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 Outer Continental Shelf (OCS). Advances in 

harsh environment offshore exploration and production technology have made it 

economically and technically feasible for projects to proceed in ice-covered waters. 

This study assesses the current state of offshore technology 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 technologies that might be applied on the US 

OCS, in particular those areas in the Beaufort, Chukchi and Bering Seas. 

The work covers exploration structures, bottom-founded and fixed production concepts, 

floating production concepts, terminals, pipelines and subsea facilities, 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 state-of-practice and state-of-the-art used in, or 

proposed for, arctic and sub-arctic offshore development areas. Assessments of 

exploration and production options are primarily based on technical feasibility. As 

appropriate, other aspects have also been considered, including constructability, capital 

costs, environmental considerations, operations, maintenance and repair, abandonment 

and decommissioning. 

Given the large geographic area encompassed by the Beaufort, Chukchi and Bering Seas, 

location scenarios were adopted to help focus the assessments. These locations were 

chosen based on current and historic activity and interest (including lease sales, drilling, 

studies, projects, etc.) and water depths (given the general differences in offshore facilities 

configuration with water depths). Overall applicability of the technology 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 OCS, 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 foundation properties are good, and up to around 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 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 solutions out to 500 ft (150 m) water depths 

are potentially viable. 

Jacket & Jack-up Structures

The ice reinforced jacket platform was first successfully used in sea ice in the mid 1960’s 

for Cook Inlet, Alaska developments. Previous studies have suggested that jacket 

structures are suitable for areas of the Bering Sea. However, these studies did not consider 

the vibration responses associated with the dynamic ice loading. 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 potentially poor response to dynamic loading and the 

need for conductor system protection are significant design issues for application in the 

Bering Sea. 

Current design practices and understanding of jacket design 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 range and season of jack-up exploration 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 practice, 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, the use of operational ice islands might be 

achieved in water depths of up to approximately 30 ft (9 m). The MMS Ice Island Study 

(2005) suggests that “incremental improvements in equipment capacity with higher 

productivity would allow islands to be constructed into deeper water and it is considered 

that 40 ft (12 m) water depth should not present a problem”. 

The use of ice islands in the nearshore Chukchi would likely be infeasible due to the 

unstable and unreliable landfast, or contiguous, ice zone. Ice islands would be generally 

infeasible for Norton Sound due to its warmer and shorter winter 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 structure has been used in the Chukchi Sea, a more detailed 

assessment would be required to determine feasibility. Due consideration would need to be 

given to the fact that the nearshore Chukchi Sea ice environment may be more dynamic 

than the Beaufort Sea. In the nearshore Bering Sea, gravel 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 exploration or production structures 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 location that a floating structure 

might be capable of staying on station year-round might be the 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 systems 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 sufficient depth, protection from ice would not be 

necessary. In areas with water depths less than 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 resources in harsh and remote environments. As a result of these 

improvements, fields requiring 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 reached 40 miles (65 km). 

Subsea facilities can potentially be considered for any development on the Alaskan OCS. 

However, there are limitations on which technology should be or would need to be 

considered. Glory holes would only offer protection from gouging keels. Where active ridge 

building is taking place or there 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 operational 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 additional consideration is 

given to aspects related to design, construction and operation. 

Some of the main considerations with respect to pipeline design in the arctic are strudel 

scour, thaw settlement of permafrost, upheaval buckling and ice gouging. It is generally felt 

that the first three considerations can be designed for on future projects. However, pipeline 

burial for protection in water depths from approximately 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 installed from the ice in winter. While trenching from the ice to a 
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 v of xxvi Rev. 0

certain water depth has been proven on projects in the nearshore Beaufort Sea, trenching 

and pipeline installation from floating 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 range of port facilities. A general review of experience in 

operation of high-latitude oil and gas marine terminals indicates that existing technology of 

port structures design and construction is sufficient to support operations in the Alaskan 

OCS. 

While technically feasible, no tanker traffic has been proposed in the EIS for upcoming 

Beaufort or Chukchi lease sales. Regulatory requirements would require the use of 

pipelines (if economically feasible) rather than barging or tankering 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 conditions (especially waves and ice conditions) 

are changing in the arctic. But no one knows definitively by how much, nor is there a 

compilation of current information (that the Study Team could find) that provides the 

information necessary to draw upon. It has been suggested by stakeholders that the MMS 

might consider a future study to compile, collect and/or generate ice, metocean and 

meteorological information to be used by interested parties in screening studies.

In carrying out this study, the Study Team identified additional information that would be 

“valuable to have” for future work. In addition, some technological areas were identified 

where advancements should be pursued, and these 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 Introduction ................................................................................................................ 1

1.1 Introduction & Overview......................................................................................... 1

1.2 Background............................................................................................................ 1

1.3 Study Technical Objectives.................................................................................... 3

2.0 Arctic Structures ........................................................................................................ 4

2.1 Evolution of Arctic Structures & Facilities............................................................... 4

2.2 Primary Design & Operation Considerations.......................................................... 8

2.2.1 Ice Loads ........................................................................................................ 8

2.2.1.1 Full-Scale Ice Load Measurements ......................................................... 8

2.2.1.2 Geotechnical Monitoring.......................................................................... 8

2.2.1.3 First-Year Ice Loads ................................................................................ 9

2.2.1.4 Hans Island Experiments & Multi-year Ice Impacts.................................10

2.2.1.5 Pipeline Considerations..........................................................................11

2.2.2 Wave Loads...................................................................................................11

2.2.3 Earthquake ....................................................................................................12

2.2.4 Foundation Reaction Loads...........................................................................12

2.2.5 Facilities Functional Considerations ..............................................................12

2.2.5.1 Deck Area...............................................................................................13

2.2.5.2 Oil Storage & Transportation ..................................................................13

2.2.5.3 Dry Storage ............................................................................................14

2.2.5.4 Environmental Safety..............................................................................14

2.2.6 Ice Gouge Effects ..........................................................................................14

3.0 Review of Exploration & Development Options .................................................... 16

3.1 General .................................................................................................................16

3.2 Analogue Area Selection ......................................................................................17

3.2.1 Selected Areas ..............................................................................................17

3.2.1.1 Cook Inlet ...............................................................................................17

3.2.1.2 Canadian High North ..............................................................................19

3.2.1.3 Canadian East Coast..............................................................................19

3.2.1.4 Offshore Greenland ................................................................................20

3.2.1.5 Eastern Russia (Sakhalin Island)............................................................20

3.2.1.6 Russian Arctic (Barents, Karas, Pechora, and Baltic).............................21

3.2.2 Screened Areas .............................................................................................24

3.2.2.1 North Caspian.........................................................................................24
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Project No. C-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 & Development Options .....................................................25

3.3.1 Bottom-Founded & Fixed Structures..............................................................25

3.3.1.1 Sakhalin Island .......................................................................................25

3.3.1.2 Russian Arctic.........................................................................................33

3.3.1.3 Canadian East Coast..............................................................................36

3.3.1.4 Cook Inlet ...............................................................................................42

3.3.1.5 Jack-up Drilling Rigs ...............................................................................46

3.3.2 Floating Structures.........................................................................................48

3.3.2.1 Canadian East Coast..............................................................................48

3.3.2.2 Canadian High Arctic..............................................................................62

3.3.2.3 Russian Arctic.........................................................................................66

3.3.2.4 Sakhalin Island .......................................................................................67

3.3.2.5 Offshore Greenland ................................................................................69

3.3.2.6 Semi-rigid Floater Concept .....................................................................71

3.3.2.7 Monocone Arctic Platform (MCAD).........................................................73

3.3.2.8 Conventional Floating Exploration Structures.........................................74

3.3.2.9 Henry Goodrich.......................................................................................77

3.3.3 Subsea Solutions...........................................................................................78

3.3.3.1 Canadian East Coast..............................................................................78

3.3.3.2 PanArctic Drake......................................................................................79

3.3.3.3 Russian Arctic.........................................................................................80

3.3.4 Pipelines ........................................................................................................80

3.3.4.1 PanArctic Drake......................................................................................80

3.3.4.2 Polar Gas Project....................................................................................83

3.3.4.3 Baydaratskaya Bay (Russia) ..................................................................89

3.3.4.4 Nord Stream Pipeline (Russia) ...............................................................90

3.3.4.5 Canadian East Coast Flowlines..............................................................92

3.3.4.6 Sakhalin Island .......................................................................................95

3.3.5 Export Terminals............................................................................................96

3.3.5.1 Canadian Arctic ......................................................................................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 Intersection Method ......................................................................104

3.3.7.2 Pilot Hole to Pilot Hole HDD .................................................................105
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Project No. C-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 Offshore 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 Caissons...................................................................................112

3.4.1.3 SSDC & SSDC/MAT (now SDC) ..........................................................112

3.4.1.4 CRI – Caisson-Retained Island ............................................................113

3.4.1.5 Molikpaq Mobile Arctic Caisson (MAC).................................................114

3.4.1.6 Concrete Island Drilling System (CIDS)................................................114

3.4.1.7 Barge Structures...................................................................................116

3.4.1.8 GBS Structures.....................................................................................118

3.4.2 Jacket Structures .........................................................................................119

3.4.3 Ice & Gravel Island Structures .....................................................................119

3.4.3.1 Grounded Artificial Ice Islands ..............................................................120

3.4.3.2 Gravel Islands.......................................................................................126

3.4.4 Floating Structures.......................................................................................134

3.4.4.1 Drillships ...............................................................................................134

3.4.4.2 Semi-Submersibles...............................................................................137

3.4.4.3 FPSO....................................................................................................138

3.4.5 Subsea Solutions.........................................................................................138

3.4.6 Pipelines ......................................................................................................138

3.4.6.1 BP Alaska Northstar .............................................................................138

3.4.6.2 Pioneer Oooguruk.................................................................................143

3.4.6.3 Nikaitchuq.............................................................................................145

3.4.6.4 BP Alaska Liberty .................................................................................145

3.4.6.5 Chukchi Sea Pipeline Studies...............................................................146

3.4.6.6 Bering Sea............................................................................................148

3.4.6.7 Mackenzie Delta (Dome, Esso, Gulf Canada) ......................................148

3.4.6.8 Amauligak.............................................................................................149

3.4.6.9 East & West Amauligak Pipelines.........................................................150

3.4.7 Extended Reach Drilling ..............................................................................150

3.5 Summary - Exploration & Development Options Review ....................................151

4.0 Assessment of Options ......................................................................................... 153

4.1 Approach.............................................................................................................153

4.2 OCS Scenarios ...................................................................................................153

4.3 Metocean/Ice Considerations..............................................................................155
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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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4.3.1 Beaufort and Chukchi Seas .........................................................................155

4.3.2 Bering Sea and South..................................................................................155

4.4 Geotechnical Considerations ..............................................................................156

4.5 Bottom-Founded Structures................................................................................157

4.5.1 Ice and Waves .............................................................................................157

4.5.2 Foundation Conditions.................................................................................158

4.5.3 Location Scenarios for Proposed Structures................................................159

4.5.4 Technical Feasibility of Structures ...............................................................162

4.5.4.1 Ice Loads ..............................................................................................162

4.5.4.2 Foundations..........................................................................................164

4.5.4.3 Steel vs. Concrete ................................................................................166

4.5.4.4 Wave Loads..........................................................................................167

4.5.4.5 Gravity & Foundation Reaction Loads ..................................................170

4.5.4.6 Vibratory Loads ....................................................................................171

4.5.4.7 Seismic Loads ......................................................................................171

4.5.4.8 Fatigue Loading, Brittle Fracture, & Temperature Effects.....................172

4.5.4.9 Oil Storage Effects................................................................................172

4.5.4.10 Platform Concepts ................................................................................173

4.5.5 Constructability ............................................................................................183

4.5.5.1 Foundation Issues ................................................................................184

4.5.5.2 Weather Window ..................................................................................184

4.5.6 Capital Costs ...............................................................................................184

4.5.7 Environmental Considerations.....................................................................190

4.5.8 Operations, Maintenance, & Repair.............................................................191

4.5.9 Abandonment & Decommissioning..............................................................191

4.6 Jacket & Jack-up Structures ...............................................................................192

4.6.1 Technical Feasibility.....................................................................................193

4.6.1.1 Arctic Jacket Structure Design Considerations.....................................193

4.6.1.2 Arctic Jacket Structure Enhancements.................................................196

4.6.1.3 Assessment of Jacket Platform ............................................................196

4.6.2 Constructability ............................................................................................198

4.6.3 Capital Costs ...............................................................................................198

4.6.4 Environmental Considerations.....................................................................198

4.6.5 Operations, Maintenance, & Repair.............................................................199

4.6.6 Abandonment & Decommissioning..............................................................199

4.6.7 Commentary on Jack-ups ............................................................................200
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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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4.7 Ice Islands...........................................................................................................203

4.7.1 Technical Feasibility.....................................................................................203

4.7.1.1 Feasibility of Selected Scenarios..........................................................208

4.7.2 Constructability ............................................................................................211

4.7.3 Capital Costs ...............................................................................................214

4.7.4 Environmental Considerations.....................................................................215

4.7.5 Operations, Maintenance, & Repair.............................................................216

4.7.6 Abandonment & Decommissioning..............................................................216

4.8 Gravel Islands .....................................................................................................217

4.8.1 Technical Feasibility.....................................................................................218

4.8.1.1 Feasibility of Selected Scenarios..........................................................222

4.8.2 Constructability ............................................................................................223

4.8.3 Capital Costs ...............................................................................................224

4.8.4 Environmental Considerations.....................................................................225

4.8.5 Operations, Maintenance, & Repair.............................................................226

4.8.6 Abandonment & Decommissioning..............................................................226

4.9 Floating Structures..............................................................................................227

4.9.1 Technical Feasibility.....................................................................................228

4.9.1.1 Ice Loads ..............................................................................................229

4.9.1.2 Wave Loads..........................................................................................231

4.9.1.3 Dynamic Positioning .............................................................................234

4.9.1.4 Mooring.................................................................................................235

4.9.1.5 Steel vs. Concrete ................................................................................236

4.9.1.6 Seismic .................................................................................................237

4.9.1.7 Oil Storage............................................................................................237

4.9.1.8 Floating Platform Concepts ..................................................................237

4.9.1.9 Assessment by Alaskan OCS Area ......................................................238

4.9.2 Exploration Operability in the Alaskan OCS.................................................239

4.9.2.1 Beaufort Sea Operability.......................................................................239

4.9.2.2 Chukchi Sea Operability .......................................................................240

4.9.2.3 Southern Bering Sea Operability ..........................................................240

4.9.3 Constructability ............................................................................................241

4.9.4 Capital Costs ...............................................................................................241

4.9.5 Environmental Considerations.....................................................................242

4.9.6 Operations, Maintenance, & Repair.............................................................242

4.9.7 Abandonment & Decommissioning..............................................................242
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Project No. C-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 Solutions................................................................................................243

4.10.1 Technical Feasibility.....................................................................................243

4.10.1.1 Subsea Tiebacks ..................................................................................243

4.10.1.2 Glory Holes & Protection ......................................................................244

4.10.1.3 Feasibility of Application of Subsea Technology at Location Scenarios ....

 ..............................................................................................................246

4.10.2 Constructability ............................................................................................249

4.10.3 Capital Costs ...............................................................................................249

4.10.4 Environmental Considerations.....................................................................250

4.10.5 Operations, Maintenance, & Repair.............................................................250

4.10.6 Abandonment & Decommissioning..............................................................251

4.11 Pipelines & Flowlines ..........................................................................................251

4.11.1 Technical Feasibility.....................................................................................252

4.11.1.1 Design Issues .......................................................................................252

4.11.1.2 Feasibility of Selected Scenarios..........................................................260

4.11.2 Constructability ............................................................................................267

4.11.2.1 Winter Construction vs. Open Water Construction ...............................267

4.11.2.2 Permafrost & Trenchability ...................................................................268

4.11.2.3 Trenching Equipment............................................................................268

4.11.2.4 Pipeline Installation...............................................................................272

4.11.2.5 Trenching & Backfill..............................................................................273

4.11.3 Capital Costs ...............................................................................................274

4.11.4 Environmental Considerations.....................................................................275

4.11.5 Operations ...................................................................................................276

4.11.6 Maintenance & Repair .................................................................................277

4.11.6.1 Monitoring & Maintenance ....................................................................277

4.11.6.2 Repair...................................................................................................277

4.11.7 Abandonment & Decommissioning..............................................................279

4.12 Export Terminals.................................................................................................279

4.12.1 General Requirements.................................................................................279

4.12.2 Technical Feasibility.....................................................................................280

4.12.3 Constructability & Capital Costs...................................................................282

4.12.3.1 General Marine Terminal Concepts for Arctic & Sub-Arctic Conditions 282

4.12.3.2 Offshore TLU Alternatives ....................................................................283

4.12.4 Environmental Considerations.....................................................................285

4.12.5 Operations ...................................................................................................286
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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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4.12.6 Maintenance & Repair .................................................................................287

4.12.7 Abandonment & Decommissioning..............................................................288

4.13 Other Technologies.............................................................................................288

4.13.1 Extended Reach Drilling ..............................................................................288

4.13.1.1 Technical Feasibility .............................................................................288

4.13.1.2 Constructability .....................................................................................290

4.13.1.3 Capital Costs ........................................................................................290

4.13.1.4 Environmental Considerations..............................................................290

4.13.1.5 Operations, Maintenance, & Repair......................................................291

4.13.1.6 Abandonment & Decommissioning.......................................................291

4.13.2 Well Intersection Method (WIM)...................................................................291

4.13.2.1 Technical Feasibility .............................................................................291

4.13.2.2 Constructability .....................................................................................292

4.13.2.3 Capital Costs ........................................................................................293

4.13.2.4 Environmental Considerations..............................................................293

4.13.2.5 Operations, Maintenance, & Repair......................................................293

4.13.2.6 Abandonment & Decommissioning.......................................................293

4.13.3 Pilot Hole to Pilot Hole HDD ........................................................................293

4.13.3.1 Technical Feasibility .............................................................................293

4.13.3.2 Constructability .....................................................................................294

4.13.3.3 Capital Costs ........................................................................................294

4.13.3.4 Environmental Considerations..............................................................294

4.13.3.5 Operations, Maintenance, & Repair......................................................294

4.13.3.6 Abandonment & Decommissioning.......................................................295

5.0 Summary, Conclusions and Recommendations ................................................. 296

5.1 Overview.............................................................................................................296

5.2 Assessment Methodology...................................................................................296

5.3 Summary & Conclusions.....................................................................................297

5.3.1 Bottom-Founded Structures.........................................................................297

5.3.1.1 Design Considerations..........................................................................298

5.3.1.2 Technical Feasibility of Structures ........................................................298

5.3.1.3 Capital Costs ........................................................................................300

5.3.2 Jacket & Jack-up Structures ........................................................................300

5.3.3 Ice Islands....................................................................................................301

5.3.3.1 Technical Feasibility .............................................................................301

5.3.3.2 Construction .........................................................................................302
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Arctic Offshore Technology Assessment 

of Exploration and Production Options for 

Cold Regions of the US Outer Continental Shelf

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5.3.3.3 Capital Cost ..........................................................................................303

5.3.4 Gravel Islands..............................................................................................303

5.3.4.1 Technical Feasibility .............................................................................303

5.3.4.2 Feasibility of Selected Scenarios..........................................................304

5.3.4.3 Constructability .....................................................................................304

5.3.5 Floating Structures.......................................................................................305

5.3.5.1 Exploration............................................................................................305

5.3.5.2 Production ............................................................................................305

5.3.5.3 Alaskan OCS ........................................................................................306

5.3.6 Subsea Solutions.........................................................................................307

5.3.6.1 Subsea Tiebacks ..................................................................................307

5.3.6.2 Subsea Facilities Protection .................................................................308

5.3.7 Pipelines & Flowlines...................................................................................308

5.3.7.1 Design ..................................................................................................309

5.3.7.2 Installation ............................................................................................310

5.3.7.3 Operations ............................................................................................310

5.3.8 Export Terminals..........................................................................................311

5.3.8.1 Technical Feasibility .............................................................................311

5.3.9 Other Technologies .....................................................................................312

5.3.9.1 Extended Reach Drilling (ERD) ............................................................312

5.3.9.2 Well Intersection Method (WIM) ...........................................................312

5.3.9.3 Pilot Hole to Pilot Hole HDD .................................................................313

5.4 Recommendations ..............................................................................................313

5.4.1 Ice and Metocean Information .....................................................................313

5.4.2 Perceived Gaps ...........................................................................................313

6.0 Acknowledgements ............................................................................................... 315

7.0 References.............................................................................................................. 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 

Experience 
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LIST OF FIGURES 

Figure 2-1: Arctic Caisson Drilling Structures....................................................................... 4

Figure 2-2: Evolution of Arctic Structure Loads and Foundation Requirements................... 6

Figure 2-3: Evolution of Ice Loads on Arctic Structure ......................................................... 7

Figure 2-4: First-Year Ice Loads (Blanchet and Kennedy, 1996) ........................................10

Figure 3-1: Oil and Gas Fields of Barents and Kara Seas (Imayev et al., 2005).................22

Figure 3-2: Orlan Platform off of Sakhalin (from PennWell Publishing, 2007).....................26

Figure 3-3: The Molikpaq Platform as part of the Vityaz Production Complex (Calitz and 

Mercer, n.d.).................................................................................................................27

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 Limited, 2007f) .............................................30

Figure 3-6: Installation of PA-B Platform, Sakhalin 2 (JSC Gazprom, 2007a).....................31

Figure 3-7: LUN-A Platform (JSC Gazprom, 2007a) ...........................................................32

Figure 3-8: Prirazlomnoye Platform (Madslien, 2006) .........................................................36

Figure 3-9: Hibernia Drilling and Production Platform with OLS (Bott, 2004) ......................37

Figure 3-10: Hibernia Platform (HMDC, 2007) ....................................................................38

Figure 3-11: Steel Stepped Gravity Base Structure ............................................................40

Figure 3-12: Cook Inlet Infrastructure (CIRCAC, 2007).......................................................42

Figure 3-13: Conventional Jacket Structure (OOP, 2007)...................................................43

Figure 3-14: Cook Inlet Jacket Structure (CIRCAC, 2007)..................................................43

Figure 3-15: Ice Resistant Jack-up Arkticheskaya 6500 / 10-30 (JSC Gazprom, 2007b)....48

Figure 3-16: Grand Banks Field Developments (Howell, 2007) ..........................................49

Figure 3-17: Terra Nova Field Development (Petro-Canada, 2007a)..................................50

Figure 3-18: Open Glory Hole (Petro-Canada, 2007a)........................................................51

Figure 3-19: Terra Nova FPSO (Petro-Canada, 2007a)......................................................52

Figure 3-20: Comparison of Mooring Capabilities (from PERD, 1998)................................54

Figure 3-21: White Rose Field Development Schematic (Clarke, 2001) .............................55

Figure 3-22: Typical White Rose Glory Hole (Lochte, 2007) ...............................................56

Figure 3-23: SeaRose FPSO (Husky, 2007a) .....................................................................56

Figure 3-24: SeaRose Offloading to Shuttle Tanker (Howell, 2007)....................................58

Figure 3-25: Design Concept of Drillships “Pelican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, 

and “Neddrill 2” (GustoMSC, n.d.)................................................................................60

Figure 3-26: Additional Design Details of “Pelican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, 

and “Neddrill 2” (GustoMSC, n.d.)................................................................................61

Figure 3-27: SPAR Concept for Offshore Canada (from Murray, 2004)..............................63
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Figure 3-28: Disconnected SPAR (from Murray, 2004).......................................................63

Figure 3-29: Cross-Section of Cape Alison Floating 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 (Courtesy of DC Marine)...........................................................68

Figure 3-31: SALM Buoy Ice Up After Storm Event (Courtesy of DC Marine).....................68

Figure 3-32: FSO “Okha” Connected up to Production SALM Buoy, Late Season (Courtesy 

of DC Marine)...............................................................................................................69

Figure 3-33: Atammik and Lady Franklin Exploration Licenses (Cooper, 2005)..................70

Figure 3-34: Potential Development Scenario Offshore West Greenland (Cooper, 2005) ..70

Figure 3-35: Arctic Semi-rigid Floater..................................................................................72

Figure 3-36: MCAD Platform (Paganie, 2007).....................................................................73

Figure 3-37: “Vidar Viking” Equipped with Compact Drill Rig, in the Central Polar Pack 

(Keionen et al., 2007)...................................................................................................75

Figure 3-38: Eirik Raude (Ocean Rig ASA, 2007) ...............................................................76

Figure 3-39: Henry Goodrich (Toolpusher, 2007)................................................................77

Figure 3-40: Drake Project Location Map............................................................................80

Figure 3-41: Drake Flowline Bundle (Palmer et al., 1979)...................................................81

Figure 3-42: Polar Gas Channel Crossings (modified from Kaustinen, 1981).....................86

Figure 3-43: Ice Island Bottom Pull Method (from Kaustinen, 1981) ...................................87

Figure 3-44: Ice Hole Bottom Pull Method (from Kaustinen, 1981) .....................................88

Figure 3-45: Polar Gas Foreshore Tunnel Concept (from Kaustinen, 1981) .......................89

Figure 3-46: Proposed Pipeline Location (Nord Stream, 2007)...........................................90

Figure 3-47: The Average Ice Extent during Mild, Normal, and Severe Winters, 

Respectively (Nord Stream, 2006) ...............................................................................92

Figure 3-48: Terra Nova Flowline Protection (Courtesy of Tideway, 2007).........................94

Figure 3-49: Technical and Economic Evaluation of Alternatives for Oil Transportation from 

Timano-Pechora Province, Krylov Institute Development (Krylov Institute, n.d.) .........98

Figure 3-50: Varandey TLU, General Concept (Krylov Institute, 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 Smith, 2004). .............................105

Figure 3-53: “Tempera” in Icebreaking Mode (SPG Media Limited, 2007h)......................107

Figure 3-54: Tarsiut Concrete Caissons during Installation and 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 for Sakhalin..........................115
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Figure 3-58: CIDS in the Beaufort and Under Tow to Sakhalin Island ..............................115

Figure 3-59: Niglintgak Barge Processing Facility (from Mackenzie Gas Project, 2004)...117

Figure 3-60: Proposed Placement of Niglintgak Gas Processing Facility on Seasonal Flood 

Plane (from Mackenzie Gas Project, 2006)................................................................117

Figure 3-61: Taglu Field Development (from Mackenzie Gas Project, 2006)....................118

Figure 3-62: Statfjord C under Construction (Statoil ASA, 2007) ......................................119

Figure 3-63: Four plus Four Template Jacket (modified from PMB Systems Engineering et 

al., 1983)....................................................................................................................120

Figure 3-64: Tarsiut Relief Spray Ice Island (ICETECH, 2008) .........................................122

Figure 3-65: Mars Spray Ice Island (C-CORE, 2005)........................................................123

Figure 3-66: Cost Comparison between Gravel and Ice Islands (C-CORE, 2005)............124

Figure 3-67: Alaskan Beaufort Sea Manmade Islands (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 September 1976 Showing Wave Action on the 

Sacrificial Beach Island Design (from Croasdale and Marcellus, 1977).....................131

Figure 3-70: Northstar Production Island (Thomas, n.d.) ..................................................132

Figure 3-71: Oooguruk Production Island (INTEC, 2007)..................................................133

Figure 3-72: Endicott Production Island (Thomas, n.d.) ....................................................133

Figure 3-73: “Northern Explorer II” (formerly the CANMAR Explorer II and Explorer II) 

(WorldOil, 2000).........................................................................................................134

Figure 3-74: Kulluk (Courtesy of DC Marine) ....................................................................135

Figure 3-75: The Kulluk - Operations with Icebreaker Support (Courtesy of DC Marine)..136

Figure 3-76: Ocean Odyssey (NationMaster, 2005)..........................................................137

Figure 3-77: Northstar and Liberty Project Location Map (from Lanan et al., 2001)..........139

Figure 3-78: Approximate Locations, Mackenzie Delta Development ...............................149

Figure 4-1: Assessment Study Areas with 2007-2012 Proposed Final Program Areas 

(modified from MMS, 2007c)......................................................................................154

Figure 4-2: Wave Load Comparison of Hibernia-type GBS vs. Stepped-style GBS 

(Fitzpatrick and Kennedy, 1997) ................................................................................170

Figure 4-3: Drawing No.1, Option No.1 – Platform 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 – Platform and Foundation for 100 ft (30 m) of 

Water .........................................................................................................................179
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Figure 4-6: Drawing No.4, Option No.9 – 445 ft (135 m) Stepped Steel 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 Hull Transverse Section 

and Design Particulars...............................................................................................182

Figure 4-9: Estimated 2007 Installed Platform Costs (USD), Platform Only Contracted to 

Shipyard, Exclusive of Topsides ................................................................................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, Cook Inlet (Courtesy of CIRCAC, 2007) ......195

Figure 4-12: Gorilla Class Jack-up (LeTourneau Technologies, 2007) .............................200

Figure 4-13: Positioning of Leg Horizontals to Avoid Sea Ice............................................201

Figure 4-14: Typical Ice Thickness Growth for Canadian Beaufort Sea (Modified from CCORE, 2005) .............................................................................................................204

Figure 4-15: Spray Ice Island Potential Failure Modes (Modified from C-CORE, 2005)....206

Figure 4-16: Spray Ice Production - Thetis Ice Island Project (C-CORE, 2005) ................212

Figure 4-17: Cost of Ice Island vs. Gravel Islands (Reproduced from C-CORE, 2005).....215

Figure 4-18: Northstar Island during Summer (Colaska, 2007).........................................217

Figure 4-19: Northstar Production Island Ice Protection Design (BPXA, 2005).................219

Figure 4-20: Ice Clearing on Northstar Island (Colaska, 2007) .........................................220

Figure 4-21: Basic Designs for Granular Fill Artificial Islands used in the Canadian Beaufort 

(drawn with an approximate vertical exaggeration 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) (MMS, 2002) ........................................................................................221

Figure 4-23: Peak Loads in Managed Ice - Effect of Ice Concentration on Various Structure 

Types (Reproduced from Comfort et al., 2001)..........................................................232

Figure 4-24: 100 year Return Wave Conditions in Area of Study; Grand Banks added for 

Comparison................................................................................................................233

Figure 4-25: Approximate Design Wave Loads - FPSO Basis (Note: wave loads for the 

Beaufort and Chukchi are for summer conditions and are not meant to imply year 

round FPSO operations) ............................................................................................234

Figure 4-26: Rough Comparison of selected Vessel Mooring Systems; with selected Ice 

Breaker Bollard Thrust for comparison (Comfort et al., 2001)....................................236

Figure 4-27: Glory Hole (From Coflexip Stena, 2000) .......................................................247

Figure 4-28: Mechanical Subsea Facilities Protection Concept for Water Depths to 30 m in 

the Canadian Beaufort Sea........................................................................................247
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Figure 4-29: Ice Gouge and Subgouge Deformation.........................................................254

Figure 4-30: Subsea Pipeline Upheaval Buckling (After Palmer et al., 1990)....................257

Figure 4-31: Strudel Scour (Courtesy of Minerals Management Service) .........................258

Figure 4-32: Ice Gouge Depth vs. Water Depth, Combined New & Unknown Age Gouge 

Data from the Alaskan Beaufort Sea..........................................................................264

Figure 4-33: Ice Gouge Depth vs. Water Depth, Known Age Gouge Data from the Alaskan 

Beaufort Sea ..............................................................................................................265

Figure 4-34: Ice Gouge Depth vs. Water Depth, Unknown Age Gouge Data from the 

Chukchi Sea...............................................................................................................266

Figure 4-35: Typical Subsea Plow (Courtesy of SMD Hydrovision, 2007).........................270

Figure 4-36: Typical Jet Sled (Courtesy SMD Hydrovision, 2007) ....................................271

Figure 4-37: Typical Subsea Mechanical Trencher (Courtesy of Rocksaw International, 

2004)..........................................................................................................................272

Figure 4-38: Ice Breaker “Smit Sibu” Providing 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 Publishing, 2007).......................................................................................284

Figure 4-40: Icebreaker and Tanker Trials at Sakhalin (Courtesy of PennWell Publishing, 

2007)..........................................................................................................................287

Figure 4-41: Well Reach vs. Time (Department of Natural Resources, 1999)...................289
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LIST OF TABLES

Table 2-1: SDC Drilling Location Ice Loads (Hewitt 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 Inlet Platforms (CIRCAC, 2007)............................................45

Table 3-4: LeTourneau Super Gorilla Operating Parameters (from LeTourneau 

Technologies, 2007).....................................................................................................47

Table 3-5: Floating Ice Pads Constructed in the Canadian High Arctic...............................65

Table 3-6: Grand Banks Canada Glory Hole Dimensions (Technip, 2001) .........................79

Table 3-7: Deployments of Bottom-Founded Structures in the Beaufort Sea (by year).....110

Table 3-8: Deployments of Bottom-Founded Structures in the Beaufort Sea (by name)...111

Table 3-9: Summary of Grounded Artificial Ice Island Construction ..................................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 Regions Exploration & Development Options...151

Table 4-1: Location Scenarios – Bottom-Founded Structures...........................................161

Table 4-2: Approximate Ice Load Ranges, Beaufort and Chukchi Seas............................164

Table 4-3: Table of Wave and Ice Loads Used in Materials and Cost Estimation .............169

Table 4-4: Platform Particulars Options 1 to 4...................................................................174

Table 4-5: Platform Particulars Options 5 to 8...................................................................175

Table 4-6: Platform Particulars Options 9 to 12.................................................................176

Table 4-7: Estimated 2007 Installed Platform Costs, in Millions of USD, Exclusive of 

Topsides Costs if Platform Only is Contracted to Shipyard, Options 1 to 4................186

Table 4-8: Estimated 2007 Installed Platform Costs, in Millions of USD, Exclusive of 

Topsides Costs if Platform Only is Contracted to Shipyard, Options 5 to 8................187

Table 4-9: Estimated 2007 Installed Platform Costs, in Millions of USD, Exclusive of 

Topsides Costs if Platform only is Contracted to Shipyard, Options 9 to 12 ..............188

Table 4-10: Historic Bering Sea Wells Drilled by Jack-up Platforms (MMS, 2007a)..........202

Table 4-11: Comparative Feasibility of Ice Island Construction in the Beaufort Sea and 

Norton Sound.............................................................................................................209

Table 4-12: Construction Times for Operational 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 Floating Technologies in Study Areas......................239

Table 4-15: Project Capital Costs for Selected Developments at Time of Completion or 

Proposal (USD)..........................................................................................................242
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Table 4-16: Overall Glory Hole Dimensions (Technip, 2001) ............................................248
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LIST OF ACRONYMS 

3D: Three Dimensional 

ACEX: Arctic Coring Expedition 

AGPPT: Alaska Gas Producers 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 Marine Drilling Ltd. 

