilli ng extended reach wells is established within the industry. As these wells are likely to be drilled in remo te locations, consideration needs to be given to supply and re-supply to areas with no perm anent roads and delivery re stricted to winter when ice roads can be built and maintained.
It should be noted that each development project might be expected to contain a unique set of geologic conditions that a ffect long-term operations.

Maintenance and repair issues associated with ERD should be es tablished within the industry. As with operations, co nsideration needs to be given to access to areas with no permanent roads and delivery restricted to winter when ice roads can be built and maintained.

4.13.1.6 Abandonment & Decommissioning
Abandonment and decommissioning for an extended reach well should not be significantly different than a conventional well.
4.13.2 Well Intersection Method (WIM)
4.13.2.1 Technica l Feasibility
Another method that may prove vi able for installation of relati vely short (approximately 3.5 miles or 6 km length or less) and small diameter (approximate ly 12-inch (305 mm) or less) pipelines or flowlines is the use of the Well Intersection Method (WIM). This method employs conventional oil and gas directional dr illing technology to intersect two wells in a horizontal orientation. The WI M option entails dril ling two wells with the largest possible diameters that intersect each other to provide a continuous flow path for hydrocarbon transportation. The wells would typically be cased and may employ solid expendable tubular (SET) technology to bridge the two ends of the casi ng in the well path at true vertical depth (TVD) and provide a conti nuous conduit for hydrocarbon transmission.

Two drilling rigs are employed simultaneously to perform the drilling (one at each end). The wells are “intersected” at approximately t he mid-point. Since conv entional drilling technology is used, traditional blowout prev enters (BOPs) are empl oyed to contain any potential shallow gas pockets that might be enc ountered. In addition, a ll drilling fluids are contained, helping eliminate the environmental issues associat ed with horizontal directionalIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 292 of 339 Rev. 0 drilling (HDD). Also, since one dr ill pad at each end is all that is required to support the drill rigs, the environmental footprint associated with temporary construction work space is mitigated. Finally, since at least one and possi bly both drill rigs may already be mobilized near the WIM drill sites, potentially very high construction spread mobilizations costs may be partially mitigated.
The use of the technology has been investigated by others in the industry (Lee et al., 2005) where the intersection of two wells (termed U- tube wells by the authors) was undertaken on land, not for development purposes, but to prov ide insight as to what could be undertaken using future implementation of the technology . The surface locations of the wells were approximately 1400 ft (430 m) from each other into an unconso lidated sandstone reservoir with a true vertical depth of 640 ft (195 m). The authors propose the technology can be used to tie-in step out wells and e liminate flowlines installed on th e seafloor or to extend the length of already extended reac h wells in harsh environments, such as those where ice gouge is an issue. The authors also suggest that, ultimately, sp ans of 6 to 12 miles (10 to 20 km) might be connected using the technology. By “daisy chaining” the spans together, longer length connections can be made.

Therefore, the use of WIM fr om an offshore facility might be feasible for the location scenario in the Beaufort closest to shore presented in this study. A single WIM connection would not be feasible fo r other location scenarios, but if daisy chaining spans together was feasible, the technology could be applied where the right conditions exist. The use of WIM offshore could then be considered for any of t he other scenarios, as long as the daisy chain connections (where they are tied t ogether) were adequately protected.

This technology may also have application in areas that will not permit pipelines across bays to be situated on the sea floor (Smith, 2004).
4.13.2.2 Constructability
While the WIM has been used, there are signifi cant well planning and drilling technology issues that would have to be addressed bef ore it could be used in the Arctic with confidence. Issues with regards to the distance between drill rigs, required pipeline (casing) size, pigging requirements and subsurface geology would have to be addressed. If individual intersections were to be daisy chai ned, some design/development effort would need to go into the connections near the surface and protection of same.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 293 of 339 Rev. 0 4.13.2.3 Capital Costs

The WIM is based on existing drilling technol ogy and well costs can be used as a basis. Smith (2004) indicates that the Buckinghorse River cro ssing exceeded $12 million, but some of this was attributed to pr oblems at the ons et of drilling.

4.13.2.4 Environmental Considerations

Again, environmental considerations associat ed with the drilling of wells are well understood and managed. If techni cally and economically feas ible, the use of such technology could reduce the amount of buried offshore pi peline on the Alaskan OCS.
4.13.2.5 Operations, Maintenance, & Repair
Based on information reviewed, it appears that the casing that is set using the Well Intersection Method would be operated simi larly to a pipeline with some potential limitations, e.g., pigging.
In terms of existing operations, the Bucking horse River crossing st arted transporting gas using WIM technology in Dece mber 2004, at a rate of 9 mmscf per day. Anadarko were also looking at potential conv ersion to a high-pressure system to increase throughput to approximately 30+ mmscf per day (Smith, 2004).
Given the technology used to implement a WI M transportation solution, maintenance and repair issues would be similar to those associat ed with drilling.

4.13.2.6 Abandonment & Decommissioning
Abandonment and decommissioning for a WIM technology solution should not be significantly different than a regular well.

