STRATEGIC ENVIRONMENTAL ASSESSMENT LABRADOR SHELF OFFSHORE ... · STRATEGIC ENVIRONMENTAL ASSESSMENT LABRADOR SHELF OFFSHORE AREA Final Report. FINAL REPORT Strategic Environmental

STRATEGIC ENVIRONMENTAL ASSESSMENTLABRADOR SHELF OFFSHORE AREA

Final Report

FINAL REPORT Strategic Environmental Assessment Labrador Shelf Offshore Area

Canada-Newfoundland and Labrador Offshore Petroleum Board

PROJECT NO. P 064

Sikumiut Environmental Management Ltd.

PROJECT NO. P 064

SUBMITTED TO Canada-Newfoundland and Labrador Offshore Petroleum Board

5th Floor TD Place, 140 Water Street · St. John's, NL · A1C 6H6 ·

FOR Strategic Environmental Assessment

ON Labrador Shelf Offshore Area

August 2008

Sikumiut Environmental Management Ltd. 175 Hamlyn Road

St. John’s, Newfoundland and Labrador, A1E 5Z5

Phone: 709-754-0499

Fax: 709-754-1445

www.sikumiut.ca

LABRADOR SHELF OFFSHORE AREA SEA – FINAL REPORT

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Table of Contents

LIST OF APPENDICES.....................................................................................................................xi LIST OF FIGURES ............................................................................................................................xi LIST OF TABLES..........................................................................................................................xviii LIST OF ACRONYMS ....................................................................................................................xxii LIST OF UNITS ..............................................................................................................................xxv

1.0 INTRODUCTION .......................................................................................................................1 1.1 Scoping ...................................................................................................................................3 1.2 Objectives and Purpose of the Labrador Shelf Offshore Area Strategic Environmental

Assessment.............................................................................................................................3 1.3 Valued Environmental Components........................................................................................4 1.4 Licences ..................................................................................................................................6 1.4.1 Exploration Licence................................................................................................................................ 6 1.4.2 Significant Discovery Licence ................................................................................................................ 6 1.4.3 Production Licence................................................................................................................................. 7 1.5 Call for Bids.............................................................................................................................7 1.6 History of Oil and Gas Activities in Labrador Shelf Offshore Area ..........................................7 1.7 Consultations ..........................................................................................................................9 1.8 Traditional Resource Use......................................................................................................10 1.9 Organization of the Strategic Environmental Assessment ....................................................11

2.0 EXPLORATION AND PRODUCTION ACTIVITIES ................................................................12 2.1 Exploration Activities .............................................................................................................12 2.1.1 Seismic Surveys................................................................................................................................... 13 2.1.2 Geohazard Surveys ............................................................................................................................. 13 2.1.3 Seabed Sampling/Geotechnical Testing.............................................................................................. 14 2.2 Drilling Activities ....................................................................................................................14 2.2.1 Drilling Platforms .................................................................................................................................. 15 2.2.1.1 Exclusion Zones ................................................................................................................................17 2.2.2 Support Vessels ................................................................................................................................... 17 2.2.3 Air Support ........................................................................................................................................... 18 2.3 Production Platforms and Facilities.......................................................................................18 2.3.1 Subsea Options.................................................................................................................................... 19 2.3.1.1 Glory Holes ........................................................................................................................................19 2.3.1.2 Installation..........................................................................................................................................21 2.3.2 Floating Structure Options ................................................................................................................... 21 2.3.2.1 Liquefied Natural Gas........................................................................................................................22 2.3.2.2 Compressed Natural Gas ..................................................................................................................22 2.3.3 Gravity-base Structure Options............................................................................................................ 22 2.3.4 Pipelines and Flowlines........................................................................................................................ 23 2.3.5 Export Facilities/Onshore Processing .................................................................................................. 25 2.3.6 Operations............................................................................................................................................ 25 2.3.6.1 Subsea Systems................................................................................................................................25 2.3.6.2 Floating and Gravity Based Structures..............................................................................................25


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2.3.6.3 Pipelines ............................................................................................................................................26 2.3.6.4 Environmental Emergency Response ...............................................................................................26 2.3.7 Decommissioning................................................................................................................................. 27 2.4 Sound Associated with Exploration and Production Activities ..............................................28 2.4.1 Underwater Sound ............................................................................................................................... 28 2.4.2 In-Air Sound ......................................................................................................................................... 28 2.4.2.1 Ambient Noise Levels........................................................................................................................29 2.4.2.2 Marine Mammal Noise.......................................................................................................................29 2.4.2.3 Shipping Traffic and Anthropogenic Noise ........................................................................................30 2.4.2.4 Wind- and Wave-generated Sound ...................................................................................................30 2.4.2.5 Comparison of Noise Levels..............................................................................................................30 2.4.3 Offshore Oil and Gas Industrial Sounds .............................................................................................. 31 2.4.3.1 Exploratory and Delineation Drilling ..................................................................................................31 2.4.3.2 Two-dimensional and Three-dimensional Seismic Surveys..............................................................32 2.4.3.3 Airgun Operating Principles...............................................................................................................32 2.4.3.4 Airgun Array Source Levels...............................................................................................................33 2.4.3.5 Production..........................................................................................................................................38 2.5 Discharges Associated with Exploration and Production Activities.......................................38 2.5.1 Drill Muds ............................................................................................................................................. 38 2.5.1.1 Water-based Muds ............................................................................................................................40 2.5.1.2 Synthetic-based Muds .......................................................................................................................41 2.5.2 Cement Slurry and Blowout Preventer Fluid........................................................................................ 42 2.5.3 Produced Water ................................................................................................................................... 43 2.5.4 Air Emissions ....................................................................................................................................... 44 2.5.5 Storage Displacement Water ............................................................................................................... 46 2.5.6 Bilge and Ballast Water........................................................................................................................ 46 2.5.7 Deck Drainage ..................................................................................................................................... 46 2.5.8 Cooling Water ...................................................................................................................................... 46 2.5.9 Sewage and Food Wastes................................................................................................................... 47 2.5.10 Dry Bulks.............................................................................................................................................. 47 2.6 Accidental Events..................................................................................................................47 2.6.1 Spill History of the Offshore Oil and Gas Industry ............................................................................... 47 2.6.2 Sources of Information......................................................................................................................... 48 2.6.2.1 Statistics of Importance to Analysis...................................................................................................49 2.6.2.2 Categories of Spill Size .....................................................................................................................49 2.6.3 Blowout and Spill Probabilities............................................................................................................. 49 2.6.3.1 Exploration Drilling Blowouts (No Gas) .............................................................................................50 2.6.3.2 Exploration Drilling Blowouts (Primarily Gas)....................................................................................52 2.6.3.3 Labrador Shelf Strategic Environmental Assessment Area Spill Frequency Calculations................53 2.6.4 Current Trends ..................................................................................................................................... 53 2.6.4.1 Shallow-Gas Blowout versus Deep Blowout .....................................................................................53 2.6.5 Blowout Probabilities for Labrador Shelf Strategic Environmental Assessment Area......................... 54 2.6.6 Batch Accidental Events ...................................................................................................................... 55 2.6.6.1 Historical Record ...............................................................................................................................55 2.6.6.2 Calculated Frequencies for the Labrador Shelf Strategic Environmental Assessment Area............56 2.6.6.3 Newfoundland and Labrador Spill Incident Data ...............................................................................57 2.6.6.4 Spill Sizes ..........................................................................................................................................61 2.6.7 Accidental Events Fate and Behaviour ................................................................................................ 61


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2.6.7.1 Shallow Water Subsea Blowouts.......................................................................................................62 2.6.7.2 Deep-water Subsea Blowouts ...........................................................................................................64 2.6.7.3 Above-surface Blowouts....................................................................................................................64 2.6.7.4 Small Spills ........................................................................................................................................65 2.6.8 General Behaviour of Oil Spilled on Open Water ................................................................................ 65 2.6.8.1 Oil Movement.....................................................................................................................................65 2.6.8.2 Evaporation........................................................................................................................................65 2.6.8.3 Oil Spreading.....................................................................................................................................65 2.6.8.4 Natural Dispersion .............................................................................................................................66 2.6.8.5 Emulsification.....................................................................................................................................66 2.6.9 Behaviour of Oil Spilled on Ice and in Pack or Drift Ice ....................................................................... 66 2.6.9.1 The Effect of Ice on the Four Main Oil Spill Processes.....................................................................66 2.6.9.2 Oil Spilled Within Pack or Drift Ice.....................................................................................................67 2.6.9.3 Oil Spilled on Top of the Ice ..............................................................................................................67 2.6.10 Oil Fate Descriptions and Oil Trajectory Modeling .............................................................................. 68 2.6.11 Environmental Data Used in Trajectory Modelling............................................................................... 68 2.6.11.1 Water Currents ..................................................................................................................................68 2.6.11.2 Wind Speed and Predominate Direction ...........................................................................................69 2.6.12 General Fate of Persistent Crude Oils, Condensates and Gas........................................................... 69 2.6.12.1 Surface Blowout Fate and Behavior ..................................................................................................70 2.6.12.2 Shallow Subsea Blowout Fate and Behavior ....................................................................................70 2.6.12.3 Deep-water Subsea Blowout Fate and Behavior ..............................................................................70 2.6.12.4 Vessel or Drilling Platform Release Modelling Results .....................................................................71 2.6.13 Open Water Trajectory Modelling ........................................................................................................ 71 2.6.14 Oil Spill Fate and Trajectory Summary ................................................................................................ 74 2.6.15 Spill Modelling and Response Planning............................................................................................... 75 2.6.15.1 Oil Spill Capabilities in Subarctic environments ................................................................................76 2.7 Well Abandonment and Decommissioning ...........................................................................78 2.8 Ice Management ...................................................................................................................78 2.8.1 Background .......................................................................................................................................... 78 2.8.2 Ice Management System ..................................................................................................................... 79 2.8.2.1 Ice Management Success .................................................................................................................85 2.8.2.2 Design Considerations ......................................................................................................................86 2.9 Severe Weather ....................................................................................................................86

3.0 PHYSICAL ENVIRONMENT ...................................................................................................87 3.1 Labrador Shelf Strategic Environmental Assessment Area Surficial Geology ......................87 3.1.1 Precambrian Bedrock (Unit 1).............................................................................................................. 87 3.1.2 Tertiary Strata (Unit 2).......................................................................................................................... 87 3.1.3 Till (Unit 3)............................................................................................................................................ 87 3.1.4 Proglacial and Subglacial Sediments (Unit 4)...................................................................................... 89 3.1.5 Post Glacial Marine Sediments (Unit 5) ............................................................................................... 89 3.1.6 Available Geotechnical Data................................................................................................................ 90 3.1.7 Earthquake Hazard ............................................................................................................................ 102 3.2 Bathymetry ..........................................................................................................................104 3.2.1 Coastal Embayments ......................................................................................................................... 105 3.2.1.1 Inner Shelf .......................................................................................................................................107 3.2.1.2 Marginal Trough...............................................................................................................................108


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3.2.1.3 Outer Shelf.......................................................................................................................................109 3.3 Metocean Conditions ..........................................................................................................109 3.4 Sea Conditions....................................................................................................................109 3.4.1 Temperature and Salinity ................................................................................................................... 109 3.4.2 Wave Conditions ................................................................................................................................ 111 3.4.3 Wind Speed........................................................................................................................................ 117 3.4.4 Current ............................................................................................................................................... 121 3.4.5 Tides................................................................................................................................................... 127 3.5 Atmospheric Conditions ......................................................................................................128 3.5.1 Air Temperature ................................................................................................................................. 128 3.5.2 Wind Chill ........................................................................................................................................... 132 3.5.3 Shipping ............................................................................................................................................. 134 3.5.4 Flying.................................................................................................................................................. 135 3.6 Ice Conditions .....................................................................................................................136 3.6.1 Sea Ice Occurrence and Concentration............................................................................................. 136 3.6.2 Sea Ice Drift ....................................................................................................................................... 151 3.6.3 Pack Ice Floe Size Data..................................................................................................................... 152 3.6.4 Sea Ice Thickness Data ..................................................................................................................... 152 3.6.5 Multi-year Ice...................................................................................................................................... 154 3.7 Iceberg Occurrence.............................................................................................................156 3.7.1 Iceberg Drift........................................................................................................................................ 159 3.7.2 Iceberg Size ....................................................................................................................................... 160 3.7.2.1 2006 Survey Program......................................................................................................................161 3.7.2.2 Iceberg Physical Dimensions Study ................................................................................................161 3.7.2.3 Icebergs Observed During Drilling Operations................................................................................161 3.7.2.4 Voisey’s Bay Iceberg Survey...........................................................................................................161 3.7.2.5 International Ice Patrol Surveys.......................................................................................................161 3.7.3 Ice Islands .......................................................................................................................................... 163 3.8 Iceberg Scour......................................................................................................................164 3.8.1 Introduction ........................................................................................................................................ 164 3.8.2 2003 Makkovik Survey Program........................................................................................................ 164 3.8.3 Scour Geometry ................................................................................................................................. 164 3.8.3.1 Scour Depth.....................................................................................................................................167 3.8.3.2 Scour Width .....................................................................................................................................168 3.8.3.3 Scour Length ...................................................................................................................................169 3.8.3.4 Scour Orientation.............................................................................................................................170 3.8.3.5 Scour Rise-Up .................................................................................................................................172 3.8.3.6 Pit Depth ..........................................................................................................................................172 3.8.3.7 Pit Plan Dimensions ........................................................................................................................173 3.8.4 Scour Rate ......................................................................................................................................... 174 3.8.5 Geometric Grounding Model.............................................................................................................. 175 3.9 Data Constraints for Physical Environment.........................................................................176 3.10 Unexploded Ordinance .......................................................................................................177 3.11 Planning Considerations for the Physical Environment ......................................................177

4.0 BIOLOGICAL ENVIRONMENT.............................................................................................178 4.1 Climate Change ..................................................................................................................180


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4.2 Species at Risk ...................................................................................................................180 4.2.1 Species at Risk Act Recovery............................................................................................................ 181 4.2.3 Wolffish .............................................................................................................................................. 182 4.2.4 Blue Whale......................................................................................................................................... 185 4.2.5 Leatherback Turtle ............................................................................................................................. 188 4.2.6 Fin Whale ........................................................................................................................................... 189 4.2.7 Harlequin Duck................................................................................................................................... 191 4.2.8 Barrow’s Goldeneye........................................................................................................................... 193 4.2.9 Ivory Gull ............................................................................................................................................ 195 4.2.10 Eskimo Curlew ................................................................................................................................... 196 4.2.11 Peregrine Falcon................................................................................................................................ 196 4.2.12 Data Constraints for Species at Risk ................................................................................................. 197 4.2.13 Planning Implications for Species at Risk .......................................................................................... 199 4.3 Committee on the Status of Endangered Wildlife in Canada Species ................................199 4.3.1 Red Knot ............................................................................................................................................ 200 4.3.2 Atlantic Cod........................................................................................................................................ 201 4.3.3 Porbeagle Shark ................................................................................................................................ 203 4.3.4 Roughhead Grenadier........................................................................................................................ 203 4.3.5 Beluga Whale..................................................................................................................................... 204 4.3.6 Sowerby’s Beaked Whale .................................................................................................................. 205 4.3.7 Harbour Porpoise ............................................................................................................................... 205 4.3.8 Walrus ................................................................................................................................................ 206 4.3.9 Bowhead Whale ................................................................................................................................. 207 4.3.10 Data Constraints for COSEWIC Status Species................................................................................ 208 4.3.11 Planning implications for COSEWIC Species.................................................................................... 210 4.4 Macrophytic Algal Communities..........................................................................................210 4.4.1 Littoral Community ............................................................................................................................. 210 4.4.2 Sublittoral Community ........................................................................................................................ 211 4.4.3 Data Constraints for Macrophytic Algal Communities ....................................................................... 212 4.4.4 Planning Implications for Macrophytic Algal Communities ................................................................ 213 4.5 Plankton ..............................................................................................................................213 4.5.1 Phytoplankton .................................................................................................................................... 213 4.5.2 Epontic Community ............................................................................................................................ 218 4.5.3 Microflora ........................................................................................................................................... 223 4.5.4 Zooplankton ....................................................................................................................................... 224 4.5.5 Significance of Oceanic Conditions Variability................................................................................... 225 4.5.6 Data Constraints for Plankton ............................................................................................................ 226 4.5.7 Planning Consideration for Plankton.................................................................................................. 227 4.6 Benthic Invertebrates ..........................................................................................................227 4.6.1 Data Constraints Associated with Benthic Invertebrate Communities............................................... 229 4.6.2 Planning Implications for Benthic Invertebrates................................................................................. 230 4.7 Deep Sea Corals.................................................................................................................230 4.7.1 Data Constraints for Corals................................................................................................................ 237 4.7.2 Planning Implications for Corals ........................................................................................................ 238 4.8 Fish .....................................................................................................................................238 4.8.1 Iceland Scallops ................................................................................................................................. 240 4.8.2 Snow Crab ......................................................................................................................................... 240


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4.8.3 Northern Shrimp................................................................................................................................. 241 4.8.4 Redfish ............................................................................................................................................... 241 4.8.5 American Plaice ................................................................................................................................. 243 4.8.6 Greenland Halibut .............................................................................................................................. 244 4.8.7 Atlantic Salmon .................................................................................................................................. 245 4.8.8 Arctic Char ......................................................................................................................................... 245 4.8.9 Sand Lance ........................................................................................................................................ 247 4.8.10 Capelin ............................................................................................................................................... 247 4.8.11 Herring................................................................................................................................................ 248 4.8.12 Arctic Cod........................................................................................................................................... 249 4.8.13 Rock Cod ........................................................................................................................................... 249 4.8.14 Witch Flounder ................................................................................................................................... 250 4.8.15 Skate .................................................................................................................................................. 250 4.8.15.1 Thorny Skate ...................................................................................................................................250 4.8.15.2 Smooth Skate ..................................................................................................................................251 4.8.16 Demersal Sharks................................................................................................................................ 251 4.8.16.1 Spiny Dogfish...................................................................................................................................251 4.8.16.2 Black Dogfish...................................................................................................................................252 4.8.17 Lumpfish............................................................................................................................................. 252 4.8.18 Whelk ................................................................................................................................................. 253 4.8.19 Toad Crab .......................................................................................................................................... 253 4.8.20 Porcupine Crab .................................................................................................................................. 253 4.8.21 Data Constraints for Fish ................................................................................................................... 254 4.8.22 Planning Implications for Fish ............................................................................................................ 255 4.9 Marine Mammals and Sea Turtles ......................................................................................256 4.9.1 Mysticetes .......................................................................................................................................... 256 4.9.1.1 Humpback Whale ............................................................................................................................256 4.9.1.2 Minke Whale ....................................................................................................................................257 4.9.1.3 Sei Whale ........................................................................................................................................257 4.9.2 Odontocetes....................................................................................................................................... 259 4.9.2.1 Long-finned Pilot Whale ..................................................................................................................259 4.9.2.2 Atlantic White-sided Dolphin............................................................................................................259 4.9.2.3 Killer Whales....................................................................................................................................259 4.9.3 Pinnipeds ........................................................................................................................................... 261 4.9.3.1 Harbour Seals..................................................................................................................................261 4.9.3.2 Harp Seal.........................................................................................................................................261 4.9.3.3 Hooded Seal ....................................................................................................................................262 4.9.3.4 Bearded Seal ...................................................................................................................................262 4.9.3.5 Grey Seal.........................................................................................................................................263 4.9.3.6 Ringed Seal .....................................................................................................................................263 4.9.4 Sea Turtles......................................................................................................................................... 265 4.9.5 Polar Bear .......................................................................................................................................... 265 4.9.6 Data Constraints for Marine Mammals and Sea Turtles.................................................................... 267 4.9.7 Planning Implications for Marine Mammals and Sea Turtles............................................................. 268 4.9.8 Marine Birds ....................................................................................................................................... 268 4.9.9 Seabirds ............................................................................................................................................. 269 4.9.9.1 Seabird Foraging Ecology and Diet.................................................................................................269 4.9.9.2 Seabird Distributions, Nesting Populations and Breeding Biology..................................................271


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4.9.10 Waterfowl, Loons and Grebes ........................................................................................................... 273 4.9.10.1 Foraging Strategies and Prey..........................................................................................................273 4.9.10.2 Distributions, Nesting Populations and Breeding Biology ...............................................................275 4.9.11 Shorebirds.......................................................................................................................................... 275 4.9.11.1 Shorebird Foraging Strategies and Prey .........................................................................................276 4.9.11.2 Shorebird Distributions, Nesting Populations and Breeding Biology...............................................276 4.9.12 Data Constraints for Marine Birds...................................................................................................... 276 4.9.13 Planning Implications for Marine Birds............................................................................................... 277 4.10 Commercial and Traditional Fisheries.................................................................................278 4.10.1 Data and Information Sources ........................................................................................................... 278 4.10.2 Historical Overview ............................................................................................................................ 280 4.10.2.1 Seasonality ......................................................................................................................................286 4.10.2.2 Fishing Vessels................................................................................................................................286 4.10.2.3 Fishing Gear ....................................................................................................................................287 4.10.2.4 Management Areas .........................................................................................................................289 4.10.3 Principal Species Fisheries................................................................................................................ 290 4.10.3.1 Atlantic Cod .....................................................................................................................................290 4.10.3.2 Redfish.............................................................................................................................................299 4.10.3.3 Herring .............................................................................................................................................302 4.10.3.4 Iceland Scallop ................................................................................................................................302 4.10.3.5 Snow Crab .......................................................................................................................................305 4.10.3.6 Northern Shrimp ..............................................................................................................................310 4.10.3.7 Greenland Halibut............................................................................................................................319 4.10.3.8 Arctic char........................................................................................................................................326 4.10.3.9 Atlantic Salmon................................................................................................................................328 4.10.3.10 Witch Flounder.................................................................................................................................336 4.10.3.11 Roughhead Grenadier .....................................................................................................................336 4.10.3.12 Rock Cod .........................................................................................................................................337 4.10.3.13 Emerging Fisheries..........................................................................................................................337 4.10.3.14 Fisheries and Oceans Canada Science Surveys ............................................................................340 4.10.4 Aquaculture ........................................................................................................................................ 341 4.10.5 Underused Fish and Shellfish Species .............................................................................................. 341 4.10.6 Country Food Harvesting ................................................................................................................... 341 4.10.6.1 Fisheries Management with “The Zone”..........................................................................................344 4.10.7 Data Constraints for Commercial Fisheries ....................................................................................... 345 4.10.7.1 Atlantic Cod .....................................................................................................................................345 4.10.7.2 Iceland Scallop ................................................................................................................................346 4.10.7.3 Skate................................................................................................................................................346 4.10.7.4 Witch Founder .................................................................................................................................346 4.10.7.5 Greenland Halibut............................................................................................................................346 4.10.7.6 Arctic char........................................................................................................................................346 4.10.8 Planning Implications for Commercial and Traditional Fisheries....................................................... 346 4.11 Sensitive Areas ...................................................................................................................347 4.11.1 Regulatory Framework....................................................................................................................... 347 4.11.2 National Marine Conservation Areas ................................................................................................. 349 4.11.2.1 Data Constraints for National Marine Conservation Areas .............................................................351 4.11.2.2 Planning implications for National Marine Conservation Areas ......................................................351 4.11.3 Battle Harbour .................................................................................................................................... 352


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4.11.4 Gilbert Bay ......................................................................................................................................... 352 4.11.4.1 Data Constraints for Gilbert Bay......................................................................................................354 4.11.4.2 Planning Consideration for Gilbert Bay ...........................................................................................354 4.11.5 Hawke Channel – Hamilton Bank ...................................................................................................... 354 4.11.5.1 Other Labrador Shelf SEA Area Banks ...........................................................................................356 4.11.5.2 Data Constraints for Labrador Shelf Banks Including Hawke Channel-Hamilton Bank ..................356 4.11.5.3 Planning Implications for Labrador Shelf Banks Including Hawke Channel-Hamilton Bank...........358 4.11.6 National Parks.................................................................................................................................... 358 4.11.6.1 Torngat Mountains...........................................................................................................................358 4.11.6.2 Mealy Mountains..............................................................................................................................359 4.11.6.3 Planning Implications For National Parks........................................................................................359 4.11.7 Coral Conservation Priority Area ....................................................................................................... 359 4.11.8 The Gannet Islands Ecological Reserve............................................................................................ 360 4.11.9 Important Bird Areas .......................................................................................................................... 360 4.11.9.1 Data Constraints for Gannett Islands and Other Important Bird Areas...........................................363 4.11.9.2 Planning Implications for Gannett Islands and Other Important Bird Areas....................................363

5.0 POTENTIAL ENVIRONMENTAL EFFECTS AND PLANNING IMPLICATIONS FROM EXPLORATION AND PRODUCTION ACTIVITIES .............................................................365

5.1 Sound and Noise Effects.....................................................................................................365 5.1.1 Species at Risk .................................................................................................................................. 366 5.1.1.1 Marine Fish ......................................................................................................................................366 5.1.1.2 Marine Mammals .............................................................................................................................366 5.1.1.3 Marine Birds.....................................................................................................................................367 5.1.2 Marine Fish ........................................................................................................................................ 368 5.1.2.1 Invertebrates....................................................................................................................................368 5.1.2.2 Fish ..................................................................................................................................................370 5.1.3 Marine Mammals and Sea Turtles ..................................................................................................... 376 5.1.3.1 Acoustic Environment......................................................................................................................376 5.1.3.2 Sound Types and Potential Effects .................................................................................................377 5.1.3.3 Sound Exposure Level and Sound Pressure Level.........................................................................379 5.1.3.4 Seismic Surveys ..............................................................................................................................380 5.1.3.5 Exploratory and Delineation Drilling ................................................................................................380 5.1.3.6 Vessel and Aircraft Traffic ...............................................................................................................381 5.1.3.7 Effects of Noise................................................................................................................................381 5.1.3.8 Effect of Noise on Baleen Whales...................................................................................................384 5.1.3.9 Effect of Noise on Toothed Whales.................................................................................................386 5.1.3.10 Effect of Noise on Pinnipeds ...........................................................................................................387 5.1.3.11 Effect of Noise on Sea Turtles.........................................................................................................388 5.1.4 Marine Birds ....................................................................................................................................... 389 5.1.4.1 Seismic Activities .............................................................................................................................389 5.1.4.2 Vessel and Air Traffic ......................................................................................................................389 5.1.5 Commercial Fisheries ........................................................................................................................ 390 5.1.6 Sensitive Areas .................................................................................................................................. 390 5.1.7 Mitigations .......................................................................................................................................... 391 5.1.8 Data Constraints Associated with Sound and Noise Effects ............................................................. 392 5.1.9 Planning Considerations for Sound and Noise effects ...................................................................... 392 5.2 Drill Cuttings Discharges Associated with Exploration and Production Activities................393


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5.2.1 Offshore Waste Treatment Guidelines Pertaining to Drill Cuttings.................................................... 393 5.2.2 Newfoundland Experience with Drill Cuttings .................................................................................... 393 5.2.2.1 Drill Cuttings Models........................................................................................................................394 5.2.2.2 Drill cuttings Dispersion and Deposition..........................................................................................395 5.2.3 Species at Risk .................................................................................................................................. 396 5.2.4 Invertebrates ...................................................................................................................................... 396 5.2.4.1 Water-based Muds and Cuttings .....................................................................................................396 5.2.4.2 Synthetic-based Muds and Cuttings................................................................................................398 5.2.5 Fish..................................................................................................................................................... 399 5.2.5.1 Water-based Muds and Cuttings .....................................................................................................399 5.2.5.2 Synthetic-based Muds and Cuttings................................................................................................399 5.2.6 Commercial Fisheries ........................................................................................................................ 400 5.2.7 Marine Birds ....................................................................................................................................... 400 5.2.8 Marine Mammals and Sea Turtles ..................................................................................................... 400 5.2.9 Sensitive Areas .................................................................................................................................. 400 5.2.10 Mitigations .......................................................................................................................................... 400 5.2.11 Data Constraints Associated with Drill Cuttings Discharge ............................................................... 401 5.2.12 Planning Considerations Associated with Drill Cuttings Discharge ................................................... 401 5.3 Routine Discharges.............................................................................................................401 5.3.1 Species at Risk .................................................................................................................................. 403 5.3.2 Invertebrates ...................................................................................................................................... 403 5.3.3 Fish..................................................................................................................................................... 404 5.3.4 Marine Mammals and Sea Turtles ..................................................................................................... 405 5.3.5 Marine Birds ....................................................................................................................................... 405 5.3.6 Commercial Fisheries ........................................................................................................................ 405 5.3.7 Sensitive Areas .................................................................................................................................. 406 5.3.8 Mitigations .......................................................................................................................................... 406 5.3.9 Data Constraints Associated with Routine Discharges...................................................................... 407 5.3.10 Planning Considerations Associated with Routine Discharges ......................................................... 407 5.4 Air Emissions and Climate Change.....................................................................................407 5.4.1.1 Climate Change...............................................................................................................................407 5.4.1.2 Data Gaps Associated with Air Emissions and Climate Change ....................................................409 5.4.1.3 Planning Considerations associated with Air Emissions and Climate Change...............................409 5.5 Existing Anthropogenic Disturbances in the Labrador Shelf Strategic Environmental

Assessment Area ................................................................................................................409 5.6 Accidental Events................................................................................................................410 5.6.1 Effects of Oil Spills on Shorelines ...................................................................................................... 410 5.6.1.1 Species at Risk................................................................................................................................413 5.6.1.2 Macrophyic Algae ............................................................................................................................413 5.6.1.3 Phytoplankton..................................................................................................................................414 5.6.1.4 Epontic Communities.......................................................................................................................414 5.6.1.5 Microbiota ........................................................................................................................................415 5.6.1.6 Zooplankton .....................................................................................................................................415 5.6.1.7 Invertebrates....................................................................................................................................415 5.6.1.8 Fish ..................................................................................................................................................417 5.6.1.9 Commercial Fisheries......................................................................................................................418 5.6.1.10 Marine Birds.....................................................................................................................................418 5.6.1.11 Marine Mammals and Sea Turtles...................................................................................................421


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5.6.1.12 Sensitive Areas................................................................................................................................423 5.6.2 Collisions............................................................................................................................................ 424 5.6.3 Mitigations .......................................................................................................................................... 424 5.6.3.1 Oil Spills...........................................................................................................................................425 5.6.3.2 Vessel Collisions..............................................................................................................................425 5.6.4 Data Constraints Associated with Accidental Events ........................................................................ 425 5.6.5 Planning Implications for Accidental Events ...................................................................................... 426 5.7 Attraction to Lights/Flares ...................................................................................................426 5.8 Cumulative Environmental Effects ......................................................................................427 5.8.1 Marine Transportation........................................................................................................................ 427 5.8.1.1 Labrador Ferry Services ..................................................................................................................428 5.8.1.2 Fuel Transportation .........................................................................................................................428 5.8.1.3 General Cargo and Barge Towing...................................................................................................428 5.8.1.4 Mining ..............................................................................................................................................430 5.8.2 Commercial Fisheries ........................................................................................................................ 431 5.8.3 Traditional Resource Use by Aboriginal People ................................................................................ 431 5.8.4 Tourism and Recreation..................................................................................................................... 431 5.8.4.1 Cruise Tourism ................................................................................................................................432 5.8.4.2 Tour Boats .......................................................................................................................................433 5.8.4.3 Local Personal Boating....................................................................................................................433 5.8.4.4 Visitor Personal Boating ..................................................................................................................433 5.8.4.5 Ecotourism.......................................................................................................................................434 5.8.4.6 Prehistoric and Historic Resources .................................................................................................434 5.8.5 Exploration and Production Activities................................................................................................. 435 5.9 Cumulative Environmental Effects Interactions...................................................................435 5.9.1 Exploration and Production Activities................................................................................................. 435 5.9.2 Exploration and Production Activities in Greenland........................................................................... 437 5.9.3 Commercial Fisheries ........................................................................................................................ 438 5.9.4 Marine Transportation........................................................................................................................ 438 5.9.5 Tourism, Recreation and Traditional Resource Use.......................................................................... 438 5.10 Effects of the Environment on the Project ...........................................................................439 5.10.1 Metaocean Conditions ....................................................................................................................... 439 5.10.2 Geology.............................................................................................................................................. 440 5.10.3 Ice Conditions .................................................................................................................................... 440 5.10.4 Planning Implications from Effects of the Environment on the Project .............................................. 440 5.10.4.1 Geology ...........................................................................................................................................441 5.10.4.2 Metocean Conditions.......................................................................................................................441 5.10.4.3 Ice Conditions ..................................................................................................................................442