CGB: Concrete Gravity Base 

CIDS: Concrete Island Drilling System 

CNG: Compressed Natural Gas 

CRI: Caisson Retained Island 

CSA: Canadian Standards Association 
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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: Environmental Impact Statement 

ERD: Extended 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 Association of Classification Societies 

IMO: International Maritime Organization 

in: Inch 
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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 Allowable 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 Service 
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MMSCF: Million Standard Cubic Feet 

MMSCFD: Million Standard Cubic Feet per Day 

MODU: Mobile Offshore 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 Vehicle 
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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 Center of Gravity 

VIV: Vortex-Induced Vibration 

VLCC: Very Large Crude Carrier 

WIM: Well Intersection Method 
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W.T.: Wall Thickness 
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1.0 INTRODUCTION 

1.1 Introduction & Overview 

Offshore hydrocarbon exploration and production requires a bottom-founded platform, an 

artificial island, or a floating structure plus subsea equipment including pipeline/riser 

systems. Transportation of produced hydrocarbons to market is also an essential aspect of 

any development. An added complexity when hydrocarbon resources are located in arctic 

regions is the presence of first-year and/or multi-year ice during 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 the United States Department of the Interior, 

Minerals Management Service Request for Proposal (RFP), MMS Technology Assessment 

and Research (TA&R) Program, Operational Safety and Engineering Research (OSER) 

Broad Agency Announcement Solicitation 0106RP39786. Specifically, Objective #4, 

“Conduct a technology assessment for Outer Continental Shelf, Oil and Gas Operations in 

the Cold Regions to determine what may be technically 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 Canada (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 operational or planned for the United States (e.g., Northstar and 

Oooguruk), can provide insight and guidance into potential exploration and development 

technologies that might be applied to cold regions of the United 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, primarily ice, with waves, currents and seismic effects 

also playing significant roles; 
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• The platform/island/structure itself (whether exploration or development), 

together with its functional requirements which consist 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 factors dictates the geometry and material quantities 

required for exploration and production structures. Ice loads are clearly the governing 

design load for Beaufort and Chukchi Sea exploration and production structures. As a 

result of the oil and gas industry’s limited arctic offshore exploration activity over the past 

20 years, ice loads research has kept a low profile. Even so, through the 1990’s and to the 

present day, there have been significant advancements in fundamental ice mechanics and 

analysis of full-scale ice load measurements. Beginning in the early 1990’s, for example, 

Canadian Marine Drilling Ltd. (CANMAR) began promoting probabilistic predictive models 

based on the use of full-scale ice load measurements, such as the Hans Island 

Experiments. CANMAR’s models suggested that design ice loads were some 15 times lower 

than the estimates of the 1980’s. Other researchers have followed suit and ice loads 

currently developed by internationally recognized 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 with 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 aspects of arctic designs include environmental loadings (e.g., ice 

gouge, thaw settlement and strudel scour) and the effective use of limit state pipeline 

design for extreme loading conditions, such as those resulting from ice gouge and thaw 

settlement. 
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The transport of produced hydrocarbons from the arctic to market is also a significant 

consideration whether it be by pipeline, tanker or LNG/CNG carrier; each with its specific 

challenges. 

1.3 Study Technical Objectives 

The objective of this study has been to deliver an assessment of oil and gas technology 

that may be applied to cold regions of the United States Outer Continental Shelf (OCS). 

Advances in harsh environment offshore exploration and production 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 technologies that might be applied on the US 

outer continental shelf, in particular those areas within the Beaufort, Chukchi, and Bering 

Seas. The work covers exploration structures, bottom founded and fixed production 

concepts, floating production concepts, terminals, pipelines, and subsea facilities, and also 

touches on some other technologies which might be relevant to Alaskan OCS exploration 

and development. 
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2.0 ARCTIC STRUCTURES 

2.1 Evolution of Arctic Structures & Facilities 

Exploration drilling for oil and gas in the Beaufort Sea began from gravel islands in shallow 

Alaskan State Waters in the late 1960’s and similarly 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 waters, followed in 1981 by the first use of a 

bottom-founded caisson system. Exploration activities commenced in Beaufort OCS 

regions in 1982 using gravel islands, ice islands, bottom-founded structures and drillships. 

Examples of bottom-founded structures deployed in the Beaufort Sea are presented in 

Figure 2-1. 

Figure 2-1: Arctic Caisson Drilling Structures 
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These bottom-founded structures were conceived primarily 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, the 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, backfill, densify the core (Molikpaq requirement), 

decommission and move. Although touted as “mobile” 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 addition of the MAT remains the only active bottom-founded exploration 

structure in the arctic offshore. 

In the early 1980’s, it was thought that an exploration (not production) structure for a 200 ft 

(60 m) water depth in the Beaufort Sea (Figure 2-2) had to be protected by a sand berm 

around 0.6 mile (1 km) in diameter 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 platform. These huge loads resulted from the 

extrapolation of small-scale tests directly to full-scale scenarios. 

However, the combination of operational experience and full-scale research programs has 

resulted in a global design load reduction factor of around 15 (Figure 2-3). This obviously 

has a direct bearing on the global size and cost of arctic production structures. A reduction 

factor of around two for local loading on a 10.8 ft2

 (1 m2) 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 predict the size, shape and weight of 

many arctic structures, including the following examples: 

• The MAT base for the SDC (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 estimated at 69,500 tons (63,000 tonnes) 

of steel. After one year’s engineering of detailed scantlings and third-party 
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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 Banks 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 University of Manchester - estimated the final required steel 

weight at 95,900 tons (87,000 tonnes) and 92,600 tons (84,000 tonnes), 

respectively (see Fitzpatrick and Kennedy, 1997). 

Figure 2-2: Evolution of Arctic Structure Loads and Foundation Requirements 
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Figure 2-3: Evolution of Ice 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 pilot pipeline projects 

have been constructed (e.g., PanArctic Drake, Northstar, Oooguruk, Sakhalin Island). In 

some cases, developments have been proposed without an offshore structure (e.g. 

PanArctic Drake). Several are planned to be constructed in coming years (e.g. North 

Caspian) while a number are being considered 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 PanArctic Drake and Polar Gas projects, explored 

innovative methods to protect the pipeline against ice gouging. Ongoing industry and 

research community work continues to progress offshore arctic pipeline design with regards 

to design gouge depths, subgouge deformation, and allowable pipeline strain limits. 
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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 extrapolating small–scale laboratory tests to full-scale scenarios 

greatly overestimates global ice loads 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 most 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 the loaded face of an arctic structure or in the surrounding ice 

were a traditional method of measuring ice loads. But it is impractical and expensive to 

outfit the entire width of a large arctic structure with instrumentation, so only very small 

portions were instrumented, if at all. The “local” pressures measured on these small contact 

areas were often averaged across the entire contact width, which assumed that the peak 

pressures at the instrumented locations occurred at the same time and also between 

instrumented locations. This type of analysis led to overestimation 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 inferred from the measured deformation using 

finite element techniques. CANMAR 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 observed. Global ice loads interpreted from ice 

instrumentation were found to be 2.0 to 3.5 times higher than 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 placing an upper bound on ice loads. More 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 in 
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“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 instrumentation) < 550 (< 500) 

 

2.2.1.3 First-Year Ice Loads 

First-year ice interactions with offshore structures are nominal, common loading events in 

the Beaufort Sea and other arctic regions. CANMAR compiled a database of measurements 

that included over 14,000 data points determined from re-analysis of 16 separate ice load 

data sets dating from as far back as 1966. Most of the data sets were collected during 

dedicated ice monitoring programs on Beaufort Sea structures and, in some cases, include 

load measurements in grounded ice rubble fields (see Blanchet and Kennedy, 1996). The 

advantage of using full-scale information is that natural effects such as ice temperature and 

the distribution of cracks and flaws 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 arctic structures for a variety of 

scenarios. The approach was used to secure drilling permits from MMS for year-round 

drilling operations for the SDC (formerly SSDC) in the Beaufort Sea. 
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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 contributions to the understanding 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 multi-year floes, determined from floe deceleration, 

were significantly lower than anticipated. 

Hans Island is a natural rock outcrop in the Kennedy Channel between Greenland and 

Ellesmere Island and it is impacted regularly by large ice 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 diameter, moving at 4 feet per second when it hit 

the vertical base of the rock island. This impact was a significant milestone event in the ice 

engineering community. It was certainly an important event to study member John 

Fitzpatrick’s understanding of ice-structure interaction, as he was present on Hans Island 

and was responsible for developing the analytical methodology for calculating the ice load. 
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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 Beaufort Sea ice feature) 

on a 230 ft (70 m) wide production structure would 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 related 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 must also be given to the design, installation 

and protection of subsea equipment such as wellheads and manifolds. Protection scenarios 

include placing the equipment below the maximum ice keel depth, 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 wave (100-year return period) 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. Functionally, the deck level for a bottom-founded 

production structure in the Beaufort Sea should be set to provide 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 design ice load, and will not govern the design. However, it does 

dictate a certain minimum freeboard above sea level which, in turn, influences the float-in 

stability requirements of the unit (the higher the center of gravity of the topsides, the more 

difficult the issue). 
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Wave loads are also a consideration for any floating type structure and subsea equipment, 

although such equipment has been designed for significant wave loads in other parts of the 

world. 

2.2.3 Earthquake 

Earthquake loads are also a consideration for bottom-founded structures and foundations. 

The SDC’s topsides, for example, were designed 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 lateral 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 definitely 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 assessment 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 trivialized 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 strength as the vertical 

sides. This is an important consideration for bottom-founded platform concepts. 

Foundation capacity associated with other concepts such as floating structures and their 

associated mooring systems must also be properly assessed. 

2.2.5 Facilities Functional Considerations 

Functional considerations must also be addressed when designing/evaluating islands, 

platforms or other structures. 
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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. While the amount of space required is site and 

project specific, many investigations over the past years result in a fairly consistent top 

deck requirement of about 110,000 ft2 (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 ft2

(10,000 m2) area, particularly in the US and Canadian Beaufort Sea, where 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 Storage & Transportation 

Many structures will be required to store oil in significant quantities particularly where 

product transportation is by ice breaking tankers. If use is made of the wet storage 

principle, i.e., either oil or water is present in the holding tanks 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 storage capacity that is “free”, so to speak. This is because the 

presence of significant environmental loads requires a certain minimum size of structure for 

stability alone. Whether or not it achieves its weight as a result of oil or water ballast does 

not make a great difference (dry storage is different; there is no “free” dry storage). This 

minimum size structure varies a great deal according to regional 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 relatively 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 product transportation system. 

In general, the minimum storage capacity is related to the off-loading cycle time. The offload quantity within each cycle is of course equal to the unfactored storage capacity. Where 

the free storage capacity is greater than this minimum, then use of this knowledge can be 

made to optimize further the tanker power, cycle times and carrying capacity. 
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2.2.5.3 Dry Storage 

Where dry storage is required this adds significant expense to the basic structure. In many 

instances the premium can be around 30% or more of the basic platform cost. For many 

reasons, it should be avoided if possible. 

2.2.5.4 Environmental Safety 

The product storage area, for environmental reasons, 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 outer face and the storage area. Approximately, 

this gives sufficient energy absorption capacity to resist penetration to the oil storage area 

by large icebreaking tanker traveling out of control at high speed. 

2.2.6 Ice Gouge Effects 

It is generally accepted that arctic pipelines would need to be trenched to some depth 

below the mudline to protect the pipeline from ice keels. Ice gouging of the seafloor is a 

near-shore feature for most of the northern continents where these ice keels intrude into 

water with depths less than the ice keel draft 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 keels 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 below 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 hence the strain in the pipeline, 

depends on the pipeline properties, the soil characteristics, the depth of the design ice 

gouge, and the depth of the pipeline below the mudline. The pipe must be trenched 

sufficiently beneath the influence zone of soil displaced below the ice keel to limit pipeline 
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strains to within acceptable limits. If the pipeline is trenched below the zone of significant 

soil movement, it will experience increased soil pressure but not high bending due to the 

relatively small soil displacements. If the pipeline 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 resulting strains in the pipeline must be 

calculated and evaluated. The effect of this soil displacement and the loading on the 

pipeline can be evaluated through non-linear finite element analysis. 
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3.0 REVIEW OF EXPLORATION & DEVELOPMENT OPTIONS 

3.1 General 

Offshore oil and gas exploration and production activities have been carried out and/or 

considered for a number of Arctic and cold ocean regions. A review 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 project team identified candidate analogue areas 

based on experience and an initial review of Arctic and cold region exploration and 

production activities. Candidate areas were then studied in sufficient detail to allow 

screening and subsequent selection 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 / technologies 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 selection/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 advances in exploration and production activities 

that have taken place in the Beaufort, Chukchi, and Bering Seas; these are reviewed below 
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in Section 3.4. Note that the US and Canadian Beaufort Seas are 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 presented in Table 3-1. The table also highlights some of the 

most significant activities undertaken, or considered, in each analogue area, along with the 

associated structure types and technologies. 

Subject areas of the Alaska OCS are included for completeness 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 considered for application in another area of the 

OCS. 

The following sub-sections provide discussion on selected analogue 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 estuary stretching southwest from Anchorage to the 

Gulf of Alaska. Oil was first discovered in Cook Inlet in 1963 and development commenced 

shortly thereafter. 

Infrastructure used to develop Cook Inlet’s offshore oil resources consist of fixed jacket 

offshore platforms connected to land based storage and distribution facilities via subsea 

pipelines. These structures are subject to first-year ice conditions ranging from 20 to 79 

inches (0.5 to 2.0 m) thick. 
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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, Pipeline 
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3.2.1.2 Canadian High North 

A limited number of projects were proposed for the Canadian High North including the 

Drake PanArctic gas project and the Polar Gas project. A Canadian company, PanArctic Oil 

Ltd., sponsored the Drake Field subsea completion 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 construct 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. 

Polar Gas was a consortium of American and Canadian companies formed in 1972 that 

investigated the possibility of bringing natural 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 the 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 developments use structures that are designed (at 

least to some degree) to withstand sea ice and iceberg loads. 

Although the Labrador Shelf does not have a production project to date, significant 

exploration has been carried out on the shelf and, in recent years, 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 offshore Nova Scotia (near Sable Island), 

experiences very little sea ice, and icebergs are rare. The likelihood of sea ice from the Gulf 

of St. Lawrence encroaching on the Sable development is very low; less than 1 percent 

based on 30 years of observations (CAEE, 2005). Furthermore, only one iceberg has been 
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reported in the Sable development 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 place off the east, north, and west coasts of 

Greenland; however, drilling has only been conducted offshore west Greenland. Initial 

exploration offshore west Greenland took place between the early to mid 1970’s with 

extensive seismic surveys. Following this period, five wells were drilled between 1976 and 

1977; however, interest in further exploration was curtailed when well results had indicated 

that the wells were dry (Geological Survey of Denmark and Greenland, 2005). 

Throughout the 1990’s, interest in offshore west Greenland began to grow and in 1997 

additional processing of well data suggested that the Kangamiut-1 (drilled in 1976) showed 

hydrocarbons (Geological Survey of Denmark and Greenland, 2005). In 2000, the sixth 

exploration well (Qulleq-1) was drilled. No further exploration 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). Some 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, north of Japan, which is part 

of Russia. Projects currently producing oil offshore Sakhalin Island include Sakhalin 1 

(ExxonMobil) and Sakhalin 2 (Shell) directly off the east coast of Sakhalin. These projects 

have been developed using retrofitted gravity base platforms from the US Beaufort (CIDS) 

and the Canadian Beaufort (Molikpaq). Future proposed 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 projects currently being 

considered. 
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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-Astokskoye, 

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 blocks. 

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 five 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), IHS 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 Canadian 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 latitudes. If there is any difference, it probably 

manifests in conditions for transportation, and in the available infrastructure which, in the 

Russian case, may be more challenging. 

The routes from the main Russian Arctic fields to European and American consumers are 

fairly long and are through remote areas both in the sea and on land. A map showing the 
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location of the main fields of the Russian Arctic 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. Descriptions 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 Barents 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 progressing along the European coast (Barents Sea, 

Pechora Sea). According to some recent publications (Snieckus et al., 2007), questions still 

surround ultimate recovery calculations and what will be required to bring the gasdominated production to the market. However, the pace of technological developments for 
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exploration in the Russian Arctic remains high. These developments are expected to be 

dominated in the near future by the exploration 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 will apparently stay at the 

forefront of contemporary Arctic development technology. 

Technical information on exploration 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 technology projects was collected during an 

information gathering trip to Moscow and St. Petersburg in April, 2007. This information has 

been mainly included in Section 3.3 and within Appendix D. 

The meeting with the specialists of Krylov Shipbuilding Research 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 promotional manual prepared by the Institute lists over 200 projects 

and contains brief descriptions of approximately 75 of them (Krylov Institute, 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 indicates the significance of Arctic development in 

the overall scope of oil and gas exploration 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 Institute of Natural Gases) in Moscow. 

Presently, VNIIGAZ is a leading scientific institution of Gazprom (the largest Russian oil 

and gas enterprise). The technology research is conducted in the VNIIGAZ Offshore Oil 

and Gas Fields Center (Gazprom and VNIIGAZ, n.d.). 

Information on development in the Russian Arctic is also contained in reviews prepared by 

foreign companies and in published results of their joint studies with Russian companies 

and institutions (Frantzen and Bambulyak, 2003). 
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A number of pipelines have been considered for the Russian Arctic, including pipelines 

across the Baltic Sea, Baydaratskaya Bay, the Pechora region, and the Barents Sea. Most 

activity currently being planned for the Barents Sea seems to be for the western part which 

is essentially ice free. 

3.2.2 Screened Areas 

In addition to the areas discussed above, the following list of areas were initially considered 

candidate analogues. However, upon further consideration 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 extent 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 stamukhi. Rafted ice regularly reaches over 

3.3 ft (1 m) in thickness in the early ice season 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 water 
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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 similar to the Alaskan OCS areas, the major 

differences are the thickness of the ice and the water depths. Therefore, 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 oil (Indian and Northern Affairs 

Canada, 1995) as there is evidence 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 part of this study, Baffin Bay is not being 

considered further in this study. 

Ice resistant structures have been considered 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 North Sea and Norwegian Sea are not subject to 

regular seasonal ice coverage or multi-year ice intrusions, they 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 Platform (Figure 3-2). Compared 

to the cost of a newbuild, the cost to purchase, 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 time of purchase, it had been 

mothballed off the north slope of Alaska. Refurbishment started in 2001 and included 
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installing a wave deflector shield, and strengthening the platform base to resist earthquake 

effects (PennWell Publishing, 2007). 

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

Sakhalin 2

The first phase of the Sakhalin development began with the Molikpaq platform producing oil 

from the Astokh feature of the Piltun-Astokhskoye field back in 1999. The Molikpaq is the 

first offshore oil production platform in the Russian Federation. It is located on the Astokh 

feature of the Piltun-Astokhskoye (PA) reservoir offshore Sakhalin. Sakhalin Energy has 

been successfully producing oil from the Vityaz Complex since July, 1999. Up until 2007, 

production from a floating storage and offloading unit was limited to the summer ice-free 

season. 

The Vityaz Complex consists of the Molikpaq production platform (Section 3.4.1.5), a single 

anchor leg mooring buoy (SALM) and the Okha floating storage and offloading (FSO) unit 

(Figure 3-3). During the ice season, following the disconnection from the Okha FSO, the 

SALM is ballasted down on the sea bottom thus completing preparations for the winter. 
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Figure 3-3: The Molikpaq Platform as part of the Vityaz Production Complex (Calitz and 

Mercer, n.d.)

Sakhalin Energy plans to convert 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 Phase 2 project is the second 

stage in plans to develop the Piltun-Astokhskoye oil field and the Lunskoye gas field. 

Together, the Piltun Astokhskoye and Lunskoye fields 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 reserves under development in the world (Sakhalin Energy, 

2006b). 

Once extracted, the oil and gas will be piped onshore for processing. It will then be 

transported via two 497 mile (800 km) pipelines to the LNG plant and oil 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. 
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The permanent offshore infrastructure installed for Sakhalin 2 includes a network of 

offshore pipelines and three bottom-founded production structures; the Piltun Astokh-A 

(PA-A) or Molikpaq, the Piltun Astokh-B (PA-B), and the Lunskoye A (Lun-A). These 

platforms are designed to operate 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 area with air temperatures that can reach 102°F 

(39°C) in the summer and -38°F (-39°C) during the winter, waves that can reach a 100-year 

maximum height of around 65 ft (20 m), and ice pressures of 0.6 psi (4 kN/m2) (Snieckus, 

2002). 

Figure 3-4: Sakhalin Island, PA-A, PA-B and Lun-A (Sakhalin Energy, 2007) 
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The Piltun Astokh-A 

The PA-A drilling and production platform (Figure 3-5) was made from the conversion and 

refurbishment of the mobile bottom-founded arctic drilling rig, the Molikpaq. The Molikpaq 

was an octagonal-shaped steel caisson structure designed to operate in the severe ice 

conditions of the Canadian Beaufort 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 reinforcing, 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 365 x 365 ft (111 x 111 m) and reduces to 285 x 

285 ft (87 x 87 m) at the top deck. The caisson supports a 240 x 240 ft (73 x 73 m) box 

girder deck structure, which carries the topsides and drilling facilities. 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 ft3 (278,000 m3) of sand which permanently 

anchors it to the seabed 10 miles (16 km) off the coast of Sakhalin Island in 100 feet (30 m) 

of water (SPG Media Limited, 2007f). 
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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 larger then the Lun-A platform described in the 

next Section; it carries topsides 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 four 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 Media 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 day 
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(11,000 m3) and up to 92 million standard cubic feet (2.6 million Sm3) 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 topsides 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 rectangular-shaped base caisson topped 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) (Rigzone, 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 capacity of 1.77 tcf (50 million m3

) of gas per day and 

50,000 barrels of condensate per day (Sakhalin Energy, 2006). 
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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 substructures, operating in 

the Sea of Okhotsk. The PA-B and the Lun-A platforms were originally designed as steel 

structures which was later revised 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 level earthquake (Beckman, 2004). At the top of the concrete 

gravity base legs, friction pendulum bearings connect the topsides to the substructure. 

These bearings isolate the topsides from severe earthquake motions by employing the 

characteristics of a pendulum to lengthen the structure’s natural period. When activated by 

a seismic shock, the convex bearing, or articulated 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 plate on which the topsides rest can twist, but the concave plate 

can also restore its own position and the topsides’ equilibrium (Beckman, 2004). 
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PA-B and Lun-A have been constructed with an unusually large 95 ft (29 m) air gap 

between the deck and the substructure, which compares with 62 to 72 ft (19 to 22 m) for a 

typical North Sea structure (Beckman, 2004). This air gap was necessary to guard against 

large ice blocks that get thrown against the 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 season. 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 development. Consequently, it will become the first oil 

producing offshore reserve on the European coast of the Arctic Ocean. The first oil 

production was originally planned for 2005 (Frantzen and Bambulyak, 2003), but now the 

field is expected to become operational in 2008 (PRINT-EXPO Co. Ltd, 2007). The various 

stages of Prirazlomnoye development may be traced through the series of projects 

executed by the Krylov institute (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 Exhibitions 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 approximately 65 ft (20 m) (see Figure 3-1). The 

estimated oil reserves at Prirazlomnoye 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 Statoil and Norsk Hydro. However, 

in 2002, after several variations in the prospective ownership, the operational license was 

issued to Sevmorneftegaz, led by the conglomerate of subsidiaries 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 described in Chernov (2005). The Arctic engineering 

aspects of the project became a focus of interest and research activities of the leading 
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Russian organizations began more than 10 years ago. It should be noted, that while 

western companies are actively involved in Prirazlomnoye, from the very beginning this 

development was geared towards maximizing 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 specialists of the Krylov institute conducted model 

tests of a gravity caisson for Prirazlomnoye back in 1996, long before the actual 

contemporary platform configuration was developed (Krylov Institute, n.d.). At that time, 

Krylov, on the orders from Rosshelf, were investigating the wave and ice loads on the 

caisson, including the ice pile-up formation at caisson walls. The work for the same client 

continued in 2000. By this time, Krylov researchers 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 development began in 2002, when Sevmorneftegaz (final field 

operations license owner) purchased the Norwegian TLP Hutton platform. The concept was 

to use the Hutton’s topsides as the Prirazlomnoye 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 superstructure 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 caisson structure and its ballasting. 

Installation of modified Hutton topsides on the caisson substructure was originally 

scheduled for July-August, 2006. The complete platform 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 Prirazlomnoye 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 Limited (2007a). The caisson’s footprint is 413 x 413 ft (126 X 

126 m). The platform has 14 oil storage tanks with the total capacity of 710,000 barrels 

(113,000 m3

) and 2 water tanks with the total capacity of 7,400,000 gallons (28,000 m3). A 

single derrick will service 40 well slots. 
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The protection berm will be placed around the caisson after the initial settlement at the site. 

The platform will be equipped with two offloading systems with capacities up to 353,000 

ft3

/hr (10,000 m3/hr) (SPG Media Limited, 2007a). The only information available on the 

design ice criteria is that the Prirazlomnoye platform will be able to safely resist the ice 

pressure generated by the ridge with a 11.5 ft (3.5 m) thick consolidated layer (Central 

Design Bureau for Marine Engineering (Rubin), n.d.). 

Medynskoye Field Platform

A gravity caisson platform is also considered for the Medynskoye oil field, which is located 

in the same general area as Prirazlomnoye (Figure 3-1). The field is closer to shore and the 

design water depth there is approximately 49 ft (15 m). The Medynskaya Center platform 

proposed for this field is an all-purpose structure (drilling, production, storage and 

offloading [Krylov Institute, n.d.]). The platform 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 level. The total substructure weight is 

130,000 tons (118,000 tonnes). The topsides consist of seven functionally completed 

modules with a total weight of 15,800 tons (14,300 tonnes) (Krylov Institute, n.d.). 
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Figure 3-8: Prirazlomnoye Platform (Madslien, 2006) 

3.3.1.3 Canadian East Coast 

Presently, the only permanent bottom-founded structure employed offshore Newfoundland 

and Labrador is the Hibernia platform. However, according to recent news, the Hebron 

project, which will also employ a fixed structure, may soon be underway (The Telegram, 

2007a; The Telegram, 2007b). 

Hibernia

The Hibernia oil field is located 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 Resources, 2007). Current recoverable reserves for Hibernia are 

estimated to be 1.244 billion barrels (Department of Natural Resources, 2007). Hibernia 

field development capital expenditures amounted to $5.8 billion (Howell, 2007). 
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The Hibernia platform (Figure 3-9, Figure 3-10), a gravity base structure (GBS) equipped 

with topsides production and drilling facilities, was employed for field development 

(Department of Natural Resources, 2007). The platform 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 light sweet crude with a gravity 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 Production 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 measure of safety, the tanker loading point is 

located 1.25 miles (2 kilometers) away from the platform (HMDC, 2007). 
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Hibernia utilizes 3 custom-built shuttle tankers for oil transport – the Kometik, Vinland, and 

Mattea. These shuttle tankers have storage capacities of 850,000 barrels, are doublehulled and have double bottoms with additional strengthening (particularly at the waterline). 

They are bow-loaded and are capable of quickly disconnecting from the OLS (HMDC, 

2007). 

The Hibernia platform has a total height of 735 ft (224 m) and weighs 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 topsides facilities, and 85 ft (26 meters) from the shafts that 

protrude through the GBS roof to support the topsides (HMDC, 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) 
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The Hibernia GBS is a one-off design. To allow year-round production, the Hibernia 

platform is designed to withstand impact from sea ice and icebergs (HMDC, 2007). 

Specifically, the platform is capable of withstanding the impact of a 1.1 million ton (1 million 

tonne) iceberg (1-in-500-year event) (SPG Media Limited, 2007d), without sustaining 

damage, and a 6.6 million ton (6-million tonne iceberg) (1-in-10,000-year event), with 

repairable damage (HMDC, 2007). Although the probability 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-strength reinforced and pre-stressed concrete, 

which is reinforced with steel (rebar) and pre-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 teeth intended to distribute iceberg loads over 

the entire structure (HMDC, 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, discovered in 1981, is located approximately 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 estimated 400-700 million barrels of resources 

(Chevron, 2007). With close-neighboring fields, 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 construction is expected 

as early as 2010 (Calgary Herald, 2007), and that the field may achieve first oil as early as 

2015 (The Telegram, 2007a). A preliminary cost estimate of $4 billion to $5 billion was 

reported for field development (The Telegram, 2007a). 

Although several options have been evaluated (subsea tieback, FPSO with subsea wells, 

new generation GBS, and FPSO with wellhead platform (Department 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 smaller then Hibernia, 

requiring less concrete and being easier to build (The Telegram, 2007b). 
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Other Proposed Grand Banks Structures

The Steel Stepped Gravity Base (SSGB) shown in Figure 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 Gravity Base Structure 
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The principal criteria affecting the design of an offshore platform in the Grand Banks 

environment is icebergs, waves and foundation strength parameters. 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 moment 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 elevation. A structure capable of resisting such an ice load has to 

be monolithic or non-wave-transparent. 

Ideally the design wave load would be very close to the ice load. The SSGB achieves this 

by reducing the diameter of the structure as it progress 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 ft2 (13,000 m2). The SSGB has been reviewed for 

deployment at several locations on the Grand Banks. Parameters chosen for the foundation 

design are considered representative of some of the weaker strength sites. Thus, the 

structure base area is unlikely to increase no matter where the structure might be 

considered for deployment. 

By optimizing the SSGB’s shape 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 tons (200,000 tonnes); 

• Provide free storage capacity. The structure needs a minimum footprint and 

size to resist the applied loads. This minimum size provides “free space”. This 

free space provides a storage capacity of 750,000 to 1,000,000 bbls; 

• Provide hydrostatic stability. Steel structures 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 VCG offers stability under towing and as a 

result the structure can be safely towed to site when loaded with up to 33,000 

tons (30,000 tonnes) of topsides; and, 
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• Minimize setup time. All solid ballast has been installed 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 structures have been installed at the Inlet using three structural 

concepts; the monopod, the tripod and the quadpod. The first of these structures was 

installed in 1964 and the last in 1986. 