4.13.3 Pilot Hole to Pilot Hole HDD
4.13.3.1 Technica l Feasibility
A relatively new development in the horizontal directional drilling industry has been to drill two pilot holes, from entry poi nts at either side of the cr ossing, and intersect them underneath the crossing, rather t han to drill a single pilot hole from entry to exit. This possibly extends the reach over conventional HDD projects.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 294 of 339 Rev. 0 HDD is a proven technology with a strong track record in non-ar ctic applications. However, it has been used on th e ARCO Alpine Developm ent on the North Slope to cross the 4300 ft (1310 m) wide east channel of the Colville River with four individual pipelines.
Therefore, the use of pilot ho le to pilot hole HDD technol ogy would not be feasible to access any of the location scenar ios presented in this study. Ho wever, if daisy chaining spans together was feasible, the technology could be applied where the right conditions exist. The use of this HDD technology could then be considered fo r any of the other scenarios as long as the daisy chain connec tions (where they are tied together) were adequately designed/protected.
4.13.3.2 Constructability

Where HDD is considered, the main technica l constraint involves the influence of soil conditions. The effects of the presence of permafrost on the drill ing operation must be considered. The presence of gravel or ice lens es would reduce the effi ciency of the drilling operations and could result in coll apse of the hole. In the case of a shore crossing, it can be performed after the shore crossing pad has been completed, thereby decoupling the construction schedules.
4.13.3.3 Capital Costs

HDD is a well-established technology and co sts can be provided by HDD contractors.

4.13.3.4 Environmental Considerations
A major advantage of a HDD shor e approach is that the shorelin e is left undisturbed. Also, theoretically, HDD installations could be link ed (daisy chain) if the connection can be engineered/constructed. The use of pilot hole to pilot hole HDD technology would increase the overall HDD reach and decreas e the number of connections if a daisy chain approach was used.
4.13.3.5 Operations, Maintenance, & Repair
A pipeline HDD crossing would be operated in the same manner as a conventional pipeline crossing including periodic inspec tions of the shore approach.

A pipeline HDD crossing would be maintained in much the same manner as a conventional pipeline crossing. There should be less main tenance as the shoreline will have beenIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 295 of 339 Rev. 0 undisturbed which would minimize any potential acceleration of shoreline erosion. If the pipeline is operated warmer than the surrounding permafrost, there is the potential for surface subsidence in areas where the pipeline is closer to the surface.

A potential issue with regards to HDD installations is the acce ssibility of the pipeline. By the nature of HDD installations, access to the pipel ine could prove difficult. In a daisy chain scenario, burial/protection of the connections would have to be conducted periodically.

4.13.3.6 Abandonment & Decommissioning

A pipeline HDD crossing woul d be abandoned and decommission ed operated in the same manner as a conventional pipeline crossing.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 296 of 339 Rev. 0 5.0 SUMMARY, CONCLUSIONS AND RECOMMENDATIONS

5.1 Overview

Offshore hydrocarbon exploratio n and production requires a bottom-founded platform, an artificial island or a floati ng structure plus subsea equipm ent including pipeline/riser systems. Transportation of produced hydrocarbons to market is also an essential aspect of any development. An added complexity when hy drocarbon resources are located in cold regions is the presence of firs t-year and/or multi-year ice duri ng a significant part of the year. Global climate changes may also result in longer open water seasons in the future, which may lead to more significant storm event s that must be considered in the design of full-field offshore development concepts for cold regions.
The objective of this study is to deliver an assessment of oil and gas technology that may be applied to cold regions of the United States Oute r Continental Shelf (O CS). Advances in harsh environment offshore exploration and production technology have made it economically and technically feas ible for projects to proceed in ice-covered waters. This study assesses the current state of offshore te chnology in arctic and sub-arctic regions. The results of this assessment are then used to provide insight and guidance into existing/future exploration and development tec hnologies that might be applied on the US OCS, in particular those areas in the Beaufort, Chukchi and Bering Seas. The work covers exploration structures, botto m founded and fixed prod uction concepts, floating production concepts, terminals, pipelines and subsea facili ties, and also touches on other technologies that might be relevant to Alask an OCS exploration and development.

5.2 Assessment Methodology

In general, the study draws on a review of Alaskan OCS and analogue experience, current state-of-practice and st ate-of-the-art. Assessments of ex ploration and production options are primarily based on technical feasibility. As appropriate, other considerations have also been examined, as follows:

• Constructability;

• Capital costs;

• Environmental considerations;IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 297 of 339 Rev. 0 • Operations;

• Maintenance and repair; and

• Abandonment and decommissioning.
Given the large geographic area encompassed by the Beaufort, Chukchi and Bering Seas, location scenarios were specifie d to help focus the assessments. These location scenarios were chosen based on current and historic activi ty/interest (including lease sales, drilling, studies, projects, etc.) and water depths (given t he general differences in offshore facilities configuration in relation to wa ter depth). Overall general applicab ility of the technology to the area of interest was also considered.

5.3 Summary & Conclusions

5.3.1 Bottom-Founded Structures Exploration drilling for oil and gas in the Beau fort Sea began from gravel islands in shallow Alaskan State waters in the late 1960’s and si milarly in the Canadian Beaufort Sea in the early 1970’s. With time, activities progressed into deeper waters. In 1976, ice reinforced drillships were first utilized in Canadian wate rs, followed in 1981 by the first use of a bottom-founded caisson system. Although touted as “mobile” structures, the caisson structures were not truly MO DU’s (mobile offshore drilling un its). The SSDC was the first MODU-type structure in the Beaufort Sea, coming into se rvice in 1982 and, with the addition of the MAT in 1985, re mains the only active bottom- founded exploration structure in the Arctic offshore.
In terms of global size, structure cost and geom etry, there is very li ttle difference between dedicated exploration platfo rms and dedicated production platforms. In fact, an arctic mobile drilling structure is o ften more expensive than a produc tion platform due to the fact that it must cater to a range of water depths, rather than a known set-down depth. Additionally, a mobile platform needs to be able to accommodate a range of foundation conditions including very weak clays. With production platforms, foundation characteristics are known and dredging of the top weak layer(s ) is an available option, but is often not practical in the case of short-term m obilization of an explor ation structure.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 298 of 339 Rev. 0 5.3.1.1 Design Considerations