6.0 SUMMARY AND CONCLUSIONS ........................................................................................443 6.1 Applicable Legislation .........................................................................................................443 6.2 Sensitive Areas ...................................................................................................................444 6.3 Potential Issues...................................................................................................................445 6.4 Data Constraints .................................................................................................................446 6.5 Addressing Data Constraints ..............................................................................................448 6.6 Planning Considerations .....................................................................................................449 6.7 Mitigation Measures ............................................................................................................450


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6.7.1 Seismic Surveys................................................................................................................................. 452 6.7.2 Drilling Programs................................................................................................................................ 453 6.7.3 Accidental Events............................................................................................................................... 453 6.8 Conclusion ..........................................................................................................................454

7.0 REFERENCES ......................................................................................................................456 7.1 Personal Communications ..................................................................................................456 7.2 Traditional Knowledge Interviews and Public Consultations...............................................456 7.2.1 Traditional Knowledge Interviews ...................................................................................................... 456 7.2.2 Public Consultations – Round One.................................................................................................... 457 7.2.3 Public Consultations – Round Two.................................................................................................... 457 7.3 References..........................................................................................................................457 7.4 Internet Sites .......................................................................................................................514

List of Appendices

Appendix A Strategic Environmental Assessment LabradorOffshore Area Scoping Document (C-NLOPB 2006e)

Appendix B Letter of Introduction to the Labrador Shelf SEA Process to Aboriginal Groups and Regulatory Agencies

Appendix C Notices of Public Meetings and List of Stakeholders Appendix D Labrador Shelf SEA Information Brochure Appendix E Public Consultation Session Minutes: round One - 2007; Round Two - 2008 Appendix F Principle and Process for Traditional Knowledge Collection Appendix G Traditional Knowledge Minutes

List of Figures

Figure 1.1 Labrador Shelf Offshore Area Strategic Environment Assessment Area ....................2 Figure 1.2 Drilling History in Labrador Shelf Strategic Environmental Assessment Area

(1970 to 1983) .............................................................................................................8 Figure 1.3 Labrador Shelf Strategic Environmental Assessment Area Exploration Wells

and Related Gas Resources .......................................................................................8 Figure 1.4 Labrador Shelf Strategic Environmental Assessment Area Seismic Acquisition

Data (kms)...................................................................................................................9 Figure 2.1 Schematic of Seismic Survey Operations .................................................................13 Figure 2.2 Typical Drilling Platforms...........................................................................................15 Figure 2.3 Glory Hole .................................................................................................................20 Figure 2.4 Ice Gouge and Subgouge Deformation.....................................................................23 Figure 2.5 Air Pressure Signature ..............................................................................................33 Figure 2.6 Estimated One-third Octave Sound Levels of Underwater Noise at 1 m for A)

Boats; and B) Ships...................................................................................................37 Figure 2.7 Drill String Components Illustrating Drill Mud Circulation ..........................................39 Figure 2.8 Spill Frequencies (1965 to 2000) in the Gulf of Mexico.............................................56


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Figure 2.9 Number of Exploration Well and Spill Incidents, Offshore Newfoundland and Labrador (1997 to 2007)............................................................................................58

Figure 2.10 Exploration and Production Spill Volumes, Offshore Newfoundland and Labrador (1997 to 2007)............................................................................................59

Figure 2.11 Subsea Blowout Schematic.......................................................................................62 Figure 2.12 Plume Behaviour Schematic .....................................................................................63 Figure 2.13 Labrador Surface Water Currents .............................................................................68 Figure 2.14 Winter Trajectories: Average Winds..........................................................................72 Figure 2.15 Spring Trajectories: Average Winds..........................................................................72 Figure 2.16 Summer Trajectories: Average Winds.......................................................................73 Figure 2.17 Fall Trajectories: Average Winds...............................................................................73 Figure 2.18 East Wind Trajectories: All Wind Speeds..................................................................74 Figure 2.19 Framework for Strategic Ice Management Operations..............................................79 Figure 2.20 Icebreaking using Circular Technique .......................................................................80 Figure 2.21 Radial Grid “Picket Boat” Ice Breaking Technique ....................................................81 Figure 2.22 Pushing Large Rough Floes at Right Angles to the Drift Line ...................................81 Figure 2.23 Single Vessel Single Towline Deployment ................................................................82 Figure 2.24 Dual Vessel Ice Island Towing ..................................................................................82 Figure 2.25 Single and Dual Vessel Net Towing ..........................................................................83 Figure 2.26 Iceberg Deflection Using Bow-mounted Water Cannon............................................83 Figure 2.27 Propeller Washing .....................................................................................................84 Figure 2.28 Illustration of Ice Management Zone Around a Drilling or Production Facility ...........85 Figure 3.1 Labrador Shelf Surficial Sediments by Soil Type ......................................................88 Figure 3.2 Labrador Shelf Surficial Sediments by Geological Unit .............................................88 Figure 3.3 Sample Description of Herjolf Site Vibro-core ...........................................................91 Figure 3.4 Stratigraphic Section Through Central Labrador Hopedale Saddle, Nain Bank

and the Marginal Trough ...........................................................................................92 Figure 3.5 Composite Analysis and Corresponding Huntec DTS Profile of Deposits from

Hopedale Saddle.......................................................................................................93 Figure 3.6 Composite Analysis and Corresponding Huntec DTS Profile of Bank-top

Muddy Sands ............................................................................................................95 Figure 3.7 Composite Analysis and Corresponding Huntec DTS Profile of Saglek Bank,

Northern Labrador Shelf ............................................................................................96 Figure 3.8 Composite Analysis and Corresponding Huntec DTS Profile of Southwestern

Nain Bank, Central Labrador Shelf............................................................................97 Figure 3.9 Composite Analysis and Corresponding Huntec DTS Profile of Hopedale

Saddle, Central Labrador Shelf .................................................................................98 Figure 3.10 Composite Analysis and Corresponding Huntec DTS Profile of Hamilton Bank,

South Labrador Shelf ................................................................................................99 Figure 3.11 Composite Analysis and Corresponding Huntec DTS Profile of the Marginal

Trough, Central Labrador Shelf ...............................................................................100 Figure 3.12 Composite Analysis and Corresponding Huntec DTS Profile of Hopedale

Saddle, Central Labrador Shelf ...............................................................................101 Figure 3.13 Locations of Recent Huntec Shallow Seismic Data and Recovered Seabed

Samples ..................................................................................................................102 Figure 3.14 Seismic Hazard Map – 2005 National Building Code of Canada ............................103


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Figure 3.15 Mesozoic Rifting of the Arctic and Atlantic Margins.................................................104 Figure 3.16 Labrador Sea Bathymetry for the SEA Area............................................................105 Figure 3.17 Location Map of Labrador Shelf Indicating Main Features ......................................106 Figure 3.18 Hopedale Run Channel passing through Inner Shelf ..............................................107 Figure 3.19 Bathymetry Indication of Presence of Channels Passing through Inner Shelf ........108 Figure 3.20 Seasonal Sea Surface Temperature Plots ..............................................................110 Figure 3.21 Seasonal Salinity Plots............................................................................................111 Figure 3.22 MSC50 Grid Point Locations ...................................................................................112 Figure 3.23 Mean and Maximum Monthly Significant Wave Height by Grid Point .....................116 Figure 3.24 Mean and Maximum Monthly Wind Speed by MSC50 Grid Point ...........................120 Figure 3.25 General Ocean Circulation ......................................................................................121 Figure 3.26 Mean Surface Current Field ....................................................................................123 Figure 3.27 Current Meter Mooring Locations............................................................................126 Figure 3.28 Location of Weather Stations in SEA Area..............................................................128 Figure 3.29 Location of Sub-regions and Offshore Weather Station (OWS Bravo) Used for

Visibility and Wind-chill Characteristics in the SEA Area.........................................129 Figure 3.30 Mean, Minimum and Maximum Monthly Temperature for Weather Stations

within Labrador Shelf SEA Area..............................................................................133 Figure 3.31 Wind-chill Plots ........................................................................................................134 Figure 3.32 Visibility using Shipping Criteria ..............................................................................135 Figure 3.33 Visibility using Flying Criteria...................................................................................136 Figure 3.34 Mean Number of Weeks per Year that Pack Ice is Present ....................................138 Figure 3.35 Mean Monthly Pack Ice Concentration When Present for January .........................139 Figure 3.36 Mean Monthly Pack Ice Concentration When Present for February .......................140 Figure 3.37 Mean Monthly Pack Ice Concentration When Present for March............................141 Figure 3.38 Mean Monthly Pack Ice Concentration When Present for April...............................142 Figure 3.39 Mean Monthly Pack Ice Concentration When Present for May ...............................143 Figure 3.40 Mean Monthly Pack Ice Concentration When Present for June ..............................144 Figure 3.41 Mean Monthly Pack Ice Concentration When Present for July ...............................145 Figure 3.42 Mean Monthly Pack Ice Concentration When Present for August...........................146 Figure 3.43 Mean Monthly Pack Ice Concentration When Present for September ....................147 Figure 3.44 Mean Monthly Pack Ice Concentration When Present for October .........................148 Figure 3.45 Mean Monthly Pack Ice Concentration When Present for November .....................149 Figure 3.46 Mean Monthly Pack Ice Concentration When Present for December .....................150 Figure 3.47 Iceberg Sightings in Strategic Environmental Assessment Area by International

Ice Patrol and Provincial Aerospace Ltd..................................................................156 Figure 3.48 Iceberg Densities Based on International Ice Patrol Surveys..................................157 Figure 3.49 Annual Average Annual Iceberg Areal Density Based on CIS Charts.....................158 Figure 3.50 Mean Iceberg Drift Vectors from Canadian Ice Service Iceberg Drift Model ...........160 Figure 3.51 Combined Waterline Length Datasets Compared with International Ice Patrol

Size Class Observations and Grand Banks Waterline Length Distribution .............162 Figure 3.52 Iceberg Scouring Through Fine-grained Sediment, with Some Characteristic

Features Indicated...................................................................................................165 Figure 3.53 Location of 2003 Surveys and Previous Survey Sites.............................................166 Figure 3.54 Combined Scour Depth Distribution and Scour Depth Distributions by Site ...........167


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Figure 3.55 Scour Depth Distributions by Sediment Type..........................................................168 Figure 3.56 Distribution of Scour Length for Various Sites.........................................................170 Figure 3.57 Distribution of Scour Orientation for Various Sites ..................................................171 Figure 3.58 Repetitive Mapping Analysis of Environmental Studies Research Fund Mosaic ....171 Figure 3.59 Modelled Iceberg Grounding Rates Over the Central Portion of the Strategic

Environmental Assessment Area ............................................................................176 Figure 4.1 Location of Banks within the Labrador Shelf Strategic Environmental

Assessment Area ....................................................................................................179 Figure 4.2 Northern Wolffish Distribution, 1980 to 2001...........................................................183 Figure 4.3 Spotted Wolffish Distribution, 1980 to 2001 ............................................................183 Figure 4.4 Atlantic (Striped) Wolffish Distribution, 1980 to 2001 ..............................................184 Figure 4.5 Blue Whale Observations (1975 to 2004) near the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................187 Figure 4.6 Fin Whale Observations (1945 to 2005) within the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................190 Figure 4.7 Map of Breeding, Wintering and Moulting Grounds of the Harlequin Duck in the

Labrador Shelf Strategic Environmental Assessment Area.....................................192 Figure 4.8 Bird Species at Risk Survey Observations (1966 to 2007) within the Labrador

Shelf Strategic Environmental Assessment Area....................................................194 Figure 4.9 Spring Chlorophyll a Concentrations in the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................219 Figure 4.10 Summer Chlorophyll a Concentrations in the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................220 Figure 4.11 Autumn Chlorophyll a Concentrations in the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................221 Figure 4.12 Winter Chlorophyll a Concentrations in the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................222 Figure 4.13 Coral Distribution in Northern Labrador Shelf SEAArea..........................................230 Figure 4.14 Coral Distribution in Southern Labrador Shelf Strategic Environmental

Assessment Area ....................................................................................................231 Figure 4.15 Density of Corals Along the Labrador Coast ...........................................................232 Figure 4.16 Coral Species Richness, 2003 to 2005 ...................................................................233 Figure 4.17 Distribution of Large Gorgonians Along the Labrador Coast...................................235 Figure 4.18 Distribution of Soft Corals Along the Labrador Coast..............................................236 Figure 4.19 Coral Species Richness within the Southeastern Region of the Labrador Shelf

Strategic Environmental Assessment Area .............................................................237 Figure 4.20 Northwest Atlantic Fisheries Organization Divisions ...............................................239 Figure 4.21 Redfish Species Distribution in the Labrador Shelf Strategic Environmental

Assessment Area ....................................................................................................242 Figure 4.22 Migration of Adult Atlantic Salmon Between Eastern North America and

Labrador ..................................................................................................................246 Figure 4.23 Baleen Whale Observations (1967–2006) in the Labrador Shelf Strategic

Environmental Assessment Area ............................................................................258 Figure 4.24 Toothed Whale Observations (1971-2006) in Labrador Shelf Strategic

Environmental Assessment Area ............................................................................260


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Figure 4.25 Polar Bear Observations (1991-1997) within the Labrador Shelf Strategic Environmental Assessment Area ............................................................................266

Figure 4.26 Seabird Records (1994-2005) from the Strategic Environmental Assessment Area, including Alcids, Storm-petrels, Fulmars and Shearwaters ...........................272

Figure 4.27 Terns, Gulls (including Kittiwakes) Records (1994-2005) from the Strategic Environmental Assessment Area ............................................................................274

Figure 4.28 Labrador Shelf Strategic Environmental Assessment Area and Northwest Atlantic Fisheries Organization Divisions 2GHJ ......................................................279

Figure 4.29 Northwest Atlantic Fisheries Organization 2GHJ Harvest, 1985 to 2004, Foreign and Domestic .............................................................................................281

Figure 4.30 Strategic Environmental Assessment Area Unit Areas Composition of Harvest, 1986 and 2005 ........................................................................................................281

Figure 4.31 Strategic Environmental Assessment Area Unit Areas, Relative Quantity of Harvest ....................................................................................................................284

Figure 4.32 Strategic Environmental Assessment Area and Georeferenced Harvest Locations, 2004 to 2006 ..........................................................................................285

Figure 4.33 NAFO Unit Areas 2GHJ Average Monthly Harvest, 2004 to 2006 ..........................286 Figure 4.34 Distribution of Shrimp, Crab and Groundfish Fisheries in the Strategic

Environmental Assessment Area ............................................................................290 Figure 4.35 Northwest Atlantic Fisheries Organizations Unit Areas 2J3KL Total Allowable

Catches and Landings (thousands of tons) in 1959 to 2006 for Atlantic Cod..........291 Figure 4.36 Atlantic Cod Offshore Biomass Index in 2J3KL.......................................................293 Figure 4.37 Atlantic Cod Annual Mortality Rate (proportion dying) Calculated in Offshore of

2J3KL ......................................................................................................................293 Figure 4.38 Atlantic Cod Standardized Catch Rates from Sentinel Surveys Using Gillnets

(5.5-inch mesh) .......................................................................................................294 Figure 4.39 Atlantic Cod Standardized Catch Rates from Sentinel Small Mesh (3.25-inch)

Gillnet Surveys ........................................................................................................294 Figure 4.40 Atlantic Cod Median Gillnet Catch Rates from Fixed Gear Logbooks.....................295 Figure 4.41 Northwest Atlantic Fisheries Organizations Unit Areas 2GH Landings

(thousands of tons) in 1953 to 2000 for Atlantic Cod ..............................................296 Figure 4.42 2GH Atlantic Cod Offshore Biomass Index .............................................................297 Figure 4.43 Strategic Environmental Assessment Area Unit Areas Atlantic Cod Harvest by

Month, 2004 to 2006 Average .................................................................................297 Figure 4.44 Georeferenced Atlantic Cod Harvesting Locations, 2004 to 2006...........................298 Figure 4.45 Research Vessel Biomass Index for Redfish in Divisions 2J3K..............................299 Figure 4.46 Percentage of Redfish Landings for Northwest Atlantic Fisheries Organization

Divisions 2GHJ........................................................................................................300 Figure 4.47 Strategic Environmental Assessment Area Unit Areas Redfish Harvest by

NAFO Division, 2003 to 2006 Average Including Discards .....................................300 Figure 4.48 Georeferenced Redfish Harvesting Locations, 2004 to 2006..................................301 Figure 4.49 Strategic Environmental Assessment Area Unit Areas Scallop Harvest by

NAFO Division, (2004 to 2006)................................................................................303 Figure 4.50 Georeferenced Iceland Scallop Harvesting Locations, (2004 to 2006) ...................304 Figure 4.51 Snow Crab Total Allowable Catch, Landings, and Fishing Effort Trends in

Division 2J ...............................................................................................................305


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Figure 4.52 Snow Crab Commercial Catch per Unit Area Trends in Relation to the Long-term Average (dotted line) for Division 2J ...............................................................306

Figure 4.53 Snow Crab 2J Pre-recruit Indices Trends................................................................307 Figure 4.54 Trends in Mortality Indices and in the Percentage of the Catch Discarded in

the Fishery for Division 2J Snow Crab. ...................................................................307 Figure 4.55 Strategic Environmental Assessment Area Unit Areas Snow Crab Harvest by

Month, 2004 to 2006 Average .................................................................................308 Figure 4.56 Georeferenced Snow Crab Harvesting Locations, 2004 to 2006 ............................309 Figure 4.57 Percentage of Northern Shrimp Landings for Northwest Atlantic Fisheries

Organization Divisions 2GHJ, 2004 to 2006............................................................310 Figure 4.58 Strategic Environmental Assessment Area Unit Areas Northern Shrimp Harvest

by Month, 2004 to 2006 Average ............................................................................311 Figure 4.59 Georeferenced Northern Shrimp Harvesting Locations, 2004 to 2006....................312 Figure 4.60 Shrimp Fishing Area 4 (Northwest Atlantic Fisheries Organization Unit Area

2G) Northern Shrimp Catches (t).............................................................................313 Figure 4.61 Shrimp Fishing Area 4 Large Vessel Catch per Unit Area ......................................314 Figure 4.62 Shrimp Fishing Area 5 (Northwest Atlantic Fisheries Organization Unit Area

2H) Northern Shrimp Catches (t).............................................................................314 Figure 4.63 Shrimp Fishing Area 5 Large Vessel catch per Unit Area .......................................315 Figure 4.64 Shrimp Recruitment Index for the Period 1997 to 2005 (Cartwright Channel

research survey data)..............................................................................................315 Figure 4.65 Shrimp Fishing Area 5 Exploitation Rate Indices Over the Period 1996 to 2005 ....316 Figure 4.66 Shrimp Fishing Area 6 (Northwest Atlantic Fisheries Organization Unit Area 2J)

Northern Shrimp Catches (t)....................................................................................316 Figure 4.67 Shrimp Fishing Area 6 Large and Small Vessel Catch per Unit Area .....................317 Figure 4.68 Shrimp Fishing Area 6 Biomass and Abundance Indices........................................318 Figure 4.69 Shrimp Fishing Area 6 Exploitation Rate Indices Over the Period 1996 to 2005 ....319 Figure 4.70 Percentage of Greenland Halibut Landings for Northwest Atlantic Fisheries

Organization Divisions 2GHJ, 2004 to 2006............................................................320 Figure 4.71 Strategic Environmental Assessment Area Unit Areas Greenland Halibut

Harvest by Month, 2004 to 2006 Average...............................................................320 Figure 4.72 Georeferenced Greenland Halibut Harvesting Locations, 2004 to 2006.................321 Figure 4.73 Catches (line) and Total Allowable Catch (triangle) of Greenland Halibut in

Sub-Area 2 and Divisions 3KLMNO ........................................................................322 Figure 4.74 Greenland Halibut Stratified Mean Weight per Tow Estimates (1978 to 2006) .......323 Figure 4.75 Campelen Stratified Mean Number and Weight (kg) per Tow of Greenland

Halibut (1978 to 2006).............................................................................................324 Figure 4.76 Mean Biomass (kg) per Tow of Greenland halibut (1978 to 2006)..........................325 Figure 4.77 Greenland Halibut By-catch for Northern Shrimp Fishery in Northwest Atlantic

Fisheries organization Subarea 2 and Division 3KL during 1996 to 2003...............326 Figure 4.78 Arctic char Complexes in Labrador Shelf SEA Area ...............................................327 Figure 4.79 Strategic Environmental Assessment Area Unit Areas Arctic char Harvest by

Month, 2004 to 2006 Average .................................................................................329 Figure 4.80 Trends in Abundance of Small and Large Atlantic Salmon in Labrador, 1969 to

2006 ........................................................................................................................330 Figure 4.81 Salmon Fishing Areas of Labrador ..........................................................................331


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Figure 4.82 Research Survey Biomass Index for Divisions 2J3K American Plaice (bars), 1978 to 2004, Log Scale (line) Shown on the Right ................................................332

Figure 4.83 Research Survey Abundance Estimates for Divisions 2J3K American Plaice, 1978 to 2004 (bars), Log Scale (line) Shown on the Right......................................333

Figure 4.84 Percentage of American Plaice Landings for Northwest Atlantic Fisheries Organization Divisions 2GHJ, 2004 to 2006............................................................333

Figure 4.85 Strategic Environmental Assessment Area Unit Areas American Plaice Harvest by Month, 2004 to 2006 Average ............................................................................334

Figure 4.86 Georeferenced American Plaice Harvesting Locations, 2004 to 2006....................335 Figure 4.87 Witch Flounder Biomass (tons) and Abundance (000's) for 2J, Fall Surveys .........336 Figure 4.88 Witch Flounder Mean Numbers and Weights (kg) per Tow for 2J Fall Surveys......336 Figure 4.89 Strategic Environmental Assessment Area Unit Areas Rock Cod Harvest by

Month, 2004 to 2006 Average .................................................................................337 Figure 4.90 Strategic Environmental Assessment Area Unit Areas Toad Crab Harvest by

Month, 2004 to 2006 Average .................................................................................338 Figure 4.91 Georeferenced Toad Crab Harvesting Locations, 2004 to 2006.............................339 Figure 4.92 Strategic Environmental Assessment Area Unit Areas Whelk Harvest by

Month, 2004 to 2006 Average .................................................................................340 Figure 4.93 Areas Identified as used for Country Food Harvesting Locales ..............................343 Figure 4.94 Sensitive Areas within the Labrador Shelf SEA Area..............................................348 Figure 4.95 Coral Conservation Priority Areas in Newfoundland and Labrador .........................357 Figure 4.96 Important Bird Areas within the Labrador Shelf Strategic Environmental

Assessment Area ....................................................................................................361 Figure 5.1 Source - Path - Receiver Model ..............................................................................365 Figure 5.2 Sound Pressure Threshold for the Onset of Fish Injuries........................................375 Figure 5.3 Schematic Representation of Zones of Potential Effects Associated with

Anthropogenic Sounds on Marine Mammals...........................................................383 Figure 5.4 Ferry Routes Between Communities in the Labrador Shelf Strategic

Environmental Assessment Area and the Ferry Route from the Area to Lewisporte in Newfoundland ...................................................................................429

Figure 5.5 Shipping Transportation to the Canadian Arctic Through the Labrador Sea...........430 Figure 5.6 Locations and Ports Visited by Cruise Ships in 2006 and 2007 in the Labrador

Shelf Environmental Assessment Area ...................................................................434 Figure 6.1 Sensitive Areas within the Strategic Environmental Assessment Area ...................451


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List of Tables

Table 2-1 Summary of Key Features of a Jack-up Rig and Semi-submersible .........................17 Table 2-2 Overall Glory Hole Dimensions .................................................................................21 Table 2-3 Regional Cetacean Acoustic Characteristics.............................................................29 Table 2-4 Comparison of Natural and Potential Exploration-related Noise Levels....................30 Table 2-5 Typical Drill Mud Components and Drill Cuttings Discharge Volume for a Grand

Banks Discharge Well ...............................................................................................40 Table 2-6 Composition of ParaDrill-IA .......................................................................................42 Table 2-7 Chemical Composition of Produced Water from Norwegian North Sea

Platforms ...................................................................................................................43 Table 2-8 Daily Criteria Air Contaminant Emissions for the Project Drilling unit

Consuming 100 Barrels of Fuel per Day ...................................................................46 Table 2-9 Annual Releases of Petroleum by Source Estimates (1990 to 1999)........................48 Table 2-10 Spill Size Categories .................................................................................................49 Table 2-11 Historical Large Oil Spills from Offshore Oil-Well Blowouts ......................................50 Table 2-12 Blowouts and Spillage from US Federal Offshore Wells, 1972 to 2006 ....................51 Table 2-13 Exploration Wells and Blowouts in US GOM OCS and North Sea, 1980 to 1997.....54 Table 2-14 Exploration Drilling Blowout Frequency for the US Gulf of Mexico and North

Sea (1980 to 1997)....................................................................................................54 Table 2-15 Exploration and Development Drilling Blowout Frequencies over Time....................55 Table 2-16 US OCS Platform Spills (1985 to 1999) ....................................................................56 Table 2-17 Predicted Number of Blowouts and Spills for the Labrador Shelf SEA Area

(1 well/yr) ...................................................................................................................57 Table 2-18 Spill Incidents, Offshore Newfoundland and Labrador, 1997 to 2007 .......................60 Table 2-19 Offshore Newfoundland and Labrador Spill Sizes, 1997 to 2007..............................61 Table 2-20 Average Wind Speeds and Direction ........................................................................69 Table 2-21 Time to Shore for Spills Moved by Easterly Winds in Open Water Conditions .........71 Table 3-1 MSC50 Grid Point Locations ...................................................................................112 Table 3-2 Grid Point 14986 Monthly Mean, Standard Deviation and Maximum Wave

Height ......................................................................................................................113 Table 3-3 Grid Point 14710 Monthly Mean, Standard Deviation and Maximum Wave







Height ......................................................................................................................115


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Table 3-10 Grid Point 12995 Monthly Mean, Standard Deviation and Maximum Wave Height ......................................................................................................................115

Table 3-11 Extreme 10-Year, 50-Year and 100-Year Significant Wave Heights.......................116 Table 3-12 Grid Point 14986 Monthly Mean, Standard Deviation and Maximum Wind

Speed ......................................................................................................................117 Table 3-13 Grid Point 14710 Monthly Mean, Standard Deviation and Maximum Wind








Speed ......................................................................................................................119 Table 3-21 10-Year, 50-Year and 100-Year Extreme Wind Speeds .........................................120 Table 3-22 Moored Current Meter Measurements on the Labrador Shelf and Slope prior to

1980 ........................................................................................................................124 Table 3-23 Moored Current Meter Measurements from Petro-Canada’s 1980 Summer

Program, July to October 1980, Average 70 Days Duration ...................................125 Table 3-24 Tidal Constituents M2 and S2 Offshore Labrador.....................................................127 Table 3-25 Monthly Air Temperatures for Saglek (1955 to 1958)..............................................129 Table 3-26 Monthly Air Temperatures for Hebron (1947 to 1957).............................................130 Table 3-27 Monthly Air Temperatures for Nutak (1948 to 1953) ...............................................130 Table 3-28 Monthly Air Temperatures for Nain (1926 to 2003) .................................................130 Table 3-29 Monthly Air Temperatures for Makkovik (1983 to 2003)..........................................131 Table 3-30 Monthly Air Temperatures for Hopedale (1942 to 1984) .........................................131 Table 3-31 Monthly Air Temperatures for Cape Harrison (1943 to 1961) .................................131 Table 3-32 Monthly Air Temperatures for Cartwright (1934 to 2003) ........................................132 Table 3-33 Monthly Air Temperatures for Mary’s Harbour (1983 to 1998) ................................132 Table 3-34 Basic Wind-chill Guidelines .....................................................................................133 Table 3-35 Sea Ice Drift Speed Data from Various Sources .....................................................151 Table 3-36 Floe Size Distribution for First Year Ice ...................................................................152 Table 3-37 Ice Thicknesses in Lake Melville and the Labrador Sea .........................................153 Table 3-38 Ice Keels with the 25 Largest Ice Drafts during the 2002/2003 Ice Season at

Makkovik Bank ........................................................................................................153 Table 3-39 Ice Keels with the 25 Largest Ice Drafts during the 2004/2005 Ice Season at

Makkovik Bank ........................................................................................................154 Table 3-40 Surface Areas of Multi-year Ice Floes .....................................................................154 Table 3-41 Iceberg Drift Characteristics from Wellsite Reports.................................................159


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Table 3-42 Size Class Data from International Ice Patrol Aerial Surveys..................................162 Table 3-43 Scour Features in Makkovik Data Analysis .............................................................166 Table 3-44 Types of Scour Features in Makkovik Scour Dataset..............................................166 Table 3-45 Variation in Scour Profile Depth with Water Depth..................................................167 Table 3-46 Variation in Mean Scour Profile Depth with Water Depth and Sediment Type........168 Table 3-47 Variation in Scour Width with Water Depth .............................................................169 Table 3-48 Scour Length Statistics by Site................................................................................169 Table 3-49 Scour Rise-up by Site..............................................................................................172 Table 3-50 Pit Depth and Effective Diameter Distributions as a Function of Water Depth........173 Table 3-51 Pit Depth by Soil Type.............................................................................................173 Table 3-52 Pit Incision Width by Soil Type ................................................................................173 Table 4-1 Species within the Labrador Shelf Strategic Environmental Assessment Area

with Species at Risk Act Schedule 1 Designations .................................................181 Table 4-2 Species within the Labrador Shelf Strategic Environmental Assessment Area

with Committee on the Status of Endangered Wildlife in Canada Designations .....200 Table 4-3 General Algal in Intertidal and Subtidal Areas in Coastal Labrador ........................212 Table 4-4 Common Phytoplankton in the Labrador Shelf Strategic Environmental

Assessment Area ....................................................................................................217 Table 4-5 Coral Species in the Labrador Shelf Strategic Environmental Assessment Area ...234 Table 4-6 Spawning Times of Commercial Fish and Shellfish Species in the Strategic

Environmental Assessment Area ............................................................................255 Table 4-7 Time of Year When Pelagic/Sensitive Life Stage is Present in the Water

Column within the Strategic Environmental Assessment Area................................256 Table 4-8 Marine-associated Bird Species Known From the Strategic Environmental

Assessment Area ....................................................................................................268 Table 4-9 Foraging Strategy and Diet for Seabirds Known in the Strategic Environmental

Assessment Area ....................................................................................................270 Table 4-10 Foraging Strategy and Diet for Waterfowl and Loons in the Strategic

Environmental Assessment Area ............................................................................273 Table 4-11 Domestic Harvest by Species, Strategic Environmental Assessment Area Unit

