Sage Thermal Pilot Project Application Volume 1 December
Sage Thermal Pilot Project Application Volume 1 December
Sage Thermal Pilot Project Application Volume 1 December
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SAGE<br />
THERMAL PILOT PROJECT<br />
ERCB & ESRD JOINT APPLICATION DECEMBER 2012<br />
VOLUME 1 – APPLICATION
Birchwood Resources Inc.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong><br />
<strong>December</strong> 2012<br />
Contents<br />
1 <strong>Sage</strong> Introduction and Overview ............................................................................................. 9<br />
1.0 Introduction .................................................................................................................. 9<br />
1.1 <strong>Project</strong> Proponent ........................................................................................................ 9<br />
1.2 <strong>Project</strong> Background .....................................................................................................10<br />
1.3 Guides to <strong>Application</strong> ..................................................................................................11<br />
<strong>Volume</strong> 1: ERCB & Alberta ESRD Joint <strong>Application</strong> ...........................................................11<br />
<strong>Volume</strong> 2: Consultant Reports ...........................................................................................11<br />
1.4 Purpose ......................................................................................................................11<br />
1.4.1 <strong>Project</strong> Need ........................................................................................................11<br />
1.5 Location ......................................................................................................................12<br />
1.5.1 <strong>Project</strong> Development Area ...................................................................................12<br />
1.5.2 Resource Development Area ...............................................................................12<br />
1.6 <strong>Project</strong> Overview .........................................................................................................12<br />
1.7 <strong>Project</strong> Facilities ..........................................................................................................13<br />
Table 1.7-1 Summary of <strong>Project</strong> Components ....................................................................13<br />
1.7.1 Minimization of Land Disturbance ........................................................................13<br />
1.8 <strong>Project</strong> Development Schedule ...................................................................................14<br />
Table 1.8-1 Development Schedule Pending Regulatory Approval ....................................14<br />
1.9 Regional Setting .........................................................................................................15<br />
1.10 Environment, Health and Safety Program ...................................................................15<br />
Figure 1.1-1 Birchwood <strong>Sage</strong> <strong>Project</strong> Map ..........................................................................16<br />
Figure 1.1-2 Birchwood <strong>Sage</strong> Regional <strong>Project</strong> Map ...........................................................17<br />
Figure 1.2-1 Regional Map ..................................................................................................18<br />
Figure 1.2-2 Regional Satellite image ..................................................................................19<br />
Figure 1.2-3 Local Aerial Image ...........................................................................................20<br />
Figure 1.5-1 <strong>Project</strong> Aerial Photo Mosaic ............................................................................21<br />
Figure 1.5-2 Aerial Photo Showing Existing Development and <strong>Pilot</strong> Site .............................22<br />
2 Economics & Land Use ..........................................................................................................23<br />
2.1 Economics .......................................................................................................................23<br />
2.1.1 Capital and Operating Costs ................................................................................23<br />
2.1.2 Taxes and Crown Royalty ....................................................................................23<br />
2.1.3 Benefit Cost Analysis ...........................................................................................23<br />
2.1.4 Marketing Arrangements ......................................................................................23<br />
2.1.5 Commercial Viability ............................................................................................24<br />
2.2 Socio-Economics ........................................................................................................24<br />
2.2.1 Employment and Procurement .............................................................................24<br />
Table 2.2.1-1 Employment Positions ..................................................................................24<br />
2.3 Traffic and Access ......................................................................................................25<br />
2.4 Integration with Other Land Uses ................................................................................25<br />
2.4.1 Timber/Forestry ..................................................................................................26<br />
2.4.2 Recreational Uses...............................................................................................26<br />
2.4.3 Agriculture ..........................................................................................................26<br />
2.4.4 Trapping .............................................................................................................26<br />
2.4.5 Petroleum and Natural Gas Rights ......................................................................26<br />
2.4.6 Oilsands Rights ...................................................................................................27<br />
2.4.7 Ecological Resources .........................................................................................27<br />
2.4.8 Wildlife ................................................................................................................27<br />
2.4.9 Vegetation ..........................................................................................................27<br />
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2.4.10 Historical Resources ...........................................................................................27<br />
2.4.11 Wetlands .............................................................................................................28<br />
2.4.12 Surface ownership ............................................................................................28<br />
Figure 2.3-1 Access Sketch .................................................................................................29<br />
Figure 2.4.5 PNG Lease Holders Map .................................................................................29<br />
Figure 2.4.6 Oilsands Lease Holders Map ..........................................................................31<br />
Figure 2.3.10A 1950 - Historical Aerial Photo ......................................................................32<br />
Figure 2.3.10B 1977 - Historical Aerial Photo ........................................................................33<br />
Figure 2.3.10C 1980 - Historical Aerial Photo ........................................................................34<br />
Figure 2.3.10D 1988 - Historical Aerial Photo ........................................................................35<br />
Figure 2.3.11 Wetlands Mapping & Potential Plant Locations .............................................36<br />
Figure 2.4.12 Surface Ownership .......................................................................................37<br />
3 Regulatory Approvals .............................................................................................................38<br />
3.1 Existing Approvals ......................................................................................................38<br />
3.2 <strong>Application</strong> for Approval ..............................................................................................38<br />
3.2.1 ERCB Approvals Requested .....................................................................................38<br />
3.2.2 ESRD Approvals Requested .....................................................................................39<br />
3.4 Additional Approvals Associated With the <strong>Application</strong>. ................................................39<br />
3.5 ERCB <strong>Application</strong> Checklist ........................................................................................39<br />
3.6 EPEA <strong>Application</strong> Checklist ........................................................................................39<br />
Appendix 3.5 ERCB <strong>Application</strong> Checklist .................................................................................40<br />
Appendix 3.6 EPEA <strong>Application</strong> Checklist .................................................................................42<br />
4 Geology .................................................................................................................................44<br />
4.1 Area Description .............................................................................................................44<br />
4.1.1 Resource Development Area ......................................................................................44<br />
4.1.2 <strong>Project</strong> Development Area ..........................................................................................44<br />
4.1.3 Geological Study Area ................................................................................................44<br />
4.2 Reservoir Geology ..........................................................................................................44<br />
4.2.1 Regional Stratigraphy .................................................................................................44<br />
4.2.1.1 Granite Wash Formation (Cambrian) ................................................................44<br />
4.2.1.2 Elk Point Group (Devonian) ..............................................................................44<br />
4.2.1.3 Beaverhill Lake Group (Upper Devonian) .........................................................45<br />
4.2.1.4 Mannville Group (Lower Cretaceous) ...............................................................45<br />
4.2.1.4A McMurray Formation .....................................................................................45<br />
4.2.1.4B Clearwater Formation ...................................................................................45<br />
4.2.1.4C Grand Rapids Formation ...............................................................................46<br />
4.2.1.5 Colorado Group Lea Park Formation (Upper Cretaceous) ................................46<br />
4.2.1.6 Overburden (Quaternary) .................................................................................46<br />
4.2.2 Well Control ................................................................................................................46<br />
4.2.2.1 Seismic Data .............................................................................................................47<br />
4.2.3 Geological Description of the Clearwater Formation ..................................................47<br />
4.2.3.1 Clearwater Net Pay ..........................................................................................48<br />
4.2.3.2 Clearwater Bottom Water .................................................................................48<br />
4.2.3.3 Clearwater Top Gas .........................................................................................48<br />
4.2.3.4 Caprock and Seal Integrity ...............................................................................48<br />
4.4 Injection/Fall-off (“mini-frac”) Testing Results ..............................................................49<br />
Table 4.4.1 Clearwater Shale Closure Pressure Regional Value ........................................49<br />
Table 4.4.2 Summary of Closure Pressures per Zone Tested ............................................49<br />
Figure 4.1.1 Resource Development Area (“RDA”) .............................................................50<br />
Figure 4.1.2 <strong>Project</strong> Development Area (PDA) & Wells .......................................................51<br />
Figure 4.1.3 Geological Study Area .....................................................................................52<br />
Figure 4.2.1 Cold Lake Stratigraphy ....................................................................................53<br />
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Figure 4.2.1.4A Schematic SW-NE cross-section Clearwater Formation ...............................54<br />
Figure 4.2.1.4B Regional Cross Section Clearwater Formation .............................................55<br />
Figure 4.2.1.4C Birchwood Clearwater Type Log ..................................................................56<br />
Figure 4.2.2A Well Control Map ..........................................................................................57<br />
Figure 4.2.2B Cross Section Birchwood Lease - Clearwater Formation ..............................58<br />
Figure 4.2.2C Formation Imaging logs (FMI) - Clearwater Formation Interval .....................59<br />
Figure 4.2.2D Log Analysis .................................................................................................60<br />
Figure 4.2.2E Summary Core Data and Photos 100/03-02-064-04W400 ...........................61<br />
Figure 4.2.2.1A Depth converted time structure map top of Clearwater Formation .................62<br />
Figure 4.2.2.1B Interpreted Seismic Data ..............................................................................63<br />
Figure 4.2.3B Structure on the Top of the Clearwater Formation ........................................64<br />
Figure 4.2.3.1 Clearwater Net Pay .......................................................................................67<br />
Figure 4.2.3.1B Clearwater Net Pay ......................................................................................68<br />
Figure 4.2.3.2 Structure Clearwater Bottom Water ..............................................................69<br />
Figure 4.2.3.4 Isopach Map Clearwater Formation Capping Shale ......................................70<br />
5 Reservoir Recovery Process ..................................................................................................71<br />
5.1 Reservoir Properties ...................................................................................................71<br />
5.1 Table <strong>Sage</strong> Typical Reservoir Properties ....................................................................71<br />
5.1.1 Recovery Process Selection ................................................................................71<br />
5.1.2 Recovery Process Description .............................................................................71<br />
5.2 SAGD Start-Up Phase ................................................................................................72<br />
5.2.1 Warm Up/Circulating (60-90 days) .......................................................................72<br />
5.2.2 Transition (30-90 days) ........................................................................................73<br />
5.3 Steady State SAGD Operating Phase .........................................................................73<br />
5.3.1 Operating Pressures ............................................................................................74<br />
5.3.2 Maximum Operating Pressure (“MOP”) ................................................................74<br />
5.3.3 Potential Follow-up Processes for Improved Recovery ........................................74<br />
5.4 Reservoir Monitoring ...................................................................................................75<br />
5.4.1 Temperature Measurement ..................................................................................75<br />
5.4.2 Gas Blanket Pressure Measurement ...................................................................75<br />
5.4.3 Micro-deformation Monitoring ..............................................................................75<br />
5.4.4 Observation Wells ................................................................................................75<br />
5.5 Recovery and Original Oil In Place .............................................................................76<br />
5.5.1 Original Oil in Place (“OOIP”) ...............................................................................76<br />
5.5-1 Original Oil In Place Summary Table ........................................................................76<br />
5.5.1.1 Gas Reserves ........................................................................................................76<br />
5.5.2 Drilling Constraints and By-passed Pay ...............................................................76<br />
5.5.3 Drainage Pattern Layouts ....................................................................................77<br />
5.5.4 Well Length and Spacing .....................................................................................77<br />
5.6 Expected Well Performance ........................................................................................77<br />
5.6.1 Typical SAGD Well-Pair Performance ..................................................................78<br />
5.6.2 SAGD Well-Pair A1 Expected Performance Data - 1,053m Effective length ........78<br />
5.6.3 SAGD Well-Pair A10 Expected Performance Data - 603m Effective length .........78<br />
5.6.4 SAGD Well-Pairs Expected <strong>Pilot</strong> Performance Data ............................................79<br />
5.7 Results of Numerical Simulation Studies ........................................................................79<br />
5.7.1 Modeling Approach ..............................................................................................79<br />
5.7.2 Model Production Performance ............................................................................80<br />
Figure 5.5.3-1 CPF & SAGD Well Pair Layout .....................................................................81<br />
Figure 5.5.3-2 SAGD Well Pair Layout & Net Pay ................................................................82<br />
Figure 5.5.3-2 Future Development SAGD Well Pair Layout ................................................83<br />
Figure 5.7.1 Grid Layout 200x200x40 ..................................................................................84<br />
Figure 5.7.2 N - S Cross Section Showing Water Saturation and Horizontal Well Locations 85<br />
Figure 5.7.3 E - W Cross Section Showing Water Saturation and Horizontal Well Locations 86<br />
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Figure 5.7.4 Refined Grid East‐West Cross‐Section Water Saturation .................................87<br />
Figure 5.7.5 Gas-Liquid Relative Permeability ......................................................................88<br />
Figure 5.7.5 Water-Oil Relative Permeability ........................................................................88<br />
Figure 5.7.6 Predicted Production Rates ..............................................................................89<br />
Figure 5.7.7 Saturation and Temperature at 1.0 year X Section ...........................................90<br />
Figure 5.7.8 Saturation and Temperature at 1.0 Year Well Length .......................................91<br />
Figure 5.7.9 Saturation and Temperature at 3.6 years X Section .........................................92<br />
Figure 5.7.10 Saturation and Temperature at 8.5 years X Section ......................................93<br />
Figure 5.7.11 Predicted Cumulative Production ..................................................................94<br />
Appendix 5.7.A1 Well Properties 100030206404W400 .........................................................95<br />
Appendix 5.7.A2 Well Properties 100060206404W400 .........................................................96<br />
Appendix 5.7.A3 Well Properties 100010306404W400 .........................................................97<br />
Appendix 5.7.A4 Well Properties 100050106404W400 .........................................................98<br />
Appendix 5.7.A5 Well Properties 102062606304W400 .........................................................99<br />
Appendix 5.7.A6 Well Properties 102062406304W400 ....................................................... 100<br />
Appendix 5.7.B1 Rock Grid Properties ................................................................................ 101<br />
Appendix 5.7.B2 Measured Viscosity and Density ............................................................... 101<br />
Appendix 5.7.B3 Extrapolated Viscosity used in Model ....................................................... 101<br />
6 Drilling and Completions ...................................................................................................... 102<br />
6.1 Overview ................................................................................................................... 102<br />
6.2 Well Pad Layout ........................................................................................................ 103<br />
6.2.1 Drilling SAGD Well Pairs .................................................................................... 103<br />
6.2.2 Surface Section ................................................................................................. 104<br />
6.2.3 Intermediate or Build Section ............................................................................. 104<br />
6.2.4 Horizontal Section .............................................................................................. 105<br />
6.3 Completions .............................................................................................................. 105<br />
6.3.1 Production Well Completion ............................................................................... 105<br />
6.3.2 Injection Well Completion................................................................................... 106<br />
6.4 Cementing Program .............................................................................................. 106<br />
6.4.1 Mud System ....................................................................................................... 106<br />
6.4.2 Float Equipment ................................................................................................. 107<br />
6.4.3 Cement and Cementing ..................................................................................... 107<br />
6.5 Casing Failure Monitoring Program ....................................................................... 107<br />
6.6 Vertical Wells ............................................................................................................ 108<br />
6.6.1 Source Water Wells ........................................................................................... 108<br />
6.6.2 Observation Wells .............................................................................................. 109<br />
6.6.3 Disposal Well(s) ................................................................................................. 109<br />
6.6.4 Abandonment Status of Wells Within the RDA ................................................... 109<br />
6.5 Drilling Waste Management ...................................................................................... 109<br />
Figure 6.2-1 Well Configuration and Spacing ..................................................................... 110<br />
Figure 6.2-2 3D Model of Well Configuration ..................................................................... 111<br />
Figure 6.2.1-1 Producer Wellhead ..................................................................................... 112<br />
Figure 6.2.1-1B Producer Wellhead ..................................................................................... 113<br />
Figure 6.2.1-2 Injector Wellhead ........................................................................................ 114<br />
Figure 6.2.1-2B Injector Wellhead ....................................................................................... 115<br />
Figure 6.3.1 Producer Well Schematic .............................................................................. 116<br />
Figure 6.3.2 Injector Well Schematic ................................................................................. 117<br />
Figure 6.6.1-1 Source Well: Utility Water Well Schematic .................................................. 118<br />
Figure 6.6.1-2 Source Well: Brackish Water Well Schematic ............................................ 119<br />
Figure 6.6.2-1 Observation Well Schematic ....................................................................... 120<br />
Figure 6.6.3-1 Disposal Well Schematic ........................................................................... 121<br />
Figure 6.6.4-1 Details of Existing Wells .............................................................................. 122<br />
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7 Facilities ............................................................................................................................... 123<br />
7.1 Overview ....................................................................................................................... 123<br />
7.1.1 Central Processing Facility ................................................................................. 123<br />
7.1.2 Well Pad Facility ................................................................................................ 124<br />
7.1.3 Design Flow Rates ............................................................................................. 124<br />
7.2 Steam Generation and Water Treatment .................................................................. 125<br />
7.2.1 Steam Generation ................................................................................................... 125<br />
7.2.2 <strong>Project</strong> Make-up and Boiler Feed Water Sources .............................................. 125<br />
Table 7.2.2-1 Summary Water Sources and Uses at Maximum Capacity ..................... 126<br />
7.2.3 Produced Water Treatment Process .................................................................. 126<br />
7.2.3.1 Evaporation .................................................................................................... 127<br />
7.2.3.2 Boiler Feed Water .......................................................................................... 127<br />
7.2.4 Produced Water Disposal .................................................................................. 128<br />
7.3 Bitumen Treatment ................................................................................................... 128<br />
7.3.1 De-Oiling ........................................................................................................... 129<br />
7.3.1.1 Skim Tanks .................................................................................................... 129<br />
7.3.1.2 Induced Gas Flotation .................................................................................... 129<br />
7.3.1.3 Oil Removal Filters ......................................................................................... 130<br />
7.3.2 De-Sanding ........................................................................................................ 130<br />
7.3.3 Sales Oil Management and LACT ...................................................................... 130<br />
7.3.5 Slop Oil System ................................................................................................. 131<br />
7.4 Inlet Cooling and Separation ..................................................................................... 132<br />
7.5 Fuel and Produced Gas Recovery System ............................................................... 132<br />
7.5.1 Sulfur Production and Recovery .............................................................................. 133<br />
Table 7.5.1-1 Sulphur Production and Recovery Criteria .................................................. 133<br />
7.6 Vapour Recovery and Flare Systems ........................................................................ 133<br />
Table 7.6.1 Vapour Sources ............................................................................................ 134<br />
7.7 Energy & Heat and Material Balances....................................................................... 134<br />
7.7.1 Energy Balance .................................................................................................... 134<br />
Table 7.7.1-1 Energy Balance .......................................................................................... 135<br />
Table 7.7.2 Heating Values .............................................................................................. 135<br />
7.8 MARP Conceptual Plan ............................................................................................ 135<br />
7.8.1 Objectives .......................................................................................................... 135<br />
7.8.2 Process Flow Metering Schematic ..................................................................... 136<br />
7.8.3 Boundary Streams ............................................................................................. 137<br />
7.8.4 <strong>Project</strong> Wells ...................................................................................................... 137<br />
7.8.5 <strong>Project</strong> Meters .................................................................................................... 137<br />
7.8.6 Facility Tankage ................................................................................................. 138<br />
Table 7.8.6-1 Tank Listing ................................................................................................ 138<br />
7.8.7 <strong>Project</strong> Dispositions and Receipts ...................................................................... 139<br />
Table 7.8.7-1 Production Battery Disposition and Receipt Points ..................................... 139<br />
7.9 Chemical Use ........................................................................................................... 139<br />
7.9.1 Produced Water Treatment Stream ................................................................... 139<br />
7.9.1.2 Feed Water .................................................................................................... 139<br />
7.9.1.3 Boiler Feed Water .......................................................................................... 140<br />
7.9.2 Bitumen Treatment ............................................................................................ 140<br />
7.9.2.1 Free Water Knockout Tank ............................................................................. 140<br />
7.9.2.5 Induced Gas Flotation .................................................................................... 140<br />
7.9.2.5 Sales Oil ......................................................................................................... 141<br />
7.10 Services and Utilities ................................................................................................. 141<br />
7.10.1 Field Office Facility and Camps......................................................................... 141<br />
7.10.2 Highways and Rights of Way ............................................................................ 141<br />
7.10.3 Utilities .............................................................................................................. 141<br />
7.10.3.1 Electrical Power ............................................................................................. 141<br />
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7.10.3.2 Natural Gas .................................................................................................... 141<br />
7.10.3.3 Pipelines ........................................................................................................ 142<br />
7.10.3.3.1 Diluent Pipeline ........................................................................................... 142<br />
7.10.3.3.2 Sales Pipeline ............................................................................................. 142<br />
7.11 Health, Safety and Environmental Controls ............................................................... 142<br />
7.11.1 Facility Emergency Response Plan ................................................................... 142<br />
7.11.2 Fire Control Plan ............................................................................................... 143<br />
7.11.2.1 Wildfire Prevention ......................................................................................... 143<br />
7.11.2.2 Facilities Fire Protection ................................................................................. 143<br />
7.11.3 Air Emissions Management ............................................................................ 143<br />
7.11.4 Noise Emissions Management ....................................................................... 144<br />
7.11.5 Spill Control and Leak Detection ..................................................................... 144<br />
7.11.6 Surface Water Management ........................................................................... 144<br />
7.12 Chemical and Waste Management ........................................................................... 144<br />
7.12.1 Chemical Management ..................................................................................... 144<br />
Table 7.12.1-1 Chemical Summary .................................................................................. 145<br />
7.12.2 Waste Management .......................................................................................... 146<br />
Figure 7.1.1 CPF and Well Pad Plot Plan .......................................................................... 147<br />
Figure 7.1.2 3D Model of CPF and Well Pad ..................................................................... 148<br />
Figure 7.2.2 Process Flowsheet 200-1 Wellpad ................................................................ 149<br />
Figure 7.2.2-A Block Flow Diagram - De-Oiling, Water treatment and Steam Generation .. 150<br />
Figure 7.2.2-B Water Balance - De-Oiling, Water treatment and Steam Generation ........... 151<br />
Figure 7.2.1-1 Process Flowsheet 100-8 Steam Generation .............................................. 152<br />
Figure 7.2.2-1 Process Flowsheet 100-6 Water Treatment ............................................... 153<br />
Figure 7.2.3-1A Process Flowsheet 100-7A Water Treatment .............................................. 154<br />
Figure 7.2.3-1B Process Flowsheet 100-7B Water Treatment .............................................. 155<br />
Figure 7.2.3-2 Process Flowsheet 100-1 Inlet Process ...................................................... 156<br />
Figure 7.3-1 Process Flowsheet 100-2 Bitumen Treating ................................................ 157<br />
Figure 7.3.1-1 Process Flowsheet 100-4 De-Oiling ............................................................ 158<br />
Figure 7.3.2-1 Process Flowsheet 100-5 Desand and Slop Oil .......................................... 159<br />
Figure 7.3.3-1 Process Flowsheet 100-3 Bitumen Storage ................................................ 160<br />
Figure 7.4-1 Process Flowsheet 100-9 Glycol System..................................................... 161<br />
Figure 7.5-1 Process Flowsheet 100-10 Utilities Instrument Air/Fuel Gas ....................... 162<br />
Figure 7.6-1 Process Flowsheet 100-11 Vapor Recovery ............................................... 163<br />
Figure 7.8.2-1 Simplified MARP Schematic ....................................................................... 164<br />
Appendix 7.1 Equipment List ............................................................................................ 165<br />
Appendix 7.2 Heat and Material Balance .......................................................................... 169<br />
Appendix 7.3 Waste Management Table .......................................................................... 182<br />
8 Environmental Review and Baseline Assessment ................................................................ 186<br />
8.1 Overview ................................................................................................................... 186<br />
8.2 Historical Resources ................................................................................................. 187<br />
8.2.1 Aerial Photograph Review.................................................................................. 187<br />
8.2.2 Land Use ........................................................................................................... 187<br />
8.2.2 Traditional Land Use .......................................................................................... 187<br />
8.3 Air Resources ........................................................................................................... 188<br />
8.3.1 Climate and Meteorology ................................................................................... 188<br />
Table 8.3.1-1 Climate and Meterologic Data .................................................................... 188<br />
8.3.2 Air Quality .......................................................................................................... 189<br />
Table 8.3.2-1 Emission Sources and Physical Stack Parameters .................................... 189<br />
Table 8.3.2-2 Dispersion Model Predictions ..................................................................... 190<br />
Table 8.3.2-3 Emission Rates Used in Dispersion Modeling in (g/s) ................................. 190<br />
8.3.2.1 Fugitive Emissions ......................................................................................... 190<br />
8.3.2.2 Air Monitoring ................................................................................................. 190<br />
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8.4 Noise Control ............................................................................................................ 191<br />
Table 8.4-1 Predicted Noise Levels for the <strong>Project</strong> <strong>Application</strong> Case ............................... 191<br />
8.4.2 Low Frequency Noise ........................................................................................ 191<br />
Table 8.4-2 Low Frequency Noise Assessment Results ................................................... 192<br />
8.5 Water Resources ...................................................................................................... 192<br />
8.5.1 Surface Water .................................................................................................... 192<br />
8.5.2 Surficial Geology and Shallow Aquifers (Hydrostratigraphic Units) ..................... 193<br />
Table 8.5.2-1 Shallow Aquifer Geochemical Characteristics ............................................ 193<br />
8.5.3 Bedrock Geology and Aquifers .......................................................................... 194<br />
8.5.3.1 Brackish Water Resources ............................................................................. 194<br />
8.5.3.2 Brackish Water Suitability ............................................................................... 194<br />
8.5.4 Fresh Water Resources ..................................................................................... 195<br />