Figure 3-12: Cook Inlet Infrastructure (CIRCAC, 2007) 
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The fixed jacket structures designed for Cook Inlet’s environment differ from conventional 

jacket structures in several ways: 

• Partially constructed from low temperature steel; 

• The jacket systems are composed of very large ice reinforced legs with 

diameters in excess of 14 ft (4.3 m); 

• The jacket bracing is located several feet below the water line. This protects 

the bracing from ice impacts and prevents ice bridging; and, 

• The jackets use an X-bracing system rather then K type bracing (Figure 3-13 

and Figure 3-14). This provides additional 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) 
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The Inlet’s jacket structures have been designed using a variety of ice loads, wave heights 

and water depths: 

• Ice thickness varying from 2.8 to 6 ft (0.9 to 1.9 m) with a crushing 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 specific location, the designer’s 

interpretation and application of the available metocean 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 Cook Inlet Regional Citizens Advisory Council 

website (CIRCAC, 2007). 
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Table 3-3: Summary of Cook Inlet Platforms (CIRCAC, 2007) 

Summary of Cook Inlet Platforms 

Wave 

Platform 

Name Type 

Design 

Ice 

Thick, 

ft (m) 

Height, 

ft (m) 

Period

(Sec) 

Wind 

Velocity, 

MPH 

(km/h) 

Earthquake

(g) 

Current, 

ft/s (m/s) 

Leg 

Dia., 

ft (m) 

Water 

Depth, 

ft (m) 

Year D

Anna Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 77 (23.5) 1966 Ea

A Quadpod 6 (1.8) 41.5 (12.6) 10.8 65 (105) 0.15 10 (3) 14.6 (4.5) 83 (25) 1964 Ea

Baker Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 102 (31) 1965 EaBruce Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 62 (19) 1966 Ea

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 Ea

Granite Point Quadpod 5 (1.5) 28 (8.5) N/A N/A N/A 13.5 (4.1) 17 (5.2) 75 (23) 1966 Bro

Grayling Quadpod 6 (1.8) 28 (8.5) 8.5 100 (161) 0.1 10 (3) 17 (5.2) 125 (38) 1967 Bro

King 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 Ea

Monopod Monopod 6 (1.8) 28 (8.5) 8.5 100 (161) 0.06 10 (3) 28.5 (8.7) 66 (20) 1966 Bro

Spark Tripod 3.5 (1.1) 28 (8.5) 8.5 60 (97) N/A 10 (3) 13 (4.0) 62 (19) 1968 M

Spurr Tripod 3.5 (1.1) 28 (8.5) 8.5 60 (97) N/A 10 (3) 13 (4.0) 67 (20) 1968 M

Steelhead Quadpod 4.2 (1.3) 28 (8.5) 8.5 80 (129) N/A 12.6 (3.8) 18 (5.5) 183 (56) 1986 M

Tyonek Quadpod 2.8 (0.9) 27.5 (8.4) 8.5 80 (129) 0.1 10.1 (3.1) 14 (4.3) 100 (30) 1968 M

Dillion Quadpod 2.8 (0.9) 30 (9) 9 80 (129) 0.1 10 (3) 14 (4.3) 92 (28) 1967 Ea

Dolly Varden Quadpod N/A N/A N/A N/A N/A N/A N/A N/A N/A 

Osprey N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 

N/A Not Available 
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The Inlet’s current metocean data characterizes 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 offshore 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 and 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 stability and buoyancy stability. 

Rig installation involves a wet or dry tow to site. Wet tows usually occur over short 

distances. Under wet tows, the rig provides its own buoyancy. Dry 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 now ready to begin drilling operations. Removal of the rig is the 

reverse of the installation. 

A modern drilling jack-up is capable of working in wave heights of 79 ft (24 m), in winds of 

100 knots, in water depths approaching 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. 
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Table 3-4: LeTourneau Super Gorilla Operating 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-Foot (184.1 meter) leg length. 

Dynamic effects included 

A study by CKJ Engineering (CKJ Engineering, 1997), the development and 

implementation of a jack-up drilling program on the Grand Banks of Newfoundland (Bagnel, 

2007) and the anticipated construction of a new Russian ice-resistant jack-up rig are 

indicative that the operating 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 brief investigations into the 

structural feasibility of using jack-up Rig SX during freeze-up in Sakhalin. 

The successful development and implementation of a jack-up drilling program on the Grand 

Banks of Newfoundland, Canada, was accomplished by the understanding of the ice-free 

season and implementation of an ice management program (Bagnel, 2007). 
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The ice-resistant jack-up rig Arkticheskaya (Figure 3-15) is under construction at the 

Severodvinsk Shipyard, Russia. It is being constructed to operate in Arctic water depths of 

up to 330 feet (100 m) and in ice flows of 1.6 feet (0.5 m) thick (MNP Global, 2007). 

In light of CKJ’s study, the successful implementation 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 extension of a traditional seasonal jack-up 

drilling program may be considered 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 producing fields in operation offshore Newfoundland within the Grand 

Banks Jeanne d’Arc Basin (Figure 3-16). Two of these fields, the Terra Nova and White 

Rose, have employed FPSO (Floating Production Storage and Offloading) vessels for field 

development. 
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Figure 3-16: Grand Banks Field Developments (Howell, 2007) 

Terra Nova

Discovered in 1984 by Petro-Canada, the Terra Nova field is currently the 2nd largest 

producing field off the east coast of Canada. Furthermore, the Terra Nova was the first 

‘harsh environment’ development 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 Nova project began in January, 2002 (Bott, 2004). 

Field recoverable oil reserves have been estimated at 440 million barrels and life of field is 

estimated to be 19-21 years (Petro-Canada, 2007a). 

As shown in Figure 3-17, a variety of equipment, vessels, and subsea infrastructure are 

employed for the development and operation of the Terra Nova field. 
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Figure 3-17: Terra Nova Field Development (Petro-Canada, 2007a) 

Through an integrated subsea and topside production system, oil is produced, stored, and 

subsequently offloaded to shuttle tankers. Production from subsea wells/trees is gathered 

by subsea manifolds and conveyed topside (to the FPSO) via flexible flowlines and risers. 

More then 25 miles (40 km) of flexible flowlines, control umbilicals, and dynamic risers were 

required for the project (Furlow, 1998). Flowline and riser inner 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 diameter 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 (Figure 3-18). Glory holes used for the project are 

approximately 38 ft (11.5 m) deep and base dimensions 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, the Queen of The Netherlands (Cottrill, 2000). 

Although considered sacrificial and equipped with ‘weak links’ to protect wellhead 

equipment, flowlines were trenched and buried in the seabed to provide stability, insulation, 

and afford some measure of protection from iceberg gouging. The initial plan was to 
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provide 5 ft (1.5 meters) of cover, however, due to trenching difficulties some flowlines were 

rock-dumped instead (Cottrill, 2000). 

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

To avoid icebergs and severe sea 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 allowing the FPSO to move off station and sail 

out of harms way. Once released, the spider buoy sinks to a mid-water equilibrium depth of 

115 ft (35 meters) (measured from surface to buoy top) (Cottrill, 2000). 

A planned disconnect, which entails well shut-in, depressurization, flowline flushing, etc., 

can be executed in under 4 hours, while in an emergency situation, disconnect can be 

achieved in approximately 15 minutes (Sofec, 2007). Up until the final moment of 

disconnect (i.e. prior to mechanical connector release), the sequence is reversible (Furlow, 

1998). The turret system is designed to reconnect 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). 
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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 25th

and was reconnected to it’s moorings on October 1st (Petro-Canada, 2006). 

There were a number of design challenges for the Terra Nova disconnectable turret 

system; severe weather and storm conditions, relatively shallow water, a large vessel, a 

significant number of risers, a heavy 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 helideck (Petro-Canada, 2007a). During operation, it 

has a draft of approximately 43 to 62 ft (13 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 bpd (Howell, 2007) and an integrated storage capacity of 

960,000 barrels of oil. 

Figure 3-19: Terra Nova FPSO (Petro-Canada, 2007a) 
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The Terra Nova FPSO is purpose built for the harsh environment experienced on the 

Grand Banks. In addition to a disconnectable turret, the Terra Nova is equipped with a 

double-hull, 3,300 tons (3,000 tonnes) of additional steel to provide ice strengthening 

(Petro-Canada, 2007a), and a thruster-assisted mooring system (Cottrill, 2000). 

As a result of ice strengthening, the Terra Nova is capable of withstanding the impact of a 

110,000 ton (100,000 tonne) iceberg traveling at 1-knot (Cottrill, 2000). Furthermore, it can 

operate in moderate to high pack ice concentrations (5 to 8/10ths) and is capable of 

maintaining station in concentrations of 8 to 9/10ths (PERD, 2002). 

The thruster-assisted mooring system is designed based on 100-year storm conditions; sea 

ice loads do not govern mooring design (Cottrill, 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 provide 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). 
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Rough Comparison of Vessel Mooring System Capabilities

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 Mooring Capabilities (from PERD, 1998) 

White Rose

The White Rose field (Figure 3-21) is located approximately 220 miles (350 km) east of 

Newfoundland’s Avalon Peninsula and about 31 miles (50 km) from the Terra Nova field 

(Clarke, 2001). 

Discovered in 1984, White Rose is the third 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 White Rose field are 283 million barrels (CNLOPB, 

2007a), and total production life is estimated 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 approximately 395 ft (120 meters) of water, and like its 

predecessor, the Terra Nova, field development 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). 
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Figure 3-21: White Rose Field Development Schematic (Clarke, 2001) 

At each drill center, subsea wells and equipment are clustered together and located in open 

glory holes to protect against potential iceberg gouging. White Rose glory holes, shown in 

Figure 3-22, are excavated to a maximum depth of 36 ft (11 meters) to ensure that the top 

of equipment (critical to well integrity) is located 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 grab 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 seafloor and are insulated for temperature 

maintenance (Husky, 2006). To afford a measure of iceberg protection, flowlines and 

umbilicals are equipped with weak link technology (Husky, 2006). 

Similar to the Terra Nova, White Rose field development is centered around the FPSO 

facility, the SeaRose (Figure 3-23). 
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Figure 3-22: Typical White Rose Glory Hole (Lochte, 2007) 

Figure 3-23: SeaRose FPSO (Husky, 2007a) 
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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 SeaRose 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 designed and purpose-built for the Grand Banks 

harsh environment. It is double-hulled, ice strengthened, and equipped with a 

disconnectable internal turret mooring system. The SeaRose hull form is based on a 

proven Grand Banks shuttle tanker design (SPG Media Limited, 2007b). Modifications to 

the tanker design included deepening 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 withstand 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 plan, 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 indicates that the SeaRose is likely 

capable of withstanding 1 ft (0.3 m) thick pack-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 (Clarke, 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 are not employed for station keeping (Clarke, 2001). The 

SeaRose mooring system is comprised of 3 groups 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 propulsion to move off station. 

Oil is offloaded from the SeaRose 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). Shuttle 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) 
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(Husky, 2001a). The hawser based mooring system has emergency 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, the Labrador shelf experienced 

significant exploration activity. During this time period, 26 exploration and 2 delineation 

wells were drilled. Five ‘significant discoveries’ were made with total reserves of 

approximately 4.2 tcf of natural gas (120 billion m3) (CNLOPB, 2007b) and 123 MMbbls of 

natural gas liquids (Wagner, 2003). 

In recent years, interest and activity offshore Labrador has increased. During a seminar in 

2003, Labrador Gas Revisited: Technologies for Development, Fluor Canada presented 

several options for gas production (Wagner, 2003). Based on the harsh environment 

characteristic of the Labrador Shelf region, the use of floating structures was considered on 

a seasonal basis. 

Fluor indicated that a combined 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 may not be economically viable 

and further analysis would be required (Wagner, 2003). To date, although progress has 

been made, a commercial CNG solution has yet to emerge. 
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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 ranged up to 1900 ft (580 m) and 

averaged around 655 to 985 ft (200 to 300 m). Wells took approximately 53 to 84 days to 

reach depths of 6900 to 10,500 ft (2100 to 3200 m). Frequently, wells 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 (DP) drillships utilized in the 

Labrador Sea were state-of-the-art vessels. The “Pelican”, “Pelerin”, “Petrel”, “BenOcean 

Lancer”, and “Neddrill 2” were all used extensively (Figure 3-25 and Figure 3-26). The 

“Sedco 445”, another DP drillship which drilled the Snorri J-90 well in 1975, was the first rig 

in the industry to operate on a well in full DP mode in 1971 offshore Brunei. One of their 

main advantages over moored vessels was enhanced 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 allowed great self sufficiency in this 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-shape hulls are subject to poor heave, pitch, 

and roll motions that prevent efficient drilling/completion/testing operations. For this reason, 

semi-submersible designs would be best in the later months of the Labrador drilling 

season, from a motion standpoint. 

The design of the “Pelican” series drillships has evolved over the years. The first units, 

“Pelican”, “Havdrill” and “Petrel” laid the 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 construct the ice-class drillships “Valentin 

Shashin”, “Mihail Mirchink” and “Viktor Muravlenko”. 
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Figure 3-25: Design Concept of Drillships “Pelican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, 

and “Neddrill 2” (GustoMSC, n.d.) 
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Figure 3-26: Additional Design Details of “Pelican”, “Pelerin”, “Petrel”, “BenOcean Lancer”, 

and “Neddrill 2” (GustoMSC, n.d.) 
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Orphan Basin

The use of a SPAR under ice conditions on the east coast 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 were 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 that the structures can be built either out of steel or concrete. The 

structure can also be used for drilling and work over and can 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 (Orphan Basin) could have a significant wave height 

of 52.5 ft (16 m) and potentially pack ice conditions. The disconnect 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 offshore oil and gas exploration began in 1973 at 

the Hecla exploration well in the Canadian High Arctic. The floating drilling pad used 

artificial thickening of the natural ice sheet by flooding with seawater. Build-up rates were 

dictated by the time required to freeze thin layers 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 techniques in water depths up 

to 1640 ft (500 m) (Masterson et al., 1987). 

A total of 38 wells were drilled from floating ice pads (see Figure 3-29) between 1973 and 

1986 (Masterson et al., 1987). Table 3-5 shows a chronological list of sites. 
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Figure 3-27: SPAR Concept for 

Offshore Canada (from Murray, 2004) 

Figure 3-28: Disconnected SPAR 

(from Murray, 2004) 
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Figure 3-29: Cross-Section of Cape Alison Floating Spray Ice Pad (Masterson et al., 1987) 
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Table 3-5: Floating Ice Pads Constructed 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) 
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Ice pads were constructed by pumping water onto the ice in thin layers, 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 the 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 rather 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 function of temperature, 

wind speed and equipment used. The platform would generally be ready to accept the rig 

during January or February, allowing up to 100 days of drilling. 

The main structure constructed was the drilling pad to support the rig and associated 

equipment. Other important infrastructure included a relief pad 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 great concern in the arctic islands, based on 

a number of years of historical data and the landlocked nature of the ice. The deep water 

depth provided some allowance for relative horizontal movement between the platform and 

seabed without over stressing the riser. 

Spray ice started to be used for the construction of the floating Arctic island platforms in 

1984/85 at Cape Alison and 1985/86 at North Cornwall. 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 located in the Barents Sea, approximately 373 miles (600 km) 

offshore, in water depths of 1080 to 1150 ft (330 to 350 m) (see Figure 3-1). Detailed 

information on the environmental and operating conditions at Shtokman field is contained in 

Zubakin et al. (2004b), Naumov (2004), Buzin (2004a), Buzin (2004b), Zubakin et al. 

(2004c) and highlights of these publications are presented 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 m3

) and more than 150 wells will be 
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required. First production is expected in 2012, with a subsequent field life of 50 years. The 

estimated total development cost is USD 20 billion. 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 considering three tension leg platforms (TLP’s) with 

topside weights of 55,000 tons (50,000 tonnes) and a total weight 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 the 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 structure for offloading oil produced at the 

Molikpaq structure. Oil produced from the Molikpaq platform is exported via a 12-inch 

subsea pipeline to a Floating Storage and Offloading (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 tankers for export (Figure 

3-32) (SPG Media Limited, 2007c). 

Due to severe climatic conditions in the Sea 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). 
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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) 
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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 exploration licenses awarded offshore Greenland 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 Denmark and Greenland, 2002). The Lady 

Franklin license lies approximately 156 miles (250 km) from shore and has water depths 

ranging from 2500 to 5700 ft (750 to 1750 m) (BMP, 2006). 

As shown in Figure 3-34, in 2005 EnCana presented a potential development scenario 

which involved the use of an FPSO and integrated subsea production system (Cooper, 

2005). The potential scenario was based on a location 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 capacity of 165,000 bbls/d (Cooper, 2005).
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Figure 3-33: Atammik and Lady Franklin Exploration Licenses (Cooper, 2005) 

Figure 3-34: Potential Development Scenario Offshore West Greenland (Cooper, 2005) 
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Ice conditions in Eastern Davis Strait are fairly benign; typically 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 severe then those experienced further North 

in the West Disko Bay area. This area is typically covered by sea ice during the winter and 

early spring and icebergs are much more frequently 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 assess field development concepts for the West 

Disko Bay area concluded that the most feasible solution would 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 uptime in the range of 40 to 65% (BMP, 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 properties 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 considered 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 consists 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 for the installation and relocation 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 ballasted and the cable groups are 

winched in until the unit is centrally located between the 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 ready to begin drilling operations. 
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Preparing the structure for relocation is essentially the reverse of the installation process. 

Depending on whether or not the 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. When 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 Floater 
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3.3.2.7 Monocone Arctic Platform (MCAD) 

The Monocone Arctic Platform (MCAD) was presented at the 2007 Offshore Mechanics 

and Arctic Engineering Conference 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 consisting of an upper and lower section. The 

upper section provides the structure’s buoyancy and ice breaking features. The lower 

section consists of a heavy steel ballast that can be lowered to adjust the unit’s vertical 

center of gravity. The unit maintains its position by the use of a steel mooring system. The 

mooring system consists of 32 chains connected to 16 driven anchor piles. The 16 piles are 

expected to be 9.8 to 13.1 ft (3 to 4 m) in diameter 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 requires 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 connected to the anchor piles and the ballast 

section is lowered. The structure is now ready to begin drilling operations. Preparing the 

structure for relocation is the reverse of the installation process. The MCAD’s mooring 

system is only partially mobile, so each installation and relocation of the unit requires the 

installation of new anchor piles. 
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The MCAD is designed to operate under ice loads of 13,200 tons (12,000 tonnes) in wave 

heights of 46 ft (14 m). The MCAD has capacity 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 Floating Exploration Structures 

Conventional floating exploration structures, drillships and semi-submersibles, have been 

used in areas subject to seasonal/marginal ice cover including the east coast of Canada, 

offshore Greenland, the Russian Arctic, and offshore Sakhalin Island. Drilling with these 

structures is generally carried out during summer months when seas are ice free. However, 

there are drilling units which are ice strengthened/classed for operation in light/managed 

ice cover. Furthermore, there are 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 breaking (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 compact drill rig for deep sea drilling in 

summer of 2004. This upgrade was performed to allow the Vidar Viking to serve as the 

drilling vessel for the Arctic Coring Expedition (ACEX) project (ALIAS, 2007). In the 

summer of 2004 as part of the ACEX, the Vidar Viking successfully gathered cores from 

under the central polar ice pack. Ocean floor core sampling was carried down to the full 

target depth, to bedrock on the Lomonosov ridge, at 1440 ft (438 meters) of core length 

(Keionen et al., 2007). Prior to this date no core drilling had taken place under the central 

polar ice pack. 
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Figure 3-37: “Vidar Viking” Equipped with Compact Drill Rig, in the Central Polar Pack 

(Keionen et al., 2007) 

This drilling program was possible as a result of the many lessons learned in ice 

management, ice intelligence and evaluations, forecasting drift, risk assessments and 

icebreaker operations by the Sovetskiy Soyuz and Oden to defend the stationary Vidar 

Viking vessel in moving pack ice. This program allowed the vessel to remain on station for 

days at a time in difficult ice and weather conditions. 

The station keeping operation had an allowable movement during operation of about 5% of 

water depth. The Vidar Viking was able to keep station at the central polar pack in 

approximately 10 tenths of 8.2 to 8.9 ft (2.5 to 2.7 m) thick multi-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 Viking with the application of the 

latest azimuth propulsion icebreaker technology. 
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Eirik Raude

The Eirik Raude (Figure 3-38) is a 5th generation harsh environment, dynamically 

positioned semi-submersible. The 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 (Ocean Rig ASA, 2007). 

Figure 3-38: Eirik Raude (Ocean Rig ASA, 2007) 

The rig is operational in water 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 controlled thrusters (Ocean Rig ASA, 2007). This DP3 system is 

capable of holding the rig on position in violent 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) waves (Goa, 2003). Furthermore, Goa (2003) indicated that the 

Eirik Raude encountered ice while drilling on location off the east coast of Canada. 
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Quick disconnect features allow the Eirik Raude to disconnect from, and secure, a well in 

35 seconds. The quick disconnect feature makes it possible for 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 4th generation semi-submersible, 

and has been used year round on the Grand Banks. The Goodrich has carried out the 

majority of development drilling for the Terra Nova field. 

Figure 3-39: Henry Goodrich (Toolpusher, 2007) 

The Henry Goodrich is ice-classed and can 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 (32 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. 
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3.3.3 Subsea Solutions 

Advancement in subsea technologies are allowing 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 recently come online, has 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 considered in arctic and sub-arctic 

type areas as described below. 

3.3.3.1 Canadian East Coast 

On the Grand Banks, the biggest concern 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 the mudline, the hazards posed 

by free floating icebergs are eliminated. If the 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 project design; however, open glory holes were identified as 

the optimum solution for east coast Canada projects requiring protection. Similar issues 

would exist for subsea infrastructure that would be placed in water depths approximately 

less than approximately 1000 ft (300 m) on the Labrador Shelf. 

There are only two known projects in the world which use glory holes to protect wellheads 

and associated equipment from potential ice impacts. Petro Canada’s Terra Nova field and 

Husky’s White Rose field located on the Grand Banks of Newfoundland (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 ranging from approximately 395 to 410 ft (120 to 

125 m). 

As an indicator of the dimensions associated with these east coast developments, Table 

3-6 provides a summary of the overall glory hole dimensions. 
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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 

Terra (10) 

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 transporting gas in April 1978, from a subsea 

wellhead to production facilities onshore (Palmer et al., 1979). A Canadian company, 

PanArctic Oil Ltd., sponsored the Drake Field subsea completion which was located in the 

Canadian High Arctic off of Mellville Island (Figure 3-40). The three-year program to design, 

fabricate and construct the flowline 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 length 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 offshore drilling (Watts and Masterson, 1979). 

The Christmas tree assembly which was installed was equipped with diverless remote 

hydraulic flowline connectors which were used to tie-in the flowlines. Diverless pipeline 

bundle connections were made by using the deflect-to-connect method (Palmer et al., 

1979). 
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Melville Island

Drake Project Location

Figure 3-40: Drake Project Location Map 

3.3.3.3 Russian Arctic 

Subsea solutions have been considered in the Russian Arctic, including Shtokman. In the 

subsea development case, subsea separation and compression technology will be used. If 

the subsea method is chosen, technology applied during development of the Ormen Lange 

field in Norway will be taken as a prototype (SPG Media Limited, 2007a). The gas will be 

transported from the well through a pipeline and liquefied onshore. The specialists of JSC 

GiproSpetsGaz (Gazprom affiliate) and VNIIGAZ, together with Norwegian companies are 

investigating the feasibility of this concept. 

3.3.4 Pipelines 

3.3.4.1 PanArctic Drake 

Overview

The Drake Field subsea well test experience is instructive, since it shows the effort required 

for pipeline bundle construction in the arctic. The implication is that the schedule lengthens 

considerably over that which would be anticipated from a more conventional pipeline 
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configuration. The gas was produced to a test flare for several months and then shut-in 

and, years later, the well and flowline bundle were abandoned. 

Pipelines

The flowline bundle is illustrated in Figure 3-41. The flowline bundle contained two 6-inch 

(152 mm) flowlines with heat tracing. One flowline was insulated with a layer of expanded 

polyurethane foam. In addition to the flowlines, the bundle contained one 2-inch (50 mm) 

annulus access line and four 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 pipe was used to contain the 

bundle of seven pipelines and various cables. 

Figure 3-41: Drake Flowline Bundle (Palmer et al., 1979) 

Project Design Challenges & Highlights

Ice gouging was a major concern for the flowline bundle. The deepest ice island keel depth 

expected for the area was 148 ft (45 m). The depth at which the 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 over which the flowline would need to be 

protected from sea ice. The sea ice at the site was found to be a mixture of first-year and 
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multi-year ice with average and maximum thicknesses of 9.8 ft (3 m) and 57 ft (17.4 m), 

respectively. 

A 13 ft (4 m) deep trench backfilled with rock was initially planned to protect 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 techniques was therefore carried out. The solution 

which was selected was to protect the pipeline with frozen soil. The pipeline would be 

placed in a 5 ft (1.5 m) deep trench, backfilled with gravel, and the soil frozen around the 

carrier pipe, thus creating a protective cylinder around the flowline system. The frozen soil 

would have a significantly greater strength than the surrounding 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 (457 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 soil 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 Challenges & 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 support 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 artificially 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 designed large trenching plow. The plow was 
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specifically designed for the 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 winter of 1977 – 78. A “stove pipe” 

technique was employed for pipe string and bundle 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 cables. 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 launch hole was cut in the ice. A 1 ft (0.3 m) wide slot was 

cut through the ice from shore to the ice island 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 pulled 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-laid through the slot in the ice and 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 control the flowline bundle position during 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 location. A portable camp and runway were 

established for the Drake work and equipment/supplies 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 natural gas southward by pipeline from the Canadian 

Arctic Islands (Houlding, 1976). Considerable design work and a research program was 
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undertaken to look at the feasibility of laying pipelines in extreme low temperatures and 

through the ice in the Canadian 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. Offshore pipelines were planned to 

be dual 36-inch (914 mm) lines. The pipelines bringing gas from the islands were planned 

as a phased approach. The first pipelines being considered were those running south from 

Melville Island. Subsequently, pipelines would 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 could 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 was that ice masses large enough to cause 

serious problems to the pipeline would not be experienced along the pipeline route due to 

the protection afforded by the surrounding islands and the prevailing 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 Challenges & Highlights

The main challenge with regards to the pipelines was to install pipelines across deepwater 

channels between the Arctic islands. Logistics were also identified as a significant issue; 15 

staging areas would be required to move almost 5.5 million tons (5 million tonnes) of 

equipment, materials, and supplies. 

A number of channel crossing methods were looked 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, 
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• Tunneling. 

All were considered feasible. The primary solution was to use the ice as a working platform 

for installation and logistics. 

A 100-day construction period would take place between February and May when daylight 

hours were available and the ice was thick (up to 6 feet (1.8 m)) and stable. At that time, 

the ice island bottom pull concept (Figure 3-43) was considered the most promising and 

cost effective solution where the availability 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 platform 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 more 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 together, 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 pipelines south across M’Clure Strait, 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) wide, 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 surfaces along the pipeline right 

of way. Tie-ins between pipeline 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 Dolphin and Union Strait was 19 miles (30 km) wide and 361 ft 

(110 m) deep. A laybarge or pullbarge method of installing the 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 pipeline 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). 
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Figure 3-42: Polar Gas Channel Crossings (modified from Kaustinen, 1981) 
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Figure 3-43: Ice Island Bottom Pull Method (from Kaustinen, 1981) 
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Figure 3-44: Ice Hole Bottom Pull Method (from Kaustinen, 1981) 
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Figure 3-45: Polar Gas Foreshore Tunnel Concept (from Kaustinen, 1981) 

3.3.4.3 Baydaratskaya Bay (Russia) 

Gas transportation schemes from the Yamal Peninsula include pipelines crossing the 

Baydaratskaya Bay of the Kara Sea over a distance 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 gouging 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). 
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The presence of ice gouging of the seabed will require pipeline 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 required to protect the pipeline. 

3.3.4.4 Nord Stream Pipeline (Russia) 

The planned Nord Stream pipeline (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, will be the first pipeline installed 

in the Baltic Sea. The maximum water depth along the pipeline route will be 690 ft (210 m) 

and the pipeline will have wall thicknesses ranging from 1.2 to 1.8 inches (30 to 45 mm). 

Trenching of the pipelines will occur in the nearshore areas where there is excessive wave 

and current action. The pipeline will also be trenched where there is a risk of ice gouging, 

ship grounding, etc. At a minimum, it is expected that the pipelines shall be trenched and 

backfilled at the landfall points, and at shallow water at Vyborg, Russia, and at Greifswald, 

Germany. If the trenches required 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 reproduced from Nord Stream (2006). 
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“The ice conditions in the Baltic Sea show a high degree of variance in time and space and 

are strongly related to the severity of the winters. 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 usually 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 the open area in the Central part of the southern Baltic proper, the 

probability of ice occurrence 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 mild, normal and severe winters, respectively, is shown in 

Figure 3-47. 
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Figure 3-47: The Average Ice Extent during Mild, Normal, and Severe Winters, 

Respectively (Nord Stream, 2006) 

3.3.4.5 Canadian East Coast Flowlines 

Terra Nova

The Terra Nova development utilizes approximately 20 miles (33 km) of flexible flowlines 

and dynamic risers to convey produced hydrocarbons from the subsea wells to the riser 
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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 diameters 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 the largest quick disconnect turret 

moorings ever built (Petro-Canada, 2007b). 

Technip Canada Ltd. (formerly Technip CSO Canada Ltd., formerly Coflexip Stena 

Offshore Newfoundland Ltd.) supplied and installed all flexible flowlines, risers, umbilicals, 

and jumpers for the Terra Nova development project (Technip, 2007). The flexible flowlines 

and risers were manufactured by Coflexip Stena 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 machine, but difficulties in trenching the hard glacial seabed 

led to the use of rock dumping on some of the 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 against 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 protection measures, flowlines used on the Terra Nova project 

are considered sacrificial and contain weak-link connections to wellhead equipment (for 

protection of the wellhead if the flowline is impacted by a gouging ice keel) (Cottrill, 2000). 

The flowline design maintains production fluid temperatures well outside of the hydrate 

formation region during normal operations, with predicted cool down times (to below 

hydrate formation temperatures) ranging from 5 to 6 hours during shutdown, depending on 

shut-in pressures and production fluid 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. 
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Figure 3-48: Terra Nova Flowline Protection (Courtesy of Tideway, 2007) 

White Rose

Similar to the Terra Nova development, the White Rose project FPSO (the SeaRose) 

utilizes a disconnectable turret mooring 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 (Technip, 2007). As with Terra Nova, the flexible 

flowlines were manufactured in Le Trait, France (Alexander’s Gas & Oil Connections, 

2007b). Subsea construction was completed by CSO’s Constructor and Marianos vessels. 

Flexible flowlines enter the FPSO via a riser buoy and quick disconnect geo-stationary 

turret which serves as the mooring point for the FPSO and the route for all produced fluids 

flowing between the FPSO 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 flowline is impacted by a gouging ice keel (Husky, 2001a). The 

flowlines are designed to be fail-safe to minimize harmful environmental consequences 

should a flowline fail or become damaged (Husky, 2001b). Flowlines may be flushed and 

purged of all internal production fluids to mitigate environmental risk associated with 

potential ice keel impact (Husky, 2001b). 
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3.3.4.6 Sakhalin Island 

Sakhalin 1 Pipelines

Two pipelines connect the Orlan platform located in approximately 82 ft (25 m) water depth 

to shore approximately 6 miles (10 km) away. From 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 effects of sediment transport (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 the presence of ice and ridging, and the fact that sediment 

transport is actively ongoing, the pipelines are buried for protection 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 tankers are loaded. This line 

is buried and backfilled out to 50 ft (15 m) water 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 pipeline systems that have been installed over two 

phases of the project. 

Phase I of the offshore pipeline development involved the installation of a 12 inch (305 mm) 

diameter, 1.25 mile (2 km) long 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 pipelines. Phase II also connects the export terminal to the 

tanker loading unit in Aniva Bay. Details of the Phase II pipelines are as follows: 
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• 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 the 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 export terminal to 

the tanker loading unit in Aniva Bay (SPG Media Limited, n.d.). 

The Sakhalin 2 offshore pipelines incorporate the state-of-the-art in design 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 constructed from API 5L X52 grade steel which 

remains ductile at low temperatures (SEIC, 2004). Cofferdams are installed at land fall to 

provide protection from sea ice at the transition between offshore and onshore pipelines. 

The Phase I offshore pipeline has been in seasonal 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 Canadian Arctic Islands which 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-hulled tanker. The field 

was abandoned in 1996 after producing a total of 2.8 million barrels of oil. The 

abandonment reflected the difficulties of exploiting the resource in harsh environments. 

After abandonment, final clean-up occurred in 1999. 
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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 the 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 ports in the Baltic as a result of the 

disintegration of the Soviet Union; and, 

• The need to create the infrastructure for the growing flow of Russian oil and 

gas to Western markets. 

The single factor which affects all transportation ideas proposed for the Barents is that the 

western sector of the sea (Kolsky peninsula, Figure 3-1) is free from ice year-round. 

Consequently, the northern part of Kolsky peninsula, including the major commercial port of 

Murmansk and nearby areas, are considered convenient transshipment locations for oil 

from the Timan-Pechora basin and Prirazlomnoye fields (Varandey terminal in the 

southeast Barents is the loading point of these operations). The Kolsky peninsula is also 

considered to be the most probable loading point for the LNG produced from the Shtokman 

field reserves. An example of one of the Barents Sea oil and gas transportation concepts is 

presented in Figure 3-49. 

A brief review of available information shows that marine transportation of hydrocarbon 

products is one of the main areas of development in the Russian Arctic. Major research & 

development and technology projects have been conducted at all levels; from global 

transportation concepts to the design of service 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. 
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Figure 3-49: Technical and Economic Evaluation of Alternatives for Oil Transportation from 

Timano-Pechora Province, Krylov Institute Development (Krylov Institute, n.d.) 