In any location where substantia l multi-year ice can impact a st ructure, the loads resulting from this interaction become th e primary design condition. In such locations, wave loads are small by comparison and do not have any real effect on the design. In the deepwater, more southerly basin areas (B ering Sea) where only first- year ice occurs, the platform design is primarily governed by wave loads. In these areas, it is still generally necessary to employ solid monolithic type structures as ice loads are still too locally intensive to permit jacket or “water transparent” type structures. However, the use of a monolithic type structure in order to eliminat e local ice load effects, bridgi ng and vibrations, results in relatively high global wave loads.
After ice loads, there are two other paramet ers that have a major effect on the global structure size optimization; water depth and foundation conditions. Generally, multi-year ice loads increase as the water depth increases, alt hough not in direct proportion. Thus, water depth has a twofold influence in t hat the deeper the water, the gr eater the horizontal design load, and also that the struct ure must increase in height and, hence, cost. Foundation types can range from “totally inade quate” (in which lateral relocation, excavation and/or replacement will be necessary) to “strong enough” to simply set-down directly on the seabed without any type of prepar ation. Foundation requirements for an exploration structure will be considerably less than those for a permanent production structure given the differences in the design loads (fir st-year ice vs. multi-year ice loads).

5.3.1.2 Technical Feasib ility of Structures
Ten (10) location scenarios are assessed with respect to the ty pes of structures that may provide a possible solution; in addition, two (2) general structur es (one with oil storage and one for mobile drilling) are a ssessed. The location scenarios, together with pr imary design assumptions are listed in Table 4-1.

In the Beaufort and Chukchi Se a areas, the 100-year design ice loading conditio n arises as a result of an interaction with th ick multi-year ice. The outer s hell of all structures must be designed to resist high local loads and since t hese local loads from first-year and multi-year ice are not terribly dissimilar (even though t here could be a factor of four between the global load scenarios), the quantities of steel in a temporary drilling st ructure will not be much different than those in a permanent production structure. In fact, temporary mobileIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 299 of 339 Rev. 0 structures may be more expensive due to having to cater to a range of set-down conditions rather than a s pecified depth.
In the case of exploration dril ling, the historical approach is to establish foundation stability based on a deterministic first-year ice loadi ng scenario and then to establish an ”alerts system” which would secure the well in the event that a large multi-year floe threatened the structure. This system works relatively well in shallower water depths where it can be almost guaranteed that large fl oes cannot impact the structure after freeze-up. In waters deeper than 65 to 100 ft (20 to 30 m), this approach becomes more problematic and sitespecific. However, the probability of greater loads in deeper waters is often offset by a likely (but not guaranteed) increase in foundation strength typically observed as one goes farther offshore. Again, these arguments only apply to te mporary “one well” drilli ng structures that have to sit on relatively weak clay foundations.

In the Beaufort and Chukchi Sea areas, where multi-year ice can impact structures, Table 4-2 gives approximate load rang es that modern probabilistic methods would predict. With respect to the Chukchi Sea, load ranges are gi ven with respect to the northernmost areas. In southern areas, close to the Bering Strai t, loads can be expected to be approximately 30% less.

In the event that a temporar y deployment for an exploration structure is being considered, arguments as outlined above can be rationa lly developed such that the foundation only needs to resist first-year ice loading of the order of 45,000 to 90,000 kips (200 to 400 MN).

Wave loads in certain areas can become a primary design consider ation (Table 4-3), although for the Beaufort and C hukchi Sea areas it is genera lly ice loads that govern stability.
In multi-year ice areas, there are botto m-founded, e.g., gravity base structure (GBS), solutions that would be considered safe and economical up to around 250 ft (75 m) water depths when foundation pr operties are good, and up to ar ound 200 ft (60 m) water depths when foundation properties are relatively weak. There are no known bottom-founded platform design solutions for water depths greater than 330 ft (100 m) that could be deemed workable or proven fo r multi-year ice areas . In the more southern areas, where multi-year ice is absent and only first-year consolidated ridge loadings are possible, bottomfounded solutions out to 425 to 500 ft (130 to 150 m) water depths ar e potentially viable.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 300 of 339 Rev. 0 5.3.1.3 Capital Costs
In Figure 4-9, 9 (nine) of the cost-estimated options were plotted. Costs range from approximately $3 million/ft ($10 million/m) for structures on st rong foundations in deeper water to approximately $8 mill ion/ft ($26 million/m) for struct ures on weak foundations in shallow water.
5.3.2 Jacket & Jack-up Structures The jacket structure is the most commonly used fi xed offshore platform. It was first used in the Gulf of Mexico and has since been adapted and modi fied for use all over the world. It comes in a variety of styles from the si ngle-legged (monopod) to mult i-legged structures.
The ice reinforced jacket platform was first succe ssfully used in sea ice in the mid 1960’s for Cook Inlet, Alaska developments. Conv entional jacket designs have been modified to make them suitable for sea ice environments. Three varieties of ice reinforced jacket structures have been used there; t he monopod, the tri pod and the quadpod.

The main considerations for t he design of any jacket structure are the payload the structure has to carry, the capacity of the foundation and the environmental loads the structure must resist. The loads unique to offshore Arctic stru ctures are temperature loading, sea ice static loads and the accompanying vibration loads. In m any cases, the sea ice static and vibration loads are the controlling factor (either globally or locally) in the sizing of the structure members. Temperature is gener ally the controlling factor in material selection.