Areas, 2004 to 2006 Average..................................................................................282 Table 4-12 Domestic Harvests by Unit Area by Species, 2004 to 2006 Average......................283 Table 4-13 Domestic Harvests by Vessel Size, 2004 to 2006 Average ....................................286 Table 4-14 Domestic Harvests by Home Port Vessel, 2004 to 2006 Average ..........................287 Table 4-15 Harvest in NAFO Unit Areas 2GHJ by Gear Type, 2004 to 2006 Average .............288 Table 4-16 Catch of Atlantic Cod in Northwest Atlantic Fisheries Organization Division

2J3KL ......................................................................................................................291 Table 4-17 2J Atlantic Herring Quotas, 2007 ............................................................................302 Table 4-18 Marine Life Found in the Gilbert Bay Area ..............................................................353 Table 4-19 Fish Species in the Hawke Channel Region ...........................................................355 Table 4-20 Bird Species Known from the Important Bird Areas of Labrador.............................362 Table 5-1 Observation from Exposures of Marine Macro-invertebrates to Air Sleeves at

Close Range............................................................................................................370 Table 5-2 Observations of Exposures of Fish and Shellfish Planktonic Life Stages to

Seismic Airguns at Close Range.............................................................................373


Sikumiut Environmental Management Ltd. © 2008 August 2008 xxi

Table 5-3 Frequency Range and Duration of Sounds Produced by Several Species of Baleen Whales ........................................................................................................384

Table 5-4 Drill Mud and Cuttings Discharges Associated with Typical Drilling Scenarios.......394 Table 5-5 Produced Water Field Validation Data ....................................................................403 Table 5-6 Labrador Cruise Newfoundland and Labrador Ports of Call....................................432


Sikumiut Environmental Management Ltd. © 2008 August 2008 xxii

LIST OF ACRONYMS AARI Arctic and Antarctic Research Institute

ADCP Acoustic Doppler Current Profile

AES Atmospheric Environment Service

BIO Bedford Institute of Oceanography

BOP Blow-out Preventer

CAPP Canadian Association of Petroleum Producers

CEAA Canadian Environmental Assessment Act

CECOM Canadian East Coast Ocean Model

CESCC Canadian Endangered Species Conservation Council

CIDS Concrete Island Drilling System

CIS Canadian Ice Service

CITES Convention on the Intervention Trade of Endangered Species

C-NLOPB Canada-Newfoundland and Labrador Offshore Petroleum Board

COSEWIC Committee on the Status of Endangered Wildlife in Canada

CWS Canadian Wildlife Service

DFO Department of Fisheries and Oceans Canada

E&P Exploration and Production

ESRF Environmental Studies Research Fund

FEZ Fisheries Exclusion Zone

FLO Fisheries Liaison Officer/UCN

FJG Fugro Jacques Geosurveys

FPSO Floating Production, Offloading and Storage Facility

FRCC Fisheries Resources Conservation Council

GBS Gravity-base Structure

GEAC Groundfish Enterprise Allocation Council

GOM US Gulf of Mexico

GSC Geological Survey of Canada

IBA Important Bird Area


Sikumiut Environmental Management Ltd. © 2008 August 2008 xxiii

IPS Ice Profiting Sonar

MBES Multi-beam Echo Sounder

MMS US Mineral Management Service

MODU Mobile Offshore Drilling Unit

MOPU Mobile Offshore Production Unit

MPA Marine Protected Area

NAFO Northwest Atlantic Fisheries Organization

NAS US National Academy of Science

NAMMCO North Atlantic Marine Mammal Commission

NEB National Energy Board

NIC National Ice Centre

NLDFA Newfoundland and Labrador Department of Fisheries and Aquaculture

NMCA National Marine Conservation Area

NMFS US National Marine Fisheries Service

NRC National Research Council

NOAA National Oceanic and Atmospheric Administration

OBM Oil-based Mud

OCMD Oceans and Coastal Management Division

OCMS Offshore Chemical Management System

OCS US Outer Continental Shelf

OGP International Association of Oil and Gas Producers

OWS Offshore Weather Station

OWTG Offshore Waste Treatment Guidelines

PAL Provincial Aerospace Limited

SAR Synthetic Aperture Radar

SARA Species at Risk Act

SBF Synthetic-based Fluids

SBM Synthetic-based Mud

SEA Strategic Environmental Assessment

SFA Shrimp Fishing Area


Sikumiut Environmental Management Ltd. © 2008 August 2008 xxiv

TAC Total Allowable Catch

UXO Unexploded Ordinance

VEC Valued Environmental Component

VHRR Very High Resolution Radiometer

VOC Volatile Organic Compound

VSP Vertical Seismic Profile

WBM Water-based Mud

USFWS United States Fish and Wildlife Services


Sikumiut Environmental Management Ltd. © 2008 August 2008 xxv

LIST OF UNITS bbl Barrel

Bbbl Billion (109) barrels

cm/s Centimetre per second

dB Decibel

Hz Hertz

kHz KiloHertz

kJ KiloJoules

km Kilometre

km/h Kilometre per hour

km2/yr Per square kilometre per year

L Litre

m Metre

m/s Metre per second

MMbbl Million barrels (106) barrels

msec Multisecond

nm Nautical Mile

psi Pounds per square inch

tcf Trillion cubic feet


Sikumiut Environmental Management Ltd. © 2008 August 2008 1

1.0 INTRODUCTION The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) is responsible, on behalf of the Government of Canada and the Government of Newfoundland and Labrador, for petroleum resource management in the Newfoundland and Labrador Offshore Area. The Canada-Newfoundland Atlantic Accord Implementation Act and the Canada-Newfoundland and Labrador Atlantic Accord Implementation Newfoundland and Labrador Act (the Accord Acts), administered by the C-NLOPB govern all petroleum operations in the Newfoundland and Labrador offshore area. The C-NLOPB’s mandate is to interpret and apply the provisions of the Accord Acts to all activities of operators in the Newfoundland and Labrador Offshore Area; and, to oversee operator compliance with those statutory provisions. In the implementation of its mandate, the role of the C-NLOPB is to facilitate the exploration for and development of the hydrocarbon resources in the Newfoundland and Labrador Offshore Area in a manner that conforms to the statutory provisions for:

• worker safety;

• environmental protection and safety;

• effective management of land tenure;

• maximum hydrocarbon recovery and value; and

• Canada/Newfoundland and Labrador benefits.

While the legislation does not prioritize these mandates, worker safety and environmental protection will be paramount in all Board decisions.

This document provides a Strategic Environmental Assessment (SEA) of potential exploration and production activities that could occur in the Labrador Shelf Offshore Area (Figure 1.1). The SEA serves as a planning document to assist the C-NLOPB in their decision process with respect to areas, which may or may not be suitable to offshore exploration, and/or areas, which may require special mitigations. The SEA will provide: an overview of the existing environment; discuss in broad terms the potential environmental effects associated with offshore oil and gas activities in the SEA Area; identify knowledge and data constraints; highlight issues of concerns; and make recommendations for mitigation and planning. The SEA provides a broad-scale environmental assessment considering larger ecological settings. As such, the Labrador Shelf SEA is not intended, in part or in whole, to preclude the requirements for a project-specific environmental assessment.

The terms “offshore” or “offshore area” refer to the jurisdictional area of the C-NLOPB, as defined in the Accord Acts, to mean “those submarine areas lying seaward of the low water mark of the Province and extending, at any location as far as (a) any prescribed line, or (b) where no line is prescribed at the location, the outer edge of the continental margin or a distance of two hundred nms from the baselines from which the breath of the territorial sea of Canada is measured, whichever is greater”.



Figure 1.1 Labrador Shelf Offshore Area Strategic Environment Assessment Area



1.1 Scoping

The C-NLOPB has the responsibility pursuant to the Accord Acts to ensure that offshore oil and gas activities proceed in an environmentally responsible manner. The C-NLOPB decided in 2002 to conduct a series of SEAs for portions of the Newfoundland and Labrador Offshore Area that may have the potential for offshore oil and gas exploration activity but that were not subject to recent SEAs nor to recent and substantial site-specific assessments.

The C-NLOPB identified a requirement for a SEA for an area offshore Labrador known as the Labrador Shelf Offshore Area. As part of the preparation of a SEA for the SEA Area, a scoping document (Appendix A) was drafted by C-NLOPB staff with the assistance of a Working Group (C-NLOPB 2007). The Working Group is comprised of 10 members representing federal and provincial government agencies, local Regional Economic Development Boards, the fishing industry and non-governmental organizations. It is co-chaired by the C-NLOPB and the Nunatsivaut Government.

The exploration activities considered within the scope of this SEA include: exploratory and delineation drilling; seismic surveys, including two-dimensional (2-D), three-dimensional (3-D), vertical seismic profiling (VSP) and geohazards surveys; and wellsite abandonment. Generic types of potential production facilities that could be employed for the SEA Area have been identified and a generic discussion of their project-environment interaction is included.

The spatial boundary for the SEA Area is shown in Figure 1.1. The temporal boundary is the oil and gas activities as described above that may occur in the SEA Area within the next 10 years. The report will be reviewed in five years to determine if updates are required.

1.2 Objectives and Purpose of the Labrador Shelf Offshore Area Strategic Environmental Assessment

SEA has been defined as:

[T]he formalized, systematic and comprehensive process of evaluating the environmental impacts of a policy, plan or program and its alternatives...and using the findings in...decision-making (Therivel et al. 1992: 19-20).

SEA represents a broader, more proactive approach to assessing and managing environmental effects than traditional project-specific environmental assessments. A SEA:

• allows environmental issues to be identified and addressed at the earliest stages of planning, and typically focuses on “regional-scale” environmental concerns;

• can facilitate the consideration of stakeholder issues and concerns early in the planning process, and demonstrates accountability and due diligence in decision-making; and

• can also help to define the environmental components and potential effects which may require consideration in subsequent project-specific environmental assessments by identifying the key environmental issues associated with a particular sector and/or region.

In this particular case, information from the SEA will assist the C-NLOPB to:

• determine whether or not an exploration licence should be offered in whole or in part within the SEA Area;



• determine what mitigative measures or restrictions should be applied of offshore oil and gas exploration activities in the SEA Area; and

• determine whether or not to issue an Exploration License (pursuant to the Accord Acts) in whole or in part within the SEA Area.

An exploration license confers (C-NLOPB 2006a):

• the right to explore for, and the exclusive right to drill and test for, petroleum;

• the exclusive right to develop those portions of the offshore area in order to produce petroleum; and

• the exclusive right, subject to compliance with the other provisions of the Accord Acts, to apply for a production licence.

Activities that may be associated with exploration licences include:

• seismic and other geophysical surveys;

• drilling of wells (either exploration or delineation); and

• well abandonment.

If one or more exploratory drilling programs are successful in the identification of petroleum deposits with commercial potential, production activities may follow. Production activities may include:

• drilling of wells (delineation, development/production and injection wells);

• installation and operation of subsea equipment;

• installation and operation of production facilities; and

• production abandonment activities.

Each of the exploration and production activities requires specific approval of the Board, including a project specific assessment of its associated environmental effects in accordance with the Canadian Environmental Assessment Act (CEAA). The Labrador Shelf Offshore Area SEA is not intended and will not replace the requirement for project-specific environmental assessments.

More detail is given on the various licences in Section 1.4.

1.3 Valued Environmental Components

The project scope encompasses those components and activities considered for the purpose of an SEA. The scoping exercise conducted in relation to this environmental assessment included:

• review of the Draft Scoping Document issued by C-NLOPB (2007);

• consultation with relevant community, regulatory agencies and other stakeholders;

• a review of available information on the existing biological and physical environments of the SEA Area;

• a review of relevant regulations and guidelines related to offshore exploration activities; and

• the professional judgment of the study team.

Representatives of key community, government agencies, fishing industry representatives and other stakeholders were consulted as part of the scoping process; in order to discuss the proposed SEA,



obtain information on the existing environment, and to identify any potential environmental issues that may be associated with the offshore exploration and production activities within the SEA Area.

It is generally acknowledged that an SEA must focus on those components of the environment that are valued by society and/or that can serve as indicators of environmental change and have the most relevance to the final decision regarding the environmental acceptability of offshore exploration and production activities within the SEA Area. These components are known as Valued Environmental Components (VECs).

Based on the results of the scoping exercise described above, the following VECs are considered in this SEA:

• invertebrates and associated habitat;

• marine fish and associated fish habitat;

• commercial fisheries;

• marine birds;

• marine mammals and sea turtles;

• species at risk; and

• sensitive areas and related tourism and recreational activities.

The rationale for the selection of these VECs is provided below.

• Invertebrates and Invertebrate Habitat: The commercial fishery is an important element in Newfoundland and Labrador’s history, as well as its current socio-cultural and economic environment. Invertebrates and invertebrate habitat have a dual role in that invertebrates may be an important fishery commodity or is an integral member of the marine ecosystem. Although examined separately from fish and fish habitat, there is a clear interrelationship between them.

• Marine Fish and Habitat: The fish and fish habitat upon which the fishery depends is an important consideration in the environmental assessment of activities which may influence the marine environment.

• Commercial Fisheries: Commercial fisheries were selected as a valued environmental component (VEC) because historically, the fishery has played an important role in Newfoundland and Labrador’s economy and has helped to define much of the Province’s character. The fishery remains an integral component of the economy of Newfoundland and Labrador.

• Marine Birds: Newfoundland and Labrador’s offshore environment hosts a range of marine birds throughout the year. Marine birds are a key element in Newfoundland and Labrador’s biological and social environment. They are important socially, culturally, economically, aesthetically, ecologically and scientifically.

• Marine Mammals and Sea Turtles: Whales and seals are key elements in the biological and social environments of Newfoundland and Labrador. Although certain sea turtles species may be uncommon in the SEA Area, they are considered a VEC because of some species’ endangered and threatened status.

• Species at Risk: There are species of marine birds, fish, marine mammals and sea turtles that are protected by the Species at Risk Act (SARA). Species at risk are considered a VEC due to regulatory concern and in recognition of their protected status under SARA.



• Sensitive Areas: Sensitive areas are assessed as they may be an important habitat for invertebrates, fish, marine birds, marine mammals, sea turtles and species at risk. In addition, these areas often are the cornerstone upon which a variety of tourism and recreational activities are based.

These seven VECs represent the key environmental components that are examined in this document. This SEA examines the potential environmental effects associated with offshore exploration and production activities for each of these VECs. Data constraints and suggested mitigations are provided where appropriate.

1.4 Licences

There are three types of licences: exploration; significant discovery; and production licences issued by the C-NLOPB. A general overview of the requirements for each licence is provided in the following sections.

1.4.1 Exploration Licence

An Exploration Licence confers: the right to explore for, and the exclusive right to drill and test for, petroleum; the exclusive right to develop those portions of the Newfoundland and Labrador offshore area in order to produce petroleum; and the exclusive right, subject to compliance with the other provisions of the Accords Acts, to obtain a production licence (C-NLOPB 2006a).

The term of an exploration licence shall not exceed nine years and shall not be extended or renewed thereafter. In the offshore area, Exploration Licences have the maximum nine-year term, typically consisting of two consecutive periods of five years (Period I) and four years (Period II). The interest owner is required to drill or spud and diligently pursue one exploratory well on or before the expiry date of Period I as a condition precedent to obtaining tenure to Period II. Failure to drill or spud a well will result in reversion to Crown reserve of the licence.

If the Exploration Licence requirement for Period I is fulfilled, the interest owner is entitled to obtain tenure to Period II. The only requirement applicable to Period II is the payment, in advance, of annual rentals.

1.4.2 Significant Discovery Licence

A drilling program that has resulted in a significant discovery entitles the interest owner to a Significant Discovery Licence (C-NLOPB 2006a). A significant discovery is defined in the Accord Acts as:

a discovery indicated by the first well on a geological feature that demonstrates by flow testing the existence of hydrocarbons in that feature and, having regard to geological and engineering factors, suggests the existence of an accumulation of hydrocarbons that has potential for sustained production.

A Significant Discovery Licence is the document of “title” by which an interested owner can continue to hold rights to a discovery area while the extent of that discovery is determined and if it has potential to be brought into commercial production in the future. An SDL is effective from the application date and remains in force for so long as the relevant declaration of significant discovery is in force, or until a production, licence is issued for the relevant lands.



1.4.3 Production Licence

The interest owner is entitled to a Production Licence once a commercial discovery has been declared (C-NLOPB 2006a). A commercial discovery is defined as:

a discovery of petroleum that has been demonstrated to contain petroleum reserves that justify the investment of capital and effort to bring the discovery to production.

A Production Licence confers: the right to explore for, and the exclusive right to drill and test for, petroleum; the exclusive right to develop those portions of the offshore area in order to produce petroleum; the exclusive right to produce petroleum from those portions of the offshore area; and title to the petroleum so produced. A Production License is effective from the date it is issued for a term of 25 years or for such period during which commercial production continues.

1.5 Call for Bids

The C-NLOPB normally issues an official call for nominations for exploration annually, in the fall. This call is a preliminary step prior to a competitive call for bids by allowing interested parties the opportunity to nominate lands of interest to be included in a subsequent call for bids. The C-NLOPB is not bound to proceed with a call for bids in respect of any lands nominated, nor is a nominee obligated to bid on lands nominated and included in a subsequent call for bids. The C-NLOPB also has the right to nominate lands on its own initiative for inclusion in a call for bids.

The C-NLOPB submits a plan annually to the provincial and federal Ministers outlining the anticipated decisions of the C-NLOPB during that year respecting calls for bids for approval. Lands that are nominated may be considered for inclusion in the plan for interests. The C-NLOPB initiates a call for bids, upon receipt of Ministerial approval, normally commencing in early March and closing in late November. In this case, the call for bids will close in August 2008 to allow for the completion of the SEA. Exploration Licences will likely be issued to successful bidders within 45 days following the close of the call for bids.

This SEA will provide support for the bid process on parcels 1, 2, 3 and 4 noted of Figure 1.1 and any future parcels within the Labrador Shelf Area.

1.6 History of Oil and Gas Activities in Labrador Shelf Offshore Area

Interest in oil and gas offshore Labrador dates back to the late-1960s. At that time, several industry companies acquired exploration permits in the Labrador Shelf area. Drilling in the area commenced in 1971 and continued intermittently until 1983. The pattern of drilling during that period, in which 28 wells were drilled, is shown in Figure 1.2. This early drilling proved the presence of 4.2 trillion cubic feet (tcf) of recoverable natural gas in five separate wells, which demonstrated the presence of a petroleum system in the area. The location of the wells that showed these discoveries (and their individual volumes) is shown in Figure 1.3.



Figure 1.2 Drilling History in Labrador Shelf Strategic Environmental Assessment Area (1970 to 1983)

Canada-Newfoundland and Labrador

Offshore Petroleum Board

wells

wells

Nu m

ber

o f W

e ll s

Dri l

l ed

Drilling HistoryDrilling History

0

1

2

3

4

5

6

1970

1971

1972

1973

1974

1975

1976

1977

1978

1979

1980

1981

1982

1983

Total: 28 wells

Figure 1.3 Labrador Shelf Strategic Environmental Assessment Area Exploration Wells and Related Gas Resources

Canada-Newfoundland and Labrador

Offshore Petroleum Board

Snorri J-90

Hopedale E-33

North Bjarni F-06

Bjarni H-81

Gudrid H-55

0.1 tcf

0.1 tcf

0.9 tcf

0.9 tcf

2.2 tcf

0 0.5 1 1.5 2 2.5

Hopedale

Snorri

Bjarni

Gudrid

North Bjarni

Discovered Gas Resources Offshore Labrador

“Zone” Boundary



The focus of exploration in the 1970s and 1980s was on oil. With the major finds at the time being gas, no development or further drilling has occurred in the area since 1983. However, the increasing demand for clean energy in the Eastern US and Canada is creating an upward trend in commodity prices. This demand and pricing, supplemented by the emergence of new cold-ocean production and transportation technologies (Compressed Natural Gas (CNG), Liquefied Natural Gas (LNG) and Gas to Liquid (GTL) tankers) and favourable existing discoveries and geologic features, is setting the stage for a new cycle of exploration drilling for gas resources in Labrador. The Annual Seismic Acquisitions from 1968 to 2007 are shown in Figure 1.4. Note that there was very little activity from 1984 to 2002, but activity has picked up substantially from 2002 to 2007.

Figure 1.4 Labrador Shelf Strategic Environmental Assessment Area Seismic Acquisition Data (kms)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

19681970197219741976197819801982198419861988199019921994199619982000200220042006

Lin

e K

ilom

eter

s

Labrador Shelf - Yearly Seismic Acquisition

Total : 149,233 km.

1.7 Consultations

Consultations commenced on this project with a letter of introduction of the project and the SEA process from Mr. Max Ruelokke, chairman and CEO of the C-NLOPB to Innu Nation, Nunatsiavut Government, Labrador Métis Nation and a number of regulatory stakeholders. A copy of this letter and its recipients is contained in Appendix B.

Consultations were undertaken with communities, interest groups, regulatory agencies, fisheries industry representatives, and aboriginal groups. With regard to the latter, a separate exercise of collection of Traditional Knowledge was undertaken. In advance of these consultations, a notice of public meetings was established. The notices and list of stakeholders are provided in Appendix C.



Consultation sessions were held on the north coast of Labrador during the week of October 29, 2007. Sessions were held in Nain, Natuashish, Hopedale, Postville and Makkovik. Due to inclement weather, the session in Rigolet was postponed until December 5, 2007. Sessions on the south coast of Labrador were held during the week of November 12, 2007, and the week of May 12, 2008, and were held in Mary’s Harbour, Port Hope Simpson and Cartwright.

Once Draft One of the report was completed, a separate round of consultations was undertaken in the spring of 2008.

The sessions generally consisted of an introduction by Sikumiut, a power point presentation by C-NLOPB, followed by a question and answer period. In addition, a brochure was prepared on this project and distributed at the meetings. A copy of this brochure is contained in Appendix D.

Detailed notes on these sessions and a list of attendees on a community-by-community basis are contained in Appendix E.

Collectively, these consultations helped to identify data constraints, concerns about commercial fisheries harvesting operations and aquaculture activities within the SEA Area. The information gathered during these consultations has been used in assessing and recommending appropriate mitigative measures relevant to the commercial fisheries and aquaculture activities present in the area.

In general, concerns were expressed in the following general areas:

• the exploration parcels noted in the SEA Area are over prime crab grounds on the Hamilton and Makkovik banks;

• concern was expressed on how ice would affect exploration facilities;

• a variety of sea birds were identified in the area which could be affected by offshore activities;

• a number of seals species were noted as being present in the area; harp seals have become increasingly plentiful in recent years;

• wolffish, an endangered species, is present in the area; and

• tourism is an emerging business opportunity in the area and there are a number of special, protected areas in the SEA area.

1.8 Traditional Resource Use

Given that the Nunatsiavut Government has formal responsibility in the Labrador Shelf SEA Area under the Labrador Inuit Land Claims Agreement and that the Inuit and Innu people have a long history of using natural resources in the area, it is very important that their knowledge be used in planning offshore activities in the area. In order to obtain information on traditional resource use and other traditional information, a formal program of collection of Traditional Knowledge (TK) was undertaken. The principles of and process for collection of this TK is outlined in Appendix F. Copies of the interview responses are presented in Appendix G.

During the public consultation sessions in the various communities, names were solicited from meeting participants as to who would be appropriate contacts in each community for collection of this information.

In Nain, Makkovik, Postville, Rigolet and Happy Valley-Goose Bay, the TK was collected directly by Sikumiut staff whereas in Natuashish, the information was collected by Minaskuat staff.



The following main points were made during the collection of Traditional Knowledge;

• The area is used extensively for fishing. Species noted were: crab; rock cod; cod; arctic char; sculpins; mussels; clams; wrinkles; and sea urchins.

• It was noted that whales migrate through the area. Walrus have also been noted in the area.

• The islands in the area are used for traditional uses such as egging and berry picking.

• Harlequin ducks, a threatened species migrate through the area.

• Ducks and geese are also hunted in the area.

• Traditional activities are well dispersed throughout the Labrador Shelf SEA Area.

1.9 Organization of the Strategic Environmental Assessment

This report is organized as follows.

Chapter 1 introduces the SEA, and includes background information on the SEA Area and SEA in general, as well as the purpose and context of the assessment, the planning and regulatory processes that apply to offshore exploration in the region, past and potential seismic surveys and drilling programs within the SEA Area and the organization of the document. The introduction also discusses the scope of the assessment, defining the specific components and activities under consideration and the spatial and temporal boundaries of the SEA. It also describes the issue scoping exercise undertaken as part of the SEA, and identifies the specific VECs upon which the SEA is focused and the rationale for their selection.

Chapter 2 provides an overview of potential exploration and production activities that could occur in the SEA Area, including a general, generic description of offshore petroleum exploration (including seismic surveys, well drilling and well abandonment/decommissioning) and production activities.

Chapter 3 provides a description of the physical setting of the SEA Area based on existing, available information.

Chapter 4 provides a description of the biological environmental setting of the SEA Area, based on existing, available information.

Chapter 5 provides the potential environmental effects analysis for each of the VECs under consideration. Each VEC is discussed in a separate section, which includes a discussion of:

• potential environmental interactions and existing knowledge regarding them, as well as standard mitigation measures to avoid or reduce potential environmental effects; and

• the nature and adequacy of available information for the SEA Area and relevant data requirements.

Chapter 6 presents a summary of the key findings and conclusions of the assessment.

References, including personal communications and the literature cited, are provided in Chapter 7.

Supporting information is provided in the Appendices.



2.0 EXPLORATION AND PRODUCTION ACTIVITIES The C-NLOPB’s regulatory role includes the issuing of approvals and authorizations pertaining to offshore exploration and production activities. The C-NLOPB is designated a Federal Authority under the Canadian Environmental Assessment Act (CEAA) and acts as the designated Federal Environmental Assessment Coordinator for offshore seismic surveys, geophysical surveys and drilling environmental assessments under CEAA. All offshore seismic surveys, geophysical surveys and exploration drilling programs on the East Coast are subject to a site-specific environmental assessment under CEAA.

Several other federal agencies have an advisory role in the environmental assessment process with respect to offshore explorations and production activities. Department of Fisheries and Oceans Canada (DFO) is responsible for the protection of fish and fish habitat under the Fisheries Act. Environment Canada is responsible for the protection of migratory birds under the Migratory Birds Convention Act, as well as discharges to the marine environment under Section 36 of the Fisheries Act and Disposal at Sea under the Canadian Environmental Protection Act. Transport Canada is responsible for provision of safe navigation (under the Navigable Waters Protection Act) and discharge of pollutants at sea (under the Canada Shipping Act and Regulations, such as the Pollutant Discharge Reporting Regulations, 1995 and the Guidelines for the Control of Ballast Water Discharge from Ships in Waters Under Canadian Jurisdiction).

Within the SEA Study Area there is an area described in the Labrador Inuit Land Claims Agreement known as the “Zone”. This zone is approximately 12 nm wide measured from selected points on the coastline. Within this zone, the C-NLOPB is obligated to consult with the Nunatsiavut Government before undertaking any environmental studies with regard to offshore oil and gas development.

The C-NLOPB, the Province and the Federal government are also obligated, in addition to studies, to consult with the Nunatsiavut Government prior to approving a Development of Minerals in the Zone. This includes any transportation in the Zone associated with the Development. The Nunatsiavut government may make recommendations to regulators on the impact on the integrity of the landfast ice of a Development or Exploration Program and with respect to the approval of any development.

2.1 Exploration Activities

Exploration and delineation activities consist of:

• seismic survey - use of seismic to map rock layers and properties through the detection of differing reflections of sound passing through geological formations;

• geotechnical survey - taking samples (cores) of the substrate prior to positioning a drilling unit over a potential exploration/delineation wellsite to ensure the substrate will pose no hazard to the drilling unit; and

• drilling a well - the primary activity of exploration/delineation drilling, this activity penetrates the substrate to an oil- or gas-containing formation; the primary discharge related to this activity is drill cuttings. Water-based muds (WBMs) are usually used for the top sections of the well, with synthetic-based muds (SBMs) used for deeper sections of the well and horizontal wells, where borehole stability and integrity can be an issue.



2.1.1 Seismic Surveys

Seismic surveys are a technique used to map rock layers and properties with sound propagation and related echo mapping (includes 2-D and 3-D seismic mapping). The goal of a seismic survey is to develop an image of the features where hydrocarbon reserves could accumulate (i.e., subsurface strata and structures). Seismic surveys are undertaken by a ship towing a submerged air or water gun array to produce short bursts of sound energy, and a set of streamers of several kilometres length. Each streamer contains a dense array of hydrophone groups that collect and pass to recorders echoes of sound from reflecting layers. The depths of the reflecting layers are calculated from the time taken for the sound to reach the hydrophones via the reflector; this is known as the two-way travel time.

Typical seismic surveys are able to map rock layers over 10 km deep (Cook 2006). A schematic illustrating seismic survey operations is provided in Figure 2.1.

Figure 2.1 Schematic of Seismic Survey Operations

2.1.2 Geohazard Surveys

A geohazard can be defined as:

a geological state, which represents or has the potential to develop further into a situation leading to damage or uncontrolled risk (NGI 2006).



The focus on offshore geohazards has increased as offshore oil and gas activities move into increasingly deep waters and a larger proportion of field installations are placed directly on the seabed.

A wellsite/geohazard survey is required to detect hazards or potential hazards in the immediate vicinity of the proposed well locations. The survey will also ensure suitable subsea conditions for drilling purposes. The purpose of the survey is to demonstrate that drilling activities can be conducted in a manner that does not endanger personnel or the environment.

Typical offshore geohazards include:

• slope stability;

• shallow gas;

• gas hydrates;

• shallow waterflow;

• mud diapirism and volcanism;

• gas and fluid venting forming seafloor, rockmarks; and

• seismicity (earthquake activity potential).

2.1.3 Seabed Sampling/Geotechnical Testing

A certain amount of seabed/geotechnical data will need to be collected in support of offshore facilities design and construction for offshore Labrador, including a detailed bathymetric survey, ice scour data collection, and a detailed geotechnical survey and associated laboratory testing.

Seabed coring and testing would take place from vessels specific to this purpose. Geotechnical information could be gathered from soil samples obtained through drilling of cores, from shallow gravity cores, vibro-cores and grab samples. Depending on the facilities proposed for development, information from the upper tens of metres may be required. Samples are then tested and the data analyzed to determine relevant soil properties.

A geotechnical program must be conducted to ensure the substrate is suitable for positioning the jack-up rig as a drilling platform. The purpose of such a survey is to demonstrate that drilling activities can be conducted in a manner that does not endanger personnel or the environment. The C-NLOPB assesses any proposed geotechnical program in accordance with the Accord Acts and as per the Geophysical, Geological, Environmental and Geotechnical Program Guidelines, Newfoundland Offshore Area (C-NLOPB 2008).

2.2 Drilling Activities

Seismic surveys and geological knowledge can provide information that a location may have the potential for hydrocarbon resources. Exploration and delineation wells are drilled to confirm the presence or define the extent of petroleum resources in specific locations as the actual geological properties and confirmation of hydrocarbon resources can only be determined by exploratory drilling programs. Drilling activities (both exploration and production) are undertaken by the offshore oil and gas industry to:

• confirm the presence of petroleum hydrocarbons;



• delineate the resource; and

• to increase the accessibility to the resource during production.

Regardless whether the drilling activity is carried out for exploration or production, equipment and related operational effects are essentially the same.

2.2.1 Drilling Platforms

Typically, drilling operations on the Canadian east coast have been conducted from several types of platforms, including a jack-up rig, a semi-submersible or a drillship (Figure 2.2). The type of rig chosen is based on the characteristics of the well site physical environment, well site water depth, expected drilling depth and the mobility required based on well site weather and ice conditions (Canadian Association of Petroleum Producers (CAPP) 2001).