8.5.4.1 Surface and Shallow Aquifer Use ................................................................... 195<br />
Table 8.5.4-1 Groundwater Allocation in the Cold Lake Beaver River Basin .................... 195<br />
Table 8.5.4-2 Groundwater Allocation in the Cold Lake Beaver River Basin Including<br />
Livestock/domestic and Domestic Usage 2003 ................................................................ 195<br />
8.5.5 Water Balance ................................................................................................... 196<br />
8.5.6 Birchwood Water Usage .................................................................................... 196<br />
8.5.7 Water Disposal .................................................................................................. 196<br />
8.6 Soil and Terrain ........................................................................................................ 196<br />
8.6.1 Surficial Geology and Landforms ....................................................................... 197<br />
8.6.2 Soil Structure ..................................................................................................... 197<br />
Table 8.6.2-1 Soil Types and Distribution in the Proposed Development Area ................. 197<br />
8.6.3 Land Capability Ratings ..................................................................................... 198<br />
Table 8.6.3-1 Land Capability Rating – Agricultural Crops ............................................... 198<br />
8.6.4 Reclamation Suitability Rating ........................................................................... 198<br />
Table 8.6.4-1 Reclamation Suitability Ratings for the Well and Facility Pad ..................... 199<br />
8.7 Vegetation ................................................................................................................ 199<br />
8.7.1 Methodology ...................................................................................................... 199<br />
8.7.2 Ecosite Phases at the Proposed <strong>Project</strong> Development Area .............................. 200<br />
8.7.3 Rare Plant and Plant Communities .................................................................... 204<br />
8.7.4 Old Growth Forests ............................................................................................ 204<br />
8.7.5 Summary of Potential Impacts and Mitigation Measures .................................... 204<br />
8.7.5.1 Direct Vegetation Removal ............................................................................. 204<br />
8.7.5.2 Impacts to Uncommon Vegetation .................................................................. 204<br />
8.7.5.3 Soil Acidification ............................................................................................. 204<br />
8.7.5.4 Introduced Plant Species Invasion ................................................................. 204<br />
8.8 Wildlife Assessment .................................................................................................. 205<br />
8.8.1 Methodology ...................................................................................................... 205<br />
8.8.1.1 Wildlife Species Occurrence and Status ......................................................... 205<br />
8.8.1.2 Wildlife Species of Management Concern ...................................................... 205<br />
8.8.2 Wildlife Species Occurrence and Status ............................................................ 205<br />
8.8.3 Species of Management Concern ...................................................................... 206<br />
8.8.4 Summary of Potential Wildlife Impacts and Mitigation Measures........................ 206<br />
8.8.4.1 Habitat Loss/Alteration ................................................................................... 206<br />
8.8.4.2 Habitat Fragmentation .................................................................................... 206<br />
8.8.4.3 Movement Obstruction ................................................................................... 206<br />
8.8.4.4 Sensory Disturbance ...................................................................................... 207<br />
8.8.4.5 Direct Mortality ............................................................................................... 208<br />
8.9 Summary of Environmental Receptors and impact ratings ........................................ 209<br />
8.10 Summary of Environmental Commitments ................................................................ 214<br />
8.10.1 Air Monitoring..................................................................................................... 214<br />
8.10.2 Noise ................................................................................................................. 214<br />
8.10.3 Water ................................................................................................................. 214<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 7
8.10.4 Vegetation ......................................................................................................... 214<br />
8.10.5 Wildlife ............................................................................................................... 214<br />
8.10.6 Emergency/Spill Response ................................................................................ 214<br />
8.10.7 Participation in Area Research ........................................................................... 214<br />
Figure 8.3.2-1 Maximum Predicted NO2 Contours for the 1-hour Averaging Period including<br />
Ambient Background ............................................................................................................... 215<br />
Figure 8.3.2-2 Maximum Predicted SO2 Contours for the 1-hour Averaging Period including<br />
Ambient Background ............................................................................................................... 216<br />
Figure 8.4-1 Noise Study Area and Receptor Locations .......................................................... 217<br />
Figure 8.4-2 Predicted Nighttime Noise Levels........................................................................ 218<br />
Figure 8.4-3 Relationships Between Everyday Sounds ........................................................... 219<br />
Figure 8.5.3-1 Stratigraphic and hydrostratigraphic columns in the Cold Lake-Beaver River<br />
Basin ....................................................................................................................................... 220<br />
Figure 8.5.3-2 Location of the <strong>Project</strong> within the Beaver River Basin in Alberta....................... 221<br />
Figure 8.5.3-3 Recharge and Discharge Areas in the Cold Lake-Beaver River Basin.............. 222<br />
Figure 8.6.2-1 Soils Types and Locations ............................................................................... 223<br />
Figure 8.7.2-1 Birchwood Study Area ...................................................................................... 224<br />
Figure 8.7.2-2 Vegetation Cover Types ................................................................................... 225<br />
Figure 8.7.2-3 Vegetation Plots .............................................................................................. 226<br />
Figure 8.7.2-4 Rare Vascular Plant Survey Path ..................................................................... 227<br />
9 Public and First Nations Consultation ................................................................................... 228<br />
9.1 Overview ....................................................................................................................... 228<br />
9.1.1 Goal of Consultation .......................................................................................... 228<br />
9.1.2 Consultation Summary ....................................................................................... 228<br />
9.2 Stakeholder Identification .......................................................................................... 229<br />
9.3 Open House Summary ............................................................................................. 230<br />
9.4 Stakeholder Comments and Responses ................................................................... 231<br />
Table 9.4.1 Summary of Stakeholder Questions and Responses by Birchwood .............. 232<br />
9.5 First Nation Consultation Framework ........................................................................ 237<br />
9.5.1 First Nation Consultation Summary .................................................................... 238<br />
9.5.1.1 Cold Lake First Nation .................................................................................... 238<br />
9.5.1.2 Frog Lake First Nation .................................................................................... 238<br />
9.5.1.3 Beaver Lake Cree Nation ............................................................................... 239<br />
9.5.1.4 Kehewin Cree Nation ..................................................................................... 239<br />
9.5.1.5 Heart Lake First Nation .................................................................................. 240<br />
9.5.1.6 Whitefish – Goodfish First Nation ................................................................... 240<br />
9.6 Meetings and Events ................................................................................................. 241<br />
Table 9.6 List of Meetings and Events ............................................................................. 241<br />
9.7 Birchwood Commitment to Consultation ................................................................... 243<br />
10 References ................................................................................................................... 244<br />
11 Acronyms and Abbreviations ........................................................................................ 253<br />
<strong>Volume</strong> 2: Consultants Reports<br />
CR1 – Hydrogeology<br />
CR2 – Air Quality Modeling Report<br />
CR3 – Noise impact Assessment<br />
CR4 – Vegetation and Wildlife Assessment<br />
CR5 – Soils Assessment<br />
CR6 – Injection/Fall off testing results<br />
CR7 – Conservation and Reclamation Plan<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 8
1 <strong>Sage</strong> Introduction and Overview<br />
1.0 Introduction<br />
Birchwood Resources Inc. (“Birchwood”) is a privately owned Canadian energy company<br />
operating in the Cold Lake Region of Alberta, Canada. This application is seeking approval to<br />
construct, operate and reclaim the <strong>Sage</strong> Commercial Demonstration <strong>Pilot</strong> <strong>Project</strong>, a crude<br />
bitumen recovery scheme that will utilize steam assisted gravity drainage (“SAGD”) technology<br />
to produce bitumen at a rate of 795m 3 (5,000 barrels) per day. The life of the 10 well pair pilot<br />
project is 5 years. Total Original Oil In Place (“OOIP”) in the Clearwater Formation is estimated<br />
at 24,037 e3m3 (151 million barrels). Recoverable crude bitumen using SAGD recovery is<br />
estimated to be up to 65%. The combined facility, well pad design and layout has incorporated<br />
the potential for up to 36 well pairs to be drilled from the facility/well pad proposed herein, If the<br />
project proves to be successful, the life of the project would be extended to at least 15 years.<br />
Birchwood is proposing an in situ recovery operation that reduces environmental impacts, and<br />
has taken additional steps to design the most efficient facility possible. Significant attention has<br />
been put towards mitigating noise and odor concerns, utilizing brackish makeup water,<br />
generating high produced water recycle ratios and managing ground water protection. The<br />
information gathered from the pilot will allow an efficient and controlled development of the<br />
provincial resource and facilitate continuous improvement at <strong>Sage</strong>.<br />
Birchwood has actively engaged stakeholders to explain the project and to understand their<br />
concerns. A Summary of Stakeholder Consultation results conducted to date is included as part<br />
of this application in Section 9. Stakeholder consultation and communication will continue<br />
throughout the life of the proposed project.<br />
1.1 <strong>Project</strong> Proponent<br />
Birchwood Resources Inc. is the project proponent. Birchwood owns a 100% working interest<br />
oilsands leases located in the South half of Section 1, all of Section 2 and SE quarter of Section<br />
3 in Township 064, Range 4 West of the 4th Meridian. The Resource Development Area<br />
includes Section 2 and SE 3 Township 064, Range 4 West of the 4th Meridian. (Figure 1.1-1)<br />
The legal name and address of the applicant for the project is:<br />
Birchwood Resources Inc.<br />
Suite 1200, 630 6 th Ave S.W.<br />
Calgary, AB<br />
T2P 0S8<br />
Correspondence concerning this application should be directed to the above office address to<br />
the attention of:<br />
Kathryn Lundy<br />
Manager, Safety Environment and Regulatory Compliance<br />
Phone: 403-265-1244, ext. 221 Fax: 403 -265-1204<br />
Email: klundy@birchwoodresources.ca<br />
Authorization for submission:<br />
“Original signed by”<br />
Alex Lemmens P.Eng<br />
President & CEO<br />
Phone: 403-265-1244, ext. 225 Fax: 403-265-1204<br />
Email: alemmens@birchwoodresources.ca<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 9
1.2 <strong>Project</strong> Background<br />
Birchwood Resources Inc. has acquired the Mineral Lease #77497120898 for oilsands in the<br />
Manville Group in the South ½ of Section 1, Section 2 and SE 1 /4 of Section 3, in Township 64,<br />
Range 04 west of the 4th Meridian leased from the Alberta Government. The mineral lease<br />
comprises approximately 448 hectares (“ha”) and is located within the Municipality of Bonnyville.<br />
(See Figure 1.2-1)<br />
Birchwood drilled three wells in the winter of 2011 targeting primary bitumen production from the<br />
Grand Rapid Formation and evaluation of the Clearwater and McMurray Formations within the<br />
Manville group. Both a Pre-disturbance Assessment and a Traditional Land Use study were<br />
completed by third parties before this work was done. Also, before any disturbance occured,<br />
meetings were held with the Cold Lake First Nation Chief and Council, the Lakeland Industry<br />
and Community Association Board of Directors and the Councilors of the Municipal District of<br />
Bonnyville.<br />
The three wells were drilled and completed using conventional production methods. Due to the<br />
high viscosity of the oil, only one of the wells achieved sub-economic production from the upper<br />
Grand Rapids formation using conventional methods. The other two wells were shut in. All three<br />
of these wells encountered clean, high porosity highly saturated bitumen sand within the<br />
Clearwater formation. Core and log analysis indicated that the Clearwater Formation would<br />
react very favorable to SAGD thermal recovery. Reservoir simulations and Pre-feed Engineering<br />
were initiated and completed in March and August, respectively, of 2012.<br />
In June of 2012 Birchwood hosted an open house at the local Riverhurst community center to<br />
introduce the project and to seek preliminary feedback form stakeholders. The feedback was<br />
used by Birchwood to augment the development to mitigate concerns and potential impacts to<br />
affected stakeholders. In total Birchwood received 157 written comments and questions.<br />
Frequently asked questions were posted on Birchwood’s website and detailed question were<br />
responded to individually upon completing the necessary evaluations and data collection and<br />
assessments in November of 2012. The assessments included 3D computer modeling, noise<br />
impacts and air quality assessments, hydrogeology groundwater assessment, vegetation and<br />
wildlife assessments, soils and geo-technical assessments, and injection testing to confirm cap<br />
rock integrity.<br />
The <strong>Sage</strong> project is proposing to develop the resources using a modular facility design and drill<br />
10 horizontal well pairs for a commercial demonstration SAGD pilot recovery exploiting the<br />
Clearwater Formation. If successful, plans will be developed and submitted to regulatory<br />
authorities to develop the remaining resources within the RDA and to test thermal recovery<br />
methods for bitumen bearing sands in the Grand Rapid Formation. The focus of this application<br />
will be the initial commercial demonstration/pilot phase of bitumen recovery from the Clearwater<br />
Formation.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 10
1.3 Guides to <strong>Application</strong><br />
This application for the project is contained in two volumes and consists of the following<br />
components:<br />
<strong>Volume</strong> 1: ERCB & Alberta ESRD Joint <strong>Application</strong><br />
Section 1 – <strong>Project</strong> Introduction and Overview<br />
Section 2 – Economics and Land Use<br />
Section 3 – Regulatory Approvals<br />
Section 4 – Geology<br />
Section 5 – Reservoir Recovery process<br />
Section 6 – Process Description<br />
Section 7 – Drilling & Completions<br />
Section 8 – Environmental Setting<br />
Section 9 – Stakeholder Consultation<br />
Section 10 – References<br />
Section 11 – Acronyms and Abbreviations<br />
<strong>Volume</strong> 2: Consultant Reports<br />
CR1 – Hydrogeology<br />
CR2 – Air Quality Modeling Report<br />
CR3 – Noise impact Assessment<br />
CR4 – Vegetation and Wildlife Assessment<br />
CR5 – Soils Assessment<br />
CR6 – Injection/Fall off Testing Results<br />
CR7 – Conservation and Reclamation Plan<br />
1.4 Purpose<br />
The purpose of the project is to demonstrate commerciality of a small scale modular concept<br />
development to recover crude bitumen from the Clearwater Formation.<br />
1.4.1 <strong>Project</strong> Need<br />
As declining conventional crude production continues, additional heavy oil production will benefit<br />
global energy needs. The <strong>Project</strong> will specifically pilot small scale sustainable commercial<br />
development to unlock smaller accumulations of bitumen in the province that were previously<br />
considered uneconomic. If successful, this modular technology may be used on other oil sands<br />
in situ projects leading to an increase in provincial reserves utilizing brackish water reducing<br />
water required to maintain and grow in-situ heavy oil production in a sustainable manner.<br />
The <strong>Project</strong> will provide benefits to the Provincial and Regional economies because of capital<br />
expenditures in the order of $230 million prior to the commencement of production operations.<br />
Once production begins additional expenditures for sustaining capital, operating costs including<br />
salaries, royalties and taxes payable will be incurred throughout the life of the <strong>Project</strong>. (See<br />
Economics in Section 2.1)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 11
1.5 Location<br />
1.5.1 <strong>Project</strong> Development Area<br />
Birchwood has identified a <strong>Project</strong> Development Area ("PDA") and a Resource Development<br />
Area ("RDA") for the <strong>Sage</strong> <strong>Project</strong> (see Figure 1.1-1). The PDA is the area of land on which<br />
wells and surface facilities will reside. The PDA encompass 18.6 ha (580 m x 320 m) of land<br />
area for the well pad and Central Processing Facility. The PDA will be located in the SW-02-<br />
064-04W4M. (See Figure 1.5-1)<br />
1.5.2 Resource Development Area<br />
The RDA is the larger area that will support the pilot project as well as additional future wells<br />
(from the existing PDA) should the project prove successful. The RDA contains the bitumen<br />
resources required for the initial stages and future phases of SAGD development and totals<br />
1.75 sections of land. The RDA is limited by the south boundary of Crane Lake; it is not<br />
Birchwood's intent to drill the horizontal section of the wells under the lake as part of this<br />
proposal. The RDA includes Section 02-064-04W4M & SE 03-064-04W4M (see Figure 1.1-1).<br />
Birchwood has identified the locations and trajectories of the first well phase which will include<br />
10 horizontal well pairs. The design provides an additional 24-26 well pairs utilizing the existing<br />
PDA.<br />
1.6 <strong>Project</strong> Overview<br />
This application is seeking approval to construct, operate and reclaim the <strong>Sage</strong> Commercial<br />
Demonstration <strong>Pilot</strong> <strong>Project</strong>, a crude bitumen recovery scheme that will utilize steam assisted<br />
gravity drainage (“SAGD”) technology to produce bitumen at a rate of 795m3 (5,000 barrels) per<br />
day. The life of the 10 well pair pilot project is 5 years. Total Original Oil In Place (“OOIP”) in the<br />
Clearwater Formation is estimated at 24,037 e3m3 (151MM barrels). Recoverable crude<br />
bitumen using SAGD recovery is estimated to be up to 65% of OOIP. The combined facility, well<br />
pad design and layout has incorporated the potential for up to 36 well pairs to be drilled from the<br />
facility/well pad proposed herein, If the project proves to be successful, the life of the project<br />
would be extended to at least 15 years.<br />
Birchwood has designed an operation that reduces environmental impacts, and has taken<br />
additional steps to design the most efficient facility possible, including significant attention to<br />
noise and odor concerns, brackish makeup water, high produced water recycle and ground<br />
water protection. Production and recovery using in-Situ SAGD technologies without using fresh<br />
water enhances oil sands sustainability. The information gathered from the pilot will allow an<br />
efficient and controlled development of the provincial resource and facilitate continuous<br />
improvement at <strong>Sage</strong>.<br />
Under steady state operation the plant is designed to process 3140m 3 of water/day and<br />
315m 3 /day of waste water disposal capacity will be required. Brackish source water for steam<br />
generation will be obtained from the McMurray formation, pumped to and treated at the CPF.<br />
Steam will be sent from the plant via above ground pipeline to each of the wells for injection into<br />
the individual well pairs. Produced water will be treated and re-used. An initial volume of up to<br />
50,000 m 3 fresh water will be required for project start-up and 5m 3 /day will be required for the<br />
duration of the project, in order to service utility requirements. Produced water will be recycled<br />
at a rate greater than 90% and spent saline water will be disposed of in deep formation disposal<br />
wells located on the pad.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 12
The facilities Birchwood is proposing for the SAGE <strong>Project</strong> include a common well and central<br />
processing facility pad and associated infrastructure such as well pairs, roads, above ground<br />
gathering and distribution systems and power lines. A plot plan showing the proposed facility<br />
and well pad details is available in Figure 7.1.1. The project attempts to avoid native vegetation<br />
to the extent feasible. The project footprint disproportionately (61%) comprises previously<br />
disturbed land. The <strong>Project</strong> footprint will directly affect 18.6 ha of land of which 11.3 ha (61%)<br />
was previously impacted by land clearing.<br />
1.7 <strong>Project</strong> Facilities<br />
Produced fluids (bitumen, water, solution gas) are also transported via above ground pipes from<br />
the wells to the CPF. Produced gas will be burned in the steam generators. Bitumen will be<br />
blended with diluent and shipped off site via an underground sales oil pipeline. Produced water<br />
will de-oiled and treated for re-use as boiler feed make up water.<br />
The project includes installation the following:<br />
1 multi well pad location with 10 initial horizontal well pairs drilled for demonstration<br />
purposes (36 well pairs possible form pad);<br />
A modular Central Processing Facility (CPF) adjacent to the well pad, including brackish<br />
water use for steam generation and produced water recycling technology;<br />
Connection of well infrastructure to the CPF with above ground pipelines, and power<br />
distribution lines;<br />
A fuel gas line tied into a nearby existing Altagas pipeline;<br />
An underground source water pipeline tied into source water wells located in the<br />
development area;<br />
An underground water disposal pipeline tied into CPF and water disposal wells.<br />
The various components of the <strong>Project</strong> are listed in Table1.7-1<br />
Table 1.7-1 Summary of <strong>Project</strong> Components<br />
<strong>Project</strong> Component Area (ha)<br />
Central Processing Facility and well pad (10 well pairs) 18.6<br />
Access Road In place<br />
Soil Storage Adjacent to CPF and well pad<br />
Pipeline Corridor In place<br />
Surface Water Run off Retention Pond On central pad<br />
Source Water wells On central pad<br />
Disposal Water Well(s) On central pad<br />
Groundwater Monitoring Wells CPF and pad perimeter<br />
TOTAL 18.6<br />
1.7.1 Minimization of Land Disturbance<br />
The project attempts to avoid native vegetation to the extent feasible. The project footprint<br />
disproportionately (61%) comprises previously disturbed land. The <strong>Project</strong> footprint will directly<br />
affect 18.6 ha of land of which 11.3 ha (61%) was previously significantly impacted by land<br />
clearing.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 13
Existing infrastructure, including the access road and the well site at 03-02-064-04W4M<br />
constructed in 2011, will be utilized in order to eliminate clearing for roads for the proposed 10<br />
well pairs and CPF. Should the pilot project prove successful, an additional 24 – 26 well pairs<br />
may be developed from the same pad.<br />
Other existing infrastructure in the area consists of:<br />
A diluent line running adjacent to the east boundary of the PDA from the Husky terminal<br />
at 04-26-063-04W4 to 12-28-064-04W4M<br />
A crude oil sales pipeline running adjacent to the east boundary of the proposed PDA<br />
from the Husky Tucker SAGD project at 12-28-064-04W4M to 04-26-063-04W4<br />
Primary Highways # 28 from Bonnyville and # 55 from Cold Lake<br />
Secondary Highway # 892 through the property to Birchwood's existing LOC<br />
A fuel gas supply line owned by Altagas is located in 03-12-64-04W4M to the NE of the<br />
PDA.<br />
This infrastructure is presented in Figure 1.5-1.<br />
1.8 <strong>Project</strong> Development Schedule<br />
Table 1.8-1 Development Schedule Pending Regulatory Approval<br />
Geological Evaluation &<br />
Development plan<br />
Public Consultation & Community<br />
Relations<br />
Environmental Baseline<br />
Assessments<br />
ASRD & ERCB Consultation –<br />
Regulatory input integration<br />
Community Open House – Public<br />
input integration<br />
<strong>Pilot</strong> <strong>Project</strong> Submission<br />
Regulatory Process/ Decision<br />
Off-site Modular Facility<br />
Construction<br />
Field Construction and Drilling<br />
Initial Steam Circulation<br />
SAGD Production<br />
Phase II Development Plan<br />
Decommissioning & reclamation<br />
2011 2012 2013 2014 2015 2016<br />
+<br />
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 14
1.9 Regional Setting<br />
The proposed project site is located on Crown land designated for agricultural purposes within<br />
the Dry Mixed Wood Sub-Region of the Lower Boreal Region in northern Alberta. The area is<br />
characterized by undulating plains with aspen dominated forests and fens, with some areas<br />
suitable for cultivation and/or grazing. There are numerous lakes and low lying water bodies in<br />
the area. The proposed facility and well pad are situated primarily on land that is currently<br />
cleared and used for cattle grazing. The lease area lies within the Cold Lake Beaver River<br />
Basin. Surface water bodies within 2 km of the proposed pad include Crane Lake 750 meters<br />
north of the facility, an un-named slough in section 1 and un-named slough approximately 300m<br />
south east of the lease.<br />
There are several offsetting thermal oilsands producers in the immediate area including Imperial<br />
Resource’s Cold Lake CSS Operations, Husky’s Tucker Lake <strong>Thermal</strong> SAGD and Shell’s<br />
SAGD, CNRL Primrose CSS and Wolf Lake SAGD, and the recently approved OSUM Taiga<br />
SAGD & CSS project (see Figure 1.1-2 and Figure 1.1-3).<br />
Substantial infrastructure is already in place to service the existing thermal in-situ operations<br />
and the majority of the required infrastructure passes through Birchwood’s lease or is<br />
immediately adjoining the <strong>Sage</strong> pilot site.<br />
1.10 Environment, Health and Safety Program<br />
Birchwood has formally documented EH&S programs that have been implemented to assist with<br />
managing the health and safety of our employees, contractors, the general public and residents,<br />
as well as manage environmental protection and stewardship, within our development areas:<br />
Health & Safety Management Program<br />
Environmental Protection and Management Program<br />
Corporate Emergency Response Program<br />
Quality Control Management Program<br />
Conservation and Reclamation Plan<br />
Additional management programs that will enhance the above and are being developed for<br />
approval are:<br />
Fire Protection and Response Program<br />
Site Specific Emergency Response Program<br />
Site Specific Safety Program (to address specific hazards, training and procedures required<br />
to operate a SAGD facility safely)<br />
Groundwater Monitoring Program<br />
Details of Birchwood's safety program and how it will be integrated into the proposed pilot<br />
project can be found in Section 7.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 15
T64<br />
T63<br />
Figure 1.1-1 Birchwood <strong>Sage</strong> <strong>Project</strong> Map<br />
Wells<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
17<br />
<strong>Project</strong> Wells<br />
Land Layer<br />
28<br />
21<br />
16<br />
33<br />
28<br />
21<br />
16<br />
Birchwood Lease Area<br />
Development Area<br />
9<br />
4<br />
R4 R3W4<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
27<br />
22<br />
15<br />
26<br />
23<br />
14<br />
11<br />
2<br />
35<br />
26<br />
23<br />
14<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 16<br />
25<br />
24<br />
13<br />
12<br />
1<br />
36<br />
25<br />
24<br />
13<br />
30<br />
19<br />
18<br />
7<br />
6<br />
31<br />
30<br />
19<br />
18<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
17<br />
T64<br />
T63<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Birchwood Development Area<br />
By : Jerry Babiuk, P.Geol Date : 2012/06/01<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake<br />
Figure 4.1
T68<br />
T67<br />
T66<br />
T65<br />
T64<br />
T63<br />
Land Layer<br />
Boundaries<br />
T62<br />
T61<br />
T60<br />
Upper Mann Lake<br />
Upper Mann Lake<br />
T59<br />
T58<br />
Upper Mann Lake<br />
Upper Mann Lake<br />
Upper Mann Upper Lake Mann Lake<br />
Upper Mann Lake<br />
Upper Upper Mann Mann Lake Lake<br />
Figure 1.1-2 Birchwood <strong>Sage</strong> Regional <strong>Project</strong> Map<br />
R10 R9 R8 R7 R6 R5 R4 R3 R2 R1W4<br />
Helina Area<br />
BONNYVILLE NO. 87<br />
Birchwood Lease Area<br />
Development Area<br />
Provincial Boundary<br />
State Boundary<br />
Map Boundary<br />
Heritage Rangeland<br />
Recreation Area<br />
Wilderness Area<br />
Wildland<br />
Provincial Parks<br />
State Parks<br />
National Parks<br />
Military Bases<br />
Native Reserves<br />
Cities<br />
Towns<br />
Villages<br />
Rural Municipalities<br />
Counties<br />
28A<br />
HORSESHOE HORSESHOE BAY BAY<br />
Active <strong>Thermal</strong> <strong>Project</strong>s<br />
CNRL Oil Sands Rights_01_01<br />
Husky Oil Sands Rights_01<br />
Imperial Resources_01<br />
Pengrowth Energy<br />
Shell Canada<br />
55<br />
GLENDON<br />
ST. PAUL COUNTY NO. 19<br />
Cold Lake Air Weapons Range<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake<br />
Wolf Lake<br />
55<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake<br />
28A<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake Islands<br />
Moose Lake Islands<br />
Moose Lake<br />
Moose Lake Islands<br />
Moose Lake<br />
Moose Lake Islands<br />
Moose Lake Islands<br />
Moose Lake Islands<br />
Moose Lake<br />
Moose Lake<br />
Moose Lake<br />
Devon SAGD<br />
Walleye<br />
PELICAN PELICAN NARROWS<br />
NARROWS<br />
BONNYVILLE BONNYVILLE BEACH BEACH<br />
KEHIWIN 123<br />
28<br />
Kehewin<br />
CNRL SAGD<br />
Wolf Lake<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 17<br />
41<br />
28 BONNYVILLE<br />
CNRL CSS<br />
Primrose<br />
Husky SAGD<br />
Tucker Lake<br />
Muriel Lake<br />
Pengrowth SAGD<br />
Lindberg<br />
Tucker Lake<br />
Crane Lake<br />
Shell SAGD<br />
Orion<br />
SAGE PROJECT<br />
Muriel Lake<br />
Doris Island<br />
Moore Lake<br />
Imperial Cold Lake<br />
CSS project<br />
Cold Lake Air Weapons Range<br />
Marie Lake<br />
Marie Lake<br />
Cold Lake<br />
First Nation<br />
COLD LAKE 149<br />
55<br />
CFB Cold Lake<br />
Cold Lake North Shore<br />
Cold Lake North Shore<br />
Cold Lake<br />
First Nation<br />
COLD LAKE 149B<br />
COLD LAKE<br />
28<br />
Cold Lake<br />
GRAND CENTRE<br />
OSUM SAGD<br />
TAIGA<br />
COLD LAKE 149A<br />
Cold Lake<br />
Cold Lake<br />
Cold Lake<br />
R10 R9 R8 R7 R6 R5 R4 R3 R2 R1W4<br />
Planned <strong>Thermal</strong> <strong>Project</strong>s<br />
Osum Oils Sands<br />
Hydrography<br />
Major<br />
Transportation<br />
Wells<br />
Primary Roads<br />
<strong>Project</strong> Wells<br />
Kilometres<br />
0 10 20 30<br />
0 10 20<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
Cold Lake<br />
Cold Lake<br />
Cold Lake<br />
Cold Lake<br />
Cold Lake<br />
Cold Lake<br />
Cold Lake<br />
COLD LAKE 149C<br />
Cold Lake<br />
T68<br />
T67<br />
T66<br />
T65<br />
T64<br />
T63<br />
T62<br />
T61<br />
T60<br />
T59<br />
T58<br />
Regional Map<br />
Active/Planned Oil Sands <strong>Project</strong>s<br />
By : Jerry Babiuk, P.Geol Date : 2012/12/04<br />
Scale = 1:515000 <strong>Project</strong> : Cold Lake
Figure 1.2-1 Regional Map<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 18
Figure 1.2-2 Regional Satellite image<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 19
Figure 1.2-3 Local Aerial Image<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 20
Figure 1.5-1 <strong>Project</strong> Aerial Photo Mosaic<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 21
Figure 1.5-2 Aerial Photo Showing Existing Development and <strong>Pilot</strong> Site<br />
Photo taken September 24, 2012 looking East<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 22
2 Economics & Land Use<br />
2.1 Economics<br />
2.1.1 Capital and Operating Costs<br />
Initial capital investment for this project is estimated to be $230 million including $75 million for<br />
drilling, completing and well tie in, $155 million for surface facilities, equipment and<br />
infrastructure. The proposed development will contribute to the fiscal health of local, regional,<br />
provincial and federal benefits through increased contributions to their tax bases and short and<br />
long term job creation in addition to delivering royalties to the Government of Alberta. The<br />
facilities will be fabricated in Airdrie Alberta using Alberta labor capacity.<br />
Operating costs are projected to be $30 million annually, approximately one third of the annual<br />
operating costs are expected to be spent locally.<br />
2.1.2 Taxes and Crown Royalty<br />
Effective March 31, 2012, independent estimates of royalties payable to the Government of<br />
Alberta for the Birchwood Lease using SAGD recovery range from a low of $500 million to a<br />
high estimate of $1.4 billion over a thirty year period. It should be noted that these estimates are<br />
highly dependent on several factors including oil prices and are, therefore subject to uncertainty<br />
and may change.<br />
Corporate Federal and Provincial income taxes will vary substantially, especially during the<br />
early years. Income taxes are estimates at approximately 15-20% of taxable income over the<br />
life of the project.<br />
Property taxes payable to MD of Bonnyville are estimated to be up to $1.7 million annually. Over<br />
a 30 year life the project may generate $110 Million in taxes for benefit of MD of Bonnyville and<br />
its residents.<br />
2.1.3 Benefit Cost Analysis<br />
A benefit cost analysis of the proposed project quantifies the creation of resources by the<br />
project, and by comparing them, determines whether the benefits outweigh the costs.<br />
The benefit of the project is represented by the projects outputs including bitumen produced<br />
over the life of the project and its contribution to the local, provincial and federal economy.<br />
The public cost associated with the project is expected to be minimal because impacts on<br />
municipal and provincial infrastructure and services are expected to be small or non-existent.<br />
The area has a substantial infrastructure created by nearly 30 years of offsetting in-situ<br />
development. From a fiscal point of view these costs (if any) can be compared to the much<br />
greater benefits derived including employment creation, use of local goods and services, and to<br />
the municipal property taxes, school taxes, income taxes and royalties payable to the Alberta<br />
Government generated by the project.<br />
2.1.4 Marketing Arrangements<br />
Produced bitumen will be blended with diluents supplied by Husky Oil at the CPF. The product<br />
will be shipped via underground pipeline to the Husky terminal at 04-26-063-04W4M. Birchwood<br />
is negotiating a sales arrangement with Husky Oil to purchase the resulting product.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 23
2.1.5 Commercial Viability<br />
SAGD technology is an accepted commercially viable form of bitumen extraction. Improvements<br />
in drilling allowing longer wells and Improvements in water treating technology and modular<br />
construction have reduced costs and the minimum size of commercial projects to below<br />
10,000bopd. SAGD has lower operating temperatures and pressures compared to CSS and<br />
therefore longer equipment and well lives. Birchwood has conducted an economic evaluation of<br />
the project which shows it to be commercially viable; these results have been verified with an<br />
independent third party geological engineering and economic evaluation.<br />
2.2 Socio-Economics<br />
2.2.1 Employment and Procurement<br />
The project will provide direct economic benefits to the local and First Nations populations of<br />
Bonnyville and Cold Lake through long term job creation and through sourcing of equipment,<br />
labour and related services and logistics from local business. Modular surface facility<br />
construction will be completed by an existing fabricator located in Airdrie, Alberta. It is estimated<br />
that job creation during the construction and operational phases of the proposed project,<br />
including plant construction, surface facility installation, drilling and well servicing, and plant<br />
operations will result in 490 man years of employment over 30 years.<br />
The construction phase of the project which will include lease development, facility construction<br />
and drilling will employ approximately 50 people over 6 month period. Facility operations will<br />
employ approximately 40 people over the life of the project. Types of employment will be varied<br />
and include drilling and service rig personnel, completions engineers, construction supervisor<br />
and associated crews, facility managers (steam, water, safety and environment, maintenance),<br />
shift foremen, central room operators, office staff, operations personnel, technical specialists<br />
(welders, pipefitters), general labour, security personnel and monitoring staff.<br />
Employment positions that will be sourced from available personnel in the Municipality of<br />
Bonnyville are as follows:<br />
Table 2.2.1-1 Employment Positions<br />
Position # of Positions Estimated Duration<br />
Management staff 11 5 years<br />
Administrative staff 6 5 years<br />
Construction Supervisor 2 1 year<br />
Surveyors 2 1 month<br />
Welders 2 6 months<br />
Pipefitters 8 2 months<br />
Drilling Rig Personnel 24 6 months<br />
Service Rig Personnel 16 3 months<br />
General Labour 30 5 years<br />
Heavy Equipment Operators 10 3 months<br />