The load imparted to a structur e by momentum, ridge building and pack ice loading relates to the width of the structure. If the jacket legs are within a certain di stance of each other, ice bridging can occur between t he legs and higher loads will be experienced by the structure compared to the case where t he legs are loaded independently.

In addition to static sea ice lo ads, the jacket structure must hand le the vibratio n loading. Ice reinforced jacket structures are more suscept ible to vibration than conventional jackets because they have less damping ability and tend to amplify vibrations. In light of jacket failure in the Gulf of Bohai and the dysfunc tion of another as a re sult of ice induced vibrations (Cammaert and Mugger idge, 1988), there is a strong possibility that jacket platforms are unworkable and/or uninhabita ble under modern vibrat ion code limits.
Previous studies have suggested that jacket stru ctures are suitable for areas of the Bering Sea. These studies did not consider the vibr ation responses associated with the dynamicIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 301 of 339 Rev. 0 ice loading. Jacket type structures could likely be made to work in light first-year ice and water depths less than 200 ft (60 m). However, the jacket structure’s potentially poor response to dynamic loading an d the conductor system protec tion issue are a significant design issues for application in the Bering S ea. Current design prac tices and understanding of jacket design make their application unsui table for the Beaufort and Chukchi Seas.

The protection and vibration iss ues associated with arctic jacket design and construction may be mitigated with further study and underst anding of ice induced vibrations and the review and development of alternative damp ing techniques. Further study of jacket leg loading under thick ice conditions is requir ed to determine if the jacket legs respond individually or as a group.
Developments in jack-up technology and the advancement of ice maintenance programs indicate that the operating r ange and season of jack-up exploration could be expanded in the Bering Sea.

5.3.3 Ice Islands Grounded ice islands have been used successfully as exploration drilling structures in nearshore areas of the US and Canadian Beaufort Sea.

5.3.3.1 Technica l Feasibility
In general, ice island technical feasibility is based on several fundamental regi onal and site specific considerations: meteorological environment, water depth, landfast ice characteristics and geotechnical (seabed) conditions.
Water depth is a fundamental fa ctor that must be considered when evaluating t he feasibility of grounded ice island structures. Generally, as water depth increases, island freeboard requirements also increase and, in turn , influence construction time/cost.

An ice island must be grounded soundly on the seabed to resist ice loads imposed by the surrounding ice sheet. This requirement is cr itical because any appreciable movement of the island during drilli ng operations can cause damage to t he drill-string. Ice loads imparted on an ice island depend on the ice failure mode, rather than on t he driving force of the ice sheet; crushing (failure) of the surrounding ice sheet typically limits the upper bound of these loads. Assuming that the shear capacity of soil beneath the island is less then than that of the ice island core, global ice island resistance wi ll be governed by its sliding resistance (lateral stability).IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 302 of 339 Rev. 0 In practice, operational ice isl ands have been employed in water depths of up to 25 ft (7.6 m) in the Beaufort Sea. Howeve r, based on work reported in C-CORE (2005), the use of operational ice islands might be achieved in wa ter depths of up to approximately 30 ft (9 m). The MMS Ice Island Study (C-CORE, 2005) s uggests that “increm ental improvements in equipment capacity with highe r productivity would allow isla nds to be constructed into deeper water and it is considered that 40 ft (12 m) water depth should not present a problem”.

Based on the location scenarios identified in th is study, ice islands were assessed for both the nearshore Chukchi Sea and No rton Sound. Results of the as sessment indicate that the use of ice islands in the nearshore Chukchi w ould likely be infeasible due to the unstable and unreliable landfast, or cont iguous, ice zone. The assessment also indicates that ice islands would generally not be feasible for Norton Sound du e to its warmer and shorter winter season. Efficient spray ice production would not be achievable, time available for construction and subsequent drilling operati ons would be reduced and creep/settlement would likely be more of an issue in comparis on to ice islands used in the Beaufort Sea. Consideration of ice loads and associated stability requirements, the possible use of innovative techniques such as chipped ice and reducing ice loads, and possible use of rubble piles to initiate island construction, may allow an ice is land to work in very shallow nearshore water depths. Further assessment woul d be required to ascertain ice island feasibility in these areas.

5.3.3.2 Construction
Initially ice islands were constructed usin g the flooding construction technique; however, build up rates were low. Alternative me thods of ice island construction have been previously investigated and through significant experimentation and study efforts, spray ice technology was developed. All oper ational ice island drilling stru ctures built in the US and Canadian Beaufort Sea (7 in total), em ployed this construction technique.
Construction time required for previous ope rational ice islands ra nged from approximately 20 to 60 days (C-CORE, 2005). The Thetis Ice Island project carried out in 2002-03 employed several innovative measures to reduce ice island volume requirements and, hence, construction time:

• Reduction of design ice load (based on extrapolated maximum in-season ice thickness);IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 303 of 339 Rev. 0 • Further reduction of design ice load by reducing the thickness of the surrounding landfast sheet; and,

• Use of chipped ice, wh ich reduces the required freeboard because it has a higher density then spray ice.
5.3.3.3 Capital Cost
Capital costs for an ice island structure will be directly proportional to the amount of ice needed, which generally depends on the ice l oads expected, water depth and soil conditions. Cost optimization may be realized in several ways, including reducing drilling facility footprint, reducing ice island diamet er based on soil conditions, using chipped ice, and considering design ice load reduction techniques. Comparat ively, ice islands are far more economical then gravel islands. Howeve r, gravel islands are more versatile with respect to water depths and ice loads. Figure 4-17 presented earlier ill ustrates the cost differences between ice and gr avel island structures.