Figure 2.2 Typical Drilling Platforms

Jack-up Rig Semi-submersible Drilling Unit Drillship

For the Labrador Shelf SEA Area, it is likely a floating vessel will be used for drilling operations (i.e., a drill-ship or semi-submersible). This is due to the extreme environment, particularly conditions of pack ice and icebergs. Only if there is a production platform designed and installed to endure all



environmental conditions could drilling operations be conducted from a fixed platform. Jack-up type drilling units are possible, but unlikely for the Labrador Shelf Area. Although some ice-class jack-up designs can be found in the literature, it is believed none has been constructed. It is noteworthy that all historical wells in the Labrador Shelf SEA Area have been drilled using either semi-submersibles or drillships.

The offshore drill unit is a complex platform housing the drill equipment and working and living quarters, while supported by supply vessels and helicopters. There are two basic types of offshore drill units, mobile and permanent. Mobile platforms can be used for exploration, delineation or production drilling while permanent platforms are typically used for production.

Typical offshore mobile platforms are jack-up rigs, semi-submersible rigs and drill ships. Semi-submersibles and some drillships can be either dynamically positioned or anchored. There is a wide variety of permanent drilling platforms; the actual platform used is dependent upon water depth, proximity to land, nature of the resource and physical environmental conditions such as weather and ice conditions.

A jack-up drilling unit is one in which the hull of the vessel is suspended above the surface of the ocean by means of legs which jack down through the hull to the sea floor. As the legs are jacked down, the hull is jacked up to the desired distance above the water - the air gap. A jack-up is therefore bottom-founded and is limited to water depths within the length of its legs and structural capability of the rig considering anticipated metocean conditions. Used in water depth of less than 120 m, these rigs cannot move under their own impetus and units are towed to the drill site (CAPP 2001).

Drilling in deeper waters is usually conducted from a semi-submersible drilling unit or drillship. Semi-submersibles and drillships are also used in areas where increased mobility is required (i.e., areas prone to incursions of sea ice and icebergs). The drilling platform sits atop steel pontoons that are filled with water so that the unit floats with the main deck above water and the remainder below the water surface. The semi-submersibles are towed to the drilling site and are either moored to the bottom (with a series of 8 to 12 anchors (which may extend up to 1 km from the rig)) or are kept on station using a dynamic positioning system (computer-controlled thrusters) in deeper waters (1,000 to 2,000 m). As a semi-submersible is not bottom-founded, it can work in much greater water depths than a jack-up. The maximum water depth is a function of the length of the rig’s riser, a bundle of utility tubes through which drilling fluids and other material are conducted, enclosed in an outer tube, attached to the seafloor via the Blow-out Preventer (BOP).

A semi-submersible can usually operate in rougher seas than a drillship (CAPP 2001). In very general terms, a drillship and semi-submersible can stay on location, stay connected to riser, stay drilling up to an approximately 2.5 m heave, with some pitch/roll limits. Beyond that point, up to 6 m heave, the rig can stay on location and stay connected but will be unable to drill. At approximately 6 m heave, the rig will need to disconnect and move off location. Both types of hulls would have generally same limits in terms of heave, different limits in terms of pitch and roll, with a drillship having less tolerance for pitch/roll. Historical data from offshore Labrador for wells drilled with semi-submersibles or drillships indicate that the earliest time drilling occurred was in June, while the latest time drilling occurred was in October or November (depending on drill unit type). A summary of key features of a typical jack-up rig and semi-submersible are provided in Table 2.1.



Table 2-1 Summary of Key Features of a Jack-up Rig and Semi-submersible Item Rowan Gorilla VI Grand Banks

Type Self-elevating Semi-submersible Year Built 2000 1984 Maximum Water Depth (m) 121.92 457.2 Maximum Drilling Depth (m) 10,660 7,620 Maximum Variable Load (drilling) (kips) 13,767 12,564 Derrick Capacity (kg) 1,133,980 589,670 Liquid Mud Storage Capacity (m3) 841.66 391.73 Bulk Material Storage Capacity (m3) 566.32 563.49

Drillships are generally used in areas of relatively deep water. In some areas of the world, drill ships can be anchored to the bottom in water depths of approximately 200 to 1,000 m. More commonly, drill ships are kept on station using a dynamic positioning system in waters up to 3,000 m deep. A moon pool in the centre of the vessel provides access for a derrick from the deck surface through the centre of the ship to the water column (CAPP 2001).

All of these mobile drilling platforms (jack-up rig, semi-submersible rig and drill ship) are self-contained units, with derrick and drilling equipment, a moon pool or some other form of access to the water surface, a helicopter pad, fire and rescue equipment and crew quarters. The operations and discharges are similar for all three drilling platforms. Typically, one to three vessels provide support to the drilling platforms.

While there are differences between platform types with respect to capabilities, treatment facilities and effluent discharge depths, the characteristics volumes and types of wastes streams are similar among drill platform (mobile and permanent).

If future exploration licences within the Labrador Shelf SEA Area border the coast of Labrador, directional drilling from land may be a plausible scenario and/or option. This technology has been used on the West Coast of Newfoundland and Labrador on the Port au Port Peninsula.

2.2.1.1 Exclusion Zones

A fisheries exclusion zone (FEZ) is a temporary exclusion zone typically established around a drilling platform for the duration of the 40- to 60-day drilling program; fishing is not permitted within a FEZ. Input into the development of the FEZ is solicited from stakeholders during public and fisheries consultation as part of the project-specific environmental assessment process. The FEZ around drilling operations is relatively small (0.5 km²). If the drilling platform is an anchored rig (such as a semi-submersible), then the FEZ typically extends 500 m beyond the anchor points (which can extend up to approximately 1,000 m from the centre of the drilling platform). If the drilling platform is not anchored, then the FEZ is established 500 m from the edge of the platform. Information on the FEZ is usually provided via the Fisheries Broadcast and through the Notice to Mariners.

2.2.2 Support Vessels

Support for offshore oil and gas exploration activities is provided by offshore supply vessels, which provide transportation services to offshore drilling units. The main services provided are the delivery of essential supplies, including food and water, personnel transport, iceberg towing services and the provision of safety and emergency response.



2.2.3 Air Support

Additional support for offshore oil and gas exploration activities is provided by helicopter. The main services provided are employee transport, delivery of smaller essential supplies and safety and emergency support.

2.3 Production Platforms and Facilities Production platforms and other facilities will only occur within the Labrador Shelf SEA Area in the event that commercially viable oil and/or gas deposits are discovered and all applicable permits and approvals required by the Accord Acts and CEAA are in place. The production facilities that might be used will be dependent upon current available technologies at the time of development and the regulatory regime at the time of development; as well as the type, quantity and location of the resource. Given the length of time from discovery to project sanction and approval (current estimates are 10+ years); general information with respect to potential platforms and facilities is provided.

Current production platforms in use on the Canadian east coast include the gravity based structure (GBS) at Hibernia; floating production, storage and offloading vessels (FPSO) at Terra Nova and White Rose combined with subsea facilities in glory holes tied back to the FPSO via flowlines/umbilicals/risers; a leg or jacket structures at Sable with a pipeline to shore; and a planned jack-up type mobile offshore production unit (MOPU) tied back to production wells with subsea flowlines/umbilicals and an export pipeline to shore for Deep Panuke.

The potential production platform types and facilities that may occur within the Labrador Shelf SEA Area in the event that a commercial viable deposit has been sanctioned and approved may include:

• bottom-founded structure (GBS) - A stand-alone production facility that includes a concrete or steel GBS with topsides. A GBS and topsides is usually constructed separately and then mated at an inshore site prior to towing and installation of the platform at the offshore site. The topsides would include all necessary processing equipment and would also include quarters to house all necessary operation and maintenance personnel. Hydrocarbon storage could be incorporated into the GBS design.

• floating structure (e.g., FPSO) - An FPSO (a concept that usually includes subsea satellite wells) would entail subsea wells drilled using a mobile offshore drilling unit (MODU). Production fluids are typically transferred to a FPSO via flowlines and flexible risers. The two existing FPSOs operating on the Grand Banks (the Terra Nova and the SeaRose) are double-hulled and double-bottomed for protection from sea ice and icebergs. An FPSO may include storage and would house the processing, gas compression, gas lift, water injection and utility equipment, including power generation. It would also include quarters to house all necessary operation and maintenance personnel.

• subsea facilities - The subsea layout may consist of production wells feeding into a template, which, in turn, will be connected by rigid or flexible flowlines to FPSO or GBS risers, or into a manifold from which the hydrocarbons would be transported via an export pipeline. In order to protect the subsea wells from iceberg scour, the equipment may be placed below the mudline in glory holes.

• pipelines and flowlines between facilities and/or to shore - Flowlines may be used to collect production from subsea wells and bring it to the platforms. An export pipeline may be used to transport processed or unprocessed production to shore.

• other export facilities.



Subsea facilities could be associated with either platform concept; pipelines could be associated with any of the production options.

Development could occur anywhere in the Labrador Shelf SEA Area, on the banks, in deeper water of the outer shelf, in saddles between the banks, or in the trough between the banks and inner shelf. The location of development within the Labrador Shelf SEA Area will drive the optimal solution in terms of production development. Potential development options will be strongly influenced by the presence of ice and icebergs in the offshore Labrador environment, which make it considerably different from other regions with minimal or no ice considerations. Export of produced hydrocarbons also needs to be considered.

2.3.1 Subsea Options

In recent years, there have been great improvements in the area of subsea facilities and processing. As a result, remote fields requiring longer, deeper subsea tiebacks are now becoming much more technically and economically feasible. Gas tiebacks have reached 170 km (Statoil Snøhvit) and oil tiebacks have reached 65 km (Shell Expro ‘Penguin’).

Subsea processing offers many advantages to Labrador field development due to the distance between wellsites, depth and the harsh environmental conditions. Subsea processing has evolved around the development of: subsea booster pumps; subsea compressors; subsea separators; and subsea gas dewpointing and dehydration.

For subsea options, production could be through remotely operated 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 helps minimize 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.

2.3.1.1 Glory Holes

Glory holes are depressions in the ocean floor, excavated to protect the subsea wellheads and associated hardware from scouring icebergs. Since the discoveries offshore Labrador are located in an active iceberg zone, open glory holes will likely be required out to approximately 300 m water depth (depending on acceptable risk) to protect subsea assets.

Currently there are just two fields in the world that use open glory holes (Figure 2.3) to protect their wellheads and associated subsea facilities from iceberg impact - Terra Nova and White Rose. The Terra Nova project uses five glory holes in water depths ranging from approximately 95 to 98 m and the White Rose project uses three glory holes in water depths ranging from approximately 119 to 123 m. A summary of the overall glory hole dimensions is included in Table 2.2.



Figure 2.3 Glory Hole

Source: Coflexip Stena 2000.

To date, glory hole excavation has been the preferred method of subsea facilities protection on the Grand Banks. Cased glory holes, soil/rock berms, or concrete structures could also be considered. However, during the 1996 front-end engineering design (FEED) study for Terra Nova, open glory holes were identified as the optimum solution for protecting wellhead facilities from scouring icebergs (Offshore Magazine 2007). These other methods, such as cased glory holes, may have some potential for smaller footprints like single wellheads. However, for subsea facilities with a larger footprint, additional mechanical protection (over and above glory hole excavation) may not be warranted. However, in order to decide definitively, it is necessary to carry out a thorough risk analysis for the specific site under consideration.

When digging glory holes, there may be a certain amount of uncertainty associated with the soil conditions offshore Labrador. The mix of soils (sands, gravels, clays) can vary within a glory hole and the presence of glacial erratics such as boulders, or dense zones of cobbles will be difficult to identify before excavation commences. Considering the uncertainty about soil conditions, excavation methods



that are insensitive to the conditions are favoured over those that are more specific. Thus, an excavation technique that can handle all types of sands, gravels, cobbles and clays would be ranked higher in suitability than a method that is extremely efficient in sand, for example, but inefficient in other soils.

Technology 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 remotely operated vehicle (ROV)-based subsea excavators. Excavation of glory holes will result in disturbance of the seabed and a spoil disposal site will be required.

Table 2-2 Overall Glory Hole Dimensions

Field Glory Hole Base Dimensions (m) Depth (m)

Side Slopes Ramp Slope

Southeast 25 × 25 Northwest 25 × 25 Northeast 45 × 25 Southwest 65 × 25

10 Terra Nova

Far East 43.2 × 23.2 10.3

1:3

Southern 58 × 44.4 Central 58.3 × 49.7 White Rose

Northern 38 × 17 9 1:1.8 1:5

Source: Technip 2001.

2.3.1.2 Installation

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.

Flowlines between subsea facilities and a pipeline or an offshore facility are given many of the same considerations as pipelines discussed in Section 2.3.4.

2.3.2 Floating Structure Options

Floating structures such as FPSOs could be located in the Labrador Shelf SEA Area in water depths ranging from relatively shallow to very deep. An FPSO option would require subsea facilities, which, depending on water depth, would need to be in glory holes, as the FPSO structure itself offers no protection to the facilities on the seabed.

The FPSO would be anchored to the seabed using piles or anchors and risers from the seabed would be used to transport hydrocarbons from the seabed to the vessel for processing. The moorings and risers would most likely be attached to a disconnectable turret, which could be detached from the vessel, thereby allowing the ship to evade icebergs. The moorings and risers would be lowered a safe distance below the water surface.

While the floating structure may have some storage capacity, processed hydrocarbons could be exported via a pipeline or by tanker export. Variations on a traditional FPSO would include a floating LNG or CNG facility (see Sections 2.3.2.1 and 2.3.2.2 for basic descriptions of these processes). Further detailed investigation would be required to determine if an FPSO could reliably operate in the Labrador Shelf SEA Area based on current technology.



Installation of the FPSO would require a number of dedicated vessels as well as ice management capabilities. In general, the installation of an FPSO would include: installation of the piles/anchors; attachment of the mooring system; installation and hook up of the risers; and connection of the turret buoy to the FPSO.

2.3.2.1 Liquefied Natural Gas

LNG is natural gas that is super-cooled to -160˚C to become a liquid. Liquid gas is much more economical than gas to transport since it displaces 1/600th the volume of gas. The reduction in volume makes it much more cost-efficient to transport over long distances where pipelines do not exist. Where moving natural gas by pipelines is not possible or economical, it can be transported by specially designed cryogenic sea vessels (LNG vessels) or cryogenic road tankers.

2.3.2.2 Compressed Natural Gas

CNG is natural gas that has been compressed to between 2,500 and 4,000 psi such that it can be transported in pressurized containers on board specialized vessels. The supply sources could be onshore or offshore. An onshore supply source would include marine terminals and inshore subsea pipelines, while an offshore supply source would likely be oil and gas production facilities. The potential delivery locations could be offshore/near shore unloading systems to subsea pipeline or an onshore marine terminal or pipeline (Melville and Young 2007).

2.3.3 Gravity-base Structure Options

GBS options can be considered for the Labrador Shelf SEA Area for water depths ranging from very shallow out to approximately 150 m. Three principal factors that govern the design of a GBS in the Labrador Shelf SEA Area are:

• the environmental loading conditions, primarily waves and icebergs with seismic loads playing a secondary role with respect to topsides design;

• the platform itself and its functional requirements; and

• the foundation capacity available at the site.

It is the combined effect of these factors that dictate the geometry and other design features of a GBS. Changes in foundation resistance can have a profound effect on the technical and economic feasibility of different GBS concepts. A workable concept at a particular site can be technically challenging at a site a short distance away with a weaker soil strength profile.

While the GBS may have some storage capacity, processed hydrocarbons could be exported via a pipeline or by tanker export. Variations on a traditional GBS could include LNG or CNG facilities on the topsides.

Relief in the seafloor topography resulting from ice gouging (Figure 2.4) could affect the final placement location of a GBS, although this should be evident from site surveys early in the project. 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 (to account for settlement) or require backfilling of the excavation with more competent material.



Figure 2.4 Ice Gouge and Subgouge Deformation

2.3.4 Pipelines and Flowlines

In addition to the transport of produced hydrocarbons by tanker from a GBS or floating structure, an export pipeline is another option. If remote wells are used to tie back into a GBS or floating structure, flowlines will be required.

It is generally accepted that pipelines in ice (iceberg or sea ice) environments will need to be trenched to some depth below the seabed to protect the pipeline from the effects of iceberg keels. Scouring of the seafloor is a relative near-shore feature for most northern continents where ice is present and where ice keels travel into water with depths less than the keel draft, forming a scour mark on the seafloor. Offshore Labrador, this may be out to 250 or 300 m water depth; this depth would need to be determined during detailed design of any project. Actual design requirements of pipelines/flowlines would need to be made in consideration of a number of factors, some of which have been discussed in this report.

On the Labrador coast, while there may be some issues with ice buildup/rideup at the shore crossing, the major issues about ice scour will be due to icebergs traveling down the Labrador coast from the north.

Design issues related to ice scouring, pipeline stability; thermal insulation 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 excavated from the trench. Select backfill, gravel, gravel filled bags or concrete mats may be considered in predetermined locations where native backfill is not adequate.



There are five main types of trenching available to lower a pipeline and these include: ploughing; jetting; mechanical excavators; conventional excavation; and hydraulic dredging. The selection of a trenching tool must be evaluated based on:

• water depth;

• soil conditions;

• trenching specification (e.g., overall trench depth required);

• backfill requirements;

• pipeline type and size;

• cost;

• location;

• availability; and

• season during which trenching operations are to be completed.

Most trenching tools have limitations. For example, dredgers can only be used to approximately 150 m water depth, jetting machines and mechanical trenchers may disperse trench spoil that would be used as backfill and many have trench depth limitations.

Pipelines are trenched to provide on-bottom stability (protection against hydrodynamic forces), physical protection against mechanical damage (such as dropped objects, drill unit anchors, fishing equipment, scouring icebergs) and elimination or reduction of free spans. Backfilling is also used to provide additional physical protection, prevention of upheaval buckling and thermal insulation.

A lay vessel is a specially built oceangoing vessel aboard which the pipeline is fabricated or unreeled as the vessel moves along the pipeline route. Such a vessel moves either by means of an anchoring system or by its own propulsion, and normally only operates under non-freezing conditions. If the lay vessel moves on anchors, anchor-handling vessels are needed to help reposition the anchors so the lay vessel can advance. A moored lay vessel usually does not have propulsion and is moved from one work location to another by tug. The lay vessel can carry a limited amount of pipe on its deck or reel, and pipe carrier vessels or barges supply additional pipe. The vessel required for pipeline installation depends on the type of pipe used (rigid or flexible) and the pipe lay method chosen. The pipeline may also be made up on shore in strings or segments, towed to site, and welded together as they are being put in position.

Dumping rock on top of subsea flowlines and umbilicals is one means of protecting them from grounded sea ice, anchors and dropped objects. Any protection afforded a pipeline against a scouring iceberg would be expected to be minimal and, therefore, the level of risk of damage to the flowline/umbilical must be acceptable to the operator.

In deeper water, where trenching and burial may not be required for protection against ice keels, stability may be an issue. If a pipeline/flowline does not have sufficient weight to resist imposed hydrodynamic loads the entire pipeline, or large sections of it, may move. Therefore, various methods might be considered to achieve pipeline stability and protection including weight coatings/saddles, concrete mattresses, and other forms of installed restraints.



2.3.5 Export Facilities/Onshore Processing

A GBS or floating structure will have a limited storage capacity for produced hydrocarbons. Tankers may be considered to transport the product to its destination. The number of vessels required would depend on a number of factors including storage capacity, distance to market and transport vessel size. Depending on the service class of these vessels, icebreaking support may be required in winter.

Therefore, if CNG/LNG tankers were used, they would load at the production facility or at an onshore pier. The size of these vessels would depend on a number of factors, including the number of vessels in the fleet and the distance to market, but they might be expected to be 100 m in length or larger. These vessels would have the appropriate class reflecting the necessary requirements to which an LNG/CNG tanker would need to be designed in order to deal with the ice conditions that will be present. Offshore loading may be discontinued when statistically significant wave heights reach a threshold value.

Development options could include a pipeline(s) to shore (Labrador). If this were the case, a certain amount of processing facilities and/or export facilities would be required onshore/nearshore. This would likely require some onshore hydrocarbon storage be part of the facilities. Tankers would need to have the ability to move through heavy onshore pack ice to dock and load. Depending on the service class of these vessels, icebreaking support may be required in winter.

Support vessels will be required for supply operations including the transfer of personnel, bunkering and materials handling. Depending on the service class of these vessels, icebreaking support may be required in winter. Helicopter flights will be a regular operation for crew rotations and ferrying of some smaller pieces of equipment.

2.3.6 Operations

2.3.6.1 Subsea Systems

Subsea systems will require that periodic inspection, maintenance and repair activities be carried out, which will require the deployment of working and support vessels. Ice management capabilities may be required to support these activities. An ROV or divers may also be deployed is used to accomplish these tasks.

2.3.6.2 Floating and Gravity Based Structures

In addition to all of the normal activities associated with operations of a floating structure or GBS, there are specific issues associated with operations in ice environments that need to be considered.

Floating structures are not normally designed to withstand impacts with icebergs. As on the Grand Banks, with respect to FPSO operations, avoidance is normally the expected manner of dealing with icebergs either through iceberg management or disconnect.

As iceberg frequency and sea ice conditions in the Labrador Shelf SEA Area would be expected to be more onerous, disconnect events for a floating structure would be expected to be more frequent than on the Grand Banks. Such disconnects can be accomplished by shutting in the wells and riser system and releasing the riser buoy from the hull. The riser buoy is then submerged to a prescribed depth below the water surface for protection.



Support vessels will be required offshore, including one vessel on standby that is fully available for emergency purposes. The other vessels (likely a minimum of two) will be required for supply operations, including the transfer of personnel, bunkering and materials handling and ice management. Helicopter flights will be a regular operation for crew rotations and ferrying of some smaller pieces of equipment. The number of flights will depend on the number of crew and rotation schedule.

2.3.6.3 Pipelines

Pipelines transporting reservoir fluids may be subject to hydrate formation during operations and/or extended shut down conditions. Hydrate inhibitor injection and recovery systems may be required at onshore or offshore processing facilities. A smaller parallel pipeline will be needed to inject glycol to the main line for hydrate inhibition. Glycol regeneration systems to handle the amount of glycol probably needed are commonplace.

In the unlikely event that pipelines/flowlines need to be repaired, a repair spread would need to be deployed that could include lay vessels, diving support vessels and ice management vessels. The logistics for pipeline repairs depend largely on the season and the sea ice conditions. Detailed repair procedures for the pipeline should be produced during design and should consider both summer and winter scenarios. The pipeline repair should be planned and closely coordinated with an emergency response plan.

2.3.6.4 Environmental Emergency Response

Environmental emergency response plans will be an important aspect of any development offshore Labrador. Typically, the project operator will contract a response organization to develop a response plan and implement procedures during a pollution event. This will likely require the storage, testing and maintenance of oil spill response equipment within a reasonable distance from the facility.

Contingency Plans including oil spill response plans are submitted to the Board as part of the Environmental Protection Plan and Safety Plan, approvals of which are required prior to issuance of a Production Operations Authorization (C-NLOPB 2006b). The conceptual discussion of environmental contingency planning and countermeasures should include consideration of the following (as outline in the Development Plan Guidelines (C-NLOPB 2006c):

• the types of environmental emergencies for which contingency plans will be in place;

• the general emergency response organization, chain of command and key areas of responsibility;

• internal and external notification and reporting procedures;

• the interface between the proponent's plans and procedures and those of government organizations and other operators;

• the training of personnel, including provisions for response exercises;

• the personnel and equipment requirements for different types of response, including logistics requirements, response timing and anticipated equipment inventory for spill surveillance and tracking, and spill containment and clean-up;

• the estimate of the capabilities and/or limitations of countermeasures equipment and techniques and their implications for effects estimation;



• the possibility of measures to increase response efficiency or capability (e.g., research and development programs);

• the capabilities, timing and logistics of relief well drilling, and alternatives to a relief well (if any);

• the capability of mounting a monitoring program in the event significant effects are anticipated; and,

• the plans for the disposal of recovered pollutants and debris.

2.3.7 Decommissioning

Decommissioning procedures for offshore installations that have reached the end of their useful life are usually included in governing legislation after exploration drilling operations (e.g., drilling regulations (Newfoundland Offshore Petroleum Drilling Regulations, 1993) and after production operations (e.g. production regulations and guidelines (Newfoundland Offshore Area Petroleum Production and Conservation Regulations, 1995). There are also international agreements relating to decommissioning that address removal and deep-sea disposal. For example, the International Maritime Organization has developed Guidelines and Standards for the removal of Offshore Installations and sets out conditions to protect navigation and maintain safety.

The requirements of the C-NLOPB with respect to decommissioning include, among others, the following conditions (Erlandson Consulting Inc. and Petroleum Research Atlantic Canada 2004):

• design 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;

• design the GBS so that it could be removed if the Authorities at that time so require;

• remove all abandoned subsea well equipment above the seafloor and to design the GBS platform for eventual re-floating; and

• ensure that the Certifying Authority reviews the suitability of the detailed design of the GBS for eventual re-floating.

Based on these requirements, decommissioning will likely be an important consideration for any Labrador Sea development concept. In general, decommissioning of offshore fixed or bottom-founded platforms is perceived as technically difficult, costly and posing a number of environmental and safety risks (International Association of Oil and Gas Producers (OGP) 2003). Decommissioning of a floating structure, by their nature, would be relatively easy in comparison as the majority of the infrastructure can simply be disconnected and floated away.

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 United Kingdom (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 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).

Decommission plans are subject to review and approval from the C-NLOPB.

2.4 Sound Associated with Exploration and Production Activities

2.4.1 Underwater Sound

Natural sounds that contribute to ambient sound levels include sounds associated with wind, storms, and ice and marine animals.

The loudness of a sound source is determined by: (1) the radiated acoustic power (source level); (2) the propagation efficiency (transmission loss); (3) the ambient sound; and (4) the hearing sensitivity of the subject species at relevant frequencies. The analyses of the effects of underwater sound are based on the Source → Path → Receiver concept. The acoustic energy originates with a “source” that generates underwater sound. Sources of anthropogenic underwater sounds associated with exploration activities include exploratory and delineation drilling, 2-D and 3-D seismic surveys, vertical seismic profiling and geohazards surveys and wellsite abandonment. Sound from these sources radiates outward and travels through the water (“path”) as pressure waves. The received level decreases with increasing distance from the source. The “receiver” of these sounds may be a marine mammal, fish or invertebrate. Whether or not the sounds are received depends upon how much propagation loss occurs between the source and the receiver, the hearing abilities of the receiver, and the amount of natural ambient or background sound in the sea around the receiver. Underwater ambient sound, if it is sufficiently strong, may prevent an animal from detecting another sound through a process known as masking. Masking can occur as a result of either natural sounds (e.g., periods of strong winds, heavy rainfall, storm events, ice movements and marine animal communications) or anthropogenic sounds (e.g., distant shipping). The sea is a naturally noisy environment and even in the absence of anthropogenic sounds, this natural sound can “drown out” or mask weak signals from distant sources.

2.4.2 In-Air Sound

In-air sounds will result from aircraft operations during exploration, production and from equipment on ships and platforms located above the waterline. The primary noise source will likely be helicopters. In-air anthropogenic sound propagation has implications for marine mammals both underwater and, in the case of pinnipeds (i.e., seals), with their ears above the water surface, and in some cases, invertebrates, fish and sea turtles. The analyses of the effects of in-air sound are also based on the Source → Path → Receiver concept. The source frequencies and intensities of sounds from various oil and gas-related activities interact with the propagation characteristics between the source and receiver to cause variation in the quality and quantity of sound reaching a receiver. In-air sounds will result from aircraft support operations and from equipment on ships and platforms located above the waterline.

Sound traveling from a source in air to a marine animal receiver underwater propagates in four ways: via a direct refracted path; direct refracted paths that are reflected by the bottom; a “lateral” (surface-traveling) wave; and scattering from a rough sea surface (Urick 1972). The types of propagation vary in importance depending on local conditions, water depth, and the depth of receiver. Under calm sea conditions, airborne sound is reflected at larger angles and does not enter the water. However, some



airborne sound may penetrate water at angles >13° from the vertical when rough seas provide water surfaces at suitable angles (Lubard and Hurdle 1976).

2.4.2.1 Ambient Noise Levels

The Labrador Sea is the part of the North Atlantic Ocean separating Labrador from Greenland. The SEA Area encompasses the sea from Cape Chidley in the north to Battle Harbour in the south, essentially the entire Atlantic coast of Labrador. A study by the US Naval Research Laboratory done in July 1972, near the 45˚W meridian in the Labrador Sea, showed that average ambient noise levels at 914 m depth were 87 decibels (dB) re 1 µPa/Hertz (Hz) @ 50 Hz. Studies of ambient noise worldwide have shown a 3 dB rise in levels per decade from 1950 to 2000 (Mazzuca 2001; Andrew et al. 2002; Ocean Studies Board 2003) which would bring the levels to approximately 96 dB today. It should be noted that this might not necessarily relate to levels in the Labrador SEA Area.

Many sources contribute to ambient noise in the ocean, from marine mammals and ocean life to anthropogenic noise.

2.4.2.2 Marine Mammal Noise

The Labrador Shelf SEA Area is home to a diverse ecological community. Many of the species who inhabit or migrate through the Labrador Shelf SEA Area contribute to ambient noise levels via acoustic communication and echolocation techniques. Cetaceans are common in the Labrador Shelf SEA Area, especially in the summer months, when whales, porpoises and dolphins migrate north through the area. Cetaceans use sound for communication, navigation and hunting. The acoustic characteristics of Labrador Shelf SEA Area cetaceans are summarized in Table 2.3.

Table 2-3 Regional Cetacean Acoustic Characteristics

Species Season/Time Spent in RegionA Frequency range

of acoustic communication

(kHz)4

Intensity of Acoustic Communication

Beluga whale Occasional migration to NL coast from Arctic1 0.26 to 20

Bottlenose whale Occasional migration to NL coast from Labrador coast1 3 to 26

Long-finned Pilot Whale Follows squid migrations2, summer and winter month 1 to 18

Minke whale Summer months, attracted by capelin² 0.060 to 20 Source level: approximately 160 dB re 1 µPa at 1 m

Humpback whale Primarily Summer months² sighted throughout year in Labrador Shelf SEA Area 0.020 to 8.20 Source level: approximately

175 dB re 1 µPa at 1 m

Sperm whale Primarily Summer months² sighted throughout year in Labrador Shelf SEA Area 0.1 to 30 Source level: approximately


Fin whale Primarily Summer months² sighted throughout year in Labrador Shelf SEA Area 0.010 to 28 Source level: approximately


Blue whale Summer and Fall month3 0.012 to 31 Source level: approximately 150 dB re 1 µPa at 1 m

Harbour Porpoise Primarily Summer months² sighted throughout year in Labrador Shelf SEA Area 0.0020 Source level: approximately

100 dB re 1 µPa at 1 m Dolphins (white-sided and white-beaked)

Primarily Summer months² sighted throughout year in Labrador Shelf SEA Area 0.0060 to 0.015

Bearded seal Occasional migration on ice in spring to Labrador 5 0.02 to 6 Source level: approximately 178 dB re 1 µPa at 1 m

Ringed seal Uncommon in spring off Labrador5 0.4 to 16 Source level: approximately 90-130 dB re 1 µPa at 1 m

Source: 1. Guerrero 2006. 2. DFO 1993a. 3. DFO Data. 4. Richardson et al. 1995.

5. Folkens et al. 2002.



2.4.2.3 Shipping Traffic and Anthropogenic Noise

Vessels are major contributors to background sound in the ocean. Sound levels generated by boats and ships are highly variable but generally related to type, age, size, power, load and speed. The primary sources of sound are propeller cavitation and singing, and propulsion, pumping, compressor and generating systems. A ship breaking ice creates additional sound from the ice, but most of the increase in sound level is due to the increased load on the vessel and increased cavitation. Traffic noise is the combined effects on ambient noise levels of all shipping at long ranges and dominates the ambient noise in the 20 to 300 Hz frequency range. Noise from distant fishing vessels also contribute to ambient noise, peaking at 300 Hz (Richardson et al. 1995).