Murmansk 
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Southeast Barents

One of the most active projects in the Russian Arctic at this time is the development of the 

oil transportation link originating at the small island of Varandey, located in the southeast 

corner of the Barents Sea, almost directly south of Novaya Zemlya archipelago (Figure 

3-1). The Varandey oil export terminal was developed to load oil recovered from the nearby 

Timan-Pechora fields on tankers and deliver it either across the Barents to the non-frozen 

Murmansk area for transshipment, or directly to Western Europe and/or the USA. 

An information search regarding the Varandey project indicates that, with respect to the 

overall scale of plans and actual developments along the Russian coast of the Arctic 

Ocean, the Varandey project is only a “tip of the iceberg”. Terminals are now being 

considered all along the European section of the coast, as well 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 catalogue as well as Falling Rain Genomics, Inc 

(2006), Lukoil-Kaliningradmorneft (n.d.), Advanced Production and Loading AS (2006), 

Russian Maritime Register of Shipping (2006), and Universal Solutions S.A.E. (2005). 

At Latitude 68.82° north, Varandey is located roughly at the latitude of King William Island 

in the Canadian Arctic and of Point Hope in Alaska (Figure 3-1). A summary of operational 

conditions in general offshore areas of the Southeast Barents is presented in Appendix A of 

this report. No direct information on the ice thickness at the Varandey site is available, but it 

is reported that the landfast 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 some indication of the possible ice thickness at the site. 

In the initial stage of the terminal development (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 was considered temporary (for Varandey “early 

oil”) and intended for summer season operations only (Krylov Institute, n.d.). These loading 

operations were conducted approximately 2.5 miles (4 km) offshore in approximately 36 ft 

(11 m) of water by a subsea pipeline connected 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 system was upgraded for winter operations. In this case, the 

tanker to be loaded was tied to a specially equipped large diesel/electric icebreaker. 
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Besides providing safer mooring for the tanker, this icebreaker also served as the 

operational facility for the diving team personnel and equipment. The divers were required 

for handling the subsea manifold and lifting of the flexible loading hose. Another icebreaker 

was permanently kept in the area for ice management on an as-needed basis. Winter 

operations began in 2001 (Krylov Institute, n.d.). The offloading concept using a totally 

underwater terminal connection was considered for Varandey as well in 2005 (Krylov 

Institute, n.d.). 

Later in 2002 the system was modified; an arctic 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 with tankers having bow loading systems for 

cargo reception.

In 2001, Krylov, working together with Halliburton, performed a conceptual design of a 

bottom-founded terminal in Varandey for a deep water (53 to 73 ft (16 to 22 m)) operation. 

At that time, four alternatives were considered for the terminal (Krylov Institute, n.d.): 

• Modified DWT 284,400 tons (258,000 tonnes) Very Large Crude Carrier 

(VLCC). The terminal was designed to provide 691,900 barrels (110,000 m3

) 

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 were to be filled with concrete. 

• Modified Steel Drilling Caisson (SDC) platform. The conceptual sketches of 

the system show additional foundation sections (block) that would be twice as 

wide as the original platform, apparently to improve the stability of the 

platform/seabed interface. The platform 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) (including 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 dimension of tower substructure was 

approximately 43 ft (13 m) at water level (stem) and 125 ft (38 m) at the 

seabed (base). The height (to the deck level) was 107 ft (32.5 m). 
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The alternative shown in Figure 3-50 is apparently the closest to that actually constructed 

(Krylov Institute, n.d.). Essentially, the TLU is based on the last concept described 

immediately above, but with some important modifications. With an apparent goal to 

increase the ballast weight, a wider caisson-type hull is being used. Twenty-four piles have 

been added to the design to ensure the on-bottom stability of the structure. The octagonalshape TLU is 115 ft (35 m) wide at the waterline 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 weight of the concept shown in Figure 3-50 is 

14,330 tons (13,000 tonnes). 

Tankers will be built to the Russian Register ice-class requirements and will be DWT 

77,160 tons (70,000 tonnes) with a loaded draft 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) were conducted in Krylov in 2005 on the orders of the TLU 

working documentation developer (CKB “Corall”, Ukraine) (Krylov Institute, n.d.). Both 

regular and irregular extreme wave conditions as well as maximum 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 configuration carries an acronym FOIRLT (Fixed Offshore Ice 

Resistant Loading Terminal). This project in general is also called “Varandey II”. The 

terminal will have a loading capacity 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 accommodations for 12 people 

(Lukoil-Kaliningradmorneft, n.d.). The swivel stack designed for arctic conditions is 

reportedly supplied by APL (Advanced Production and Loading), which was their first 

stand-alone swivel stack delivery not part of a complete turret system (Advanced 

Production and Loading AS, 2006). The TLU was built at the Vyborg, Baltic and Kaliningrad 

shipyards and the TLU installation was scheduled for September, 2007 (Russian Maritime 

Register of Shipping, 2006). 
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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 products to Europe; the Karelia Isthmus coast, 

specifically the northernmost part of it, near the Finnish 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 average ice thickness is 1.6 ft (0.5 m). However, considering 

that no special ice-resistant or ice protection engineering measures are included into the 

terminal designs (Panin and Rode, 2003), the structural designs in these cases may be of 
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certain interest in the current study. The weak seabed soils require piles as the only 

reasonable option for pier and trestle foundations in 49 to 59 ft (15 to 18 m) of water. 

Consequently, the main focus of the 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 Gulf of Finland (Panin and Rode, 2003) 

Prirazlomnoye

Substantial effort was dedicated to development of the optimal overall logistics of 

exploration and production at Prirazlomnoye field. According 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 location with well-developed infrastructure, but 
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still approximately 621 miles (1,000 km) from the field. The oil transportation concept for 

Prirazlomnoye described in available 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 system (AZIPOD or conventional). However, the general idea 

is the same; the shuttle tankers will take the oil from Prirazlomnoye platform to the nonfrozen north-west fiords of the Kolsky peninsula 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 Europe and/or America. The transshipment 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 ice management at the platform, particularly 

during offloading operations (SPG Media Limited, 2007a). 

3.3.6 Extended Reach Drilling 

World records with respect to extended reach drilling continue to be set in harsh 

environments. The push to extend the capabilities of extended reach drilling is driven in 

part by the significant reduction in offshore facilities if wells can be drilled from shore or 

from existing structures to access reservoirs. 

Within the last few years, the Hibernia platform off the east coast of Canada successfully 

drilled a 31,000 ft (9450 m) measured depth (MD) oil 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 accomplished 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 onshore application where it was successfully 

employed in 2004 by Anadarko Petroleum (Smith, 2004) in the Buckinghorse River Valley 

in the foothills of Northeastern British Columbia, Canada (Figure 3-52). In the Buckinghorse 

area, Anadarko encountered a deep river valley that prevented the connection of a number 
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of gas wells on one side of the gorge to production facilities on the other side of the gorge. 

This gorge made conventional onshore pipeline construction both uneconomical and 

environmentally challenging. The river crossing design incorporated the drilling and 

intersecting of two conventional 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 approximately 4700 ft (1433 m) TVD. An 8-3/4-inch (222 mm) hole 

was drilled and intersected downhole 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 Valley 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 them 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, Canada in January, 2004. Two 9-7/8-inch (251 

mm) pilot holes were intersected at approximately 200 ft (61 m) Total Vertical Depth (TVD) 

using rotating magnet ranging equipment. The crossing 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). 
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3.3.7.3 Arctic Offshore Vessels 

The most advanced developments for Arctic offshore oil and gas development in Russia 

are associated with shipbuilding because, traditionally, a wide scientific and technological 

base exists in this area. For example, the following is a list of development works presented 

in the Krylov Institute’s project catalogue (Krylov 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 transportation 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 transportation 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 OSR equipment units and helipad 

installation), 2004; 

• Development of technical requirements for LNG carriers to be built for 

Shtokman field operations, 2005; 

• 60-ton (54.4 tonne) lifting capacity hovercraft for oil and gas exploration in the 

Yamal swampy areas (crane, fire fighting and well services modifications), 

2005; 

• New generation nuclear Arctic icebreaker, DWT 26,500 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 Plant, 132,000 tons/year (120,000 tonnes/year) 

maximum oil input capacity for 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. 
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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 astern 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 Icebreaking Mode (SPG Media Limited, 2007h) 
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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 Beaufort Sea began from gravel islands in shallow 

Alaskan State Waters in the late 1960’s and similarly 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 waters, followed in 1981 by the first use of a 

bottom-founded caisson system. Exploration activities commenced in Beaufort OCS 

regions in 1982 using gravel islands, ice islands, bottom-founded structures and drillships. 

In the authors’ view, the experience of bottom-founded exploration structures provides the 

best analogue to the operating conditions that will be experienced by future production 

structures in the Alaskan OCS. In total, five separate bottom-founded structures were 

deployed in the Beaufort Sea: 

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

• Single-Steel Drilling Caisson or SSDC (steel structure) 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 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, the 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, backfill, densify the core (Molikpaq requirement), 

decommission and move. Although touted as “mobile” structures, the caisson structures 

were not truly “MODU’s” (mobile offshore drilling units). 
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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 similar 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 sorted by structure name in Table 3-8. 

In recent years, with additional gas discoveries in the Mackenzie Delta region and the 

revival of the Mackenzie Valley Pipeline, some companies have proposed constructing gas 

conditioning facilities supported by barge structures. These barge structures are discussed 

following the review of the aforementioned exploration structures. 
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Table 3-7: Deployments of Bottom-Founded Structures 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] 
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Table 3-8: Deployments of Bottom-Founded Structures in the Beaufort 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] 
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3.4.1.2 Tarsiut Caissons 

The industry’s first caisson-retained island was installed by Canadian Marine Drilling Ltd. 

(CANMAR) at the Tarsiut location in the Canadian 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 then infilled and backfilled with dredged material to a freeboard 

of +23 ft (+7 m). The structure was used only for one drilling season, 1981 – 82, although 

the structure did serve as an ice engineering research platform the following season. Based 

on the Tarsiut Caisson experience, CANMAR saw the need for a fully-mobile year-round 

drilling platform, which led to the development of the SSDC (see below). The Tarsiut 

Caissons were decommissioned 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 Tarsiut Caissons led CANMAR 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 (VLCC) and the name “Single-Steel Drilling 

Caisson” (SSDC) was adopted to differentiate it from the multiple concrete caissons used 

at Tarsiut. In 1986, the SSDC was modified to prepare it for deployment in the US Beaufort 

Sea. It was mated with a steel MAT1

 substructure to eliminate the need for foundation 

 

1

 The MAT structure carries the highest loads of any steel structure ever built.
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preparation (subsea berms) and functioned as a single unit called the SSDC/MAT. In 

recent years, with a change of ownership, the structure (including MAT) has been renamed 

the SDC. The structure is a MODU and all drilling and topsides facilities are permanently 

affixed to the deck, resulting in simpler and faster mobilization for drilling operations. Of the 

19 deployments of bottom-founded structures in the US and Canadian Beaufort Sea, 8 

were those of the SDC. 

Figure 3-55: SSDC (left), MAT Substructure (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 reduce the amount of dredged material and 

was comprised of eight individual hinged steel caissons placed in a ring and held together 

with steel wire cables. Like the Tarsiut Caissons, the core of the CRI was filled with 

dredged material to provide the base for drilling operations and provide resistance to wave 

and ice loads. The CRI was deployed three times in the Canadian Beaufort Sea from 1983 

– 87. The structure has not been active since that time. 
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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 drilling and topsides facilities, but unlike the fully waterballasted SSDC and CIDS, Molikpaq relied on a densified sand core to provide the bulk of 

its resistance to environmental loads. Like the Tarsiut Caissons and the CRI, Molikpaq is 

not a true MODU. The unit began operations in 1984 and drilled four locations in the 

Canadian Beaufort Sea. It was mothballed in 1990 and later modified and redeployed in 

1997 as a permanent production facility in the Sea of Okhotsk off Sakhalin Island, Russia. 

The only Beaufort Sea production 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 topped 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, the last in 1997. In 2001, the 

structure was towed to Russia for refurbishment and (like Molikpaq) now operates as the 

permanent production platform Orlan in the Sea of Okhotsk, offshore Sakhalin Island. 
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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 Island 
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3.4.1.7 Barge Structures 

Niglintgak Barge

Shell Canada Ltd. has proposed to develop its Niglintgak gas field (of the Mackenzie Gas 

Project) using barge-mounted processing and gas conditioning facilities which will be prebuilt prior to arriving on location at the Niglintgak site (Mackenzie Gas Project, 2004). The 

Niglintgak gas field is located within the Mackenzie Delta of the Canadian Beaufort Sea, 

offshore of the North West Territories. 

Shell proposed that the required processing facility topsides modules be transported via 

marine barge through the Beaufort Sea and into the Kumak Channel, where the barge 

would then serve as the foundation for the modules, as shown in Figure 3-59. Placement of 

the barge-mounted gas conditioning facility is planned for a naturally sheltered area on the 

seasonal flood plane of the Little Kumak Channel, near the Kendall 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 facilitated as the barge may be removed from 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 barge from any potential permafrost. An alternate 

installation proposal placed the barge upon driven piles in the sheltered channel. 

The preliminary design proposed that a lightweight, 180 x 361 ft (55 x 110 m), ice 

strengthened steel barge be constructed overseas and towed to its installation location in 

the Kumak Channel (Mackenzie Gas Project, 2004). 

Taglu Barge

Imperial Oil Resources has also considered utilizing barge-mounted gas conditioning 

facilities for its Taglu field development in the Kuluarpak Channel, as shown in Figure 3-61 

(Mackenzie Gas Project, 2004). Unlike the Niglintgak barge, the proposed Taglu barge 

would require excavation of a slip for protection 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 difficult 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 concept was ultimately chosen for the Taglu 

field (Mackenzie Gas Project, 2004). 
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Figure 3-59: Niglintgak Barge Processing Facility (from Mackenzie Gas Project, 2004) 

Figure 3-60: Proposed Placement of Niglintgak Gas Processing Facility on Seasonal Flood 

Plane (from Mackenzie Gas Project, 2006)
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Figure 3-61: Taglu Field Development (from Mackenzie Gas Project, 2006) 

Norton Sound Barge Concept

In an evaluation of structural concepts carried 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 transportation and installation, and 

therefore to minimize draft light-weight concrete was to be used where possible. Ballast for 

the barge consisted of gravel. The barge was designed to accommodate drilling and 

production facilities. 

3.4.1.8 GBS Structures 

A number of arctic GBS structures have been considered for 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. Specific areas considered in the 

study were the St. George’s, Navarin and North Aleutian Basins in water depths ranging 

from 300 to 450 feet (91 to 137 m). The concrete GBS evaluated was composed of a 

cellular base with a flared mat, steel skirts, and four main shafts 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 platform Statfjord C as shown in Figure 3-62. 
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Figure 3-62: Statfjord 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. The 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 Aleutian Basins in water depths ranging from 300 

to 450 ft (91 to 137 m). 

The four plus four template jacket as shown in Figure 3-63 has eight legs complete with 

skirt piles. The four end legs terminate beneath the surface giving the structure a clean 

water plane, which is expected to prevent ice bridging of the legs. The four double walled 

legs are on a spacing of 100 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 exploration drilling has been carried out from ice and gravel islands in the 

Beaufort Sea. Gravel islands have also been used as production structures. Due to the 

inherent similarity of the Alaskan and Canadian Beaufort Sea regions, with respect to 
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environment and previous structure types used, both regions will be discussed together 

under this Section. 

Figure 3-63: Four plus Four Template Jacket (modified from PMB Systems Engineering et 

al., 1983) 

3.4.3.1 Grounded Artificial Ice Islands 

This complete section has been extracted from the major MMS Project No. 468 (C-CORE 

et al., 2005). Minor modifications to the text have been made. It should be noted that 
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floating ice drill pads were generally not considered 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 spraying on experimental and relief well pads has 

allowed these methods to be developed with lower 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 movement of the island in 

relation to the seabed will damage the drill-string, and so the design requirement is to 

eliminate any differential movement. The island is therefore designed to withstand the 

horizontal force applied by the surrounding ice sheet by providing resistance through 

contact with the seabed. An additional requirement is to maintain the stability of the rig 

foundation, which will undergo creep settlement 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 exploration drilling was constructed by Union 

Oil in Harrison Bay in 1977/78. It was grounded in 9.8 ft (3 m) water depth using flooding 

techniques by applying thin layers of seawater to the ice surface and allowing it to freeze in 

place. Generally, however, the relatively slow build-up rates achievable with flooded ice 

techniques limit the usefulness of these structures 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 rubble 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. 
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Figure 3-64: Tarsiut Relief Spray Ice Island (ICETECH, 2008) 

The first use of an island built completely from spray ice for exploratory 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 required 4 pumps to produce 35.3 million ft3

 (1 million 

m3

) of ice during the 45 day construction program. Figure 3-65 shows the Mars ice island 

during drilling operations. 
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Figure 3-65: Mars Spray Ice Island (C-CORE, 2005) 

The technical and financial success of this platform led to spray ice becoming the material 

of choice for the construction of grounded platforms 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. 
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Figure 3-66: Cost Comparison between Gravel and Ice Islands (C-CORE, 2005) 

Operational spray ice islands were used at the Thetis Field in 2002/03, where a number of 

innovative techniques were successfully used. This 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. 
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Table 3-9: Summary of Grounded Artificial Ice Island Construction 

Name Operator Location Technique Use 

Union Oil Harrison Bay, US Beaufort Sea Flood Experimental Island 

Exxon Harrison Bay, US Beaufort Sea Flood, Spray Experimental Island 

Esso Canadian Beaufort Sea Spray Experiment 

Tarsiut Gulf Canada Canadian Beaufort Sea Spray Relief Pad 

Alerk island Esso Canadian Beaufort Spray Relief Pad 

SSDC Uviluk CANMAR Canadian Beaufort Sea Spray Experimental Protection Structure 

Kadluk 0-07 Esso Canadian Beaufort Sea Spray Relief Pad 

Sohio Rubble Generator Sohio McKinley Bay, Beaufort Sea Spray Experimental Protection Structure 

Ice Island Experiment Exxon Canadian Beaufort Sea Spray Experimental Island 

Big Gun Expt., MV Kigoriak Esso McKinley Bay, Beaufort Sea Spray Experimental Protection Structure 

SSDC Kogyuk CANMAR McKinley Bay, Beaufort Sea Spray Experimental Protection Structure 

CIDS Antares Barrier Exxon Alaskan Beaufort Sea Spray Operational Protection Structure 

Cape Alison C-47 PanArctic Ellef Ringnes Island, Canadian Arctic Spray Operational Floating Island 

MARS full-scale prototype Sohio Harrison Bay, US Beaufort Sea Spray Experimental Island 

Mars Amoco Harrison Bay, US Beaufort Sea Spray Operational Island 

Angasak L-03 Imperial/Esso Canadian Beaufort Spray Operational Island 

Nipterk P-32 Imperial Canadian Beaufort Spray Operational Island 

Karluk Chevron US Beaufort Spray Operational Island 

lsserkl-15 Imperial Canadian Beaufort Sea Spray Relief Pad 

Ivik Pioneer Thetis, Harrison Bay, Alaska Spray Operational Island 

Oooguruk Pioneer Thetis, Harrison Bay, Alaska Spray Operational Island 

Natchiq Pioneer Thetis, Harrison Bay, Alaska Spray Operational Island 

Kashagan, Sunkar Site Agip KCO North Caspian Sea Spray Operational Protection Structure 

Kashagan, Aktote Site Agip KCO North Caspian Sea Spray Operational Protection Structure 

Kashagan, Kairan Site Agip KCO North Caspian Sea Spray Operational Protection Structure 
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A review of the design criteria used in practice for spray ice islands suggests that the 

strength of the island itself is rarely critical in determining resistance to lateral ice loads, but 

rather the sliding shear force developed between the island and the seafloor. The general 

practice has therefore been to adopt a safe, lower-bound strength profile and undertake a 

check that it is adequate 

3.4.3.2 Gravel Islands 

This section begins with an overview of gravels islands with a general focus on their use 

from an exploratory drilling perspective. Following this, production projects utilizing gravel 

islands have been highlighted; further information with respect to gravel islands can be 

found within the assessment section, Section 4. 

Exploratory drilling for oil and gas commenced in the Mackenzie Delta area of Northern 

Canada in the mid-sixties. After 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 island was constructed at a fairly sheltered 

location in the offshore delta in a water depth of 43 ft (13 m). There was no drilling from the 

island during the first winter in order to demonstrate that the island could withstand the 

winter ice. This it did successfully, and after adding additional fill during the next summer, 

drilling commenced (Croasdale and Marcellus, 1977). 

As shown below in Table 3-10, 31 artificial granular islands have been built in water depths 

ranging to 62 ft (19 m) in the Canadian Beaufort Sea. Note that Table 3-10 is an excerpt 

from Appendix Table C-2, Overview of Drilling Activity in the Canadian Beaufort Sea. 
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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 island
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Figure 3-67: Alaskan Beaufort Sea Manmade Islands (modified from US Army Corps of Engin
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Between 1975 and 1990, 17 gravel islands were constructed in the Alaskan Beaufort Sea 

(refer to Figure 3-67). In 2001, Seal Island (known 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 considerable influence on construction methods and 

island design. In the deeper water areas, multi-year ice incursions 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 trucking granular fill over the ice 

or in the short Arctic summer using dredges. Islands have been constructed of gravel, 

sand, silt and a mixture thereof. Slope protection has been designed to match the 

measured and predicted sea-state, which also influences the island freeboard needed to 

avoid wave over-topping. Slope protection methods for artificial islands have included 

anchored poly-filter cloth 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 concepts which were considered, 

artificial granular fill islands were selected to initiate Arctic offshore drilling. They had the 

advantage of short lead-time and the use of proven technology. Also they could be built to 

withstand the year-round environment and thus the drilling rig could stay over 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 ice-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. Figure 3-68 shows the two 
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basic designs utilized in the Canadian Beaufort Sea for the construction of granular fill 

artificial islands. 

Figure 3-68 is drawn with an approximate vertical 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 Artificial 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 beach 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. 
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Figure 3-69: Imperial Oil’s Arnak L-30 September 1976 Showing Wave Action on the 

Sacrificial Beach Island Design (from Croasdale and Marcellus, 1977) 

Referring back to Table 3-13, of the 31 islands constructed in the Canadian Beaufort Sea, 

13 were Sandbag Retained Islands, 13 were Sacrificial 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 large 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 m2

) manmade production island which 

was built upon an abandoned/deteriorated exploration island, Seal Island. It was chosen to 

utilize Seal Island because significant cost and time savings would be realized through 

rebuilding (and subsequent expansion) as opposed to starting 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 feet (12 m) of water and is located about 

6 miles (9.7 km) offshore. Seasonal access to the island is achieved via ice roads. 
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Figure 3-70: Northstar Production 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 truckloads of gravel was used to 

construct the island (Wright, 2006). In the summer 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 the island has been estimated as a meter or so which will 

require maintenance of the island. Wick drains were installed 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 constructed. 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 operated by BP Exploration 

(Alaska). 

This project pool has been developed from two artificial 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). 
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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). Production 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 Production Island (INTEC, 2007) 

Figure 3-72: Endicott Production Island (Thomas, n.d.) 
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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 the 1980’s and 1990’s. To the south, in Navarin 

Bay and St. George Basin, semi-submersibles were used extensively due to the relatively 

ice-free environment for most of the year. The first drilling operations undertaken by 

drillships in ice prone waters were primarily 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 developed the capability to maintain position in a variety of 

pack-ice conditions. This extended their operating season beyond the open water period, 

although they did not work extensively in heavy ice. The Explorer II (see Figure 3-73) is a 

Donheiser Marine, Super Class 1AA design. Its mooring system is an eight point wire 

design and had a variable load capability of 6,387 tons (5794 tonnes). 

Figure 3-73: “Northern Explorer II” (formerly the CANMAR 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 drilling operations in the spring 

break-up period and continuing until early winter. As a result, the Kulluk operated in a 

greater and more difficult range of pack-ice conditions than drillships. In addition, “in-ice 
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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 station-keeping operations in various pack-ice conditions. 

Figure 3-74: Kulluk (Courtesy 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 technical challenges that were 

considered and accommodated in the Kulluk’s design are highlighted as follows: 

• Minimizing the icebreaking and clearance forces that the vessel would 

experience from any direction, by providing it with an “omni-directional 

capability” to resist ice action; 
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• Developing a hull form that would “minimize” 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 conditions during extended season 

operations, with acceptable mooring line tensions and vessel offsets; 

• Developing a submerged mooring system that would “eliminate” the problem 

of ice entanglement with mooring lines at (or near) the waterline; and, 

• Configuring an ice management system that would be capable 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 unbroken ice, it 

normally worked in managed ice conditions, where 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 - Operations with Icebreaker Support (Courtesy of DC Marine) 
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3.4.4.2 Semi-Submersibles 

Semi-submersibles are conventional floating exploration structures and have been used 

considerably in the south Bering Sea. Table C-1 located in Appendix C provides 

information on Alaska OCS drilling activity including drilling rigs employed. In general, 

harsh environment winterized semi-submersibles have been used. 

An example of a previously used semi-submersible; the Ocean Odyssey (Figure 3-76) was 

an advanced super-class unit designed to operate 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-load 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 platform (SPG Media Limited, 2007i). 

Figure 3-76: Ocean Odyssey (NationMaster, 2005) 
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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 126,000 DWT tanker 

design with an ice strengthened hull. The assessment considered several mooring systems 

with both flexible and rigid risers. The final concept selection utilized a turret mooring 

system with flexible risers. 

The assessment concluded that although the FPSO would require local ice strengthening, 

ice was not the governing global design load. Moreover, the assessment concluded that no 

significant advances in technology were required 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/considered for ice environments. While no such 

production facilities have been built in the Alaskan OCS or the 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 project with a subsea oil pipeline. The Northstar 

project operated by BP Exploration (Alaska) Inc. included the design, construction and 

installation of the first offshore oil and gas production pipeline in the U.S. Arctic (Lanan et 

al., 2001). The Northstar Unit is located approximately 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). 
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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 Liberty Project Location Map (from Lanan et al., 2001)

A single drilling/production 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 facilities installed for oil production. Construction of the island 

and the pipeline were completed in 2000. Facilities 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) offshore in 37 feet (11 m) of water. Production 

of the 65,000 bbl/day is from the gravel island, with the oil transported 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. 
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The 10.75-inch (273 mm) crude sales oil pipeline offshore segment was a 0.594-inch (15 

mm) W.T., API 5L Grade X-52 based on pipe stability requirements during installation and 

compatibility with potentially high 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 thicknesses, 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 incorporated 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 gouge protection, permafrost and strudel current 

loadings, and construction methodology. The pipelines have been designed to withstand 

100-year return period environmental conditions. The Northstar 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 challenges 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 designed to avoid failure due to ice keel gouging 

of the seabed. The effect of sub-keel soil displacement interaction 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 considered against the maximum depth ice gouge measured from 
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10 years of gouge data which was determined to be 2.0 ft (0.6 m) (Lanan et al., 2001). The 

results indicate the pipeline bending strains due to gouging would be safely less than 

maximum allowable levels for the burial depth selected. 

Strudel Scour: The allowable pipeline free span lengths were evaluated for pipeline strain 

limitations and the prevention of vortex shedding induced oscillations of the pipelines. 

Based on available and applicable data, the value associated with the 100-year return 

period maximum horizontal dimension event was found 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 dimension 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 permafrost was found to be present along the 

pipeline route close to shore in water depths less than approximately 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 the 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 the influence of deeper water conditions. 

Here, the potential settlement was found to be generally less than 1.5 ft (0.46 m); a design 

value of 1.5 ft (0.46 m) was adopted and was assumed to be differential settlement. An 

operational limit state bending strain criterion was used to confirm that the pipelines would 

be safe under the maximum predicted differential thaw settlement. 

Upheaval Buckling: Because the pipelines were operated at a temperature significantly 

higher than that at which they were installed, upheaval buckling was a design issue. A 

maximum allowable overbend vertical curvature had to be defined for pipeline construction. 

A maximum 2 ft (0.6 m) variation in pipeline elevation (trough to peak) over 302 ft (92 m) 

was considered reasonable given the pipeline trenching/installation method (see Lanan et 

al., 2001). The results of the analyses indicate 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. 
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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 bending strain, with 1.8% strain for extreme events (Nogueira 

et al., 2000). Because these criteria are 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 shore approach at the landfall point included 

the consideration of coastline erosion effects on the stability of the pipelines as well as ice 

ride-up onshore. The shore approach at Point Storkersen 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 Island, the trench terminated at a vertically 

curved sheet pile slot in the island. The design 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 feet (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 undisturbed seabed. The trench was 

backfilled overtop of the pipelines using the trenching spoils. 

Pipeline Construction / Construction Planning Challenges & 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 techniques. The limited open water season in 

the Beaufort Sea combined with its remoteness and reduced accessibility with respect to 

mobilizing marine equipment (e.g. pipe laying vessels and ocean-going barges) makes 

construction significantly more expensive, extends 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 had 
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been used successfully in artificial gravel island construction and, coupled with ice 

thickening, offered an attractive alternative to conventional marine pipeline installation 

methods in this area. 

Construction of the offshore segment of the pipelines included construction of ice roads, 

thickening of the sea ice to form a bearing 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 prevent excessive deflections of the ice in the 

working areas. Offshore trenching was conducted from the surface of the ice using 

modified backhoes equipped with extended reach booms. 

Welding of the pipeline took place to the side of the trench, where non-destructive testing 

(NDT) was also performed. The welds were then coated, the cathodic protection anodes 

attached to the pipelines, and the pipelines strapped 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 pipelines 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 Oooguruk 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 height 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 transported to shore via a 

multiphase pipe-in-pipe system. 

Pipelines

Production will be transported to shore through a 5.6 mile (9 km) multiphase pipeline which 

will form part of a subsea bundle, including power to the island, which will be unmanned 
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during production operations. This line will be the first application of pipe-in-pipe (PIP) 

production flowline technology in the offshore Alaskan Arctic (Knott, 2006). The bundle is 

an open bundle rather than being enclosed in a single large pipe; individual pipes are 

strapped together which makes the system lighter and less complex which translates to 

lower cost (Knott, 2006). 

The open bundle consists of four pipelines including a 12.6 inch (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 grade X-52 materials or better. The presence of an annulus facilitates 

the use of an annulus vacuum monitoring or pressure monitoring system for leak detection. 

The annulus between the external and internal pipelines would 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 top of the pipeline (Knott, 2006). This backfill 

cover would also resist upheaval buckling of the pipeline as it heats up during operations. 

Another significant challenge associated with the Oooguruk pipeline was to design against 

the effects of strudel scour, where river overflood 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 pipeline. Such 

a system will detect any decrease in temperature, indicating loss of soil cover as the result 

of seabed erosion (Knott, 2006). Other design issues included thaw settlement of 

permafrost and upheaval buckling potential. 

Construction was planned to be carried out from the ice. In preparation for construction 

planning, two 330 ft (100 m) long test trenches 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 from the ice in the winter of 2007 (Nelson, 

2007a).
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3.4.6.3 Nikaitchuq 

ENI is planning to develop the Nikaitchuq Field offshore the coast of the North Slope of 

Alaska. The site is in the Beaufort Sea, near Spy Island and approximately three miles 

offshore Oliktok Point. 

The project calls for a production pad at Oliktok Point and offshore 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 pipeline leak detection. 

Nikaitchuq will produce up to 40,000 bbls/day (OilVoice, 2007). 

The pipeline was planned to be trenched from the ice in winter. Initial engineering work 

included pipeline concept evaluation, flow assurance, pipeline 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 artificial gravel island was to be located in 

Foggy Island Bay east of Endicott and was to be a self-contained drilling and production 

facility. The island would have been constructed 6 miles (9.7 km) offshore inside the natural 

barrier islands in approximately 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 pipeline 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 potentially high operational strains. The oil line was designed for a 

MAOP of 1415 psig (9756 kPa). The oil pipeline 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 selection, upheaval buckling, ice gouge protection, permafrost and 

strudel current loadings, and construction methodology. The pipelines were designed to 

withstand 100-year return period environmental conditions and utilized limit strain design 

criteria to meet the challenges of offshore arctic environments. 
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The pipeline was designed to avoid failure due to ice keel gouging of the seabed. Analysis 

indicated a 100-year ice gouge depth 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 potential 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 criterion to confirm the pipelines 

were adequately designed. The Liberty pipeline was designed for a maximum 1.2% 

operating bending strain, with 1.8% strain for extreme events (INTEC, 1999). 

INTEC (1999) prepared a conceptual 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 alternatives in the Liberty Environmental 

Impact Statement. The report reviews four design alternatives:

• Single wall steel pipeline; 

• Steel pipe-in-pipe system; 

• Single wall steel pipe inside HDPE (high-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 was 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 Sea Pipeline Studies 

In 1986, joint industry studies were undertaken to investigate the feasibility and cost of 

hydrocarbon transportation systems for the central and northern Chukchi Sea (INTEC, 

1986). The technical feasibility and costs for transportation systems 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. 
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Preliminary pipeline analysis was performed to define parameters that would significantly 

affect the technical feasibility and the costs of offshore pipelines, including routing, 

hydraulics, trenching, and construction. In subsequent studies (INTEC, 1991), preliminary 

pipeline design requirements 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 shore 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 environmental condition affecting hydrocarbon transportation 

systems. 