5.3.4 Gravel Islands Although not a “high tech” technology, gravel islands have been successfully used in the Beaufort Sea for decades and continue to be vi ewed as candidate structures for exploration and/or production (for ex ample, Northstar).

In general, gravel islands are attractive because they are a proven technology, offer a short construction lead time, and have historically been the most econom ical structure for shallow water depths. Given recent increasi ng oil prices and in creasing material and fabrication costs for other types of structures, it is not inconc eivable that the water depth for which gravel islands are considered might be increased.

5.3.4.1 Technica l Feasibility
The use of gravel islands fo r arctic exploration and produc tion has been proven. On the order of fifty (50) gravel isl ands have been constructed in the Beaufort Sea in water depths from several feet to over 60 ft (19 m). In theory, a gravel is land has no depth limitation, but in practice water depth limitat ions have been considered to be approximately 65 ft (20 m) based on economics and logistics.
Landfast ice, typically ranging up to 6.6 ft (2 m) thick, covers the nearshore Beaufort Sea for about nine months of the year and has a c onsiderable influence on island design andIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 304 of 339 Rev. 0 construction methods. In deeper water areas, multi-year ice incursions have to be considered and, in general, ice ri de-up is more frequently encountered.

As is generally the case with other arctic bottom-founded structures, the primary design requirement for a gravel island is that it mu st have adequate lateral stability to resist ice loads. Gravel islands must al so be capable of withstanding po tential ice ride-up and wave conditions.
In general terms, these environm ental loads are managed throug h gravel island geometry. Ice ride-up is impeded by the sl oped island sides due to fricti on and plowing forces and/or, in some cases, by discontinuity in slope. Waves begin to break as they reach the sloped island sides, thereby dissipat ing energy before they reach the working surface. Wave overtopping is dealt with by placing the wo rking surface above the design wave height and/or by placing a barrier around the working surface perimeter.
5.3.4.2 Feasibility of Selected Scenarios
Based on the OCS location scenarios investigat ed in this study, and considering practical water depth limitations, nearshore areas of t he Beaufort Sea, Chukch i Sea and Bering Sea can be considered for the us e of a gravel island.
Since no gravel island struct ure has been used in the Chuk chi Sea, a more detailed assessment would be required to determine feas ibility. From a qua litative stand-point, however, considering the primar y design requirement is lateral stability, it would seem reasonable that a gravel island could be made to work in the Chukchi Sea. Due consideration would need to be given to the fact that the nearshore Chukchi Sea ice environment may be more dynam ic then the Beaufort Sea.
In the nearshore Bering Sea, gravel island s may be subject to higher waves and larger wave loads. Any island design would need to take this into consideration.
5.3.4.3 Constructability
There are basically two methods of construc ting gravel islands: the onshore (hauled) method or the offshor e (dredged) method.

The onshore method typically involves excavati ng material from onshore and transporting it to site via truck over ice roads. Material is dumped through a hole cut in the ice by conventional chain trenchers and backhoes. The ma jority of gravel islands constructed inIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 305 of 339 Rev. 0 the US Beaufort have used this method. During the summer season, material can alternatively be transported to site via barge.

The offshore method involves dredging material and transport ing it site via barge or pipeline. This method is typically used in deeper water where it is unfeasible to build ice roads or causeways. Most gravel islands in the Canadian Beaufort we re built using this method.
The Chukchi Sea has a dynamic ice environment and nearshore “landfast” or “contiguous” ice is highly unreliable. Ther efore, the truck haulin g method will likely be infeasible. Norton Sound ice roads will have limited use in com parison to the Beaufor t Sea, which will therefore limit the us e of truck hauling.

When constructing a gravel island, consideration must be given to the fact that a pipeline will need to be brought onto t he island. The timing and met hod of pipeline installation should be such that interference with island c onstruction and/or facilities installation is minimized.
Typical costs associated with gravel is lands were presented in Figure 4-17.
5.3.5 Floating Structures There are only a limited number of floating expl oration or production st ructures that have been used in ice environments.

5.3.5.1 Exploration
During exploration in the Canad ian Arctic in the 1980’s, floating vessels (drillships) were used successfully with the support of ic ebreaking ships for ice management, e.g., CANMAR “Explorer III” drillship and CANMAR “Kigoriak” icebreaker. In particular, the Kulluk, a round drilling barge purpose built by Gulf Canada, operated in the Canadian Beaufort Sea. This vessel could operat e through the open water season until early December (at the latest) with intensive ice management support.

5.3.5.2 Production
Historically, on the Grand Bank s of Newfoundland, FPSOs (F loating Production, Storage and Offloading) have been the choice of floating production vesse ls under potential sea ice (first-year) and iceberg condition s. The hulls of both of t he existing Grand Banks FPSOsIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 306 of 339 Rev. 0 are designed to operate in light to moderate first-year pa ck ice and can maintain their moorings in heavy first-year pack conditions. This ice cover would not have significant pressure ridges, nor would multi-year ice be pr esent, as might be the case in the Alaskan OCS. Additionally, the hulls ar e designed to withstand the energy from a strike by a 110,000 ton (100,000 tonne) iceberg moving at 1 knot. This is an impact event and not a sustained load as might be found in the Beaufort or Chukchi Seas.
Modified spar, TLP (Tension Leg Platform) and semi-submersible designs have also been proposed for ice environments, although none have been built and there is much debate about the feasibility of these concepts in ice, particularly for Beaufort and Chukchi Sea applications.
Floating production platforms proposed for ice/ iceberg areas are typically designed to be readily disconnected from thei r moorings and operated in managed ice conditions. The ability of these floating platforms to leave st ation would allow the ve ssel to avoid extreme ice loads and also provide the capability for operations on a seasonal basis. The amount of time that it might take any particular float ing vessel to reconnect back on station will be a significant consideration in concep t selection for any production site.