2.4.2.4 Wind- and Wave-generated Sound

Meteorological conditions such as wind and precipitation can make measurable contributions to ambient noise. Noise produced by wind is in the range of approximately 100 Hz to 50 kiloHertz (kHz), noise produced by large surface waves occurs in the 1 to 20 Hz range, and noise produced by precipitation occurs at frequencies above 500 Hz (Wenz 1962).

2.4.2.5 Comparison of Noise Levels

A comparison of natural and potential exploration-related noise levels is provided in Table 2.4.

Table 2-4 Comparison of Natural and Potential Exploration-related Noise Levels

Source Noise Level (dB re 1µPa)

Noise Frequency (Hz) Notes

Ambient Noise Calm Seas 60 - Modern Waves/surf 102 100 to 700

Fin whales 160 to 186 20 Fin whales produce series of one to five second noise pulses across 3 to 4 Hz around the 20 Hz level.

Seismic Exploration Small Single Airgun 216 10 to 5,000 0 to peak Medium Single Airgun 225 10 to 5,000 0 to peak Large Single Airgun 232 10 to 5,000 0 to peak GSC 7900 Array 259 10 to 5,000 0 to peak ARCO 4000 Array 255 10 to 5,000 0 to peak GECO 3100 Array 252 10 to 5,000 0 to peak Drilling-related Noise Jack-up Drilling units 119 to 127 5

Moored Semi-submersibles 154 - Overall, broadband sound level did not exceed ambient beyond about 1 km; received levels at 100 m would be approximately 114 dB re 1 µPA.

Moored Drillships 174 to185 45 to 7,070 Noise is predicted to attenuate to 115 to 120 dB at distances of 1 to 10 km.

Supply boats 170 to 180 100 Other Industrial Noise Fishing trawlers 158 At 100 Commercial freighter 172 - Supertanker Chevron London 190 dominant tone of

6.8 Hz

Helicopter (Sikorsky @ 305 m above water) 105 -

Pile-driving (1 km distance) 131 to 135 - Source: Richardson et al. 1997, in Hurley and Ellis 2004; Lawson et al. 2000 in Hurley and Ellis 2004; Thompson et al. 2000, in Hurley and Ellis 2004.



2.4.3 Offshore Oil and Gas Industrial Sounds

Sources of underwater sounds associated with exploration and production activities include:

• exploratory and delineation drilling;

• 2-D and 3-D seismic surveys;

• vertical seismic profiling and geohazards surveys;

• production activities; and

• support vessels and aircraft.

Activities associated with the above may include drilling of wells (either exploration or delineation wells), in addition to seismic and other geophysical surveys. The process of extracting oil and gas from the marine environment involves activities on many different times, spatial and acoustic scales. These include rig transportation to the site, platform installation, operational noise and sound associated with support vessels and aircraft.

2.4.3.1 Exploratory and Delineation Drilling

Underwater drilling noise from a variety of offshore platforms, artificial islands and drillships has been studied extensively, especially in Arctic environments. Gales (1982) surveyed underwater noise from drilling and production operations in locations from California to Alaska to the Atlantic, for both platforms and artificial islands. Greene (1987) studied the underwater drilling sound from drillships and a caisson-retained island in the Beaufort Sea, along with noise from vessels related to platform installation. A number of other studies can be found referenced and summarized in Richardson et al. (1995).

Drilling noise results from multiple processes; aside from the rotation of the drill string and the associated movement of pipe as it is fed through, there is the operation of generators, pumps, hydraulic equipment and other machinery in direct support of drilling. This noise is generally confined to the low frequency end of the spectrum, below 1 kHz. A relatively strong infrasonic component approximately 1.5 Hz, corresponding to the rotation rate of the drilling turntable, was measured by Hall and Francine (1991) for the Glomar Concrete Island Drilling System (CIDS) caisson in the Beaufort Sea. This infrasonic noise is likely to occur from most drilling rigs but may not be detected on conventional recording equipment.

Drilling can produce maximum broadband (10 Hz to 10 kHz) energy of approximately 190 dB re 1μPa @ 1 m. Noise from dynamic positioning (DP) drill ships and semi-submersible noise comes from both the drilling machinery and the propellers and thrusters used for station keeping. Drilling generates ancillary noise from the movements of supply boats and support helicopters. Emplacement of drilling platforms creates localized noise for brief periods. Powerful support vessels are used to transport these large structures.

Deep-water drilling has the potential to generate greater noise than shallow-water drilling, owing to the use of dynamically positioned drilling units. This noise may be more easily coupled into the deep sound channel for long-range propagation. The level of drilling noise from any platform will on occasion increase temporarily when operations such as tripping (extracting the drill string to change the bit and reinserting it afterwards) are performed; no references to quantitative measurements of these variations have been found.



2.4.3.2 Two-dimensional and Three-dimensional Seismic Surveys

Two-dimensional and three-dimensional seismic surveys (refer to Figure 2.1) are most commonly carried out using airguns and streamers towed behind a seismic vessel. The length of time a seismic survey continues depends on the area in question, but usually ranges from a week to a month (it should be noted that depending on the size of the seismic program an weather and technical delays, the actual duration of a survey could last a few months). A typical seismic survey lasts two to three weeks and covers a range of approximately 555 to 1,110 km. The ship towing the array is typically 60 to 90 m long and moves through the water at speeds usually in the range of 8 to 10 km/h (4.5 to 5.5 knots).

Acoustic propagation and received sound levels in the Labrador marine environment will vary as a function of depth, range and environmental properties (oceanographic and geoacoustic). The most important environmental parameters needed to give accurate predictions are the sound speed profile, the bathymetry and the bottom loss. The sound speed profile will vary with temperature and salinity; hence, it will vary seasonally and with depth.

Hydrophone assemblies are towed as “streamers” behind a vessel, with between 6 to 10 streamers towed in typical 3-D surveys. A smaller number of streamers are towed in a typical 2-D survey.

Airguns and arrays of airguns are towed approximately 50 to 250 m behind a ship and “release” compressed air every 6 to 10 seconds for duration of 10 to 30 milliseconds per shot. Hydrophone assemblies in the form of a cable (0.5 to 8 km in length) are towed behind the airgun arrays to record the reflected sound waves. The arrays and hydrophones are usually towed several metres below the sea surface. The arrays may consist of 10 to 70 airguns (Richardson et al. 1995).

The noise associated with airguns can range between approximately 215 and 235 dB re 1 µPa-m for a single airgun and approximately 235 to 260 dB re 1 µPa-m for arrays (Richardson et al. 1995). The downward pressure pulse or source strength ranges between 1 and 8 bar-m for a single gun or 12 and 174 bar-m for an array (Richardson et al. 1995); frequencies range between 10 and 300 Hz. For an airgun with sound intensity of 250 dB at the source, noise levels over 30 km away can be as high as 117 dB.

2.4.3.3 Airgun Operating Principles

An airgun is a pneumatic sound source that creates low-frequency acoustic impulses by generating bubbles of compressed air in water. The rapid release of highly compressed air (typically at pressures of approximately 2,000 pounds per square inch (psi) from the airgun chamber creates an oscillating air bubble in the water. The expansion and oscillation of this air bubble generates a strongly peaked, high-amplitude acoustic impulse that is useful for seismic profiling. The main features of the pressure signal generated by an airgun, as shown in Figure 2.5, are the strong initial peak and the subsequent bubble pulses. The amplitude of the initial peak depends primarily on the firing pressure and chamber volume of the airgun, whereas the period and amplitude of the bubble pulse depends on the volume and firing depth of the airgun (Figure 2.5).



Figure 2.5 Air Pressure Signature

Airguns are designed to generate most of their acoustic energy at frequencies less than approximately 200 Hz, which is the frequency range most useful for seismic penetration beneath surficial seabed sediment layers. In general, the frequency output of an airgun depends on its volume: larger airguns generate lower-frequency impulses. However, due to the pulsive nature of the source, airguns inevitably generate sound energy at higher frequencies, above 200 Hz, although the energy output at these frequencies is substantially less than at low frequencies.

Zero-to-peak source levels for lone airguns are typically between 220 and 230 dB re μPa•m, with larger airguns generating higher peak pressures than smaller ones. However, the peak pressure of an airgun only increases with the cubic root of the chamber volume. Furthermore, the amplitude of the bubble pulse also increases with the volume of the airgun and for the geophysicist; the bubble pulse is an undesirable feature of the airgun signal, since it smears out sub-bottom reflections. Therefore, in order to increase the pulse amplitude (to see deeper into the Earth); geophysicists generally combine multiple airguns together into arrays. Airgun arrays provide several advantages over single airguns for deep geophysical surveying:

• the peak pressure of an airgun array in the vertical direction increases nearly linearly with the number of airguns;

• airgun arrays are designed to project maximum peak levels toward the seabed (i.e., directly downward); and

• by using airguns of several different volumes, airgun arrays may be “tuned” to increase the amplitude of the primary peak and simultaneously decrease the relative amplitude of the bubble pulse.

2.4.3.4 Airgun Array Source Levels

The far-field pressure generated by a seismic airgun array is substantially greater than that of an individual airgun. An array of 30 guns, for example, may have a zero-to-peak source level of 255 dB re μPa•m in the vertical direction. This apparently high value for the source level can lead to erroneous conclusions about the effect on marine mammals and fish for the following reasons:



• peak source levels for seismic survey sources are usually quoted relative to the vertical direction; however, due to the directional dependence of the radiated sound field, source levels off to the sides of the array are generally lower; and/or

• far-field source levels do not apply in the near-field of the array where the individual airguns do not add coherently; sound levels in the near-field are, in fact, lower than would be expected from far-field estimates.

Airgun energy levels generally decrease, and signal duration increases, with increasing range. In shallow water, higher frequencies (approximately 200 Hz) usually arrive before lower frequencies (approximately 70 Hz) at ranges of several kilometres. This results in a downward sweeping “chirp”-like sound. Although the arrays direct as much energy as possible, downward strong sound pulses propagate horizontally, even in shallow water.

Greene and Richardson (1988) made recordings using open bottom gas guns in water 9 to 11 m depth, hydrophone depth 8 m, ranges 0.9 to 14.8 km. Received levels ranged from 177 dB re 1µPa at range 0.9 km to 123 dB at 14.8 km.

The acoustic source level of a seismic airgun array varies considerably in both the horizontal and vertical directions, due to the complex configuration of guns composing the array. This variability must be accounted for in order to correctly predict the sound field generated by an airgun array. If the source signatures of the individual airguns are known, then it is possible to accurately compute the source level of an array in any direction by summing up the contributions of the array elements with the appropriate time delays, according to their relative positions.

The difference in sound levels between one direction and another of an airgun array is called its directivity. It is typically discussed in the horizontal direction, comparing broadside sound levels to endfire levels. A towed airgun array may have sound levels more than 10 dB greater at broadside than endfire. The directivity of an array is a function of its geometry and varies depending on the particular airguns being used.

Geohazard Surveys

Several tools exist for geoscientists to get an idea of what the bottom of the ocean looks like and determine if hazards to oil and gas activities are present. Active sonar is the most common tool for undertaking geohazard surveys. Types of sonar include simple depth sounders, multibeam sonar and side-scan sonar.

Depth sounders and multibeam sonar work by transmitting a ping of noise (signal) through the water column and measuring the time the sound takes to return to the receiver; the distance to the bottom or object of interest can be calculated this way. Multibeam sonar sends a fan-shaped swath of pings to the bottom, so that enough depth information can be gathered to get a very detailed image of the bathymetry, including any marine geohazards present.

Side-scan sonar is similar to multibeam sonar except instead of measuring the time for a signal to return to the transmitter, it measures the strength of the return signal. This creates an image of the ocean bottom where objects that protrude from the bottom create a dark image (strong return) and shadows from these objects are light areas (little or no return). No information on the water depth can be gained using this method. A sidescan is usually towed behind a vessel.



Side-scan Sonar System for Seabed Imagining

Side-scan sonar builds up a 2-D picture of the seabed, together with any targets on the seabed, using a combination of an asymmetrical transducer and the motion of the sonar platform through the water. Typical side scan sonar uses a simultaneous dual frequency (105 and 390 kHz) system. It has peak to peak source levels of 228 dB re 1μPa @ 1 m for 105 kHz and 222 dB re 1μPa @ 1 m for 390 kHz. The side scan firing rate is 3.3 times per second (300 millisecond (msec) firing rate) at 200 m range. Side-scan horizontal beam widths are 1.2 degrees at 105 kHz and 0.5 degrees at 390 kHz. Both sweep over an arc (perpendicular to transect) of 50 degrees.

Sub-bottom Profiler

Sub-bottom profiling operations use a Deep Tow System (DTS) deployed from the stern of the survey vessel, through an “A” Frame. The system is towed approximately 150 m behind the survey vessel (dependent on cable deployed, water depth and vessel speed), and approximately 20 to 40 m above the seabed.

The DTS uses a broadband acoustic source with frequency bandwidth from 500 Hz to 6 kHz. Power output is typically 500 Joules, but may be increased to 1 kiloJoules (kJ) if necessary. Rise time of the pulse is less than 0.1 millisecond. The boomer derived pulse is primarily restricted to a 60-degree cone. Maximum peak to peak amplitude is 221 dB relative to 1 μPa at 1 m. The system uses an internal and external hydrophone to record the return signal. Vertical resolution is approximately 10 cm, with penetration of 40 m in sands and 100 m in soft sediment. The option exists to use a sparker source, instead of the boomer, if seabed conditions and data quality warrant it. This system is more omni-directional, and provides similar output power at a lower frequency.

Echo-Sounder

Geophysical surveying operations may employ either a dual frequency single beam sounder or a multibeam echo-sounder. A typical single beam echo-sounder (SBES), which is dual frequency capable, operates at 24 and 200 kHz. SBES source levels are 219 dB re 1μPa @ 1 m for 24 kHz, and 215 dB re 1μPa @ 1 m for 200 kHz (peak to peak). The SBES firing rate is typically two times per second. Conical beam widths are 9 degrees (200 kHz) and 24 degrees (24 kHz). A multibeam echo sounder (MBES) operates 240 kHz, with a source level of 213 dB re 1μPa @ 1 m (peak to peak). Its firing rate is approximately four to six times per second, with a beam width of 1.5 degrees per beam. To cover a 150 degree arc, 101 beams are used perpendicular to the transect direction.

Vertical Seismic Profiles

VSPs are a collection of well bore measurements (seismograms) developed by means of geophones inside the wellbore and sound sources at the surface near the well. The seismic data can be gathered while the borehole is being drilled or afterwards. These measurements are used to correlate with surface seismic data, for obtaining images of higher resolution than surface seismic images and for looking ahead of the drill bit.

Standard surface seismic surveys use a seismic source on or near the Earth’s surface, which emits energy that reflects at subsurface interfaces and is recorded by a set of receivers also located on or near the surface. VSPs, also known as borehole seismic surveys, differ in that receiver locations are restricted to the confines of a borehole. While this constraint limits the image volume, it also confers several advantages to seismic surveys in the borehole. For example, waves that travel from a surface source, reflect off a subsurface reflector and then arrive at a borehole receiver are less attenuated by



shallow low-velocity layers, having traversed them only once, instead of the two times traveled by surface seismic waves.

The borehole usually is a quieter environment than the surface, so receivers can collect data with higher signal-to-noise ratio. Receivers clamped in the borehole record multiple components of seismic energy in the form of converted shear and direct compressional waveforms, whereas towed marine seismic and standard land seismic acquisition methods record a single component of data that is processed to enhance only compressional arrivals.

Borehole receivers can record direct down going airwaves, and/or signals that have been reflected from subsurface geology adjacent to the receivers. Changes in the direct signal recorded at multiple calibrated borehole receivers help determine the attenuation properties of overburden layers. Knowledge of attenuation properties helps restore portions of signal lost during transmission of both borehole and surface seismic waves. Receivers can be positioned accurately at specified depths in the borehole, allowing geophysicists to derive a profile of layer velocities at the well location. This helps convert time-indexed surface seismic data to depth, so seismic images can be tied to well-log data and drill-bit positions can be tracked on seismic sections.

There are numerous methods for acquiring VSPs. VSPs include the zero-offset VSP, offset VSP and walkaway VSPs. Zero-offset VSPs have sources close to the wellbore directly above receivers. Offset VSPs have sources some distance from the receivers in the wellbore. An offset VSP uses a source located at an offset from the drilling unit during acquisition to allow imaging to some distance away from the wellbore. In a walkaway VSP, the source is moved to progressively farther offset at the surface and receivers are held in a fixed location, effectively providing a mini 2-D seismic line that can be of higher resolution than surface seismic data and provides more continuous coverage than an offset VSP. Three-dimensional walkaways, using a surface grid of source positions, provide 3-D images in areas where the surface seismic data do not provide an adequate image due to near-surface effects or surface obstructions.

With a zero-offset VSP, a seismic source array is deployed over the side of the drilling platform. A typical VSP source array would be comprised of four 150-cubic inch airguns and four 40-cubic inch airguns with a calibrated peak vertical source level of 242.5 dB re 1μPa @ 1 m. The source is activated three to five times to create a sonic wave that is picked up by the geophones in the borehole. VSP surveys are of short duration, lasting several hours to a few days.

A typical zero-offset compressional source signal has a 12 second linear sweep covering the frequency band 10 to 200 Hz. Frequency content for other VSPs include 10 to 100 Hz for an offset compressional source and 10 to 50 Hz for a zero offset shear source (Mi et al. 1999).

Vessel Traffic and Aircraft Operations

Various supply vessels will be involved in the support of exploration and production; they will serve a variety of roles, ranging from ice management to personnel transport possibly tinkering product to re-provisioning to inspection and maintenance work. In addition to marine vessel traffic, helicopters will fill a vital role especially in the transport of personnel to and from ships and platforms. All of these sources of noise will contribute to the overall acoustic environment of the area.

Underwater noise due to vessels and aircraft associated with the installation and operation of oil and gas facilities can be attributed primarily to dredgers, installation vessels, tugs and barges, icebreakers, supply ships, tankers, small vessels and helicopters.



Vessels discussed in this section can be characterized essentially as continuous noise sources, though, as discussed below, helicopter overflight is considered a transient noise source due to the limited angle of propagation of the airborne sound into the water column. The vessels involved in offshore oil and gas operations span a wide range of sizes, power ratings and applications and, consequently, generate widely different levels of underwater sound. Vessel and helicopter noise are a combination of tonal and broadband sounds, which in the case of vessels, is dependent on their size, design and speed (Richardson et al. 1995).

Boat and ship noise is attributable mainly to propeller cavitation, propeller singing, propulsion engines (noise transmitted through the vessel’s hull) or other machinery. Noise from any of these sources can be exacerbated given any damage or improper operation. Cavitation is usually the dominant noise source according to Ross (1976, in Richardson et al. 1995). The frequency spectrum of cavitation noise has been observed to be a broadband noise consisting of sharp pulses that correspond with the propeller rotation frequency times the number of blades (Erbe and Farmer 2000). Noise from older, medium to high-speed diesel engines built with simple connecting rods is strong enough to potentially overshadow cavitation (Ross 1976). Modern diesels built with articulated connecting rods (mostly found in tankers, freighters and container ships) are slow speed (<250 rpm) and relatively quiet, with cavitation being the dominant noise source (Richardson et al. 1995).

Generally, the larger the vessel, the greater the level and lower the frequency of sound emitted. A comparison of one-third octave bands associated with both small and medium to large vessels is provided in Figure 2.6. In an operation involving diverse vessel sizes, noise will be mainly due to medium and large vessels. When operating at relatively close range, small vessels with outboard engines, such as Zodiacs, may also contribute considerable underwater noise levels.

There will also be noise associated with ice/ship interaction in the case of icebreakers, icebreaking tankers and icebreaking supply vessels.

Figure 2.6 Estimated One-third Octave Sound Levels of Underwater Noise at 1 m for A) Boats; and B) Ships

Source: Richardson et al. 1995. Note: The icebreaker noise is from the Robert Lemeur (studied by Greene 1987) pushing on ice at full power (7.2 MW) and zero speed. This is estimated to be louder than that generated by an ocean-going tug pulling a load at low speed.



Airborne sound waves only penetrate effectively into the ocean environment within a 13-degree cone off the vertical; much of the noise outside this cone does not penetrate the water surface. Because of the conical acceptance volume, aircraft are audible in the water column for longer periods when flying at higher altitudes. Furthermore, the duration of audibility is greater for shallow receiver depths (Urick 1972; Greene 1985).

Propellers or rotors generate the primary source of aircraft noise. Blade rotation produces tones with fundamental frequencies dependant on the number of blades and rate of rotation. An increase in the number of blades also produces a corresponding increase in the fundamental frequency for a given rotation rate (Richardson et al. 1995). Generally, noise spectra are below 500 Hz, with dominant tones produced as harmonics of the blade rates of the main and tail rotors (Richardson et al. 1995). Tones associated with the engines and other rotating parts may be present, resulting in a potentially large number of less prominent tones at many frequencies.

2.4.3.5 Production

Additional noise is generated during oil production activities, which include borehole casing, cementing, perforating, pumping and ship and helicopter support. Production activities can generate source levels as high as 135 dB re 1μPa @ 1 km from the source (Greene and Moore 1995), which suggests as much as 195 dB re 1μPa @ 1 m with peak levels at 40 to 100 Hz.

Production machinery on board platforms will generate noise in addition to that created by drilling operations. Very little data exist in the literature in terms of non-drilling noise levels from platforms; Richardson et al. (1995) summarize a few reported measurements that generally point to very modest noise levels, but a quantitative acoustic characterization of such activities would require considerably more data and a more standardized monitoring approach. Measurements of noise from fixed production platform showed the strongest tones between 4.5 and 38 Hz, measured at ranges 9 to 61 m, peak sound spectrum levels at 50 to 200 Hz. Production machinery is generally located above the water, so sound transferred to the water column is not important.

2.5 Discharges Associated with Exploration and Production Activities

Discharges associated with the exploration and production activities may include drill fluids and muds, bilge water, deck drainage, ballast water, storage displacement water, glycol, cooling water, produced water, garbage, miscellaneous waste discharges (such as BOP fluid and cement slurry) and air emissions. All discharges will be required to comply with applicable limits as set forth in the Offshore Waste Treatment Guidelines (OWTG) (National Energy Board (NEB) et al. 2002). In addition to waste discharges; noise, light and accidental events are a consideration associated with exploration and production activities. As a result of the potential environmental effects associated with noise and accidental events, these issues are presented separately in Sections 2.3 and 2.6.

2.5.1 Drill Muds

Drill muds are a complex mixture of clays, chemical additives and water that are pumped down the drill pipe to lubricate and cool the drill bit, flush out cuttings, control formation pressures, seal permeable formations and maintain well bore stability. Drill muds can also help to minimize damage to reservoirs, prevent the formation of gas hydrates, assist in the transition of hydraulic energy to drill tools, assist in



formation evaluation via logging equipment, controls corrosion and facilitates casing cementing (CAPP 2001).

Drill solids (or cuttings) are the particles that are generated by drilling activities and are returned to the surface with drill muds. Drill solids associated with WBMs may be discharged after treatment. Drill solids associated with oil-based muds (OBMs) are not permitted to be discharged. Drill solids associated with SBMs are either reinjected or, when reinjection is not technically feasible, the synthetic-based muds (SBM) must be treated to achieve a concentration of 6.9 g/100 g or less oil on wet solids prior to discharge (NEB et al. 2002).

All exploration and production drilling on the east coast has been conducted using WBMs or SBMs. Hibernia reinjects greater than 95 percent of their cuttings; however, the feasibility of cuttings reinjection is dependent on a variety of factors that include drill platform type and site-specific geography, resulting in cuttings reinjection being more feasible for fixed platforms than for floating platforms.

The drill bit cuts the formation rock, producing drill cuttings, resulting in the creation of the well bore. Drill mud is circulated through the drill pipe and out through small jets or holes in the drill bit. The velocity and viscosity of the mud flushes drilled cuttings away from the bit, transporting them to the surface through the annulus, as illustrated in Figure 2.7 (CAPP 2001).

Figure 2.7 Drill String Components Illustrating Drill Mud Circulation

Source: CAPP 2001.



At predetermined intervals, steel casing is cemented into the well hole, thereby providing a conduit that returns muds and cuttings to the drill platform for treatment and discharge. Drill mud is expensive and, as much as possible, is recovered for reuse. However, some mud will remain on the drill cuttings and be discharged. Discharged drill cuttings are required to meet the drill solids requirements outlined in the OWTG (NEB et al. 2002) prior to disposal via discharge.

The muds and the cuttings are dispersed in the water column and settle to the seabed, with heavier cuttings and particles near the hole and the fines dispersed at increasing distances from the drill unit. The dispersion pattern for muds and cuttings is irregular, largely dependent on water depth and current direction as well as intensity. In some cases, majority of muds and cuttings initially deposited with 1,000 m from source (National Research Council (NRC) 1983). Depending upon bottom energy, the deposited muds and cuttings may persist as discharged or undergo rapid or prolonged dispersion (Neff 1987). Drill, mud and cuttings and their potential effects have been discussed in several recent studies (Husky 2000, 2001; CAPP 2001; Hurley and Ellis 2004) and all confirm that exploratory drilling has no measureable effect on the marine environment.

2.5.1.1 Water-based Muds

WBMs employ freshwater or brines as the continuous liquid phase. WBMs muds are generally used in the earliest sections of a well, including shallow exploratory wells. Muds generally are composed of barite, bentonite or other clays, silicates, lignite, caustic soda, sodium carbonate/bicarbonate, inorganic salts, surfactants, corrosion inhibitors, lubricants and other additives for unique drilling problems (Thomas et al. 1984; GESAMP 1993). The constituents of muds are screened via the Offshore Chemical Screening Selection Guidelines (NEB et al. 1999). Composition of an example of a typical water-based mud (WBM) formulation is presented in Table 2.5.

Table 2-5 Typical Drill Mud Components and Drill Cuttings Discharge Volume for a Grand Banks Discharge Well

Casting Strings Unit Conductor Surface Production Hole Section inch 36 16 12¼ DF System Gel/SW Gel/SW WBM Depth (See Note 4) metre (brt) 220 1,200 3,600 Volume Usage Bbl 897 4,199 5,246 Wash Out % 50 30 10 Products Barite MT - 58 115 Bentonite MT 16 65 - Calcium Carbonate kg - - - Caustic kg 116 482 138 Fluid Loss Agent kg - - 2,385 Inhibitor kg - - 4,769 Fluid Loss Agent kg - - 9,538 Potassium Chloride kg - - 100,153 Lime kg 116 482 - Glycol Inhibitor L - - 25,024 Soda Ash kg 116 482 238 Viscosifier kg - - 3,577 Biocide L - - 72 Drilled Cuttings kg 192,032 429,562 521,786 Volume of Cuttings m3 74 165 201 Source: Husky 2003, in LGL Limited 2005a. Notes: 1. Three scenarios were taken into account. The 310-mm (12¼”) hole section varies in depth with each scenario. 2. 900-mm (36-inch) and 400-mm (16-inch) hold section - near seabed discharge. 3. WBM used for complete well. 4. All depths are measured below rotary table (brt). The rotary table is 145 m above the seafloor.



Spent and excess WBMs may be discharged on-site from offshore installations without treatment (NEB et al. 2002). Operators should have procedures that reduce the need for the bulk disposal of these muds following either a drilling mud changeover or a drilling program completion.

2.5.1.2 Synthetic-based Muds

SBM refers to a water-in-oil emulsion whose continuous phase is composed of one or more fluids produced by the reaction of a specific purified chemical feedstock, rather than the physical separation processes such as fractionation, distillation and minor chemical reactions. SBMs are produced to duplicate favorable properties of both WBMs and OBMs.

SBMs were developed as a replacement to OBMs, which were toxic and were partially responsible for the longevity of cuttings piles. SBMs are typically used for long reach (i.e., onshore to offshore) drilling, directional drilling and in deep waters where hole stability and integrity are critical. The Synthetic-based fluids (SBFs) used in the preparation of SBMs are water insoluble and, as such, the SBM does not disperse in water in the same manner as a WBM (Hurley and Ellis 2004). Therefore, as SBMs tend to sink to the sea bed, research has focused on toxicity in the sedimentary phase as opposed to the aqueous phase.

The OWTG (NEB et al. 2002) require that SBM (if approved for use by the Chief Conservation Officer), be recovered and recycled, reinjected down-hole, or transferred to shore for approved disposal (NEB et al. 2002). The discharge of whole SBM is not allowed.

Synthetic Base Fluid Properties

SBFs used as the base fluid in SBMs typically have a total PAH concentration of less than 10 mg/kg (<0.001 percent) and are non-acutely toxic in most or all marine toxicity tests. Examples of synthetic based fluids that are a component of SBMs include C16-C18 internal olefins, poly-alpha olefins, linear-alpha olefins, esters and low viscosity esters, as well as other SBFs such as paraffinic fluids (i.e., saturated hydrocarbons or alkanes). One of the drilling muds used on the Grand Banks is a SBM with PureDrill IA-35 or PureDrill 1A-35LL as the base fluid, together with weighting agents, wetting agents, emulsifiers and other additives. The synthetic-based fluids (SBF) PureDrill IA-35 that is used in the Grand Banks SBMs is classified as a high purity synthetic alkane consisting of isoalkanes and cycloalkanes (Williams et al. 2002a). PureDrill IA-35 is a clean, colourless, odourless fluid that is safe to handle (Williams et al. 2002a). It has an aromatic content of <0.01 percent and a PAH content of <0.001 ppm. It is non-toxic to human, plant and marine life.

PureDrill IA-35 had undergone an evaluation using the Offshore Chemical Management System (OCMS). The fluid was screened from a facility, human health and environmental perspective (Williams et al. 2002a). PureDrill IA-35 base oil (SBF) is a component of a whole mud system called ParaDrill that received a Group E classification by the Offshore Chemical Notification System (OCNS) classification system employed in the UK. The Group E classification is the best rating achievable under the OCNS system and is assigned to chemicals that have relatively low toxicity and/or does not bioaccumulate or readily biodegrades. The formulation of ParaDrill-IA, a commonly used SBM on the Grand Banks, is presented in Table 2.6.



Table 2-6 Composition of ParaDrill-IA Component Purpose

PureDrill IA-35 Base Fluid NOVAMULL L Primary Emulsifier NOVAMOD L Rheology Modifier NOVATHIN L Thinner MI-157 Wetting Agent HRP Rheology Modifier TRUVIS Viscosity VERSATROL Filtration Control ECOTROL Filtration Control (Alternative) Lime Alkalinity Calcium Chloride Salinity Water Internal Phase Barite Density Source: Williams et al. 2002, in LGL Limited 2005a.

The toxicity data for PureDrill IA-35 (Harris 1998) are:

• mysid shrimp 96-hour LC50 of >500,000 ppm;

• rainbow trout 96-hour LC50 of >400,000 ppm;

• amphipod (Corophium volutator) 10-day LC50 of 2,633 mg/L;

• Macoma 20-day LC50 of >50,000 mg/L;

• echinoid fertilization (Lytechinius pictus) IC50 (20 minutes) of >100 percent; and

• bacterial bioluminescence (Microtox test using Vibrio fischeri) EC50 of >100 percent.