Survey data available at the time indicated 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) was recorded at a water depth between 115 

and 130 feet (35 and 40 m) and no ice gouges were recorded in water depths greater than 

190 feet (58 m). 

As with other arctic areas, one of the primary design concerns was ice gouging. The 

required depths of cover derived from statistical parameters 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 evaluated including laybarges, bottom tow, and 

bottom pull. For pipelines in water depths greater than 40 feet (12 m), a third generation 

laybarge was recommended as the method of installation. 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, the 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 advantage for the linear trencher where the pipeline length 

was greater than 35 miles (56 km). In shallow water nearshore, which was not accessible 

by the trailing hopper suction hopper dredge, a cutter suction dredge would be used to 

excavate the trench.
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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 respect to offshore drilling and 

production structures, topsides requirements, crude oil pipelines, 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 annual ice cover. Open water was described as 

approximately eight months of the 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 selected on the basis of 

withstanding combined stresses in the sagbend during laying and not on the basis of 

environmental loadings. 

Pipeline construction was not considered an issue and the longest line could be completed 

in two seasons. Construction in the southern Bering 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 sufficient 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, hydrocarbon discoveries in the Canadian Beaufort Sea convinced 

potential offshore operators to investigate offshore pipeline options for the Mackenzie Delta 

Region. Dome Petroleum, Esso Resources Canada, and Gulf Canada Resources 

evaluated pipelines and inter-island 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 satellite) in 65 to 200 ft (20 to 60 m) water depth to 

produce oil and gas. 
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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 trench. These pipelines would transport crude oil from the 

Amauligak field to an onshore pump station. The water depth was approximately 102 ft (31 
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m) at Amauligak and gradually decreased 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 flowline bundles from the proposed future Amauligak caisson retained 

island (CRI) to developments at East and West Amauligak which would be tied back into 

Amauligak. 

Additional details on these 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 Alpine field has been developed 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 (approximately 6 miles (9.7 km) long). The project did 

not progress in that form but the current production plan filed by BP proposes to use 

extended reach drilling that was not considered feasible 5 or 6 years ago. BP plans to drill 

six extended reach wells from Endicott Island which is located approximately 8 miles (12.9 

km) to the west of Liberty (Fischer and Schmidt, 2007). 
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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 Options Region US Beaufort Sea Chukchi Sea Bering Sea Cook Inlet Can. Beaufort Sea Can. High North Can. East Coast Offshore West Greenland Barents Sea Kara Sea (Gulf of Ob) Pechora Sea Baltic Sea Sakhalin Island 

Bottom-Founded & Fixed Type Structures 

GBS X X X X X X X X 

Mobile 

BottomFounded 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 X 
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The assessments of options presented in Table 3-11 are carried out in the following section 

(Section 4). In addition to the options above, advancing technologies (ERD, WIM, and Pilot 

Hole to Pilot Hole HDD) are also assessed as they have potential Alaskan OCS 

applications. Several options not carried forward 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 required (especially with sand islands) near the 

water line. However, CRI’s are an expensive solution for exploration in comparison to 

mobile bottom-founded units and have been generally 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 with other bottom-founded 

structures; both GBS and mobile bottom-founded structures are assessed. 

Floating ice pads, like those used for exploration drilling in the Canadian High Arctic, have 

also been excluded from assessment. Although these are potentially economical seasonal 

exploration structures, the project team is unaware of a location in the OCS study areas, 

which would permit their use (i.e. a location with adequate water depths and stable, or nonmoving, floating landfast ice). 
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4.0 ASSESSMENT OF OPTIONS 

4.1 Approach 

The results of the assessment of potential exploration and production options suitable for 

the northernmost regions of the Alaska OCS (the Beaufort, Bering, and Chukchi Seas) are 

presented in the sections that follow. 

In general, the assessment draws on the review of Alaskan OCS and analogue experience, 

current state-of-practice and state-of-the-art. Assessments also consider bathymetry, 

metocean, ice and geotechnical conditions (where such data is available). This 

environmental data is included in Appendix A (Metocean & Ice Data) and Appendix B 

(Geotechnical Considerations). 

Assessments of exploration and production options are primarily based on technical 

feasibility. As appropriate, the following other considerations 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 potential options identified, and the large geographic area 

encompassed by the Beaufort, Chukchi, the Bering Sea, location scenarios were created to 

help focus the assessments. Scenario identification also facilitated the gathering of 

metocean, ice and geotechnical data. Scenario locations (shown below in Figure 4-1) were 

chosen based on current and historic activity/interest (including lease sales, drilling, 

studies, projects, etc.) and water depths (given the general differences in structure types 

with water depths). 
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Figure 4-1: Assessment Study Areas with 2007-2012 Proposed Final Program Areas (modified f
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4.3 Metocean/Ice Considerations 

4.3.1 Beaufort and Chukchi Seas 

In coastal areas of the Beaufort and Chukchi Seas, mean monthly 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 Chukchi Sea winds on average are 

from the northeast. Nearshore 1/100 year winds in the Beaufort are higher 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 value 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 Chukchi. In the Beaufort, nearshore wave heights 

can reach up to approximately 20 ft (6 m) (US Army Corps of Engineers, 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 the Chukchi Sea, 1/100 year significant wave 

heights have been predicted at 29 ft (8.8 m) (MMS, 1986). 

Ice conditions in the Chukchi and Beaufort have some similarities; however, the ice in the 

Chukchi is much more dynamic than in the Beaufort. In particular, Chukchi landfast ice is 

typically unpredictably unstable 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 Beaufort 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 approximately 165 ft (50 m) water depth in some 

areas. 

4.3.2 Bering Sea and South 

In general, the Bering Sea presents a much less severe ice environment compared to the 

Beaufort or Chukchi Seas. However, wave conditions and seismic effects are more of a 

concern. Norton Sound has an average winter temperature 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). The 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-existent 
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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 North Aleutian Basins. 

Temperatures for these areas are approximately the same; during February the mean 

temperature is approximately 35°F (2°C). Winds generally prevail from the north or 

northeast during the winter months. 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 Bering Sea, St. George’s Basin is predicted to have the worst 

wave conditions, with a 1/100 year significant wave height of 45.6 ft (13.9 m) and a period 

of 15 seconds. From an ice perspective, the St. George and North Aleutian Basins do not 

experience ice each year, however, the Navarin 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 thickness is approximately 4 ft (120 cm). 

A summary of metocean and ice conditions for these areas is included in Appendix A. 

4.4 Geotechnical Considerations 

Areas of the Beaufort and Chukchi Seas are underlain 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) silts and clays or loose to dense 

granular soils, ranging in thickness 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 perspective, they may not provide 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, sands and gravels are present. Soil properties for St. George’s 

Basin, the North Aleutian Basin and the Navarin Basin have been adopted from PMB 

Systems Engineering et al. (1983) and are presented in Appendix B. It should be noted that 
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given the limited information available to the study team, these are significant 

generalizations based on information from certain areas. 

4.5 Bottom-Founded Structures 

This Section of the report addresses the types of bottom-founded structures that would be 

suitable for exploration drilling and/or production development. Only the support platforms 

up to the top deck are addressed; topsides facilities are not included in estimates of costs 

and quantities. However, the effects of the topsides facilities (weight, carrying capacity, 

stability, etc.) have been considered and allowed for. 

In terms of global size, structure cost and geometry, there is very little difference between 

dedicated exploration platforms and dedicated production platforms. In fact, an arctic 

mobile drilling structure is often more expensive than a production 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 mobilization of an exploration structure. 

4.5.1 Ice and Waves 

In any location where substantial multi-year ice can impact a structure, the loads resulting 

from this interaction become the primary design condition and the structure shape and 

scantlings1

 are dictated by both local and global ice loading intensities. In such locations, 

wave loads are small by comparison 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, the use of a monolithic type structure in order 

to eliminate local ice load effects, bridging and vibrations, results in relatively high global 

wave loads (an unfortunate “Catch 22” effect). In these areas, platforms similar to those 

proposed for the Sakhalin Island region would also be applicable. 

 

1

 Scantlings are the interior framing members of the structure. 
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After ice loads, there are two other parameters 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, although not in direct proportion. 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 that the deeper the water, the greater the 

horizontal design load, and also that the structure must increase in height and, hence, cost. 

In multi-year ice areas, there 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) water depths when foundation 

properties are relatively weak. There are no known bottom-founded platform design 

solutions for the 330 ft (100 m) plus water depth 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 consolidated ridge loadings are possible, bottom-founded solutions out 

to 425 ft to 500 ft (130 m to 150 m) water depths are potentially viable. 

4.5.2 Foundation Conditions 

The last of the three most important parameters is that of foundation strength and capacity. 

Foundation types range from “totally inadequate” (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 preparation. 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 soft material is only 3.3 ft (1 m) or so in thickness, 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 will 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 multi-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. 
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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 bottom, but be prepared to 

have an on-bottom contact force of approximately 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 replacement and providing a very large base area to 

the structure. 

• Weak clay foundation with shear strengths 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-situ clay strength and the base area 

chosen for the structure. Other effects that influence the excavation depth are 

water depth and the magnitude of the design ice load. 

With respect to foundation capacity for mobile drilling structures, the picture is somewhat 

different in that the structure will only be on location for a relatively short period of time. 

This allows for a basic design based on impact from first-year 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 either sandy cohesionless soils or cohesive soils that are 

stronger than about 600 psf (29 kPa) undrained shear strength. This 600 psf (29 kPa) 

minimum is not a given; the figure can be either higher or lower depending on the ratio of 

the water plane diameter to the base diameter of the structure. Generally, a value of 1 ksf 

(50 kPa) at the skirt tips will suffice for exploration drilling. 

4.5.3 Location Scenarios for Proposed Structures 

After a discussion on various factors that influence the choice of structures, ten (10) 

location scenarios are assessed with respect to the types of structures that may provide a 
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possible solution; in addition, two (2) general structures (one with oil storage and one for 

mobile drilling) are assessed. Material quantities and approximate installed costs are tabled 

and discussed. Quantities and costs are also given for a platform in 100 ft (30 m) water 

depth with 331,000 tons (300,000 tonnes) 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. 
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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 

Foundation1

 

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 Foundation3

 

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 are 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 required 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 for 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 round exploration or early development drilling. However, it would not have 

the capacity to stay on location under the 100-year multi-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 area, ice and wave loads are of the same order of 

magnitude. Wave loads will dominate the design from a point of view of required weight on bottom and ice 

loads will dominate from the aspect of local strength design.
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4.5.4 Technical Feasibility of Structures 

4.5.4.1 Ice Loads 

In the Beaufort and Chukchi Sea areas, the 100-year design ice loading condition arises as 

a result of an interaction with thick multi-year ice. The load resulting 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 structure should have a factor of safety of 1.0 

against significant lateral movement or tilting under a 1000-year scenario. This load and 

resistance philosophy is not specified rigidly in offshore codes, but it is one that is generally 

accepted throughout ice-dominated areas. In the event that large quantities of oil are 

stored, then survivability or non-spillage may have to be demonstrated 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 four between the global load scenarios), the quantities of steel in 

a temporary drilling structure will not be much different than those in a permanent 

production structure. In fact, as mentioned earlier, temporary mobile structures may be 

more expensive due to having to cater to a set-down range rather than a specified depth. 

In the case of exploration drilling, the historical approach is to establish foundation stability 

based on a deterministic first-year ice loading 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 floes 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 typically observed as one goes 

farther offshore. Again, these arguments only apply to temporary “one well” drilling 

structures that have to sit on relatively weak clay foundations. 

Prior to 1980, there was no real understanding of the global ice loads that could be 

imparted to a bottom-founded structure in the Beaufort 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 extrapolate directly to large contact areas. Most 

scientists recognized that, due to the brittleness of ice, linear extrapolation was 

conservative, but they had no way of knowing by how much. In 1980, in a water depth of 
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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 metric tonnes or 15,000 MN). 

Since that time, and particularly as a result of the Hans Island experiments 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 presented 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 probability distribution 

curve, a factor of safety of 1.5 with respect to a 100-year load becomes 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 Canadian 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 relevant factors (ice strength, floe size, etc.) 

with their individual probability distributions are fed into a Monte Carlo simulation. An 

important factor in this exercise is the waterline diameter of the structure being impacted. 

Another factor that is considered important by some is whether 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 multi-year ice impact. This is 

because large amounts of ice can build up and crushing is then transferred to a pseudo 

vertical ice wall some distance back from the structure. For first-year and relatively thin 

multi-year ice, a slope should definitely reduce ice loads, but these scenarios do not govern 

the design. It is the authors’ opinion that any proposal to significantly reduce the global load 

from a multi-year ice interaction as a result of interacting with sloping sides (as opposed to 

vertical sides) be viewed with skepticism. 

The waterline diameters of bottom-founded structures 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 necessarily in a directly linear 

fashion. Also, water depth affects global multi-year loads. Between 30 and 100 ft (10 and 

30 m) water depth, loads are approximately linearly 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 ranges that modern probabilistic methods would predict. With 

respect to the Chukchi Sea, load ranges are given with respect to the northernmost areas. 
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In southern areas, close to the Bering Strait, 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 temporary deployment for an exploration structure is being considered, 

arguments as outlined above can be rationally 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 design loads and they do 

not affect the overall external dimensions of the structure. Depending on the degree of 

conservatism chosen, these local ice-loading pressures can greatly affect the outer shell 

quantity requirements. Additionally, the outer shell design methodology is very important 

and whether or not it is a deformation-based design, as opposed to a stress-based design, 

can have an enormous effect. As an example, a typical local loading pressure could be 

about 435 psi (3 MPa) over approximately a 16 ft by 16 ft (5 m by 5 m) area (270 ft2 or 25 

m2), with smaller areas having greater intensities. 

4.5.4.2 Foundations 

The effect of foundation strength has been discussed earlier and it must be restated that a 

strong foundation is a great asset to any bottom-founded development. 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 shallow example is presented such that 

inclined bearing failure will not be an issue; 
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• 13 ft (4 m) of cohesionless 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)/(Tanφ), 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 without solid ballast. Thus, even though 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 clay 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 necessary as an on bottom weight. 

In this example, as long as the on bottom weight 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 required is given by (Ice Load*FS)/(Soil Shear 

Strength), or about 110,000 ft2 (10,000 m2). 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 additional 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 ft2 (10,000 m2) need to be met for 

this example. A full 3D analysis could, however, lessen the base area requirement by a 

small amount. But there are other 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 granular 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 respect to the use of sand backfills, this is a 

different matter. Thus, stability can be achieved on all cohesionless foundations simply by 

means of weight alone. 

However, in the event of a cohesive clay foundation, the structure base area requirement 

grows proportionally to the ice load and inversely as to the shear strength of the clay 

foundation. 
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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 design 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 ft2 (30,000 m2) and the base diameter 

to approximately 625 ft (190 m). This diameter would need to be achieved by an inverted 

cantilever design, but would nevertheless be extremely 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 and backfilling are seen to be 

undesirable from an environmental 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 arctic bottom-founded structures had 

the advantage over steel. At that time, local ice loads were thought to be phenomenally 

high, which favored thick-wall concrete as the construction material of choice. As well, steel 

plastic catenary mechanisms were not well understood, and this led to thicker steel “ice 

walls” with corresponding increases in steel weight and cost. Steel was also thought to 

have insufficient notch toughness for the arctic environment. Experience has proven, 

however, that steel is the preferred construction material of choice for high arctic and subarctic GBS concepts. 

There are many additional implications 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 width is subsequently required 

than that of a “lighter” steel GBS. It is the authors’ 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 where ice is involved, concrete solutions end up being close to two 

or more times the cost of steel solutions. 
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These cost factors of two or more are often not readily apparent and at first glance price 

differentials may not be obvious. For instance, 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 being performed after set-down (this can also lead to 

decommissioning issues). Steel solutions can carry 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 Sea areas with water depths in the 65 to 

130 ft (20 to 40 m) range, the compounded problems of draft and topsides 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 the 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 perfectly 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 comparable job to steel in the Arctic will be 

significantly greater than that of steel). With respect to the existence of lobbyists for steel 

arctic construction, the shipyards of the world do not partake in promoting 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 can 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 contractors will often readily provide design, 

construction and cost estimating services. 

4.5.4.4 Wave Loads 

Wave loads in certain areas can become a primary design consideration, although for the 

Beaufort and Chukchi Sea areas it is generally ice loads that govern stability. There are 

three subsets, however, that need checking. The 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 bottom contact force as the wave amplifies due to 

reflection at the front face of the structure. The third is shallow water. 
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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, the design wave becomes a 26 ft (8 m) breaking 

wave. Such a wave can exert considerably more force on a monolithic object than on its 

deep-water counterpart. Since ice loads are fairly low in 33 ft (10 m) water depths, it is 

possible that equivalence or “crisscrossing” of dominant load effects 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 monolithic GBS. These GBS structures 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 the structure, a diameter squared 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 tend to occur at still 

water, whereas maximum drag loads occur when 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 the structure is to be deployed in deepwater, e.g., 200 to 445 ft 

(60 to 135 m), particularly if the accompanying ice loads 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) mark, if constructed of steel. 

Accurate evaluation of wave loads involves the use of sophisticated computer programs 

that take into account wave diffraction effects on large structures of arbitrary shape. The 

final load is a function of wave height, water 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 estimated based on certain empirical rules. The loads shown in 

Table 4-3 below are approximate and are based on “pyramidal” or stepped structures being 

used in the deeper areas of interest. 

Changing the shape from cylindrical to conical can have load reduction effects of 50% or 

more (this effect is graphically illustrated below in Figure 4-2). Such conical shapes are 

easy to achieve with steel but costly for concrete, and since the vertical centre of gravity 

(VCG) of the steel conical shape can be lowered by the use of solid ballast, very large 
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amounts of topsides can be carried due to its relatively 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 have 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 large 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 displacements are based on the 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] 

Beaufort Sea 100 (30) 25 (40) 90,000 (247,000) [400 (1100)] 

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 loads 
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Figure 4-2: Wave Load Comparison of Hibernia-type GBS vs. Stepped-style GBS 

(Fitzpatrick and Kennedy, 1997) 

4.5.4.5 Gravity & Foundation 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. Foundation reaction loads for a 

GBS are often overlooked, trivialized 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 “loads” rather than “supports”. 

As detailed in Fitzpatrick (1994), the recommended 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 shell strength requirements. 

Experience has shown that, even when soils are soft, very high local pressures can build 

up locally against the base of an offshore structure. These pressures are of the same order 

of magnitude as ice load pressures, which means that the structure base needs to be “as 

strong” as the vertical sides. This is an important 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 structure, skirt systems that cater to varying soil conditions are 

virtually mandatory. In some instances in mobile structures, where the skirts have been 
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specifically designed for a range of soil conditions, complete penetration may not be 

achievable where soils are tough. Generally, skirts on mobile arctic structures need to be 

about 6.6 ft (2 m) high to cater to varying conditions. For permanent structures, the skirts 

can be designed to site-specific conditions. However, 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 foundations, to ensure sand particle 

to sand particle frictional resistance. Generally though, skirts for permanent structures will 

be thin to ensure complete penetration and will only 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 – provided the base is greater 

than 330 ft (100 m) – plus the large mass, minimizes vibrational effects to a level of around 

5 to 10% of gravity with a total system frequency on the order of 1 Hz. Potential vibratory 

effects from, for example, continuous first-year light ice are therefore of minor concern. 

Radiation damping plays a significant role in eliminating the dynamic amplification of forced 

vibrational effects from ice. It is a complicated phenomenon, but its effects grow in 

accordance with a power law function of the base diameter of the structure. 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 diameters 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 for 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 demonstrated that lesser levels are permissible. 

4.5.4.7 Seismic Loads 

The general Chukchi and Beaufort 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 vibrations) 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 structures are to be designed for the very high 
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seismic loads in these locations, these loads will not significantly affect the overall size or 

cost of the basic platform, but rather will require greater attention to foundation capacity. 

Additionally, some dynamic amplification will result in greater topsides stiffening or isolation 

requirements. 

With a steel GBS, the VCG in deepwater seismic areas is very low (due to the enormous 

amount of concrete ballast required) and dynamic 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 topsides location. There are cut-off points with 

respect to allowable vibrational levels and, in some instances, topsides isolation 

mechanisms may be deemed necessary. However, this last point is a relatively subtle 

technical difference between the two materials. 

4.5.4.8 Fatigue Loading, Brittle Fracture, & Temperature Effects 

The day-to-day loads from ice or waves induce only very low levels 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 structures 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 ductility 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 structures. Differential temperatures of 100°F to 

125°F (40°C to 50°C) across a structure can be easily handled by steel. However, 

differential temperature stresses, in combination with ballasting and differential settlement 

effects, can be a more serious concern for the long-term serviceability of concrete, e.g., 

liquids tightness and crack control. For concrete, these effects can become a significant 

design condition and solutions may require very high levels of multi-axial pre-stressing 

steel. The effects are more pronounced in relatively shallow waters, 33 to 100 ft (10 to 30 

m) where high shear stresses can build up in the concrete due to differential settlements. 

4.5.4.9 Oil Storage Effects 

Depending on the water depth and the foundation type, a certain amount of potential oil 

storage capacity can be provided relatively cheaply. All oil storage concepts to date in the 

Arctic are of the oil/water type. Oil/air concepts become enormously expensive, are viewed 
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as more dangerous and, to date, a concept that no one has considered seriously. A certain 

amount of oil storage is generally considered to be reasonably “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, therefore, depends on the water depth, the foundation 

type, the structure volume and whether or not solid ballast as opposed to water is used in 

the free space. This initial “free 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 thousand bbls up to 1.5 million 

bbls or more. 

After this initial amount of relatively free storage, any additional barrels must be provided 

for by specifically increasing the volume of the 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, Drawing 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. 
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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, ft2

 (m2)] 

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], ft3 (m3) 

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/a 
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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, ft2

(m2)] 

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], ft3

(m3

) 

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) 
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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, ft2

(m2

)] 

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], ft3

(m3

) 

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) 
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Figure 4-3: Drawing No.1, Option No.1 – Platform and Foundation for 33 ft (10 m) of W
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Figure 4-4: Drawing No.2, Option No.4 – 660 ft (200 m) Plus Mobile Exploration Concept
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Figure 4-5: Drawing No.3, Option No.5 – Platform and Foundation for 100 ft (30 m) of W
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Figure 4-6: Drawing No.4, Option No.9 – 445 ft (135 m) Stepped Steel Structure
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Figure 4-7: Drawing No.5, Option No.10 – 330 ft (100 m) Stepped Steel Structure
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Figure 4-8: Drawing No.6, Option No.11 – 100 ft (30 m) Storage Hull Transverse Section and Des
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4.5.5 Constructability 

In the early-1990’s, a Canadian firm (CANMAR) 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 conservatism inherent 

in the state-of-the-art at that time and to demonstrate that significant savings in steel weight 

(and cost) were possible. 

Four basic types of tests on low temperature ductile steel were conducted. The first two 

were plate and stiffener tests with hydrostatic pressure loading and the results were directly 

applicable to the outside wall and base of an arctic steel gravity structure. The last two tests 

were in-plane loading tests, and the results were used to improve the design performance 

of internal bulkheads (the members that transfer global loads through to the foundation). 

The testing program was carried out in Edmonton 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-Founded Arctic Steel Structures (Fitzpatrick, 

1994), discusses the underlying engineering principles and the verification of these 

principles by the testing program. 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 presented in this report could 

be constructed by a number of shipyards around the world. 

Installation of a GBS structure in the Alaskan OCS will not be dissimilar to installations on 

Sakhalin, on the Grand Banks and in the North Sea. Weather and seasonal 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 platform 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 required. If the allowable location tolerance is around 16 to 33 ft 

(5 to 10 m), this could be achieved by floating vessels only. In the event that set-down 
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accuracy of about 3.3 ft (1 m) is required, an anchored spread and a day or more of calm 

weather will be required. There should be no reason for extreme set-down accuracy unless 

the unit is required to sit precisely over pre-installed seabed systems, e.g., wellhead 

templates, pipeline connection, etc. 

4.5.5.1 Foundation Issues 

Relief in the seafloor topography resulting from ice gouging could affect the final placement 

location of a bottom-founded structure, 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” these gaps. However, a small lateral transfer is all that is 

necessary. 

As discussed in Section 4.5.4, of greater concern for bottom-founded structures is the soil 

strength profile at the installation site and the possible need for foundation improvement. 

Sites with soft/weaker upper layers may require excavation of these layers to expose the 

stronger soils below. This will either add to the overall height of the platform or require 

backfilling of the excavation with more competent material. 

4.5.5.2 Weather Window 

During installation, there will be some sea state limitations, but these are fairly well 

understood and are not considered showstoppers. Because the structures proposed have 

short skirt systems and are not reliant on foundation grouting, basically all that is required is 

to get the structure on location within +/-33 ft (+/-10 m) and then flood quickly. Normally, it 

takes up to 24 hours to get the structure 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 investigation was carried out with 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 North Aleutian Basin GBS 
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solution, as it is similar in nature. It can be seen that the tabularized costs have been 

estimated as approximately twice the 1997 costs. There is no real justification for the large 

cost increases quoted other than that shipyards today are 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 shipyards would still make a significant profit. 

An important way to significantly reduce the tabularized costs is to allow the shipyard to 

engineer and fabricate most of the facilities. As a result, 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 market and that nothing else other than the 

basic platform is being contracted. Chinese yards could be cheaper, but they are very 

unpredictable in their responses.
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Table 4-7: Estimated 2007 Installed Platform Costs, in Millions of USD, Exclusive of 

Topsides Costs if Platform Only is Contracted 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) 
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Table 4-8: Estimated 2007 Installed Platform Costs, in Millions of USD, Exclusive of 

Topsides Costs if Platform Only is Contracted 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) 
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Table 4-9: Estimated 2007 Installed Platform Costs, in Millions of USD, Exclusive of 

Topsides Costs if Platform only is Contracted 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 on 

Max. 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. 
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In Figure 4-9 below, 9 (nine) of the cost-estimated options are plotted. The estimated cost 

(Y-axis) is in millions of USD per foot (and per meter) water 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, consider a 165 ft (50 m) water depth. 

For a weak foundation, a cost of about $15 million/m can be read from the figure. Similarly, 

for a strong foundation the appropriate 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 factor for the platform. 

Consider the following two permutations: 

• 165 ft (50 m) water depth, good foundation and shipyard involved with 

topsides. The cost of a platform would then be $11.5 MM/m times 50 m times 

0.75, which equals approximately $430 million. 

• 165 ft (50 m) water depth, weak foundation and no shipyard relationship 

concerning topsides. The cost of platform 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 perfectly defined, there is 

still the possibility of a wide variance in cost. In this simple example, depending on just the 

variance of two parameters (shipyard relationship and foundation conditions), the cost can 

vary between $430 million and $750 million. 
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Figure 4-9: Estimated 2007 Installed Platform Costs (USD), Platform Only Contracted to 

Shipyard, Exclusive of Topsides 

4.5.7 Environmental Considerations 

There will potentially be some environmental considerations associated with the installation 

of a bottom-founded structure in the Alaskan OCS. A primary consideration will be whether 

or not dredging and/or backfilling 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 required) 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 near the excavation, but 

that a plume of fine suspended sediment could drift several miles (MMS, 2003). 
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4.5.8 Operations, Maintenance, & Repair 

A significant operational consideration is transport of production whether through a pipeline 

or by tanker. In the case of tanker transport, weather conditions are a key factor. Another 

key aspect of operations will be the safe evacuation 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, ice management, bunkering, etc. 

Maintenance and inspection shutdowns may be required for regulatory compliance. 

However, these shutdowns would 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 Alaskan OCS, site-specific consideration needs 

to be given to the environment. 

While a planned inspection and maintenance program can be controlled to some degree, 

breakdowns occur. Consideration needs to be given to redundancy of critical equipment, 

spares philosophy and transport of personnel/equipment. 

Supply and personnel logistics for operations will be an important consideration. A marine 

base will need to be established 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 production chemicals, diesel, fresh water, 

equipment/materials and drilling/completion bulk fluids. 

Helicopters and a heliport will be required to transport personnel to and from a GBS and 

also provide emergency response support. 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 safety risks. Decommissioning 

procedures for offshore installations that have reached the end of their useful life are 

usually included in governing legislation, e.g., C-NLOPB, Norwegian Petroleum Directorate, 

UK Oil and Gas Directorate. There are also international agreements relating to 

decommissioning that address removal and deep-sea disposal. For example, the 
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International Maritime Organization (IMO) has 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 overseeing decommissioning might 

include, among others, the conditions that the bottom-founded structure be designed so 

that it can be removed if the authorities at that time so require and the requirement that the 

Certifying Authority reviews the suitability of the detailed design of the structure for eventual 

re-floating. 

Based on these requirements, decommissioning will likely be an important consideration for 

any Alaskan OCS bottom-founded structure concept. 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 future has increased. The OSPAR Convention (1998), whose 

signatories include Norway and the UK, includes provisions relating to prevention and 

elimination of pollution from offshore installations. 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 made 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 platforms 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 Association 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 raised 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 production 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 properties 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 since been adapted and modified for use all over the 
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world. It comes in a variety of styles from the single-legged (monopod) to multi-legged 

structures. 

The ice reinforced jacket platform was first successfully 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 Inlet; 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 conducted by PMB Systems Engineering Inc. et al. 

(1983), the Norton Basin by Fluor Engineers Inc. (1982), and the North Aleutian Basin by 

Brian Watt Associates (1985) suggest that jacket structures may be suitable for use in the 

Bering Sea. 

4.6.1 Technical Feasibility 

4.6.1.1 Arctic Jacket Structure 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 structures are temperature loading, sea ice static 
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loads and the accompanying vibration loads. In many 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 generally 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 designed for the maximum ice load that results 

from three specific loading mechanisms. 

• Momentum load is the load that results from the ice flow impacting the 

structure. 

• Ridge building load is the pressure load the structure experiences as a ridge 

and rubble field builds. 

• Pack-Ice loading is the tangential frictional loading that results from the ice 

flow passing by the ridge and rubble field that has formed in front of the 

structure (Cammaert and Muggeridge, 1988). 

The load imparted to a structure 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 legs (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 independently and ice bridging will not occur between the jackets 

legs. When the legs of the jacket act independently, smaller global loads are experienced 

by the structure. Sanderson (1988) does not indicate what the maximum sea ice thickness 

for which this D/W ratio value of seven is applicable. 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 the 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. 
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Figure 4-11: Sea Ice Loading a Jacket Leg, Cook Inlet (Courtesy of CIRCAC, 2007) 

In addition to handling static sea ice loads, the jacket structure must handle the vibration 

loading resulting from the random ice edge hit, sudden ice load relaxation, unsystematic ice 

load level variations and continuous repeating ice load failures. Ice reinforced jacket 

structures are more susceptible to vibration than conventional jackets because they have 

less damping ability and tend to amplify vibrations 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 design 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 possible to minimize the displacement resulting 

from the dynamic loading. Second, the structural mass and stiffness of the jacket can be 

changed to reduce the structures resonance. 

Another consideration is temperature 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 that is readily available in today’s market. 
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4.6.1.2 Arctic Jacket Structure Enhancements 

Recent developments and lessons learned that should be used in the potential 

development of future jacket structures 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 damage 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 design by increasing the redundancy of its 

members. 

4.6.1.3 Assessment of Jacket Platform 

The suitability of jacket structures has been assessed for the 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 Platforms in the Bering Sea

A review of metocean data, prior studies of the South Bering, the Norton Basin, the North 

Aleutian Basin and George’s Basin, along with an evaluation of the Cook Inlet jacket 

structures, indicates that jacket structures potentially can be used in some areas of the 

Bering Sea. However, if oil storage is required, jacket structures are limited by this 

requirement. 

Previous studies of the 1980’s (PMB Systems 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 studies do not consider the dynamic loading of the sea ice on 

jacket structures. 
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In light of a previous jacket failure in the Gulf of Bohai and the dysfunction of another as a 

result of ice induced vibrations (Cammaert 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 problems, jackets used in sea ice have 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 separate ice reinforced enclosure. 

Both solutions have challenges and increase jacket 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 flow of 100,000 BOPD would require a leg diameter 

of 55 ft (17 m) (Brian Watt Associates, 1985). In turn, 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 additional 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 load and it also 

increases the possibility of ice bridging across the conductor and the legs, which again 

further increases the 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). The jacket structure’s poor response to dynamic loading and the 

conductor system protection issues are a significant 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 design make their application 

unsuitable for the Beaufort and Chukchi Seas. The primary load case in both areas is ice. 