Plant technicians 18 5 years<br />
Well Operators 6 5 years<br />
Turnaround specialists 10 5 years<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 24
The above positions may require sourcing from other areas of Alberta and Canada if there is not<br />
a sufficient pool of labour to meet technical and safety specific position requirements. There is<br />
considerable activity in the Cold Lake and Lloydminster areas and Birchwood intends to follow a<br />
project timeline such that Cold Lake hospitality services are capable of overnight housing of<br />
workers.<br />
2.3 Traffic and Access<br />
The existing infrastructure shown in Figure 2.3-1 will facilitate movement of construction and<br />
operations personnel during the various phases of the project. Hwy #28 and #41 from<br />
Bonnyville to Hwy #55 and Hwy # 55 from Cold Lake provide access to Secondary Hwy #892<br />
which link Birchwood’s existing road (LOC 112372), to the location of the facility/well pad. These<br />
routes will provide access for the transport of personnel for construction as well as equipment,<br />
and provide ongoing access for operations activities. There is no water crossings associated<br />
with these access routes that require construction.<br />
The placement of the pilot project has been selected in order to limit surface disturbance by<br />
taking advantage of existing industrial infrastructure including highway 892 which is the primary<br />
access to Imperial Resource’s Cold Lake CSS Operations, Husky’s Tucker Lake <strong>Thermal</strong> SAGD<br />
and Shell’s SAGD projects. Considering the significantly smaller size of the operation compared<br />
to the already existing development it is unlikely to cause any noticeable changes to traffic<br />
volumes or road usage.<br />
Transportation of the modular facilities for the CPF will utilize a route Highway 36 from Airdrie to<br />
Highway 28. During construction, oversized loads will be utilized to transport equipment and<br />
structures to the well pad and CPF. Communication with other industrial users, utilities and the<br />
municipality will be undertaken to ensure that the loads can be transported safely and minimize<br />
road burdens.<br />
2.4 Integration with Other Land Uses<br />
Land use documents relevant to the project are:<br />
1. Lower Athabasca Regional Plan (2012) (“LARP”),<br />
The proposed development is located in the southern area of the Lower Athabasca Regional<br />
Plan; the plan, broadly, prescribes the overall activities that occur and are acceptable within the<br />
region, specifies limits on land use to preserve habitat and biodiversity, specifies air, surface<br />
water and groundwater management targets and provides strategic direction for the region in<br />
order to achieve balanced growth objectives.<br />
2. Cold Lake Sub Regional Integrated Resource Plan (1996) (“CL SRIRP”),<br />
The proposed development is within the Nine Lakes Resources Management Area of the CL<br />
SRIRP. Activities proposed in this application have integrated the management strategies and<br />
guidelines presented in that Plan. Orderly development of oil and gas resources is a key<br />
requirement for the plan. The objectives identified specifically highlight development which will<br />
assist in exploiting oilsands reserves in concurrence with protection of other resources and<br />
activities, which are consistent with this project.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 25
3. Crane Lake Area Structure Plan (2006) (“CLASP”)<br />
The focus of CLASP is predominately protection of the recreational aspects of Crane Lake and<br />
shoreline ecosystem protection and development.<br />
4. Recovery Strategy for The Woodland Caribou, Boreal Population, in Canada, (EC 2012)<br />
The federal government's Caribou recovery strategy provides a comprehensive program and<br />
strategic direction for re-establishing the species at risk in the boreal forests of northern<br />
Canada. Range plans and action plans have not yet been developed or implemented; however<br />
the location of Birchwood's proposed facility should not have a direct effect on the recovery<br />
strategy.<br />
2.4.1 Timber/Forestry<br />
The RDA area contains both private and public lands. The PDA considered in this application<br />
lies wholly within Public lands and it is designated as “white” in the CL SRIRP, as the available<br />
timber for harvesting in the RDA is minimal. The Conservation and Reclamation Plan will<br />
address various components required to maintain the sustainability of the land for grazing and<br />
re-establishment of forest cover.<br />
2.4.2 Recreational Uses<br />
There is recreational activity on Crane Lake to the northwest and west of the proposed RDA.<br />
The proposed setbacks (approximately 2km from existing residents and campgrounds and<br />
750m from Crane Lake) will prevent interference with recreational activities.<br />
Access and egress from the well pads and CPF will be restricted and monitored by camera in<br />
order to ensure residents and visitors, as well as staff, safety.<br />
2.4.3 Agriculture<br />
Grazing is the primary land use in the proposed RDA. Crop cultivation is not currently<br />
undertaken as a result of poor quality soils. The Conservation and Reclamation Plan addresses<br />
requirements for landscape, soil, and water management in order to return the land to<br />
equivalent land capacity in and use with respect to grazing and potential for using disturbed<br />
lands within the RDA for cultivation purposes. The proposed PDA will be on land that is<br />
currently utilized for cattle grazing.<br />
The project development area lies within Grazing Lease GRL#40375. Birchwood has been in<br />
consultation with the grazing lease holder since April of 2011 and has received consent for the<br />
proposed development.<br />
2.4.4 Trapping<br />
The project development area lies within Registered Fur Management Area TPA#1473.<br />
Birchwood has been in consultation with the trapper since April of 2011 and has not received<br />
any objections or concerns for the proposed development.<br />
2.4.5 Petroleum and Natural Gas Rights<br />
Imperial Oil holds the PNG mineral rights in the RDA. A Map of Natural Gas lease holders is<br />
presented in Figure 2.4.5<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 26
2.4.6 Oilsands Rights<br />
Birchwood owns the mineral lease for oilsands in the mannville group. A map of oilsands lease<br />
holders is presented in Figure 2.4.6<br />
2.4.7 Ecological Resources<br />
A review of various public information databases and third party studies has not identified any<br />
significant ecological resources in the RDA. Additional plant and animal inventories of the RDA<br />
will provide the baseline for protection of existing ecological resources that may be affected by<br />
the development and are incorporated into the Conservation and Reclamation Plan.<br />
2.4.8 Wildlife<br />
The resource development area supports a variety of mammals, birds and a small number of<br />
amphibians/reptiles as is noted in the Wildlife Assessment (see Section 8 and Consultant<br />
Report 4 - Vegetation and Wildlife). The RDA is outside any designated "Key Diversity and<br />
Wildlife Zones" as designated by ESRD. Specific surveys to verify species at risk occurrence<br />
and the status and abundance of management species of concern will be completed during<br />
winter and spring of 2013.<br />
The project footprint occurs primarily on an existing cleared area and does not affect any natural<br />
movement corridors. Effects on regional movement will be negligible because of the small<br />
project footprint and avoidance of large blocks of native habitat.<br />
2.4.9 Vegetation<br />
The predominant ecosite phase on the PDA is comprised of pasture; open grassland and open<br />
grassland with shrubby regeneration. The remaining land is comprised of a variety of forest<br />
covered land and oil and gas infrastructure (pipelines and wells. The project attempts to avoid<br />
native vegetation to the extent feasible. The <strong>Project</strong> footprint will directly affect 18.6 ha of land of<br />
which 11.3 ha (61%) was previously impacted by existing land clearing.<br />
The project footprint area was searched for rare plants and rare plant communities from August<br />
13 to August 15, 2012. No rare plants species were found at the time of the survey. An<br />
additional survey will be undertaken to capture early blooming plants and this work will be<br />
undertaken in June 2013.<br />
2.4.10 Historical Resources<br />
There are a number of initiatives that have been undertaken to determine the existing historical<br />
resources with the proposed RDA and specifically to the PDA.<br />
In the fall of 2011, Birchwood conducted a study with the Cold Lake First Nations Traditional<br />
Land Use prior to the construction and development of the surface lease areas and access for<br />
drilling of the cold production wells. The study included recommendations for development and<br />
preferred solutions for potential issues. Figure 2.4.10A – Figure 2.4.10D present a review of the<br />
historical development of the project area.<br />
The proposed well and Central Processing Facility pad lies outside the 400 m buffer zone<br />
identified by the CLSIRP as having potential historical resources. In addition, the Alberta<br />
conservation Information Management System database indicated that the RDA has low<br />
potential for historical resources.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 27
2.4.11 Wetlands<br />
Wetland complexes within the RDA and PDA were classified according to the Alberta Wetland<br />
Inventory Standards, see Figure 2.3.11. The area selected for the well pad and CPF exceed the<br />
minimum setback criteria that any wetland areas were outside the 100m buffer and primary<br />
lakes outside the 300m buffer zone for wetland protection.<br />
2.4.12 Surface ownership<br />
Surface ownership is presented in Figure 2.4.12.<br />
2.5 Participation in Regional and Research Initiatives<br />
Birchwood has established membership in various regional associations, including the Lakeland<br />
Industry and Community Association (“LICA”), the Alberta Lake Management Society, in order<br />
to facilitate the integration of their work into the project design monitoring systems. It is<br />
Birchwood’s intent to actively participate in the various monitoring programs and incorporate its<br />
data with these groups.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 28
Figure 2.3-1 Access Sketch<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 29
T64<br />
Land Layer<br />
Wells<br />
PNG Rights<br />
T63<br />
Figure 2.4.5 PNG Lease Holders Map<br />
IP<br />
RS<br />
RS<br />
WS WS IP IP S<br />
Birchwood Lease Area<br />
<strong>Project</strong> Wells<br />
CNRL<br />
Freehold Land<br />
Frehold Resources<br />
EOG Rsrcs<br />
Crescnt Pnt & Conserve<br />
Devon Canada<br />
Conserve O&G & Waymar<br />
CNRL Lands<br />
Husky Lands<br />
Open PN&G Lands<br />
Imperial Lands<br />
Shell Lands<br />
Pipelines & Facilities<br />
Crude Oil<br />
Oil Well Effluent<br />
Natural Gas<br />
Sour Gas<br />
Fuel Gas<br />
Misc Gases<br />
Fresh Water<br />
Salt Water<br />
HVP Products<br />
LVP Products<br />
Misc Liquids<br />
S<br />
R4 R3 R2W4<br />
S<br />
S<br />
S<br />
S<br />
PS LR TF TL TL<br />
SS<br />
WP CT<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
IP<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S S<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 30<br />
S<br />
IP S<br />
S S<br />
R4 R3 R2W4<br />
Kilometres<br />
0 1 2 3 4 5 6<br />
0 1 2 3 4<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
S<br />
S<br />
S<br />
S<br />
S<br />
IP S<br />
IP S<br />
WS IP SS<br />
S<br />
S<br />
S<br />
WP S<br />
MS PS PS PS IP IP<br />
SS<br />
S<br />
S<br />
S<br />
S<br />
S<br />
IP<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
MS CS<br />
S<br />
MS<br />
IP<br />
S<br />
RS<br />
S<br />
S<br />
WS<br />
S<br />
S<br />
IP<br />
MS CS GS<br />
RS<br />
MS CS GS<br />
Regional Map<br />
Held PN&G Rights<br />
MS GS GS CS<br />
T64<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/12/05<br />
Scale = 1:103000 <strong>Project</strong> : Cold Lake
T64<br />
Land Layer<br />
Wells<br />
Figure 2.4.6 Oilsands Lease Holders Map<br />
IP<br />
RS<br />
RS<br />
WS WS IP IP S<br />
Birchwood Lease Area<br />
<strong>Project</strong> Wells<br />
Oil Sands Rights<br />
T63<br />
Open Rights<br />
Freehold Land<br />
Keppoch Energy<br />
Pengrowth Energy<br />
CNRL Oil Sands Rights<br />
Husky Oil Sands Rights<br />
Imperial Resources<br />
Osum Oils Sands<br />
Shell Canada<br />
Pipelines & Facilities<br />
Crude Oil<br />
Oil Well Effluent<br />
Natural Gas<br />
Sour Gas<br />
Fuel Gas<br />
Misc Gases<br />
Fresh Water<br />
Salt Water<br />
HVP Products<br />
LVP Products<br />
Misc Liquids<br />
S<br />
R4 R3 R2W4<br />
S<br />
S<br />
S<br />
S<br />
PS LR TF TL TL<br />
SS<br />
WP CT<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
IP<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S S<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 31<br />
S<br />
IP S<br />
S S<br />
R4 R3 R2W4<br />
Kilometres<br />
0 1 2 3 4 5 6<br />
0 1 2 3 4<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
S<br />
S<br />
S<br />
S<br />
S<br />
IP S<br />
IP S<br />
WS IP SS<br />
S<br />
S<br />
S<br />
WP S<br />
MS PS PS PS IP IP<br />
SS<br />
S<br />
S<br />
S<br />
S<br />
S<br />
IP<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
S<br />
MS CS<br />
S<br />
MS<br />
IP<br />
S<br />
RS<br />
S<br />
S<br />
WS<br />
S<br />
S<br />
IP<br />
GS MS CS<br />
RS<br />
MS GS CS<br />
Regional Map<br />
Held Oil Sands Rights<br />
MS GS GS CS<br />
T64<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/12/05<br />
Scale = 1:103000 <strong>Project</strong> : Cold Lake
Figure 2.3.10A 1950 - Historical Aerial Photo<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 32
Figure 2.3.10B 1977 - Historical Aerial Photo<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 33
Figure 2.3.10C 1980 - Historical Aerial Photo<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 34
Figure 2.3.10D 1988 - Historical Aerial Photo<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 35
Figure 2.3.11 Wetlands Mapping & Potential Plant Locations<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 36
Figure 2.4.12 Surface Ownership<br />
T64<br />
T63<br />
9<br />
4<br />
33<br />
Land Layer<br />
Crown<br />
Howatt Holdings<br />
M Clements<br />
Development Area<br />
Surface Landowners<br />
Grazing Leases<br />
Crown<br />
Freehold<br />
Crown<br />
R Howatt<br />
D&E Pearson<br />
J&D Healey<br />
10<br />
3<br />
34<br />
R Howatt<br />
R Howatt<br />
C&D Prediger<br />
Crown<br />
R4 R3W4<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 37<br />
Crown<br />
R Howatt<br />
R Howatt<br />
R Howatt<br />
Crown<br />
Kilometres<br />
11<br />
2<br />
35<br />
Crown<br />
J Roux<br />
Lazurko &<br />
Geoffroy<br />
Lazurko &<br />
Geoffroy<br />
Howatt Holdings<br />
0 1 2 3<br />
12<br />
D Berg D Berg D Berg<br />
D Berg<br />
1<br />
J Roux A&D Moon D&J McDaniel<br />
G&B Crawford<br />
G&B Crawford<br />
36<br />
D Berg<br />
K Dodman<br />
Crown<br />
D Berg<br />
Mclean<br />
Guthrie<br />
Moon<br />
D&E Delmarter<br />
Crown<br />
7<br />
6<br />
31<br />
R4 R3W4<br />
0 1 2<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
Crown<br />
Crown<br />
R&C Pemarowski<br />
G&R Felding<br />
G&R Felding<br />
SAGE <strong>Project</strong><br />
Surface Landholders<br />
By : Jerry Babiuk, P.Geol Date : 2012/12/07<br />
Scale = 1:39000 <strong>Project</strong> : Cold Lake<br />
T64<br />
T63
3 Regulatory Approvals<br />
3.1 Existing Approvals<br />
The existing approvals associated with the proposed development area are:<br />
Existing Access Road - LOC # 112372 November 2011<br />
Existing Access Road - LOC # 112288 November 2011<br />
Existing Access Road - LOC # 112371 November 2011<br />
Existing Well Site - MSL #112662 (03-02-064-04W4) November 2011<br />
Existing Well Site - MSL #112568 (01-03-064-04W4) November 2011<br />
Existing Well Site - MSL #112660 (06-02-064-04W4) November 2011<br />
Undeveloped Well Site - MSL #112661 (10-02-064-04W4) November 2011<br />
Birchwood has conducted exploratory drilling in 2011 within the lease. An access road was<br />
constructed and vertical wellbores were drilled to evaluate potential for conventional production of<br />
the bitumen resources on the lease. Well licenses from the ERCB and Surface leases from ESRD<br />
were secured for all the wells drilled on the lease. Birchwood will re-use the following existing ESRD<br />
approvals listed below as part of this application.<br />
Existing Access Road - LOC # 112372 November 2011<br />
Existing Access Road - LOC # 112371 November 2011<br />
Existing Well Site - MSL #112662 (03-02-064-04W4) November 2011<br />
Existing Well Site - MSL #112660 (06-02-064-04W4) November 2011<br />
Birchwood has filed with Alberta ESRD a request for determination if an Environmental Impact<br />
Assessment would be required for the <strong>Sage</strong> <strong>Thermal</strong> <strong>Pilot</strong> <strong>Project</strong>. Birchwood received notice dated<br />
May 22, 2012 from the Designated Director of the Government of Alberta Environment and Water<br />
that pursuant to Section 44 of the Environmental Protection and Enhancement Act (“EPEA”) an<br />
environmental impact assessment is not required for the <strong>Sage</strong> <strong>Thermal</strong> <strong>Pilot</strong> <strong>Project</strong>.<br />
The Canadian Environmental Assessment Agency has issued a letter dated June 15, 2012<br />
indicating that a federal environmental impact assessment was not required for the <strong>Sage</strong> <strong>Thermal</strong><br />
<strong>Pilot</strong> <strong>Project</strong>.<br />
3.2 <strong>Application</strong> for Approval<br />
The approval application package herby submitted is for various types of approvals from the ERCB<br />
and ESRD as follows:<br />
3.2.1 ERCB Approvals Requested<br />
Scheme approval to construct and operate pursuant to Section 10 of the Oil Sands<br />
Conservation Act (“OSCA”), for approval to construct and operate its proposed <strong>Sage</strong><br />
commercial demonstration pilot project (795m 3 or 5,000 bbl/day) from the Cold Lake Oil<br />
Sands Deposit in the Mannville Formation, an oil sands leases located in Townships 64,<br />
Range 4W4M, consisting of a central processing facility adjoining a 10 SAGD well pair pad.<br />
Approval in accordance with ERCB Directive 51 to drill and dispose waste water in the<br />
Granite Wash (Cambrian) Formation, the single well would be located in Section 2 Township<br />
64 Range 4, West of the 4th Meridian.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 38
3.2.2 ESRD Approvals Requested<br />
Approval to construct and operate and reclaim the <strong>Project</strong> facilities to recover and treat<br />
bitumen and processed water, pursuant to Part 2, Division 2 of the Alberta Environmental<br />
Protection and Enhancement Act (“EPEA”);<br />
A Conservation and Reclamation Plan Approval from ESRD under Division 2 of Part 2 and<br />
Part 6 of the EPEA to develop, operate and reclaim components of the <strong>Sage</strong> <strong>Project</strong>; and<br />
Approval pursuant to Part 3, Division 1 of the Water Act, to divert up to 50,000 m 3 of<br />
groundwater from the Muriel Lake Aquifer for initial start-up and up to 25,000 m 3 annually<br />
thereafter, and up to 175,000 m 3 annually of brackish groundwater from the McMurray<br />
Formation for the purpose of oilfield injection (i.e., SAGD). The proposed water source wells,<br />
(one Muriel Lake Formation wells and one McMurray Formation wells), would be located in<br />
Section 2 Township 64 Range 4, West of the 4th Meridian.<br />
Surface water diversion licence to operate a storm water pond. Diversion licences are issued<br />
pursuant to Part 3, Division 1 of the Water Act.<br />
3.4 Additional Approvals Associated With the <strong>Application</strong>.<br />
Separate applications will be filed by Birchwood for other parts of the project that are legislated<br />
under various other statues. <strong>Application</strong> and approvals requirements under Provincial laws<br />
applicable to the project for which separate applications will be filed under separate cover are:<br />
Development permit pursuant to Section 17 of the Municipal Government Act, for the<br />
Municipality of Bonnyville, for the construction and operation of the project and related<br />
infrastructure<br />
Public lands act, for surface rights<br />
Historical Resources Act, for clearance to construct the facilities.<br />
Oil and Gas conservation Act for Well Licenses<br />
Pipelines Act for the construction and operation of pipelines between the central processing<br />
facility and the well pads, water supply wells, water disposal wells, and fuel gas, diluent and<br />
sales pipeline connections.<br />
3.5 ERCB <strong>Application</strong> Checklist<br />
Birchwood is making application under Section 10 of the Oil Sands Conservation Act (“OSCA”) for<br />
approval to construct and operate the <strong>Sage</strong> <strong>Pilot</strong> <strong>Project</strong>. The information provided in this<br />
application is in compliance with the requirements ERCB D-23. Each subsection in the regulation is<br />
cross-referenced to the relevant section in the documentation to facilitate the review process is<br />
found in Appendix 3.5.<br />
3.6 EPEA <strong>Application</strong> Checklist<br />
Birchwood is making application under Part 2, Division 2 of EPEA for approval to construct and<br />
operate the <strong>Sage</strong> <strong>Pilot</strong> <strong>Project</strong>. The information provided in this application is in compliance with the<br />
requirements of Alberta Regulation 113/93. Each subsection in the regulation is cross-referenced to<br />
the relevant section in the documentation to facilitate the review process is found in Appendix 3.6.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 39
Appendix 3.5 ERCB <strong>Application</strong> Checklist<br />
D-23<br />
Reference<br />
Summary Requirement<br />
Location in<br />
<strong>Application</strong><br />
1.5 <strong>Project</strong> Description Section 1.6<br />
1.5.1 Applicable Acts and Sections under which the application is made Section 3.2.1<br />
1.5.2<br />
Name and address of the application and any partners involved and the<br />
details of company incorporation<br />
Section 1.1<br />
1.5.3 Statement of need and project timing Sections 1.4.1, 1.8<br />
1.5.4 Overall project description and discussion of schedule Sections 1.6, 1.8<br />
1.5.5<br />
Description of the regional setting of the development and reference to<br />
existing and proposed land use<br />
Sections 1.9, 2.4<br />
1.5.6<br />
Map indicating the freehold, leasehold, mineral and surface rights of the<br />
proposed scheme and surrounding area and maps showing land use and<br />
landowners<br />
Figure 1.1-2, 2.4.5, 2.4.6<br />
2.4.12<br />
1.5.7 Map showing topography and any development in the project area Figure 2.3.11,1.5-1, 1.5-2<br />
1.5.8 Aerial photomosaic Figure 1.5-1, 1.5-2<br />
1.5.9 Description of storage and transportation facilities including pipelines Sections 7.8.6 7.10.3.3<br />
1.5.10 Proposed rate of production over the life of the <strong>Project</strong> Sections 1.6, 7.1.3<br />
1.5.11 Description of the subject oil sands owned by or leased to the applicant Section 1.2<br />
1.5.12 Status of negotiations N/A<br />
1.5.13 Proposed energy source, alternatives, resource use, sources and supply<br />
Sections 7.1.3,<br />
7.5,7.7,7.10.3.1 7.10.3.2<br />
1.5.14 Description and results of public information program Section 9<br />
1.5.15<br />
The term of the approval sought, including expected project start and<br />
completion dates<br />
Section 1.6<br />
1.5.16 Name of responsible person to contact Section 1.1<br />
2.1 Surface mining operations N/A<br />
2.2 Underground access and development N/A<br />
2.3 In-situ operations -<br />
2.3.1 Geological description of zone of interest Section 4.2.3<br />
2.3.2<br />
Identification by name and depth of the target zone including any crude<br />
bitumen zone or water zone immediately above or below the zone of<br />
interest.<br />
Section 4.2.1.4B, 4.2.3,<br />
4.2.3.2<br />
2.3.3 Criteria used in selecting the oil sands zone for recovery<br />
A description of the cut off bitumen grade and thickness criteria used to<br />
Section 4.2.3.1<br />
2.3.4 establish the in-place resource potential of the project area supported by<br />
reserve estimates and trends<br />
A geological, engineering and economic evaluation of the bitumen reserves<br />
Section 4.2.3.1<br />
2.3.5 recoverable by the proposed scheme and a description of and rationale for<br />
the criteria employed<br />
Section 5.1.1<br />
2.3.6<br />
A geological, engineering and economic evaluation of bitumen reserves not<br />
recoverable by the proposed scheme<br />
Section 5.5.2<br />
2.3.7<br />
A discussion of the potential and requirements for any follow-up recovery of<br />
reserves<br />
Section 5.3.3<br />
2.3.8 Evaluation of gas reserves associated with the oil sands to be developed<br />
Appendix 5.7.B1, 4.2.3.3<br />
5.1.1.1, 7.1.3<br />
2.3.9<br />
An evaluation of sand or fines production, the effects on recovery and<br />
anticipated disposal methods as well as anticipated disposal methods<br />
Section 6.2.4<br />
2.3.10<br />
A description of the recovery process to be used, including (2.3.11- 2.3.20,<br />
as listed below):<br />
Section 5.1.2<br />
2.3.11 The recovery efficiency of the process and well spacing Sections 5.5, 5.5.4<br />
2.3.12<br />
A description of the <strong>Project</strong> layout with emphasis on equipment spacing and<br />
surface disturbance.<br />
Sections 1.7,1.7.1, 7.1<br />
2.3.13<br />
A description of the efforts to minimize land disturbance and the<br />
collection, conservation or other disposition of produced gases<br />
Section 1.7.1, 7.6<br />
2.3.14<br />
A diagram and description of proposed well drilling and completion<br />
Methods<br />
Sections 6.2, 6.3 Figures<br />
6.3.1, 6.3.2<br />
2.3.15 A description of the proposed well performance monitoring program Section 5.4<br />
2.3.16<br />
A description of geotechnical factors and techniques of monitoring, that may<br />
affect operations<br />
Section 5.4.3<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 40
2.3.17<br />
The volume of fluids and solids produced and the proposed disposition of<br />
each<br />
Section 7.2.4 Figure 7.2.2-<br />
A, 7.2.2-B<br />
2.3.18<br />
Material balances for hydrocarbons, sulphur and water in the central<br />
processing facility<br />
Appendix 7.2<br />
Figures 7.2.2, 7.2.1-1<br />
7.2.2-1, 7.2.3-1A,<br />
2.3.19 A process flow diagram for the central processing facility<br />
7.2.3-1B,7.2.3-2 7.3-1,<br />
7.3.1-1, 7.3.2-1 7.3.3-1,<br />
7.4-1, 7.5-1, 7.6-1<br />
2.3.20<br />
A sample set of production accounting reports for the central processing<br />
facility<br />
Section 7.8<br />
2.4.1<br />
A separate description of the bitumen extraction, upgrading, utilities, refining<br />
and sulphur recovery facilities<br />
Section 7.3, N/A, 7.10,<br />
N/A, 7.5.1<br />
2.4.2 Material and energy balances Appendix 7.2 Section 7.7.1<br />
2.4.3 Products, by-products and waste and their disposition Section 7.3, 7.12.2<br />
2.4.4<br />
Surface drainage within the areas of the processing plant, product Storage<br />
and waste treatment and disposal<br />
Section 7.11.6<br />
2.4.5 Comparison of proposed process to alternatives Section 5.1.1<br />
2.4.6 This number has been omitted from D-23 N/A<br />
2.4.7 Example of production accounting reports Section 7.8<br />
2.5.1<br />
A description of any facilities to be provided for the generation of electricity to<br />
be used by the project.<br />
Section 7.10.3.1<br />
2.5.2<br />
Identification of the source, quantity and quality of any fuel, electricity or<br />
steam to be obtained from sources beyond the project site<br />
Section 7.10<br />
2.5.3<br />
An appraisal of the options available to eliminate the need for offsite<br />
resources<br />
Section 7.10.3<br />
2.6.1<br />
A description of air and water pollution control and monitoring facilities, as<br />
well as a liquid spill contingency plan<br />
Section 8.3.2.2, 7.11.5<br />
2.6.2 A description of the water management program<br />
Section 7.2.2, 7.2.3, 7.2.4,<br />
Figure 7.2.2-A<br />
2.6.3<br />
The manner in which surface water drainage within the <strong>Project</strong> area would<br />
be collected, treated and disposed<br />
Section 7.11.6<br />
2.6.4 A description of the air and water pollution control and monitoring facilities Section 8.3.2,7.11<br />
2.6.5 A description of the emission control system<br />
Commercial Viability: An appraisal and projections, on an annual basis of<br />
Section 7.6, 7.11.3, 7.11.4<br />
3.1.1 revenues, capital and operating costs, royalties and taxes, net cash flow,<br />
marketing arrangements, fuel and electric power arrangements<br />
Section 2.1<br />
3.1.2 A description of project costs which include capital and operating cost Section 2.1.1<br />
3.2.1<br />
Benefit-Cost Analysis: A summary of quantifiable public benefits and costs<br />
incurred during the construction and operation of the <strong>Project</strong><br />
Section 2.1.3<br />
3.2.2<br />
A summary of non-quantifiable public benefits and costs incurred each year<br />
during construction and operation of the <strong>Project</strong><br />
Section 2.2<br />
3.3.1<br />
Economic Impact: An appraisal of the economic impact of the <strong>Project</strong> on the<br />
region, province and nation<br />
Section 2.1<br />
3.3.2<br />
A discussion of any initiatives undertaken to accommodate regional<br />
economic priorities and interests<br />
Section 2.2.1, 2.4<br />
3.3.3<br />
An assessment of direct and indirect employment opportunities for all<br />
groups associated with the <strong>Project</strong><br />
Section 2.2.1<br />
4.0 Environmental Impact Assessment Section 3.1<br />
5.0 Biophysical Impact Assessment Section 8<br />
6.0 Social Impact Assessment Section 2.2<br />
7.0<br />
Describe the environmental protection plan including mitigation measures,<br />
environmental monitoring and research<br />
Section 8.10, 8.10.7<br />
8.0 Conceptual Development and Reclamation Plan CR 7<br />
9.0 Solid Waste Management Plan<br />
Section 7.12<br />
Appendix 7.3<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 41
Appendix 3.6 EPEA <strong>Application</strong> Checklist<br />
EPEA<br />
Guide<br />
Summary Requirement<br />
Location in<br />
<strong>Application</strong><br />
1 Applicant Identification -<br />
1.1<br />
1.2<br />
1.3<br />
1.4<br />
2<br />
2.1<br />
Applicant’s Name<br />
Mailing address<br />
Mailing address of the plant or facility / regional office<br />
Contact information<br />
Plant or Facility Identification<br />
Description of plant or facility activities<br />
Section 1.0<br />
Section 1.1<br />
Section 1.1<br />
Section 1.1<br />
-<br />
Section 1.6, 7.1<br />
2.2 Plant or facility location Section 1.5<br />
2.3 Plant or facility location map<br />
Figure 1.1-1, 1.2-1, 1.2-2,<br />
1.5-1, 1.5-2<br />
2.4 Area potentially affected by the plant or facility Section 8 Figure 1.2-3<br />
3 <strong>Project</strong> Background Section 1.2<br />
3.1 Government approved regional initiatives in the affected area Section 1.9<br />
3.2 Hearing results or decisions N/A<br />
3.3 Environmental Impact Assessment report for Hearing N/A<br />
3.4 Authorizations related to the <strong>Project</strong> Section 3.1<br />
3.5 Related EPEA applications for other plants N/A<br />
3.6 Financial Security N/A<br />
3.7 Proposed timelines Section 1.8<br />
3.8 Public consultation process Section 9<br />
4 Current State of the Environment -<br />
4.1<br />
Local and regional landscape features, drainage and surface watercourses,<br />
and groundwater<br />
Figure 2.3.11<br />
Section 8.5, CR1<br />
4.2 Ambient air quality Section 8.3.2, CR2<br />
4.3 Baseline soil and vegetation Section 8.6, 8.7 CR4, CR5<br />
4.4 Previous development and disturbance<br />
Section 1.7.1<br />
Figure 1.5-2<br />
4.5 Baseline wildlife and wildlife habitat Section 8.8 CR4<br />
4.6 Baseline watercourses Section 8.5.1 CR1<br />
4.7<br />
Current properties and suitability of the receiving soil properties for<br />
irrigation/land application<br />
Section 8.6.3<br />
4.8 Restrictions to irrigation or land application of waste in the area N/A<br />
4.9 Maps and diagrams of the local and regional environment<br />
Figure 1.1-2, 1.2-1,<br />
1.2-2. 1.2-3<br />
4.10 Government regional initiatives obligations Section 2.4, 8.10<br />
5 <strong>Project</strong> Design -<br />
5.1 Process overview, major equipment and mass balances<br />
Section 7.1 Appendix 7.1,<br />
7.2<br />
5.2 Substances generated Appendix 7.3<br />
5.3 Options examined to optimize efficiency Section 7.10.3.1<br />
5.4 Footprint minimization Section 1.7.1<br />
5.5 Plot plan Figure 7.1.1<br />
5.6<br />
Materials storage, waste management, tanks, and runoff/wastewater<br />
management system<br />
Section 7.1 – 7.9, 7.3.3,<br />
7.11.6, 7.12<br />
Appendix 7.3 CR7<br />
5.7 Monitoring and performance evaluation of collection and storage N/A<br />
5.8 Wastewater and runoff treatment and control Section 7.11.6<br />
5.9 Suitability and capacity of treatment and release control systems N/A<br />
5.10 Location of proposed treatment facility and disposal Figures 7.1.1<br />
5.11 Monitoring and performance evaluation of wastewater treatment and disposal Section 7.8<br />
5.12 Monitoring and evaluation of treated wastewater release rates N/A<br />
5.13 Ambient monitoring of released treated wastewater N/A<br />
5.14 Data and models of released wastewater and disposal methods Section 4.2.1.4A<br />
5.15 Air emissions Section 7.11.3, CR2<br />
5.16 Air emissions streams Table 8.3.2-3<br />
5.17 Environmental control systems Section 7.11<br />
5.18 Emission source Table 8.3.2-3<br />
5.19 Flare pits N/A<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 42
5.20 Fugitive emissions Section 8.3.2.1<br />
5.21 Significant area or non-point emissions -<br />
5.22 Dispersion modelling Tables 8.3.2-1, 8.3.2-2<br />
5.23 Dispersion modelling diagrams Figures 8.3.2-1, 8.3.2-2<br />
5.24<br />
Proposed monitoring and performance evaluation of treatment and control<br />
Section 7.8<br />
equipment<br />
5.25 Proposed monitoring and evaluation of ambient air quality Section 8.3.2.2, 8.10.1<br />
5.26 Air emissions data, calculations and models Section 8.3.2 CR2<br />
6 Construction -<br />
6.1 Construction schedule Section 1.8<br />
6.2 Construction site map and sensitive areas N/A<br />
6.3 Location of construction activities Section 2.2.1<br />
6.4 Reclamation materials salvage CR7<br />
6.5 Storage location of reclamation materials during and after construction CR7<br />
6.6 Timber salvage and woody debris management CR7<br />
6.7 Construction on contaminated land N/A<br />
6.8 Contamination avoidance during construction CR7<br />
6.9 Process flow for releases during construction N/A<br />
6.10 Environmental releases monitoring Section 8.10.3, 7.11.5<br />
6.11 Ambient monitoring equipment Section 8.10.1<br />
7 Operation -<br />
7.1 Record keeping procedures Section 7.8<br />
7.2 Operating procedures for release monitoring and performance evaluation Section 7.8<br />
7.3 Joint monitoring network Section 8.10.7<br />
7.4 Suitability of proposed ambient air-monitoring network N/A<br />
7.5 Suitability of proposed ambient monitoring of the receiving environment N/A<br />
7.6 Proposal for periodic wastewater characterization testing Section 7.8<br />
7.7 Record keeping procedures to meet applicable requirements Section 7.8<br />
7.8 Reporting procedures Section 7.8<br />
7.9 Spill response and reporting plan development<br />
Section 7.11.1, 7.11.5,<br />
8.10.6<br />
7.10 Storage, treatment and monitoring plan for wastewater, runoff and sludge Section 7.11.6<br />
7.11 Air emission control equipment maintenance and repair plan Section 7.11.3<br />
7.12 Monitoring programs for potential substance release to groundwater<br />
Section 6.5, 7.8, 8.10.3,<br />
8.10.6, 5.4.2<br />
7.13 Management of releases to soils from other media Section 8.7.5<br />
7.14 Third-party waste procedures Appendix 7.3<br />
7.15 Classifying and characterizing waste methods Appendix 7.3<br />
7.16 Soil storage protection measures from contamination and erosion CR7<br />
7.17 Operator certification N/A<br />
8 Reclamation -<br />
8.1 End land-use and capability ratings CR7<br />
8.2 Reclamation of landform, drainage and watercourses CR7<br />
8.3 Soil reclamation plan CR7<br />
8.4 Vegetation reclamation plan CR7<br />
8.5 Effectiveness of alternatives for proposed “engineered” watercourses N/A<br />
8.6 Short and long term effects of reclamation to watercourses N/A<br />
8.7 Progressive reclamation plan CR7<br />
8.8 Reclamation timeline CR7<br />
8.9 Maximization of progressive reclamation CR7<br />
8.10 Reclamation materials salvage and handling procedures CR7<br />
8.11 Storage of reclamation materials CR7<br />
8.12 Progressive reclamation plan for landforms, watercourses, soil and vegetation CR7<br />
8.13 Wastewater and runoff releases during reclamation CR7<br />
8.14 Waste management during reclamation CR7<br />
8.15 Dust, odours, contaminants and noise control Section 7.1 – 7.11, 8.3.2.1<br />
8.16<br />
8.17<br />
Remedial treatment systems vapour control<br />
Existing and planned infrastructure for environmental monitoring<br />
Section 7.6<br />
N/A<br />
8.18 Stakeholder involvement N/A<br />
8.19 Contact information for reclamation activities Section 1.1<br />
9 Continual Improvement Plan Section 8.10<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 43
4 Geology<br />
4.1 Area Description<br />
4.1.1 Resource Development Area<br />
The Resource Development Area (“RDA”) is defined as Section 2 and SE 1 /4 of Section 3, in<br />
Township 64, Range 04 west of the 4th Meridian. (Figure 4.1.1)<br />
4.1.2 <strong>Project</strong> Development Area<br />
The <strong>Project</strong> Development Area (“PDA”) is defined as the well pad and Central processing facility<br />
encompassing 18.6 ha. (Figure 4.1.2)<br />
4.1.3 Geological Study Area<br />
The Geological Study area is defined in Figure 4.1.3<br />
4.2 Reservoir Geology<br />
4.2.1 Regional Stratigraphy<br />
Sedimentary rocks that overly the Precambrian basement in the <strong>Sage</strong> area of Cold Lake are about<br />
1200m thick and range from Cambrian to Quaternary in age (Figure 4.2.1).<br />
The Clearwater Formation is the main bitumen reservoir within the Birchwood acreage and is part of<br />
the Lower or Early Cretaceous Mannville Group. The Clearwater Formation deposition occurred<br />
initially approximately 110Ma (Early Cretaceous), and was then capped by the Grand Rapids<br />
Formation ending approximately 100Ma (Lower Cretaceous).<br />
The Clearwater is the geologic time equivalent to the Lloydminster formation in south eastern region<br />
of Alberta and time equivalent to the Bluesky and Spirit River Formation in the NW. Sediment into<br />
the Basin during deposition of the Clearwater typically came from the south east and was deposited<br />
into the basin in a NW direction.<br />
4.2.1.1 Granite Wash Formation (Cambrian)<br />
Cambrian aged sandstones rest unconformably on granites of the Precambrian basement. These<br />
sandstones are quartzose, with well-developed porosity and permeability. Minor interbedded shales<br />
and silts occur locally. Thicknesses of greater than 60 m have been observed. These sandstones<br />
are used by various operators in the Cold Lake area for water disposal. This formation is anticipated<br />
to be the primary water disposal zone for the thermal pilot at <strong>Sage</strong>.<br />
4.2.1.2 Elk Point Group (Devonian)<br />
Lower to Middle Devonian Elk Point group strata (evaporites) rests unconformably over the<br />
Cambrian sandstones. The formations from oldest to youngest are:<br />
• Lotsberg (240 m of salt, shale, and shaly dolomite)<br />
• Ernestina (20 m of dolomitic limestone and anhydrite)<br />
• Cold Lake (50 m of salt)<br />
• Contact Rapids (40 m of shaly dolomite)<br />
• Winnipegosis (50 m of dolomitic limestone)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 44
• Muskeg (170 m of salt)<br />
• Watt Mountain (20 m of dolomitic limestone, shale, and anhydrite)<br />
4.2.1.3 Beaverhill Lake Group (Upper Devonian)<br />
The Beaverhill Lake Group rests unconformably over the Elk Point Group. Strata in this group are<br />
composed of limestones, calcareous dolomites and argillaceous shales and comprise the<br />
Waterways Formation. Dissolution of Devonian salts and subsidence of overlying strata resulted in a<br />