5.3.5.3 Alaskan OCS
Seasonal exploration can be carried out in the Alaskan OCS using drillships and drilling barges and, in areas without mu lti-year ice, semi-submersibl es or a TLP. However, for exploration, the only location th at a floating structure might be capable of staying on station year-round might be the Bering Sea under light ice conditi ons. A Semi-rigid Floater structure might work year-round under first- year ice conditions, but would need to have the ability to disconnect and leave station in the ev ent of potentially higher loads. Fitzpatrick’s Semi-rigid Floater is designed to stay in pl ace year-round under 100-yr loading from a firstyear ice, pack ice (NOIA, 2007).
The applicability of floating structures for use in the Alaskan OCS would depend on whether or not the structur e was permanent or temporary, the ice environment, water depth, etc., and would have to be evaluated during any detailed assessment. However, floating production systems fo r the Beaufort Sea, Chukchi Sea and North Bering Sea are not considered to be technically feasible, even with continuous ice management. No floating production structures could be economically designed to stay on station with multiyear ice loads found in the Beaufort and Chukchi Seas, and possibly northern Bering SeaIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 307 of 339 Rev. 0 depending on local ice conditions. Floating syst ems may have some merit in southern Alaskan OCS areas, however.

Table 4-14 presents an overview of the possible use of floating structures for seasonal exploration, year round expl oration and production in the Al askan OCS areas of study.

Floating structures have been and will continue to be used fo r seasonal exploration. A floating structure will likely be onl y able to carry out year round exploration operations in the south Bering Sea under light ic e conditions. However, a Semi -rigid Floater type structure could be considered for year-round explorati on, if disconnects were permissible under extreme loading events. Based on current tec hnology, no floating type structures could operate as a production structur e in the most of the Alask an OCS areas under investigation in this study. It is possible that a production structure might work in the southern Bering under light ice conditions.

5.3.6 Subsea Solutions In some cases, there may not be a requirement for a production island or platform offshore. If the wellhead is located in water of suffici ent depth, protection from ice would not be necessary. In areas with water depths less t han the maximum ice keel depth, glory holes may need to be considered to protect the subsea facilities from ice ridge keels. This is considered to be approximately 165 to 200 ft ( 50 to 60 m) water depth in areas subjected to ice gouging.

5.3.6.1 Subsea Tiebacks
Improvements in the area of subsea facilities and processing have been made in recent years in the pursuit of resour ces in harsh and remote environm ents. As a result of these improvements, fields requiri ng longer, deeper subsea tiebacks are now becoming much more technically and economically feasible . Gas tiebacks have reached 105 miles (170 km) (Statoil Snøhvit) and oil tiebacks have reac hed 40 miles (65 km) (Shell Expro Penguin).

For subsea tieback options on the Alaskan OCS, production would be through remotelyoperated subsea facilities with pipelines running to offshore facilities and/or landfall. Offshore structures would not be required in cert ain areas except during drilling of the wells and installation of the subsea equipment. Due consideration would need to be given to the design/protection of pipelines and flo wlines tying in the subsea facilities.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 308 of 339 Rev. 0 Consideration would need to be given to the distances to shor e or to a platform. Distances greater than those mileston es stated above will require additional technological development or intermediate tie-in fac ilities for distances greater than these.

5.3.6.2 Subsea Facilities Protection
Glory holes (Figure 4-27) are excavations in t he seafloor into which subsea facilities can be installed for protection from sc ouring ice keels. Although not in the Arctic, two existing projects use open glory holes to protect we llheads and associated su bsea equipment from iceberg keel impact. These are the Terra Nova and White Rose projec ts located on the Grand Banks (Canadian east coast) where, to date, glory hol e excavation has been the preferred method of subs ea facilities protection.
Subsea facilities can potentially be used at any of the location scenarios considered in this study or, in general, for any dev elopment on the Alaskan OCS. Ho wever, there are limits on which technology should be considered.
There is a lower limit on when open glory holes would be effective. Glory holes only offer protection from gouging keels. Where active ridge building is taking place, at around perhaps 65 ft (20 m) water depth, or where grounded ridges are pr esent, there is the potential for a ridge keel to be pushed into an open glory hole as the keel is being formed. Further site-specific analysis would be requi red to determine the r ange of water depths between which this protection strategy could be used. If glory holes were to be considered for protection in an active ridge building area, they may need to be cased and a cover incorporated into the design for protection.
Beyond the zone of active goug ing, about 165 to 200 ft (50 to 60 m) water depth depending on the location, subsea facilities might be pl aced directly on the seabed (depending on the ice gouging regime). In any event, deeper water location scenarios (beyond which production platforms are not feasible) will likely require some type of su bsea facilities on the seabed, whether they are part of a subsea to beach option or tied into a central production facility in shallower water.

5.3.7 Pipelines & Flowlines
There are a number of issues to be considered with regard to the protection of pipelines and flowlines in arctic environments such as the Alaskan OCS, over and above what might normally be considered for pipeline design in more temperate climates. These include issues surrounding design, construction, oper ations, maintenance and repair. PipelinesIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 309 of 339 Rev. 0 have been designed, constructed and are operat ional in the arctic, but these are in relatively shallow water depths and relatively close to shore. Pushing the limits to developments further offshore, in deeper water, will require that additi onal consideration be given to some of these aspects.