Toxicity studies conducted by DFO using American plaice (Hippoglossoides plastessoides) and the amphipod Rhepoxynius abronius on Hibernia drill cuttings found:

• no acute toxicity in juvenile American plaice exposed for 30 days to Hibernia cuttings, approximating hydrocarbon concentrations found 200 to 500 m from rigs in the North Sea (Payne et al. 2001a); and

• in a dose response study using amphipods a toxic response at 5,000 ppm hydrocarbon concentration only. The cuttings demonstrated a low acutely toxicity potential and extrapolations have been carried out to determine possible size of toxic zones. The extrapolations indicate little or no risk of toxicity as close as 1,000 m or less from the rig (Payne et al. 2001b).

2.5.2 Cement Slurry and Blowout Preventer Fluid

The upper reaches of a well (60 to 1,200 m) may be drilled into sediments with no casing by a process referred to as spudding. The drill string is removed and a pipe (casing) is inserted and cemented into place. Based on experience with previous exploratory wells (Husky 2000), excess cement may be released to the environment.

BOP fluid, a glycol-water mixture, is used in the BOP during drilling. Periodic testing of the BOP fluid is required, resulting in the release of small amounts of glycol (LGL Limited 2002). Subsea BOPs used with semi-submersibles and drillships typically release a greater amount of fluid compared to surface BOPs on a jackup. On occasion, a remotely operated vehicle (ROV) is required to operate subsea



BOP functions directly via an interface called a “hot stab”. Small quantities of BOP fluid can be released in these operations,

2.5.3 Produced Water

Produced water includes formation water, injection water and process water that is extracted along with oil and gas during petroleum production. Little if any produced water is associated with exploration drilling programs, it is a primary waste stream during production. Produced water is usually discharged back into the marine environment (although it is reinjected in some fields). Current OWTG (NEB et al. 2002) require produced water to be treated to 30 mg/L oil in discharged produced water.

Produced water is warmer that the receiving environment and contains residual oil from the formation. Produced water may also contain a range of trace metals and radioisotopes. The typical chemical composition of produced water is provided in Table 2.7. During exploration drilling activities, if produced water is encountered during flow testing, then it is either treated prior to discharge or atomized in the flare.

Table 2-7 Chemical Composition of Produced Water from Norwegian North Sea Platforms

Compound Unit Statfjord Gullfaks Ekofisk 2/4B-K Ekofisk 2/4B Tor Ula

TOC mg/L 850 61 180 - 85.5 71 THC mg/L 15 35 - - - 50 Sum Aromatics mg/L 6 9.56 5.67 66.95 - 15 BTX µg/L 4 5 5.41 66.90 1.1 12 Naphthalenes mg/L 0.942 2.16 0.247 0.052 0.597 - Naphthalene 0.261 0.398 0.157 0.038 0.073 - C1-naph mg/L 0.35 0.628 0.062 0.012 0.17 - C2-naph mg/L 0.199 0.584 0.018 0.002 0.204 - C3-naph mg/L 0.132 0.55 0.010 0.0005 0.155 - Phenanthrenes mg/L 45 90 6.26 0.28 135 - Phenanthrene mg/L - - 2.09 0.08 - - C1-phenanthrene mg/L - - 2.43 0.12 - - C2-phenanthrene mg/L - - 1.74 0.08 - - C3-phenanthrene mg/L - - n.d. n.d. - - Dibenzothiophenes µg/L 8.6 22.7 1.39 0.15 10 - Dibenzothiophene µg/L - - n.d. n.d. - - C1-Dibenzothiophene µg/L - - 1.39 0.03 - - C2-Dibenzothiophene µg/L - - n.d. 0.12 - - C3-Dibenzothiophene µg/L - - n.d. n.d. - - Sum NPD µg/L 1 2.27 0.254 0.055 0.74 - Acenaphytlene µg/L - - 0.89 0.02 - - Acenaphthene µg/L 0.001 0.001 n.d. 0.04 0 - Fluorene µg/L 12 11.3 n.d. 0.33 8.1 - Fluoranthene µg/L 0.0854 0.195 n.d. n.d. 0.24 -- Pyrene µg/L 0.0894 0.194 n.d. 0.08 0.42 - Chrysene µg/L 0.226 0.398 - - 0 - Benz(a)anthracene µg/L 0.0193 0.311 n.d. n.d. 0.23 - Benzo(a)pyrene µg/L 0.001 0.001 n.d. n.d. 0 - Benzo(ghi)perylene µg/L 0.001 0.001 n.d. n.d. 1.35 - Benzo(k)fluoanthene µg/L 0.0197 0.0528 n.d. n.d. 0.016 - Sum PAH 3-6 Ring µg/L 66.04 125.15 0.89 0.47 155.36 - Sum Phenol mg/L 8.3 2.7 1.03 2.56 3.62 0.09 Phenol mg/L 5.1 0.8 0.61 0.97 2.19 0.033 C1-phenol mg/L 2.5 0.86 0.19 0.83 1.1 0.028 C2-phenol mg/L 0.4 0.6 0.14 0.57 0.254 0.02



Compound Unit Statfjord Gullfaks Ekofisk 2/4B-K Ekofisk 2/4B Tor Ula

C3-phenol mg/L 0.13 0.18 0.06 0.26 0.0316 0.0006 C4-phenol mg/L 0.026 0.1 0.03 0.02 - - C5-phenol mg/L 0.016 0.065 n.d. n.d. - - C6-phenol mg/L 0.013 0.11 n.d. n.d. - - C7-phenol mg/L 0.005 0.012 n.d. n.d. - - Sum Organic Acids mg/L 895 55 323 577 234 - Formic Acid mg/L - - 148 275 - - Acetic Acid mg/L 732 15.6 132 267 104 9.5 Propionic Acid mg/L 106 8.9 35.2 27.4 10 1.2 Butylic Acid mg/L 39 14.1 6.35 5.18 - 1.5 Valeric Acid mg/L 18 8.2 1.61 2.17 - 0.6 Carioic Acid mg/L 9 8.2 n.d. 0.09 - - Organic Acids > C6 mg/L - - n.d. n.d. - - Methanol mg/L - - 6.3 33.9 - - Salinity Cl- mg/L - - 30,400 - 90,500 40,400 Ammonium mg/L 24.5 26.9 - - - 0.1 Lead µg/L 50 50 n.d - 80 270 Copper µg/L 2 2 20 - 600 20 Iron mg/L - - 4 - 8.9 23 Barium mg/L - - 28.2 -- 42.1 12 CS-Vl µg/L 10 10 6 - 0.08 40 Mercury µg/L 1.9 1.9 n.d. - - 9 Zinc µg/L 6.8 13 13 - 200 0.26 Cadmium mg/L 10 10 n.d. - - 0.02 H2S mg/L 0.12 0.17 - - -- - Total Radioactivity Bql - - - - - - 40K Bql - - - - - - 226Ra Bql - - - - - - Source: Røe and Johnsen 1996, in LGL Limited 2005b.

The scientific literature indicates that toxicity of produced water is related to the produced water’s chemical composition and so varies widely, ranging from non-toxic to toxic. The causative agents of the observed toxicity in produced waters are not known. However, it has been theorized that the toxic responses may be related to extremely high dissolved solids (salinity) concentrations, altered ratios of seawater ions, elevated ammonia (Moffitt et al. 1992), hydrocarbons, hydrogen sulphide and volatile compounds (Sauer et al. 1992).

2.5.4 Air Emissions

Exploration installations are usually in an area for a short duration (e.g., exploration drilling usually takes 40 to 90 days, depending on the water and well depths to be drilled). Air emissions for production activities originate from flaring, generator exhaust, support vessels exhaust, helicopter exhaust, fugitive emissions from storage tanks and other related exhaust associated with production activities. Although, air emissions have been of limited concern to date, increasing societal focus on greenhouse gases (GHG) and climate change issues, air emissions may be subject to a greater focus within the Labrador Shelf SEA Area than for previous offshore exploration and production activities to date.



The main source of air emissions associated with routine activities of exploration drilling (Husky Energy 2007) includes:

• the burning of diesel fuel for power generation on the drill unit;

• flaring during any required well testing; and

• fugitive emissions will be a negligible source.

Exhaust gas will be emitted from diesel-powered generators on drill units and the support vessels. Exhaust gases are known to contain oxides of nitrogen, carbon dioxide, and methane emissions that make up greenhouse gas emissions and are recorded in carbon dioxide equivalent (CO2e). Husky Energy (2007) noted that air emissions from a typical rig with two engines of less than 600 horsepower, performing development drilling year round produced approximately 18,509.34 tonnes CO2e per year (CO2 [17,690.57] + N2O [2.58] + CH4 [0.90]).

Testing of the wells is critical to the determination of the reservoir and fluid conditions. Flaring activities during required well testing produces air emissions in the order of 1,650 tonnes CO2e per test (Husky Energy 2007). Project specific Environmental Assessments may want to consider limiting flaring activities to only those tests necessary to determine reservoir parameters.

Fugitive emissions from valves, seals, open ended piping release air emissions. However, this source is typically less than 1 to 2 percent of overall emissions and as such is considered negligible (Husky Energy 2007).

As a planning strategy, all potential reduction strategies should be investigated and analyzed during the early planning and design stages of a project, when BATEA best applicable technology options are easier and more economical and achievable to address. Operators should estimate of the annual quantities of GHG that would be emitted from its offshore installation(s), provide a description of potential means for their reduction and reporting and calculate and report the GHG emitted from the installation on an annual basis as per the requirements of the OWTG (NEB et al. 2002). Operators of a drilling or production installation should determine the type and significance of volatile organic compound (VOC) emissions and report them in accordance with existing best management practices for oil and gas operations in Canada. Several GHG reduction technologies and strategies are most likely to be feasible if incorporated when a project is constructed.

The air contaminants of primary concern with respect to air emissions include carbon dioxide (CO2), carbon monoxide (CO), sulphur oxides (SOX), nitrogen oxides (NOX) and particulate matter (PM). It is estimated a typical drill unit consumes approximately 110 barrels of diesel per day. Each barrel holds approximately 42 US Gallons (159 L) of fuel.

Representative emissions factors for air contaminants released to the atmosphere by source type was estimated using US EPA AP-42 Emission Factor Inventory by Husky Energy and Norsk Hydro Canada (2006) for a delineation well. The resulting information is based on the assumption that evaporative losses are nominal in diesel engines due to low volatility of diesel and as such only air contaminant emissions emitted through exhaust were considered. It was also assumed that all sulphur in the fuel is converted to SO2. Therefore, for a fuel with a sulphur content of 0.5 percent, an emission factor of 0.505 would apply.

Daily air contaminant emissions for the consumption of 110 barrels of fuel per day were evaluated and are presented in Table 2.8. A formal analysis has not been conducted on air emissions from a semi-



submersible, so the resultant emissions would be slightly higher due to greater fuel consumption required for activities such as station-keeping (Husky Energy and Norsk Hydro Canada 2006). These emissions are comparable to emissions from a single large container ship of the type commonly present in the Jeanne d’Arc Basin area.

Table 2-8 Daily Criteria Air Contaminant Emissions for the Project Drilling unit Consuming 100 Barrels of Fuel per Day

Contaminant Diesel Fuel (# bbl/day)

US Gallons/Day

Energy Produced per

Day (MMBTUs)

Emission Factor

(lb/MMBTU)

Contaminant Emissions (lbs/day)

Contaminant Emissions (tones/day)

NOX 110 4,620 642 3.2 2,055 0.93 COX 110 4,620 642 0.85 546 0.25 SOX 110 4,620 642 0.505 324 0.15 CO2 110 4,620 642 165 105,960 48 PM 110 4,620 642 0.1 64 0.03

Source: Husky Energy and Norsk Hydro Canada 2006. Note: MMBTU = 100,000 BTU.

The numbers noted in Table 2.8 (Husky Energy and Norsk Hydro Canada 2006) for a typical drill unit corresponds to less than 0.2 percent of the greenhouse gas emissions for Newfoundland and Labrador (based on 2003 greenhouse gas emissions data).

2.5.5 Storage Displacement Water

Storage displacement water is seawater that is pumped into and out of oil storage chambers (either through mechanical or natural (gravity) means) on certain types of production installations (GBS) during oil production and off-loading operations. Storage displacement water that is discharged should be treated to reduce its oil concentration to 15 mg/L or less (NEB et al. 2002).

2.5.6 Bilge and Ballast Water

Bilge water is seawater that may seep or flow into the structure from various points in an offshore installation. Ballast water is water used to maintain the stability of an offshore facility. If present, oil concentrations in discharged bilge and ballast water should be treated to levels of 15 mg/L or less before discharge.

2.5.7 Deck Drainage

The deck of an offshore installation may be exposed to water from a number of sources, including precipitation, sea spray or wash down and fire drill operations. Offshore facilities often have separate systems for areas where deck drainage may be contaminated with oil. Deck drainage that has the potential to be contaminated with oil must be treated to 15 mg/L or less prior to discharge into the marine environment as per the OWTG (NEB et al. 2002).

2.5.8 Cooling Water

Cooling water is seawater (usually treated with chlorine to prohibit organic marine growth) that is used to remove heat from production systems; upon discharge it is warmer than the receiving environment. The Chief Conservation Officer may impose residual chlorine level limits for any discharged cooling



water (NEB et al. 2002). The Chief Conservation Officer (C-NLOPB) must also approve any other biocide agent.

2.5.9 Sewage and Food Wastes

Sewage and domestic waste originates from 10 to approximately 200 personnel, depending upon the type of originating platform (mobile or permanent). Sewage and food wastes should be reduced through maceration to a particle size of 6 mm or less prior to discharge.

2.5.10 Dry Bulks

Barite (BaSO4), Bentonite clay and dry cement are potential non-routine discharges. This may occur from the drilling unit or supply/support vessels. Barite and Bentonite are naturally occurring compounds. Cement is two-thirds by mass of calcium silicates, the remainder consisting of aluminum and iron-containing clicker phases and other compounds.

2.6 Accidental Events

Blowout and accidental spill events during drilling operations are considered in this section. Operational discharges of other oil and waste products, such as produced water, are generally excluded here since they are not included in spill incident reports. Two types of accidental events that could occur during exploration and production activities are blowouts and “batch” spills. Blowout accidental events are discussed in Section 2.6.3, while batch accidental events are discussed in Section 2.6.6.

2.6.1 Spill History of the Offshore Oil and Gas Industry

Compared with other industries that have potential for discharging petroleum oil into the marine environment, the industry of exploring, developing and producing offshore oil and gas (the offshore Exploration and Production (E&P) industry) has a good record. A recent study on marine oil pollution by the US NRC (2002) indicates that accidental petroleum discharges from platforms contribute approximately 0.07 percent of the total petroleum input to the world’s oceans (0.86 thousand tonnes per year versus 1,300 thousand tonnes per year - see Table 2.9).

The accidental event record is particularly good in the US Outer Continental Shelf (OCS), where 37,000 wells were drilled and over 13 billion (109) barrels1 of oil and condensate were produced from 1972 to 2006; with 18 blowouts occurring that involved discharge of oil or condensate. The total oil discharged in the 18 events was approximately 1,156 barrels.

1 The petroleum industry usually uses the oil volume unit of petroleum barrel (which is different than a US barrel and a British barrel). There are 6.29 petroleum barrels in one cubic metre (m3). Most spill statistics used in this report are taken from publications that use the oil volume units of petroleum barrels.



Table 2-9 Annual Releases of Petroleum by Source Estimates (1990 to 1999) Sources of Annual Releases of Petroleum North America Worldwide

Natural Seeps 160 600 Extraction of Petroleum 3.0 38 Platforms 0.16 0.86 Atmospheric Deposition 0.12 1.3 Produced waters 2.7 36 Transportation of Petroleum 9.1 150 Pipeline Spills 1.9 12 Tank Vessel Spills 5.3 100 Operational Discharges [Cargo Washings] na1 36 Coastal Facility Spills 1.9 4.9 Atmospheric Deposition 0.01 0.4 Consumption of Petroleum 84 480 Land-Based [River and Runoff] 54 140 Recreational Marine Vessel 5.6 nd2

Spills [Non-Tank Vessels] 1.2 7.1 Operational Discharges [Vessels 100 GT] 0.10 270 Operational Discharges [Vessels <100 GT] 0.12 nd3

Atmospheric Deposition 21 52 Jettisoned Aircraft Fuel 1.5 7.5 TOTAL 260 1,300 Source: US National Academy of Science (NAS) 2003. Notes : Petroleum estimates in thousands of tonnes..

Cargo washing is not allowed in US waters, but is not restricted in international waters. Thus, it was assumed that this practice does not occur frequently in US waters. World-wide populations of recreational vessels were not available.

Blowout and spill probability assessment for the Labrador Shelf SEA Area uses statistics collected nationally and internationally. It is assumed that the practices and technologies that will be used with the Labrador Shelf SEA Area will be similar to those used in other offshore oil and gas operations around the world, specifically US OCS waters and the North Sea. The analysis uses statistics from the UK and Norwegian sectors of the North Sea based on the understanding that they have severe weather. While it is recognized that the Labrador Shelf SEA is a unique environment, comparable drilling practices is a better determinant of spill probability.

2.6.2 Sources of Information

Several sources and statistics are available to characterize and quantify the relative proportion of petroleum sources released into the marine environment. Statisticians at the US Minerals Management Service (MMS) have produced a large body of literature on marine oil-spill probability in the US OCS. Because these oil-spill statistics have been extensively peer-reviewed and are updated regularly, they will be used as the information primary source. These sources are quoted due to the long reporting interval, back to 1964, with frequent updates since then on the statistical compilations and high standard of reporting and analyses completed. Much of the data discussed in this report are readily available on the Internet at http://www.mms.gov/stats/index.htm. Another source of information is a study completed by Scandpower (2000), which analyzes blowout statistics related to activities in the Norwegian and UK sectors of the North Sea, as well as the US Gulf of Mexico (GOM) OCS region (GOM OCS). The proximity of the US operations to offshore Canada and generally similar drilling equipment and practices employed render these data relevant and informative.

The US National Academy of Sciences (NAS) (2003) report Oil in the Sea III indicated that approximately 3 percent of the oil in the world’s marine environment is the result of offshore oil and gas



operations, and that production and transportation from the US OCS contributes less than 0.01 percent of the oil in the world’s marine waters. The primary source of oil in marine waters is natural seepage, which introduces approximately 50 times more oil than OCS oil and gas activities (MMS 2006a). This 3 percent annual figure comprises approximately 0.86 thousand tonnes from platforms, 1.3 thousand tonnes from atmospheric deposition and 1.3 thousand tonnes from produced waters. Natural seepage is the largest single source of petroleum input to the world’s marine environment, contributing over 4 million barrels per year (MMbbl), or 47 percent of the total inputs. Transportation of petroleum, including pipelines, tank vessel spills, operational discharges, coastal facilities and atmospheric deposition, account for approximately 12 percent, while consumption of petroleum, with largest contributions from land-based (river and runoff) and operational discharges sources, being responsible for approximately 37 percent of world-wide petroleum inputs.

2.6.2.1 Statistics of Importance to Analysis

Pollution incidents are estimated based on the exposure variable of “wells drilled”. As there is no specific development proposed at this time, the number of wells to be drilled is unknown. In any case, the number of wells to be drilled prior to a potential development will be contingent upon the results of exploration.

For the purposes of the Labrador Shelf SEA, it is assumed that the rate of exploration drilling will be one well per year, (if more wells are drilled, the results can be scaled up by simple multiplication: for example, for two wells the predicted frequencies would be doubled). It is assumed conservatively that the target reservoirs do contain oil or condensate of some sort.

2.6.2.2 Categories of Spill Size

Five spill size categories are selected and analyzed. The first category is for "extremely large" spills, arbitrarily defined as spills larger than 150,000 bbl (23,800 m3). Good worldwide statistics are available for this size range. The second and third categories are for “very large” and “large” spills, defined by the MMS as spills larger than 10,000 barrels (1,590 m3) and 1,000 barrels (159 m3) respectively. The fourth category is for spills in the range of 50 to 999 bbl, and the fifth category is for spills in the 1 to 49 bbl category. The spill size classifications used in this study are summarized in Table 2.10. Note that the top three categories in the table are cumulative; that is, the large-spill category (>1,000 bbl) includes the very large and extremely large spills, and the very large category includes extremely large spills.

Table 2-10 Spill Size Categories

Spill Category Name Spill Size Range (in barrels)

Spill Size Range (in m3 and tonnes)

Extremely Large spills >150,000 bbl (>23,850 m3 or >20,830 tonnes) Very Large spills >10,000 bbl (>1,590 m3 or >1390 tonnes) Large spills >1,000 bbl (>159 m3 or >139 tonnes) Medium spills 50 to 999 bbl (7.95 m3 to 158.9 m3) Small spills 1 to 49.9 bbl (0.08 m3 to 7.94 m3)

2.6.3 Blowout and Spill Probabilities

Blowouts are continuous spills lasting hours, days or weeks that could involve the discharge of petroleum hydrocarbons into the atmosphere and into surrounding waters. When such an incident occurs, formation fluids begin to flow into the wellbore and up the annulus and/or inside the drill pipe



and are commonly called a kick. A kick can quickly escalate into a blowout when the formation fluids reach the surface, especially when the fluid is a gas, which rapidly expands as it flow up the wellbore and accelerates to near supersonic speeds. Blowouts can cause considerable damage to drilling units and injuries or fatalities to rig personnel.

2.6.3.1 Exploration Drilling Blowouts (No Gas)

The main concern is the possibility of a well blowout occurring and discharging large quantities of oil into the marine environment. In the US, only two moderate-size oil-well blowouts involving oil spills greater in size than 50,000 barrels have occurred since offshore drilling began in the mid-fifties. All worldwide blowouts involving spills of more than 10,000 barrels each are listed in Table 2.11.

Table 2-11 Historical Large Oil Spills from Offshore Oil-Well Blowouts

Area Reported Spill Size (bbl) Date Operation Underway

Mexico (Ixtoc 1) 3,000,000 1979 Exploratory Drilling Dubai 2,000,000 1973 Development Drilling Irana see note 1983 Production Mexico 247,000 1986 Workover Nigeria 200,000 1980 Development Drilling North Sea/Norway 158,000 1977 Workover Iran 100,000 1980 Development Drilling US, Santa Barbara 77,000 1969 Production Saudi Arabia 60,000 1980 Exploratory Drilling Mexico 56,000 1987 Exploratory Drilling US, S. Timbalier 26 53,000 1970 Wireline US, Main Pass 41 30,000 1970 Production US, Timbalier Bay/Greenhill 11,500 1992 Production Trinidad 10,000 1973 Development Drilling a The Iranian Norwuz oil-well blowouts in the Gulf of Arabia, which started in February 1983, were not caused by exploration or drilling accidents but were a result of military actions during the Iraq/Iran war. Source: Gulf Canada 1981, updated to present (2007) by reference to the Oil Spill Intelligence Report.

Based on the definition of an “extremely large” spill being oil spills of 150,000 barrels in size or greater, there have been five such spills in the history of offshore drilling. Two of these spills occurred during development drilling and two occurred during production or workover activities. The fifth was from exploration drilling; the Ixtoc 1 oil-well blowout in the Bay of Campeche, Mexico, which occurred in 1979. It is worth noting that this incident, producing the largest oil spill in history, was caused by drilling procedures that were contrary to US and Canadian regulations and to the accepted practices within the international oil and gas industry.

Spill frequencies are best expressed in terms of a risk exposure factor such as number of wells drilled. On a worldwide basis, it has been estimated that 36,633 offshore wells were drilled from 1955 to 1980, of which 11,737 were exploration wells (Gulf Canada 1981). The total number of exploration wells drilled up to 1988 has been estimated to be 20,000 (Sharples et al. 1989). It has been estimated that the number of exploration wells drilled up to the end of 2006 on a worldwide basis is approximately 40,000. There has been one extremely large spill (>150,000 bbl) during offshore exploration drilling (see Table 2.11), so the frequency up to the present has been 2.5 x 10-5 spills per well drilled (1/40,000).

A similar analysis for “very large” spills, that is spills larger than 10,000 barrels, indicates that the frequency for drilling blowouts is 7.5 x 10-5 spills per well drilled (3/40,000).



In the entire history of operations in the US OCS or the North Sea, there have been no large (>1,000 bbl) spills during exploration drilling. It is difficult to obtain and be confident of data elsewhere in the world. A complete search was made of the records of the Oil Spill Intelligence Report, a weekly newsletter that identifies international spills larger than 1,000 gallons (24 bbl). The search revealed only one exploration-drilling blowout that resulted in a large oil spill, other than the spills listed in Table 2.12 (remember that the category of large spills includes very large spills and extremely large spills). This occurred in the offshore Ankleshwar field in Gujarat, India, in 1998. The operator was the state-owned Oil and Natural Gas Corporation (ONGC) and the spill size was 100,000 gallons or 2,380 barrels. If it is assumed that this was the only large-spill blowout to occur after the ones accounted for above (and this may be a weak assumption), then the spill frequency for large (>1,000 bbl) spills from exploration drilling becomes 4/40,000 = 1.0 x 10-4 spills per well drilled.

Table 2-12 Blowouts and Spillage from US Federal Offshore Wells, 1972 to 2006

Drilling Blowouts Non-drilling Blowouts Exploration Development Production Workover Completion Total Blowouts

OCS ProductionYear Well

Starts No. bbl No. bbl No. bbl No. bbl No. bbl No. bbl MMbbl

1972 845 2 0 2 0 1 0 0 0 0 0 5 0 396.0 1973 820 2 0 1 0 0 0 0 0 0 0 3 0 384.8 1974 816 1 0 1 0 4 275 0 0 0 0 6 275 354.9 1975 372 4 0 1 0 0 0 1 0 1 0 7 0 325.3 1976 1,038 1 0 4 0 1 0 0 0 0 0 6 0 314.5 1977 1,064 3 0 1 0 1 0 3 0 1 0 9 0 296.0 1978 980 3 0 4 0 0 0 3 0 1 0 11 0 288.0 1979 1,149 4 0 1 0 0 0 0 0 0 0 5 0 274.2 1980 1,307 3 0 1 0 2 1 1 0 1 0 8 1 274.7 1981 1,284 1 0 2 0 1 0 3 64 3 0 10 64 282.9 1982 1,035 1 0 4 0 0 0 4 0 0 0 9 0 314.5 1983 1,151 5 0 5 0 0 0 2 0 0 0 12 0 350.8 1984 1,386 3 0 1 0 0 0 1 0 0 0 5 0 385.1 1985 1,000 3 0 1 0 0 0 2 40 0 0 6 40 380.0 1986 1,538 0 0 1 0 0 0 1 0 0 0 2 0 384.3 1987 772 2 0 0 0 3 0 1 0 2 60 8 60 358.8 1988 1,007 1 0 1 0 0 0 1 0 0 0 3 0 332.7 1989 911 2 0 51 0 3 0 1 0 0 0 11 0 313.7 1990 987 1 0 1 0 0 0 3 9 1 0 6 9 304.5 1991 667 3 0 32 0 0 0 0 0 0 0 6 0 326.4 1992 943 3 100 0 0 0 0 0 0 0 0 3 100 337.9 1993 7173 1 0 2 0 0 0 0 0 0 0 3 0 352.7 1994 7173 0 0 0 0 0 0 1 0 0 0 1 0 370.4 1995 7173 1 0 0 0 0 0 0 0 0 0 1 0 429.2 1996 921 1 0 1 0 0 0 0 0 2 0 4 0 433.1 1997 1,333 1 0 3 0 0 0 0 0 1 0 5 0 466.0 1998 1,325 1 0 1 0 2 0 3 0 0 0 7 2 490.5 1999 364 1 0 2 0 0 0 1 0 0 0 5 0 534.6 2000 973 5 200 4 0 0 0 0 0 0 0 9 200 551.6



Drilling Blowouts Non-drilling Blowouts Exploration Development Production Workover Completion Total Blowouts

OCS ProductionYear Well

Starts No. bbl No. bbl No. bbl No. bbl No. bbl No. bbl MMbbl

2001 2,289 1 0 4 1 2 0 2 0 1 0 10 1 591.7 2002 1,030 1 0 2 0 2 350 1 1 0 0 6 351 602.3 2003 1,2603 1 0 1 0 2 1 1 10 0 0 5 11 594.8 2004 1,490 2 16 0 0 0 0 2 1 0 0 4 17 567.94 2005 1,232 3 0 1 0 0 0 0 0 0 0 4 0 497.34 2006 1,586 1 0 0 0 0 0 0 0 0 0 1 25 498.94 Total 37,026 68 316 61 1 24 627 38 125 14 60 206 1,156 13,961.0

1. Two of the drilling blowouts occurred during drilling for sulphur. 2. Two of the drilling blowouts occurred during drilling for sulphur. 3. Estimated: cumulative total correct. 4. Preliminary.

It must be noted that the spill frequency calculations are based on the entire offshore experience from 1955 to the present. Most of the spills noted in Table 2.12 occurred over 20 years ago. In addition, as noted earlier, no large spills from exploration operations have ever occurred in US OCS or North Sea waters. There is an obvious trend toward fewer blowouts, and this is discussed in some detail in Section 2.6.3.2.

2.6.3.2 Exploration Drilling Blowouts (Primarily Gas)

Two sources are used for historical statistics on blowouts involving only gas or small oil discharges. A particularly good source for US blowouts is the MMS web page (www.mms.gov) because MMS keeps track of spills down to one barrel in size. The C-NLOPB also tracks and records all spills (www.cnlopb.nl.ca). This is not the case in other parts of the world. Scandpower (2000) provides good, recent statistics on blowouts in the North Sea and the US GOM, although no information is provided as to whether or not oil spills were involved in the reported blowouts.

US OCS data representing the 29-year period from 1972 to 2006 are provided in Table 2.12. Note that there are no large spills (>1,000 bbl) in the entire database. However, if the table had started in 1970 two very large blowout spills would have been shown, involving 30,000 barrels and 53,000 barrels respectively (see Table 2.12). The total number of exploration wells drilled in the US OCS from 1972 to 2005 is not shown in Table 2.12, but it is derived from other Sources (E&P Forum 1996; MMS 1997). The total number of exploration wells drilled in the US OCS is approximately 14,500. The number of blowouts from exploration drilling is shown to be 68. Therefore, the blowout frequency is 68/14,500 or 4.70 x 10-3 blowouts per well drilled, or one blowout for every 213 wells drilled. Four of the blowouts involved oil spills, one of size 200 bbl, one was 100 bbl, one was 11 bbl and one was 5 bbl.



2.6.3.3 Labrador Shelf Strategic Environmental Assessment Area Spill Frequency Calculations

On the basis of one exploration well drilled per year, the spill frequencies estimated for the Labrador Shelf SEA Area would be:

• Predicted frequency2 of extremely large oil spills (>150,000 bbl) from blowouts during an exploration drilling operation, based on an exposure of wells drilled is 1 well x 2.5 x 10-5 = 2.5 x 10-5. Another way of expressing this would be to say that the expected frequency is 2.5 x 10-5 spills per year, or one such spill every 40,000 years of operation. This means that if this drilling rate of one well per year were to continue forever, one could expect an oil spill larger than 150,000 barrels once every 40,000 years.

• Predicted frequency of very large oil spills (>10,000 bbl) from exploration drilling blowouts based on an exposure of wells drilled is 1 well x 7.5 x 10-5 = 7.5 x 10-5, or a probability of one in 13,300, or, at this drilling rate, one could expect such a spill every 13,300 years.

• Predicted frequency of large oil spills (>1,000 bbl) from exploration drilling blowouts based on an exposure of wells drilled is 1.0 x 10-4, or a probability of one in 10,000.

C-NLOPB data were presented for comparison but not used to predict frequencies because: 1) the exposure number is only 24 wells; and 2) there are no large spills from an exploration drilling program.