structural low on top of the Waterways Formation. This represents the basement upon which the<br />
Mannville Group sediments would accumulate.<br />
4.2.1.4 Mannville Group (Lower Cretaceous)<br />
Mannville Group was deposited over top of the Beaverhill Lake Group. Depositional sands or strata<br />
represent the major reservoirs in the Cold Lake area. The formations from oldest to youngest are:<br />
• McMurray (McMurray A, B, C)<br />
• Clearwater<br />
• Lower and Upper Grand Rapids (Rex, General Petroleum, Sparky, Waseca, McLaren and<br />
Colony).<br />
All formations are unconsolidated sands with varying amounts of interbedded silts and shales.<br />
4.2.1.4A McMurray Formation<br />
The McMurray Formation was deposited on the Paleozoic carbonate. The McMurray C sands at the<br />
base is an unconformable surface and consists of approximately 15-30m of clean, quartz sand with<br />
interbedded silts and shales. The McMurray can be broken down to three subunits within the<br />
McMurray informally called the McMurray A, McMurray B, and McMurray C. The Lower McMurray<br />
consists of thick fluvial sands with a large aeriel extent. The Upper McMurray consists of<br />
interbedded silt, very fine sand, and shale, and is increasingly tidal in nature. These sands are wet<br />
and brackish in nature. The Lower McMurray sandstone has been used as a brackish water source<br />
and disposal zone for offsetting thermal projects such as Husky’s Tucker Lake and Shell’s Orion.<br />
The Lower McMurray C sandstone is targeted to be the primary brackish water source for the<br />
thermal pilot at <strong>Sage</strong>.<br />
4.2.1.4B Clearwater Formation<br />
The Clearwater Formation is the principal bitumen-bearing reservoir at <strong>Sage</strong>. Its average gross<br />
thickness is 45 to 65m at an average depth of 400m. These sands are unconsolidated feldspathic<br />
litharenites, and have a complex mineralogy. Clearwater sands at <strong>Sage</strong> were deposited in an<br />
estuarine environment. A drop in sea level during Clearwater deposition resulted in formation of an<br />
incised valley system, which removed older marine Clearwater sediments as well as some<br />
underlying Wasbiskaw Member sediments. Sea level rose, and a transgression along the valley<br />
system resulted in deposition of the Clearwater and Grand Rapids Formations. Marine shale caps<br />
the Clearwater and a water leg underlies the Clearwater in the <strong>Sage</strong> area.<br />
The Wabiskaw member lies beneath the base of the Clearwater Formation and overlies the<br />
McMurray Formation. Over the Birchwood acreage the Wabiskaw is a marine shale 2.0 - 8.0m. The<br />
Wabiskaw is often eroded by younger Clearwater strata. There is no reservoir potential associated<br />
with the Wabiskaw.<br />
A cross-section showing the zone of interest is provided (Figure 4.2.1.4A & Figure 4.2.1.4B) and a<br />
type log is provided (Figure 4.2.1.4C).<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 45
4.2.1.4C Grand Rapids Formation<br />
The Grand Rapids Formation consists of interbedded sands and shales deposited in a marginal<br />
marine setting. Individual sands and shales can be 5-10m thick and are lithic, feldspathic, to<br />
quarzose, in composition. The entire formation is approximately 100m thick. Individual sands can be<br />
hydrocarbon bearing, with separate contacts for each sand unit.<br />
Using nomenclature from the heavy oil area around Lloydminster the Lower Grand Rapids is<br />
informally divided into the “A”, “B” and “C” units with the lowermost A (Rex sand) and B (General<br />
Petroleum) and C (Sparky) sands typically wet.<br />
The Upper Grand Rapids sands are thin and laterally discontinuous and separated by shales up to<br />
10 m thick. The Upper Grand Rapids is informally divided into the “A”, “B” and “C” units with the<br />
lowermost A (Waseca) followed by the B unit (McLaren) and the uppermost ‘C’ (Colony). The<br />
Waseca sand and has been mapped over the <strong>Sage</strong> area. Birchwood has tested 100/01-03-64-<br />
04W4M for primary production potential in the Waseca and McLaren and recovered bitumen at sub<br />
economic rates. The Upper Grand Rapids can be gas bearing. These gas pools have limited aerial<br />
extent are structurally controlled and are isolated from the Clearwater Formation.<br />
4.2.1.5 Colorado Group Lea Park Formation (Upper Cretaceous)<br />
The Colorado Group conformably overlies the Mannville strata. This Group is up to 180m thick and<br />
consists of massive shales with minor silts deposited in a marine environment. From oldest to<br />
youngest, the Formations are:<br />
• Joli Fou<br />
• Viking / Pelican<br />
• Base Fish Scales<br />
• Second White Specks<br />
These formations provide a barrier between the productive zone and the groundwater resources<br />
above.<br />
4.2.1.6 Overburden (Quaternary)<br />
Overburden sediments are approximately 100m thick and are composed of glacial and post-glacial<br />
gravel, sand, silt, clays and tills. The sands and gravels are within channels eroded into the<br />
Colorado and are the fresh water aquifers in the <strong>Sage</strong> area. The formations from oldest to youngest<br />
are:<br />
• Empress<br />
• Muriel Lake (Durlingville)<br />
• Bonnyville<br />
• Ethel Lake<br />
• Sand River<br />
• Grand Centre<br />
4.2.2 Well Control<br />
Across the SAGE area there is sufficient well and core data to establish a stratigraphic framework<br />
and to determine reservoir quality (Figure 4.2.2A). There are 19 cored wells from offsetting lands<br />
and many open-hole logs that define the Clearwater reservoir on Birchwood’s property. To date<br />
there have been 4 wells drilled within the Birchwood Oil Sands lease. These wells are as follows<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 46
100/01-03-64-04W4, 100/03-02-64-04W4, 100/06-02-64-04W4 and 100/05-01-64-04w4 (Figure<br />
4.2.2B). All wells were logged with a full suite of open-hole logs (density, neutron, induction and<br />
sonic). Formation Imaging logs (“FMI”) were run on each of 100/01-03-64-04W4, 100/03-02-64-<br />
04W4, and 100/06-02-64-04W4, (Figure 4.2.2C). Petrophysical log analysis was completed on each<br />
set of open-hole logs for wells within the property in addition to 3 offsetting wells (Figure 4.2.2D).<br />
The 100/3-2-64-04W4 location was cored in both the Clearwater and the Waseca Formations. The<br />
core has been analyzed for porosity, permeability and oil saturation and viscosity (Figure 4.2.2E).<br />
Log analysis has been correlated against core data. Resulting net pay values from core and log<br />
analysis were used to generate the net pay map (Figure 4.2.3.1).<br />
Beyond the limits of the <strong>Sage</strong> lease, there is both log and core data which have been incorporated<br />
into the <strong>Sage</strong> stratigraphic interpretation.<br />
Additional drilling is planned. The objective of these wells is to refine the delineation of the bitumen<br />
resource within the planned development area, and to advance development planning for the<br />
remainder of the lease.<br />
4.2.2.1 Seismic Data<br />
Data from two 2D seismic lines was purchased by Birchwood in 2011 and interpreted to support the<br />
geological interpretation.<br />
A depth structure map of the top of the Clearwater was generated from Formation tops picked in<br />
Geoscout. Wells were then integrated with the two 2D Birchwood seismic lines (Figure 4.2.2.1A).<br />
Seismic confirmed that the top of the Clearwater remained relatively constant and consistent over<br />
the development area. No significant lows were developed due to salt solution and collapse of the<br />
underlying Devonian deposition (Figure 4.2.2.1B).<br />
A seismic program is planned for the winter of 2012-2013 pending regulatory approval.<br />
4.2.3 Geological Description of the Clearwater Formation<br />
The Clearwater formation was deposited in a shallow marine prograding (or basinward) deltaic<br />
system that was orientated towards the North/Northwest direction. Silica rich, fine to fine-medium<br />
grained sandstones were deposited along low to horizontal angle bedding planes composition.<br />
Occasional small scaled ripples and laminae are noted in Clearwater cores.<br />
The most common diagenetic feature of the Clearwater is carbonate cement and shale rich and clay<br />
laminations can occur and are found in certain areas of the Clearwater on the order of 1-10 cm in<br />
thickness, but are not believed to be continuous over large areas. They are believed to be calcite<br />
concretions and are not considered to be a barrier to steam chamber growth.<br />
The main reservoir within the Clearwater is the valley-fill sediments. Reservoir quality is determined<br />
by the shale content of the fill and the occurrence of early diagenetic pore filling clays. Over the<br />
Birchwood <strong>Sage</strong> <strong>Project</strong>, Clearwater sediments range from 30 to 65 m as a result of the stacking of<br />
sand rich valley fills with no significant shale breaks. A schematic W-E cross-section across the<br />
Birchwood SAGE <strong>Project</strong> shows the stacking of the incised valleys and the nature and relationship<br />
of the fill within and between each valley (Figure 4.2.1.4A). A W-E cross section including offsetting<br />
thermal operations is presented in Figure 4.2.1.4B. The fill of valleys B and C is dominantly sandrich,<br />
high energy channel flat facies. The fill of valley D is sediment deposited within tidal channels,<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 47
with varying amounts of shale clasts and beds that are characteristic of this facies. Bitumen<br />
saturation within valley D is also variable when compared to valleys B and C.<br />
Structure on the top of the Clearwater sand (Figure 4.2.3B) is fairly consistent across Birchwood’s<br />
Property with the exception of a small localized dip to the South East of Birchwood’s land.<br />
Structure on the base of the Clearwater sand (Figure 4.2.3C) varies across Birchwood’s Property.<br />
The consistent water height provides a bitumen leg with minimal elevation variation.<br />
The Clearwater isopach map (Figure 4.2.3D), illustrates where the Clearwater reaches a maximum<br />
thickness of 65m.<br />
4.2.3.1 Clearwater Net Pay<br />
The Clearwater Net Pay map denotes a Northern trending Clearwater pay interval that lies directly<br />
over Birchwood lands. The total bitumen thickness (Figure 4.2.3.1) across the development area at<br />
<strong>Sage</strong> ranges from 20-30m. Effective pay in the Clearwater Formation is designated as the<br />
continuously porous, oil-bearing zone that would be accessed by the steam chamber created<br />
around a horizontal well pair. Pay was determined from core analysis utilizing a bulk mass oil<br />
fraction of 0.07 as a pay cut-off. A porosity cutoff of 27 percent has been used along with a<br />
resistivity cutoff of 7 ohm-metres and a minimum thickness of 8m. An average porosity of 33 percent<br />
with an average bulk mass oil of 0.104 has been measured for the Clearwater pay from the 100/03-<br />
02-064-04W4 well resulting in the an average net pay of 25m within the Resource Development<br />
Area.<br />
4.2.3.2 Clearwater Bottom Water<br />
Across the Birchwood lease, the lowermost Clearwater sands are water saturated. Bitumen<br />
reservoir saturated sands rest directly on top of the water saturated sands. Bottom water structural<br />
dip is minimal over Birchwood’s Property, and averages around 1 m of structure variation across<br />
Sections 1, 2, and 3-64-4W4. The structure map (Figure 4.2.3.2) identifies the bitumen-water<br />
contact varies from +132.1m to + 133.0m.<br />
4.2.3.3 Clearwater Top Gas<br />
There appears to be no known gas identified over the Birchwood property in the Clearwater<br />
Formation. Open hole logs show no cross over or approach between the Density and neutron log<br />
indicating gas effect. Gas pockets have not been observed during drilling in the Clearwater<br />
Formation.<br />
The Upper Grand Rapids can be gas bearing. These gas pools have limited aerial extent are<br />
structurally controlled and are isolated from the Clearwater Formation.<br />
4.2.3.4 Caprock and Seal Integrity<br />
A seal exists between the oil saturated Clearwater and the overlying Lower Grand Rapids, as well<br />
as between the Upper Grand Rapids and the Quaternary fresh water aquifers.<br />
Clearwater sands are capped by 4-6 m thick shale across the RDA (Figure 4.2.3.4). This shale acts<br />
as a seal to hydrocarbon migration above the Clearwater and the lowermost Grand Rapids.<br />
Overlying Colorado shale’s up to 180m thick act as a seal to hydrocarbon migration above the<br />
Upper Grand Rapids and the Quaternary fresh water aquifers.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 48
4.4 Injection/Fall-off (“mini-frac”) Testing Results<br />
Taurus Reservoir Solution Ltd. (“Taurus”) was asked to perform a mini-frac analysis on tests<br />
conducted by ET Technical Systems and Pure Energy on the well 100/06-02-064-04 W4M (06-02)<br />
(CR6 – Injection/fall-off testing report). These tests covered 5 sand and shale intervals from the<br />
Colorado Shale (271 – 271.5 m KB) down to the Clearwater Sand (409.0 – 409.53 m KB). It was<br />
possible to interpret closure pressures for all zones from the tests except for the Clearwater shale<br />
zone.<br />
The Clearwater shale interval was tested twice and both tests showed rapid pressure drops after<br />
each fall-off. This indicates a significant fluid mobility not normally seen in shale caprock. It is<br />
concluded that fracture height growth occurred during testing to an external permeable zone. The<br />
zone is likely downwards into the Clearwater sand. The Clearwater shale in the area is regionally<br />
consistent and existing stress gradients can be used to calculate closure pressures for the<br />
Clearwater shale. As such a search of publicly available offsetting data was conducted.<br />
The search revealed that in 2009 Weatherford preformed a study for Osum on their Taiga project in<br />
the Cold Lake area. As part of their work they documented publically available mini-frac work in the<br />
Cold Lake area. The data includes information from a number of zones; the bulk of the data was<br />
from the Clearwater sand and shale intervals. High quality mini-frac data is available from the<br />
offsetting Imperial Oil lands and is specific to the Clearwater shale. Horizontal stress gradients of<br />
20.9 kPa/m have been measured. This is the recommended value to pick for the Clearwater shale.<br />
The Clearwater shale in the area is regionally consistent and stress gradients can be used to<br />
calculate closure pressures for the Clearwater shale on the 06-02 well.<br />
Table 4.4.1 Clearwater Shale Closure Pressure Regional Value<br />
Zone<br />
Depth<br />
m GL TVD<br />
Gradient<br />
kPaa/m<br />
Closure Pressure<br />
kPaa<br />
Clearwater Shale 407.35 20.9 8514<br />
Table 4.4.2 Summary of Closure Pressures per Zone Tested<br />
Source<br />
Depth equal to MPP of<br />
perforated interval<br />
Zone<br />
Depth<br />
m GL TVD<br />
Gradient<br />
kPaa/m<br />
Closure Pressure<br />
kPaa<br />
Source<br />
Colorado Shale 269.35 24.6 6617 Birchwood FP_10_FO<br />
Waseca Shale 329.35 19.5 6407 Birchwood FP_06_FO<br />
Waseca Sand 336.65 22.3 7514 Birchwood FP_05_FO<br />
Clearwater Sand 426.85 16.3 6969 Birchwood FP_06_FO<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 49
Figure 4.1.1 Resource Development Area (“RDA”)<br />
T64<br />
T63<br />
Wells<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
17<br />
<strong>Project</strong> Wells<br />
Land Layer<br />
28<br />
21<br />
16<br />
33<br />
28<br />
21<br />
16<br />
Birchwood Lease Area<br />
Development Area<br />
9<br />
4<br />
R4 R3W4<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
27<br />
22<br />
15<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 50<br />
26<br />
23<br />
14<br />
11<br />
2<br />
35<br />
26<br />
23<br />
14<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
25<br />
24<br />
13<br />
12<br />
1<br />
36<br />
25<br />
24<br />
13<br />
30<br />
19<br />
18<br />
7<br />
6<br />
31<br />
30<br />
19<br />
18<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
17<br />
T64<br />
T63<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Birchwood Development Area<br />
By : Jerry Babiuk, P.Geol Date : 2012/06/01<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake<br />
Figure 4.1
Figure 4.1.2 <strong>Project</strong> Development Area (PDA) & Wells<br />
T64<br />
T63<br />
Land Layer<br />
10<br />
3<br />
34<br />
Birchwood Lease Area<br />
Development Area<br />
Hydrography<br />
Major<br />
Minor Lake<br />
Minor River<br />
Pad Layout<br />
Wells<br />
Hz well path<br />
Faciity site<br />
Build Section<br />
Well heads<br />
<strong>Project</strong> Wells<br />
Kilometres<br />
R4 R3W4<br />
11<br />
2<br />
35<br />
0 0.5 1 1.5<br />
0 0.5 1<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 51<br />
12<br />
R4 R3W4<br />
1<br />
36<br />
T64<br />
T63<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
CPF & SAGD Horizontal Well Pairs<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/17<br />
Scale = 1:32493 <strong>Project</strong> : Cold Lake
T64<br />
T63<br />
Figure 4.1.3 Geological Study Area<br />
30<br />
19<br />
18<br />
31<br />
30<br />
19<br />
Land Layer<br />
Wells<br />
7<br />
6<br />
29<br />
20<br />
17<br />
32<br />
29<br />
20<br />
Birchwood Lease Area<br />
Development Area<br />
Geological Study Area<br />
<strong>Project</strong> Wells<br />
Hydrography<br />
Major<br />
Minor Lake<br />
Minor River<br />
8<br />
5<br />
28<br />
21<br />
16<br />
9<br />
4<br />
33<br />
28<br />
21<br />
R4 R3W4<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
27<br />
22<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 52<br />
26<br />
23<br />
14<br />
11<br />
2<br />
35<br />
26<br />
23<br />
25<br />
24<br />
13<br />
12<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
1<br />
36<br />
25<br />
24<br />
30<br />
19<br />
18<br />
7<br />
6<br />
31<br />
30<br />
19<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
28<br />
21<br />
16<br />
9<br />
4<br />
33<br />
28<br />
21<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Geological Study Area<br />
27<br />
22<br />
T64<br />
15<br />
10<br />
34<br />
27<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/17<br />
Scale = 1:85000 <strong>Project</strong> : Cold Lake<br />
22
Figure 4.2.1 Cold Lake Stratigraphy<br />
(Modified from Husky-Tucker <strong>Thermal</strong> <strong>Project</strong>, 2003)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 53
Figure 4.2.1.4A Schematic SW-NE cross-section Clearwater Formation<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 54
Figure 4.2.1.4B Regional Cross Section Clearwater Formation<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 55
Figure 4.2.1.4C Birchwood Clearwater Type Log<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 56
Figure 4.2.2A Well Control Map<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 57
Figure 4.2.2B Cross Section Birchwood Lease - Clearwater Formation<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 58
Figure 4.2.2C Formation Imaging logs (FMI) - Clearwater Formation Interval<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 59
Figure 4.2.2D Log Analysis<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 60
Figure 4.2.2E Summary Core Data and Photos 100/03-02-064-04W400<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 61
Figure 4.2.2.1A Depth converted time structure map top of Clearwater Formation<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 62
Figure 4.2.2.1B Interpreted Seismic Data<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 63
Figure 4.2.3B Structure on the Top of the Clearwater Formation<br />
+177.3<br />
+169.3 +170.7+170.7 +177.4 +179.0<br />
+170.0<br />
+167.2<br />
+163.2<br />
+169.8<br />
+172.7+175.9<br />
+174.2<br />
T64<br />
T63<br />
+166.7 +167.1<br />
+160.3<br />
+153.9 +148.4 +152.0<br />
Land Layer<br />
Wells<br />
29<br />
+164.3 +161.4<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
+166.2<br />
20<br />
+163.3<br />
+165.6 +164.2 +163.2+167.9<br />
+161.1<br />
+159.8<br />
+163.2<br />
+156.4<br />
28<br />
+164.3+165.0<br />
21<br />
16<br />
+161.7 +161.0 +152.3<br />
33<br />
28<br />
21<br />
+164.4<br />
+172.9,+172.9 +173.1,+172.6<br />
Birchwood Land<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
9<br />
4<br />
+175.6<br />
R4 R3W4<br />
27<br />
+179.8<br />
22<br />
15<br />
10<br />
3<br />
34<br />
+170.9<br />
27<br />
+156.8<br />
+176.9<br />
+176.4,+169.3<br />
22<br />
+175.7<br />
+155.5<br />
+157.2<br />
+170.5,+170.2 +170.7<br />
+176.6<br />
26<br />
23<br />
14<br />
11<br />
2<br />
35<br />
26<br />
23<br />
150.0<br />
150.0<br />
+164.7<br />
+179.8<br />
+177.3,+177.5<br />
150.0<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 64<br />
+174.9<br />
+178.2<br />
+172.6<br />
+158.2<br />
+149.5<br />
+159.0<br />
+158.2<br />
13<br />
12<br />
1<br />
36<br />
25<br />
24<br />
+174.0<br />
+157.5<br />
+164.6<br />
+159.7<br />
+169.7<br />
+179.0<br />
+164.2<br />
+159.3<br />
+147.6<br />
30<br />
+167.8<br />
+167.6<br />
19<br />
+170.2<br />
+162.5<br />
18<br />
+160.5<br />
7<br />
6<br />
31<br />
30<br />
19<br />
+171.6<br />
+169.5<br />
+172.3<br />
+173.7 +175.0<br />
+170.4<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
25<br />
24<br />
+169.7<br />
+169.3<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
+167.9<br />
+167.8 +164.6<br />
+164.8<br />
+170.5<br />
+147.5<br />
+172.2<br />
+174.2<br />
+172.4<br />
20<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Structure Map<br />
Clearwater Formation<br />
T64<br />
150.0<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/11<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake
115.0<br />
T64<br />
T63<br />
Figure 4.2.3C Structure at Base of the Clearwater Formation<br />
+109.2<br />
90.0<br />
115.0<br />
115.0<br />
+108.3 +113.9 ,+108.8,<br />
+102.9<br />
+104.6 +110.6<br />
+98.3<br />
Land Layer<br />
Wells<br />
29<br />
+120.9<br />
+114.5 +120.4 +121.2<br />
+118.4<br />
+112.4+116.1<br />
+115.8<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
+106.7<br />
20<br />
+108.2<br />
+104.5<br />
+95.2<br />
+87.5<br />
+87.4<br />
+106.0<br />
+95.7<br />
28<br />
+107.7 +103.9+113.7<br />
21<br />
16<br />
33<br />
28<br />
21<br />
90.0<br />
90.0<br />
+120.1,+119.4 +119.4,+120.5<br />
Birchwood Land<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
9<br />
4<br />
+118.5<br />
+114.9<br />
+111.5<br />
+112.7<br />
+105.3<br />
115.0<br />
R4 R3W4<br />
27<br />
+115.2<br />
22<br />
15<br />
10<br />
3<br />
34<br />
+116.9<br />
27<br />
+94.4<br />
+139.1<br />
+137.2,+137.3,<br />
22<br />
+111.9<br />
+101.9<br />
+104.4<br />
--- +126.7,, +130.3<br />
+124.3<br />
+121.4<br />
26<br />
23<br />
115.0<br />
14<br />
11<br />
2<br />
35<br />
26<br />
23<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 65<br />
+112.4<br />
115.0<br />
115.0<br />
+112.6<br />
+114.7<br />
+116.8<br />
+109.8<br />
+106.4<br />
+117.5<br />
+118.6<br />
13<br />
12<br />
1<br />
115.0<br />
36<br />
25<br />
24<br />
+132.6<br />
+115.3<br />
+112.1<br />
+130.9<br />
115.0<br />
+116.7<br />
+139.2<br />
+117.9<br />
+108.9<br />
90.0<br />
+123.1<br />
30<br />
+127.3<br />
+124.5 +131.1<br />
19<br />
+130.6<br />
+123.3<br />
18<br />
+121.0<br />
7<br />
6<br />
31<br />
115.0<br />
30<br />
+138.6,<br />
19<br />
+125.1<br />
+125.8<br />
+132.0<br />
+128.5<br />
+120.0<br />
+134.5<br />
+130.9<br />
+120.5<br />
+134.4 +134.7<br />
+118.5<br />
115.0<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
25<br />
24<br />
29<br />
20<br />
+133.1<br />
+130.8 +124.9<br />
+134.2<br />
17<br />
8<br />
5<br />
32<br />
29<br />
+128.7<br />
+133.6<br />
+127.8 ,+133.6<br />
+137.2<br />
+126.0<br />
+120.6<br />
+132.6<br />
+134.5<br />
+132.6<br />
20<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Structure Cleawater Base<br />
T64<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/05<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake<br />
Frigure
Figure 4.2.3D Clearwater Isopach Map<br />
53.0 53.5 56.2<br />
56.4<br />
57.0 57.8<br />
58.0<br />
56.8<br />
59.2<br />
51.6<br />
60.3 59.858.4<br />
T64<br />
T63<br />
55.6<br />
58.4 53.2<br />
57.4<br />
Land Layer<br />
Wells<br />
29<br />
57.9 57.3<br />
20<br />
17<br />
8<br />
5<br />
70.0<br />
32<br />
29<br />
59.5<br />
20<br />
53.4<br />
57.4<br />
56.6<br />
64.6<br />
74.2<br />
61.0<br />
59.7 54.4<br />
57.2<br />
60.7<br />
28<br />
56.5 59.3 54.2<br />
21<br />
16<br />
33<br />
28<br />
70.0 70.0<br />
21<br />
45.0<br />
52.8,53.5 53.7,52.1<br />
Birchwood Land<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
9<br />
4<br />
57.1<br />
59.1<br />
R4 R3W4<br />
64.6<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
27<br />
54.0<br />
37.8<br />
39.2,32.0<br />
22<br />
62.4<br />
63.8<br />
53.6<br />
52.8<br />
43.8, 40.4<br />
45.0<br />
52.3<br />
26<br />
23<br />
14<br />
11<br />
2<br />
35<br />
45.0<br />
26<br />
23<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 66<br />
62.5<br />
45.0<br />
45.0<br />
65.6<br />
45.0<br />
57.9<br />
41.4<br />
39.7<br />
41.5<br />
39.6<br />
13<br />
12<br />
1<br />
36<br />
25<br />
24<br />
41.4<br />
42.2<br />
38.8<br />
52.5<br />
43.0<br />
39.8<br />
45.0<br />
41.4<br />
41.1<br />
38.7<br />
40.5<br />
30<br />
43.1<br />
19<br />
18<br />
39.6<br />
7<br />
6<br />
31<br />
39.2<br />
39.5<br />
30<br />
38.7,37.2<br />
19<br />
45.0<br />
38.9<br />
39.6<br />
49.5<br />
51.8<br />
39.3 40.3<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
25<br />
24<br />
45.0<br />
38.8<br />
50.8<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
45.0<br />
37.0<br />
39.2<br />
49.9<br />
39.6<br />
39.7<br />
39.8<br />
20<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Isopach Map<br />
Clearwater Formation<br />
39.7<br />
38.8<br />
T64<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/11<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake
Figure 4.2.3.1 Clearwater Net Pay<br />
T64<br />
T63<br />
Land Layer<br />
Wells<br />
10<br />
3<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
Clearwater Fm<br />
34<br />
Net Pay Contours<br />
20.0m<br />
ST= 155.9m<br />
46.5/23.5/23.5<br />
wtr line= 132.1m<br />
ST= -157.0m<br />
63.5/23.7/22<br />
wtr line= 133.0m<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 67<br />
25.0m<br />
30.0m<br />
R4 R3W4<br />
11<br />
2<br />
ST= 157.3m<br />
44.2/24.8/23<br />
wtr line= 132.7m<br />
35<br />
30.0m<br />
25.0m<br />
Kilometres<br />
0 0.5 1 1.5<br />
0 0.5 1<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
ST= 155.7m<br />
40/22.4/19.0<br />
wtr line= 133.7m<br />
20.0m<br />
12<br />
1<br />
36<br />
15.0m<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Net Pay Clearwater Formation<br />
By : Jerry Babiuk, P.Geol Date : 2012/10/09<br />
Scale = 1:23000 <strong>Project</strong> : Cold Lake<br />
R4 R3W4<br />
7<br />
6<br />
31<br />
T64<br />
T63
T64<br />
ST= 149.4m<br />
51.8/9.0/5.1<br />
wtr line= 139.6m<br />
T63<br />
Figure 4.2.3.1B Clearwater Net Pay<br />
ST= 153.9m<br />
55.6/13.9/4.0<br />
Land Layer<br />
Wells<br />
29<br />
20<br />
17<br />
8<br />
5<br />
0.0m<br />
ST= 148.8m<br />
58.9/25.0/3.4<br />
ST= 161.7m<br />
70.4/16.6/11.8<br />
wtr line= 130.8m<br />
32<br />
29<br />
ST= 166.2m<br />
20<br />
61.6/24.8/9.9<br />
wtr line=134.4m<br />
NDE<br />
ST= 160.8m<br />
NDE/14.6/9.1<br />
wtr line= NDE<br />
NDE<br />
ST= 163.2m<br />
57.2/25.5/22.5<br />
Wtr Line= 126.1m<br />
ST= 156.4m<br />
60.7/13/12.5<br />
wtr line= 121.4m<br />
5.0m<br />
ST= 172.9m<br />
28<br />
21<br />
16<br />
10.0m<br />
ST= -151.4m<br />
NDE/NDE/12.0<br />
33<br />
28<br />
21<br />
53.50/33.6/19.0<br />
wtr line= 137.1m<br />
Birchwood Land<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
9<br />
4<br />
ST= 164.4m<br />
59.1/19.6/13.0<br />
wtr line= 135.2m<br />
15.0m<br />
20.0m<br />
25.0m<br />
30.0m<br />
35.0m<br />
ST= 155.9m<br />
46.5/23.5/23.5<br />
wtr line= 132.1m<br />
ST= -157.0m ST= 157.3m<br />
63.5/23.7/22<br />
44.2/24.8/23<br />
wtr line= 133.0m wtr line= 132.7m<br />
ST= -170.6m<br />
53.5/36.5/36.5<br />
wtr line= 134.6m<br />
ST= 176.9m<br />
38.6/33.9/24.9<br />
wtr line= 140.9m ST= 169.3m<br />
32.0/24.6/21<br />
ST= 173.1m<br />
53.7/35.3/22.2<br />
wtr line= 135.8m<br />
R4 R3W4<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
27<br />
22<br />
NDE<br />
wtr line= 140.2m<br />
ST= 155.6m<br />
ST= 175.7m<br />
34.2/34.0/28<br />
26<br />
23<br />
14<br />
No Logs<br />
11<br />
2<br />
35<br />
35.0m<br />
30.0m<br />
ST= 181.8m<br />
26<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 68<br />
25.0m<br />
51.4/46.8/33.4<br />
wtr line= 135.0m<br />
ST= 155.7m<br />
40/22.4/19.0<br />
wtr line= 133.7m<br />
20.0m<br />
NDE<br />
ST= 148.9m<br />
NDE/NDE/>11.0m<br />
wtr line NDE<br />
15.0m<br />
ST= 149.1m<br />
32.6/16.7/13.5<br />
wtr line=132.8m<br />
10.0m<br />
ST= 159.7m<br />
43.0/24.9/21.0<br />
wtr line 131.5m<br />
15.0m<br />
5.0m<br />
ST= 169.7m<br />
ST= 149.5m<br />
ST= 174.1m<br />
NDE/NDE/>15.0<br />
38.8/30.3/17.3m<br />
wtr line= 139.4m<br />
wtr line= NDE ST= 179.0m<br />
23<br />
ST= 176.7m<br />
52.4/35.9/14.1<br />
wtr line= 136.5m<br />
25<br />
24<br />
ST= 159.0m<br />
60.5/26.1/21.0<br />
wtr line= 130.6m<br />
ST= 159.3m<br />
ST= 158.2m<br />
41.4/25.5/24.5<br />
wtr line= 133.9m<br />
40.5/25.0/21.1<br />
wtr line= 133.2m<br />
13<br />
12<br />
1<br />
36<br />
25<br />
ST= 174.0m<br />
ST= 157.5m<br />
42.2/24.9/22.5<br />
wtr line= 131.4m<br />
24<br />
41.4/26.5/18.2<br />
wtr line= 143.9m<br />
39.8/27.5/18.6<br />
wtr line= 147.6m<br />
40.6/15.6/12.8<br />
Wtr line= 133.5m<br />
0.0m<br />
30<br />
19<br />
18<br />
ST= 160.5m<br />
51.0/25.5/20.9<br />
7<br />
6<br />
31<br />
30<br />
ST= 164.7m<br />
ST= 168.2m<br />
38.9/27.4/17<br />
wtr line= 137.3m<br />
ST= 171.9m<br />
19<br />
31.6/25.1/17.5<br />
wtr line=146.8m<br />
ST= 166.2m<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
NDE<br />
NDE<br />
T64<br />
T63<br />
ST= 172.2m<br />
39.6/30.6/20<br />
wtr line= 138.5m<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Net Pay Clearwater Formation<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/05<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake<br />
Figure 4.3.1
T64<br />
wtr line= 139.6m<br />
T63<br />
Figure 4.2.3.2 Structure Clearwater Bottom Water<br />
130m<br />
Wtr Line= 133.9m<br />
Land Layer<br />
Wells<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
wtr line=134.4m<br />
NDE<br />
Wtr Line= 126.1m<br />
wtr line= 121.4m wtr line= 135.2m<br />
Wtr line= 134.4m<br />
NDE<br />
28<br />
21<br />
16<br />
wtr line= 130.8m wtr line= NDE<br />
33<br />
28<br />
21<br />
wtr line= 137.1m<br />
Birchwood Land<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
9<br />
4<br />
135m<br />
140m<br />
wtr line= 140.9m<br />
wtr line= 135.8m<br />
R4 R3W4<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
wtr line= 132.1m<br />
wtr line= 133.0m wtr line= 132.7m<br />
wtr line= 134.6m<br />
27<br />
22<br />
wtr line= 140.2m<br />
Wtr Line= 137.8m<br />
NDE<br />
26<br />
23<br />
14<br />
No Logs<br />
11<br />
2<br />
35<br />
26<br />
wtr line= 135.0m<br />
wtr line= NDE<br />
23<br />
wtr line= 136.5m<br />
130m<br />
wtr line= 130.6m<br />
wtr line= 133.2m<br />
wtr line= 133.7m<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 69<br />
25<br />
NDE<br />
24<br />
13<br />
12<br />
1<br />
wtr line=132.8m<br />
wtr line= 131.4m<br />
wtr line NDE<br />
36<br />
25<br />
24<br />
wtr line 131.5m<br />
wtr line= 139.4m<br />
wtr line= 143.9m<br />
wtr line= 133.9m<br />
wtr line= 147.6m<br />
30<br />
19<br />
18<br />
Wtr line= 133.5m<br />
Wtr Line=132.6m<br />
7<br />
6<br />
31<br />
30<br />
wtr line= 137.3m<br />
19<br />
wtr line=146.8m<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
20<br />
NDE<br />
NDE<br />
T64<br />
T63<br />
wtr line= 138.5m<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Structure Cleawater Bottom Water<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/05<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake<br />
Frigure
T64<br />
T63<br />
Figure 4.2.3.4 Isopach Map Clearwater Formation Capping Shale<br />
4.3<br />
Land Layer<br />
Wells<br />
3.5<br />
29<br />
20<br />
17<br />
8<br />
5<br />
32<br />
29<br />
1.4<br />
20<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
Clrwtr Shale Unit<br />
3.7<br />
4.5<br />
Clwtr Shale Isopach Contours<br />
5.8<br />
28<br />
21<br />
16<br />
9<br />
4<br />
33<br />
28<br />
21<br />
6.0<br />
2.5 3.2<br />
4.1<br />
R4 R3W4<br />
27<br />
22<br />
15<br />
10<br />
3<br />
34<br />
3.5<br />
27<br />
22<br />
3.2<br />
2.1<br />
4.3<br />
5.3<br />
5.0<br />
2.8<br />
2.9 2.6<br />
2.9<br />
3.83.0<br />
1.9<br />
3.1<br />
26<br />
23<br />
14<br />
11<br />
2<br />
35<br />
26<br />
23<br />
3.5<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 70<br />
2.4<br />
3.5<br />
4.7<br />
3.2<br />
4.0<br />
1<br />
3.4<br />
36<br />
25<br />
24<br />
3.0<br />
6.5<br />
2.3<br />
2.5<br />
2.4<br />
2.7<br />
3.6<br />
3.5<br />
R4 R3W4<br />
Kilometres<br />
0 1 2 3 4 5<br />
0 1 2 3<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
25<br />
24<br />
13<br />
12<br />
30<br />
19<br />
18<br />
7<br />
6<br />
31<br />
30<br />
2.9<br />
1.7<br />
19<br />
2.8<br />
2.0<br />
1.4<br />
29<br />
20<br />
17<br />
8<br />
5<br />
3.5<br />
32<br />
3.5<br />
29<br />
20<br />
3.2<br />
3.5<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Isopach Map<br />
Shale Unit Above Clearwater<br />
3.8<br />
T64<br />
T63<br />
By : Jerry Babiuk, P.Geol Date : 2012/12/04<br />
Scale = 1:65000 <strong>Project</strong> : Cold Lake
5 Reservoir Recovery Process<br />
5.1 Reservoir Properties<br />
The Clearwater Formation for the <strong>Sage</strong> project is encountered at a true vertical depth (“TVD”) of<br />
approximately 400mKB. The Clearwater formation within the proposed development area has<br />
gross pay thickness varying between 45 m to 64 m with bottom water thickness varying from 22<br />
m to 37 m and net / SAGD exploitable pay ranging from 20-30 meters.<br />
5.1 Table <strong>Sage</strong> Typical Reservoir Properties<br />
Gross Pay Thickness (m) 45 – 64<br />
Bottom Water Thickness (m) 22 – 37<br />
Net Pay / OOIP / SAGD Exploitable Pay Thickness (m) 20 – 30<br />
Porosity (%) 33 – 36<br />
Water Saturation in SAGD Exploitable Pay (%) 30 – 40<br />
Oil Saturation in SAGD Exploitable Pay (%) 60 – 70<br />
Horizontal Permeability (mD) 1,000 – 3,000<br />
Vertical Permeability (mD) 550 – 1,500<br />
Reservoir Temperature ( o C) 16<br />
Dead Oil Viscosity @ Reservoir Temperature (mPa.sec) 60,000 – 3,600,000<br />
Oil Gravity ( o API) 8.0 – 10.5<br />
Initial Reservoir Pressure (kPa) 2,700 - 2,900<br />
Initial Gas saturation 0<br />
5.1.1 Recovery Process Selection<br />
Generally accepted methods for recovering bitumen form the Clearwater Formation include<br />
Steam Assisted Gravity Drainage (“SAGD”) and Cyclic Steam Stimulation (“CSS”) both of which<br />
have commercial operations in close proximity to the project recovering bitumen from the<br />
Clearwater. CSS is historically the more developed method for recovery in the Clearwater<br />
formation in the area but this process has limited application in reservoirs with bottom water.<br />
CSS Recovery in reservoirs absent of bottom water is potentially 30% of the Original Oil In<br />
Place.<br />
The SAGD process is a high efficiency recovery process that may potentially recover 65% of the<br />
Original Oil In Place and is considered the most viable process for bitumen recovery from the<br />
Clearwater Formation on the Birchwood Lease. Data from offsetting operations utilizing SAGD<br />
with well pairs placed in pay with bitumen weight percent similar to those occurring in this<br />
project, within the Clearwater provide a reasonable basis for recovery projections.<br />
5.1.2 Recovery Process Description<br />
The <strong>Project</strong> will utilize a SAGD process for bitumen recovery by drilling pairs of horizontal wells<br />
near the base of the oil sands net pay. Each well pair comprises of two horizontal wells, which<br />
include an injector placed approximately 5 m directly above the producer, which is placed near<br />
the base of the bitumen zone. The SAGD process involves continuous injection of high quality<br />
steam which heats the reservoir and produces a steam chamber. The latent heat of the<br />
condensing steam is transferred to the sand and bitumen in the formation. The viscosity of the<br />
bitumen drops as the temperature rises. The reduced viscosity allows the bitumen to move<br />
down through the sand matrix to the production well using gravity as the driving force; hence the<br />
term, “Steam Assisted Gravity Drainage”.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 71
Because of the presence of bottom water, the lower horizontal producing well will be placed<br />
between 2 - 5 m above the oil-water contact (OWC) to maximize bitumen recovery. The<br />
application of the SAGD process near bottom water in oil sands reservoir requires the careful<br />
monitoring and control of the steam chamber pressure, aquifer pressure and producing<br />
backpressure for optimum production performance.<br />
It is estimated that the viscosity of the bitumen near the bottom water is 3.6MM centipoise (cp)<br />
which will provide a “tar matt” that should limit vertical migration of bottom water. Additionally,<br />
vertical permeability in the Clearwater is substantially lower than horizontal permeability, again<br />
limiting vertical migration of bottom water.<br />
Gas saturation is assumed to be 0 initially, when steam is introduced into the reservoir; solution<br />
gas will be produced that is mainly methane. As the process continues, aquathermolysis occurs<br />
and both CO2 (often in larger amounts than solution gas) and a small amount of H2S are<br />
produced with the solution gas. As the solubility of these products becomes the same in the<br />
water as in the bitumen at steam temperatures, and substantially more water is produced than<br />
bitumen, solution gas, C02 and H2S will also be collected in the water treatment system. All of<br />
the gas produced from either the water or bitumen processing stream is conserved and used as<br />
fuel gas in the boilers.<br />
5.2 SAGD Start-Up Phase<br />
The Clearwater Formation at original reservoir temperature has bitumen with a viscosity of<br />
60,000 cp at the top of the reservoir and as much as 3.6MM cp at the base, and is therefore<br />
immobile around the two wells. Both injector and producer well bores must be heated evenly to<br />
establish oil mobility before injection into the reservoir can commence. During initial cold startup,<br />
attempting to inject steam into a cold formation will cause the steam in the wellbore to<br />
condense and the combination of steam pressure at surface and hydrostatic pressure can<br />
potentially fracture the reservoir leading to bottom water production and communication<br />
between the injection well and the production well near the heel of the injector. This can lead to<br />
undesirable steam distribution and poor steam chamber development. To ensure the well bores<br />
are heated evenly the steam control manifolds will be configured to allow steam to be fed into<br />
any of the wells to accommodate the start-up strategy.<br />
5.2.1 Warm Up/Circulating (60-90 days)<br />
In order to achieve uniform heating along the horizontal sections and the area vertically between<br />
injector and producer, a circulation program of both injector and producer will be deployed.<br />
Steam will initially be circulated in the injection and producing wells during the initial phase.<br />
Circulating is achieved in the well bore by sending steam down the long string located near the<br />
toe and returning steam and condensate to surface through the short string located at the heel,<br />
which will heat up the well bore and adjacent rock formation. Conduction is the main heating<br />
mechanism during the warm up phase. Circulation will continue until inter-well communication is<br />
established at which time the injector well will then be converted to transition SAGD. Start-up<br />
procedures for the proposed well pairs will be similar to that of the latest start-up procedures at<br />
other SAGD operations.<br />
Proposed operating parameters for the circulation phase are summarized below:<br />
• Both injector and producer will be circulated with steam injected into the long production<br />
string and fluid return through short production string.<br />