5.3.7.1 Design
Some of the main considerations with respect to pipeline design in t he Arctic are strudel scour, thaw settlement of permafr ost, upheaval buckling and ice gouging.
The first two design issues happen over very limited distances of t he nearshore portion of the pipeline and have been addressed in existi ng pipeline designs. The third issue, upheaval buckling, can happen in any region of the pi peline if conditions are conducive to buckling. Installation procedures have been impl emented on past projects to minimize the risk of upheaval buckling (considered limits on installed pipeline prof ile, use of select backfill or additional weight over imperfections). Therefore, it is generally felt that these three considerations can be designed for on future projects.
It is generally accepted that offshore arctic pi pelines would need to be trenched to some depth below the seabed to protec t the pipeline from the effect s of pressure ridge ice or iceberg keels. This burial dept h would be such that the ice would not contact the pipeline plus any required clearance bet ween the bottom of the ice keel and the pipeline such that soil loadings on the pipeline ar e within acceptable limits (Fi gure 4-29). A number of buried offshore pipelines are being successfully operated in ice gouge env ironments, including projects in the Alaskan OCS (e.g., Northstar, Oooguruk).
Trench depths will increase in areas of more se vere gouging. In nearshore zones (less than 33 ft (10 m) water depth), pipelines might be ex pected to be buried less deep than those in deeper water due to the less severe gouging. In the 65 to 130 ft (20 to 40 m) water depth range, ice gouging would be more extreme and result in the deepest burial. In waters deeper than this, gouge depths begin to taper off, as do the burial depth requirements. Offshore pipelines may be required to be trenc hed to approximately 165 to 200 ft (50 to 60 m) water depth in areas subjected to active ice gouging.
Ice gouging is only one factor in the overa ll determination of burial depth and must be examined in conjunction with ot her factors such as thaw settlement, upheaval buckling, strudel scour, pipeline stability and flow assur ance. However, as mentioned above, theseIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 310 of 339 Rev. 0 other aspects can likely be acco mmodated, given successful oper ation of projects in the shallow waters of the Beaufort.

5.3.7.2 Installation
Offshore arctic equipment and logistics requirem ents for summer and winter installation of pipelines are quite different. Construction methods for summer (open water) and winter construction (from ice) need to be evaluated to identify the best potential method with respect to probability of success, logistics cost and schedule.
While trenching from the ice to a certain water depth has been proven on projects in the nearshore Beaufort Sea, trenchi ng and pipeline installation from floating vessels has not yet been attempted.
Floating vessels used in trenching or in support of trenching during open water may be subject to ice incursions. Equipment that is not designed for such an environment may be subject to damage under these conditions. C onventional trenching eq uipment may also have water depth or trench depth limitations which will need to be assessed.

Installation equipment must be suitable for use under the appropriate environmental conditions regardless if summer construction or winter constructi on is planned. Similar general considerations apply as noted fo r trenching equipment operations.
Given potential burial depth requirements fo r pipelines in deeper water (>50 ft or 15 m water depth), technology to economically trenc h and backfill these pipelines is considered one of the most significant issues with r egards to successful project execution.
5.3.7.3 Operations
Consideration also needs be given to leak detection technology that might be used to detect leaks (in the unlikely event of a pipelin e leak) in an environment where the sea is frozen over for most of the year.

An assessment on how pipeline repairs would be executed in t he unlikely event of damage also needs to be carried out. The logistics for pipeline repairs will largely depend on the season, sea ice conditions and whether or not the repair is temporary or permanent. Further work is needed to determine if mec hanical repair devices are appropriate for a permanent arctic offshore repai r, where the pipeline may s ubsequently be subjected to significant strains.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 311 of 339 Rev. 0 5.3.8 Export Terminals A marine export terminal is defined as a comple x of structures and equipment for loading of hydrocarbon products, either pum ped to a tanker from a storage facility located onshore or directly from a processing facility.
In most cases, marine transportation of hy drocarbon products starts with large storage facilities located onshore. The land-based components of these facilities (tank farms, loading pump stations, treatment plants, etc.) in the Arctic ar e basically the same as those in moderate climates. The main difference is primarily in providin g the conditions and the process equipment to allow continuous operation under low temperatures, icing and snowfall conditions. Flow assurance is a crit ical consideration for arctic and sub-arctic locations. Consequently, to ens ure smooth operations, an import ant aspect of any terminal concept is the need for proper insulation and heat-tracing tec hnology on piping and pipelines.
Alternatively, hydrocarbons may be loaded on tankers at sea or in the vicinity of production platforms, either from the platform storage tanks or from a FSO (Floating Storage and Offloading) vessel. The FSO may also be used in the nearshore for temporary storage or trans-shipment loading.
Particularly challenging in the Arctic is the offloading of products to tankers. This operation would need to be conducted in floating ice if year-round operations are going to be carried out.