The Beaufort Sea commonly experiences thick multi-year ice floes and the Chukchi has 

been observed with enormous multi-year ridges. The thickness of the ice not only 

significantly increases the load on the structure, but it also creates problems with the 
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location of the jacket bracing. The bracing should be located below the underside of any ice 

features which could interact with the structure. Thick ice features means that the effective 

length to radius of gyration ratio (KL/R) of the 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 the greater unsupported column length, it will result in 

increased wave loads and drag on the structure. This process 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 similar to typical jacket construction for the Gulf 

of Mexico, North Sea, etc. The only exception is that the procedures used to weld low 

temperature steels are slightly different than those for conventional steels. 

Jacket fabrication would take place onshore using conventional shipbuilding techniques 

and equipment. Suitable facilities exist nearby in the Western USA, Russia and Japan. 

The fabricated jacket would be loaded out on a barge and transported to site. Once onsite 

the jacket would be launched, upended and seated in place. Piles 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. Jacket structures are hydrostatically unstable 

and, therefore, no topsides could be on board during installation. 

4.6.3 Capital Costs 

The capital costs associated with the platform design, fabrication, and installation would be 

directly related to the water depth, environmental loading and topsides requirements. As an 

indicator, the costs per tonne for conventional piles and jackets can be estimated as 

follows: piles – $2,500 per ton ($2,800 per tonne); jackets – $7,300 per ton ($8,000 per 

tonne). These costs are in USD and cover the material, fabrication labor, load-out and tiedown at the topsides fabricators quayside. 

4.6.4 Environmental Considerations 

Installation of a jacket structure would have minimal environmental issues associated with 

the activity. The major environmental considerations for offshore platforms inclusive of 

jacket types consist of the following: 
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• The presence of the platform: how will the presence affect the local 

ecosystem and industries such as commercial shipping and fish harvesting; 

• The possibility of discharges from the platform; 

• Platform noises, and the affect the noise 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 concerns as a result of its small footprint and 

due to the fact that the topsides and jacket of the structure can be removed 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 structure 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), additional inspections may be dictated. Physical 

inspections would be planned around open water as inspections in winter would be 

challenging. 

4.6.6 Abandonment & Decommissioning 

Considerations regarding abandonment 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 removed 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 sides and deck can be recycled or alternatively 

retrofitted and installed at an alternative location. 
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The next step in the demolition process is the removal of the jacket. This is performed by 

cutting the jacket from the piles by the use of mechanical or thermal cutters. In some 

situations, the jacket can be separated from the piles using explosives. Once the jacket is 

separated from the piles, a sea crane is used to lift the jacket 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 date, a cost effective method has not been 

developed. 

4.6.7 Commentary on Jack-ups 

The jack-up rig was first introduced to the offshore 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 fleet 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 recent state of the art jack-ups can operate in 

water depths of up to 500 ft (150 m) and drill 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 numerous ocean environments. As of yet, 

none have been constructed to operate 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 indicative that the operating 
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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 brief investigations into the 

structural feasibility of using jack-up Rig SX during freeze up in Sakhalin. Rig SX is a 

triangular shaped hull configured with 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 and 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 connections between the verticals and the leg 

chords. 

Extrapolation of CKJ's study would suggest that a proportion of the world’s jack-up fleet 

have the structural potential to operate in light 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 Ice 
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The successful development and the implementation of a jack-up drilling program on the 

Grand Banks of Newfoundland, Canada was accomplished by the establishment of the 

understanding of the ice-free 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 statistical analysis of the historic 

sea ice edge. The ice management program was inclusive 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 first of its kind, is under construction at the 

Severodvinsk Shipyard, Russia. It is being constructed to operate in Arctic water depths of 

up to 330 ft (100 m) and in ice floes of 1.6 ft (0.5 m) thick (MNP Global, 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 drilling program on the 

Grand Banks – coupled with the previous use of jack-ups in the Norton Basin (see Table 

4-10) – indicate that the operating range of jack-up drilling rigs can be marginally expanded 

in the Bering Sea. The limit of this expansion is dependent on the development of an icefree season, ice management programs and the study of individual rigs to determine sea 

ice loading capabilities. 

Table 4-10: Historic Bering Sea Wells Drilled 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 for 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 drilling methods such as ice class drillships or 

bottom-founded structures, e.g., SDC. 
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4.7 Ice Islands 

Grounded ice islands have been used as exploration drilling structures in nearshore areas 

of the US and Canadian Beaufort Sea. Based on the current state-of-practice and 

technology, ice islands have been assessed with respect 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 Technical Feasibility 

From a general perspective, the technical feasibility of an ice island exploratory drilling 

platform is based on several fundamental regional and site specific considerations: 

• Meteorological environment; 

• Water depth; 

• Landfast ice characteristics; and, 

• Geotechnical (seabed) conditions. 

With respect to meteorology, the winter temperature regime plays an important role. The 

temperature regime is important because of its influence on natural landfast ice thickness, 

spray ice construction process effectiveness and ice island/road integrity. 

Natural landfast ice must be stable and sufficiently thick to permit mobilization of equipment 

and personnel for construction. Road construction and site preparation using light 

equipment may proceed when ice thickness reaches approximately 2.6 ft (80 cm) (CCORE, 2005). In the Beaufort Sea, freeze-up typically begins in mid-October and as shown 

in Figure 4-14 below, ice thickens by an average rate of approximately 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 spray ice production can be achieved below -4°F (-

20°C), but that the process becomes ineffective above 5°F (-15°C) (C-CORE, 2005). Wind 

speed also plays important role in spray ice production rates. 
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Figure 4-14: Typical Ice Thickness Growth for Canadian Beaufort Sea (Modified from CCORE, 2005) 

Ice strength is a function of temperature. Therefore, as the winter season draws to a close 

and temperatures begin rising above freezing, ice island/road integrity begins to 

deteriorate. Ice ablation also starts occurring when temperatures rise above freezing. 

Ice roads must maintain adequate load capacity to permit safe demobilization upon 

completion of drilling activities and, therefore, this deterioration 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 generally occur by late April to late June (CCORE, 2005). Ice road closures, therefore, ultimately 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 feasibility of an ice island, it is obvious that 

temperature regime is an important consideration and that lower temperatures and longer 

winter seasons are favorable. In the Beaufort 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). 
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Water depth is a fundamental factor that must also be considered when evaluating the 

feasibility of grounded ice island structures. Generally, as water depth increases, island 

freeboard requirements increase as well and, in turn, influence construction time/cost. 

Practical limits on freeboard are governed by spray ice equipment capacity and time, i.e., 

environment temperatures and durations. Review of previous ice island usage shows that, 

in practice, operational drilling 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 surrounding 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 velocity, total seasonal movement and air and ice 

temperature (C-CORE, 2005). 

Ice loads imparted on an ice island will depend on the ice failure mode, rather 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 the 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 operational 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. 
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Figure 4-15: Spray Ice Island 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 core). Assuming that the shear capacity of soil 

beneath the island is less then than that of the ice island core, sliding resistance will be the 

governing failure mechanism. This is typical of the Canadian and Alaskan offshore Arctic 

where soils are of relatively low strength (C-CORE, 2005). 

The sliding resistance of an ice island is a function of contact area and soil strength, and 

can be found from the following expression: 

u i si w s

c

s c gH gd D R ρ ρ ρ φ π ( ( ( ) )tan

4

2

= + + −

Equation 4-1

Where, 

Rs is the sliding resistance of the island; 

Dc is the island core diameter; 

ρi is above water spray ice density; 

ρsi is below water spray ice density; 
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ρw is sea water density; 

cu is the bottom material cohesion; 

φs is bottom material friction angle; 

H is island freeboard; and, 

d is water depth. 

A contact factor is sometimes incorporated into 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 island 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 attributed to the fact that the strength of a clay soil is defined by 

its undrained shear strength (cohesion) and is therefore independent of applied confining 

pressure when acting in an undrained 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 ice/soil interface. A bearing pressure of about 520 psf (25 kPa) 

is considered acceptable”. 

If the seabed soil is cohesionless, ice island sliding resistance is a function of the applied 

normal (vertical) stress and the soil internal angle of friction. Increasing bearing stress, by 

increasing freeboard, will therefore cause a rise in shear resistance 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 ice island design, which will aid in 

assessing this technology for other Alaska OCS regions. It should 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 “This simplified model is 

convenient and has been shown to provide an acceptable level of confidence in design. 

However, it should be recognized that the island is not rigid, but acts as a continuum in 

which compression and distortion occurs”. Further information on ice island design, ice 
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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 that they present a proven and economical option 

for exploration drilling structures in nearshore areas of the Beaufort Sea. 

In practice, operational ice islands have been employed in water depths of up to 25 ft (7.6 

m) in the Beaufort Sea. However, 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 study (C-CORE, 2005) suggests that 

“incremental improvements in equipment capacity with higher productivity would allow 

islands to be constructed into deeper water and it is considered that 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 geotechnical considerations. Based on these fundamental 

considerations, Beaufort Sea experience and state-of-practice, ice island structures can be 

assessed for other Alaska OCS study areas. 

If the location scenarios and water depths presented in Figure 4-1 are specifically 

considered with respect to operational ice islands used in practice, 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 examination 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 assessment, Table 4-11 has been created to capture 

parameters indicative of ice island feasibility. 
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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) 

FDD3 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 feasible as observed from Table 4-11. A primary 

reason for this assessment is that Norton Sound’s average winter temperatures will prevent 

spray ice construction from being consistently effective. 

Furthermore, the time frame between mobilization and demobilization will be shorter. From 

the table, break-up in Norton Sound can occur up to one month ahead of that in the 

Beaufort Sea, and based on differences in maximum ice thickness and freezing degree 

days, one can draw the conclusion that “sufficiently thick” ice needed to begin mobilizing 

will not exist until later into the winter season. 

Also, since ice strength is a function of temperature, 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 temperatures and may result 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 limits that are observed. However, without 

detailed analysis it is difficult to rule them out definitively. 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 island to work 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 thickness & empirical formula: h = 0.01x√[(8Nθ-501)] (Sanderson, 1988)
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Nearshore areas of the Chukchi Sea (25 to 50 miles (40 to 80 km) from the coast) have 

been excluded from the upcoming lease 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 appropriately, contiguous ice zone, one can draw 

the conclusion that an ice island structure 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 continuous to shore and does 

not necessarily indicate that the ice has “stability inferred by the term fast ice” (MMS, 

1990a). Contiguous ice is unreliable and “sudden 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 3rd week of February, while the Beaufort Sea can experience 

stable landfast ice conditions more than a month and a half earlier (MMS, 2007b). Also, as 

stated by MMS (2007b), “the growth of landfast ice is not continuous and can involve 

formation break-up and reformation”. 

In the Chukchi Sea, landfast ice movements 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 the 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 environment can be found in MMS (2007b) and 

MMS (1990a). 

In light of the above description 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 drilling structure, very 

nearshore Ledyard Bay or just north of Icy Cape might be possibilities for consideration. 

These areas are at least partially protected and would possibly experience less dynamic 

conditions due to the bay environment. 
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4.7.2 Constructability 

As discussed earlier in this report, the first ice structures constructed for exploratory drilling 

were floating ice pads used in the Canadian High Arctic during the 1970’s and 1980’s. The 

majority of these ice pads were constructed 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 constructed the first grounded ice island during the 

winter of 1977-78 in Harrison Bay, Alaska. Similarly, slow build-up rates 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 demobilization date, prior to break-up. Within this 

timeframe (in addition to equipment mobilization, ice road and island construction), the 

drilling of a relief well may be required. If same-season relief well capability is required, a 

relief pad will need to be constructed and the drilling schedule must contain adequate time 

to permit relief well completion, prior to the latest safe demobilization date. Needless to say, 

time is of the essence in such a drilling program. To maximize the potential operating 

window, the ice island must be constructed and ready to accept the rig as early as possible 

(C-CORE, 2005). 

Alternative methods of ice island construction were investigated and through significant 

experimentation and study efforts spray ice technology 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 projecting a high pressure water jet into cold 

ambient air. The jet causes the airborne water to break into droplets thereby enhancing 

heat transfer, between the relatively warm seawater and the cold ambient air, as a result of 

increased surface area (C-CORE, 2005). This can result in water droplets forming ice 

crystals prior to reaching the ice island surface. 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 below, taken during the 

Thetis Ice Island project in 2002-03, illustrates the production/application of spray ice. 

Spray ice is typically applied in layers to the natural ice sheet. Over time, with continued 

application, the ice sheet will begin to sink as a result of the increased load and will 
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eventually ground on the seabed (C-CORE, 2005). Spray ice production may continue until 

the design freeboard is reached. The rate at which the island can be built up is a function of 

the time required to freeze and cure the spray 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 depending on the volume of spray ice needed, 

meteorological conditions (primarily ambient 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 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); 
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• Further reduction of design ice load by reducing the thickness of the 

surrounding landfast sheet; and, 

• Use of chipped ice, which 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 construction periods of warmer than seasonal 

temperatures, spray ice production 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 Date 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 equipment are employed to maximize 

ice accretion rates. Some examples of techniques 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 two main pump types used: skid mounted pumps, which are 

supported by the landfast ice, and larger pumps mounted on floating 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 island construction phase is required in order to verify that 

design assumptions and specifications are complied with (C-CORE, 2005). Monitoring is 

also necessary to track schedule and identify any productivity issues (C-CORE, 2005). 

Upon construction completion, construction monitoring data is reviewed and as-built 

geometry checks and ice strength tests may be performed (C-CORE, 2005). 
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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 loads expected, water depth and soil 

conditions. Cost optimization may be realized 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 facilities. This is, of course, because reducing 

the diameter of the island will reduce the amount of ice needed by a squared factor. 

The second factor is soil conditions and is also related to potential diameter reduction. As 

noted above, island sliding resistance for cohesionless soils is not dependent on contact 

area; therefore, for cohesionless soil conditions, island diameter should be minimized and 

freeboard increased to achieve required sliding resistance. C-CORE (2005) presents a 

good example, which demonstrates the sensitivity of island sliding resistance with respect 

to sand and clay soil conditions. 

The use of chipped ice in combination with spray ice can reduce freeboard 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 first involves monitoring ice conditions prior to 

and during construction and comparing them with 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 may allow reduction of ice load. This premise 

was utilized during the construction of the Thetis ice islands (C-CORE, 2005). A second 

way that ice load reduction may be achieved is through physical reduction of the 

surrounding ice sheet thickness. This technique was also used during the 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 should be kept in mind that the risks associated with the ice 

island drilling are higher, and gravel islands are more versatile with respect to water depths 

and ice loads. 
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Figure 4-17: Cost of Ice Island vs. Gravel Islands (Reproduced from C-CORE, 2005) 

4.7.4 Environmental 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 that it does not create a potential leak path 

for contaminants. In addition, C-CORE (2005) states that “The 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.” 
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4.7.5 Operations, Maintenance, & Repair 

As discussed throughout this assessment, time is a primary concern with respect to 

operations. However, drilling from ice islands has proven successful in the Beaufort Sea 

and, through continued optimization of design and construction and implementation of 

efficient drilling programs, risks associated with schedule will 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 movement 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 include 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 ensuring 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 maintenance perspective are ice 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 decommissioning are not seen as a concern with 

respect to the feasibility of this structure. It is assumed that upon 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. 
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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 candidate structure for 

exploration and/or production (for example, 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 economical structure type for shallow water 

depths. For the Beaufort Sea in particular, the potential to re-use abandoned 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 for other types of structures, it is not inconceivable that the 

current depths at which gravel islands are used will be surpassed. 

For these reasons and the renewed interest in the Arctic, it was 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 islands, referred to as “gravel islands”. Caisson 

retained islands are not considered. 
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4.8.1 Technical Feasibility 

The use of gravel islands for Arctic exploration 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, gravel islands have been constructed in a range 

of water depths, from on the order of several feet to over 60 ft. In theory, a gravel island 

has no depth limitation, but in practice it has been considered unfeasible beyond 

approximately 65 ft (20 m) because of economics 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 above the waterline. The Tarsiut caisson was previously 

deployed in 65 ft (20 m) water depth but a gravel island was constructed to within 9.8 ft (3 

m) of the water surface on which the caisson was 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 discussed in detail here. Instead, a summary and highlights of basic 

technical and design considerations 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 considerable 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 must have adequate lateral stability to resist ice 

loads. A gravel island typically satisfies this requirement 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 sliding 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 surrounding ice sheet is forced up the sloped side 
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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 magnitudes will differ, both exploratory drilling 

(short-term use) and production (permanent) gravel islands must account for the above 

mentioned design considerations. For exploration gravel islands, design loads are generally 

based on 1/10 year events, while production island design loads are based on 1/100 year 

and, in some cases, 1/1000 year events. 

In general terms, these environmental loads are managed through gravel island geometry. 

Ice ride-up is impeded by the sloped island sides due to friction and plowing forces and/or, 

in some cases, by discontinuity in slope (Cammaert and Muggeridge, 1988). Consideration 

also has to be given to ice fragments being driven into the island during storms. Figure 4-19 

illustrates Northstar’s ice protection design. Waves begin to break as they reach the sloped 

island sides, thereby dissipating energy before they reach the working surface. Wave 

overtopping is dealt with by placing the working surface above the design wave height 

and/or by placing a barrier around the working surface perimeter. The Northstar production 

island incorporated such a wall into its design. 

Figure 4-19: Northstar Production Island Ice Protection Design (BPXA, 2005) 
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In addition to design loads, the erosional effect of ice and waves (and potentially current) is 

another important consideration. A variety of methods/materials and combinations have 

been used to control gravel island erosion, including sandbags, various filter cloths and 

fabrics, sheet piles and concrete mats. 

Figure 4-20: Ice Clearing on Northstar 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 exploration island. Figure 4-21 and Figure 4-22 

show some additional exploration and production gravel island designs. 
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Figure 4-21: Basic Designs for Granular Fill Artificial Islands used in the Canadian Beaufort 

(drawn with an approximate vertical exaggeration 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) 
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4.8.1.1 Feasibility of Selected Scenarios 

Based on the OCS location scenarios identified in Section 4.2, and considering practical 

water depth limitations, nearshore areas of the Beaufort Sea, Chukchi Sea and Norton 

Sound can be considered for the use of a gravel island. Other Bering Sea location 

scenarios are excluded from assessment; however, this does not preclude the use of 

gravel islands in shallow coastal 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 upcoming 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 height selected. However, wave height data found during collection of 

metocean information (Appendix A) were not necessarily reported at consistent water 

depths. Therefore, in an attempt to be consistent, 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 offshore 1/100 year waves may reach upwards of 

29 ft (8.8 m) based on maximum wind and fetch conditions. 

Regarding multi year ice incursion; 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)) 
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Based on the primary design condition for a gravel island (i.e. adequate lateral stability to 

resist ice loads), Norton Sound would be a feasible location for a gravel island. As noted 

below, increased wave conditions can be managed. 

As described previously (Section 4.7.1.1), the nearshore Chukchi Sea ice environment is 

much more dynamic then the Beaufort Sea and, therefore, would require further 

consideration. Also, since no gravel 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 Beaufort Sea gravel island structure 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 might require further 

consideration. 

The preceding assessment was based on a water depth of approximately 33 ft (10 m) and 

considered nearshore areas of Norton Sound and the Chukchi Sea. Considering the use of 

gravel islands for use in OCS up to current limits 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 freeboard and potentially slope side lengths would need to be 

increased. Chukchi Sea considerations would also remain the same, but with increasing 

water depth larger ridges would be encountered, and therefore larger ice loads would be 

expected. 

4.8.2 Constructability 

There are basically two methods of constructing gravel islands: the onshore (hauled) 

method or the offshore (dredged) method. 

The onshore method typically involves excavating 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)” 
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(Cammaert and Muggeridge, 1988). The majority of gravel islands constructed in 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 transporting 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 section (Section 4.7.1.1), the Chukchi Sea has a 

very dynamic ice environment and nearshore “landfast” 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 will 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 the island. The timing and method of pipeline installation 

should be such that interference with island construction and/or facilities installation is 

minimized. 

4.8.3 Capital Costs 

In comparison to other offshore structures, gravel 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 million and $40 million 

exclusive of topsides (US Army Corps of Engineers, 1999). Figure 4-17, included in the ice 

island section (Section 4.7.3), provides gravel island capital cost information based on 

water depth and illustrates the cost differences between ice and gravel islands. 

The most recently proposed use of a gravel island was for the Liberty prospect located in 

the nearshore US Beaufort Sea. The proposed 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 level, the island was estimated at $50 million 

(MMS, 2002). 

In general, the cost of a gravel island is directly 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 65 
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ft (20 m) and greater (US Army Corps of Engineers, 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 the Beaufort Sea through the rehabilitation of 

abandoned gravel islands. This was also put into practice in 2001, when the abandoned 

Seal (exploration) Island was rehabilitated and turned into a production island for the 

Northstar project. 

With regard to the Bering and Chukchi Seas, no cost savings 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 have to be carefully considered. Based on 

the assessment above, one hypothesis can be made regarding cost: gravel islands for 

these areas will likely cost more than an island for the Beaufort 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 Environmental Considerations 

The main environmental considerations associated 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 can help mitigate environmental considerations associated with 

construction are: 

• Minimize facility/island size; 
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• 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 experience the same quality of landfast ice as 

the Beaufort Sea, therefore the ability to mitigate environmental 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 notable operational consideration 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, consideration 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 possibly 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 maintenance/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-specific lease agreements. 

Following decommissioning of a facility, abandonment may fall within a range of activities 

from complete removal of facilities and structure, to basically a shutdown and preservation 

of the facilities for potential future use (US Army Corps of Engineers, 1999). 
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With respect to the structure, complete removal of a gravel island would pose much 

difficulty and many environmental 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 naturally. This method of abandonment has been 

historically acceptable in Alaskan Beaufort. 

4.9 Floating Structures 

There are only a limited number of floating exploration or production structures that have 

been used in ice environments. This Section of the report addresses the types of floating 

structures that might possibly be considered for exploration drilling and/or production 

development. Topsides are not included in this analysis, except in consideration of the 

requirement of the floating structure 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 Canadian Arctic in the 1980’s, floating vessels (drillships) were 

used successfully with the support of icebreaking ships for ice management. In particular, 

the Kulluk, a round drilling barge purpose built by Gulf Oil to the Arctic Class IV 

specification, roughly equivalent to the modern IACS Polar Class PC4, operated in the 

Canadian Beaufort Sea. This vessel could operate through the open water season until 

early December (at the latest) with intensive ice management support. The Kulluk has 

recently been refurbished for exploration activities in the Alaskan OCS. 

Historically, on the Grand Banks of Newfoundland, FPSOs (Floating Production, Storage 

and Offloading) have been the choice of floating production vessels under potential sea ice 

(first-year) and iceberg conditions. The hulls of both of the Grand Banks FPSOs (Terra 

Nova and White Rose) are designed to continue operations 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 have 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 the Beaufort or Chukchi Seas. In heavy pack 

conditions, or in the event of the approach of an unmanageable iceberg, the FPSOs are 

designed to disconnect from their moorings and an emergency disconnect can be effected 

in approximately 15 minutes. No continuous ice management support is required. 
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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 production systems for the Beaufort and 

Chukchi Seas are currently not technically feasible, even with 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 and 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 and scantlings of the 

vessel must be chosen to handle ice loads. Any vessel will also need a mooring foundation 

design capable of handling environmental loads. Moored floating 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-year ice conditions (Bohai Bay). 

4.9.1 Technical Feasibility 

Seasonal exploration can be carried out using drillships and drilling barges and, in areas 

without multi-year ice, semi-submersibles or a TLP. However, for exploration, the only 

location that a floating structure 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 (Figure 3-38) could work year-round under first-year ice conditions (loads 

~ 22,000 tons (~ 20,000 tonnes)), but would need 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-year ice loads found 

in the Beaufort and Chukchi Seas, and possibly northern Bering 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, under light ice conditions, a floating structure might be feasible. 

However, additional information/data would be needed to fully assess the feasibility. Ice 

conditions in the Grand Banks are roughly analogous to operating conditions that 
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predominate in the Bering Sea, particularly south of approximately 57° north latitude. North 

of 57°, pack concentrations tend to be greater 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 which would need to be considered.

4.9.1.1 Ice Loads 

In sub-arctic climates, with respect to managing ice loads, there are three approaches to 

the design and operation of a floating production structure in ice covered water: passive, 

semi-active and active (Makrygiannis et al., 2006). 

The passive approach is to design the system to withstand interaction with all anticipated 

ice conditions (and other ice conditions). The semi-active approach is to design the system 

to withstand most environmental conditions, but also design the facility to leave station in 

anticipation of environmental events beyond the design capabilities of the system. An 

active approach would, as with the semi-active approach, utilize a floating structure that 

could move off station if environmental conditions dictated. However, to modify and control 

the operating environment, an active program of ice management is undertaken. Ice 

management involves the use of ice capable ships to break-up ambient ice conditions into 

small pans or rubble, or by means of towing, divert large ice features from the operating 

area. 

In the Beaufort and Chukchi Seas, the design load event (~85,000 to 110,000 tons 

(~75,000 to 100,000 tonnes)) for a production structure would be the result of an interaction 

with a multi-year ice feature similar 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) thick floe traveling at 0.8 ft/s (0.25 m/s) 

over a contact width of 330 ft (100 m); 

• Sustained load from a multi-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 techniques used to bring the loads down to an acceptable 
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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 platform will need to remain off station until ice 

conditions improve sufficiently for reconnection (this might possibly be until the spring 

season). As an example, this approach is used in Sakhalin for offloading, where the 

offloading buoy (SALM) remains in operation 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 are suspended until the spring. 

In the southern part of the Alaskan OCS, where only first-year sea ice is present, the most 

important criteria for ice loading is the pack concentration (typically expressed as the ratio 

of ice to open water in tenths). At pack concentrations of less than 8 tenths, the ice loads 

are typically 50% or less of the loads at 10 tenths (note that 10 tenths 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 less than 8 tenths contain 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 contained in the pack). In pack or managed ice, the loads are 

also largely independent of the drift speed of the ice (Comfort et al., 2001). These 

conclusions have been drawn from a wide range of model test data, with limited validation 

from operational experience. Figure 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 structure operating in unmanaged continuous 

heavy ice conditions, but a wide range of model test experiments 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 thickness and drift speed become important 

factors in the ice loading in unmanaged ice, primarily due the 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 sizes if ice jams in 

between the legs of the structure. 

Another significant potential issue 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 interacts with the structure. If 
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ice is forced under the structure, interaction with the mooring and riser systems might be 

problematic. 

4.9.1.2 Wave Loads 

The 100 year return wave conditions for the areas of study are shown below in Figure 4-24. 

It can be generalized that the intensity of the design wave condition 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 waterplane area (and therefore 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, Figure 4-25 illustrates approximate design wave loads for a 

214,000 ton (194,000 tonne) (displacement) FPSO 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. 
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Figure 4-23: Peak Loads in Managed Ice - Effect of Ice Concentration on Various Structure 

Types (Reproduced from Comfort et al., 2001) 
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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 Banks

Beaufort Chukchi Bering

North

Atlantic

Geographic Location

Significant Wave Height (m) or Peak Period (s)

Significant Wave Height Spectral Peak Period

Figure 4-24: 100 year Return Wave Conditions in Area of Study; Grand Banks added for 

Comparison 
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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 Banks

BeaufortChukchi Bering

North

Atlantic

Geographic Location

Design Mooring Load (MN)

Figure 4-25: Approximate Design Wave Loads - FPSO Basis (Note: 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 platforms in marginal ice areas, e.g., Terra 

Nova on the Grand Banks. 

The dynamic positioning systems installed in deepwater exploration vessels require 

significant thrust availability for sea-keeping 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. 
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As a example of the technical (if not perhaps economic) feasibility 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) thick (Keinonen et al., 2006). 

4.9.1.4 Mooring 

Modern mooring systems can provide extremely robust anchoring systems for floating 

structures. In most areas of application, mooring systems for floating structures are 

governed by wave loading. 

In the Beaufort and Chukchi Seas, unfactored loads from first-year ice will be on the order 

of 45,000 kips (200 MN) (on a fixed structure) while unfactored 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 the 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 mooring force for a selection of FPSOs and drillships is 

plotted1 in Figure 4-26 with two icebreaking ships2 to provide a comparison. The thrust or 

mooring system resistance available from such vessels is considerably 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 ship break-power, with the assumption of approximately 

0.026 tonnes of thrust per kW break-power.
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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 Fox

Moored FPSOs

Moored

Drillships

Ice

Breakers

Thrust or Mooring Force (MN)

Figure 4-26: Rough Comparison of selected Vessel Mooring Systems; with selected Ice 

Breaker Bollard Thrust for comparison (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 regulators with the material and its performance in ice from the 

experience with ice breaking ships. 

Concrete has been proposed as a construction 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 the design and uncertainty of 

fabrication methods and costs (Husky, 2001); however, a concrete spar design is believed 

to be among design options considered for the development of the Shtokman Field in the 

Barents Sea. 
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4.9.1.6 Seismic 

Moored floating structures are not generally critically affected 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 respond with large motions, 

and so these pressure waves will not constitute a design condition. There may be some 

foundation considerations with respect to seismic events. 

Seismic event induced waves (tsunami) offshore are of low amplitude and long wavelength, 

and again will not induce significant motions or loads of a moored 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 production facilities typically do not have integral storage 

and would require a pipeline connection for export. An FSO or direct loading of shuttle 

tanker can be used with a floating production platform without integral 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 those presented in the following paragraphs. Their 

applicability for use in the Alaskan OCS would depend on whether or not the structure was 

permanent or temporary, ice environment, water depth, etc. and would have to be 

evaluated during any detailed assessment. However, floating 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 the 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. 
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Drilling Barges can be designed to be insensitive to the direction of environmental loading 

and can therefore use a conventional mooring arrangement. 

Semi-submersibles will, like drillships, use mooring 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 anything but very light ice conditions, there is 

the possibility of ice jamming in between the structure’s legs, thus creating the 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 offloading to tankers. 

Tension Leg Platforms (TLP’s) use taut moorings to maintain station and can be round or 

conical in shape as to be insensitive to the direction 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 year-round production and 

storage platform. 

Floating Production Storage and Offloading (FPSO) platforms will typically be turret 

moored to allow the vessel to weather-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 structure that allows the FPSO to weather-vane, and provides the 

connections from the production platform to the wells. This design requires that the yoke 

penetrate the water’s surface, requiring that the yoke structure be capable of breaking ice. 

This system has been used in Bohai 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 floating structures for seasonal 

exploration, year round exploration and production in the Alaskan OCS areas of study. 
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Floating structures have been and will continue to be used for seasonal exploration. A 

floating structure will likely be only able to carry out year round exploration operations in the 

south Bering Sea under light ice conditions. However, a Semi-rigid Floater type structure 

that can handle a design ice load of 22,000 tons (20,000 tonnes) could be considered for 

year-round exploration. Based on current technology, no floating type structures could 

operate as a production structure in the most of the Alaskan 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 N1

 N 

Chukchi Sea Y N1

 N 

North Bering Y N1

 N 

South Bering Y P1, 2 P2

 

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 options would be the potential interaction of ice 

with the risers and mooring system as ice moves around and under the floating structure. 

4.9.2 Exploration Operability 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 Beaufort Sea, drilling operations in water depths of 

200 to 655 ft (60 to 200 m) using conventional technology 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 equipped and constructed vessels are required 

as well. Statistical wave data from the area suggests that there are no extreme wave 

induced motions to contend with, such as would 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. 
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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 due to infrequent use or outdated drilling packages, these rig 

designs offer some protection from ice crush 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 Chukchi 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 equipped and constructed vessels are required 

as well. It is apparent from statistical wind/wave data that the Chukchi Sea has more 

extreme wave conditions, potentially making a “Kulluk-like” drilling unit unsuitable for this 

area. Therefore, an ice class drillship would likely be the most suitable to utilize for drilling 

operations. A semi-submersible, due to its superior motion characteristics compared to a 

drillship, could also be a suitable 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 Bering 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 approximately 8 months of the 

year. This being the case, these areas are more favorable for 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 area. 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), with potential for occasional 

occurrences higher than this. Historical data shows drilling activity in the Navarin Bay and 

St. George Basin with semi-submersibles with the earliest spud in August and latest end in 

March. The extreme winds in the area of approximately 110 knots maximum precludes use 
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of drillships if an extended drilling 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-round drilling activity has taken 

place in comparable conditions – the Grand Banks off Newfoundland. 

The Norton Basin has had drilling activity in the past in shallower 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 expected 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 providing minimum resistance 

to passing through the ice. 

The new IACS Unified Requirements 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 the topsides units, and tow out of the assembled 

unit. Spar structures, due to their extreme draft, are normally 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 potential development costs, the preproduction 

development costs of the two FPSO developments on the Grand Banks are presented in 

Table 4-15. Also presented are 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 Engineering, 2005) intended for exploration in arctic 

waters (Section 3.2.2.6). 
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Table 4-15: Project Capital Costs for Selected 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. Semi-rigid Floater 2005 n/a 500 

4.9.5 Environmental 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 installation 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, tracking 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 challenge 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 developments have been made recently 

in developing evacuation systems, much development is still required in this field. 