2.6.4 Current Trends

The above-calculated blowout statistic for the US (4.7 x 10-3) is based on blowout records of the past 30 years and does not take into account recent improvements in safety and blowout prevention that have tended to reduce blowout frequencies. It is appropriate at this time to analyze current trends and to update predictions of blowout frequency as appropriate. This is done by taking into consideration:

• the differences between “shallow gas” blowouts and “deep-well” blowouts; and

• decreases in blowout frequency in recent years due to improvements in blowout prevention.

Both issues are covered thoroughly in the Scandpower (2000) publication, which is the primary source for the following analysis.

2.6.4.1 Shallow-Gas Blowout versus Deep Blowout

A blowout might occur if shallow gas is encountered unexpectedly during drilling operations. Gas that is trapped in the shallow sediments can originate from deeper gas reservoirs, but can also come from biogenic activity in the shallow sediments. Generally, shallow gas blowouts are more likely to occur than deep well blowouts, but they do not involve a discharge of oil. Various statistics on shallow and deep well blowouts in the North Sea and in the GOM OCS are shown in Table 2.13, which is derived from Scandpower (2000).

2 In this and other similar calculations in the report, spill frequency rates are kept as three-decimal data, and the probability numbers are rounded off to two decimal points.



Table 2-13 Exploration Wells and Blowouts in US GOM OCS and North Sea, 1980 to 1997

Area Number of Exploration Wells

Shallow Gas

Blowouts

Shallow Gas Releases

while Drilling Deep

Blowouts

Deep Well Releases

while Drilling

Total Blowouts

and Releases

US GOM 5,751 13 5 15 0 33 UK 2,899 2 0 2 0 4

Norway 680 5 3 0 5 13 TOTALS 9,330 20 8 17 5 50

Source: Scandpower 2000. Notes: • A blowout is as an incident where hydrocarbons flow from the well to the surface, all barriers are non-functional, and well

control can only be regained by means that were not available when the incident started. • A deep blowout is defined as one that occurs after the Blowout Preventor (BOP) is set. • A shallow gas blowout is a release of gas prior to the BOP being set. • A well release is an incident where hydrocarbons flow from the well to the surface and is stopped by one or several

barriers that were available when the incident started. In this case, hydrocarbons do not enter the environment.

The statistic of 33 blowouts and releases for the US GOM noted in Table 2.13 is reasonably consistent with the data in Table 2.12, which shows 32 blowouts for the period 1980 to 1997. Note that the US regulator, the MMS, classifies “blowouts” in Table 2.12 to include well releases (where no hydrocarbons enter the environment) as well as blowouts. The frequency of blowout and releases from Table 2.13 for the US GOM is 33/5751 = 5.74 x 10-3, which is close to the value derived earlier from Table 2.12 (4.7 x 10-3).

Deep blowouts are the primary concern and not well releases because releases by definition do not involve a discharge of hydrocarbons into the environment. The frequencies for both shallow and deep blowouts, derived from Table 2.13, are summarized in Table 2.14.

Table 2-14 Exploration Drilling Blowout Frequency for the US Gulf of Mexico and North Sea (1980 to 1997)

Shallow Gas Blowouts Deep Blowouts US GOM North Sea US GOM North Sea

Blowouts per well drilled 2.26 x 10-3 1.96 x 10-3 2.61 x 10-3 5.59 x 10-4 Wells drilled per blowout 440 510 380 1800

Although the frequency of shallow gas blowouts is similar for both regions, the frequency of deep blowouts is almost five times higher in the U.S. Gulf of Mexico than in the North Sea. The reason for this, according to Scandpower (2000), is that North Sea operators are required by law to always have two barriers during exploration and development drilling, and this was not always the case in the U.S. Gulf of Mexico. Scandpower (2000) does note that comparable regulations are followed in Canadian East Coast drilling operations as in the North Sea, so it is fair to derive blowout frequencies for the Labrador Shelf based on North Sea statistics.

2.6.5 Blowout Probabilities for Labrador Shelf Strategic Environmental Assessment Area

It is important to note that blowout frequencies in the North Sea and in the GOM have been on the decline over recent years, as shown in Table 2.15.



Table 2-15 Exploration and Development Drilling Blowout Frequencies over Time Time Period No. of Blowouts Number of Exp. and Dev. Wells Drilled Blowout Frequency

18 years (1980 to 1997) 53 22,084 24.0 x 10-4 10 years (1988 to 1997) 23 13,870 16.6 x 10-4 5 years (1993 to 1997) 5 7,581 6.6 x 10-4 3 years (1995 to 1997) 1 4,924 2.0 x 10-4

Source: Scandpower 2000.

The blowout risk frequency for Labrador Shelf SEA Area operations will be calculated (as per Scandpower 2000) as the average of the four frequencies provided in Table 2.15, yielding an adjustment factor of 51 percent. This means that frequencies derived for the period 1980 to 1997 should be cut by approximately 50 percent for an estimate of frequencies today. The adjustment factor cannot be fully justified. A justified approach would have been to divide the frequency by 4 or perhaps 10, based on the most recent years. The approach used in the source document (Scandpower 2000) which only halved the frequency was used, to be conservative.

Based on the above analysis, the expected frequency of a deep blowout during the operations within the Labrador Shelf SEA Area should be predicted based on the North Sea experience and take into account current falling trends. Accordingly, the prediction yields (from Tables 2.14 and 2.15) a value of 5.59 x 10-4 x 0.51 = 2.85 x 10-4 deep blowouts per wells drilled or a probability of one blowout for every 3,500 wells drilled. Considering a one-well-per-year program, the blowout frequency simply becomes 1 well x 2.85 x 10-4 = 2.85 x 10-4 or a one in 3,500 chance of a deep blowout occurring over the one-year drilling period.

2.6.6 Batch Accidental Events

Batch spills are instantaneous or short-duration discharges of oil that could occur from accidents on the exploration or production drilling platforms where fuel oil and other petroleum products are stored and handled. These include spills of diesel oil or lubricating oil on the platforms, spills from transfer operations, spills of synthetic or water based drilling muds, and spills from similar accidents involving the handling of oil that is needed to run operations. Hydrocarbon spills may occur because of equipment malfunction and/or a failure in properly implementing procedures. Most incidents involve everyday operations and duties; unsafe acts may also cause a worker to lose their life so that safety is paramount. Spill incidents sometimes occur during, or are exacerbated by, poor weather and sea conditions. The majority numbers of batch spills are small.

2.6.6.1 Historical Record

Oil spills of all sizes from operations on US OCS leases for the period 1985 to 1999 (Anderson and LaBelle 2000) are provided in Table 2.16. Spill data are available for the period 1971 to 1995 (MMS 1997). Normalization of the annual data using an exposure of “wells drilled per year” is illustrated in Figure 2.8. The small-spill frequencies in the GOM OCS were relatively high in its early stages, but have decreased by almost a factor of 10 over the past 25 years, as illustrated in Figure 2.8. The spill statistics provided in Table 2.16 cover the timeframe that follows a dramatic decline in spills that occurred within 1975 to 1980.



Figure 2.8 Spill Frequencies (1965 to 2000) in the Gulf of Mexico

Table 2-16 US OCS Platform Spills (1985 to 1999) Spill Size Number of Spillsa Spills per Well Drilledc 0 to 1.0 bbl 13,000b 0.9920

1.1 to 9.9 bbl 326 2.49 x 10-2 10.0 to 49.9 66 5.04 x 10-3

50.0 to 499.9 28 2.14 x 10-3 500.0 to 999.9 2 1.53 x 10-4

1,000 bbl and greater 0 0 Source: Anderson and LaBelle 2000. Notes: a. Oil spills include crude oil, condensate and refined petroleum products, including oils in oil-based drilling muds. b. This number assumes that 67 percent of spills of size 0 to 1.0 bbl are from platforms and 33 percent from pipelines.

Only the total number (19, 506) is provided in the source for the table (Table 13 in Anderson and LaBelle 2000), but the 2:1 distribution seems reasonable based on the distribution given for the other spill size classifications.

c. Total wells drilled for period 1985 to 1999 is 13,100.

2.6.6.2 Calculated Frequencies for the Labrador Shelf Strategic Environmental Assessment Area

Three spill size classifications are considered: spills one barrel or less (very small spills), small spills in the size range of 1.1 to 49.9 bbl, and medium spills (50 to 999 bbl). The statistics in Table 2.16 are sufficient for deriving an estimated spills frequency for these spill size range. On the basis of a one well per year drilling program, the predicted frequency of spills of size one barrel and less during drilling operations is 1 well x 0.992 = 0.99 spills per year, or approximately one spill every year.

Small spills in the range of 1.1 to 49.9 barrels are a result of operational activities on platforms and are usually caused by human error. If it is assumed that the distribution in Table 2.16 applies, then based on US OCS experience, the predicted frequency of small spills (1 to 49 bbl) during exploration drilling is [1 well x (326 + 66)/13,100] = 2.99 x 10-2 spills per year, or approximately one spill every 33 years.



Medium spills (50 to 999 barrels) are relatively large spills and based on US OCS experience, the predicted frequency of medium spills (50 to 999 bbl) during exploration drilling is 1 well x (28 + 2)/13,100 = 2.29 x 10-3 spills per year, or approximately one spill every 440 years.

The calculated oil spill frequencies are summarized in Table 2.17. The highest frequencies are obviously for the smaller, platform-based spills. Spills less than one barrel in size may occur once every year, based on US OCS data. Oil spills during exploration that are larger than one barrel but less than 50 barrels have about a 1-in-33 chance of occurring per year. Oil spills of all types in the 50 to 999 bbl range may have about a 1-in-440 chance of occurring every year, based on experience in the US OCS.

Table 2-17 Predicted Number of Blowouts and Spills for the Labrador Shelf SEA Area (1 well/yr)

Event Historical Frequency

(per well drilled)A Predicted No. of Events per year

Frequency (assumes one well/ year)

Deep well blowout during exploration drilling 2.85 x 10-4 2.85 x 10-4 One every 3,500 yrs Exploration drilling blowout with oil spill >1000 bbl 1.00 x 10-4 1.0 x 10-4 One every 9,700 yrs Exploration drilling blowout with oil spill >10,000 bbl

7.50 x 10-5 7.5 x 10-5 One every 13,000 yrs

Exploration drilling blowout with oil spill >150,000 bbl

2.50 x 10-5 2.5 x 10-5 One every 39,000 yrs

Platform oil spill, 0 to 1.0 bbl 0.992 0.99 One every year Platform oil spill, 1.1 to 49.9 bbl 2.99 x 10-2 3.0 x 10-2 One every 33 yrs Platform oil spill, 50 to 999 bbl 2.29 x 10-3 2.3 x 10-3 One every 440 yrs Notes: A All spill frequencies are based on worldwide, US OCS and North Sea experience.

There is an approximately 1-in-3,500 chance per year of having any sort of deep well blowout. Shallow gas blowouts may occur and are three or four times more probable than ones that occur at depth, but these would have virtually no chance of involving an oil spill.

The chances of an extremely large (>150,000 bbl), very large (>10,000 bbl) and large (>1,000 bbl) oil well blowout from exploration drilling are very small: approximately 1-in-40,000, 1-in-13,000 and 1-in-10,000 chance per year, respectively. This means that if drilling continued at the rate of one well per year, one could expect an extremely large spill once every 40,000 years. These predictions are based on worldwide blowout data and are strongly influenced by blowouts that occurred in parts of the world where drilling regulations may be less rigorous. It might be reasonable to expect even lower frequencies for the operations on the Labrador Shelf SEA Area than those calculated above in view of the fact that no exploration drilling blowout spills larger than 10,000 barrels have occurred anywhere in the world since 1987, suggesting a considerable improvement of technology and/or practice over the past 20 years.

2.6.6.3 Newfoundland and Labrador Spill Incident Data

The C-NLOPB report spill incident information for activities offshore Newfoundland and Labrador. Details include numbers of incidents, spill volumes, spilled product, spill size and description of the incident. Exploration and production hydrocarbon spill information for Newfoundland and Labrador Offshore Areas can be reviewed on the C-NLOPB web site following the links for Statistics and Environmental Statistics (C-NLOPB 2006d). C-NLOPB present reported spills for the Newfoundland and Labrador Offshore Area, tabulated by exploration and development drilling for synthetic-based



drilling fluids and all other hydrocarbons, with some incident counts annotated with additional details of the spill, such as a breakdown of the spill materials and actual volumes.

Selected spill and volume statistics from Newfoundland and Labrador are presented in Figures 2.9 and 2.10 and Table 2.18. .

Figure 2.9 Number of Exploration Well and Spill Incidents, Offshore Newfoundland and Labrador (1997 to 2007)

0

50

100

150

200

250

300

350

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Total

Number of Spill Incidents

Year

Exploration Production Total



Figure 2.10 Exploration and Production Spill Volumes, Offshore Newfoundland and Labrador (1997 to 2007)

0

50000

100000

150000

200000

250000

300000

350000

400000

450000

500000

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Total

Spill

Vol

umes

(Lite

rs)

Year

Exploration Production

Total

Table 2.18 provides a summary of the spill incident by year for 1997 to 2007 for exploration, production and a cumulative total. The number of exploration wells and amount of cumulative oil production is provided to put the spill data into context with respect to activity and production. Figure 2.9 represents the number of spill events that have occurred from 1997 to 2007 and Figure 2.10 is the volume



Table 2-18 Spill Incidents, Offshore Newfoundland and Labrador, 1997 to 2007

Spill Location 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Total Average / Year

Exploration Spill Incidents for Number of Exploratory Wells 1997 to 2007 NL, # Exploration Wells 2 1 7 4 0 3 4 0 3 - TBD 24 2.4 NL, # Spill Incidents, Exploration 1 4 24 1 0 1 4 0 0 4 1 40 4

Spill Volume, Exploration (L) 40 3,195 1,965 160 0 1 4,547 0 0 616 74,000 84524 8,452.4

Production Spill Incidents for Cumulative Production Activity 1997 to 2007 Offshore NL Cumulative Production (MMbbl) 1.272 23.799 36.391 52.798 54.288 104.334 122.963 114.78 111.269 111.835 143.479 877.208 87.7208

NL, # Spill Incidents, Production 10 24 23 9 17 25 21 56 40 34 4 263 26.3

Spill Volume, Production (L) 1,691 2,597 8,270 4,763 5,732 12,280 26,868 274,008 4,220 3,646 93 43,292 4,329.2

Summary of Spill Incidents 1997 to 2007 (Exploration and Production) NL, # Spill Incidents, Total 11 28 47 10 16 26 25 56 40 38 5 302 30.2

Spill Volume, Total (L) 1,731 5,792 10,235 4,923 5,732 12,281 31,415 274,008 4,220 4,262 74,093 428,692 42,869.2



In general, continued efforts by the oil and gas industry in conjunction with research, inspection and appropriate enforcement programs by offshore regulators are expected to contribute to minimizing the amount of oil and related materials into the marine environment. Ongoing efforts for inspecting safety devices and systems, conducting oil spill exercises and accident investigations are key factors for success. Operators should be required to use the best and safest technologies on all new and where practical, existing operations.

2.6.6.4 Spill Sizes

For Offshore Newfoundland and Labrador, since 1997, mean and maximum spill sizes are provided in Table 2.19 based on summary information provided on the C-NLOPB website (http://www.cnlopb.nl.ca/pdfs/spill/sumtab.pdf).

Table 2-19 Offshore Newfoundland and Labrador Spill Sizes, 1997 to 2007 Mean (L) Maximum (L)

Exploration Drilling Synthetic Oils/Fluids 26,334 74,000 (Orphan Basin)

Crude or Refined Petroleum 149 2080 (West Bonne Bay) Development Drilling and Production

Synthetic Oils/Fluids 4,600 96,600 (White Rose) Crude or Refined Petroleum 658 165,000 (Terra Nova)

In terms of further discrimination of material types, from the exploration drilling spill incidents from 1997 to 2007, 93.5 percent of the spilled volume was synthetic oils and fluids, 3.1 percent crude, 3.2 percent diesel, <1 percent hydraulic and lubricating oils and < 1 percent other oils (http://www.cnlopb.nl.ca/pdfs/spill/anexpvol.pdf).

Corresponding spills by volume for development drilling and production (1997 to 2007) were approximately 50.6 percent synthetic oils and fluids, 48.8 percent crude and the smaller remaining volume (<1 percent) comprised of diesel, hydraulic and lubricating oils, other oils and condensate (http://www.cnlopb.nl.ca/pdfs/spill/andevvol.pdf).

2.6.7 Accidental Events Fate and Behaviour

It should be noted that in preparing for a drilling program, the environmental assessment will require a detailed spill trajectory analysis for accidental releases of hydrocarbons. For the Labrador Shelf SEA Area, environmental conditions will change over the course of the year; the wind, current and wave magnitudes and directions and sea and air temperatures in summer will be different from those encountered in the fall and winter. These conditions directly determine the fate and transport of an oil spill. Particular times of year may introduce severe weather and sea conditions that might increase the chance of an accident occurring and could compound spill response, including ice cover.

The actual proposed drilling location would be fundamental to any spill assessment and trajectory analysis, as would the time of year for proposed exploration, and such study should be carried out once those particulars are known and prior to any drilling activity. Locations in the Labrador Shelf SEA Area will have varying proximity to coastlines, and each location will be subject to different wind and current regimes, so that the range of possible transport and fate scenarios and shorelines potentially at risk and actual times to shoreline impact may be unique in each instance.

Spills that could occur from offshore exploration drilling operations include surface well blowouts, both shallow and deep-water subsea blowouts and relatively small releases of marine diesel from platform or vessel operations. In above-surface blowouts, the drilling platform maintains its position during the



accident (because it is undamaged) and the oil and gas discharges into the atmosphere from some point on the drilling platform above the water surface and falls on the water surface some distance downwind. Examples of this kind of oil well blowout are the 1977 Ekofisk blowout in the North Sea (Audunson 1980) and the Uniacke blowout on the Scotian Shelf in 1984 (Martec 1984). Shallow water (<500 m) subsea blowouts discharge oil and gas from a point on the seabed and the oil and gas rise through the water column to the surface via the influence of the expanding gas bubbles. An example of this kind of oil well blowout was the 1979 Ixtoc 1 blowout in the Bay of Campeche, Mexico (Ross et al. 1979). In deep-water subsea blowouts (>700 to 900 m), the released gas quickly converts to solid hydrates and/or dissolves in the surrounding water and does not influence the rise of the oil to the surface. The oil rises due to its buoyancy alone. A blowout of this type has never occurred. The initial behavior of the oil and gas from the various types of spills that could occur during exploration drilling operations in the Labrador Shelf region are discussed in more detail in the following sections.

2.6.7.1 Shallow Water Subsea Blowouts

Oil-well blowouts generally involve two fluids, crude oil and natural gas. The volume ratio of these two fluids is a function of the characteristics of the fluids and the producing reservoir. The natural gas, being a compressible fluid under pressure at reservoir conditions, provides the driving force for an uncontrolled blowout. As the well products flow upwards, the gas expands, finally exiting at the well-head at very high velocities. At this point, the oil often makes up only a small fraction of the total volumetric flow.

Oil and gas released from a subsea blowout pass through three zones of interest as they move to the sea surface (Figure 2.11). The high velocity at the well-head exit generates the jet zone that is dominated by the initial momentum of the gas. This highly turbulent zone is responsible for the fragmentation of the oil into droplets ranging from 0.5 to 2.0 mm in diameter (Dickins and Buist 1981).

Figure 2.11 Subsea Blowout Schematic



Because water is also entrained in this zone, a rapid loss of momentum occurs a few metres from the discharge location. In the buoyant plume zone, momentum is no longer important relative to buoyancy, which then becomes the driving force for the remainder of the plume. In this region, the gas continues to expand due to reduced hydrostatic pressures. As the gas rises, oil and water in its vicinity are entrained in the flow and carried to the surface.

Although the terminal velocity of a gas bubble in stationary water is only approximately 0.25 m/sec, velocities in the centre of blowout plumes can reach 5 to 10 m/sec due to the pumping effect of the rising gas in the bulk liquid. That is, the water surrounding the upward moving gas is entrained and given an upward velocity, which is then increased as more gas moves through at a relative velocity of 0.25 m/sec. When the plume becomes fully developed, a considerable quantity of water containing the oil droplets is pumped to the surface.

In the surface interaction zone, the upward flow of water turns and moves in a horizontal layer away from the centre of the plume. The influence of the surface water current causes this radial flow to turn and form a parabolic surface influence, as seen in Figure 2.12. This surface influence carries the oil down-current and spreads it over the surface up to the point where this flow no longer affects the surface water motion (between 1 to 1.5 slick widths down-current). At this point, the oil moves with the prevailing currents and spreads as any batch spill of oil would behave. The gas exits from the centre of the plume and causes a surface disturbance or “boil zone”, identified by the arrows in the top view of Figure 2.12. At the surface, the oil coalesces in this outward flow of water and is spread into a slick at a rate much faster than conventional oil slick diffusion or spreading rates.

Figure 2.12 Plume Behaviour Schematic



2.6.7.2 Deep-water Subsea Blowouts

The initial dimensions of oil slicks from shallow water blowouts are mostly determined by the flow of gas that is released with the oil, as described in Section 2.7.6.1. Because the normal ocean currents are small compared to the vertical rise velocities in the plume, they have little influence on the oil in shallow water blowouts. This may be different when considering a subsea well blowout in deep water. In deep water, the high pressure and low temperatures may cause the natural gas to combine with water to form a solid, ice-like substance known as hydrates. The gas volume may also be depleted through dissolution into the water. With the loss of gas through either or both of these processes, the driving buoyancy of the rising plume may be completely lost, which will result in the oil droplets rising slowly under gravity forces alone. The movement of the oil droplets will be affected by cross currents during their rise. This will result in the separation of the oil droplets based on their drop size. The large diameter oil drops will surface first and smaller drops will be carried further down current prior to reaching the surface. Oceanic diffusion processes will result in additional lateral separation of the oil drops.

2.6.7.3 Above-surface Blowouts

Oil released during a blowout from an offshore drilling platform above the water's surface will behave differently than that from a subsurface discharge. The gas and oil will exit at a high velocity from the well-head and will be fragmented into a cloud of fine droplets. The height that this cloud rises above the release point will vary depending on the gas velocity and the prevailing wind velocity. Atmospheric dispersion processes and the settling velocity of the oil particles determine the fate of the oil and gas. A simple Gaussian model of this behavior that can be used to predict the concentrations of oil and gas downwind from the release point (Turner 1970) is illustrated in Figure 2.13. Atmospheric dispersion is controlled in part by atmospheric turbulence that is influenced by solar radiation, wind speeds and temperatures. On clear, sunny days, with light winds, solar radiation will create highly turbulent conditions.

Overcast conditions regardless of the winds will result in a neutral atmospheric stability. Low winds will tend to make mixing more prominent, whereas high winds tend to reduce the vertical and lateral mixing conditions. The shape of the concentration profile of the plume will vary depending on the atmospheric stability. In very stable conditions, the spread both vertically and laterally will be less than in very turbulent conditions.

The atmospheric plume representation shown in Figure 2.13 can also be used to illustrate the behavior of oil droplets with the following two modifications. The plume centreline is sloped down to account for the oil droplets’ fall velocities and the oil is not reflected at the water surface. The oil will "rain" down, with the larger droplets falling closer to the release point. As it falls, it will also be spread by the atmospheric turbulence. A portion of the falling oil evaporates and the remainder eventually lands on the water and is carried down-current. As water passes through the area of falling oil, it will be “painted” by the falling oil and an accumulation of oil over the width of the fallout zone will occur. Changing wind and water current directions will affect the ultimate distribution of the oil on the water surface in the fallout zone. If the gas and oil is blowing through the derrick or other obstruction, some of the oil droplets may agglomerate on the obstruction(s) and flow down onto the rig floor and eventually to the water surface. This portion of the oil will then behave more like a continuous surface release of oil.



2.6.7.4 Small Spills

Small spills could occur from the support vessels or the drilling platform during transfer and handling of diesel fuels during normal operations. This fuel oil will be released over a short time and behave initially as a single batch spill of oil. The initial slick will be composed of a thick portion that contains the majority of the spilled oil surrounded by a larger area of thin sheen of much smaller total volume. The general behavior of the oil once spilled is described in sections 2.6.7 and 2.6.13.

2.6.8 General Behaviour of Oil Spilled on Open Water

Once oil reaches the ocean surface, it is swept away by winds and currents and undergoes a number of so-called “weathering” processes. This section provides an overview of the processes that have a major influence on the potential cleanup and impact of the oil. In pack or drift ice conditions, the oil may be on or under the ice or on the water between the floes. The behaviour of the oil on open water is discussed in this section. The behaviour of oil on ice, under ice, and among ice floes is discussed in Section 2.6.9.

The most important spill phenomena that influence its impact and control are movement, evaporation, oil spreading, natural dispersion and emulsification. Each of these processes is discussed briefly in the following sections.

2.6.8.1 Oil Movement

Surface slicks may be transported away from the site of a spill by water currents. These currents usually combine residual movement and wind-induced surface movement. Mackay (1984) reports that the rate of oil slick movement may be increased by a factor of 3 percent of the wind speed measured 10 m above the water surface. However, the final vector of oil movement depends on the combined influences of residual currents and wind-induced surface currents. Over relatively long distances, Coriolis forces (due to the Earth's rotation) cause the direction of wind-induced slick motion to deviate some 10° to 15° to the right of the wind direction (in the Northern Hemisphere). In nearshore marine waters, the movement of oil slicks is also affected by tidal currents, river outflows and longshore currents.

2.6.8.2 Evaporation

Evaporation is a relatively well understood and predictable oil spill process (Nadeau and Mackay 1978; Stiver and Mackay 1983; Mackey 1984). The evaporation rate of an oil slick is controlled or affected by: 1) the temperature of the oil and the air; 2) the surface area of the oil in contact with air; 3) the thickness of the oil; 4) wind speeds; and (perhaps most important) 5) the concentration and vapour pressure of the individual components of the oil.

With an above-surface blowout, evaporation also occurs as the oil droplets from the blowout rain down onto the surface. The amount of oil that evaporates in this situation is controlled by the size of the droplets, the volatility of the oil, the length of time they are in the air, and the air temperature.

2.6.8.3 Oil Spreading

Numerous models of oil spreading behaviour have been developed over the past 25 years. All relate the properties of the oil (density, viscosity and interfacial tension) to its spreading on calm water. Most models today use the model developed by Mackay et al. (1980) that includes the assumption that as the slick spreads, it forms thick patches that contain most of the oil volume in a small portion of the



area. These patches are surrounded by thin sheens (in the 0.001 mm range) containing a small portion of the total oil volume over a wide area. The feature is consistent with observed spill behaviour.

Some oils do not spread on water as described above. This category includes oils that have a pour point (i.e., the temperature below that the oil does not flow) that exceeds the ambient temperature. The pour point of oil can be naturally high or may be high because of evaporative losses of hydrocarbons during exposure to the environment. Poor flow properties can be particularly important for spills in cold waters.

2.6.8.4 Natural Dispersion

In conjunction with evaporation, the process of natural dispersion reduces the volume of oil on the water surface, thereby influencing the potential extent of surface and shoreline contamination. Dispersion rates are determined by oil/water interfacial tension, oil viscosity, oil buoyancy and slick thickness. Environmentally, sea state is the most important factor controlling the rate and amount of dispersion. In calm seas, light oils may persist, but even the heaviest, emulsified oils can disperse over a period in heavy seas with frequent breaking waves.

2.6.8.5 Emulsification

When most crude oils are spilled at sea, they tend to form water-in-oil emulsions. Emulsification occurs in the presence of mixing energy such as that provided by wave action. During emulsification, seawater is incorporated into the oil in the form of microscopic droplets. This water intake results in two undesirable changes to the oil. First, there is a considerable increase in the bulk volume of the oil (usually up to a four-fold increase), greatly expanding the amount of oily material that must be dealt with. Secondly, there is a marked increase in fluid viscosity (up to 100-fold). The much higher viscosities greatly inhibit the natural dispersion of oil and greatly reduce the effectiveness of chemical dispersants.

2.6.9 Behaviour of Oil Spilled on Ice and in Pack or Drift Ice

The following is a description of the likely behaviour of oil spilled in the presence of ice. It should be noted that this is drawn from a relatively limited knowledge base: two experimental spills in pack ice, and a few well-documented actual incidents of spills in ice conditions.

2.6.9.1 The Effect of Ice on the Four Main Oil Spill Processes

The effect of pack or drift ice on the four main spill processes of spreading, evaporation, dispersion and emulsification is briefly discussed first.

Oil spill spreading can be dramatically curtailed by the presence of pack or drift ice and brash ice. In high concentrations (greater than 5/10ths), oil spreading tends to be limited to the spaces between the floes. There are simple models that predict the spreading of oil as a function of ice concentration. These are based largely on the results of a field trial off the east coast of Canada (SL Ross and DF Dickins 1987). In general terms, the rate of spreading of an oil slick is not much affected by ice concentrations up to 3/10ths, is reduced by approximately 50 percent in concentrations between 3 and 7/10ths, and there is little spreading of slicks within an ice field of 7/10ths or greater.

Oil spill evaporation is not greatly affected by the presence of ice unless the oil is trapped under or within the ice. Evaporation of volatile components will occur if the oil is exposed to the atmosphere,



regardless of whether the oil rests on water or on ice. Oil will generally evaporate more slowly in pack ice than in open water, due to its increased thickness.

Oil spill dispersion and emulsification rates for oil spills on water depend on the mixing energy available at the sea surface (primarily in the form of breaking waves), and since the presence of ice tends to dampen the effects of wind on sea state, both dispersion and emulsification rates in pack or drift ice conditions would be expected to be less than the case in open water conditions, all other factors remaining the same.

2.6.9.2 Oil Spilled Within Pack or Drift Ice

Oil spilled in pack or drift ice conditions would be contained on water in the leads between floes, or it could coat the ice floe surface if released from an above sea blowout. The oil will travel with the ice as it moves under the influence of winds and water currents. As spring melt proceeds and the ice pack diverges and ablates, the area of oil contamination would increase.

For the case of oil trapped within or under newly forming pancakes or sheet ice, the likely fate will be rapid encapsulation, with new ice quickly growing beneath the oil to entrap it. The oil sandwiched in the ice sheet would remain trapped until the spring, when the warming ice would result in the oil appearing on the surface of the floes and accumulating in melt pools (NORCOR 1975, Dome 1981).

The fate of oil trapped between floes will depend largely on the ice concentration and time of year. During freeze-up, the oil will most likely be entrained in the solidifying frazil ice and slush present on the water surface prior to forming coherent floes. Storm winds at this time often break up and disperse the newly forming ice, leaving the oil to spread temporarily in an open water condition until incorporated in the next freezing cycle (within hours or days depending on the air and water temperatures at the time).

In high ice concentrations, the oil is effectively prevented from spreading and is contained by the ice. As the ice cover loosens, more oil is able to escape into larger openings as the floes move apart. Eventually, as the ice concentration decreases to less than 3/10ths, the oil on the water surface behaves essentially as an open water spill, with localized oil patches being temporarily trapped by wind against individual floes. Any oil present on the surface of individual floes will move with the ice as it responds to winds and currents (SL Ross and Dickins, 1987, Singsaas et al. 1994, Vefsnmo and Johannessen 1994).

2.6.9.3 Oil Spilled on Top of the Ice

The resulting area of contamination from a release of oil on top of ice will be influenced by a number of site-specific factors, such as wind speed, surface roughness and the amount of snow cover in the area of the release. Surface roughness will be a dominant factor for limiting the spreading of spills on ice. A number of process equations are available to predict the spreading and evaporation behaviour of oil in snow (Belore and Buist 1988). Key behavioural factors associated with oil spilled on snow can be summarized as follows (after Wotherspoon 1992):

• evaporation rates in snow are substantially less than oil slicks on open water;

• oil spreads very slowly in snow, and stops spreading much sooner than on open water (snow is a good sorbent for oil); and

• oil mixed with snow neither naturally disperses, nor forms emulsions.