• Circulating duration to be no less than 90 days with injection rates at 100 - 200 t/d per<br />
well or 200 - 400 t/d per pair.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 72
• Target total steam volume of 30,000 – 36,000 m 3 cold water equivalent (CWE) per well<br />
pair at the conclusion of circulation.<br />
• Primary control during circulation is circulation pressure in both injector and producer.<br />
• Proposed circulation pressures will be gradually increased throughout the circulation<br />
phase with a bottom-hole pressure not exceeding 5,000 kPa (maximum).<br />
Operating challenges include accurate and continuous down-hole pressure monitoring, transient<br />
temperature and pressure gradients. These challenges are managed by well sensors for<br />
temperature measurement and by surface gas lift or blanket gas measurement to ensure<br />
continuous, accurate and reliable pressure measurement in the producer and injector.<br />
5.2.2 Transition (30-90 days)<br />
Transition SAGD is achieved by continued steam circulation in the production well and the<br />
injection well is converted to injecting steam into both long and short strings in the reservoir at a<br />
controlled rate with strict management of injection pressures. Transition SAGD results in a<br />
differential pressure applied between the injector and producer, to promote movement of fluid,<br />
as well as heat, between the wells. Start-up steaming operations are maintained until the<br />
bitumen region between the injector well and producer well becomes mobile. The time required<br />
to establish fluid communication is well-pair dependent and relates to:<br />
• injector-to-producer well separation along the horizontal well length;<br />
• inter-wellbore reservoir quality;<br />
• injected steam temperatures; and<br />
• pressure.<br />
Maximum bottom-hole pressure for circulation and transition start-up of a SAGD well pair will be<br />
limited to 5,000kpa. Water volumes injected into and produced from the wells during circulation<br />
will be continuously monitored along with bottom-hole pressures and the total net injection into<br />
the formation.<br />
5.3 Steady State SAGD Operating Phase<br />
After communication has been established between the SAGD injection and production wells,<br />
steam is injected into the injection well at a constant pressure while mobilized oil, condensed<br />
steam, formation water and produced gas are removed from the production well. During this<br />
period the zone of communication between the wells is expanded axially along the full well pair<br />
length and the steam chamber is expected to expand vertically up to the top of the bitumen<br />
zone, at which point lateral growth becomes the dominant mechanism for recovering oil.<br />
Bitumen mobilization predominantly occurs at the boundary of the steam chamber. As the<br />
steam chamber grows and bitumen flow decreases, new well pairs will be required to maintain<br />
consistent production to the facility.<br />
The following are the proposed injection strategies and production control philosophy:<br />
• Steam chamber pressures will be targeted at the range of 3,000 – 3,500 kPa but will not<br />
exceed 5,000 kPa in all injectors with various steam injection rate bias to heel and toe.<br />
• Effective production well sub-cool will be targeted in the range of 0 – 20 o C. Subcool may<br />
vary at different operating stages depending on maturity of steam chamber development.<br />
• Reservoir material balance between fluid production and steam injection will be maintained<br />
by monitoring water production to steam injection ratio (WSR ~1.0).<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 73
Production from the well pairs will be regularly monitored with a test separator that will measure<br />
oil, water and gas production. A cooling loop will be added to differentiate between produced<br />
gas and steam.<br />
It is anticipated that conventional SAGD operations will be sustained until the optimal amount of<br />
heat has been supplied to the well-pair. When this occurs, it is estimated that 65% of the OOIP,<br />
will have been produced, and the steam injection will be ramped down to zero.<br />
The field operating strategy will be monitored and revised based on temperature and pressure<br />
data collected from instrument strings in the producer and pressure monitoring injection wells.<br />
The data would provide information on steam chamber growth, direction of preferential steam<br />
movement (if any), injector-producer steam distribution and coning and other pertinent<br />
conditions. The information can then be utilized to modify and optimize the SAGD recovery<br />
process for each well pair.<br />
5.3.1 Operating Pressures<br />
Birchwood is planning to operate the steam chamber over a range of bottom hole pressures;<br />
however, there are essentially two pressure conditions: initial pressure (4,000-4,500 kPa) during<br />
the start-up stage to establish the steam chamber, followed by a lower pressure (3,000-3,500<br />
kPa) during the conventional SAGD stage. A complete description of the SAGD stages is<br />
provided in Section 5.2.<br />
5.3.2 Maximum Operating Pressure (“MOP”)<br />
The fracture gradient of the Clearwater capping shale calculated based on offsetting cap rock<br />
integrity testing is 20.9 kPa /m resulting in a calculated closure pressure at 407.35 m GL TVD or<br />
8,514 kPa. The fracture limits of the Clearwater sand measured using injection/fall-off testing is<br />
6,969 kPa at 426.85 m GL TVD. (Section 4.4) It is proposed that 5,000 kPa will be used as<br />
MOP to ensure Clearwater sand formation stress limits are not exceeded.<br />
Zone<br />
Clearwater<br />
Shale<br />
Clearwater<br />
Sand<br />
Depth<br />
m GL<br />
TVD<br />
Gradient<br />
kPaa/m<br />
Closure<br />
Pressure<br />
(“CP”)<br />
kPaa<br />
MOP % of<br />
Closure<br />
Pressure<br />
80%<br />
factor<br />
(kpa)<br />
407.35 20.9 8514 59% 6,811<br />
Source<br />
Offsetting testing &<br />
Depth equal to MPP of<br />
perforated interval<br />
426.85 16.3 6969 72% 5,575 Birchwood FP_06_FO<br />
5.3.3 Potential Follow-up Processes for Improved Recovery<br />
Birchwood is monitoring several industry programs underway to investigate the use of noncondensable<br />
gases to provide additional in-situ bitumen recovery. It is expected that once<br />
steam injection is terminated or reaches uneconomic Steam Oil Ratios, a non-condensable gas<br />
may be injected into the steam chambers to maintain pressure. This activity is subject to ERCB<br />
approval; thus, Birchwood expects to apply for co-injection as required at a later date. During<br />
co-injection, bitumen production continues with operations maintained under the same control<br />
scheme employed in conventional SAGD. Bitumen production rates decline over time as the<br />
growth rate of the steam front slows under gas injection. Available steam is then directed to new<br />
SAGD well pairs.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 74
5.4 Reservoir Monitoring<br />
5.4.1 Temperature Measurement<br />
Sensors will be provided to monitor the down-hole operating temperatures in the well bore of<br />
each production and injection well. Fibre-optic temperature cables will be encased in 1” Inconel<br />
coiled tubing for insertion into each well to discretely measure temperature from the toe to the<br />
heel of each producer.<br />
5.4.2 Gas Blanket Pressure Measurement<br />
All wells are equipped with a blanket gas distribution header that will be used to feed a slow<br />
stream of blanket gas into the annulus of each well. The blanket gas will provide a slow<br />
downward sweep of the annulus to provide the following benefits during steam injection:<br />
1. The dry gas provides an insulation effect to substantially reduce heat loss from the<br />
steam injection tubing to the vertical region where formation heating is undesirable,<br />
2. Inhibits transient thermal stresses on the well bore casing and cement sheath,<br />
3. Prevents the accumulation of corrosive gases that could damage the well bore casing,<br />
4. The gas blanket in the injector will also prevent accumulation of corrosive fluids at shutdown<br />
of injection as steam condenses, causes a vacuum and refluxes produced fluids<br />
into the annulus,<br />
5. The gas blanket allows the bottom-hole pressure to be monitored in both producer and<br />
injector using a pressure transmitter on the annulus wing valve,<br />
6. Continuous monitoring of gas volumes and recoveries would also provide an early<br />
warning of intermediate casing failure.<br />
7. In the producing well the blanket gas will also provide gas lift for the short string.<br />
5.4.3 Micro-deformation Monitoring<br />
Micro-deformation monitoring seeks to precisely monitor rock deformation to infer hydraulicfracture<br />
orientation and geometry. Changes in reservoir volumes, such as those produced by<br />
fluid production, injection, and thermal processes such as CSS and SAGD generate unique and<br />
measurable patterns. These patterns can be measured at the earth’s surface with<br />
instrumentation, such as tilt-meters, InSAR, and GPS. In particular, tilt-meters are used to<br />
detect subtle deformation changes to help characterize out-of-zone fluid flow while it can still be<br />
mitigated. The monitoring purpose includes;<br />
1. Risk mitigation, specifically identifying, characterizing, and reporting on fluid migration<br />
before movements can occur,<br />
2. Improve production surveillance, and;<br />
3. Increase operational efficiency.<br />
Birchwood will use a combination of tilt-meters, and InSAR monitoring technology to take<br />
advantage of the strengths and mitigate the weaknesses of each respective technology. Realtime<br />
surveillance is employed to help ensure that Birchwood can identify and react quickly to<br />
undesirable fluid flow and migration.<br />
5.4.4 Observation Wells<br />
Vertical observation wells are planned in order to monitor the formation pressures and<br />
temperatures. The wells will be completed with fibre optic temperature sensors for monitoring<br />
allowing for distribution and retrieval of internal temperature monitoring equipment Birchwood<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 75
considers that at least one well per well pad leg (12 pairs) within the pattern is sufficient, in<br />
addition to at least one well completed to monitor reservoir pressures per pad (36 pairs).<br />
5.5 Recovery and Original Oil In Place<br />
5.5.1 Original Oil in Place (“OOIP”)<br />
Birchwood defines OOIP as the amount of bitumen resource originally in place from the oil<br />
water contact to the top of the formation, over the designated lease area. Birchwood uses OOIP<br />
as a benchmark for as well as an indicator of resource volumes amenable to recovery, and for<br />
the development planning, sequencing and field optimization of well-pairs. Potential recovery is<br />
based on the actual well-bore geometry (perforated portion of the producer horizontal section<br />
plus 50m at each end).<br />
5.5-1 Original Oil In Place Summary Table<br />
Area Acres<br />
Net Pay<br />
(m)<br />
average<br />
Sw<br />
average Porosity<br />
OOIP<br />
E3M3<br />
Potential<br />
Recovery<br />
E3M3<br />
Potential<br />
Recovery<br />
%<br />
Total Lease Area 1,140 23 35 33 24,037 15,384 64<br />
Resource<br />
Development Area<br />
<strong>Pilot</strong> <strong>Project</strong><br />
(10 wells)<br />
5.5.1.1 Gas Reserves<br />
787 24 35 33 18,301 11,713 64<br />
117 25 35 33 2,918 1,871 64<br />
Any gas recovered (exclusive of by-products of the SAGD process) is assumed to methane<br />
which is in solution in the bitumen at saturation conditions. No gas resource or reserve, either in<br />
place or recoverable, is assumed.<br />
5.5.2 Drilling Constraints and By-passed Pay<br />
The following list details the drilling constraints Birchwood will use for all of its well-pairs<br />
- directional changes in the horizontal section are typically planned at 6-9°/30 m to<br />
minimize drilling and completion difficulties such as liner placement,<br />
- a depth separation of 5 m is used between the injection well and production well,<br />
- the production well must be no closer than 2 meters from the bottom water,<br />
- proposed well profiles will likely be different from final drilled/surveyed trajectories,<br />
- surface casing will be set into a competent formation below the quaternary sands at<br />
approximately 160m,<br />
- a tangent section is built into the heel of the build section to allow for pumps at some<br />
future date,<br />
- horizontal wells will be terminated at the shore-line of Crane Lake to accommodate<br />
stakeholder concerns,<br />
- the combined well pad and CPF will be located approximately 750m from Crane Lake<br />
and approximately 2,000 m from residents to accommodate stakeholders concerns.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 76
5.5.2.2 By-passed pay - Crane/Moore Lake<br />
Solely as the result of concerns expressed by the public and residents during the consultation<br />
process, Birchwood has not included plans to access pay located beneath Crane/Moore Lake.<br />
Birchwood believes that the thick layer of Colorado shale and the Clearwater shale above the<br />
affected formation provide an impenetrable barrier between groundwater and the producing<br />
formation and there is virtually no risk of affecting the lake. The by-passed pay results in 1,049<br />
e3m3 of Original Oil In Place not being developed.<br />
5.5.2.3 By-passed pay – 100m boundary<br />
The 100m boundary normally used in the Cold Lake area, largely as a result of high impact CSS<br />
operations utilized to date results in 3,428 e3m3 of Original Oil In Place that is not able to be<br />
developed. Given the high degree of separation from CSS operations in the vicinity of this<br />
project, it is anticipated that this may be relaxed by offset leaseholders in the future. The primary<br />
rationale behind drilling the first 10 well pairs north is to allow only the lake area to constrain<br />
initial recovery. It is Birchwood’s intention to seek strategic partnerships with area operators to<br />
access the entire Clearwater play area and to limit boundaries as much as possible.<br />
5.5.3 Drainage Pattern Layouts<br />
The pattern of well pads and well-pairs was determined by jointly minimizing the SOR and<br />
maximizing the volume swept by the well pad proposed (Figure 5.5.3-1). Overall the elevation<br />
change within the resources development area is minimal. The pattern selected was designed<br />
to achieve a high number of wells from a single pad and minimize surface disturbances (Figure<br />
5.5.3-2).<br />
5.5.4 Well Length and Spacing<br />
Birchwood is expecting to use an inter-pair spacing of approximately 60 m for the initial<br />
implementation of the <strong>Project</strong>. This spacing is within the optimum range to balance the reserves<br />
developed by a single well-pair and the scheme CSOR. As the spacing is increased, oil<br />
recovered from a single well-pair may increase; however, depletion time also increases,<br />
resulting in additional heat loss and an increase in the CSOR. Additionally, analysis of the Orion<br />
I1P1 well pair, with 4 observation wells near well bore and a lengthy operating history would<br />
indicate that, for the Clearwater formation in this area, lateral heat transfer has been limited.<br />
The optimal horizontal well length will be verified by the different length wells utilized in the initial<br />
layout of the pilot phase. Birchwood estimates that the optimal well length is 800-1,000 m based<br />
on the limited additional time required to drill this section of the well, the absence of drilling<br />
problems with RSS tools, the pressure drop associated with the liner and tubing sizes, and the<br />
high initial cost of well tie-ins of up to 75% of well pair drilling and completion cost.<br />
5.6 Expected Well Performance<br />
The following table summarize the performance of the initial 10 wells proposed based upon<br />
numerical computer simulation and actual wellbore geometry.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 77
5.6.1 Typical SAGD Well-Pair Performance<br />
Parameter Unit Well-Pair A1 Well-Pair A10<br />
Well-Pair Length m 1,053 601<br />
Well-Pair Spacing m 60 60<br />
SAGD Pay Thickness m 25 25<br />
Sw % 35 35<br />
Porosity % 33 33<br />
Permeability D 0.5-3 0.5-3<br />
SAGD Operating Pressure Kpa 3,000-3,500 3,000-3,500<br />
Original Oil In Place M 3 364,513 208,242<br />
Expected Recovery M 3 233,597 133,451<br />
Expected Recovery % 64% 64%<br />
Expected Recovery time 9 yrs 9 yrs<br />
CSOR times 3.27 3.27<br />
5.6.2 SAGD Well-Pair A1 Expected Performance Data - 1,053m Effective length<br />
Year<br />
Average Rates (m3/d)<br />
Oil Water Steam<br />
Cumulative <strong>Volume</strong>s (m3)<br />
Oil Water Steam<br />
Recovery<br />
Factor<br />
(%)<br />
CSOR<br />
(m3/m3)<br />
1 111 243 314 40,352 88,793 114,716 11 2.84<br />
2 99 217 250 76,377 167,988 205,830 21 2.69<br />
3 93 223 235 110,374 249,368 291,651 30 2.64<br />
4 85 223 231 141,311 330,914 375,925 39 2.66<br />
5 66 223 224 165,250 412,239 457,552 45 2.77<br />
6 53 219 216 184,711 492,196 536,521 51 2.90<br />
7 48 214 211 202,405 570,224 613,701 56 3.03<br />
8 44 210 207 218,500 646,743 689,155 60 3.15<br />
9 41 206 203 233,597 721,779 763,126 64 3.27<br />
5.6.3 SAGD Well-Pair A10 Expected Performance Data - 603m Effective length<br />
Year<br />
Average Rates (m3/d) Cumulative <strong>Volume</strong>s (m3)<br />
Oil Water Steam Oil Water Steam<br />
Recovery<br />
Factor<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 78<br />
(%)<br />
CSOR<br />
(m3/m3)<br />
1 63 139 180 23,053 50,726 65,536 11 2.84<br />
2 56 124 143 43,633 95,970 117,588 21 2.69<br />
3 53 127 134 63,056 142,461 166,616 30 2.64<br />
4 48 128 132 80,729 189,047 214,761 39 2.66<br />
5 37 127 128 94,405 235,507 261,393 45 2.77<br />
6 30 125 124 105,523 281,185 306,508 51 2.90<br />
7 28 122 121 115,631 325,762 350,599 56 3.03<br />
8 25 120 118 124,826 369,476 393,705 60 3.15<br />
9 24 117 116 133,451 412,343 435,964 64 3.27
5.6.4 SAGD Well-Pairs Expected <strong>Pilot</strong> Performance Data<br />
Year<br />
Average Rates (m 3 /d) Cumulative <strong>Volume</strong>s (m 3 )<br />
Oil Water Steam Oil Water Steam<br />
Recovery<br />
Factor<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 79<br />
(%)<br />
CSOR<br />
(m3/m3)<br />
1 885 1,948 2,517 323,119 711,009 918,590 11 2.84<br />
2 790 1,737 1,999 611,591 1,345,168 1,648,189 21 2.69<br />
3 746 1,785 1,883 883,824 1,996,815 2,335,393 30 2.64<br />
4 679 1,789 1,849 1,131,552 2,649,792 3,010,219 39 2.66<br />
5 525 1,784 1,791 1,323,238 3,301,007 3,663,847 45 2.77<br />
6 427 1,754 1,723 1,479,074 3,941,259 4,296,194 51 2.90<br />
7 388 1,712 1,693 1,620,759 4,566,073 4,914,212 56 3.03<br />
8 353 1,679 1,655 1,749,640 5,178,799 5,518,409 60 3.15<br />
9 331 1,646 1,623 1,870,525 5,779,649 6,110,736 64 3.27<br />
5.6.5 Expected Individual Well Recovery<br />
Well ID<br />
East-<br />
West<br />
Effective<br />
HZ Well<br />
Length<br />
(M)<br />
Original<br />
Oil In<br />
Place<br />
(M3)<br />
Expected<br />
Recovery<br />
(M3)<br />
Recovery<br />
%<br />
A10 601 208,242 133,451 64%<br />
A9 655 226,954 145,442 64%<br />
A8 709 245,659 157,430 64%<br />
A7 763 264,371 169,421 64%<br />
A6 817 283,080 181,411 64%<br />
A5 871 301,792 193,402 64%<br />
A4 925 320,501 205,392 64%<br />
A3 979 339,213 217,383 64%<br />
A2 1,053 364,513 233,597 64%<br />
A1 1,053 364,513 233,597 64%<br />
Total M3 2,918,838 1,870,525 64%<br />
5.7 Results of Numerical Simulation Studies<br />
Numerical simulation, prepared by Dr. John K. Donnolly P.Eng, is being used to model the<br />
SAGD response of the Clearwater sandstone reservoir on Birchwood’s Cold Lake lease. The<br />
purpose of this work is to provide a design basis for a commercial development of the lease.<br />
The model is based on the petrophysical information available on four wells on Birchwood’s<br />
lease and three wells off the lease on surrounding properties. The properties associated with<br />
these seven wells are summarized in Appendix 5.7.A.<br />
5.7.1 Modeling Approach<br />
A three dimensional model was used to model the SAGD performance. The reservoir was<br />
divided into 40 one-meter layers. Porosity and initial water saturation were assigned to each<br />
layer based on petrophysical analysis of logs and cores. Inverse square distance weighting was<br />
used to interpolate the reservoir properties between the wells. An x-y Rectangular grid was<br />
placed over a portion of the lease as shown in Figure 5.7.1, where the x-direction is East-West<br />
and the y-direction is North-South. The horizontal production well was placed approximately two<br />
meters above the oil-water contact. The horizontal injection well was placed five meters above<br />
the production well. The heels of the two wells were located approximately midway between the
vertical wells 100/03-02-064-04W400 and 100/06-02-064-04W400 and runs North with the toes<br />
being approximately 100 meters from the lease boundary. The length of the well pair was<br />
approximately 994 meters. This is shown in Figure 5.7.2, which is a North South cross-section<br />
of the Property. Figure 5.7.3 shows an East-West cross-section.<br />
Figures 5.7.2 and Figure 5.7.3 also show that the reservoir quality is fairly uniform across the<br />
property based on water saturation. The other properties show the same result. A refined grid<br />
was placed normal to the wells and large sections of the grid were made inactive to reduce the<br />
active model size as shown in Figure 5.7.4.<br />
Oil properties were determined from measurements taken on samples obtained from the core.<br />
The solution gas was assumed to have the properties similar to methane. The reservoir was<br />
assumed to be initially at 2700 kPa at top of the Clearwater, which is at a depth of<br />
approximately 400 meters, and at a temperature of 16 degress C. The fluid and rock properties<br />
developed from literature values and are given in Appendix 5.7.B.<br />
The relative permeability curves used are typical of those used for other projects exploiting the<br />
Clearwater reservoir such as Husky’s Tucker project and Shell’s Orion project an example of<br />
which is shown in Figure 5.7.5.<br />
It was assumed that the wells would be completed with a 7 inch liner. A skin of 5 was used for<br />
the injector and 15 for the producer. In the model source/sink wells were used. For the first 90<br />
days heater wells were used to approximate steam circulation. After 90 days the wells were<br />
operated in SAGD mode. In the SAGD mode the following constraints were used: For the<br />
injector 95% quality steam was injected at a maximum pressure of 3500 kPa and a maximum<br />
rate of 600 m3 per day and the production well was restricted to a maximum steam production<br />
rate of 20 tonnes per day and minimum operating pressure of 2500 kPa.<br />
5.7.2 Model Production Performance<br />
The forecast oil production rate, water production rate and Instantaneous Steam Oil Ratio<br />
(ISOR) are shown in Figure 5.7.6 from the beginning of SAGD at 90 days to 6000 days (16.4<br />
years). During the first 1330 days (3.6 years) the oil rate starts at over 130 m3 per day (820<br />
BPD) and declines to 80 m3 per day (500 BPD) and the ISOR remains below three. After one<br />
year the development of the SAGD steam chamber is shown in Figure 5.7.7 which illustrates the<br />
phase saturations, the gas saturation, the oil saturation and the temperature distribution normal<br />
to the well pair. The same parameters along the well are shown in Figure 5.7.8. These Figures<br />
indicate that the steam chamber development is fairly uniform along the wells as well as normal<br />
to them. Figure 5.7.9 shows the same parameters at 1330 days. At this time the steam chamber<br />
has grown into the lower quality reservoir near the top of the Clearwater and is approaching the<br />
top of the formation.<br />
After the steam chamber reaches the top of the formation the oil production declines and the<br />
ISOR increases. After 3110 days (8.5 years) the oil production has declined to 40 m 3 per day<br />
(250 BPD) and the ISOR has climbed to five. At this point the steam has expanded to a width of<br />
60 meters as shown in Figure 5.7.10. Based on this it is recommended that SAGD be<br />
terminated when the steam chamber to a width of 60 meters and that a well spacing of 60<br />
meters employed.<br />
Figure 5.7.11 shows the cumulative oil production, water production, liquid production and<br />
Cumulative Steam Oil Ratio (CSOR). At 3110 days the cumulative oil production is 229,000 m 3<br />
(1.44 million barrels) and the CSOR is 3.01.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 80
Figure 5.5.3-1 CPF & SAGD Well Pair Layout<br />
T64<br />
T63<br />
Land Layer<br />
10<br />
3<br />
34<br />
Birchwood Lease Area<br />
Development Area<br />
Hydrography<br />
Major<br />
Minor Lake<br />
Minor River<br />
Pad Layout<br />
Wells<br />
Hz well path<br />
Faciity site<br />
Build Section<br />
Well heads<br />
<strong>Project</strong> Wells<br />
Kilometres<br />
R4 R3W4<br />
11<br />
2<br />
35<br />
0 0.5 1 1.5<br />
0 0.5 1<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 81<br />
12<br />
R4 R3W4<br />
1<br />
36<br />
T64<br />
T63<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
CPF & SAGD Horizontal Well Pairs<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/17<br />
Scale = 1:32493 <strong>Project</strong> : Cold Lake
Figure 5.5.3-2 SAGD Well Pair Layout & Net Pay<br />
T64<br />
T63<br />
Land Layer<br />
Wells<br />
3<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
Hydrography<br />
Major<br />
Minor Lake<br />
Minor River<br />
Pad Layout<br />
Hz Well Path<br />
Facility Site<br />
Build Section<br />
Well Head<br />
20.0m<br />
25.0m<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 82<br />
30.0m<br />
2<br />
Kilometres<br />
R4 R3W4<br />
30.0m<br />
35.0m<br />
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8<br />
0 0.25 0.5<br />
Miles<br />
25.0m<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
20.0m<br />
15.0m<br />
R4 R3W4<br />
1<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Initial SAGD Well Pairs<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/27<br />
Scale = 1:17500 <strong>Project</strong> : Cold Lake<br />
T64<br />
T63
Figure 5.5.3-2 Future Development SAGD Well Pair Layout<br />
T64<br />
T63<br />
Land Layer<br />
Wells<br />
3<br />
100m buffer<br />
34<br />
Birchwood Lease Area<br />
Development Area<br />
<strong>Project</strong> Wells<br />
Hydrography<br />
Major<br />
Minor Lake<br />
Minor River<br />
Pad Layout<br />
Hz Well Path<br />
Facility Site<br />
Build Section<br />
Well Head<br />
Future Hz Well Path<br />
Future Build Section<br />
100m buffer<br />
35<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 83<br />
2<br />
100m buffer<br />
Kilometres<br />
0 0.5 1 1.5<br />
R4 R3W4<br />
100m buffer<br />
R4 R3W4<br />
0 0.5 1<br />
Miles<br />
Datum: NAD 83 Spheroid: GRS 80<br />
<strong>Project</strong>ion: 6 degrees TM (Transverse Mercator)<br />
1<br />
36<br />
SAGE <strong>Pilot</strong> <strong>Project</strong><br />
Full Development Plan<br />
By : Jerry Babiuk, P.Geol Date : 2012/09/27<br />
Scale = 1:18000 <strong>Project</strong> : Cold Lake<br />
T64<br />
T63
Figure 5.7.1 Grid Layout 200x200x40<br />
Well Locations are indicated<br />
Locations K1‐K8 are Lease Boundary Corners<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 84
Figure 5.7.2 N - S Cross Section Showing Water Saturation and Horizontal Well Locations<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 85
Figure 5.7.3 E - W Cross Section Showing Water Saturation and Horizontal Well Locations<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 86
Figure 5.7.4 Refined Grid East‐West Cross‐Section Water Saturation<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 87
Figure 5.7.5 Gas-Liquid Relative Permeability<br />
Figure 5.7.5 Water-Oil Relative Permeability<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 88
Figure 5.7.6 Predicted Production Rates<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 89
Figure 5.7.7 Saturation and Temperature at 1.0 year X Section<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 90
Figure 5.7.8 Saturation and Temperature at 1.0 Year Well Length<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 91
Figure 5.7.9 Saturation and Temperature at 3.6 years X Section<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 92
Figure 5.7.10 Saturation and Temperature at 8.5 years X Section<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 93
Figure 5.7.11 Predicted Cumulative Production<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 94
Appendix 5.7.A1 Well Properties 100030206404W400<br />
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv<br />
M M M M avg avg avg mD mD<br />
404.00 398.78 156.74 1.00 1.00 0.5845 0.3365 0.1024 2364.80 1061.30<br />
405.00 399.78 155.74 2.00 1.00 0.4449 0.3632 0.1498 2610.70 1109.84<br />
406.00 400.78 154.74 3.00 1.00 0.4664 0.3895 0.1205 2879.34 1266.19<br />
407.00 401.78 153.74 4.00 1.00 0.4358 0.3818 0.1391 2798.21 1204.42<br />
408.00 402.78 152.74 5.00 1.00 0.4549 0.3830 0.1130 2810.43 1246.39<br />
409.00 403.78 151.74 6.00 1.00 0.4507 0.3769 0.1186 2747.99 1211.09<br />
410.00 404.78 150.74 7.00 1.00 0.4684 0.3678 0.1232 2656.25 1164.52<br />
411.00 405.78 149.74 8.00 1.00 0.5042 0.3436 0.2209 2428.03 945.85<br />
412.00 406.78 148.74 9.00 1.00 0.3832 0.3863 0.0495 2845.49 1352.32<br />
413.00 407.78 147.74 10.00 1.00 0.3239 0.3781 0.0000 2760.18 1380.09<br />
414.00 408.78 146.74 11.00 1.00 0.2842 0.3963 0.0000 2952.43 1476.22<br />
415.00 409.78 145.74 12.00 1.00 0.2461 0.3933 0.0000 2919.90 1459.95<br />
416.00 410.78 144.74 13.00 1.00 0.2481 0.4225 0.0000 3255.03 1627.52<br />
417.00 411.78 143.74 14.00 1.00 0.3362 0.3841 0.0403 2821.85 1354.10<br />
418.00 412.78 142.74 15.00 1.00 0.4397 0.3211 0.2596 2233.26 826.70<br />
419.00 413.78 141.74 16.00 1.00 0.4105 0.3674 0.1186 2652.57 1169.00<br />
420.00 414.78 140.74 17.00 1.00 0.2534 0.4230 0.0000 3260.98 1630.49<br />
421.00 415.78 139.74 18.00 1.00 0.2417 0.3942 0.0000 2929.98 1464.99<br />
422.00 416.78 138.74 19.00 1.00 0.2389 0.3901 0.0000 2886.16 1443.08<br />
423.00 417.78 137.74 20.00 1.00 0.2378 0.4101 0.0000 3108.12 1554.06<br />
424.00 418.78 136.74 21.00 1.00 0.2463 0.4039 0.0000 3038.04 1519.02<br />
425.00 419.78 135.74 22.00 1.00 0.2738 0.3945 0.0000 2932.75 1466.38<br />
426.00 420.78 134.74 23.00 1.00 0.3017 0.4132 0.0000 3144.67 1572.33<br />
427.00 421.78 133.74 24.00 1.00 0.3808 0.4079 0.0000 3083.44 1541.72<br />
428.00 422.78 132.74 25.00 1.00 0.6172 0.3801 0.0000 2780.87 1390.43<br />
429.00 423.78 131.74 26.00 1.00 0.7924 0.3744 0.0000 2722.49 1361.24<br />
430.00 424.78 130.74 27.00 1.00 0.7708 0.3998 0.0000 2991.49 1495.75<br />
431.00 425.78 129.74 28.00 1.00 0.7918 0.3943 0.0000 2931.46 1465.73<br />
432.00 426.78 128.74 29.00 1.00 0.9500 0.3037 0.0000 2092.85 1046.42<br />
433.00 427.78 127.74 30.00 1.00 0.8531 0.3845 0.0000 2826.43 1413.21<br />
434.00 428.78 126.74 31.00 1.00 0.9043 0.3885 0.0000 2868.95 1434.48<br />
435.00 429.78 125.74 32.00 1.00 0.9255 0.3864 0.0000 2846.36 1423.18<br />
436.00 430.78 124.74 33.00 1.00 0.9115 0.3949 0.0000 2937.31 1468.66<br />
437.00 431.78 123.74 34.00 1.00 0.9293 0.3889 0.0000 2872.73 1436.37<br />
438.00 432.78 122.74 35.00 1.00 0.9091 0.3962 0.0000 2951.74 1475.87<br />
439.00 433.78 121.74 36.00 1.00 0.8852 0.4039 0.0000 3037.63 1518.81<br />
440.00 434.78 120.74 37.00 1.00 0.8816 0.4056 0.0000 3056.37 1528.18<br />
441.00 435.78 119.74 38.00 1.00 0.8981 0.3991 0.0000 2983.32 1491.66<br />
442.00 436.78 118.74 39.00 1.00 0.9135 0.3923 0.0000 2909.66 1454.83<br />
443.00 437.78 117.74 40.00 1.00 0.9415 0.3797 0.0000 2776.17 1388.09<br />
444.00 438.78 116.74 41.00 1.00 0.9286 0.3837 0.0002 2818.04 1408.79<br />
445.00 439.78 115.74 42.00 1.00 0.9216 0.3891 0.0000 2875.45 1437.73<br />
446.00 440.78 114.74 43.00 1.00 0.9126 0.3978 0.0124 2969.24 1466.26<br />
447.00 441.78 113.74 44.00 1.00 0.9933 0.2137 0.5025 1498.28 372.73<br />
448.00 442.78 112.74 45.00 1.00 1.0000 0.1682 0.5580 1265.23 279.59<br />
449.00 443.78 111.74 46.00 1.00 1.0000 0.1642 0.5356 1246.27 289.39<br />
450.00 444.78 110.74 47.00 1.00 1.0000 0.2057 0.3648 1454.20 461.85<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 95
Appendix 5.7.A2 Well Properties 100060206404W400<br />
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSHL Kh Kv<br />
M M M M avg avg avg mD mD<br />
412.00 397.13 155.09 1.00 1.00 0.5363 0.3035 0.26 2091.22 777.07<br />
413.00 398.13 154.09 2.00 1.00 0.4786 0.3301 0.21 2309.22 915.85<br />
414.00 399.13 153.09 3.00 1.00 0.4658 0.3535 0.12 2518.94 1111.94<br />
415.00 400.13 152.09 4.00 1.00 0.4768 0.3315 0.24 2320.79 879.98<br />
416.00 401.13 151.09 5.00 1.00 0.4521 0.3382 0.21 2379.55 940.53<br />
417.00 402.13 150.09 6.00 1.00 0.4661 0.3243 0.25 2259.59 843.94<br />
418.00 403.13 149.09 7.00 1.00 0.5080 0.2903 0.32 1991.58 681.36<br />
419.00 404.13 148.09 8.00 1.00 0.5080 0.3095 0.25 2138.95 805.99<br />
420.00 405.13 147.09 9.00 1.00 0.4303 0.3319 0.24 2324.56 885.55<br />
421.00 406.13 146.09 10.00 1.00 0.3396 0.3760 0.08 2738.81 1259.26<br />
422.00 407.13 145.09 11.00 1.00 0.3142 0.3986 0.05 2977.88 1417.27<br />
423.00 408.13 144.09 12.00 1.00 0.3222 0.3848 0.09 2829.68 1293.84<br />
424.00 409.13 143.09 13.00 1.00 0.3380 0.3795 0.04 2774.58 1329.59<br />
425.00 410.13 142.09 14.00 1.00 0.3712 0.3266 0.22 2278.99 885.30<br />
426.00 411.13 141.09 15.00 1.00 0.4589 0.2760 0.40 1888.50 571.05<br />
427.00 412.13 140.09 16.00 1.00 0.3733 0.3794 0.08 2772.80 1271.74<br />
428.00 413.13 139.09 17.00 1.00 0.2747 0.4037 0.01 3035.68 1499.39<br />
429.00 414.13 138.09 18.00 1.00 0.2733 0.3798 0.00 2777.49 1388.74<br />
430.00 415.13 137.09 19.00 1.00 0.2540 0.3939 0.00 2926.42 1461.13<br />
431.00 416.13 136.09 20.00 1.00 0.2656 0.3935 0.00 2921.87 1460.94<br />
432.00 417.13 135.09 21.00 1.00 0.3077 0.3818 0.00 2797.73 1398.87<br />
433.00 418.13 134.09 22.00 1.00 0.3395 0.3883 0.00 2866.53 1433.26<br />
434.00 419.13 133.09 23.00 1.00 0.4831 0.3945 0.00 2933.05 1466.52<br />
435.00 420.13 132.09 24.00 1.00 0.7083 0.3907 0.00 2891.72 1445.86<br />
436.00 421.13 131.09 25.00 1.00 0.7569 0.3928 0.00 2914.97 1457.48<br />
437.00 422.13 130.09 26.00 1.00 0.7797 0.3917 0.00 2902.59 1451.29<br />
438.00 423.13 129.09 27.00 1.00 0.8219 0.3872 0.01 2855.12 1414.75<br />
439.00 424.13 128.09 28.00 1.00 0.8972 0.3843 0.00 2823.75 1409.53<br />
440.00 425.13 127.09 29.00 1.00 0.9540 0.3690 0.07 2667.58 1245.32<br />
441.00 426.13 126.09 30.00 1.00 0.9502 0.3753 0.04 2731.15 1305.87<br />
442.00 427.13 125.09 31.00 1.00 0.9305 0.3852 0.02 2833.12 1393.15<br />
443.00 428.13 124.09 32.00 1.00 0.9160 0.3942 0.00 2930.08 1462.73<br />
444.00 429.13 123.09 33.00 1.00 0.9326 0.3841 0.02 2821.56 1378.45<br />
445.00 430.13 122.09 34.00 1.00 0.9625 0.3730 0.03 2708.27 1314.78<br />
446.00 431.13 121.09 35.00 1.00 0.9505 0.3807 0.02 2786.60 1359.05<br />
447.00 432.13 120.09 36.00 1.00 0.9474 0.3789 0.06 2768.21 1301.59<br />
448.00 433.13 119.09 37.00 1.00 0.9728 0.3663 0.10 2641.66 1187.87<br />
449.00 434.13 118.09 38.00 1.00 0.9663 0.3806 0.02 2785.85 1358.96<br />
450.00 435.13 117.09 39.00 1.00 0.9613 0.3866 0.00 2848.09 1424.05<br />
451.00 436.13 116.09 40.00 1.00 0.9479 0.3931 0.00 2917.63 1458.81<br />
452.00 437.13 115.09 41.00 1.00 0.9407 0.3937 0.03 2925.03 1415.04<br />
453.00 438.13 114.09 42.00 1.00 0.9367 0.3976 0.01 2966.93 1470.14<br />
454.00 439.13 113.09 43.00 1.00 0.9555 0.3885 0.00 2868.66 1427.56<br />
455.00 440.13 112.09 44.00 1.00 0.9533 0.3883 0.01 2866.33 1417.53<br />
456.00 441.13 111.09 45.00 0.90 0.9791 0.3763 0.05 2741.31 1295.91<br />
456.90 442.13 110.19 46.00 1.10 0.9995 0.2134 0.51 1496.46 366.33<br />
458.00 443.13 109.09 47.00 1.00 1.0000 0.0065 0.96 693.60 12.69<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 96
Appendix 5.7.A3 Well Properties 100010306404W400<br />
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv<br />
M M M M avg avg avg mD mD<br />
399.00 399.00 156.96 1.00 1.00 0.5585 0.2535 0.3580 1736.72 557.50<br />
400.00 400.00 155.96 2.00 1.00 0.5199 0.3071 0.2158 2119.96 831.28<br />
401.00 401.00 154.96 3.00 1.00 0.5097 0.3160 0.2666 2190.88 803.40<br />
402.00 402.00 153.96 4.00 1.00 0.4855 0.3263 0.2410 2276.68 864.04<br />
403.00 403.00 152.96 5.00 1.00 0.4444 0.3435 0.1301 2426.64 1055.51<br />
404.00 404.00 151.96 6.00 1.00 0.5090 0.2867 0.1312 1965.31 853.74<br />
405.00 405.00 150.96 7.00 1.00 0.4486 0.3325 0.2268 2329.91 900.71<br />
406.00 406.00 149.96 8.00 1.00 0.4731 0.3418 0.2130 2411.84 949.10<br />
407.00 407.00 148.96 9.00 1.00 0.5280 0.3115 0.2788 2154.69 777.02<br />
408.00 408.00 147.96 10.00 1.00 0.5040 0.3212 0.2625 2234.01 823.79<br />
409.00 409.00 146.96 11.00 1.00 0.4357 0.3400 0.2036 2395.19 953.79<br />
410.00 410.00 145.96 12.00 1.00 0.3758 0.3583 0.0287 2564.37 1245.41<br />
411.00 411.00 144.96 13.00 1.00 0.5065 0.2795 0.0000 1912.84 956.42<br />
412.00 412.00 143.96 14.00 1.00 0.4197 0.3412 0.1138 2405.74 1065.93<br />
413.00 413.00 142.96 15.00 1.00 0.5334 0.2843 0.3369 1947.27 645.63<br />
414.00 414.00 141.96 16.00 1.00 0.4991 0.3321 0.2374 2326.37 887.02<br />
415.00 415.00 140.96 17.00 1.00 0.3258 0.3890 0.0207 2874.19 1407.32<br />
416.00 416.00 139.96 18.00 1.00 0.2741 0.3952 0.0012 2940.59 1468.56<br />
417.00 417.00 138.96 19.00 1.00 0.2611 0.3991 0.0006 2984.23 1491.23<br />
418.00 418.00 137.96 20.00 1.00 0.2660 0.3874 0.0208 2856.47 1398.54<br />
419.00 419.00 136.96 21.00 1.00 0.2835 0.3732 0.0000 2709.82 1354.91<br />
420.00 420.00 135.96 22.00 1.00 0.3096 0.3809 0.0000 2788.58 1394.29<br />
421.00 421.00 134.96 23.00 1.00 0.3521 0.3824 0.0000 2804.74 1402.37<br />
422.00 422.00 133.96 24.00 1.00 0.4856 0.3842 0.0000 2823.28 1411.64<br />
423.00 423.00 132.96 25.00 1.00 0.7180 0.3746 0.0075 2723.68 1351.60<br />
424.00 424.00 131.96 26.00 1.00 0.7714 0.3539 0.0238 2522.86 1231.35<br />
425.00 425.00 130.96 27.00 1.00 0.9763 0.1149 0.0000 1037.52 518.76<br />
426.00 426.00 129.96 28.00 1.00 1.0000 0.0630 0.0000 855.66 427.83<br />
427.00 427.00 128.96 29.00 1.00 0.8594 0.3065 0.0065 2115.24 1050.70<br />
428.00 428.00 127.96 30.00 1.00 0.8674 0.3776 0.0183 2754.31 1352.00<br />
429.00 429.00 126.96 31.00 1.00 0.9321 0.3767 0.0130 2745.86 1355.09<br />
430.00 430.00 125.96 32.00 1.00 0.9681 0.3700 0.0000 2678.06 1339.03<br />
431.00 431.00 124.96 33.00 1.00 0.9688 0.3749 0.0012 2727.46 1362.14<br />
432.00 432.00 123.96 34.00 1.00 0.9782 0.3681 0.0267 2659.48 1294.29<br />
433.00 433.00 122.96 35.00 1.00 0.9728 0.3679 0.0196 2656.79 1302.41<br />
434.00 434.00 121.96 36.00 1.00 0.9902 0.3671 0.0164 2648.99 1302.82<br />
435.00 435.00 120.96 37.00 1.00 0.9788 0.3709 0.0009 2686.76 1342.18<br />
436.00 436.00 119.96 38.00 1.00 0.9726 0.3720 0.0056 2698.13 1341.51<br />
437.00 437.00 118.96 39.00 1.00 0.9770 0.3770 0.0329 2748.55 1329.11<br />
438.00 438.00 117.96 40.00 1.00 0.9650 0.3840 0.0224 2821.27 1378.99<br />
439.00 439.00 116.96 41.00 1.00 0.9821 0.3782 0.0248 2760.37 1345.95<br />
440.00 440.00 115.96 42.00 1.00 0.9571 0.3890 0.0071 2873.90 1426.72<br />
441.00 441.00 114.96 43.00 1.00 0.9663 0.3837 0.0289 2817.37 1368.02<br />
442.00 442.00 113.96 44.00 1.00 0.9935 0.3642 0.0640 2620.77 1226.57<br />
443.00 443.00 112.96 45.00 1.00 0.9934 0.3653 0.0499 2631.95 1250.32<br />
444.00 444.00 111.96 46.00 1.00 0.9963 0.3708 0.0303 2686.03 1302.32<br />
445.00 445.00 110.96 47.00 1.00 0.9546 0.3954 0.0010 2942.87 1470.03<br />
446.00 446.00 109.96 48.00 1.00 0.9783 0.3804 0.0360 2783.50 1341.63<br />
447.00 447.00 108.96 49.00 1.00 0.9850 0.3762 0.0312 2740.39 1327.49<br />
453.00 453.00 102.96 55.00 1.00 0.9927 0.3633 0.0216 2612.20 1277.89<br />
454.00 454.00 101.96 56.00 1.00 0.9965 0.3588 0.0468 2569.22 1224.48<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 97
Appendix 5.7.A4 Well Properties 100050106404W400<br />
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv<br />
M M M M avg avg avg mD mD<br />
401.20 397.54 155.50 1.00 1.00 0.5012 0.2834 0.3035 1940.96 675.91<br />
402.20 398.54 154.50 2.00 1.00 0.4792 0.3486 0.1560 2473.15 1043.69<br />
403.20 399.54 153.50 3.00 1.00 0.5436 0.3547 0.1475 2529.94 1078.38<br />
404.20 400.54 152.50 4.00 1.00 0.5193 0.3546 0.1286 2528.75 1101.73<br />
405.20 401.54 151.50 5.00 1.00 0.4695 0.3535 0.1283 2518.35 1097.56<br />
406.20 402.54 150.50 6.00 1.00 0.4832 0.3589 0.0538 2569.74 1215.71<br />
407.20 403.54 149.50 7.00 1.00 0.4618 0.3271 0.0139 2283.38 1125.78<br />
408.20 404.54 148.50 8.00 1.00 0.4416 0.3557 0.0817 2539.71 1166.05<br />
409.20 405.54 147.50 9.00 1.00 0.4323 0.3785 0.0798 2764.29 1271.89<br />
410.20 406.54 146.50 10.00 1.00 0.4201 0.3671 0.1153 2649.62 1172.06<br />