4.9.7 Abandonment & Decommissioning 

Decommissioning of production platforms in the North Sea has resulted in legislated 

requirements for the platforms to be decommissioned as opposed to abandoned. Although 

many of the North Sea platforms were intended to be disposed of at sea (or left in place in 
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the case of fixed structures), regulators have virtually banned this practice and have 

required the removal of the floating structure for reuse or to be salvaged in other ways. For 

example, the Brent Spar in the North Sea was (with regulatory approval from UK 

authorities) to be sunk offshore, but public out-cry resulted in the platform being used as a 

ferry terminal. 

Any development will most likely require 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 requirement for an island/platform offshore. If the 

wellhead is located in water of sufficient depth, protection from ice would not be necessary. 

This was the case for the Drake PanArctic project in the 1970’s, where 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 ft (45 m) deep in that area. 

In areas with water depths less than 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 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 protection from gouging keels. Where active ridge building is taking 

place (around 65 ft (20 m) water depth), there is the potential for a ridge to be pushed into 

an open glory hole. Further site-specific analysis would be required to determine the 

appropriate water depths between which this 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 resources in harsh and remote environments. As a result of these 

improvements, fields requiring 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 reached 40 miles (65 km) (Shell Expro “Penguin”). 
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Subsea processing could offer advantages to Arctic development due to potential distance 

between wellsites, the harsh environmental conditions and water depths further offshore. 

Subsea processing has primarily evolved around the development of: subsea booster 

pumps, subsea compressors, subsea separators 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 and installation 

of the subsea equipment. Depending on the development, water depth, tieback distance 

and landfall location will vary. Technology has been developed (and continues to be 

progressed) which allows for separation and disposal of produced water subsea. This helps 

reduce flow assurance issues associated with pipelines and flowlines, as well as minimizing 

above water or onshore facilities. However, facilities still may be required to allow for the 

injection of hydrate inhibitors into the subsea facilities/pipelines/flowlines. 

One of the most notable subsea 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 project will flow 2.5 Bcf/day (70 million m3/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 subsea compression station into 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 protection of subsea facilities in 

the Alaskan OCS, although secondary factors may come into play such as 

operational/maintenance issues or protection from fishing equipment, ship anchors, etc. 

The type and degree of protection is usually determined through a site-specific risk 

assessment, which involves understanding the probability of ice incursion and the 

consequences should an impact occur. 

Glory holes (Figure 4-27) are excavations in the seafloor into which subsea facilities can be 

installed for protection from scouring 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. 
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Two existing projects use open glory holes to protect wellheads and associated subsea 

equipment from iceberg keel impact. These are the Terra Nova and White Rose projects 

located on the Grand Banks (Canadian east coast) where, to date, glory hole excavation 

has been the preferred method of subsea facilities protection. 

The White Rose project uses three glory holes in water depths ranging from 395 to 410 ft 

(120 to 125 m), whereas the Terra 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 considered for the Canadian east coast including 

cased glory holes, soil/rock berms and concrete structures. However, open glory holes 

have been identified as the optimum solution for protecting subsea facilities from gouging 

iceberg keels in this region (Offshore Magazine, 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 interaction with subsea facilities in the 

Alaskan OCS was beyond the scope of this study, but the following options would likely be 

considered: 

• Do nothing, i.e., the risk analysis may suggest that discrete subsea facilities 

(not pipelines) placed directly on the seafloor, with no additional protection, 

will be acceptable (dependant on water depth); 

• Reduce the probability of ice keel impact by placing subsea facilities in a glory 

hole, such as on the Grand Banks; and 

• Reduce the probability (and/or consequences) of ice impact through some 

sort of additional mechanical protection of the subsea facilities. 

The use of other methods, such as cased glory 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. 
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The robust “ice lid” provides protection of the subsea facilities from the scouring ice above. 

This system has potential for the Canadian Beaufort 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 ridge 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 install this system anyway and in deeper water 

(100 ft (30 m) plus maybe) the glory hole alone may provide sufficient protection from ice 

keels. Again, for small footprint subsea facilities (< 33 ft or 10 m diameter), a backfilled 

caisson may offer some protection against fishing equipment or undue silting-in of the glory 

hole, but for larger footprints (> 100 ft or 30 m), glory hole excavation alone may be the 

preferred method (depending on water depth). 

4.10.1.3 Feasibility of Application of Subsea Technology at Location Scenarios 

The use of subsea production facilities 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 technology 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 located 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 chosen, 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 shore or a platform in shallower 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. 
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Figure 4-27: Glory Hole (From Coflexip Stena, 2000) 

Figure 4-28: Mechanical Subsea Facilities Protection Concept for Water Depths to 30 m in 

the Canadian Beaufort Sea
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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 less than 65 ft (30 m), the use of subsea to 

beach or subsea tiebacks might be considered. However, this is in a region of grounded ice 

and ridge building. Therefore, a cover would likely be required to protect the facilities from 

ice keels entering the glory holes. 

Open glory hole concepts may be sufficient in areas with greater than 100 ft (30 m) and 

less than 200 ft (60 m) water depth 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 possible to put the subsea 

facilities directly on the seafloor. 

Deeper water location scenarios will likely require 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 platform. Recent records were approximately 30 

miles (50 km) for oil and 100 miles (160 km) for gas. Therefore, some of the location 

scenarios will require additional technological development or facilities for distances greater 

than these. 

In all cases, the overall depth of the glory hole (where used) and the requirement for tie 

back flowline burial would need to be determined through appropriate risk analyses. 
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4.10.2 Constructability 

Installation of subsea equipment will require a number of dedicated vessels for the 

installation activities, as well as ice management 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 vessels would be required for 

ice management, survey, support, supply, etc. All would be required to be suitable for Arctic 

work. 

Flowlines between subsea facilities, to a platform 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. Geotechnical and geophysical information would need to be obtained 

to support an excavation. The mix and strength of soils can vary within a single excavation 

and the presence of boulders, cobbles, etc., will be difficult to identify before the start of 

excavation. 

Equipment capable of digging glory holes will depend on water depth 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 that 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 beach projects can be put in perspective by looking at some 

of the large subsea projects including Tordis, Snøhvit and Ormen Lange. Costs associated 

with wells, subsea booster pumps, subsea compression, subsea separation and subsea 

gas dewpointing and dehydration may need to be considered. 

The selection of excavation equipment will depend on a number of variables including 

R&D/field trials of selected equipment, schedule, weather, presence of ice during 

construction, availability of equipment that is Jones Act compliant and required upgrades to 

equipment to work in an Arctic environment. 
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Excavation costs using a floating dredge can be estimated based on a current cost of 

$250,000 for a large dredger, plus mobilization/demobilization 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 constructed for around $2 to $3 

million USD and larger caissons for up to $30 million USD (excluding costs to backfill). At 

this cost, caissons could be attractive for operational/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 depth in areas subjected to ice gouging. The 

overall size and depth of the glory hole will be a function of the 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 will 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 sediment 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 hydrocarbons 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 inhibition will need to be considered 

which may require an inhibitor injection and recovery system be installed on the 

platform/island or onshore. 

Asset integrity management, scheduled maintenance and asset reviews will be an 

important aspect of the operation of subsea facilities. Subsea systems will require that 

periodic inspection, maintenance and repair activities be carried out which will require the 
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deployment of working and support vessels. Ice management capabilities may be required 

to support these activities. An ROV or divers may also be deployed to accomplish these 

tasks. Having critical spares on hand will also need to be considered given the remoteness 

of the region. 

An important aspect of the use of subsea facilities 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 intervention 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 challenges will be equipment and personnel logistics. 

4.10.6 Abandonment & Decommissioning 

Decommissioning procedures for offshore installations that have reached the end of their 

useful life are usually included in governing legislation. There are also international 

agreements relating to decommissioning that address removal and deep-sea disposal. For 

example, the International Maritime Organization (IMO) has developed Guidelines and 

Standards for the removal of Offshore Installations and sets out conditions to protect 

navigation and maintain safety. 

Some general requirements in other jurisdictions with regards to decommissioning include 

designing all subsea facilities such that, upon termination of production, they will be 

capable of being covered or removed so that the area is returned to a fishable condition. 

This may require that glory holes be filled in after the completion of a project. Based on 

these requirements, decommissioning will likely be an important consideration 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, maintenance and repair which 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 limits to developments 

further offshore in deeper water will require additional consideration be given to some of 

these aspects. 
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4.11.1 Technical Feasibility 

4.11.1.1 Design Issues 

Surveys & Data Collection

It is accepted that a certain amount of data will need to be collected in support of arctic 

offshore pipeline design and construction planning; 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 / Laboratory Testing (including permafrost 

testing); 

• Sediment Transport Studies; 

• Detailed Shore Crossing Survey and Evaluation of Shoreline Erosion; 

• Ice Surveys. 

Several years of data might be expected to support pipeline design and construction 

planning. It should be considered that data collection efforts may be hampered by ice or 

lack thereof in any particular year and that several seasons may be required to successfully 

gather all the data necessary for design and construction planning. 

Geotechnical Conditions

Geotechnical information (field and laboratory) needs to be collected and analyzed to 

determine soil properties which will be used in design and the evaluation of potential thaw 

settlement. The results of the geotechnical testing/analysis, along with the pipeline design 

analyses, can also be used to determine or confirm trenching and backfilling requirements, 

thaw settlement or frost heave. 
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Pipeline Routing

Given the cost of arctic offshore pipelines, potential routing of offshore arctic pipelines is 

primarily evaluated based on minimizing length of pipeline and minimizing the potential 

loading from environmental conditions. Also of significant importance is minimizing the 

impact on the environment and maximizing use of existing infrastructure. 

Metocean Conditions

The characteristics of the Arctic environment include ice-free summer ocean conditions 

during which waves and currents achieve their 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 large expanses of open water 

generally do not exist, thereby precluding wave generation. 

Meteorological factors important to the design and construction of the arctic facilities 

include wind, temperature, precipitation, barometric pressure and visibility. Ocean currents 

are normally of secondary importance, as other loadings will likely govern. However, 

currents can cause seabed erosion which could expose the pipeline or affect its stability. 

Water level fluctuations caused by tides, storm surge, winds, etc. must be considered in 

pipeline design. Waves must be considered in various aspects of the pipeline design, most 

notably sediment transport and pipeline stability. 

All of these factors must be considered when evaluating constructability as they can create 

potential operational difficulties during periods of offshore summer construction, marine 

vessel transport, maneuvering and docking. 

Ice can be characterized as landfast ice, the transition or shear zone, seasonal pack ice, 

first-year and multi-year pressure ridges, ice islands and icebergs. In the Arctic, heavy ice 

ridging typically happens at the 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 pipelines would need to be trenched to some 

depth below the seabed to protect the pipeline from the effects of pressure ridge ice or 

iceberg keels. Gouging of the seafloor is a nearshore feature for most northern continents 
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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 may 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 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 

soil movement can impose forces on the buried pipeline and result in deformation. The 

configuration of the pipeline after gouging, and hence the strain in the pipeline, depends on 

the pipeline properties, the soil characteristics, the depth of the design ice gouge and the 

depth of the pipeline below the undisturbed seabed surface. 

The pipe must be trenched sufficiently beneath the influence zone of soil displaced below 

the ice keel to limit pipeline strains to within acceptable limits. Analyses must be carried out 

to understand the soil displacements 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 Deformation
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Geophysical surveys of the seabed are conducted 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 the gouge orientation. 

Gouges on the seabed are altered by other gouge occurrences, sedimentation (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 implications of ice 

gouging, would need to be appropriately accounted for in design. 

Thaw Settlement & Frost Heave

In arctic areas, permafrost can be found through 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 surface erosion onshore at shore crossings. 

Differential settlement or frost heave is possible along a pipeline route due the fact that soil 

conditions or permafrost may not be continuous and uniform and the pipeline is not at a 

constant temperature along its length. 

Analyses can be carried out to predict the thaw bulb extent, the thaw strain potential of the 

permafrost and the strains imposed on the pipeline. There are a number of ways to deal 

with the issue of thaw settlement, including incorporation of mitigative measures, avoiding 

excessive thawing by insulating the pipeline and designing the pipeline to take the strains. 

If a pipeline is operated at a temperature lower than the freeze point of the surrounding 

soil’s pore fluid, then the soil surrounding the pipeline could freeze, potentially subjecting 

the pipeline to frost heave. Alternatively, even if the pipeline were not operated below 

freezing, the active layer of the soil surrounding the pipeline could freeze, forming ice and 

pushing the soil surface upward. Analytical and numerical tools can be used to determine 

the behavior of pipelines undergoing frost heave in discontinuous environments. 

Upheaval Buckling & Thermal Expansion

When a buried steel pipeline is operated at a temperature (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 restraint provided by the surrounding 

soil, and thus will develop a locked-in axial compressive force. If the buried pipeline has 

some residual vertical curvature, possibly due to trench bottom irregularities during 
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installation, the effect of the axial force near the high points of these trench irregularities will 

attempt to buckle the pipeline upward at these locations. If the upward force exceeds the 

downward force, then the pipeline will move upward and may 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, pipelines in such environments are 

normally installed at lower ambient temperatures and therefore will experience a larger 

temperature change when operating under steady state conditions. 

The immediate effect of upheaval buckling for arctic offshore pipelines is that the pipeline 

could become exposed at the seabed, which increases the risk of impact by ice keels. 

Problems associated with upheaval buckling may include high bending stresses and loss of 

protective soil cover but may not directly cause a leak or exceed other limit states. 

However, upheaval buckling is a limit state that is an undesired condition 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 imperfection) 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 the installation and operating temperatures 

experienced in arctic regions will also result in larger potential 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. 
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Figure 4-30: Subsea Pipeline Upheaval Buckling (After Palmer et al., 1990) 

Strudel Scour

Nearshore arctic zones typically develop a bottomfast ice sheet during the winter season. If 

an onshore river flow encounters such an area during the spring breakup, the river water 

will overflow the bottom-fast ice sheet in the nearshore zone. This overflow water will 

spread offshore and drain through tidal and thermal cracks or seal breathing holes in the 

ice sheet. High velocity currents caused by the 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 alignment, there is the possibility that the 

scour could result in an unacceptable pipeline span. In extreme conditions, the pipeline 

span could possibly experience vortex-induced vibration (VIV) due to the water velocity of 

the strudel flow. An analysis to assess the pipeline span can be carried out using analytical 

or finite element methods. 
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Figure 4-31: Strudel Scour (Courtesy of Minerals Management Service) 

Ice Ride-Up, Grounding, Pounding & Wallowing

Sheet ice at the coastline can be driven ashore and ride up onto the beach. Shoreline pileup can also occur, created by the rafting/stacking of the failed ice blocks onto each other. 

The design of a buried offshore pipeline which transitions to an aboveground pipeline 

should account for the setback distance as the result of ice encroachment. 

Ice keels can be driven ashore and become grounded over a pipeline or rubble piles can 

form in place over a pipeline. “Ice pounding” refers 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 grounded ice features due to 

current flow disturbances and wave-induced motion of the ice feature displacing water and 

sediment. These potential loading scenarios should be considered during pipeline design. 
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Shoreline Erosion & Sediment Transport

Shoreline erosion must be considered in the determination of the setback distance of the 

point where a buried offshore pipeline transitions to an aboveground pipeline. Average 

long-term shoreline erosion rate, as well as the maximum short-term 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 depth has been increased or it may become 

susceptible to upheaval buckling. In extreme cases, the pipeline could 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 should consider the long-term stability of the 

seabed/backfill. 

Trenching & Backfill

Design issues related to ice gouging, strudel scour, frost heave / thaw settlement, upheaval 

buckling and sediment transport will determine pipeline 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-frozen) excavated from the trench. 

When native soil is used as backfill, it will be remolded and will be a composite blend of 

different materials excavated between 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. Select backfill, gravel, gravel filled bags or concrete mats 

may be considered in predetermined locations where native backfill is not adequate. 

Limit State & Probabilistic Design

Offshore arctic pipelines, which rely on trenching and backfilling for protection, need to be 

deep enough to withstand environmental 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. 
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Limit state design is an approach whereby the various potential failure mechanisms are 

evaluated. The pipeline failure mechanism that has the lowest initiation strain is then 

selected as the governing condition and will dictate the design strain. Limit state strain 

criteria can be used in the design for non-cyclic pipeline displacements, e.g., thaw 

settlement, subgouge soil deformation and island settlement). It is apparent that if the 

pipeline strain can exceed that allowed by a stress-based design, 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 procedures can be used to optimize pipeline design. Elements 

of this type of design could include, for example, 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 subsea valves and fittings and a well-planned 

inspection program minimize the potential for offshore pipeline leaks in the Arctic. Small 

leaks, however unlikely, which might normally be detectable on the open water surface 

during personnel/supply transport to and from the island/platform, could go undetected for 

several months under ice cover. Therefore, it might be expected that 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 may 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 regional requirements. 

Pipeline / Flowline Architecture

The pipeline/flowline configuration 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 pipeline design in the Arctic are strudel scour, 

thaw settlement of permafrost, upheaval buckling and ice gouging. 
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The first two design issues happen over very limited distances of the nearshore portion of 

the pipeline and have been addressed in existing pipeline design, e.g. Northstar and 

Oooguruk. The third issue, upheaval buckling, can happen in any region of the pipeline if 

conditions are conducive to buckling. Installation procedures have been implemented on 

past projects (Northstar) to minimize the risk of upheaval buckling (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 report, a number of site-specific strudel scour surveys have been 

conducted for and in the vicinity of the Northstar Project (see, for example, Coastal 

Frontiers Corporation, 1999). Span analysis indicated that the pipeline remained elastic and 

within design code limits in the case of a strudel scour event that exposed the pipeline. The 

potential for vortex-induced vibrations of the Northstar bundle when exposed to a current jet 

resulting from the strudel was also evaluated and found to be nonexistent. 

The change in strudel scour regime after startup of operations has been investigated by 

Leidersdorf et al. (2006). 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. Circular scours up to 14 ft (4.3 m) deep and up to 105 ft (32 m) in 

diameter were recorded in the Northstar area. The maximum linear scour was 276 ft (84 

m), but this scour only had a depth of 1.6 ft (0.5 m). Maximum scour depths were found in 

the 6.5 to 13 ft (2 to 4 m) water depth range. The potential cause of the increase in the 

frequency of scour formation over the pipelines may be the local thinning of the ice sheet 

above a buried warm pipeline in shallow water 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 potentially be subject to strudel scour 

(depending on proximity to rivers and the overflood 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 along the pipeline route, can result in 

differential thaw settlement which could subject the pipeline to high strains. On the 
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Northstar project, the maximum thaw induced 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 limit 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 scenarios could potentially pass through 

zones of ice bonded permafrost. Using the Northstar pipeline as an example, differential 

settlement up to a certain magnitude can be accommodated in design and operations. If 

the differential settlement is beyond a certain 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 considered in conceptual pipeline design for 

decades. A number of buried offshore pipelines are being successfully operated in ice 

gouge environments, including projects in the Alaskan OCS (Northstar, Oooguruk). 

Trench depths will increase in areas of more severe 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 the 65 to 130 ft (20 to 40 m) water depth range, 

ice gouging might be the most significant and result in the deepest burial. In deeper waters, 

the gouge depths begin to taper off, as do the burial depth requirements. Offshore pipelines 

will be required to be trenched to approximately 165 ft (50 m) water depth in areas 

subjected to ice gouging. 

Ice gouging is only one factor in the overall determination of burial depth and must be 

examined in conjunction with other factors such as thaw settlement, upheaval buckling, 

strudel scour, pipeline stability and flow assurance. However, as mentioned above, these 

other aspects can likely be accommodated, given successful operation of projects in the 

shallow waters of the Beaufort. The ice gouging issue warrants further discussion (below). 

Ice gouge depth distributions can be estimated using ice gouge data, e.g. depths and 

widths. Annual ice gouge recurrence rates can also be estimated where repetitive mapping 

surveys have been carried out. If repetitive mapping survey data is not available, the age of 

gouges cannot be determined and data may not accurately represent the current ice gouge 

regime. The same can be said for the location from which data is used. If site-specific data 
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is not available, the use of ice gouge data from other regions may not accurately reflect the 

conditions at the area of interest. 

However, in an initial screening study where there might not be adequate site-specific data, 

insight may be gained by looking at regional ice gouge datasets. Unfortunately, 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 gouge data available in public domain study/survey 

reports from the Beaufort, Chukchi and Bering 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 available, 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 occurring beyond the 65 ft (20 m) 

isobar. Analysis of ice gouge width/depth relationships and distributions from the study 

areas has indicated a general trend of decreasing gouge width with increasing gouge 

depth. 

Beaufort Sea 

Summary plots of ice gouge depth vs. water depth for combined known and unknown age 

data and known age gouge data only are presented 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). 
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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 Depth, 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 comparable to what it is today. Based on this 

information, gouges up to 18 ft (5.5 m) deep 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 significantly 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 limited to less than approximately 80 ft (25 m) 

water depth. Of the data available, gouge depths are generally less than 5 ft (1.5 m). 

Pipeline burial depth for this area (any of the location scenarios) would be a function of not 

only gouge statistics, but also design return period, pipeline geometry, line pipe 
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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 shelf 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. water depth data for gouge 

observances in the Chukchi Sea. 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 (40 
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m) water depth. After this point, ice gouge depth decreases with increasing water depth to 

near zero at 200 ft (60 m) water depth. Pipeline 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 Depth, 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 Bering 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 shore-perpendicular and vary in gouge trajectory. Ice gouges are 
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observed in the northeastern Bering Sea in water depths ranging from 16 to 100 ft (5 to 30 

m) (Thor and Nelson, n.d.). 

Various ice gouge features have also been identified in Norton Sound of the eastern Bering 

Sea, including single, ice island and pressure ridge raking (multiplet) gouges. Single-keeled 

(solitary) ice gouges have been observed to ubiquitously dominate within Norton Sound, 

where gouge depths are reported to a maximum of 2.5 ft (0.75 m) deep (Thor et al., 1977). 

Single-keeled ice gouge widths have been observed 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 range from 165 ft (50 m) to several kilometers wide (Thor et 

al., 1977). The maximum density of ice gouges occurs in central Norton Sound near the 

Yukon Delta in water depths ranging from 33 to 50 ft (10 to 15 m) (Thor et al., 1977; Thor 

and Nelson, n.d.). Ice gouge densities of up to 195 gouges/mile2 (75 gouges/km2) have 

been observed near the Yukon Delta. Little ice gouging is observed in water depths less 

than 33 ft (10 m) or greater than 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 function 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 requirements for summer and winter construction 

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. 

Winter construction is primarily affected by the ice environment. Construction cannot 

commence until the ice is of sufficient thickness and stability to support the weight of the 

equipment required to begin ice thickening. Ice ridges within the ice sheet could also affect 

construction. However, winter construction eliminates 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. 
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During an open-water construction scenario, activities and their timing may be primarily 

affected by considerations for environmental protection 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 restricted 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, consideration also needs to be given to the Jones 

Act or Coastwise Laws and potential requirements for US owned, operated and flagged 

vessels for the Alaskan offshore. This law could significantly influence decisions regarding 

the preferred construction scenario for projects off of Alaska. 

4.11.2.2 Permafrost & Trenchability 

The general assumption is that Arctic offshore pipelines will need to be trenched for 

protection and seabed trench excavation will be a critical activity for the pipeline installation 

schedule. Given the nature of the arctic environment, there is a possibility that permafrost 

could be encountered during trenching, regardless if a summer trenching or winter 

trenching program is planned. Either way, the trenching technique must be capable of 

trenching through permafrost. 

Soil conditions must be considered when evaluating trenching options to come up with the 

most cost effective trenching spread configuration. The presence of high strength silts and 

clays or dense sands will affect trenching production rates. It is important that the trench 

remains open until the pipeline is placed in the trench, regardless of whether winter or 

summer construction is carried out. 

4.11.2.3 Trenching Equipment 

Trenching equipment must be compatible with arctic conditions. The equipment must be 

robust and able to operate in a summer or winter arctic environment, depending on the 

execution plan, and able to create a suitable trench profile in site-specific soil conditions. 

Ice-based excavation could be carried out using hydraulic backhoes, clamshell buckets or 

similar methods. Conventional excavation is a proven but time-consuming method. The 
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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 permafrost may be encountered. 

Most of the excavated trench soil would need to be temporarily stored on the ice before 

backfilling. The material excavated from floating ice would be trucked off and stored 

temporarily on bottomfast ice in a designated area. If stored on floating ice, consideration 

must be given to sinking or creep (deflection) of the ice. Once a section of the pipeline is 

installed in the trench, and its profile verified, backfilling using recently excavated trench 

spoils would commence. 

Generally, floating trenching equipment has not been designed 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 which does not come in direct contact with 

floating equipment could still affect construction if the ice were to come in contact with 

anchor lines. The need for ice management vessels in support of trenching 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 the 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 depth limitation of approximately 115 ft (35 m), 

while a large trailer suction hopper dredge could reach to approximately 460 ft (140 m). 

Protection of the installed pipeline could be provided by pre- or post-trenching techniques. 

However, pre-trenching or post-trenching immediately following installation would most 
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likely be required for arctic conditions, since the pipeline would otherwise rest on the 

seabed and be potentially exposed to the action of ice moving into the area. 

Historically, plows (Figure 4-35) have achieved 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 trench depth of 6.6 ft (2 m) if the soils are soft enough to allow 

plowing but strong enough to remain stable until the pipeline 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 full-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 large; 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 these 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 consideration may need to be given to areas where ice-rich or 

bonded permafrost may be encountered. 

Figure 4-35: Typical Subsea Plow (Courtesy of SMD Hydrovision, 2007) 
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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 liquefy the soil, and air is used to lift it from 

under the pipeline. The pipeline lowers 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 times, thereby increasing the risk of damage to 

the pipeline. Due to the very large fluidized sediment load created, environmental concerns 

may be a significant issue. Another issue with jetting is the management 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 requirements, soil may need to be barged in to backfill the pipeline. 

Figure 4-36: Typical Jet Sled (Courtesy SMD Hydrovision, 2007) 

Mechanical trenching is commonly used for burying cables and umbilicals, and has been 

used on multiple pipeline trenching projects. Typically, 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 requirements make these trenchers very large, 

often requiring large buoyancy tanks to keep the trencher from sinking into the soil and 

collapsing the trench, and to facilitate handling of the machine. 
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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 the 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 construction is planned. Similar 

general considerations apply as noted for trenching equipment operations. 

Winter construction using a through-ice method 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 pipeline installation. Backhoes are 

used universally for land and marine trenching within the limits of their capabilities. A 

potential disadvantage is that floating 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 approximately 50 ft (15 m). 
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During installation, the pipe is welded together into a continuous pipe string, either onshore 

or along the ice slot. If strings are made up onshore or in the nearshore, after they are 

welded they are towed over the ice and positioned alongside the ice slot. Tie-in welds 

would be made to join the pipeline strings together 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 exclusively been designed for ice-free operation. 

Floating vessels used for installation or in support 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 subject 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 vessel 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 placement of backfill material in the trench and 

over the pipe may be required. This is a normal activity associated with pipeline 

construction and typically returns the trench excavation spoils back into the pipeline trench. 

In a winter construction scenario, where the trench 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 practical after installation, which 

minimizes the amount of time the spoils are exposed to freezing temperatures. Frozen 

spoils create some challenges for construction as they may not spread easily over the 

pipeline trench cross-section or large pieces of frozen spoil may damage the pipeline. 

In the simplest cases, the soil from the trench 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 conventional excavation or a trailing-suction hopper 

dredge, the excavated material can be stored and reclaimed for backfill. However, the use 
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of a cutter suction dredge for digging the trench may create a problem for the backfill 

operation, as these dredges normally either “rainbow” 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 techniques are considered for trenching the pipeline, the 

excavated material may or may not be available for backfilling. If the pipeline has been 

jetted-in, the majority of the excavated material 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 position. 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 will not meet requirements in terms of uplift 

resistance at a prop/overbend, the pipeline 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 pipeline would effectively be made up of material costs and 

installation costs. Material costs 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 pipeline, lay the pipeline and 

backfill the trench. Such activities have been carried out on previous projects (Northstar, 

Oooguruk). Costs could be obtained 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 selected. 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, availability of equipment that is Jones Act 

compliant, and required upgrades to equipment to work in an Arctic environment. 
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Installation costs can be estimated based on a best-case scenario, assuming that 

equipment can be found that is suitable for use in the Alaskan OCS. Again, it is stressed 

that is highly likely that that there would be additional costs 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 execute projects in the Alaskan OCS. 

Pipeline trenching costs using a floating dredge can be estimated based on a current cost 

of $250,000 per day for large dredger (plus mobilization/demobilization costs). Actual 

production rates would depend on the depth of trench required 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 shallow trenches in relatively soft soils. Rates of 

165 ft/hr (50 m/hr) might be typical for a plough, 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 trenched to approximately 165 ft (50 m) water 

depth in areas subjected to ice gouging (see Ice Gouging of Section 4.11.1.1). The overall 

depth of the trench will be a function of the ice gouge protection and other design 

requirements, diameter of pipeline and any overdig to ensure pipeline position below 

mudline. 

Pipeline construction could occur 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 nature of burying a pipeline, some seabed disturbance will take 

place along the right of way. Depending on the methodology used, areas may be required 

for spoil storage or excess spoil disposal. Trenching and backfilling will create some 

turbidity and some habitat alteration associated with offshore pipeline construction and 

installation activities. It is anticipated that coarse sediment would settle to the seafloor very 

near the trench, but that a plume of fine suspended sediment would drift several miles 

(MMS, 2003). 
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4.11.5 Operations 

Pipeline leak detection monitoring is an important aspect of pipeline operations that will 

need to meet regional requirements. The State of Alaska requires all transmission pipelines 

to subscribe to a “best available technology” (BAT) evaluation regarding leak detection. The 

criteria for a BAT evaluation are prescribed by the Alaska Department of Environmental 

Conservation and include availability (i.e., proven technology), compatibility with existing 

SCADA and hardware, transferability, effectiveness, etc. 

There are a number of different approaches that could be used to monitor an oil or gas 

pipeline for leaks. Pipeline integrity checking and leak detection for arctic subsea pipelines 

can generally be categorized as follows (with no implied order 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 considered proven technology and others 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 are other possible leak 

detection strategies that involve remote sensing techniques, fiber optic sensors, acoustics 

and electrical detection devices. 
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4.11.6 Maintenance & Repair 

4.11.6.1 Monitoring & Maintenance 

A pipeline monitoring/inspection philosophy is important to the successful operation of an 

arctic offshore pipeline. A good inspection plan optimizes the amount of useful information 

that can be gained from inspection surveys and pigging runs, and takes into account the 

criticality of the various systems. If inspection results are satisfactory, it can generally be 

inferred that the system is fit for service. When degradation is discovered, 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 pipeline’s condition may be characterized as 

follows: conditions that require no action; conditions that require more rigorous monitoring 

schedules; or conditions that require immediate intervention. Such conditions are 

determined based on pigging test data and route survey data. 

As suggested earlier in this report, annual monitoring 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 developed 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 permanent repairs would be the desired repair 

strategy, given the potential for high strain loading events. Mechanical pipeline repair 

systems may be used is if there 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. 
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In developing pipeline repair strategies, consideration 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 localized 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 account. Given the circumstances, 

temporary repairs may have to be made, followed 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, with modifications, from 

a stable ice sheet of sufficient thickness. However, some repair techniques are compatible 

only with specific support equipment. Repair methods 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 permanent arctic offshore repair where the 

pipeline may subsequently be subjected to significant strains. The short term and long-term 

acceptability of mechanical repair systems should be evaluated during detailed design. 

However, mechanical repair devices have the advantage that they are relatively easily 

deployed compared to a pipeline cut out and replacement. 
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4.11.7 Abandonment & Decommissioning 

Decommissioning procedures for offshore installations that have reached the end of their 

useful life are usually included in governing legislation. There are also international 

agreements relating to decommissioning that address removal and deep-sea disposal. For 

example, the International Maritime Organization (IMO) has developed Guidelines and 

Standards for the removal of Offshore Installations 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 removal of all facilities to a requirement that 

most facilities be left in place for future use. Actual requirements would not be stipulated 

until near the end of the 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 considerations. Therefore, the decision might be made to pig the 

pipeline of any residual hydrocarbons 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 complex of structures and 

equipment for loading of hydrocarbon products, either pumped to a tanker from a storage 

facility located onshore or directly from a processing facility. 

In most cases, marine transportation of hydrocarbon 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 are basically the same as those 

in the moderate climate. The main 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 critical 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 technology on piping and 

pipelines. 

Hydrocarbons may be loaded on tankers at sea or in the vicinity 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 storage or trans-shipment loading. Several 

recent applications of these concepts in the Arctic were described in Section 3.2.1.2 (the 
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production platform offloading at Prirazlomnoye field and the FSU in Kolsky Bay in the 

Barents Sea, Russia). 

Particularly challenging in the Arctic is the offloading of products to tankers because this 

operation will need to be conducted in floating ice if year-round operations are going to be 

conducted. 