2.6.10 Oil Fate Descriptions and Oil Trajectory Modeling

To provide insight into the possible behaviour of the various spills that might occur in open water, a summary of the fate of oil from hypothetical spills as described in other Canadian east coast drilling operations (SL Ross 2001, 2002, 2005, 2006; Encana 2002) has been provided. The fate of both persistent crude oil and condensate spills in open water conditions are discussed. The descriptions of the fate of persistent oils are based on previous studies of Hibernia, Terra Nova and White Rose crude oils. The descriptions of the fate of condensates are based on the past modelling of Cohasset, Panuke and Sable Offshore Energy Project (SOEP) condensates. The general fate of 100-barrel batch spills of diesel fuel is also reported. It is highly unlikely that larger volumes of diesel fuel would be spilled from the drilling platforms or support vessels during the drilling operations that would typically be completed.

Oil spill trajectories in open water for spills originating from various locations within the SEA Area have been modelled based on average wind conditions and surface water currents.

2.6.11 Environmental Data Used in Trajectory Modelling

2.6.11.1 Water Currents

A coarse representation of surface water currents for the Labrador Sea and Grand Bank area was entered in the SLROSM spill model from a graphic provided by Charles Tang of DFO. Details regarding the modeling completed by DFO can be found at http://www.mar.dfo-mpo.gc.ca/science/ocean/icemodel/ice_ocean_forecast.html. The water current field used in the modeling is a rough approximation of water currents in the area but is sufficient for the purpose of this SEA. The surface water current field is shown in Figure 2.13. These water currents were combined with 3 percent of the average winds to determine the surface movement of oil slicks.

Figure 2.13 Labrador Surface Water Currents



2.6.11.2 Wind Speed and Predominate Direction

The average wind speeds and predominate directions used in the spill trajectory modelling are shown in Table 2.20. The contents of Table 2.20 were derived from the Meteorological Service of Canada’s 50-year hindcast climatological data (MSC50). The winds in the southern portion of the SEA Area are slightly stronger than in the north. The winds in the winter and fall are predominately from the west-northwest throughout the SEA Area, with the exception of the southern fall winds that are more westerly. In the spring, the winds are predominately from the northwest throughout the SEA Area. Summer wind directions are highly variable throughout the region and winds from the south are more prevalent.

Table 2-20 Average Wind Speeds and Direction Winter Spring Summer Fall

Location Ave. Speed (m/s)

Predominate Direction

Ave. Speed (m/s)


Ave. Speed(m/s)


Ave. Speed (m/s)


Northern (14710)A 9.5 WNW 7.2 NW 5.2 WNW - ESE 8.4 WNW

Central (13893) 10.2 WNW 7.7 NW 5.2 SSE, NW,

WNW 8.5 WNW

Southern (13408) 10.8 WNW 8.3 NW 5.8 SSW 9.0 W

A MSC50 grid point from which data were derived shown in brackets.

2.6.12 General Fate of Persistent Crude Oils, Condensates and Gas

Crude oils found to date in the Grand Bank region have high pour points and form stable emulsions when fresh or slightly weathered. These two factors result in persistent oil spills. Even relatively thin slicks will persist for many days due to an increase in the viscosity of the oil as it weathers and emulsifies. Spills of these types of crude oils will lose about 25 to 30 percent of oil to evaporation within a few days. Concentrations of oil in the water column under slicks of these persistent oils will be very low due to the slow dispersion of oil into the water column. Over long periods (several weeks), the oil will weather and break up into small pieces of benign tar that will diffuse over large areas.

Condensates are light by definition and readily evaporate and disperse when spilled in offshore conditions. At least 50 percent of the condensate reaching the water surface from subsea blowouts will evaporate and the remainder will disperse within hours. Surface condensate slicks will be short-lived and pose little threat to surface resources except in the immediate vicinity (1 or 2 km) of the spill. The rapid dispersion of the condensate may generate in-water hydrocarbon concentrations that could impact in-water resources.

The gas released from surface or shallow subsea blowouts will disperse in the air downwind from the release point if not ignited. Concentrations will drop to levels below health and safety concentration limits within a few hundred metres of the release point. (Ross 1995, 1999, 2000). If the gas is ignited at the source, it will pose an obvious risk to workers and infrastructure in the immediate vicinity of the fire. Gas released from deep-well blowouts under high pressure and low temperature conditions will combine with water to form a solid, ice-like substance known as hydrates that have a density slightly lower than the surrounding water. The solid hydrates will diffuse over a wide area as they slowly rise to the surface and convert back to gas. As the gas is released from the solid hydrate and raises, it will also dissolve into the surrounding water resulting in gas concentrations below health and safety or ignition levels at the water surface.



The general behaviour of persistent crude oils or condensates will not change dramatically if spilled in pack or drift ice conditions. Rates of oil dispersion and emulsification will be reduced if the presence of ice dampens the ocean surface mixing. Evaporation will be similar unless the oil is trapped in layers of frozen ice or is present under snow.

2.6.12.1 Surface Blowout Fate and Behavior

Surface blowouts from drilling platforms will result in small but relatively thick slicks. The amount of oil that evaporates in the air prior to the oil falling to the water surface will depend on the type of oil being discharged. Crude oils may lose 5 to 10 percent through this in-air evaporation, whereas condensates can evaporate up to 70 percent. The oil reaching the water surface will initially form slicks of about 100 m in diameter and 1 to 3 mm thick.

Slicks of persistent crude oil from surface blowouts will quickly emulsify and be very persistent as described in Section 2.6.7.5.

If the blowout is gas and condensate, up to 70 percent of the condensate will evaporate in the air before it reaches the water surface and the remaining condensate will disperse into the water column in less than an hour after forming a slick.

If the surface blowout occurs in the presence of ice, some percentage of the oil will fall onto the surface of the ice passing by the blowout zone. The amount that reaches water or ice will depend on the ice cover concentration. Persistent oil will remain on the ice until breakup; light condensates will completely evaporate unless covered by snow or trapped under an ice layer.

2.6.12.2 Shallow Subsea Blowout Fate and Behavior

Shallow water subsea blowouts (water depth less than 500 m) will create an initially large expanse of relatively thin oil (1.5 to 2.0 km wide and 0.1 to 0.2 mm thick). Approximately 30 percent of a persistent crude oil will evaporate in several hours and the remaining oil will form tea-leaf emulsions and small patches that may survive for days or weeks. The oil will eventually break up into small particles and diffuse over a broad area. If the discharged liquid is a condensate, it will evaporate and disperse within minutes of surfacing.

If the blowout occurs under moving pack ice, the oil will thinly coat the underside of the ice and rise to the water surface between the ice pieces with a thickness and area similar to those described for the open water condition. The oil present under the ice will travel with the ice and remain relatively fresh until released to the surface water.

2.6.12.3 Deep-water Subsea Blowout Fate and Behavior

Deep-water blowouts (water depth greater than 500 m) will generate a range of initial oil conditions, from relatively thick near source to very thin down current from the release, due to the nature of the release. The oil that rises nearest the source will be the thickest and most problematic from a countermeasure or environmental effects assessment perspective. The slicks near the spill source will be very similar to the slicks from the surface blowout scenarios (100 m wide and 1 to 2 mm thick). The persistence of the oil rising near the source will also be similar to the oil from surface blowouts. Persistent crude oils will last on the surface for several weeks and be slowly converted to bits and pieces of tar diffused over large areas. Condensate releases will quickly evaporate and disperse near source. The oil rising to the surface further from the discharge location will behave more like the oil from shallow subsea blowouts.



If the deep-water blowout occurs under moving pack ice, the oil will coat the ice underside and rise between the ice pieces as the pack ice moves past the rise zone. The ultimate fate of the oil will be as described for the shallow water blowout case.

2.6.12.4 Vessel or Drilling Platform Release Modelling Results

Diesel fuel spill scenarios of 100 barrels (1.59 m3) have been considered. Larger spills of diesel fuels from the drilling platform or support vessels are highly unlikely. The initial surface slick from a 100-barrel spill of diesel will be about 30 m wide and reach a maximum thick oil slick width of approximately 125 m. Approximately 30 percent of the diesel can be expected to evaporate from the surface; the remaining diesel will disperse into the water column within a day or two, at most.

If the diesel spills were to occur in pack ice, the oil would be contained by the presence of ice and behave as described in Section 2.6.13. The spreading of the oil would be impeded if the ice concentrations were 5/10ths or higher and emulsification and dispersion would be reduced if the ice causes considerable wave dampening.

2.6.13 Open Water Trajectory Modelling

Spill trajectories have been modelled from several sites throughout the SEA Area to provide an indication of the likely movement of spilled oil in open water conditions. Persistent oil has been tracked for a period of 30 days. If a light oil or condensate were spilled, the slick will not survive for the full 30-day trajectory. The seasonal wind speeds and directions shown in Table 2.20 and water currents in Figure 2.13 have been used in the trajectories. The results are presented by season in Figures 2.14 to 2.17. When seasonal average wind conditions are used in the modelling, the oil moves with the southerly flow of the Labrador Current and remains offshore in all seasons. The movement of pack or drift ice and oil will be somewhat different from that shown in Figure 2.14, the winter trajectory. The speed of drifting ice, especially when in high concentrations, will be different from that of free surface oil. The general direction of the movement of ice and oil will be similar to that shown in these figures.

Winds can be very different from seasonal averages, so it is instructive to investigate the trajectory of oil under different wind conditions. The time that it might take oil to reach shore from various spill locations in the SEA Area is of interest for spill response planning. Winds from the east, while uncommon in this area would most efficiently move oil to the Labrador shore. Spill trajectories have been completed using winds from the east at three wind speeds; 5, 10 and 15 m/s. These speeds represent typical summer speeds, typical fall/winter speeds and a maximum summer wind speed, respectively. Summer is the time of year when easterly winds are most likely to occur. The presence of pack ice will prevent the movement of oil to the Labrador shore by winds from the east in the winter months. The resulting trajectories are shown in Figure 2.18. The trajectories with lower wind speeds are influenced more strongly by the surface water currents and are deflected further to the south prior to hitting land. The times to shore for these scenarios are summarized in Table 2.21.

Table 2-21 Time to Shore for Spills Moved by Easterly Winds in Open Water Conditions Time to Shore

(hours) Wind Speed (m/s) N1* N2 N3 N4 C1 C2 S1 S2 S3 S4

5 240 >720 264 >720 228 >720 228 708 228 684 10 108 312 120 444 180 360 108 312 132 468 15 84 216 72 276 132 228 72 216 84 288

N = Northern (14710)A; C = Central (13893)A; S = Southern (13408)A A MSC50 grid point from which data was derived shown in brackets.



Figure 2.14 Winter Trajectories: Average Winds

Figure 2.15 Spring Trajectories: Average Winds



Figure 2.16 Summer Trajectories: Average Winds

Figure 2.17 Fall Trajectories: Average Winds



Figure 2.18 East Wind Trajectories: All Wind Speeds

2.6.14 Oil Spill Fate and Trajectory Summary

Spills that could occur from offshore exploration drilling operations in the Labrador Shelf SEA Area include surface well blowouts, both shallow and deep-water subsea blowouts and small releases of marine diesel from platform or vessel operations. The behavior of both persistent oils and non-persistent condensates is considered.

Surface blowouts from drilling platforms will result in small but relatively thick slicks. The oil reaching the ocean surface will initially form slicks of about 100 m in diameter and 1 to 3 mm thick. If light oils or condensates are released into the air, a large percentage of the oil will evaporate in the air (up to 70 percent). Much smaller amounts will evaporate in the air if a persistent crude oil is released (5 to 10 percent). Deep subsea blowouts will create similar initial oil thicknesses and footprints near-source to those generated by the above sea releases. Shallow sub-sea blowouts will form larger and thinner initial surface oil deposits (1.5 to 2.0 km wide and 0.1 to 0.2 mm thick).

If subsea or above sea blowouts occur in the presence of pack ice, the oil will be deposited either on the top or underside of the ice pieces as well as between the ice. Any oil trapped under ice by new ice formation below the oil will remain fresh until released to the water surface; oil on the surface of ice will



evaporate but be contained by the ice until breakup. The presence of ice in concentrations higher than approximately 5/10ths will limit the normal spreading of oil over the water surface.

The oil from even relatively thin slicks of persistent oils will remain on the surface for many days due to an increase in the viscosity of the oil as it weathers and emulsifies. Spills of persistent crude oils will lose approximately 25 to 30 percent of oil to evaporation within a few days. Concentrations of oil in the water column under slicks of persistent oils will be very low due to the slow dispersion of oil into the water column. Over long periods (several weeks), the oil will weather and break up into small pieces of benign tar that will diffuse over large areas.

If condensates are spilled, they will evaporate and disperse within hours, under open water conditions. Surface condensate slicks will be short lived and pose little threat to surface resources except in the immediate vicinity (1 to 2 km) of the spill. The rapid dispersion of the condensate may generate in-water hydrocarbon concentrations that could affect in-water resources. The presence of pack ice may reduce the spreading and rate of dispersion of the condensate, depending on the ice concentration. However, it is unlikely that spilled condensate will persist for more than a few days if spilled on open water or between or on ice. Condensate trapped between layers of ice will persist until the ice breaks up.

Batch spills of diesel from vessel or platform operations will form relatively small, low to moderately persistent slicks. The initial surface slick from a 100-barrel spill of diesel will be approximately 30 m wide and reach a maximum thick oil slick width of approximately 125 m. Approximately 30 percent of the diesel can be expected to evaporate from the surface; the remaining diesel will disperse into the water column within a day or two, at most. The presence of high concentrations of pack ice would limit the spread and dispersion of diesel spills resulting in longer surface persistence.

Spilled oil will generally travel to the southeast, in all seasons, under the influence of the southerly Labrador Current and predominate winds from the west-northwest or northwest. Winds are more variable in the summer months and winds from the east are more prevalent in this season. Winds from the east could blow spilled oil to the Labrador shore in open water conditions, depending on how far offshore the spill occurs and if the easterly winds persisted over a long enough period. At those times when ice is present, easterly winds would also push ice towards shore and it would form a natural barrier preventing the movement of oil to the Labrador shore.

2.6.15 Spill Modelling and Response Planning

The exact trajectory (where, when and how much will reach shore) from an oil spill in the Labrador Shelf SEA Area is unknown. Site-specific oil spill trajectory modelling will be required for any proposed exploration drilling project that may occur in the Labrador Shelf SEA Area.

It will be a requirement for any operator to prepare and implement an appropriate and approved Oil Spill Emergency Response Plan, one that recognizes the range of possible accidental events associated with the proposed drilling activities, establishes procedures for notification and response in the event of an incident and identifies locations of trained personnel and nearest equipment. One consideration would be possible remoteness and access to response equipment, depending on how far the spill location is from shore base, or from other operators drilling offshore.

Transport Canada is the Lead Agency for ship safety, response organizations (i.e., Eastern Canada Response Corporation (ECRC) in NL), the 60 Oil Handling Oil Pollution Emergency Plans (OPEPs), and the shipboard oil pollution emergency plans (SOPEPs) for tankers over 150 tonnes and all ships



over 400 tonnes. After an oil pollution incident has occurred from a ship or vessel or is about to occur, then the Canadian Coast Guard-Environmental Response becomes the Lead Agency responsible for ensuring an adequate response. For fixed platforms involved in oil and gas activities operating in the Newfoundland and Labrador Offshore Area, the C-NLOPB is the Lead Agency.

One element of spill response planning is hypothetical spill scenarios that could occur. This will assist in determining possible environmental or economic resources at risk downstream from a spill and be one means of gauging the appropriateness of the spill response plan. The spill assessment results are appropriate supporting information for any spill response strategy developed.

It is appropriate to review available information on shorelines potentially at risk downstream of a spill. In concert with the human and ecological resources in these regions, the physical characterization of shoreline type for example or oil residence index may help one assess the type and level of response that might be in order in the event of cleanup activities. In some instances, local perceptions of what is at risk and should be protected will be factors. And in some cases, for example if natural removal rates of stranded oil are high, it may be better to allow natural recovery of an affected shoreline and the decision to have limited or no cleanup, which may delay natural recovery in areas, may have merits as well (Owens 1999).

Essential to note are the possible variations in wind and current speed and direction that individual trajectories can assume. Of inherent importance as well are the primary fate-determining environmental conditions. In particular, wind and sea surface temperature, at the time of a potential spill, should be key considerations in any response strategy formulation.

The type and quantity of spilled product should be considered if there are to be any considerations of weathering processes, although at least in the pre-drilling assessment period and prior to much information on possible well formations its properties may not be known. Evaporation, the conversion of liquid oil into a gaseous component, and natural dispersion, the break-up of an oil slick into small droplets that are mixed into the sea by wave action, are two important weathering processes that typically occur over the first five days following a spill and act to remove oil from the sea surface. Consideration of the amounts lost due to these processes yields an estimate of the remaining amount of oil. Empirical relations exist for evaporation of many fuel types (usually a function of sea temperature and time). Similarly, vertical dispersion can be estimated from winds and waves. The type of oil will also determine the nature of damage or possible damage following an accident (e.g., risks of fire or explosion, and contamination and mortality to marine life and shoreline resources and costs for possible cleanup).

2.6.15.1 Oil Spill Capabilities in Subarctic environments

Spill response operations in ice and open water are fundamentally different. These variances must be recognized when determining the most appropriate strategy for dealing with oil in specific ice conditions and seasons, including freeze-up, winter, and break-up (DF Dickins Associates 2004). Because of the vastly different ice environments and oil-in-ice situations, over-reliance on a single type of response will likely result in inefficient, ineffective cleanup after an actual spill (DF Dickins Associates 2004).

Mechanical recovery of oil spills in pack ice is limited by drifting ice interrupting conventional containment and skimming activities and is not an effective response option for large scale oil spills above 30 percent ice coverage (DeCola et al. 2006). New techniques to deflect and separate oil and ice, such as prop wash or pneumatic bubblers may enable mechanical systems to encounter and recover oil at higher rates in the presence of drifting ice (DF Dickins Associates 2004).



A series of successful Arctic field experiments in the 1970s and early 1980s was largely responsible for helping in-situ burning become accepted as the most effective oil recovery strategy in situations involving spills in ice covered waters (Dickins and Buist 1981; DF Dickins Associates 2004). Mechanical recovery has been demonstrated to be a practical strategy in solid, fast ice (DF Dickins Associates 2004). However, the effectiveness of conventional mechanical containment and recovery systems can be seriously degraded in broken ice (DF Dickins Associates 2004). Intensive international efforts to develop dedicated mechanical systems for operations in naturally broken ice have not progressed beyond the prototype stage (DF Dickins Associates 2004).

Oil spilled in ice-infested waters, and especially under the ice layer, is not only difficult to contain, it is very difficult to track and model (DeCola et al. 2006). Marine oil spill tracking and remote sensing technology generally relies on air operations, which can be severely constrained by environmental and logistical factors in winter. Existing mathematical models cannot accurately predict the movement of oil on, under, or among offshore ice, although this is an area where considerable research and development is ongoing (DeCola et al. 2006).

The following mechanical recovery devices and systems may have some effectiveness in dynamic ice conditions (DeCola et al. 2006):

• Oleophilic skimmers seem to work best in ice conditions because they limit the amount of water introduced into the skimming and storage units. Disc, drum, and rope mope skimmers can remove light and medium viscosity oils; brush and belt drum skimmers can collect heavy oils.

• Containment booms must be sufficiently durable to withstand the extra force from sea ice. Several types of large ocean boom have been demonstrated to be effective in ice conditions up to 30 percent coverage, although field trials have shown that ice coverage greater than 10 percent can be problematic for some systems.

• Ice booms may be effective in reducing the ice concentration to facilitate skimmer recovery operations. For effective deployment of ice booms, vessels must be able to safely operate in prevailing ice conditions.

• Multi-purpose vessels that can break ice and also provide spill response platforms and temporary storage may prove useful to support mechanical recovery operations in dynamic ice conditions.

• Most mechanical recovery equipment operates more effectively during spring break-up ice conditions than in fall freeze-up conditions. Fall ice conditions as low as 1 percent coverage have been demonstrated to limit the operation of some mechanical recovery systems.

In-situ burning may be effective in ice-infested waters under the following conditions (Decola et al. 2006):

• The oil spill is not widely distributed and can be collected and contained to an adequate thickness for ignition.

• Volatile oil components have not been released due to dispersion via the blowout trajectory or by weathering, such that there are too few volatile components available to sustain a burn.

• Ice floes provide natural containment to maintain slick thickness necessary for ignition (2-3 mm).

• Fire booms can be deployed to maintain slick thickness necessary for ignition (2-3 mm). (Ice conditions can make boom deployment difficult or lead to boom failure.)

• Tracking and surveillance can be carried out from vessels or aircraft to direct ignition missions.

• Slicks can be accessed by vessel or aircraft to deploy ignition device.



Research into the potential efficacy of dispersants in ice-infested waters is ongoing. Initial studies show that this may be a feasible response option, but response experts generally agree that additional study is needed. A major problem with dispersant use in ice-infested waters is the lack of mixing energy. To date, limited consideration has been given to the use of dispersants for spills in ice. Previous experience is summarized in Brown and Goodman (1996).

Compared to temperate, open water conditions, the ability to clean up oil spills in the presence of sea ice is extremely limited and conditional (DeCola et al. 2006). Ice conditions present the significant challenges to on-water spill response. There is very little commercially available equipment appropriate for use offshore in ice-infested waters. Actual experience responding to oil spills in the offshore arctic environment is extremely limited. In addition to the technological limitations on oil spill response systems in sea ice conditions, efficiencies of mechanical recovery equipment such as skimmers and boom may be further reduced by the impacts of cold weather and ice on response personnel, vessel operations, and ancillary equipment such as pumps and anchor systems (DeCola et al. 2006). Similarly, limited daylight and low visibility may complicate or preclude the operation of support vessels or aircraft.

The present inability to reliably detect and map oil trapped in, under, on, or among ice is a critical deficiency, affecting all aspects of response to spills in ice.

2.7 Well Abandonment and Decommissioning

Following completion of exploration (and production) activities, exploration and production well abandonment will be conducted in accordance with Guidelines Respecting Drilling Programs in the Newfoundland Offshore Area (C-NLOPB 2000) and the Newfoundland Offshore Petroleum Drilling Regulations. Under the Newfoundland Offshore Petroleum Drilling Regulations, every operator shall ensure that on the termination of any well, the seafloor is cleared of any material or equipment that could interfere with other commercial uses of the sea, that is the seafloor, is left “fit for use”. It should be noted that explosives are sometimes used for difficult wellhead removal, but only if mechanical severance fails. It is a requirement that operators have authorization from C-NLOPB before explosives are used. Furthermore, in some cases approval can be granted for leaving wellheads in place on a case by case basis. Factors to consider in this case are occurrence and type of fishery in the area as well as water depth at the location of the wellhead.

2.8 Ice Management

2.8.1 Background

Ice management has been an integral part of oil and gas operations in the Beaufort Sea, Offshore Sakhalin, on the east coast of Canada (Grand Banks) and other regions since the 1970s. By breaking up ice floes and towing icebergs, ice management has been effective in extending drilling seasons as well as reducing the risk of downtime and disconnection. Ice management is also effective in reducing the risk of extreme sea ice and iceberg loading on bottom founded and moored facilities. From a design perspective, it is reasonable to consider a blend of ice management with structural resistance in the design philosophy thereby reducing the exposure and demand for structure resistance.



2.8.2 Ice Management System

Ice management strategies involve a number of inter-related components, including ice detection, monitoring and forecasting, ice threat analysis, rig performance and operational status, supply vessel and icebreaker support, and structured operational procedures and protocols for icebreaking and/or iceberg towing and disconnection. An illustration of an ice management framework is illustrated in Figure 2.19. Detection, classification and tracking are the primary components of any ice management system. Sea ice and icebergs must be detected before a basis exists for threat analyses, and if necessary, subsequent intervention activities. Detection tools include, marine radar, airborne radar, satellite based radar (Radarsat and Envisat), optical imagery (Quickbird), vessel reconnaissance, aerial reconnaissance and other marine traffic.

Figure 2.19 Framework for Strategic Ice Management Operations

PhysicalManagement Forecasting

DataManagement

Detection,Tracking &

Classification

Threat Evaluation &

Decision Making

Ice Leaving

Zone

Weather,OperationalStatus, etc.

Ice Observed

Source: C-CORE 2000.

In terms of ice classification, the size and shape of ice features is important for assessing the probability for impact with surface or subsea facilities, as well as estimates of impact and interaction loading based on estimated mass and drift speed. Once a threat has been identified, active physical management is executed. For sea ice management, a number of icebreaking methods exist, depending on ice conditions experienced at the site (Wright 2000; Dunderdale and Wright 2005). A circular pattern icebreaking technique is illustrated in Figure 2.20. When larger, heavier ice is present, the radial grid “picket boat” approach as illustrated in Figure 2.21 may be used. Depending on ice conditions including concentrations, floe size, and velocity, two vessels may be required. One vessel would be operating upstream performing initial heavy icebreaking duties and breaking ice floes into moderate piece sizes of approximately 100 to 150 in diameter. This vessel would have the greatest capability of the fleet given the demand. A second icebreaker would be working closer to the facility breaking the moderately sized floes into smaller piece sizes that would efficiently flow around the facility (typically 50-m floe diameter). The size of this management sector would be typically 1 km2. This vessel would also locate and break up floes that may have been missed by the upstream activities. Depending on conditions, a third vessel may be required to allow close-in management for ice



clearance as well as identifying and breaking larger and older ice embedded within the larger floes. Other techniques are given in the above references, including propeller wash to clear ice around the facility and ice floe pushing (illustrated in Figure 2.22).

Figure 2.20 Icebreaking using Circular Technique



Figure 2.21 Radial Grid “Picket Boat” Ice Breaking Technique

Figure 2.22 Pushing Large Rough Floes at Right Angles to the Drift Line

Source: Wright 2000.

Iceberg towing/deflection methods depends on iceberg size and environmental conditions include single line towing, dual vessel, net towing, prop wash and water cannon as illustrated in Figures 2.23 to 2.27 (Crocker et al. 1998; Mclintock et al. 2007). Deployment and retrieval using two vessels may improve effectiveness and safety of crew for operations in high seas. The vessels can be maneuvered to minimize wind and wave exposure on the aft deck (C-CORE 2006a). To minimize the tendency for the tow rope to slip over the iceberg, the shape of the towline catenary for a given tow force and tow speed is important. The optimal configuration corresponds to a length of deployed tow wire that is



sufficient to allow the direction of the tow force on the aft end of the iceberg to act downward through the center of gravity of the iceberg (C-CORE, 2006).

Figure 2.23 Single Vessel Single Towline Deployment

Figure 2.24 Dual Vessel Ice Island Towing



Figure 2.25 Single and Dual Vessel Net Towing

Figure 2.26 Iceberg Deflection Using Bow-mounted Water Cannon



Figure 2.27 Propeller Washing

As part of the threat analysis process, iceberg drift forecasting is important. An ice-ocean drift prediction model has been developed by Canadian Ice Service (CIS) and DFO for drift prediction on the east coast of Canada, particularly the Grand Banks. Appropriate ice and metocean data must be collected and processed along with ice trajectory forecasting and operational information such as the facility, T-time3 to assess the threat of ice contact with a facility.

Zones are defined around a facility to prioritize ice threat based on facility T-time and ice movement, as illustrated in Figure 2.28. Clear communication, roles, and responsibilities must exist between key operational individuals, including ice advisor, offshore installation manager, drilling supervisor and towing vessel captains.

Ice management performance can be modelled and used to simulate expected performance based on predicted conditions at a particular site. Performance curves for detection and towing have been developed based on iceberg size, sea state and distance from the facility. The reduced exposure associated with reduction in the probability of an iceberg collision with a facility, given detection and towing can be evaluated. Models should consider operational limitations such as fog, multiple icebergs and the influence of pack ice on management effectiveness.

3 T-Time is the time required to suspend drilling operations and move the facility off location.



Figure 2.28 Illustration of Ice Management Zone Around a Drilling or Production Facility

Note: Zones sizes vary on expected ice movement and facility T-Time.

2.8.2.1 Ice Management Success

A detailed review of iceberg management operations can be found in the Programme for Educational Research and Dvelopment (PERD) Comprehensive Iceberg Management Database that presently contains detailed information on 1,505 iceberg management operations (PERD 2002; Rudkin et al. 2005). The database reports details on past iceberg management activities that can be used to analyze the various components of operations, such as techniques, conditions and outcomes. Key parameters relevant for reviewing tow performance include berg size, berg shape, deflection method, reason for ending deflection and deflection outcome. Tow success has been estimated on average to be approximately 85 percent. The introduction of the iceberg net has demonstrated an improvement in ice management tow success. In 2003, 15 of 17 icebergs with shape/stability characteristics that would have normally deemed them as un-towable were successfully towed.

The success of management in sea ice depends on the performance of detection sensors and the accuracy of forecast and drift prediction models used to assess the threat, as well as number and capacity of icebreakers to effectively break-up larger floes, thereby permitting the ice to flow around the structure. Ice management has been very effective with operations in the Arctic (Wright, 2000) as well as operation offshore Sakhalin (Keinonen et al. 2001).

An ice management operation on the Grand Banks primarily involves detection and towing of icebergs with little influence from pack ice. While seasonal activities offshore Labrador may be planned to avoid the threat of sea ice and icebergs, plans for year round operations should consider requirements for ice

Observation Zone

Control Zone (Ice management)

Alert Zone (varies with T-time)

Exclusion Zone (shut-in and disconnection)



management to break up large ice floes and ridges in addition to towing icebergs (including icebergs within pack ice).

While iceberg towing is feasible, the presence of pack ice may considerably reduce towing effectiveness depending on concentrations and, at present, there is no operational experience with towing icebergs through pack ice. In theory, towing in pack ice could be possible for certain light pack conditions, but there are some issues to be considered:

• pack ice will affect vessel manoeuvrability and increase the difficulty with towline deployment and retrieval; and

• pack ice will tend to accumulate in front of the iceberg, thereby increasing the effective mass and reducing resultant tow speed.

2.8.2.2 Design Considerations

It is important that an ice management system be considered as part of the strategy for drilling or production activities in ice-prone regions. Depending on the facility and its capacity to resist ice loading, the demands and type of an ice management system will vary. This is important from design consideration, in that the reliability of the ice management system coupled with the reliability of the structure to resist ice loading must satisfy target reliability levels (e.g., 1-10-5 for a Safety Class 1 Structure - See CSA S471-06 General Requirements, Design Criteria, the Environment, and Load). Design considerations may include such processes and/or equipment as the performance of ice detection equipment, forecast/prediction models, as well as the number and capacity of vessels to manage the ice. Operators may also want to consider the availability of trained offshore ice management individuals, particularly since ice management operations are seasonal in nature.

2.9 Severe Weather

Offshore rigs and platforms are exposed to a variety of severe weather conditions that can cause considerable damage and injury. Severe squalls can shake apart a rig or accelerate the natural aging of the structure. Modern rigs and platforms are designed to withstand severe weather than older rigs. Drilling rigs and production platforms operating in arctic conditions face a number of unique exposures due to the severe weather of the region. Icebergs and pack ice may form near or around the facility; such ice bodies, when moved by wind currents, can exert immense physical strain on the facility and can cause structural damage or even collapse. It is important that when designing or choosing a platform (drilling or production) that the unique and harsh environment of the high attitude areas be considered. Bad weather, metal fatigue, loss of towline, human error and equipment failure are all common factors leading to the loss of rigs at sea including en-route to a new location. At least 30 jack-ups alone have been lost while on tow. Information on a selection rigs that have sunk can be found at http://www.oilrigdisasters.co.uk/, which provides summary details on the incident.

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