411.20 407.54 145.50 11.00 1.00 0.4344 0.3501 0.1541 2486.98 1051.90<br />
412.20 408.54 144.50 12.00 1.00 0.4373 0.4028 0.0435 3025.65 1446.96<br />
413.20 409.54 143.50 13.00 1.00 0.3968 0.3906 0.0259 2890.65 1407.84<br />
414.20 410.54 142.50 14.00 1.00 0.3900 0.3582 0.0081 2562.72 1271.04<br />
415.20 411.54 141.50 15.00 1.00 0.4861 0.3152 0.1282 2184.60 952.32<br />
416.20 412.54 140.50 16.00 1.00 0.3333 0.3679 0.1003 2656.79 1195.14<br />
417.20 413.54 139.50 17.00 1.00 0.3127 0.3814 0.0000 2793.86 1396.93<br />
418.20 414.54 138.50 18.00 1.00 0.2952 0.3938 0.0000 2925.23 1462.61<br />
419.20 415.54 137.50 19.00 1.00 0.3192 0.3871 0.0000 2853.39 1426.69<br />
420.20 416.54 136.50 20.00 1.00 0.3463 0.3981 0.0000 2973.16 1486.58<br />
421.20 417.54 135.50 21.00 1.00 0.3957 0.3935 0.0000 2922.27 1461.13<br />
422.20 418.54 134.50 22.00 1.00 0.6379 0.3946 0.0000 2933.94 1466.97<br />
423.20 419.54 133.50 23.00 1.00 0.7611 0.3998 0.0000 2992.10 1496.05<br />
424.20 420.54 132.50 24.00 1.00 0.8048 0.3889 0.0000 2873.32 1436.66<br />
425.20 421.54 131.50 25.00 1.00 0.8124 0.3844 0.0032 2825.09 1408.06<br />
426.20 422.54 130.50 26.00 1.00 0.8181 0.3812 0.0000 2791.41 1395.70<br />
427.20 423.54 129.50 27.00 1.00 0.8656 0.3726 0.0000 2704.33 1352.17<br />
428.20 424.54 128.50 28.00 1.00 0.8932 0.3644 0.0291 2622.45 1273.13<br />
429.20 425.54 127.50 29.00 1.00 0.8670 0.3760 0.0099 2737.98 1355.41<br />
430.20 426.54 126.50 30.00 1.00 0.8276 0.3504 0.0000 2489.50 1244.75<br />
431.20 427.54 125.50 31.00 1.00 0.8847 0.3134 0.0268 2170.33 1056.10<br />
432.20 428.54 124.50 32.00 1.00 0.9779 0.2169 0.4003 1515.80 454.53<br />
433.20 429.54 123.50 33.00 1.00 0.8837 0.3198 0.1365 2222.49 959.56<br />
434.20 430.54 122.50 34.00 1.00 0.8011 0.3832 0.0252 2812.99 1371.05<br />
435.20 431.54 121.50 35.00 1.00 0.8249 0.3669 0.0322 2647.56 1281.11<br />
436.20 432.54 120.50 36.00 1.00 0.8783 0.2757 0.1244 1886.08 825.75<br />
437.20 433.54 119.50 37.00 1.00 0.9021 0.2576 0.2291 1763.26 679.63<br />
438.20 434.54 118.50 38.00 1.00 0.8676 0.2491 0.3319 1708.84 570.81<br />
439.20 435.54 117.50 39.00 1.00 0.8972 0.1234 0.6549 1071.04 184.81<br />
440.20 436.54 116.50 40.00 1.00 0.9713 0.0061 0.9796 692.60 7.07<br />
441.20 437.54 115.50 41.00 1.00 1.0000 0.0000 1.0000 677.05 0.00<br />
442.20 438.54 114.50 42.00 1.00 0.9922 0.0059 0.9787 691.94 7.35<br />
443.20 439.54 113.50 43.00 1.00 0.8820 0.0805 0.7078 913.04 133.37<br />
444.20 440.54 112.50 44.00 1.00 0.8873 0.1819 0.4056 1331.01 395.55<br />
445.20 441.54 111.50 45.00 1.00 0.7620 0.2712 0.0884 1854.92 845.52<br />
446.20 442.54 110.50 46.00 1.00 0.7698 0.3121 0.0006 2159.80 1079.28<br />
447.20 443.54 109.50 47.00 1.00 0.8633 0.3314 0.0035 2319.93 1155.92<br />
448.20 444.54 108.50 48.00 1.00 0.8581 0.3456 0.0006 2445.90 1222.25<br />
449.20 445.54 107.50 49.00 1.00 0.7717 0.2028 0.4948 1438.56 363.39<br />
450.20 446.54 106.50 50.00 1.00 0.6194 0.0506 0.9121 817.27 35.90<br />
451.20 447.54 105.50 51.00 1.00 0.6758 0.0542 0.8890 828.27 45.99<br />
452.20 448.54 104.50 52.00 1.00 0.9609 0.0047 0.9927 689.10 2.52<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 98
Appendix 5.7.A5 Well Properties 102062606304W400<br />
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv<br />
M M M M avg avg avg mD mD<br />
381.00 413.04 171.00 1.00 1.00 0.8904 0.2600 0.3073 1779.30 616.27<br />
382.00 414.04 170.00 2.00 1.00 0.7428 0.3093 0.1878 2137.00 867.82<br />
383.00 415.04 169.00 3.00 1.00 0.6460 0.3208 0.1733 2230.47 922.01<br />
384.00 416.04 168.00 4.00 1.00 0.5467 0.3402 0.1280 2397.38 1045.21<br />
385.00 417.04 167.00 5.00 1.00 0.5146 0.3415 0.1326 2408.67 1044.67<br />
386.00 418.04 166.00 6.00 1.00 0.5357 0.3341 0.1293 2343.80 1020.33<br />
387.00 419.04 165.00 7.00 1.00 0.5845 0.3087 0.2030 2132.17 849.66<br />
388.00 420.04 164.00 8.00 1.00 0.5366 0.3239 0.1606 2256.08 946.90<br />
389.00 421.04 163.00 9.00 1.00 0.4789 0.3126 0.1529 2163.89 916.54<br />
390.00 422.04 162.00 10.00 1.00 0.4151 0.3559 0.0632 2541.68 1190.57<br />
391.00 423.04 161.00 11.00 1.00 0.3436 0.3644 0.0000 2623.25 1311.63<br />
392.00 424.04 160.00 12.00 1.00 0.3480 0.3643 0.0000 2621.83 1310.92<br />
393.00 425.04 159.00 13.00 1.00 0.3849 0.3401 0.0090 2396.33 1187.37<br />
394.00 426.04 158.00 14.00 1.00 0.4328 0.2870 0.1162 1967.30 869.35<br />
395.00 427.04 157.00 15.00 1.00 0.4408 0.3192 0.1891 2217.39 898.99<br />
396.00 428.04 156.00 16.00 1.00 0.4794 0.3317 0.1626 2322.44 972.35<br />
397.00 429.04 155.00 17.00 1.00 0.5420 0.2941 0.1755 2019.50 832.53<br />
398.00 430.04 154.00 18.00 1.00 0.4076 0.3409 0.0963 2403.87 1086.23<br />
399.00 431.04 153.00 19.00 1.00 0.3929 0.3533 0.0584 2516.81 1184.90<br />
400.00 432.04 152.00 20.00 1.00 0.5178 0.2447 0.0442 1681.01 803.38<br />
401.00 433.04 151.00 21.00 1.00 0.3469 0.3515 0.1139 2499.70 1107.51<br />
402.00 434.04 150.00 22.00 1.00 0.3797 0.3401 0.1316 2396.08 1040.39<br />
403.00 435.04 149.00 23.00 1.00 0.4768 0.3489 0.0639 2475.74 1158.74<br />
404.00 436.04 148.00 24.00 1.00 0.5083 0.3475 0.0365 2462.98 1186.60<br />
405.00 437.04 147.00 25.00 1.00 0.5038 0.3459 0.0523 2448.13 1160.09<br />
406.00 438.04 146.00 26.00 1.00 0.4959 0.3318 0.0983 2323.38 1047.50<br />
407.00 439.04 145.00 27.00 1.00 0.5269 0.3363 0.0914 2363.12 1073.60<br />
408.00 440.04 144.00 28.00 1.00 0.5449 0.3431 0.0748 2423.11 1120.99<br />
409.00 441.04 143.00 29.00 1.00 0.5165 0.3168 0.1656 2197.93 916.93<br />
410.00 442.04 142.00 30.00 1.00 0.4841 0.3349 0.1136 2350.54 1041.79<br />
411.00 443.04 141.00 31.00 1.00 0.4751 0.3307 0.1506 2313.90 982.66<br />
412.00 444.04 140.00 32.00 1.00 0.5180 0.3278 0.1693 2289.64 950.96<br />
413.00 445.04 139.00 33.00 1.00 0.5470 0.3024 0.2769 2083.04 753.17<br />
414.00 446.04 138.00 34.00 1.00 0.6000 0.2836 0.2942 1942.80 685.58<br />
415.00 447.04 137.00 35.00 1.00 0.6376 0.2985 0.1351 2053.21 887.91<br />
416.00 448.04 136.00 36.00 1.00 0.7112 0.3025 0.0736 2083.46 965.11<br />
417.00 449.04 135.00 37.00 1.00 0.7903 0.3109 0.1605 2149.97 902.40<br />
418.00 450.04 134.00 38.00 1.00 0.9684 0.2418 0.3258 1663.16 560.61<br />
419.00 451.04 133.00 39.00 1.00 0.9858 0.1787 0.4588 1315.54 356.01<br />
420.00 452.04 132.00 40.00 1.00 0.9108 0.0406 0.8321 787.42 66.11<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 99
Appendix 5.7.A6 Well Properties 102062406304W400<br />
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv<br />
M M M M avg avg avg mD mD<br />
421.90 401.67 159.63 1.00 1.00 0.8490 0.1815 0.5291 1329.34 312.97<br />
422.90 402.67 158.63 2.00 1.00 0.5801 0.2969 0.2366 2040.69 778.88<br />
423.90 403.67 157.63 3.00 1.00 0.5177 0.3478 0.1473 2465.73 1051.32<br />
424.90 404.67 156.63 4.00 1.00 0.4640 0.3953 0.0070 2942.38 1460.92<br />
425.90 405.67 155.63 5.00 1.00 0.4293 0.4015 0.0000 3010.76 1505.38<br />
426.90 406.67 154.63 6.00 1.00 0.4276 0.3759 0.0000 2737.52 1368.76<br />
427.90 407.67 153.63 7.00 1.00 0.4123 0.3820 0.0000 2799.81 1399.91<br />
428.90 408.67 152.63 8.00 1.00 0.3947 0.3767 0.0000 2745.67 1372.84<br />
429.90 409.67 151.63 9.00 1.00 0.3955 0.3823 0.0000 2803.32 1401.66<br />
430.90 410.67 150.63 10.00 1.00 0.3746 0.3903 0.0000 2887.43 1443.71<br />
431.90 411.67 149.63 11.00 1.00 0.3443 0.4094 0.0000 3100.04 1550.02<br />
432.90 412.67 148.63 12.00 1.00 0.3903 0.3561 0.0000 2543.23 1271.61<br />
433.90 413.67 147.63 13.00 1.00 0.3781 0.3454 0.0000 2444.33 1222.16<br />
434.90 414.67 146.63 14.00 1.00 0.3551 0.3890 0.0000 2874.38 1437.19<br />
435.90 415.67 145.63 15.00 1.00 0.3541 0.3957 0.0000 2945.86 1472.93<br />
436.90 416.67 144.63 16.00 1.00 0.3418 0.4030 0.0046 3026.87 1506.47<br />
437.90 417.67 143.63 17.00 1.00 0.3656 0.3790 0.0024 2769.24 1381.26<br />
438.90 418.67 142.63 18.00 1.00 0.3463 0.3904 0.0000 2889.18 1444.59<br />
439.90 419.67 141.63 19.00 1.00 0.3444 0.4013 0.0000 3008.83 1504.41<br />
440.90 420.67 140.63 20.00 1.00 0.3700 0.4008 0.0000 3002.83 1501.42<br />
441.90 421.67 139.63 21.00 1.00 0.3804 0.3865 0.0000 2847.80 1423.90<br />
442.90 422.67 138.63 22.00 1.00 0.3873 0.3928 0.0000 2914.38 1457.19<br />
443.90 423.67 137.63 23.00 1.00 0.4310 0.3868 0.0000 2850.88 1425.44<br />
444.90 424.67 136.63 24.00 1.00 0.4784 0.3802 0.0035 2781.81 1386.06<br />
445.90 425.67 135.63 25.00 1.00 0.5040 0.3854 0.0000 2835.80 1417.90<br />
446.90 426.67 134.63 26.00 1.00 0.5241 0.3755 0.0248 2733.73 1333.02<br />
447.90 427.67 133.63 27.00 1.00 0.5429 0.3830 0.0029 2811.00 1401.44<br />
448.90 428.67 132.63 28.00 1.00 0.5436 0.3965 0.0627 2954.63 1384.67<br />
449.90 429.67 131.63 29.00 1.00 0.5974 0.3803 0.0541 2782.75 1316.10<br />
450.90 430.67 130.63 30.00 1.00 0.7168 0.3848 0.0000 2829.10 1414.55<br />
451.90 431.67 129.63 31.00 1.00 0.8029 0.3808 0.0000 2787.54 1393.77<br />
452.90 432.67 128.63 32.00 1.00 0.7774 0.3711 0.0156 2689.12 1323.52<br />
453.90 433.67 127.63 33.00 1.00 0.7372 0.3499 0.1441 2485.63 1063.68<br />
454.90 434.67 126.63 34.00 1.00 0.8346 0.3231 0.1793 2249.31 923.00<br />
455.90 435.67 125.63 35.00 1.00 0.9153 0.2739 0.3091 1873.44 647.14<br />
456.90 436.67 124.63 36.00 1.00 0.8893 0.2968 0.2787 2040.14 735.79<br />
457.90 437.67 123.63 37.00 1.00 0.8825 0.3267 0.1479 2279.76 971.26<br />
458.90 438.67 122.63 38.00 1.00 0.9404 0.2715 0.3273 1856.87 624.54<br />
459.90 439.67 121.63 39.00 1.00 0.8972 0.2824 0.3066 1933.76 670.42<br />
460.90 440.67 120.63 40.00 1.00 0.9143 0.2960 0.2048 2034.29 808.82<br />
461.90 441.67 119.63 41.00 1.00 0.8495 0.3589 0.0471 2570.18 1224.57<br />
462.90 442.67 118.63 42.00 1.00 0.9376 0.2591 0.3685 1773.48 559.94<br />
463.90 443.67 117.63 43.00 2.00 0.9977 0.1844 0.5374 1343.66 310.76<br />
465.90 444.67 115.63 44.00 1.00 0.9804 0.2019 0.5084 1433.66 352.40<br />
466.90 445.67 114.63 45.00 1.00 0.9657 0.2179 0.4532 1521.44 415.93<br />
467.90 446.67 113.63 46.00 1.00 0.9929 0.1781 0.5256 1312.39 311.32<br />
468.90 447.67 112.63 47.00 1.00 0.9652 0.2026 0.4895 1437.78 366.99<br />
469.90 448.67 111.63 48.00 1.00 0.9947 0.2095 0.2683 1474.98 539.61<br />
470.90 449.67 110.63 49.00 1.00 0.9245 0.2485 0.2857 1704.63 608.78<br />
471.90 450.67 109.63 50.00 1.00 0.9483 0.2253 0.4484 1564.23 431.45<br />
472.90 451.67 108.63 51.00 1.00 0.9869 0.2243 0.3876 1558.06 477.11<br />
473.90 452.67 107.63 52.00 1.00 0.9736 0.2501 0.3094 1715.08 592.26<br />
474.90 453.67 106.63 53.00 1.00 0.9026 0.3002 0.1917 2066.36 835.15<br />
475.90 454.67 105.63 54.00 2.00 0.9559 0.2405 0.3472 1654.69 540.08<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 100
Sample<br />
Depth<br />
(m)<br />
Appendix 5.7.B1 Rock Grid Properties<br />
PARAMETER VALUE<br />
ROCK HEAT CAPACITY kJ/m3/oK 2350<br />
ROCK COMPRESSIBILITY v/v/kPa 4.50E‐07<br />
THERMAL CONDUCTIVITY kJ/D‐m‐oK 150<br />
INITIAL DATUM PRESSURE kPa 2700<br />
DATUM DEPTH metres 400<br />
GAS‐OIL CONTACT DEPTH metres 400<br />
WATER‐OIL CONTACT DEPTH metres 440<br />
INITIAL GAS SATURATION 0<br />
INITIAL RESERVOIR TEMPERATURE deg C 16<br />
Appendix 5.7.B2 Measured Viscosity and Density<br />
Gushor<br />
Analysis<br />
Date<br />
Measured Oil Viscosity (cP) Density API Gravity<br />
25°C 35°C 45°C Measured<br />
Temp °C<br />
@<br />
Measured<br />
Temp<br />
@ 15°C<br />
407.2 m 2012-02-09 34,950 10,938 4,535 40.0°C 0.9797 0.9951 10.55 10.99 10.60<br />
417.2 m 2012-02-09 86,658 25,221 8,653 40.0°C 0.9831 0.9985 10.07 10.50 10.11<br />
421.2 m 2012-02-09 325,206 77,408 24,926 60.0°C 0.9815 1.0091 8.58 9.01 8.63<br />
428.2 m 2012-02-09 640,492 139,387 43,638 70.0°C 0.9804 1.0140 7.91 8.33 7.95<br />
Appendix 5.7.B3 Extrapolated Viscosity used in Model<br />
Temperature ( C ) Viscosity (cP)<br />
10 5907393.819<br />
20 1270709.017<br />
30 302499.0365<br />
40 78924.47301<br />
50 22377.59489<br />
60 6843.481463<br />
70 2242.486234<br />
80 782.751522<br />
90 289.5293193<br />
100 112.95663<br />
120 19.84885948<br />
140 4.127369795<br />
160 0.992195926<br />
180 0.270500421<br />
200 0.082310492<br />
220 0.027583772<br />
240 0.010066137<br />
260 0.003962029<br />
280 0.001668228<br />
300 0.000746123<br />
@<br />
15°C<br />
@<br />
20°C<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 101<br />
@<br />
60°F
6 Drilling and Completions<br />
6.1 Overview<br />
The well pad will be contiguous with the producing facilities pad which will also include source<br />
water wells for start-up and for domestic purposes, brackish source water for steam generation<br />
from the McMurray sand and a Granite Wash salt water disposal well. The well pad is designed<br />
to accommodate up to 36 well pairs in the Clearwater Formation.<br />
Based on the high quality of the Clearwater formation under this lease, it is anticipated that<br />
SAGD will result in recovery factors of 65% or more of the oil in place. SAGD is a continuous<br />
process that minimizes thermal stress on the well bores by eliminating the need for continuous<br />
heating and cooling cycles. Reservoir integrity is preserved by continuously injecting low<br />
pressure steam below reservoir fracture pressure. The horizontal well spacing reduces the<br />
number of wells and surface pads required for the project full development, resulting in less land<br />
disturbance and fewer environmental impacts. Surface facilities will be required to distribute<br />
steam, gather and test well production, process oil and emulsions, treat water for maximum<br />
recycle and generate steam.<br />
The SAGD process involves drilling pairs of horizontal wells with both the producer and injector<br />
well bores located in high enough oil saturation to economically initiate effective SAGD. The<br />
producer horizontal well bore will be placed near the base of the effective pay using rotary<br />
steerable directional tools and logging while drilling tools to ensure competent formation and<br />
limit sinuosity in the well bore. Proper well placement is crucial to the project. In order to achieve<br />
proper well placement in the producing well a resistivity tool will be used to keep the well bore in<br />
effective pay and above the Clearwater high water saturation line. The producer well will be<br />
positioned approximately 2-5 meters above the bitumen/water interface to avoid interference of<br />
formation water with the SAGD process. The second well of the pair that will be drilled is the<br />
injector. Its purpose is to inject high quality steam into the formation. This horizontal portion of<br />
the injector well will be drilled using measurement while drilling tools and a mud motor along<br />
with a ranging tool run in the accompanying producer well bore which will allow a very accurate<br />
trajectory again minimizing sinuosity and maintaining a consistent offset above the already<br />
drilled producer of approximately 5m.<br />
Dual tubing strings will be installed in both the injector and producer to both the toe and heel of<br />
each well to accommodate circulation while pre-heating and to optimize both injection of steam<br />
and production of emulsion.<br />
Natural gas will be injected into the injector annulus with a minimum flow into short tubing string<br />
in order to provide both a bottom-hole pressure measurement and to ensure that there is a gas<br />
blanket in the annulus for all of thermal insulation, leak detection and corrosion protection in the<br />
event of a shut- down of steam injection.<br />
The producer well will be equipped with an Inconel coil tubing string to the toe of the well inside<br />
the long tubing string with fibre optic cable to discretely measure temperatures along the well<br />
bore. Natural gas will be injected into the producer annulus with a minimum flow into the short<br />
tubing string in order to provide both a bottom-hole pressure measurement and to ensure that<br />
there is a gas blanket in the annulus for thermal insulation, leak detection, prevent pitting in the<br />
tubing resulting from flashing to steam and corrosion protection in the event of a shut- down.<br />
Wellheads, casing, tubing and other down-hole equipment as well as surface equipment will be<br />
designed for sour service. Use of gas lift and gas blankets will substantially protect those<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 102
components associated with test production from corrosion and corrosion allowance, at or<br />
beyond, specifications as set out by the ERCB.<br />
6.2 Well Pad Layout<br />
Birchwood plans to use existing clearings for the production facility and well pad sites in order to<br />
minimize the overall footprint of the project as indicated in Figure 1.5-1.<br />
The well pad(s) will be directly adjacent to the CPF pad as shown in Figure 7.1.1 CPF & SAGD<br />
Well Pair Layout. In selecting the production facility/well pad, consideration was given to surface<br />
topography, surface hydrology and area wetlands, distance from Crane Lake, regional and<br />
ERCB setback requirements, access, steam line traverse route, and reservoir characteristics.<br />
The selected location of the pad will minimize impact on other area activities, environmental<br />
disturbance and optimize bitumen recovery.<br />
On surface the wellhead spacing will be 7m between the well pairs and offset 20m between<br />
injector and producer to ensure sufficient room for test separator and header buildings as shown<br />
in Figure 6.2-1 well configuration and spacing & Figure 6.2-2 3D model of well configuration.<br />
Horizontal well spacing will be at 60m inter-well spacing.<br />
The horizontal section of the producers and injectors will be drilled as noted above and will vary<br />
in length in accordance with surface proximity to the Crane Lake. In order to avoid drilling<br />
underneath the lake the horizontal leg will be stopped short of the lake. Of the ten pilot wells the<br />
maximum horizontal well path is 952 m and the shortest horizontal well path is 501 m as shown<br />
in Figure 6.2-1.<br />
The well pad will be constructed to contain surface water for testing, and treatment in<br />
accordance with regulatory requirements.<br />
6.2.1 Drilling SAGD Well Pairs<br />
Due to the presence of bottom water, the lower producing wells will be placed 2-5 m above the<br />
oil-water contact (“OWC”) to limit the influence of bottom water.<br />
The application of SAGD technology in a reservoir with bottom water will require careful<br />
monitoring of the steam chamber pressure, aquifer pressure and producing backpressure for<br />
optimum well performance. Monitoring of the well bores, including pressure and steam chamber<br />
development is addressed in Section 5.4.<br />
The SAGD wells will have surface, intermediate and horizontal sections and both surface and<br />
intermediate casing strings will be thermally cemented and bond logged. Batch drilling is<br />
proposed to optimize drilling and to allow sufficient time for cement to cure prior to bond logging.<br />
Surface casing of the producing well will be landed in competent shale at approximately 160m<br />
and the intermediate casing will be landed at a true vertical depth of approximately 427 mTVD.<br />
Surface casing of the injection well will also be landed at approximately 160 m and the<br />
intermediate casing will be landed at a true vertical depth of approximately 422 mTVD.<br />
Production wells will be drilled first using Measurement While Drilling (“MWD”) tools and a mud<br />
motor for the build section to TD of the intermediate hole, then Rotary Steerable directional<br />
drilling (“RSS”) technology for the horizontal section. In addition a gamma ray and resistivity<br />
Logging While Drilling (“LWD”) tool will be used as set out above to manage both offset from<br />
bottom water and well trajectory. Given the importance of accurate horizontal well placement on<br />
reservoir recovery, Birchwood will be generating a magnetic survey of the area for In-Field<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 103
Referencing (“IFR”) MWD tool correction purposes, using observatory data to generate IFR for<br />
diurnal corrections, performing Multi-Station Analysis (“MSA”) continuously and roll tests on a<br />
regular basis to ensure accurate well placement. The Cold Lake area is fortunate to have actual<br />
Observatory data available nearby that will improve the accuracy of diurnal corrections.<br />
Injector wells will be drilled after the production wells and will utilize the MWD tools and mud<br />
motor for both the build section and the horizontal section of the well. A magnetic tracer system<br />
(or ranging tool) will be run in the offset production well to maintain a constant specified vertical<br />
separation between the producer and its associated injection well. The specified separation<br />
target is 5.0 m with a deviation tolerance of 0.5 m.<br />
Well head design for typical SAGD wells are shown in Figures 6.1.1-1 and Figure 6.1.1-2.<br />
Wellhead specifications are AP6A, LY, DD-NL, PR-1, PSL1 rated at 9860 kPa at 343C trim for<br />
exposure to high pressure/high temperature fluids. High temperature swivel joints will be used<br />
for wellhead connection flanges to all injection and production flow lines to allow for thermal<br />
expansion of the wellhead components without stressing the flow lines.<br />
6.2.2 Surface Section<br />
Surface sections/holes for both the injection and production wells will be batch drilled and<br />
339.7mm, 81.1kg/m, Grade J-55 surface casing and an appropriate float equipment package<br />
will be set at approximately 160m and cemented with thermal cement. A cement bond log will<br />
be run to confirm both cement integrity and fall back, if any. Fall back will be top cemented to<br />
ensure that the entire interval is protected. The depth of groundwater protection is 160m.<br />
6.2.3 Intermediate or Build Section<br />
Drilling of the intermediate hole for the producer wells will be on a batch basis with a drilling rig<br />
equipped with a top drive. The bottom-hole assembly (“BHA”) for the intermediate hole on the<br />
producer wells drilled on the Birchwood well pad will be equipped with RSS and LWD tools as<br />
set out above.<br />
Drilling of the intermediate hole for the injector wells will also be on a batch basis with a drilling<br />
rig equipped with a top drive. The injector well BHA will set up with MWD tools, a mud motor<br />
and LWD tools as well as a ranging tool run in the offset producer of the pair in order to range<br />
5m away from the producer well drilled lower in the Clearwater formation.<br />
Kick off Point (“KOP”) depth where directional drilling will commence for both producer and<br />
injector wells will be at approximately 190m. A tangent section will be built at or near horizontal<br />
in the producer well bore to allow for running pumps in the future.<br />
Depending on the surface location of each well and landing point of each intermediate casing<br />
point the doglegs in the build section will vary on each wellbore. The wells will be drilled at a<br />
build rate of approximately 7.0 degrees to 9.25 degrees per 30.0m. In order to further assess<br />
the reservoir quality and saturation a gamma ray and azimuthal direction resistivity will be run in<br />
conjunction with the RSS and MWD tools. Two experienced horizontal well-site Geologists will<br />
be on site 24hrs a day that will work closely with the directional drillers and well-site supervisors<br />
on site. The Geologists will monitor the gamma ray response, directional well path, drill cuttings,<br />
and penetration rate to assess the path of the intermediate casing landing point and well path of<br />
the horizontal well.<br />
Designs for the intermediate casing will be the same for the injection and producer wells.<br />
244.5mm, 59.53kg/m, Grade L-80 intermediate casing with appropriate high strength thermal<br />
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grade couplings torqued to strict specifications and with an appropriate centralization package<br />
will be set at approximately 750m MD and cemented with thermal cement.<br />
6.2.4 Horizontal Section<br />
The horizontal length of the wellbore will be dependent on each of the individual landing points<br />
from each well drilled off the Birchwood pad site and the distance from there to lakeshore of<br />
Crane Lake. Every well pair drilled will have a different measured depth based on the different<br />
lengths of each build section. The true vertical depth should be relatively consistent over the<br />
RDA and in the producing wells will be approximately 426m true vertical depth and the injectors<br />
will be at a true vertical depth of 421.7m.<br />
Once the horizontal wells are drilled each of the open-hole horizontal sections will be lined with<br />
177.8mm, 43.16kg/m, Grade L-80 casing also equipped with appropriate high strength thermal<br />
grade couplings torqued to strict specifications and a stainless steel bullnose. The liner will be<br />
set approximately 10m short of TD, will overlap intermediate casing by approximately 30m, and<br />
be landed in the intermediate casing with a high temperature pack off assembly.<br />
Experience in the area from IOL, Shell and Husky indicates that sand production has not been<br />
an issue in the Clearwater near Cold Lake. Fines production combined with Calcium Carbonate<br />
and bitumen released by pressure drop across slotted liners in producing wells has been an<br />
issue. Plugging of production liners often occurs over time. Acid and/or EDTA treatments have<br />
had limited success, but pulling liners (IOL) and perforating liners (Husky and Shell) all without<br />
significant sand production has had long term success in resolving the plugging issue. The<br />
nature of the reservoir with its higher clay contents and lithic fragments appears to consolidate<br />
the formation over time after steaming without significantly affecting flow rates or producing<br />
sand. Based on this, a liner design that maximizes open flow without allowing sand production<br />
early in the life of the well before consolidation occurs appears to the optimal solution.<br />
Producer wells will be lined with a perforated base pipe equipped with wire-wrapped screen<br />
utilizing 7 micron spacing to minimize sand production early in the well life and both maximize<br />
open flow area and limit plugging during the producer well life. A single blank joint and two blank<br />
joints will be installed at the toe and heel, respectively. Perforations will be designed to<br />
maximize torque capacity for liner installation. Injector wells will be lined with base pipe slotted<br />
utilizing 24 micron keystone slots. A single blank joint and two blank joints will be installed at the<br />
toe and heel, respectively. The liner perforations, wire wrap spacing, slot size, material strength<br />
and size are engineered to optimize both steam injection and emulsion production, to control the<br />
production of solids, and maintain well bore integrity.<br />
6.3 Completions<br />
6.3.1 Production Well Completion<br />
Dual tubing strings will be inserted into the well. The secondary or short string will be 73mm<br />
tubing to the heel of the well above the 177.8mm liner with a 60.3mm “stinger” landed inside the<br />
liner just before the first perforations. Gas injection ports will be installed at slightly above TVD<br />
to allow small amounts of gas injection for both bottom hole pressure measurement and to<br />
provide a gas blanket in the annulus of the producer well bore. The primary or long string will be<br />
88.9mm tubing and will be landed at the toe of the well just past the perforations. Fibre optic<br />
cable sensors will be installed in each wellbore to monitor the down-hole operating temperature.<br />
The fibre optic cable sensors will be encased in 1” Inconel coiled tubing for insertion into the<br />
long string of each well. The coil tubing string will be equipped with gas ports to provide gas lift<br />
and to limit tubing damage from produced water flashing to steam. Figure 6.3.1 provides a<br />
schematic of the well bore completion for production wells.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 105
As noted above, a tangent section will be designed into the intermediate well path. This will be<br />
done so that, in the future, a mechanical lift system may be installed. Birchwood would notify the<br />
Board should this be the case and request an amendment to the scheme (if approved). Briefly,<br />
a service rig will be brought in to convert the well to a mechanical artificial lift system. The short<br />
and long string tubing will be removed from the well. Either an Electric Submersible Pump (ESP)<br />
or a metal-to-metal Progressive Cavity Pump (PCP) will be run on the 88.9 mm tubing to the<br />
tangent section depending on flow rate and absence of sand. A pump suction “stinger” string<br />
may also be attached to the pump to draw the produced fluids evenly throughout the liner. Gas<br />
would still be injected into the annulus to provide a gas blanket and also at the wellhead to dilute<br />
corrosive produced gas in surface flow-lines.<br />
6.3.2 Injection Well Completion<br />
Dual tubing strings will be inserted into the well. The secondary or short string will be 73mm<br />
tubing to the heel of the well above the 177.8mm liner with a 60.3mm “stinger” landed inside the<br />
liner at just before the first perforations. Gas injection ports will be installed at slightly above<br />
TVD to allow small amounts of gas injection for both bottom hole pressure measurement and to<br />
provide a gas blanket in the annulus of the injector well bore. The primary or long string will be<br />
88.9mm tubing and will be landed at the toe of the well just past the perforations. No additional<br />
instrumentation will be run. Figure 6.3.2 provides a well bore completion schematic for the<br />
injection wells.<br />
At all times the steam pressure in the steam chamber will be maintained below the formation<br />
fracture pressure. Steam splitter valves will be evaluated to optimize steam quality (by reducing<br />
pressure drop) and optimize steam distribution in the reservoir.<br />
6.4 Cementing Program<br />
Based on recent experience in the area and the high level of importance of well integrity, the<br />
mud system design, float equipment design and cementing practices need to be designed in<br />
concert and are outlined below. The mud system will require properties that generate sufficient<br />
hole cleaning to avoid drilling problems, but also stabilize the clay and shale intervals, while<br />
treating the bitumen to avoid blinding the shale shaker screens and (most importantly) avoiding<br />
accretion of the bitumen on drilling tools and casing. The float equipment will need be designed<br />
to ensure that a good cement bond is created throughout the well and at TD and that the high<br />
strength pipe is adequately centralized especially in the high deviation parts of the hole and<br />
near surface. Finally, cement properties and (most importantly) circulation rates must be<br />
managed to ensure that sufficient annular velocity is achieved without generating equivalent<br />
circulating density high enough to fracture formations. Target annular velocities should be 20 –<br />
30m/minute to ensure proper mud removal.<br />
6.4.1 Mud System<br />
The mud system for the surface hole will be gel-chemical maintaining density and pump rates<br />
as low as possible to protect the conductor from washing out and still provide adequate hole<br />
cleaning. Water dilution and solids control equipment, including centrifuges, will be used to<br />
control density, which will be decreased to 40-45 s/l at TD prior to running casing.<br />
The mud system for the intermediate hole to the Viking formation will be floc water with calcium<br />
nitrate to maintain Ca > 400mg/l and clay stabilizer to inhibit shales. The hole will be displaced<br />
to Bitumax, or equivalent, fluid including chemicals and mud products to control bitumen<br />
accretion and clay stability throughout.<br />
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The mud system for the intermediate hole from the top of the Mannville to TD will be the<br />
Bitumax system above. Solids will be controlled to 7% using fine mesh screens, high g force<br />
shakers, and centrifuges. Mud sweeps will take place at TD to clean the hole, minimize<br />
accretion, and control viscosity prior to running casing.<br />
6.4.2 Float Equipment<br />
Surface casing float equipment will consist of a weld on double valve float shoe, a float collar,<br />
339.7mm x 444mm latch-on bell spring centralizers on a stop collar at the mid-point of the shoe<br />
joint and every 40m to surface. One 444mm rigid centralizer will be installed on the top joint,<br />
inside the conductor barrel and below the casing cut-off point.<br />
Intermediate casing float equipment will consist of a weld on double valve float shoe, a float<br />
collar, 2-311mm semi-rigid centralizers per joint (with a stop collar in the middle of the casing<br />
joint) for 2 joints or the start of the tangent section. 1-311mm semi-rigid centralizer per joint to<br />
200m MD, 1-311mm semi-rigid centralizer every second casing joint from 200m to 13m, and 2-<br />
311mm positive bar centralizers on the top joint below the casing cut-off point.<br />
6.4.3 Cement and Cementing<br />
Surface casing cement will be Steam Cem 1800, or equivalent, with 1% CaCl2, with a pre-flush<br />
of fresh water and pumped at 2m 3 /min (estimated 10-30m/min annular velocity) maintaining<br />
equivalent circulating density below the fracture gradient at TD. The estimated TVD hydrostatic<br />
pressure at plug down is 3002 kPa or 17.7 kPa/m at 2m 3 /min.<br />
Intermediate casing cement will be Steam Seal 1270, or equivalent, plus 20% glass beads, 20%<br />
micro sand, and 4% CaCl2 pre-flushed with a 6m 3 spacer and 10m 3 scavenger and pumped at<br />
1-2m 3 /min (estimated 15-30 m/min annular velocity) maintaining equivalent circulating density<br />
below fracture gradient at TD. The estimated TVD hydrostatic pressure at plug down is 7000<br />
kPa or 18.1kpa/m at 1m 3 /min.<br />
6.5 Casing Failure Monitoring Program<br />
Unlike the CSS (Cyclic Steam Stimulation) methods used in the cold lake area, the SAGD<br />
process reduces thermal impact due to lower temperature associated with lower pressures that<br />
occur in SAGD. Casing failures have occurred largely during the CCS process or in wells with<br />
inadequate casing connection quality or poor cement jobs.<br />
Birchwood does not anticipate casing failures and is taking measures that will mitigate the risk<br />
of casing failure including:<br />
Use of premium thermal connections which are stronger than the pipe body and have a<br />
metal to metal seal in order to resist steam leakage and subsequent stress and<br />
corrosion cracking and recoding of torque readings during make-up.<br />
Use of high grade L80 steel for intermediate casing which will isolate the producing<br />
formation from the overlying geological formations.<br />
Use of thermal grade cement, management of equivalent circulating density to avoid<br />
fracturing, maximizing annular velocity, reciprocation and rotation (if possible) of the<br />
intermediate casing string during cementing operations and acquisition of bond logs for<br />
each well to ensure thermal cement integrity<br />
Operating of both the injection and producer wells at below the fracture pressure of the<br />
producing formation.<br />
Managing injection pressure at surface. While the facility boilers will not produce steam<br />
in excess of 7000kpa, ensuring that no cold water column exists the wellbore when<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 107
7000kpa is reached will ensure pressure at the reservoir face does not exceed fracture<br />
pressure.<br />
Managing the impact of the reflux of potentially corrosive fluids into injection wells at<br />
shutdown with a gas blanket and pressure maintenance.<br />
Development of a corrosion control and monitoring program including inhibitor injection<br />
and corrosion coupons in piping to and from the wellheads.<br />
Birchwood will monitor well bore integrity by:<br />
Ensuring control personnel will continuously monitor and permanently record the steam<br />
injection data and pressure relationships for each injector well as well as production rate<br />
vs. pressure and temperature in the producer wells. This data will change over time;<br />
however, if anomalies are noted by technical staff then the well(s) will be flagged for<br />
operators as this could be an indicator of an intermediate casing leak.<br />
Continuously monitoring gas blanket material balances to provide early indication of<br />
casing or coupling failure.<br />
Regularly monitoring casing vents and analyzing releases (if any).<br />
Installing a network of tilt-meters that will continuously monitor micro-deformation at<br />
surface as both an early warning system and a reservoir monitoring program to detect<br />
anomalous production and injection patterns.<br />
Upon the occurrence of any of: well bore temperature anomalies, gas blanket material<br />
imbalances, casing vent flow, anomalous micro-deformation, Birchwood would immediately<br />
inform local ERCB personnel, shut-in the well and provide a measurement and/or remediation<br />
program to mitigate the failure or potential failure.<br />
6.6 Vertical Wells<br />
6.6.1 Source Water Wells<br />
Source water wells are necessary for the project; a fresh water well to be utilized primarily for<br />
utility water during continuous operations, but also to assist in start- up operations. A brackish<br />
water source well will be utilized for both start-up and continuous operations as a make-up<br />
water source. In order to start the boilers and before any re-cycled water is available from<br />
production, an estimated volume of 4,000m 3 /day of fresh water will be required for a period of 5-<br />
10 days to fill the plant and the Boiler Feed Water Tank. As soon as practical, the brackish<br />
water well will be integrated as the primary make-up water source. Source water wells will be<br />
completed in the Murial Lake Formation (~80-90m fresh water) and the McMurray formation<br />
(~480-500m brackish water).<br />
The source water wells have been, or will be, drilled on the proposed facility/well pad. The<br />
schematic for the fresh water well and the brackish water wells are shown in Figures 6.6.1-1<br />
and Figure 6.6.1-2.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 108
6.6.2 Observation Wells<br />
A vertical observation well has been drilled and cased with thermal cement to the base of the<br />
McMurray formation in order to monitor the formation temperatures. The wells will be completed<br />
with fibre optic temperature sensors for monitoring. The wells will allow for distribution and<br />
retrieval of internal temperature monitoring equipment and will provide a conduit for running<br />
cased hole logging tools. Figure 6.6.2-1 illustrates a schematic of the well bore completion of<br />
the observation wells.<br />
6.6.3 Disposal Well(s)<br />
One disposal well is required to dispose of the produced water used in steam generation. The<br />
location of the disposal well is identified on the site plot plan in Section 7, Figure 7.1-1. The well<br />
will be drilled to a depth that will allow disposal into the Granite Wash formation. A full length<br />
casing log will be run to determine casing integrity. The Clearwater, Grand Rapids and<br />
Wabiskaw formations as well as the McMurrray formation which is the proposed brackish<br />
source water zone will be isolated using thermal cement. Prior to commencing disposal<br />
operations hydraulic isolation will be tested. No monitoring instrumentation will be place<br />
internally or externally on the casing however annual packer isolation tests will be run and<br />
submitted to the ERCB. Figure 6.6.3-1 provides a well completion schematic for the disposal<br />
well contemplated herein.<br />
The disposal well will be drilled and completed in compliance with meeting the Class Ib<br />
requirements indicated for disposal wells as set out in Directive 51. In order to ensure reservoir<br />
containment of injected fluids, as well as wellbore integrity, the wellhead injection pressure will<br />
be compatible with the bottomhole injection pressure.<br />
Birchwood will apply for approval of the disposal scheme under Directive 65. Additional above<br />
ground pipelines will be installed to move the waste water from the CPF to the disposal well.<br />
6.6.4 Abandonment Status of Wells Within the RDA<br />
There is one abandoned well within the Birchwood lease, located at 05-01-064-04W4M. This<br />
well is approximately 400 meters outside the boundary of the RDA. Details of existing wells are<br />
presented in Figure 6.6.4-1. All wells on the Birchwood lease are thermally compatible.<br />
6.5 Drilling Waste Management<br />
The wells will be drilled using a water based drilling mud system. All Drilling waste generated<br />
from the wells will be managed in compliance with Directive 50.<br />