5.3.8.1 Technica l Feasibility
The technical feasibility of marine terminals in arctic areas has been established through successful experience in a wide range of port facilities (Tsinker, 1995). These include the port structures and terminals in Nome, Cook Inlet, Anchorage and Valdez (Alaska), Godthab and De Long (Greenland), Nanisivik (N orth Baffin Island, Canada), St. David de Levis and Caps Noirs (Quebec, C anada), Norwegian and Russian ports in the Barents Sea (Murmansk, Arkhangelsk), and Magadan and Petropavlovsk (Ok hotsk Sea, Russia). The most recent examples are t he large Oil Terminal in DeKast ri and the LNG Terminal in Prigorodnoye (Sea of Japan), Russia.
The common specific feature, as well as t he main challenge in all of these ports and terminals projects, is that the marine struct ures are to be operated and maintained under adverse ice conditions. Very large latera l loads may be generated during floatingIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 312 of 339 Rev. 0 ice/structure interaction, both in the crushing and in the impact mode. As well, significant uplift and/or additional compression loads may be generated during tide variations due to ice adfreeze to the structure. Floating ice not only directly affects the terminal structures, but also significantly complicates vessel operations:
The loads generated through ice/stru cture interaction, in most cases, govern the design of arctic ports and terminal structures.
A general review of experienc e in operation of high-latit ude oil and gas marine terminals indicates that existing technology of port struct ures design and construction is sufficient to support operations in the Alaskan OCS. Ne w technology development s will be required in shipping operations, primarily by providing the hi ghest level of safety of tanker operations in ice-infested waters and by maximizing t he efficiency of ice management systems.
While technically feasible, no tanker tra ffic has been proposed in the EIS for upcoming Beaufort or Chukchi lease sales. Regulator y requirements would require the use of pipelines (if economically feasib le) rather than barging or tanker ing production to shore. An exception may be gas export by LNG or CNG.
5.3.9 Other Technologies
5.3.9.1 Extended Reac h Drilling (ERD)

The use of extended reach dril ling (ERD) has matured on some projects and upwards of 37,000 ft (11,200 m) wells are cu rrently achievable. Theref ore, ERD from shore is considered technically feasible for nearshore lo cations considered in this study. While not specifically feasible for location scenarios further offshore, it is obvious that the technology could be applied where the right condition s exist. The use of ERD offshore could be considered for any of the other scenarios t hat would utilize a platform and on which the equipment could be mounted.
5.3.9.2 Well Intersection Method (WIM)
The well intersection method (WIM) may offer an alternative means of transporting product from a producing well to shore in arctic environments. While t he limit of this technology is currently estimated to be a maximum of approx imately 6.2 miles (10 km), it has been suggested that spans may be daisy-chained together to make longer length connections (Lee et al., 2005). Further work is needed to veri fy this technique for arctic environments and to look at the economics compar ed to traditional trenched pipelines.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 313 of 339 Rev. 0 5.3.9.3 Pilot Hole to Pilot Hole HDD
A pilot hole to pilot hole HDD (horizontal directi onal drilling) installation can be considered as an option to conventional pi peline installation. However, th ere are length limitations to what can successfully be accomplished. If dai sy-chaining spans together was feasible, the technology could be applied to access great er distance under the right conditions.

5.4 Recommendations

5.4.1 Ice and Metocean Information As part of the scope of this study, the work wa s to include an evaluation of facilities not only in ice, but also in open water with large fetches and waves. If ice conditions in the Arctic deteriorate, it might be expected that fetch di stances increase, result ing in higher waves.
There is general agreement t hat environmental conditions (especially waves and ice conditions) are changing in th e Arctic. But no one definitivel y knows by how much, nor is there a compilation of current information (that t he Study Team could find) that provides the information necessary for those interested in Al aska OCS projects to draw upon. The Study Team has tried to account for this in this study (somewhat) by reviewing a significant amount of literature, as well as holdi ng discussions with selected stakeholders.
It has been suggested by stakeholders that t he MMS might consider a future study to compile, collect, and/or generate (e.g., hindc ast) ice, metocean, and meteorological information to be used by interested parties in screening studies.
5.4.2 Perceived Gaps In carrying out this study, the Study Team ident ified additional informa tion that would be “valuable to have” for future work. In addition, some technological areas were identified where advancements should be pursued.
These areas are included here as “perceived gaps ” with respect to arctic development. This is not to imply that these ar e the responsibility of the MMS to advance (although they might be given consideration), but rather are included for completeness.

• Regional gouge database fo r the US Beaufort and Chukchi Seas. This would include a plan for repetitive mapping similar to the one established and maintained in the Canadian Beaufort by the Geological Survey of Canada (GSC);IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 314 of 339 Rev. 0 • Ice gouge recurrence rates;

• Multi-year ice thickness distribution, ridge dimensions and frequency within a floe, floe size distributi on, floe speed distribution;

• First-year ice thickness distribution, ridge dimensions;

• Regional geotechnical database for t he US Beaufort, Chukchi and Bering Seas;

• Advancements in allowable/acce ptable pipeline strain limits;

• Advancements in pipeline repair techniques for arctic pipelines;

• Advancements in pipeline leak det ection systems for use in arctic environments;

• Advancements in subsea protection systems;

• Advancements in trenching technologie s for use in an arctic environment including assessment, development and field trials;

• Clarity on emergency well control requirements;

• Advancements in determining maxi mum gouge depth based on ice strength and driving forces; and

• Evaluation of climate change and ho w it may affect exploration and development.IMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

01/31/2008 Page 315 of 339 Rev. 0 6.0 ACKNOWLEDGEMENTS

Krylov Shipbuilding Research Institute 44, Moskovskoe Shosse 196158, St.Petersburg Russian Federation
http:/www.krylov.com.ru

Contact person: Head of Design and Rese arch Centre of Ocean Engineering Krylov Shipbuilding Research Instit ute, Professor Evgeny M. Appolonov

Phone: (812) 723-6619 Fax: (812) 727-9609 E-mail: appolonov@krylov.spb.ru, orlan@krylov.sp.ruIMVPA Project No. C-0506-15 Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf

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