4.12.2 Technical 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 (North Baffin Island, Canada), St. David de 

Levis and Caps Noirs (Quebec, Canada), Norwegian and Russian ports in the Barents Sea 

(Murmansk, Arkhangelsk), and Magadan and Petropavlovsk (Okhotsk Sea, Russia). The 

most recent examples are the large Oil Terminal in DeKastri and the LNG Terminal in 

Prigorodnoye (Sea of Japan), Russia. 

The common specific feature, as well as the main challenge in all of these ports and 

terminals projects, is that the marine structures are to be operated and maintained under 

adverse ice conditions: 

• Very large lateral loading may be generated during floating 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 ice 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 structural 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 affects the terminal structures, but also 

significantly complicates vessel operations: 
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• Ship traffic is to be restricted to certain lanes, offshore, in the approach 

channel and inside the port maneuvering areas. However, this protection 

measure may become insufficient during occasional winter and spring breakups when large masses of floating ice enter the limits of ice-free shipping 

lanes. 

• Berthing operations may become potentially hazardous because ice growth 

on the fenders eliminates their ability to deflect and absorb berthing energy. 

• Large quantities of broken 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 affordable) 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/structure interaction, in most cases, govern the design of 

Arctic ports and terminal structures. 

A general review of experience in operation of high-latitude oil and gas marine terminals 

indicates that existing technology of port structures design and construction is sufficient to 

support operations in the Alaskan OCS. New technology developments will be required in 

shipping operations, primarily by providing the highest level of safety of tanker operations in 

ice-infested waters and by maximizing the efficiency of ice management systems. 

While technically feasible, no tanker traffic has been proposed in the EIS for upcoming 

Beaufort lease sales (MMS, 2003). Regulatory requirements would require pipelines, if 

economically feasible in comparison with barging or tankering production to shore. 

Because the EIS stipulates a preference to pipelines for transport, this suggests that MMS 

may consider tankering of hydrocarbons from the Chukchi OCS a less likely scenario 

(MMS, 2007b). 
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4.12.3 Constructability & Capital Costs 

4.12.3.1 General Marine Terminal Concepts for Arctic & Sub-Arctic 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 shallow water, lagoon or beach formations, 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 terminals designed for moderate climates often 

suggest that the approach trestle solution is the most expensive. This conclusion becomes 

more certain for the Arctic and sub-Arctic conditions because the relatively light structural 

supports for a trestle need to be increased significantly to resist ice loads. 

The dredged channel option is also quite expensive and may have negative environmental 

impacts (disposal of dredge spoil). Two main cost-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 frequently rejected due to the long 

time required for its execution and, more frequently, because of the potential for 

environmental damage. In some Arctic coastal areas, storm wave action, prevailing current 

and long-shore sediment transport processes cause an accelerated siltation of the dredged 

channels. 

The difficulties and high costs associated 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 need to be conducted in the floating ice, 

e.g. Sakhalin 1 DeKastri export terminal in the Sea of Japan and Varandey Terminal in the 

Barents Sea, Russia (see Section 3.2.7). 
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4.12.3.2 Offshore TLU Alternatives 

The main advantage of offshore berthing is that the TLU may be sited at the required 

natural water depth without dredging or without 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 oil 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 Anchor Leg type (SALM buoy) and Multiple Buoy 

Mooring (MBM) cannot be used in the Arctic for year round operations. These solutions are 

vulnerable to damage from floating 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 used on the Sakhalin 2 project but tanker 

loading was halted in the winter (Figure 4-38). This type structure has suffered damage 

during severe weather and is scheduled to be replaced by a permanent pipeline to shore 

(Platts, 2007). For year-round operation in arctic 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 stability of a bottom-founded SPM in floating ice. It 

may de designed as a gravity structure (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, according to available information, the Varandey oil 

terminal in the Barents Sea (Russia) is a wide turret tower with a caisson gravity base and 

a group of piles to supplement the lateral resistance (Section 3.2.7). The Sakhalin 1 SPM of 

the DeKastri terminal is a relatively slender tower with piles driven over the perimeter of a 

wide base. This structure also has a large ice-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 tons (3200 tonnes) and sits 200 ft (61 m) above 

sea level. It can handle tankers up to 110,000 DWT and is designed for year-round loading 

in the ice-infested Tatar Strait between Sakhalin Island and the Russian mainland 

(PennWell Publishing, 2007). 
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Figure 4-38: Ice Breaker “Smit Sibu” Providing Ice Management Operations for SALM Buoy 

Lay Down Operations on Sakhalin 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) 
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The application of ice-breaking cones is not without controversy. 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 ice crushing mode than the tower stem without a cone. This 

premise is similar to that presented in Section 4.5.4.1 with respect to the use of a slopedsided structure for a GBS production structure. 

Conceptual evaluations of structures for sub-arctic conditions, with level ice less than 3.3 ft 

(1 m), showed that the increase of the wall thickness of the steel pipe piles at the zones of 

maximum bending moment is a more cost efficient solution than the application of cones at 

the water level. In these cases, the cost for 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 ice conditions (Tsinker, 1995). 

4.12.4 Environmental Considerations 

Hydrocarbon transport marine terminals are considered by countries having access to the 

Arctic seas as potentially having an impact on the environment. For instance, the maximum 

allowable level of hydrocarbon products in seawater in the Russian Federation is barely 

achievable by the best oil/water separators. Proposed solutions require the application of 

additional stormwater treatment technology. Other stringent requirements have resulted in 

the creation of Water Conservation Zones, where many industrial activities are disallowed. 

Terminal concepts where tankers are loaded offshore require a subsea 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 components of the operations of a marine terminal in arctic 

conditions is Oil Spill Response (OSR) in floating 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 spills from tankers, there has been a mandatory phase-in of 

double-hulled tankers, better navigational systems and tanker escorts (MMS, 2003). 
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Another consideration is that the use of tankers would result in air emissions from the 

tankers’ engines during loading operations, transit and unloading. 

4.12.5 Operations 

Safe vessel operation in ice (Figure 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 discharge, bubbler systems and ice dusting, and 

ice diversion by small islands, cells and dolphins. All of these inevitably increase the costs 

of terminal development in the Arctic and impose a range of requirements to the layout of 

the terminal facilities and their structural design. 

The key component of vessel operations in ice in the vicinity of marine terminals is 

maintaining the operational areas (approach channels, maneuvering zones and turning 

circles, anchorages, etc.) free of ice as long as possible with minimal ice management. This 

particular requirement makes the design and the layout of arctic marine terminals more 

site-specific than any other initial investment cost consideration. For instance, it may be 

more cost efficient (in the long run) to extend the loading line 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 observations, 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 tidal currents. The shoreline 

geometry, and particularly the natural rocks and islands, may be efficiently used to reduce 

the interaction of the structures with particularly large ice features. More than one approach 

channel may be maintained through the winter to make sure that at least one will remain 

free of ice if the wind changes. Lower cost breakwater and berthing front configurations 

may be sacrificed in favor of an alternative solution which provides better ice clearing 

conditions in the harbor. 
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Figure 4-40: Icebreaker and Tanker Trials at Sakhalin (Courtesy of PennWell Publishing, 

2007) 

4.12.6 Maintenance & Repair 

A maintenance program for arctic terminals includes three types of inspections: 

• Regular inspections performed at least once a year to identify the need for 

repairs; 

• Detailed pre-construction inspections conducted if the decision 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 clear. 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 structures 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 potential damage from the ice loading: static and dynamic 

overstressing, bending, cracking and breakage of support components, etc. 
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Depending on the approach channel infill rates, dredging may need to be carried out 

periodically to ensure vessel access. 

4.12.7 Abandonment & Decommissioning 

Decommissioning procedures for offshore installations that have reached the end of their 

useful life are usually included in governing legislation. There are also international 

agreements relating to decommissioning that address removal and deep-sea disposal. For 

example, the International Maritime Organization (IMO) has developed Guidelines and 

Standards for the removal of Offshore Installations and sets out conditions to protect 

navigation and maintain safety. 

Some general requirements in other jurisdictions with regards to decommissioning include 

designing facilities such that, 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 Technical Feasibility 

The Liberty FEIS (MMS, 2002) defines extended-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 Alaska also continues to grow (Figure 4-41) 

and has been used to increase access to the Alpine development reservoir (Alvord et al., 

2007). 

A long-reach US record for horizontal directional wells was set by BP in 1998 with a reach 

of 19,804 ft (6036 m) in the Niakuk Field (see Figure 4-41). While the well cost $6 million, 

the use of extended reach technology resulted in a cheaper solution over other drilling 

alternatives such as the construction of an artificial gravel island (Department of Natural 

Resources, 1999). 
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Figure 4-41: Well Reach vs. Time (Department 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 develop 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 reached 37,000+ ft (11,300+ m) measured depth and 

reservoirs within this range should be reachable depending on site-specific conditions. 

Each development might be expected to contain a unique set of geologic conditions that 

affect drilling costs and long-term operations. 

Therefore, ERD from shore is considered technically feasible for location scenario closest 

to shore presented in this study. While not specifically feasible for the other location 

scenarios, it is evident that the technology could be applied where the right conditions exist. 
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The use of ERD offshore could be considered for 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 from onshore or access additional reservoirs offshore from existing 

facilities should be less expensive than considering an offshore platform or gravel island. 

The costs of drilling using extended reach technology, while not presented 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 extended-reach drilling in other settings, both on the North Slope 

of Alaska and elsewhere and also presents some information on costs. 

The Sakhalin 1 Project uses what 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), demonstrating 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 including remote areas. The use of extended reach drilling, 

where feasible, should help minimize the overall footprint of facilities in Alaska, both 

onshore and in the OCS region. 
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4.13.1.5 Operations, Maintenance, & Repair 

Operations associated with drilling extended reach wells is established within the industry. 

As these wells are likely to be drilled in remote locations, consideration needs to be given 

to supply and re-supply to areas with no permanent roads and delivery restricted 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 affect long-term operations. 

Maintenance and repair issues associated with ERD should be established within the 

industry. As with operations, consideration 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 Technical Feasibility 

Another method that may prove viable for installation of relatively short (approximately 3.5 

miles or 6 km length or less) and small diameter (approximately 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 drilling technology to intersect two wells in a 

horizontal orientation. The WIM option entails drilling 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 casing in the well path at true 

vertical depth (TVD) and provide a continuous conduit for hydrocarbon transmission. 

Two drilling rigs are employed simultaneously to perform the drilling (one at each end). The 

wells are “intersected” at approximately the mid-point. Since conventional drilling 

technology is used, traditional blowout preventers (BOPs) are employed to contain any 

potential shallow gas pockets that might be encountered. In addition, all drilling fluids are 

contained, helping eliminate the environmental issues associated with horizontal directional 
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drilling (HDD). Also, since one drill 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 possibly 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 provide 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 unconsolidated 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 eliminate flowlines installed on the seafloor or to extend the 

length of already extended reach wells in harsh environments, such as those where ice 

gouge is an issue. The authors also suggest that, ultimately, spans 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 from 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 for 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 the other scenarios, as long as the daisy chain 

connections (where they are tied together) 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 significant well planning and drilling technology 

issues that would have to be addressed before 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 chained, some design/development effort would 

need to go into the connections near the surface and protection of same. 
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4.13.2.3 Capital Costs 

The WIM is based on existing drilling technology and well costs can be used as a basis. 

Smith (2004) indicates that the Buckinghorse River crossing exceeded $12 million, but 

some of this was attributed to problems at the onset of drilling. 

4.13.2.4 Environmental Considerations 

Again, environmental considerations associated with the drilling of wells are well 

understood and managed. If technically and economically feasible, the use of such 

technology could reduce the amount of buried offshore pipeline 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 similarly to a pipeline with some potential 

limitations, e.g., pigging. 

In terms of existing operations, the Buckinghorse River crossing started transporting gas 

using WIM technology in December 2004, at a rate of 9 mmscf per day. Anadarko were 

also looking at potential conversion to a high-pressure system to increase throughput to 

approximately 30+ mmscf per day (Smith, 2004). 

Given the technology used to implement a WIM transportation solution, maintenance and 

repair issues would be similar to those associated 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 Technical Feasibility 

A relatively new development in the horizontal directional drilling industry has been to drill 

two pilot holes, from entry points at either side of the crossing, and intersect them 

underneath the crossing, rather than to drill a single pilot hole from entry to exit. This 

possibly extends the reach over conventional HDD projects. 
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HDD is a proven technology with a strong track record in non-arctic applications. However, 

it has been used on the ARCO Alpine Development 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 hole to pilot hole HDD technology would not be feasible to 

access any of the location scenarios presented in this study. However, 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 for any of the other 

scenarios as long as the daisy chain connections (where they are tied together) were 

adequately designed/protected. 

4.13.3.2 Constructability 

Where HDD is considered, the main technical constraint involves the influence of soil 

conditions. The effects of the presence of permafrost on the drilling operation must be 

considered. The presence of gravel or ice lenses would reduce the efficiency of the drilling 

operations and could result in collapse 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 costs can be provided by HDD contractors. 

4.13.3.4 Environmental Considerations 

A major advantage of a HDD shore approach is that the shoreline is left undisturbed. Also, 

theoretically, HDD installations could be linked (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 decrease 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 inspections 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 maintenance as the shoreline will have been 
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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 accessibility of the pipeline. By the 

nature of HDD installations, access to the pipeline 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 would be abandoned and decommissioned operated in the same 

manner as a conventional pipeline crossing. 
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5.0 SUMMARY, CONCLUSIONS AND RECOMMENDATIONS 

5.1 Overview 

Offshore hydrocarbon exploration and production requires a bottom-founded platform, an 

artificial island or a floating structure plus subsea equipment including pipeline/riser 

systems. Transportation of produced hydrocarbons to market is also an essential aspect of 

any development. An added complexity when hydrocarbon resources are located in cold 

regions is the presence of first-year and/or multi-year ice during 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 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 Outer Continental Shelf (OCS). Advances in 

harsh environment offshore exploration and production technology have made it 

economically and technically feasible for projects to proceed in ice-covered waters. This 

study assesses the current state of offshore technology 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 technologies that might be applied on the US 

OCS, in particular those areas in the Beaufort, Chukchi and Bering Seas. The work covers 

exploration structures, bottom founded and fixed production concepts, floating production 

concepts, terminals, pipelines and subsea facilities, and also touches on other technologies 

that might be relevant to Alaskan 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 state-of-the-art. Assessments of exploration and production options 

are primarily based on technical feasibility. As appropriate, other considerations have also 

been examined, as follows: 

• Constructability; 

• Capital costs; 

• Environmental considerations; 
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• Operations; 

• Maintenance and repair; and 

• Abandonment and decommissioning. 

Given the large geographic area encompassed by the Beaufort, Chukchi and Bering Seas, 

location scenarios were specified to help focus the assessments. These location scenarios 

were chosen based on current and historic activity/interest (including lease sales, drilling, 

studies, projects, etc.) and water depths (given the general differences in offshore facilities 

configuration in relation to water depth). Overall general applicability 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 Beaufort Sea began from gravel islands in shallow 

Alaskan State waters in the late 1960’s and similarly 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 waters, followed in 1981 by the first use of a 

bottom-founded caisson system. Although touted as “mobile” 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 

addition of the MAT in 1985, remains the only active bottom-founded exploration structure 

in the Arctic offshore. 

In terms of global size, structure cost and geometry, there is very little difference between 

dedicated exploration platforms and dedicated production platforms. In fact, an arctic 

mobile drilling structure is often more expensive than a production 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 mobilization of an exploration structure. 
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5.3.1.1 Design Considerations 

In any location where substantial multi-year ice can impact a structure, the loads resulting 

from this interaction become the 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 (Bering 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 eliminate local ice load effects, bridging and vibrations, results in 

relatively high global wave loads. 

After ice loads, there are two other parameters 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, although not in direct proportion. Thus, water 

depth has a twofold influence in that the deeper the water, the greater the horizontal design 

load, and also that the structure must increase in height and, hence, cost. Foundation types 

can range from “totally inadequate” (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 preparation. Foundation requirements for an exploration 

structure will be considerably less than those for a permanent production structure given 

the differences in the design loads (first-year ice vs. multi-year ice loads). 

5.3.1.2 Technical Feasibility of Structures 

Ten (10) location scenarios are assessed with respect to the types of structures that may 

provide a possible solution; in addition, two (2) general structures (one with oil storage and 

one for mobile drilling) are assessed. The location scenarios, together with primary design 

assumptions are listed in Table 4-1. 

In the Beaufort and Chukchi Sea areas, the 100-year design ice loading condition arises as 

a result of an interaction with thick multi-year ice. 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 four between the 

global load scenarios), the quantities of steel in a temporary drilling structure will not be 

much different than those in a permanent production structure. In fact, temporary mobile 
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structures may be more expensive due to having to cater to a range of set-down conditions 

rather than a specified depth. 

In the case of exploration drilling, the historical approach is to establish foundation stability 

based on a deterministic first-year ice loading 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 floes 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 temporary “one well” drilling 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 ranges that modern probabilistic methods would predict. With 

respect to the Chukchi Sea, load ranges are given with respect to the northernmost areas. 

In southern areas, close to the Bering Strait, loads can be expected to be approximately 

30% less. 

In the event that a temporary deployment for an exploration structure is being considered, 

arguments as outlined above can be rationally 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 consideration (Table 4-3), 

although for the Beaufort and Chukchi Sea areas it is generally ice loads that govern 

stability. 

In multi-year ice areas, 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 foundation properties are good, and up to around 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 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, bottomfounded solutions out to 425 to 500 ft (130 to 150 m) water depths are potentially viable. 
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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 strong foundations in deeper 

water to approximately $8 million/ft ($26 million/m) for structures on weak foundations in 

shallow water. 

5.3.2 Jacket & Jack-up Structures 

The jacket structure is the most commonly used fixed offshore platform. It was first used in 

the Gulf of Mexico and has since been adapted and modified for use all over the world. It 

comes in a variety of styles from the single-legged (monopod) to multi-legged structures. 

The ice reinforced jacket platform was first successfully used in sea ice in the mid 1960’s 

for Cook Inlet, Alaska developments. Conventional jacket designs have been modified to 

make them suitable for sea ice environments. Three varieties of ice reinforced jacket 

structures have been used there; the monopod, the tripod and the quadpod. 

The main considerations for the 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 structures are temperature loading, sea ice static 

loads and the accompanying vibration loads. In many 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 generally the controlling factor in material selection. 

The load imparted to a structure by momentum, ridge building and pack ice loading relates 

to the width of the structure. If the jacket legs are within a certain distance of each other, ice 

bridging can occur between the legs and higher loads will be experienced by the structure 

compared to the case where the legs are loaded independently. 

In addition to static sea ice loads, the jacket structure must handle the vibration loading. Ice 

reinforced jacket structures are more susceptible 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 dysfunction of another as a result of ice induced 

vibrations (Cammaert and Muggeridge, 1988), there is a strong possibility that jacket 

platforms are unworkable and/or uninhabitable under modern vibration code limits. 

Previous studies have suggested that jacket structures are suitable for areas of the Bering 

Sea. These studies did not consider the vibration responses associated with the dynamic 
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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 and the conductor system protection issue are a significant 

design issues for application in the Bering Sea. Current design practices and understanding 

of jacket design make their application unsuitable for the Beaufort and Chukchi Seas. 

The protection and vibration issues associated with arctic jacket design and construction 

may be mitigated with further study and understanding of ice induced vibrations and the 

review and development of alternative damping techniques. Further study of jacket leg 

loading under thick ice conditions is required 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 range 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 Technical Feasibility 

In general, ice island technical feasibility is based on several fundamental regional and site 

specific considerations: meteorological environment, water depth, landfast ice 

characteristics and geotechnical (seabed) conditions. 

Water depth is a fundamental factor that must be considered when evaluating the 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 critical because any appreciable movement of 

the island during drilling operations can cause damage to the drill-string. Ice loads imparted 

on an ice island depend on the ice failure mode, rather than on the 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 will be governed by its sliding 

resistance (lateral stability). 
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In practice, operational ice islands have been employed in water depths of up to 25 ft (7.6 

m) in the Beaufort Sea. However, based on work reported in C-CORE (2005), the use of 

operational ice islands might be achieved in water depths of up to approximately 30 ft (9 

m). The MMS Ice Island Study (C-CORE, 2005) suggests that “incremental improvements 

in equipment capacity with higher productivity would allow islands 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 this study, ice islands were assessed for both 

the nearshore Chukchi Sea and Norton Sound. Results of the assessment indicate that the 

use of ice islands in the nearshore Chukchi would likely be infeasible due to the unstable 

and unreliable landfast, or contiguous, ice zone. The assessment also indicates that ice 

islands would generally not be feasible for Norton Sound due to its warmer and shorter 

winter season. Efficient spray ice production would not be achievable, time available for 

construction and subsequent drilling operations would be reduced and creep/settlement 

would likely be more of an issue in comparison 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 island to work in very shallow 

nearshore water depths. Further assessment would be required to ascertain ice island 

feasibility in these areas. 

5.3.3.2 Construction 

Initially ice islands were constructed using the flooding construction technique; however, 

build up rates were low. Alternative methods of ice island construction have been 

previously investigated and through significant experimentation and study efforts, spray ice 

technology was developed. All operational ice island drilling structures built in the US and 

Canadian Beaufort Sea (7 in total), employed this construction technique. 

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 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); 
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• Further reduction of design ice load by reducing the thickness of the 

surrounding landfast sheet; and, 

• Use of chipped ice, which 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 loads expected, water depth and soil 

conditions. Cost optimization may be realized in several ways, including reducing drilling 

facility footprint, reducing ice island diameter based on soil conditions, using chipped ice, 

and considering design ice load reduction techniques. Comparatively, ice islands are far 

more economical then gravel islands. However, gravel islands are more versatile with 

respect to water depths and ice loads. Figure 4-17 presented earlier illustrates the cost 

differences between ice and gravel 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 viewed as candidate structures for exploration 

and/or production (for example, 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 economical structure for 

shallow water depths. Given recent increasing oil prices and increasing material and 

fabrication costs for other types of structures, it is not inconceivable that the water depth for 

which gravel islands are considered might be increased. 

5.3.4.1 Technical Feasibility 

The use of gravel islands for arctic exploration and production has been proven. On the 

order of fifty (50) gravel islands have been constructed in the Beaufort Sea in water depths 

from several feet to over 60 ft (19 m). In theory, a gravel island has no depth limitation, but 

in practice water depth limitations 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 considerable influence on island design and 
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construction methods. In deeper water areas, multi-year ice incursions have to be 

considered and, in general, ice ride-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 must have adequate lateral stability to resist ice 

loads. Gravel islands must also be capable of withstanding potential ice ride-up and wave 

conditions. 

In general terms, these environmental loads are managed through gravel island geometry. 

Ice ride-up is impeded by the sloped island sides due to friction and plowing forces and/or, 

in some cases, by discontinuity in slope. Waves begin to break as they reach the sloped 

island sides, thereby dissipating energy before they reach the working surface. Wave 

overtopping is dealt with by placing the working 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 investigated in this study, and considering practical 

water depth limitations, nearshore areas of the Beaufort Sea, Chukchi Sea and Bering Sea 

can be considered for the use of a gravel island. 

Since no gravel 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 Chukchi Sea. Due 

consideration would need to be given to the fact that the nearshore Chukchi Sea ice 

environment may be more dynamic then the Beaufort Sea. 

In the nearshore Bering Sea, gravel islands 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 constructing gravel islands: the onshore (hauled) 

method or the offshore (dredged) method. 

The onshore method typically involves excavating 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 majority of gravel islands constructed in 
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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 transporting 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 were built using this 

method. 

The Chukchi Sea has a dynamic ice environment and nearshore “landfast” or “contiguous” 

ice is highly unreliable. Therefore, the truck hauling method will likely be infeasible. Norton 

Sound ice roads will have limited use in comparison to the Beaufort Sea, which will 

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 the island. The timing and method of pipeline installation 

should be such that interference with island construction and/or facilities installation is 

minimized. 

Typical costs associated with gravel islands were presented in Figure 4-17. 

5.3.5 Floating Structures 

There are only a limited number of floating exploration or production structures that have 

been used in ice environments. 

5.3.5.1 Exploration 

During exploration in the Canadian Arctic in the 1980’s, floating vessels (drillships) were 

used successfully with the support of icebreaking 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 operate 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 Banks of Newfoundland, FPSOs (Floating Production, Storage 

and Offloading) have been the choice of floating production vessels under potential sea ice 

(first-year) and iceberg conditions. The hulls of both of the existing Grand Banks FPSOs 
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are designed to operate in light to moderate first-year pack 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 present, as might be the case in the Alaskan 

OCS. 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 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 their moorings and operated in managed ice conditions. The 

ability of these floating platforms to leave station would allow the vessel 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 floating vessel to reconnect back on station will be a 

significant consideration in concept 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 multi-year ice, semi-submersibles or a TLP. However, for 

exploration, the only location that a floating structure might be capable of staying on station 

year-round might be the 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. Fitzpatrick’s 

Semi-rigid Floater is designed to stay in place 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 structure was permanent or temporary, the ice environment, water 

depth, etc., and would have to be evaluated during any detailed assessment. However, 

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 multiyear ice loads found in the Beaufort and Chukchi Seas, and possibly northern Bering Sea 
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depending on local ice conditions. Floating systems 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 exploration and production in the Alaskan OCS areas of study. 

Floating structures have been and will continue to be used for seasonal exploration. A 

floating structure will likely be only able to carry out year round exploration operations in the 

south Bering Sea under light ice conditions. However, a Semi-rigid Floater type structure 

could be considered for year-round exploration, if disconnects were permissible under 

extreme loading events. Based on current technology, no floating type structures could 

operate as a production structure in the most of the Alaskan 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 sufficient depth, protection from ice would not be 

necessary. In areas with water depths less than 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 resources in harsh and remote environments. As a result of these 

improvements, fields requiring 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 reached 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 certain 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 flowlines tying in the subsea facilities. 
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Consideration would need to be given to the distances to shore or to a platform. Distances 

greater than those milestones stated above will require additional technological 

development or intermediate tie-in facilities for distances greater than these. 

5.3.6.2 Subsea Facilities Protection 

Glory holes (Figure 4-27) are excavations in the seafloor into which subsea facilities can be 

installed for protection from scouring ice keels. Although not in the Arctic, two existing 

projects use open glory holes to protect wellheads and associated subsea equipment from 

iceberg keel impact. These are the Terra Nova and White Rose projects located on the 

Grand Banks (Canadian east coast) where, to date, glory hole excavation has been the 

preferred method of subsea facilities protection. 

Subsea facilities can potentially be used at any of the location scenarios considered in this 

study or, in general, for any development on the Alaskan OCS. However, 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 present, 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 required to determine the range 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 gouging, about 165 to 200 ft (50 to 60 m) water depth depending 

on the location, subsea facilities might be placed 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 subsea 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, operations, maintenance and repair. Pipelines 
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have been designed, constructed and are operational 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 additional consideration be 

given to some of these aspects. 

5.3.7.1 Design 

Some of the main considerations with respect to pipeline design in the Arctic are strudel 

scour, thaw settlement of permafrost, upheaval buckling and ice gouging. 

The first two design issues happen over very limited distances of the nearshore portion of 

the pipeline and have been addressed in existing pipeline designs. The third issue, 

upheaval buckling, can happen in any region of the pipeline if conditions are conducive to 

buckling. Installation procedures have been implemented on past projects to minimize the 

risk of upheaval buckling (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 on future projects. 

It is generally accepted that offshore arctic pipelines would need to be trenched to some 

depth below the seabed to protect the pipeline from the effects of pressure ridge ice or 

iceberg keels. This burial depth would be such that the ice would not contact the pipeline 

plus any required clearance between the bottom of the ice keel and the pipeline such that 

soil loadings on the pipeline are within acceptable limits (Figure 4-29). A number of buried 

offshore pipelines are being successfully operated in ice gouge environments, including 

projects in the Alaskan OCS (e.g., Northstar, Oooguruk). 

Trench depths will increase in areas of more severe gouging. In nearshore zones (less than 

33 ft (10 m) water depth), pipelines might be expected 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 trenched 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 overall determination of burial depth and must be 

examined in conjunction with other factors such as thaw settlement, upheaval buckling, 

strudel scour, pipeline stability and flow assurance. However, as mentioned above, these 
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other aspects can likely be accommodated, given successful operation of projects in the 

shallow waters of the Beaufort. 

5.3.7.2 Installation 

Offshore arctic equipment and logistics requirements 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, trenching 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. Conventional trenching equipment 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 construction is planned. Similar 

general considerations apply as noted for trenching equipment operations. 

Given potential burial depth requirements for pipelines in deeper water (>50 ft or 15 m 

water depth), technology to economically trench and backfill these pipelines is considered 

one of the most significant issues with regards 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 pipeline 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 the 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 mechanical repair devices are appropriate for a 

permanent arctic offshore repair, where the pipeline may subsequently be subjected to 

significant strains.
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5.3.8 Export Terminals 

A marine export terminal is defined as a complex of structures and equipment for loading of 

hydrocarbon products, either pumped to a tanker from a storage facility located onshore or 

directly from a processing facility. 

In most cases, marine transportation of hydrocarbon 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 are basically the same as those 

in moderate climates. The main 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 critical 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 technology 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 Technical 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 (North Baffin Island, Canada), St. David de 

Levis and Caps Noirs (Quebec, Canada), Norwegian and Russian ports in the Barents Sea 

(Murmansk, Arkhangelsk), and Magadan and Petropavlovsk (Okhotsk Sea, Russia). The 

most recent examples are the large Oil Terminal in DeKastri and the LNG Terminal in 

Prigorodnoye (Sea of Japan), Russia. 

The common specific feature, as well as the main challenge in all of these ports and 

terminals projects, is that the marine structures are to be operated and maintained under 

adverse ice conditions. Very large lateral loads may be generated during floating 
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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/structure interaction, in most cases, govern the design of 

arctic ports and terminal structures. 

A general review of experience in operation of high-latitude oil and gas marine terminals 

indicates that existing technology of port structures design and construction is sufficient to 

support operations in the Alaskan OCS. New technology developments will be required in 

shipping operations, primarily by providing the highest level of safety of tanker operations in 

ice-infested waters and by maximizing the efficiency of ice management systems. 

While technically feasible, no tanker traffic has been proposed in the EIS for upcoming 

Beaufort or Chukchi lease sales. Regulatory requirements would require the use of 

pipelines (if economically feasible) rather than barging or tankering production to shore. An 

exception may be gas export by LNG or CNG. 

5.3.9 Other Technologies 

5.3.9.1 Extended Reach Drilling (ERD) 

The use of extended reach drilling (ERD) has matured on some projects and upwards of 

37,000 ft (11,200 m) wells are currently achievable. Therefore, ERD from shore is 

considered technically feasible for nearshore locations 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 conditions exist. The use of ERD offshore could be 

considered for any of the other scenarios that 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 the limit of this technology is 

currently estimated to be a maximum of approximately 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 verify this technique for arctic environments 

and to look at the economics compared to traditional trenched pipelines. 
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5.3.9.3 Pilot Hole to Pilot Hole HDD 

A pilot hole to pilot hole HDD (horizontal directional drilling) installation can be considered 

as an option to conventional pipeline installation. However, there are length limitations to 

what can successfully be accomplished. If daisy-chaining spans together was feasible, the 

technology could be applied to access greater 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 was 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 distances increase, resulting in higher waves. 

There is general agreement that environmental conditions (especially waves and ice 

conditions) are changing in the Arctic. But no one definitively knows by how much, nor is 

there a compilation of current information (that the Study Team could find) that provides the 

information necessary for those interested in Alaska 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 holding discussions with selected stakeholders. 

It has been suggested by stakeholders that the MMS might consider a future study to 

compile, collect, and/or generate (e.g., hindcast) 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 identified additional information 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 are the responsibility of the MMS to advance (although they might 

be given consideration), but rather are included for completeness. 

• Regional gouge database for 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); 
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• Ice gouge recurrence rates; 

• Multi-year ice thickness distribution, ridge dimensions and frequency within a 

floe, floe size distribution, floe speed distribution; 

• First-year ice thickness distribution, ridge dimensions; 

• Regional geotechnical database for the US Beaufort, Chukchi and Bering 

Seas; 

• Advancements in allowable/acceptable pipeline strain limits; 

• Advancements in pipeline repair techniques for arctic pipelines; 

• Advancements in pipeline leak detection systems for use in arctic 

environments; 

• Advancements in subsea protection systems; 

• Advancements in trenching technologies for use in an arctic environment 

including assessment, development and field trials; 

• Clarity on emergency well control requirements; 

• Advancements in determining maximum gouge depth based on ice strength 

and driving forces; and 

• Evaluation of climate change and how it may affect exploration and 

development. 
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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 Research Centre of Ocean Engineering 

Krylov Shipbuilding Research Institute, Professor Evgeny M. Appolonov 

Phone: (812) 723-6619 

Fax: (812) 727-9609 

E-mail: appolonov@krylov.spb.ru, orlan@krylov.sp.ru 
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