Drilling waste will be stored in steel tanks during drilling operations. Surface hole mud will be<br />
land sprayed on nearby cultivated land provided the fluids pass all analytical requirements.<br />
Once the bitumen zone is penetrated, the cuttings and drilling fluid will evidence hydrocarbons.<br />
All oil contaminated cuttings will be dried using on-site centrifuges, stored in above ground tanks<br />
and, prior to testing and disposal, mixed with wood fibre. Confirmatory testing will be undertaken<br />
to ensure the waste can be sent to the Tervita Class II Bonnyville Landfill. Oil contaminated<br />
liquid mud residues that cannot be recycled will be hauled to the Tervita Lindbergh Salt Cavern<br />
for Disposal.<br />
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Figure 6.2-1 Well Configuration and Spacing<br />
2 future well pairs<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 110<br />
A10<br />
10 <strong>Pilot</strong> Pair wells<br />
A1
Figure 6.2-2 3D Model of Well Configuration<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 111
Figure 6.2.1-1 Producer Wellhead<br />
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Figure 6.2.1-1B Producer Wellhead<br />
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Figure 6.2.1-2 Injector Wellhead<br />
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Figure 6.2.1-2B Injector Wellhead<br />
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Figure 6.3.1 Producer Well Schematic<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 116
Figure 6.3.2 Injector Well Schematic<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 117
Figuure<br />
6.6.1-1<br />
<strong>Sage</strong> <strong>Pilot</strong> Applicatio on<br />
Source Well: Utility<br />
Water Well Schematic<br />
Page 118
Figure 6.6.1-2 Source Well: Brackish Water Well Schematic<br />
Notes :<br />
Surface Hole<br />
349.00mm<br />
Depth<br />
Grand Center 547.3 mKB<br />
Sand River 537.3 mKB<br />
Ethe l Lak e 517.3 mKB<br />
Muriel Lake 507.3 mKB<br />
Em pre s s<br />
244.5 mm<br />
Cemented<br />
477.3 mKB<br />
Suface Casing 399.3 mKB<br />
Colorado 429.7 mKB<br />
2WS<br />
222.0mm Main Hole<br />
177.8 mm Casing<br />
389.0 mKB<br />
Viking 300.8 mKB<br />
Joli Fou 292.2 mKB<br />
Colony 255.7 mKB<br />
McLaren 243.9 mKB<br />
Waseca 231.8 mKB<br />
Sparky coal<br />
Sparky 213.9 mKB<br />
GP 185.4 mKB<br />
Rex 168.2 mKB<br />
Clearw ater 155.8 mKB<br />
Tubing Stng<br />
88.9mm<br />
Wabiscaw 102.2 mKB<br />
McMurray 93.9 mKB<br />
Perforations<br />
(BHL) Paleo 44.8 mKB<br />
TD 29.8 mKB<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 119
Figure 6.6.2-1 Observation Well Schematic<br />
Note s:<br />
Surface Hole<br />
349.00mm<br />
Grand Center 547.3 mKB<br />
Sand River 537.3 mKB<br />
Ethel Lake 517.3 mKB<br />
Muriel Lake 507.3 mKB<br />
Em pr e s s<br />
244.5 mm<br />
Cemented<br />
477.3 mKB<br />
Suface Casing 399.3 mKB<br />
Colorado 429.7 mKB<br />
2WS<br />
222.0mm Main Hole<br />
177.8 mm Casing<br />
389.0 mKB<br />
Viking 300.8 mKB<br />
Joli Fou 292.2 mKB<br />
Colony 255.7 mKB<br />
McLaren 243.9 mKB<br />
Waseca 231.8 mKB<br />
Sparky coal<br />
Sparky 213.9 mKB<br />
GP 185.4 mKB<br />
Rex 168.2 mKB<br />
Clearw ater 155.8 mKB<br />
Tubing Stng<br />
88.9mm<br />
Wabiscaw 102.2 mKB<br />
McMurray 93.9 mKB<br />
(BHL) Paleo 44.8 mKB<br />
TD 29.8 mKB<br />
Fiber Optic Cable<br />
Depth<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 120
Figure 6.6.3-1 Disposal Well Schematic<br />
Note s:<br />
349.0mm<br />
Surface Hole<br />
Grand Center 547.3 mKB<br />
Sand River 537.3 mKB<br />
Ethe l Lak e 517.3 mKB<br />
Muriel Lake 507.3 mKB<br />
Empress 477.3 mKB<br />
244.5 mm Csg<br />
(cemented)<br />
Suface Casing 399.3 mKB<br />
222.0mm Main Hole<br />
Colorado 429.7 mKB<br />
2WS 389.0 mKB<br />
Viking 300.8 mKB<br />
Joli Fou 292.2 mKB<br />
Colony 255.7 mKB<br />
McLaren 243.9 mKB<br />
Waseca 231.8 mKB<br />
Spky coal<br />
Sparky 213.9 mKB<br />
GP 185.4 mKB<br />
Rex 168.2 mKB<br />
Clearwater 155.8 mKB<br />
Wabiscaw 102.2 mKB<br />
McMurray 93.9 mKB<br />
(BHL) Paleo 44.8 mKB<br />
Christina 33.8 mKB<br />
Calumet -5.4 mKB<br />
Firebag -32.7 mKB<br />
Watt Mtn -98.9 mKB<br />
Daw son Bay -103.2 mKB<br />
Praire Evap -112.7 mKB<br />
Winnipegosis -266.7 mKB<br />
Contact Rapids -313.4 mKB<br />
Cold Lake -355.3 mKB<br />
Ernest Lake -412.4 mKB<br />
Lotsberg -428.4 mKB<br />
Red Beds -603.7 mKB<br />
Packer<br />
Cambrian -651.2 mKB<br />
PreCambrian -735.6 mKB<br />
TD<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 121<br />
Depth
Figure 6.6.4-1 Details of Existing Wells<br />
Unique Well ID 100/05-01-064-04W4/0 100/03-02-064-04W4/0 100/06-02-064-04W4/0 100/01-03-064-04W4/0<br />
Date Well Spudded 8/9/1991 12/4/2011 12/12/2011 12/16/2011<br />
Lic/WA/WID/Permit # 149592 438597 438596 438585<br />
Well Status Drilled & ABD Drilled & Cased Observation Pump Cr-Bitumen<br />
Current Operator Code 0R46 A5YL A5YL A5YL<br />
Casing - Surface<br />
Casing - Production<br />
177.8mm SRF @ 155.0m<br />
None - ABD<br />
244.5mm SRF @ 175.0m;<br />
177.8mm PRD @ 518.0m<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 122<br />
244.5mm SRF @ 167.0m;<br />
177.8mm PRD @ 524.0m<br />
244.5mm SRF @ 166.0m;<br />
177.8mm PRD @ 520.0m<br />
Casing Grade (Surface) H-40 (25.3 kg/m3) H-40 (48.1 kg/m3) H-40 (48.1 kg/m3) H-40 (48.1 kg/m3)<br />
Casing Collars (Surface) ST&C ST&C ST&C ST&C<br />
Cement Returns (Surface) 3.0m3 5.0m3 0.5m3 5.0m3<br />
Cement Type (Surface) Expando mix 0:1:0 Class G 0:1:0 Class G 0:1:0 Class G<br />
Casing Collars (Production) N/A ST&C ST&C ST&C<br />
Casing Grade (Production) N/A J-55 (29.76 kg/m3) J-55 (29.76 kg/m3) J-55 (29.76 kg/m3)<br />
Cement Returns (Production) N/A 2.0m3 3.0m3 3.0m3<br />
Cement Type (Production/ABD) <strong>Thermal</strong> <strong>Thermal</strong> T-Mix TS <strong>Thermal</strong> T-Mix TS <strong>Thermal</strong> T-Mix TS<br />
Surface Vent Flows None None None None<br />
<strong>Thermal</strong> Compatible (Yes/No) Yes Yes Yes Yes<br />
Closest Proposed SAGD Well 1,250m 200m 5-30m 500m
7 Facilities<br />
7.1 Overview<br />
7.1.1 Central Processing Facility<br />
The Central Processing Facility (“CPF”) consists of an injection facility and an oil production<br />
battery. The purpose of the injection/disposal facility is to process and recycle water for steam<br />
generation and includes water treatment, water disposal, and solids dewatering and handling<br />
facilities. The purpose of the production battery is to process bitumen and includes separation,<br />
produced water de-oiling, slop oil recovery and diluent handling facilities. The facility integrates<br />
the following process:<br />
Bitumen and slop oil treatment,<br />
Produced water de-oiling and recycling,<br />
Water recovery and treatment for (re)use as boiler feed water,<br />
Steam generation,<br />
Surplus produced water treatment and disposal, produced water regeneration waste and<br />
boiler blow down disposal,<br />
Vapor recovery & produced gas treatment and blending for use as steam generator fuel,<br />
Heat recovery,<br />
Utilities (flare ignition, sweet fuel and lift gas, instrument air, heating/cooling medium,<br />
safety and office fresh water),<br />
Diluent and chemical injection.<br />
The CPF will be located adjacent to the well pad in the SW quarter of Section 02-064-04W4M<br />
and the combined lease will occupy an estimated 19 hectares (“ha”) (320 m X 580m) of land<br />
(see Figure 1.1-1 Plot Plan and 3D model in Figure 1.1-2). The CPF will occupy an estimated 8<br />
ha (380 m X 280m) of land on the eastern half of the lease.<br />
Under steady state operating conditions the plant is expected to produce 795 m 3 (5,000 bbl/day)<br />
of 8.7° API bitumen and process produced water at a rate of 3,140 m 3 /day (20,000bbl/day) (±<br />
10%). The Free Water Knockout (“FWKO”) and treater have been designed to accommodate<br />
bitumen production rates of 954 m 3 /day (6,000 bbl/day) to allow for recycling of off spec product<br />
and should also provide flexibility if the reservoir has a steam/oil ratio better than expected.<br />
The best option for handling the produced gas is to burn it as fuel in the boilers. Apart from fuel<br />
savings the high temperature, high turbulence, and long residence time in the chambers<br />
provides H2S destruction efficiency that is comparable to engineered waste gas incinerators.<br />
Detailed information regarding equipment and Heat and Material Balances can be found in the<br />
following appendixes.<br />
Appendix 7.1 Equipment list<br />
Appendix 7.2 Heat and Material Balance<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 123
7.1.2 Well Pad Facility<br />
Figure 7.1.2-1 Process Flowsheet 200-1 Wellpad.<br />
The well pad will be located directly adjacent to the CPF and constructed with the following<br />
features:<br />
• Ten SAGD well pairs (future drilling potential to 36 pairs on the same pad)<br />
• A steam distribution header<br />
• A blanket gas distribution header<br />
• A group production header<br />
• A test header with a de-gasser, flow meter, and water cut analyzer to generate ERCB<br />
production accounting data.<br />
• Each well pair will have a control manifold to manage the flow of each fluid.<br />
• Instrument air will be used to operate automated control and switching valves.<br />
• The production wells will be equipped with lift gas. Each production well can be diverted<br />
to a test header equipped with a flow meter and water cut analyzer.<br />
Steam will flow from the CPF to the well pads via above ground steam pipelines at a maximum<br />
pressure of 7000 kPa. The manifold buildings located at the well pad will then distribute the<br />
steam to each well pair through flow-lines. There will be one steam control manifold per well<br />
pair. Steam will be flow controlled to each production and each injection well during the project’s<br />
circulation warm up phase (Section 5.2) to optimize the initiation of the SAGD process and to<br />
each injection well during steady state operations (Section 5.3).<br />
During steady state operations at full production, steam will be fed into dual tubing strings set at<br />
the toe and at the heel of each injection well at a rate of 318.5 t/day. Control values and<br />
metering instruments will be configured to allow the steam injection rates to be controlled, in the<br />
range of 72 t/day to 408 t/day per steam injection well. Normally the steam will be injected at a<br />
flow rate set in the Digital Control System (“DCS”) by the operator. A high pressure override will<br />
be programmed into the logic to prevent the wellhead injection pressure from exceeding the limit<br />
prescribed by the well license.<br />
Each injection and production line at the well pad will be equipped with external electric tracing<br />
in segments where liquids can become trapped during a cold weather shutdown. To enhance<br />
freeze protection, minimize temperature transients and avoid water hammer issues, a steam<br />
cross over may be provided to feed steam into production lines at suitable locations.<br />
7.1.3 Design Flow Rates<br />
• Ten SAGD well pairs.<br />
• Average bitumen production per well pair = 79.5 m 3 /day (500 bbl/day).<br />
• Average water production per well pair = 318 m 3 /day (2,000 bbl/d CWE; WOR = 4.0).<br />
• Average reservoir gas production per well pair = 1,590 sm3/day (GOR = 20 sm 3 / m 3 ).<br />
• H2S production = 0.203 kg H2S per m3 of dry bitumen (0.141 sm 3 H2S / m 3 bitumen).<br />
• H2S concentration in the reservoir gas = 4400 – 7,050 ppm (dry basis; due to<br />
aquathermolysis)<br />
• Average steam injection per well pair = 318 tonnes/day (2,000 bbl/day CWE; SOR =4.0).<br />
• Bottom Hole Pressure = 2900 kPa.<br />
• Bottom Hole Temperature = 234°C in the steam chamber; 226°C in the horizontal<br />
segment of the production well.<br />
• Design down-hole sub-cool = 5 °C.<br />
• Well head temperature = 195°C.<br />
• Production pressure at the wellhead (upstream of choke) = 1,490 kPa.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 124
• Lift gas per well = 3000 sm 3 /day<br />
• Average produced gas recovered, excluding lift gas = 15,355 sm3/day (dry basis);<br />
design for maximum 30,710 sm 3 /day.<br />
• H2S production (fully developed steam chambers) = 161.4 kg/day; design for 201.8<br />
kg/day max.<br />
7.2 Steam Generation and Water Treatment<br />
Figure 7.2-2 Block Flow Diagram of the De-oiling, Water Treatment and Steam Generation.<br />
Figure 7.2-2B Water Balance of the De-oiling, Water Treatment and Steam Generation<br />
7.2.1 Steam Generation<br />
Figure 7.2.1-1 Process Flowsheet 100-06 Steam Generation<br />
The drum boiler packages include a steam drum, blowdown drum, air pre-heater, forced draft<br />
fan, burner and a burner management system. A mixture of produced gas and pipeline quality<br />
make-up gas will fuel the main burner of each boiler; pilot flames will receive only sweet dry<br />
natural gas. During initial start-up only a small volume of produced gas will be available<br />
therefore only pipeline quality natural gas will also be used to fuel the main boilers.<br />
The small amount of produced gas (co-produced with the bitumen from the reservoir) is not<br />
expected to have any significant commercial value. During normal operation, the produced gas<br />
Is expected to contain mostly steam, carbon dioxide, and methane. The steam will be<br />
condensed and removed from the gas. The gas will then be blended with sweet dry natural gas<br />
to fuel the main burners in the steam generators. In addition to exploiting the marginal amount<br />
of fuel value from the produced gas, the steam generator combustion chamber will provide<br />
complete destruction of noxious and toxic components such as H2S.<br />
7.2.2 <strong>Project</strong> Make-up and Boiler Feed Water Sources<br />
Figure 7.2.2-1 Process Flowsheet 100-6 Water Treatment<br />
The facility will generate high quality steam from predominately brackish water sourced from the<br />
McMurray formation and sent to the plant via pipeline. Annual brackish water requirements are<br />
expected to be 150,000 m 3 . Fresh make up water will be required for the initial start-up period;<br />
it is anticipated that no more than 50,000 m 3 of fresh water will be required for start-up;<br />
thereafter a volume of approximately 5 m 3 /day of fresh water will be necessary to meet utility<br />
requirements. Two drum boilers (B-5000/B-5010) rated at 165 GJ/hr., will produce high pressure<br />
steam saturated vapor, also referred to as 100% quality steam.<br />
The CPF design is based on receipt of water from the following sources: make-up water (fresh<br />
and brackish), produced water from the production wells, and steam condensate. It is<br />
anticipated that shallow water from the Empress Formations (80-100 m) and brackish water<br />
from the McMurray Formation (480-500 m) will be utilized and transported to the facility via pipe<br />
lines from wells located on the combined wellpad and CPF site. A summary of water sources<br />
and uses is shown in Table 7.2.1-1, a detailed water balance can be found in Figure 7.2.2B.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 125
Table 7.2.2-1 Summary Water Sources and Uses at Maximum Capacity<br />
Boiler<br />
Reservoir<br />
Fresh<br />
Make- Brackish<br />
Time Feed Utility Loss Recycle up Water<br />
Phase Frame Water Water 5% 92.5% Water Make Up Notes<br />
(Days) M3/day M3/day M3/day M3/day M3/day M3/day<br />
Plant Fill 5–10 4,030 5 (4,030) 0 3,640 395<br />
Start-up Water<br />
required<br />
Assumes<br />
Warm Up 90–180 4,030 5 0 3,829 5 201<br />
injection equals<br />
returns for 2<br />
wells<br />
Assumes<br />
Transition<br />
Steady<br />
30–90 4,030 5 (2,015) 1,914 1,728 395 injection equals<br />
returns for 1 well<br />
State<br />
SAGD<br />
3000+ 4,030 5 (202) 3,635 5 395 Steady State<br />
Water from both the fresh and the brackish water pipelines will be filtered as it enters the<br />
treating system. Produced water will be recovered from the condensable portion of the<br />
produced gas condensing train and from the bitumen treating system; this water will form the<br />
bulk of the boiler feed water (BFW) after is de-oiled and treated. It is anticipated that the total<br />
produced water will vary from 92% to 105% of the steam injected. On occasion (such as startup)<br />
make up water will be required. De-oiled water will require disposal when steam recycle<br />
rates exceed 100%.<br />
7.2.3 Produced Water Treatment Process<br />
Figure 7.2.3-1A Process Flowsheet 100-7A Water Treatment<br />
Figure 7.2.3-1B Process Flowsheet 100-7B Water Treatment<br />
Figure 7.2.3-2 Process Flowsheet 100-1 Inlet<br />
The produced water treatment process is designed to create high quality boiler feed water. The<br />
process utilizes falling film evaporator technology, which operates at a moderately high pH and<br />
results in the removal of silica, dissolved solids, and hardness in order to meet drum boiler feed<br />
specifications.<br />
Steam sent to the wells is generated through the following process: BFW is pumped first by the<br />
low pressure BFW Pumps (P-4020 A/B) to the Emulsion/BFW Heat Exchanger (E-1040) where<br />
the BFW is preheated by recovering heat from emulsion at the CPF inlet. The BFW then flows<br />
to the HP BFW Pumps (P4040 A/B), which increases the BFW pressure to 7400 kPa. Dry steam<br />
leaving the Drum Boilers (B-5000/B-5010) is sent to the wells via a high pressure steam line,<br />
where the high pressure steam will be injected into the formation via injection wells. A small<br />
portion of the high pressure steam is diverted, its pressure reduced, and used as utility steam.<br />
Steam blow-down from the Drum Boilers will be sent to the Evaporator. The blow-down rate is<br />
expected to be 4-7.5%.<br />
Produced emulsion from the wells will be routed to the inlet de-gasser (V-1000) where vapours,<br />
pre-dominently water vapour, will be condensed in an aerial cooler. Produced gas, lift gas and<br />
hydrocarbon vapours from the vapour recovery system will be recovered for re-use as fuel gas.<br />
Emulsion is treated chemically (Section 7.8.2) then sent to the Free Water Knock Out Vessel (V-<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 126
1100) where water with some hydrocarbons is sent to the produced water/glycol heat exchanger<br />
(E- 1140 A/B) for commencement of the bitumen treatment process (Section 7.3) and then to<br />
the produced water skim tanks (T-2000/2010). The hydrocarbons with some water will be sent<br />
to a treater (V-1110) where it is treated with chemicals and diluent, cooled in the sales oil/glycol<br />
heat exchanger (E-1130) and sent to the sales oil tanks (T-7000, T7010). Vapours from the<br />
treater are cooled in a produced gas/glycol heat exchanger (E-1150) and sent to a diluent<br />
recovery separator (V-1160) with produced gas going to the fuel gas mix drum, water to the<br />
produced water skim tanks and hydrocarbons to the sales oil tanks.<br />
In the de-oiling area, produced water enters the skim tanks where oil and water are separated<br />
by gravity. The produced water is sent to the Induced Gas Flotation (IGF) vessel (V 2100)<br />
where additional oil recovery occurs. The produced water leaving the IGF vessel is fed to the Oil<br />
Removal Filters (“ORF's”) (V2200 A/B) then flows to the de-oiled water tank (T-3000) and<br />
undergoes additional chemical treatment (see Sections 7.12) to allow for separation of water,<br />
hydrocarbons and solids removal. De-oiled water from the bitumen treatment process, as well<br />
as drum boiler blowdown water and make up brackish water, is sent to an evaporator.<br />
7.2.3.1 Evaporation<br />
The mixed flow of de-oiled produced water and boiler blow-down is combined with heated<br />
brackish water and is fed to a de-aerator (C-3100) where a small amount of excess steam from<br />
the evaporator condenser or low pressure steam line is used to strip the oxygen, carbon<br />
dioxide, nitrogen and other non-condensable gas to prevent downstream equipment corrosion.<br />
The water then enters a falling film evaporator (V-3400) where the brine water is recirculated<br />
from the vapour body/retention chamber through an internal return circuit and then flows as a<br />
thin film down the heat transfer tubes. The heat from condensing vapours on the shell side of<br />
the evaporator heat exchanger causes a portion of the water in the re-circulating liquid to<br />
vapourize. The majority of the vapour production occurs in the heater tubes and flows down the<br />
tubes with the liquid film in the same direction as the vapour body. This two phase co-current<br />
flow helps to stabilize the liquid film on the inner surface of the tube and accelerates the liquid<br />
flow down the tubes, creating turbulence and augmenting heat transfer.<br />
Chemicals are injected into the evaporator include magnesium oxide and caustic in order to<br />
precipitate silica and other scaling constituents as well as preventing scale formation (see<br />
Section 7.12).<br />
The water slurry entering the evaporator is significantly concentrated (~5 concentration factors)<br />
during the evaporation process. Disposal brine from the system is neutralized and sent to the<br />
disposal system.<br />
The clean vapours are compressed (K-3440) and the vapour pressure increased to the<br />
condensing temperature of the heater shell. The compressed vapour is then cooled to provide a<br />
consistent heat transfer rate at the entrance to the condenser. The distillate is cooled and<br />
pumped through the raw water exchanger (E-3450 A/B) to the BFW tank.<br />
7.2.3.2 Boiler Feed Water<br />
The Boiler Feed Water (“BFW”) pump system provides decoupling between the water treatment<br />
and boilers. The BFW tank is blanketed with gas to prevent the ingress of oxygen and insulated<br />
to conserve heat and to avoid freezing during cold weather shut downs. Tank vapours are<br />
routed to the VRU to avoid emissions and odour concerns. The Low Pressure BFW booster<br />
pump is then used to draw water from the tank and send it through the heat recovery system.<br />
The Low Pressure BFW booster pumps (P-4020A/B) discharge at a pressure of about 1200 kPa<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 127
and a rated flow of 165 m 3 /hr which ensures that the BFW will not boil and there will be<br />
adequate suction at the head of the High Pressure BFW pumps (P-4040A/B). The booster pump<br />
will be equipped with a suitable minimum flow bypass system. The pre- heated, pressurized<br />
water is sent to the drum boilers for steam generation. Concentrated brine is collected in the<br />
evaporator sump for subsequent treatment and disposal.<br />
7.2.4 Produced Water Disposal<br />
Concentrated brine from the evaporator sump is pumped to a neutralization tank where it is<br />
treated with hydrochloric acid. Hydrochloric acid is stored in a separate tank equipped with a<br />
water wash vent scrubber. Circulation pumps (P 3450 A/B) and a glycol cooler (E-3480)<br />
ensures the tank temperature does not exceed 83 o C. The neutralized product is flocculated and<br />
pumped to a decanting centrifuge where the majority of spent magnesium oxide is concentrated<br />
and dumped to a designated bin for off-site disposal at an approved facility. The concentrate is<br />
pumped to a waste water disposal tank and subsequently disposed of in an approved disposal<br />
well. See Figure 7.2.2 Block Flow diagram and Figure 7.2.2B Water Balance.<br />
7.3 Bitumen Treatment<br />
Figures 7.3-1 Process Flowsheet 100-2 Bitumen Treating<br />
The bitumen treatment system is designed to separate produced fluids into sales oil and<br />
produced water, while recovering produced gas for use in the plant. The sales oil produced by<br />
the bitumen treatment process is must meet the following minimum pipeline specifications:<br />
BS&W: 0.5% by volume<br />
Specific Gravity: 0.940<br />
Temperature: 60 o C, Maximum 65 o C<br />
Viscosity: 350 centistokes at 4 o C<br />
Emulsion composed of bitumen, produced water and produced gas is sent to the CPF in an<br />
above ground pipeline and is routed to an inlet de-gassing vessel. The vapour phase which is<br />
composed primarily of condensable water vapour, produced gas, lift gas and lighter<br />
hydrocarbons is transferred to a condenser (E-1020), then to a produced gas separator (V-<br />
9210) cooled by the produced gas cooler (E-1140) and eventually recovered as fuel gas<br />
(Section 7.5).<br />
The emulsion from the de-gasser will be cooled to ~120 o C in the emulsion/boiler feed water<br />
exchanger (E-1040). The heat from the emulsion will be transferred to the boiler feed water to<br />
reduce generator fuel consumption. Emulsion along with diluent enters the FWKO where<br />
produced water is separated from the emulsion after which diluent is added again to the<br />
emulsion which then enters the treater where final separation of produced water from the<br />
bitumen occurs through the addition of clarifiers and demulsifers. The FWKO allows large<br />
droplets and slugs of water to drop out of the emulsion. The water stream leaving the FWKO<br />
vessel should contain
initiate decanting of the treater rag layer until the operating profile is established and the rag can<br />
be drawn on a continuous basis. This design also:<br />
Compensates for low temperatures and high viscosity during plant start-up.<br />
Increases the density differential between oil and water,<br />
Reduces fouling in the glycol heat exchangers, and<br />
Results in lower viscosity of the emulsion thereby improving heat transfer performance.<br />
The piping design also incorporates recycling of off-spec product and slop oil at the front of the<br />
treating system. A recycle line will be tied into the emulsion line upstream of the FWKO tank.<br />
Recycle rates are not expected to exceed 10% of the treating system.<br />
7.3.1 De-Oiling<br />
Figures 7.3.1-1 Process Flowsheet 100-4 De-oiling<br />
Produced water from the FWKO and Treater undergoes three separate de-oiling treatments:<br />
cascading produced water skim tanks (T-2000/T-2010) with polymer injection, Induced Gas<br />
Floatation (“IGF”) (V-2100) with polymer injection and oil recovery filtration (V-2200A/B) with<br />
provision for back-wash.<br />
7.3.1.1 Skim Tanks<br />
Oil recovered from the treater is sent to the sales oil tank (T-7000/7010). Produced water from<br />
the glycol heat exchangers, the VRU liquids pump, the slop water tank, and the decant water<br />
pump is sent to the skim tanks for recovery using gravity. The skim tanks are designed to utilize<br />
chemical injection and mechanical separation to allow the small oil droplets to coalese into large<br />
oil droplets and accumulate on the water surface for skimming.<br />
A chemical injection port is provided upstream of each skim tank to allow a water clarifier<br />
(polymer solution see Section 7.9.2) to be added to the water. A low shear static mixer<br />
downstream of the clarifier injection point disperses the chemicals into the water as well as<br />
helping the oil droplets collide allowing them to agglomerate into larger oil droplets. A vortex will<br />
be utilized in the skim tanks to prevent the small oil droplets from short circuiting to the bottom<br />
of the tank; the vortex flow pattern rotates at a rate that extends the residence time in the tank<br />
thereby extending the coalescence period. The bottoms of the tanks are equipped with an<br />
internal cone shaped baffle over the produced water discharge. The baffle acts as a barrier to<br />
short circuiting as it ensures that the emulsion flow is redirected around the periphery of the tank<br />
prior to discharge.<br />
Each skim tank is equipped with an interface probe and sampling valves in order to monitor the<br />
rag emulsion in the skim tank and prevent the rag emulsion from hindering the separation<br />
process. Floating skimmers will be utilized to remove the rag layer.<br />
Pumps will be provided to transfer the remaining emulsion from the primary skim tank to<br />
secondary skim tank, as well as from the secondary skim tank to the IGF unit, and from the IGF<br />
unit to the ORF if required, for additional treatment.<br />
7.3.1.2 Induced Gas Flotation<br />
The emulsion stream from the skim tanks is then sent to the IGF Vessel (V-2100) where natural<br />
gas is bubbled through the water to allow the oil to rise to the top of the vessel and skimmed off.<br />
The IGF can typically recover up to 90% of the residual oil in the produced water from the skim<br />
tanks.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 129
A circulation pump in the IGF feeds an in-line educator that induces blanket gas into the<br />
educator which then disperses fine bubble of blanket gas into the produced water via an in-line<br />
disperser set across the flow path in the IGF unit. This facilitates contact and adsorption of the<br />
oil droplets to the surface of the gas bubbles. The blanket gas pressure is controlled with a pilot<br />
gas regulator. A globe valve on the piping is used to adjust the supply of gas to the educators.<br />
Gas bubbles adhere to oil droplets and rise to the top of the IGF's internal compartment and<br />
produced water flows downward through the outer compartment and is pumped to the oil<br />
recovery filters. The froth oil flows over a weir around the top of the vessel and is pumped to the<br />
oil recovery via the oil recovery pump (P-2120A/B). The skim oil/IGF froth may be returned to<br />
the slop oil tank for more aggressive treatment.<br />
The IGF liquid level controller adjusts feed to the unit. An interface controller regulates the IGF<br />
froth. A chemical injection quill is incorporated into the design of the plant and will allow the<br />
injection of polymer into the system via the IGF charge pumps if required during start up.<br />
7.3.1.3 Oil Removal Filters<br />
The water stream is then sent through the oil recovery filters (ORF's V-2200 A/B) where oil is<br />
adsorbed onto a filter matrix in 2 vessels so that 1 is in service at all times and 1 can be treated<br />
and backwashed. The water stream is sent to the de-oiled water tank (T-3000). The backwash<br />
from the ORF's and quenched desand slurry from the FWKO and treater is piped to the desand<br />
tank (T-2300) to remove solids.<br />
7.3.2 De-Sanding<br />
Figure 7.3.2-1 Process Flowsheet 100-5 De-sanding and Slop Oil<br />
Sand and sludge will accumulate in the FWKO and treater vessels, as well as in the ORF<br />
backwash. Both the FWKO and treater will be equipped with automated flush and drain stations<br />
that can be remove sand without taking the equipment out of service. Water to flush the sand<br />
will be supplied from the de-oiled water tank through a desand jet pump (P2320). Desand drains<br />
will include internal sand pans to catch sands disturbed by the water flush. The slurry of<br />
produced water and sand will be sent to the de-sand tank after it is blended with de-oiled water.<br />
Sand and sludge from the ORF backwash and desand slurry is sent to the desand tank<br />
equipped with blanket gas where the solids settle and are sent for disposal. Oil is skimmed and<br />
pumped to the Oil Recovery Tank. Water is decanted and sent to the Skim Tank, and slop oil<br />
sent to the FWKO vessel.<br />
Vapours from the de-sand tank are routed to the VRU for recovery.<br />
7.3.3 Sales Oil Management and LACT<br />
Figures 7.3.3-1 Process Flowsheet 100-3 Bitumen Storage<br />
Oil product is pumped from the sales oil tanks to the Lease Automatic Custody Transfer unit<br />
(“LACT”) (P-7200) unit. There are two sales oil tanks (T-7000, T-7010) and one off spec tank<br />
(T7100) with a design pressure of no less than 3.5 kPa (-0.5 kPa vacuum). While one is feeding<br />
the pipeline the others are taking production. Each tank will have capacity to accommodate<br />
eight (8) hours of production and should normally operate at 50% capacity. The tanks will be<br />
bottom sloped toward the tank wall to facilitate decanting of bottom water. A slop oil tank with<br />
recycle pump and collection header will be piped to draw bottom water from the sales tanks and<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 130
off spec tank as well as transfer off-spec material to treatment area. The combined volume of<br />
the tanks will allow for 24 hours of storage should a pipeline upset occur. Each sales tank will<br />
include the following:<br />
Insulation to conserve heat and minimize headspace breathing due to sudden weather<br />
changes as well as glycol tracing around the bottom 2 m of the tank wall to prevent<br />
freezing of the inlet and outlet nozzles. PSVS's will be traced and insulated to prevent<br />
freeze up.<br />
Fuel gas blanketing to prevent the ingress of oxygen.<br />
Traced and insulated sample box to allow samples to be drawn from various levels<br />
within the tank. A blow-case will be installed to return oily sample waste to the tank.<br />
Level transmitters. A high level alarm and shutdown system will reduce the risk of<br />
overfilling the tank(s) and a low level alarm and shutdown will prevent damage to the<br />
pumps drawing from the tank(s).<br />
Clean sales oil headers and off spec headers upstream and downstream of the sales<br />
and off-spec tanks; the sales oil headers will be piped with a tank bypass line to the<br />
LACT booster pump.<br />
Two 100% duty LACT booster pumps (one operating, one standby).<br />
A water cut analyzer to monitor sales oil BS&W flowing to the LACT unit prior to diluent<br />
blending.<br />
A sales oil diluent blending station with a static mixer to ensure pipeline viscosity<br />
specifications can be maintained.<br />
During startup, feedstock fluctuations or plant upset, the sales oil may go off-spec.The off-spec<br />
tank will provide storage space and a means to isolate off-spec product from the clean sales oil.<br />
The treated sales oil must be blended with diluent to reduce viscosity and frictional drag in the<br />
market pipeline. The system will be designed to operate with normal diluent to bitumen blend<br />
ration of 23:73 in order to produce a 350 cST blend at 4 o C pipeline flowing temperature. Static<br />
mixers will be installed downstream of the diluent injection quills to promote uniform mixing of<br />
the blend.<br />
The diluent pipeline into the CPF is expected to operate at sufficient pressure and with sufficient<br />
reliability that there should be no requirement for a diluent tank or diluent injection pumps. An<br />
emergency shutoff valve will be installed at the diluent injection pipeline riser entering the CPF.<br />
The flow will be measured and totalized to reconcile custody transfer records.<br />
7.3.5 Slop Oil System<br />
Slop oil is a mixture of rag draws, off-spec oil, emulsions, sludge, tank bottom and any other oily<br />
liquid waste. On-site treatment of slop oil is the prefer option for slop oil treatment as it allows for<br />
maximizing the recovery process however composition and characteristics of the slop oil may<br />
require occasional off-site disposal.<br />
The slop oil tank will assist in management of the oily emulsions from the above noted sources.<br />
The tank will be equipped with a heating coil to maintain contents at 79 o C with hot glycol used<br />
as the heating medium.<br />
Plant piping has been configured to allow decanting of rag emulsion from the interface layer in<br />
the FWKO vessel or treater into the slop tank (see Figure 7.3.2-1). A slop oil recirculation pump<br />
will allow for chemical treatment of the slop emulsion. Slop oil will often contain a high<br />
percentage of water and may require long settling times to break the emulsions. As the<br />
emulsion breaks, the slop oil recirculation pump can be used to transfer skim oil to the FWKO<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 131
inlet, or bottom water to the skim oil system. A network of slop oil headers will be provided to<br />
allow fluid to be transferred to the slop oil tank and the oil recovery tanks. This will allow<br />
decanting of the emulsion layer from one tank to the next where further chemical treatment can<br />
be applied.<br />
The slop oil and oil recovery tanks will be fuel gas blanketed to prevent ingress of oxygen. Tank<br />
vapours will be routed to the VRU through a common header. Tanks will be designed for<br />
pressures no less than 3.5kpa (-0.5 kpa vacuum) and be equipped with PVSV’s traced and<br />
insulated to prevent freezing.<br />
7.4 Inlet Cooling and Separation<br />
Figures 7.4-1 Process Flowsheet 100-4 Glycol Circuit<br />
In order to achieve high levels of energy efficiency for the project, a closed loop ethylene/glycol<br />
water system is one of the CPF components and it will be used for cooling and to recover and<br />
utilize low grade heat which would otherwise be released or lost to the atmosphere. The heat<br />
recovered will be used to heat various process streams such as boiler combustion air,<br />
purchased fuel gas, HP and LP flare knock out drums, tank heaters, tracing stations, and<br />
building heaters. Cold glycol will be used to cool the various VRU inlet streams along with<br />
providing the medium required to cool the inlet streams, largely produced water, to meet<br />
process cooling requirements.<br />
Produced water is typically a high fouling service. Sediment in the produced water is expected<br />
to contribute to fouling. Traces of dispersed oil in the water will bind sediment to the exchanger<br />
tubes and internal passages. An extra exchanger bundle is anticipated to be available at all<br />
times so that one shell can be taken out of service for cleaning while maintaining flow through<br />
the other shells. All exchangers in the produced water cooling train will be heat traced and<br />
insulated. The exchangers will be drained as soon as a failure in the glycol system is detected.<br />
7.5 Fuel and Produced Gas Recovery System<br />
Figures 7.5-1 Process Flowsheet 100-10 Instrument Air/Fuel Gas<br />
Two sources of gas will be utilized for various processes on the well pad and within the CPF;<br />
produced gas from the reservoir and dry natural gas supplied by a third party for all of lift gas,<br />
blanket gas and boiler fuel gas. No alternative sources of fuel are being considered as the<br />
natural gas infrastructure exists within close proximity to the plant and establishing other<br />
infrastructure would be economically infeasible and cause unnecessary environmental<br />
disturbance.<br />
Produced gas will be recovered from the inlet degassing system, the VRU, the FWKO and<br />
treater and used for fuel in the drum boilers. The main produced gas stream will be recovered<br />
after condensing water from the inlet degasser. After the gas is cooled it will separate into noncondensable<br />
recovered vapour and liquids, the latter composed primarily of water. The liquids<br />
are sent to the de-oiling system. Produced gas will contain CO2 and small amounts of H2S due<br />
to the occurrence of aquathermolysis in the reservoir. The high volumes of lift gas anticipated<br />
will substantially reduce the concentrations of both at surface. The high temperature, high<br />
turbulence and long residence time in the boiler fire box chambers will provide H2S destruction<br />
efficiency that is equivalent to engineered waste gas incinerators. Additional vapour streams will<br />
be recovered from plant tanks and other sources of low pressure vapours via a header system<br />
that feeds the VRU. To minimize the vapour load to the VRU compressor the inlet stream is<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 132
cooled with cold glycol and the vapour and liquid are separated in the suction scrubber. All liquid<br />
streams will be collected and sent to the de-oiling system.<br />
Commercial natural gas (odorized) will be piped into the plant from the Alta Gas pipeline<br />
terminating at a suspended well at 6-12-64-4W4M line. The riser into the CPF will be equipped<br />
with an emergency shut down valve and a flow metering station. The primary use of this high<br />
pressure gas is for lift gas; once the gas is heated with glycol it will be piped to the well pad.<br />
Once a portion of the remaining gas has its pressure reduced, it will also be used for heating the<br />
office/warehouse, glycol heater fuel, pilot for the flare(s) and for blanketing tanks and vessels.<br />
The balance, and bulk, of the pipeline quality fuel gas will be used to fire the drum boilers.<br />
All produced and lift gas will be recovered and, with the use of a vapour recovery system, all<br />
blanket gas will be directed to the fuel gas system, mixed with fuel gas and used for fuelling the<br />
steam generators.<br />
All vents from all equipment in the CPF will be directed to the fuel gas and produced gas<br />
recovery system. This will minimize fugitive emissions and ensure maximum recovery of this<br />
resource.<br />
7.5.1 Sulfur Production and Recovery<br />
For in situ thermal facilities, the sulphur inlet rate is the sulphur content of the produced gas. At<br />
<strong>Sage</strong>, produced gas includes gas produced from the reservoir and lift gas. This produced gas is<br />
combined with gas recovered from the VRU collected from various parts of the process train<br />
and is used as a part of the mixed fuel gas stream for steam generation. Lift gas and the bulk of<br />
the fuel gas used for steam generation is sourced from pipeline quality fuel gas and has no<br />
sulphur content.<br />
Produced gas from the bitumen in the Clearwater zone in this area has no sulphur content<br />
initially. It develops a sulphur component as sulphur is released from the bitumen to form<br />
hydrogen sulphide in the reservoir through a process known as aquathermolysis.<br />
The following table, from ERCB Interim Directive ID 2003, provides specifications for Inlet<br />
sulphur rates and minimum required recovery criteria.<br />
Table 7.5.1-1 Sulphur Production and Recovery Criteria<br />
Sulphur Inlet Rate<br />
(T/D)<br />
Design Sulphur Recovery Criteria<br />
(%)<br />
Calendar Quarter Year Sulphur<br />
Recovery Guideline (%)<br />
5 to 10 79 69.7<br />
>10 96.2 95.9<br />
The design inlet sulphur rate is based on predictions of the effect of aquathermolysis and is<br />
estimated to be 190 kg/d based on the maximum daily H2S production of 201.8 kg/d or 0.239<br />
kg/m 3 of bitumen produced see Section 7.1.3, as such no sulphur recovery is required.<br />
7.6 Vapour Recovery and Flare Systems<br />
Figure 7.6-1 Process Flowsheet 100-11 Flares and VRU<br />
The vapour recovery system consists of various operations in the plant that will capture vapours<br />
as per Table 7.6.1:<br />
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Table 7.6.1 Vapour Sources<br />
Dearator Overhead Separator (V-3130) Sales Oil Tanks (T-70000 & T 7100)<br />
Produced Water Skim Tanks (T-2000 & T-2010) Slop Tank (T-2400)<br />
Desand Tank (T-2300) De-Oiled Water Tank (D-3000)<br />
Fresh Water Tank (T-3240) Brackish Make-up Water Tank (T-3210)<br />
Boiler Feed Water Tank (T-4000) Off- Spec Oil Tank (T-7100)<br />
Induced Gas Flotation Vessel (V-2100) Oil Recovery Tank (T-2500)<br />
Fuel Gas Header Make-up Purge Gas<br />
The vapour recovery unit (VRU PKG 9100) will collect vapours from the above sources through<br />
a header system that feeds into the VRU. Vapours will be cooled with glycol and then sent to an<br />
inlet scrubber where gases and liquids will be separated. Gases will be compressed in the VRU<br />
compressor (K 9120A/B/C) and sent to the outlet scrubber for injection into the produced gas<br />
separator and burned in the steam generators. Liquids will be pumped (P9130 A/B) to the<br />
produced water skim tank and/or slop oil tank for further treatment and hydrocarbon recovery.<br />
The VRU will be equipped with three compressors (K9120 A/B/C); two – 50% use electric drive<br />
compressors will be utilized on regular service, the third electric drive compressor will be utilized<br />
should one of the regular service compressors fail. An emergency generator will be sized to<br />
accommodate one of the VRU compressors along with other critical plant functions. Should all<br />
of these fail, a shutdown will be initiated immediately. This will facilitate mitigating upset<br />
conditions as well as maintenance without using the low pressure flare.<br />
Both a high pressure and low pressure flare system will be installed at the plant for emergency<br />
relief flows. Each system will include a knock-out vessel, pumps from the vessel and a flare<br />
complete with pilot, flame monitoring and a closed circuit television. The high pressure flare (F-<br />
9020) will only be utilized in emergency situations where the inlet degasser requires relief due to<br />
well operations. The low pressure flare is designed to handle VRU vapour, in case of VRU<br />
compressor failure. The emergency generator will provide power to the VRU in the event of a<br />
power failure. A shutdown will be initiated upon an emergency generator failure. The LP flare<br />
will be utilized to vent off any remaining vapours during shut down. Liquids recovered in the flare<br />
knock out drums will be sent to the slop oil tank for treatment.<br />
7.7 Energy & Heat and Material Balances<br />
The Heat and Material Balances for the <strong>Project</strong> are presented in Appendix 7.2.<br />
7.7.1 Energy Balance<br />
The energy sources required to operate the facilities and wells consist of produced natural gas,<br />
pipeline quality natural gas and electricity. Pipeline quality gas is routed to the wells to act as a<br />
medium for all of lift gas, bottom hole pressure measurement, gas blanketing in the annulus of<br />
the wells for thermal insulation, well integrity monitoring, and to provide a buffering agent in the<br />
production tubing against pinholes created by steam flashing. Wellhead produced gas<br />
consisting of solution gas and by products of aquathermolysis is combined with tank and vessel<br />
vapors, additional pipeline quality gas and is used to fire the boilers. Steady state demand for<br />
gas is expected to be in the order of 210 e3m3/day. Electricity is used for all pumps and motors<br />
to limit both greenhouse gas emissions and noise. The steady state electrical load is expected<br />
to be in the order of 5MW, well below the demand that would make cogeneration feasible.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 134
Table 7.7.1-1 Energy Balance<br />
Total Energy In<br />
Bitumen from Wells<br />
Chemical Energy Flow (GJ/day)<br />
31 363 GJ/day<br />
Diluent Feed<br />
Chemical Energy Flow (GJ/day) =<br />
8861 GJ/day<br />
Reservoir Gas<br />
Chemical Energy Flow (GJ/day)<br />
761 GJ/day<br />
Natural Gas<br />
Chemical Energy Flow (GJ/day) =<br />
7197 GJ/day<br />
Electricity Import<br />
Electrical Power (GJ/day) =<br />
335 GJ/day`<br />
Total Energy Out<br />
Saleable Product (Dil-Bit Blend)<br />
Chemical Energy Flow (GJ/day) =<br />
40586 GJ/day<br />
Total Energy In (GJ/day) =<br />
Total Energy Out (GJ/day) =<br />
Energy Efficiency (%) =<br />
Efficiency<br />
48522 GJ/day<br />
40586 GJ/day<br />
84%<br />
Table 7.7.2 Heating Values<br />
Bitumen 0.0399 GJ/kg<br />
Diluent 0.0426 GJ/kg<br />
Reservoir Gas 0.0305 GJ/kg<br />
Natural Gas 0.0457 GJ/kg<br />
7.8 MARP Conceptual Plan<br />
The Measurement and Reporting Plan reporting plan includes both the production battery and<br />
injection facility for the purposes of the ERCB registry reporting.<br />
All flow streams that cross the CPF boundary limit will be measured or estimated depending on<br />
volumes and operational requirements.<br />
The metering requirements are presented on the attached Process Flow Diagrams with the<br />
notes. Oil, water and gas production will be based on the production battery balance of<br />
inventory, dispositions and receipts, and the injection facility will have zero production. Oil, water<br />
and gas production will be pro-rated to wells based on individual well metering. The simplified<br />
reporting structure and water reporting will be based on ERCB Bulletin 2006-11 (ERCB 2006),<br />
the ERCB draft directive Requirements for Water Measurement, Reporting and Use for <strong>Thermal</strong><br />
In Situ Oil Sands Schemes (ERCB 2009) and Directive 17.<br />
7.8.1 Objectives<br />
The project metering objective is to ensure that the required flow meters are properly selected,<br />
installed and configured to accurately determined volumes of all the liquids and gases entering<br />
or leaving the plant as required by ERCB.<br />
The following methodology is considered for measuring report of the plant to ERCB Registry:<br />
A Distributed Control System (“DCS”) receives process data for the plant control. Flow<br />
data are stored for a daily reporting;<br />
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Process and volume data will be stored in a production accounting drive or process<br />
historian;<br />
<strong>Volume</strong> data, well tests, tickets, and receipts will be fed into the production volume<br />
reporting system. A manual upload, using Microsoft Excel, is performed to load data into<br />
production accounting software;<br />
Measured data (volume) with manual inputs, will be fed into the production volume<br />
reporting system for daily production and allocation totals; and<br />
Production accounting generates ERCB registry database.<br />
7.8.2 Process Flow Metering Schematic<br />
The process flow metering, which is laid out on the process flow diagrams, covers both the<br />
production battery and injection facility parts of the plant requiring measurement and reporting to<br />
ERCB. These drawings will be part of the MARP and contain the following major equipment and<br />
information required for accounting and measuring all relevant flows and levels throughout the<br />
plant.<br />
All wells associated with the scheme, representing each well tie-in to the surface<br />
facilities; crude bitumen wells, steam injection wells, disposal wells, and brackish and<br />
fresh water wells.<br />
All surface facilities associated with the scheme, including process equipment for<br />
bitumen treating (free water knock-out drum, treater and diluent recovery separator),<br />
test facility, produced gas handling & mixing and flares, produced water de-oiling (skim<br />
tank, induced gas flotation unit and oil removal filters), water treatment (process water<br />
and fresh water treatment systems), steam generation (drum boiler), disposal and waste<br />
handling (neutralization and dewatering unit),<br />
All applicable receipt points includes gas pipeline, diluent pipeline and truck in (at this<br />
stage only chemicals) and associated LACT,<br />
All applicable disposition points includes pipeline and associated LACT,<br />
All applicable flow lines such as, fuel lines, flare lines, recycle lines, skim lines, steam<br />
and utility lines,<br />
All applicable bitumen, slop oil, and water tanks,<br />
All applicable flow measurement devices and product analyzers (type of devices will be<br />
determined when selected). All flow measurement will be of an electronic type. The<br />
measured signals will be sent to the DCS. All meter compensation, correction factors<br />
and totalizing will be done in the DCS with the exception of a few (e.g. devices located at<br />
the well pad area as a remote location relative to the central processing facility) that<br />
depend on the location of the instruments that could be reporting back to the plant DCS<br />
by a wired data or radio link, and<br />
Manual emulsion sampling at the producers, manual input of result into the DCS, store<br />
to history drive and feed to the production accounting system.<br />
Figure 7.8.2-1 shows a simplified MARP schematic.<br />
The production battery will be a multi-well proration battery, with bitumen, water and gas<br />
production rates being determined by a volumetric balance of the battery limits. This will include<br />
lease fuel as well as an estimation of light ends transferred to the gas system. This will be<br />
accomplished through flow measurement of the total gas stream and gas chromatography<br />
analysis of the stream for light ends. The battery is the main custody transfer for diluent,<br />
blended sales and fuel gas streams associated with the <strong>Project</strong>. Condensate with a density of<br />
approximate 711 kg/ m 3 is the type of diluent planned for use in treating and blending activities.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 136
The injection facility will be a water facility and will not include any oil production or inventory. It<br />
will be set-up to allow for zero gas production. Gas co-injection and lease fuel at the end-users<br />
will provide the total volume transferred from the production battery. The water balance will not<br />
fully “close”, but is expected to have a closure error less than two percent. If the closure error<br />
grows to, or exceeds, five percent, Birchwood will rectify the error through review of applicable<br />
data and meter calibration. Disposal water will be trucked out until the disposal injection well is<br />
ready and approved for use.<br />
7.8.3 Boundary Streams<br />
The following flow streams cross the boundary between the production battery and the injection<br />
facility:<br />
Produced water downstream of the oil removal filter;<br />
Utility water and seal flushes from fresh water treatment system;<br />
Steam from drum boiler to the well injection pads;<br />
Mixed fuel gas to drum boiler; and<br />
Sweet fuel gas to well injection.<br />
Produced water will be directly metered, as this is a critical number in the water balance. Utility<br />
streams will be metered where flow magnitude dictates, and will be estimated based on<br />
engineering design numbers where volumes are less than 3% of the total water. These<br />
estimations will be verified annually or more frequently as required. Steam for well injection<br />
pads is calculated by measuring total-in flow of boiler feed water and total-out flow of boiler blow<br />
down and utility steam use.<br />
7.8.4 <strong>Project</strong> Wells<br />
Injection and production wells are associated with both the injection facility and the production<br />
battery during the circulation phase (usually a few months). Once the wells are turned to steam<br />
assisted gravity drainage mode, production wells are associated with the battery and injection<br />
wells are associated with the injection facility. All water source and disposal wells are<br />
associated with the injection facility. All water production wells and water reinjection wells are<br />
associated with the injection facility.<br />
A test separator will be used to measure and prorate water and oil production. The proration<br />
factor for both water and oil will be kept within the regulated range of 0.85 to 1.15. It is expected<br />
that the proration error will average less than 10%.<br />
7.8.5 <strong>Project</strong> Meters<br />
Metering groups associated with the <strong>Project</strong> are listed below:<br />
• Boiler blowdown;<br />
• Boiler feed water;<br />
• Brackish water source;<br />
• Casing gas;<br />
• HP & LP flares;<br />
• Fresh water source;<br />
• Gas co-injection;<br />
• Gas injection (and co-injection);<br />
• Injection facility lease fuel;<br />
• Pipeline blend;<br />
• Pipeline diluent;<br />
• Pipeline gas;<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 137
• Produced gas;<br />
• Produced water;<br />
• Produced water disposal;<br />
• Test separator liquid and gas streams;<br />
• Evaporator blowdown;<br />
• Steam injection;<br />
• Utility water and steam.<br />
7.8.6 Facility Tankage<br />
All applicable accounting tanks are listed in the following Table.<br />
Table 7.8.6-1 Tank Listing<br />
Tank Tag Product <strong>Volume</strong> Diameter Height<br />
(m3) (mm) (mm)<br />
Injection Facility<br />
T-4000 Boiler Feed Water Tank 2690 16764 12192<br />
T-2000 PW skim Tank 2050 14630 12192<br />
T-2010 PW Skim Tank 2050 14630 12192<br />
T-3000 Deoiled Water Tank 2690 16764 12192<br />
T-2300 Desand Tank 475 7045 12192<br />
T-3440 Neutralization Waste Tank 100 TBD TBD<br />
T-3210 Brackish Make-up Water Tank 80 4572 4877<br />
T-3240 Raw Fresh Water Tank 80 4572 4877<br />
T-9450 Utility Water Tank 11 TBD TBD<br />
T-9650 Domestic Water Tank 5 TBD TBD<br />
T-3500 Waste Water Tank 450 6857 12192<br />
Production Battery<br />
T-7000 Sales Oil Tank 450 6857 12192<br />
T-7010 Sales Oil Tank 450 6857 12192<br />
T-2500 Slop Oil Tank 410 6900 10973<br />
T-2400 Oil Recovery Tank 410 6900 10973<br />
Tanks associated with the injection facility are considered to be 100% water, and vessels or<br />
tanks with consistent inventory are not included.<br />
Tanks associated with the production battery are typically considered to be an emulsion type<br />
(both oil and water). Vessels assumed to have relatively constant make-up and volume are not<br />
included for accounting. These include, but are not limited to, treater, induced gas flotation unit,<br />
oil removal filters, pad test vessel and pipeline inventory.<br />
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7.8.7 <strong>Project</strong> Dispositions and Receipts<br />
The following table outlines the planned disposition and receipt points for the production battery.<br />
Table 7.8.7-1 Production Battery Disposition and Receipt Points<br />
7.9 Chemical Use<br />
Product Disposition/Receipt Name<br />
Water Disposition SAGE Injection Facility<br />
Dilbit Disposition Husky<br />
Condensate Receipt Husky<br />
Gas Disposition SAGE Injection Facility<br />
Gas Receipt Alta Gas<br />
Chemicals will be added to the produced water treatment, the bitumen treatment, water disposal<br />
and the utility water treatment systems. At each point of injection, a static mixer will be installed<br />
downstream of the chemical injection quills to enhance the penetration of chemicals into tight<br />
emulsions.<br />
7.9.1 Produced Water Treatment Stream<br />
The steam generation plant will be equipped with three chemical injection packages; a Sulphite<br />
Injection Package, a Chelant Injection Package and an Amine Injection Package. The chemical<br />
injection rate will be automatically adjusted in relation to the BFW flow rate. Oxygen scavenger<br />
and chelant will be injected into the BFW pumps suction header.<br />
7.9.1.2 Feed Water<br />
Magnesium Oxide, caustic, scale inhibitor/dispersant and antifoam/foam control chemicals are<br />
added to the feed water at various stages of feed water processing.<br />
Magnesium oxide slurry is used to condition the feed water prior to commencing steam<br />
generation or water treatment as an elevated suspended solids level is required to initiate the<br />
steam generation and water/bitumen treatment processes. Magnesium oxide is added to the<br />
system from the Mag Ox silo (T-3330). This is shown in Figure 7.2.3-1B. Magnesium oxide<br />
prevents scaling while rapidly allowing for the development of silica and other potentially scaling<br />
constituents including magnesium hydroxide and calcium carbonate. Magnesium oxide demand<br />
is proportional to the amount of silica in the produced water stream and is metered via a screw<br />
conveyor into a slurry mix tank.<br />
Caustic is required to maintain the proper pH for silica precipitation. Caustic is added to the<br />
incoming feed to control the pH in the evaporator. The system consists of two metered pumps<br />
and a tank; the two pumps are dedicated to the incoming feed and can be used to adjust the pH<br />
in the feed conditioning tank (start-up) or to trim pH in the evaporator.<br />
Scale Inhibitor/dispersant is utilized to control suspended solids and mineral build up that occurs<br />
on heat exchange surfaces. The scale inhibitor/dispersant can be added in small doses to<br />
prevent scaling on the de-aerator. The scale inhibitor can be dosed to the feed line prior to the<br />
in-line mixer on a continuous basis.<br />
The foam control package will control the foam that can occur due to the presence of organic<br />
compounds carrying over with the vapour and potentially impacting the compressor operation<br />
and distillate quality. The package will include two metering pumps, video cameras, lights and<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 139
monitors for the evaporator. Antifoam can be added to the evaporator feed or sump, on an as<br />
needed or continuous basis; this will depend on the foaming propensity of the produced water.<br />
7.9.1.3 Boiler Feed Water<br />
Boiler Feed Water will be treated with a sulphite oxygen scavenger, chelant and amine. The<br />
sulphite scavenger will remove residual dissolved oxygen in the BFW. The scavenger will<br />
minimize corrosion.<br />
Chelants bond to various cations such as iron, magnesium and calcium and will minimize the<br />
deposition of chrystalline deposits in the boilers. Amine is added to steam condensate to protect<br />
piping from corrosion by neutralizing acidic compounds and by forming a protective film on<br />
metal surfaces.<br />
7.9.2 Bitumen Treatment<br />
7.9.2.1 Free Water Knockout Tank<br />
Clarifier, diluent and demulsifiers must be added to the produced fluid (oil and water) stream<br />
prior to entering the FWKO tank, in order to ensure oil separation.<br />
1. Clarifiers, in the form of polymers, will assist in coalescence of oil droplets in the skim<br />
tanks and will be added to the system upstream of the FWKO vessel and treater. The<br />
rate of addition will be dependent on the water fraction of the emulsion and is estimated<br />
to range between 100 ppm to 200 ppm.<br />
2. Diluent will be injected into the system to upstream of the FWKO and treater as well as<br />
prior to entering the LACT unit. In the water treatment phase, the diluent will increase the<br />
density differential between the oil and water phases of the emulsion and thereby allow<br />
separation via gravity and ensure the oil phase floats on the water phase. The injection<br />
rate will be designed to produce a blended dry oil-phase gravity of about 12 o API or ~<br />
27% diluent fraction in the dil-bit blend. The injection system will be designed to deliver<br />
twice this rate to respond to variations in bitumen density as well optimizing treater<br />
performance and managing treatment upsets.<br />
During abnormal operating conditions the diluent injection rate will be kept at a minimum<br />
dosage that can produce sales oil product that meets pipeline specifications. Over<br />
dosing with diluent can lead to excessive vapour generation during the treatment<br />
process. The FWKO and treater pressure must be maintain above 400 kPa to control<br />
flashing and prevent the diluent from boiling.<br />
3. Demulsifiers will help coalese water droplets in the oil phase. Demulsifiers will be<br />
injected upstream of the FWKO and treater. The rate of injection will vary in accordance<br />
with the oil fraction of the emulsion and is estimated to range between 200 ppm to 400<br />
ppm.<br />
7.9.2.5 Induced Gas Flotation<br />
A chemical injection quill is provided on the suction portion of the IGF for injection of clarifier if<br />
required during start up.<br />
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7.9.2.5 Sales Oil<br />
Injection of diluent prior will also occur prior to the sales oil entering the LACT unit in order to<br />
reduce viscosity of the treated oil and frictional drag in the market pipeline.<br />
7.10 Services and Utilities<br />
7.10.1 Field Office Facility and Camps<br />
A small area, as shown in the NE area of the facility design in Figure 7.1-1, will be developed to<br />
accommodate workers needs for administration, sanitization, washrooms facilities and meals<br />
and a separate storage area.<br />
Birchwood does not propose to utilize a construction camp for the housing of workers during the<br />
preparation of the well pad and central processing facility, for the assembly of the modular<br />
central processing facility or the drilling of the well pairs. Workers can be adequately housed in<br />
Cold Lake existing facilities. Birchwood has given due consideration to other industrial activity in<br />
the area and has planned the construction phase, which will require approximately 100<br />
employees over a three month period, to be timed such that we avoid conflicts with other<br />
industrial, municipal and commercial developments. In addition, Birchwood has been in contact<br />
with hotels in both the Bonnyville and Cold Lake area and has tentative arrangements to book<br />
room blocks for personnel.<br />
7.10.2 Highways and Rights of Way<br />
Access to the site for construction and operations are specified in Section 2.3. Highway 892<br />
and Birchwood's access roads will provide the routes necessary to access the site from Cold<br />
Lake and Bonnyville.<br />
7.10.3 Utilities<br />
7.10.3.1 Electrical Power<br />
The normal operating electrical load is estimated at 5 MW. Power will be brought to the site via<br />
an electrical connection from Atco Electric. Atco will supply 25 kV line up to the plant boundary<br />
and tie-in the connection with an above ground 25kV cable. Low power distribution transformers<br />
(25kV-480 V) fed from the 25 kV disconnect switch will provide the low voltage power<br />
distribution for the CPF and well pad. Given the accessibility of low interruptible electrical supply<br />
and the limited demand, cogeneration not considered to be economically feasible.<br />
The main consumers of power are motors. The equipment list is Appendix 7-1 includes all the<br />
known motors and electrical demand. A full service backup generator for emergency upset<br />
conditions is not included in the design however a temporary power generator set for<br />
emergency lighting, glycol circulation, and vapor recovery.<br />
The grounding resistor for the 480 Volt system consists of high resistance grounded at 5 amps<br />
through a 5 amp neutral grounding resistor connected to each transformer.<br />
7.10.3.2 Natural Gas<br />
Natural Gas will be provided to the facility by Altagas. The natural gas will be piped to the CPF<br />
at a minimum delivery pressure of 5000 kPa.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 141
7.10.3.3 Pipelines<br />
7.10.3.3.1 Diluent Pipeline<br />
Diluent from the Husky diluent line, license # 19114-73, running adjacent to the eastern edge<br />
(see Figure 1.2-3) of the CPF pad will be utilized as the diluent source for the plant. The diluent<br />
pipeline into the plant site is expected to operate with sufficient pressure and reliability that there<br />
will be no requirement for a diluent storage tank or diluent injection pump(s). The Diluent riser<br />
will be equipped with an emergency shut-off valve and the flow will be measured and totalized<br />
to reconcile with custody transfer records. Space has been allowed should there be a<br />
requirement for Diluent storage.<br />
7.10.3.3.2 Sales Pipeline<br />
The Husky crude oil emulsion line, license 19115-73, will be utilized to access sales markets.<br />
7.11 Health, Safety and Environmental Controls<br />
Protection of the health and safety of community residents, Birchwood and contractor personnel<br />
and the environment are of fundamental importance to Birchwood Resources Inc. To this end,<br />
safety and environmental management programs will be developed which provide general<br />
direction for protecting human and natural elements as well as very specific training<br />
requirements and safe work operating procedures for controlling and/or mitigating hazards and<br />
environmental degradation. The various components identified include:<br />
Health and Safety Program<br />
Codes of Practice Program<br />
Corporate Emergency Response Plan<br />
Employee Health Safety and Environment Handbook<br />
Domestic and Hazardous Waste Management Program<br />
Pipeline Installation and Monitoring Program<br />
Quality Control Program<br />
In addition, Birchwood follows the requirements laid out in various IRP's and Manuals<br />
developed by industry associations in conjunction with government agencies.<br />
7.11.1 Facility Emergency Response Plan<br />
A Corporate ERP has been developed and implemented. The plan will be further expanded to<br />
incorporate evacuation requirements for residences in proximity to the well pad and CPF,<br />
escalation of alerts and call down procedures, external emergency involvement (eg., registration<br />
with STARS, agreement with local area hospitality organization for establishment of a local<br />
emergency response center), and additional training will be provided to Birchwood's staff to<br />
ensure they remain current with the plans elements. As well, participation in a desk top<br />
simulation with the ERCB and other third parties will be scheduled to be conducted prior to the<br />
commencement of the project's circulation phase.<br />
The current ERP addresses incidents and accidents outlined in ERCB Directive D-71.<br />
Amendments to the ERP will have to address following additional incidents:<br />
Central Processing Facility Shut Down<br />
Well Pad and/or Well bore shut down<br />
Fire in or on company facilities<br />
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Wildfire Prevention<br />
Steam Line Rupture<br />
High Pressure Vapour Equipment<br />
The site specific Emergency Response Plan will be forwarded to the ERCB for approval prior to<br />
commencement of plant operation.<br />
7.11.2 Fire Control Plan<br />
There are two potential fire types that could occur at or near the Birchwood proposed facilities; a<br />
wildfire could break out in the area or a fire could start at an ignition source in the company's<br />
facilities. As part of the site specific ERP, Birchwood will developed a Fire Control Plan to be<br />
approved by Forest Protection Division of ESRD. The following provides a summary of<br />
protection measures for both types of fires.<br />
7.11.2.1 Wildfire Prevention<br />
The leading cause of fires in or around oilfield facilities are brush burning, flaring, ATV use and<br />
cooking. All such fires are preventable using various mitigation and Best Management Practice<br />
techniques. Other fire control issues will be identified, along with mitigation measures, in<br />
Birchwood's Fire Control Plan that will be approved by AESRD prior to construction.<br />
7.11.2.2 Facilities Fire Protection<br />
The potential sources of fire resulting from the project, and associated mitigation strategy are as<br />
follows:<br />
Internal operations in the CPF:<br />
Non-combustible materials will be used in building construction where possible,<br />
Buildings will be placed to allow adequate spacing between buildings to prevent fires<br />
from spreading,<br />
Every building in which hydrocarbon liquids and/or produced gas vapours will be<br />
equipped with Lower Explosive (LEL) and/or H2S detection monitors.<br />
All internal combustion engines will be equipped with flame arrestors.<br />
Fire alarms will be installed in areas where there is potential for fire to occur. Fire eye<br />
sensors capable of detecting open flame will also be placed in critical areas of the CPF.<br />
Detectors, alarms and sensors will be tied into the process control system allowing for<br />
prompt response should an incident occur.<br />
7.11.3 Air Emissions Management<br />
The CPF will utilize a Vapour Recovery System to capture all continuous vapours and re-use<br />
them as a fuel source. Fugitive emission monitoring will be in compliance with the Canadian<br />
Council of Ministers of the Environment (CCME) Code of Practice Measurement and Control of<br />
Fugitive Volatile Organic Chemicals (VOC) Emissions from Equipment Leaks.<br />
The plant will be equipped with air monitoring devices as required by Section 14 of the AEPEA,<br />
specifically the "Alberta Ambient Air Quality Guidelines", the Lower Athabasca Regional Plan<br />
(LARP), and Environment Canada's "Protocals and Performance Specifications for Continuous<br />
Monitoring of Gaseous Emissions from <strong>Thermal</strong> Power Generation".<br />
All NOx emitting equipment will utilize low NOx burner technology as required by the LARP.<br />
Specific air monitoring requirements, including sampling locations, frequency, parameters to be<br />
monitored and reporting requirements will be issued by AESRD upon approval of the facility.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 143
Birchwood will participate in LICA air monitoring initiatives to assist in monitoring cumulative and<br />
regional air quality information.<br />
Air quality model results are summarized in Section 8.3.2 – Environment Conditions and in<br />
Consultants Report 2 Air Quality Model Results.<br />
7.11.4 Noise Emissions Management<br />
Noise levels at the plant will be maintained at or under the conditions prescribed in ERCB<br />
Directive 38 "Noise Control", the "Alberta Occupational Health and Safety Act" and the "Alberta<br />
Occupational Health and Safety Regulations".<br />
The primary sources of noise release in the proposed project are compressors, pumps,<br />
generators, blowers, coolers (fans) and control, switching and vent valves. This equipment is<br />
housed in buildings or equipment specific enclosures providing mitigation. Initial noise modeling<br />
indicates that the daytime and nighttime noise levels are within the limits required by the ERCB<br />
(See Section 8.4 – Environment Conditions and Consultants Report 3 Noise Assessment).<br />
Noise levels inside buildings may not meet OH&S requirements for personal safety and as such<br />
safety equipment (ear plugs/muffs) will be required in certain areas of the facility to prevent of<br />
hearing loss.<br />
7.11.5 Spill Control and Leak Detection<br />
Engineered containment systems will be utilized wherever there is the potential for a release<br />
from process equipment. Where practical, all systems that contain hydrocarbons, chemicals and<br />
brackish water will be designed to allow for visual inspection for leaks. All containment systems<br />
will be in compliance with Directive 55 "Storage Requirements for the Upstream Petroleum<br />
Industry". In addition, above ground lines will allow for leaks to be readily observed.<br />
The base of the facility and well pad will be composed of clay or cement thereby preventing<br />
migration of spills into the soils below facilities. The site will be bermed to provide adequate<br />
retention of any spills on location. Spills will be reported to the ERCB/AESRD as required by<br />
regulatory requirements. Any incident are required to be investigated as per the Corporate ERP<br />
and quality assurance programs.<br />
7.11.6 Surface Water Management<br />
It is anticipated that the site will be bermed and that a contoured, compacted clay base will<br />
underlay all of the wellhead, pipeline, production and storage modules. A surface water run off<br />
drainage pond has been included in the plot plan design sized to manage seasonal<br />
precipitation. Water in the pond will tested, treated and either released off site or, if untreatable<br />
for release, used in the process or hauled to an approved disposal facility. Site contouring will<br />
ensure that all run off is collected in the pond.<br />
7.12 Chemical and Waste Management<br />
7.12.1 Chemical Management<br />
A Chemical Management Program has been established to effectively control on-site chemical<br />
hazards, usage and inventory. Chemicals used on site will be managed in accordance with<br />
Transportation of Dangerous Goods Act and Regulations (TDG) and Workplace Hazardous<br />
Materials Information System (WHMIS), with individuals trained in accordance with<br />
requirements.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 144
Table 7.12.1-1 provides the required chemicals for the proposed SAGD process as well as the<br />
injection point, storage and estimated annual useage:<br />
Table 7.12.1-1 Chemical Summary<br />
Chemical<br />
Delivery<br />
Method<br />
Injection Point Storage Method<br />
Annual <strong>Volume</strong><br />
Treating Demulsifier Trucked In FWKO/Treater Bin on Site 126.5<br />
Reverse Demulsifier Trucked in FWKO/Treater Bin on Site 100.5<br />
De-oiling Polymer (c/w<br />
Dilution Water)<br />
De-oiling Coagulent (c/w<br />
Dilution Water)<br />
Caustic (Sodium Hydroxide<br />
- 50%)<br />
Water Treatment Anti-<br />
Foam Agent<br />
Disposal Treating<br />
Magnesium Oxide<br />
DisposaL Treating<br />
Hydrochloric Acid<br />
Disposal Treating Sodium<br />
Hypochlite<br />
Disposal Treating Sodium<br />
Bisulphate<br />
BFW System Oxygen<br />
Scavenger<br />
Trucked In<br />
Skim Tanks - A & B<br />
IGF In<br />
IGF Out<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 145<br />
M3<br />
Bin on Site 157.0<br />
Trucked In ORF Back Wash Bin on Site 10.1<br />
Trucked In Evaporator Bin on Site 384.0<br />
Trucked In De-aerator Bin on Site 10.3<br />
Trucked In Evaporator Silo on Site 319.0<br />
Trucked In Neutralization Tank Bin on Site 230.0<br />
Trucked In Disposal Water Tank Bin on Site 10.0<br />
Trucked In Disposal Water Tank Bin on Site 0.8<br />
Trucked In Boiler Feed Water Bin on Site 24.4<br />
BFW System Chelant Trucked In Boiler Feed Water Bin on Site 9.7<br />
Steam Injection Filming<br />
Amine<br />
Domestic Water<br />
Hypochlorite<br />
Trucked In HP Steam/ Utility Steam Bin on Site 3.7<br />
Trucked In<br />
Domestic Fresh Water<br />
Feed<br />
Bin on Site 2.5<br />
Utility Water SAC Salt Trucked In Utility Water Feed Sacks on Site 107.7
7.12.2 Waste Management<br />
A Waste Management Program has been established for the proposed project in order to<br />
effectively limit potentially hazardous waste generation as well as minimize other waste<br />
generation and the associated waste disposal required. In accordance with Directive 58, the<br />
primary goals of the program will be to reduce, re-use, recycle and recover. In accordance with<br />
Directive 58 as well the Waste Control Regulation, the following program requires the following:<br />
Classification of DOW and NDOW wastes, measurement of waste and controlling waste<br />
generation,<br />
Proper handling, storage, treatment (if required) and disposal,<br />
Ensuring waste transporters are trained in handling the waste streams they are<br />
accepting for transport,<br />
Ensuring facilities that accept various waste streams are properly approved/licensed to<br />
accept such streams for further treatment, recycling or disposal, and<br />
Documenting, tracking and reporting of waste streams generated at company facilities<br />
including the disposal method proposed and actually used at various facilities.<br />
Construction Waste will be minimal as the buildings, associated facilities and pipes will be<br />
prefabricated in a facility in Airdrie. The waste generated at that location is currently recycled or<br />
disposed of at approved facilities. Small volumes of waste will be generated at the facility<br />
location during construction. This waste will be contained in bins which are segregated. Wastes<br />
will be sorted and placed into the relevant container in order for transport to a recycling facility,<br />
wherever possible. If recycling is not an option, the waste will be transported to a suitable,<br />
approved where required, disposal facility. Various options exist within a relatively close area to<br />
the facility and well pad location, including the Tervita Class II landfill, the Beaver River Regional<br />
Waste Management Commission transfer stations, Lindbergh Salt Cavern, and Ardmore<br />
Landfill.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 146
Figure 7.1.1 CPF and Well Pad Plot Plan<br />
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Figure 7.1.2 3D Model of CPF and Well Pad<br />
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Figure 7.2.2 Process Flowsheet 200-1 Wellpad<br />
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Figure 7.2.2-A Block Flow Diagram - De-Oiling, Water treatment and Steam Generation<br />
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Figure 7.2.2-B Water Balance - De-Oiling, Water treatment and Steam Generation<br />
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Figure 7.2.1-1 Process Flowsheet 100-8 Steam Generation<br />
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Figure 7.2.2-1 Process Flowsheet 100-6 Water Treatment<br />
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Figure 7.2.3-1A Process Flowsheet 100-7A Water Treatment<br />
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Figure 7.2.3-1B Process Flowsheet 100-7B Water Treatment<br />
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Figure 7.2.3-2 Process Flowsheet 100-1 Inlet Process<br />
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Figure 7.3-1 Process Flowsheet 100-2 Bitumen Treating<br />
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Figure 7.3.1-1 Process Flowsheet 100-4 De-Oiling<br />
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Figure 7.3.2-1 Process Flowsheet 100-5 Desand and Slop Oil<br />
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Figure 7.3.3-1 Process Flowsheet 100-3 Bitumen Storage<br />
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Figure 7.4-1 Process Flowsheet 100-9 Glycol System<br />
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Figure 7.5-1 Process Flowsheet 100-10 Utilities Instrument Air/Fuel Gas<br />
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Figure 7.6-1 Process Flowsheet 100-11 Vapor Recovery<br />
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Figure 7.8.2-1 Simplified MARP Schematic<br />
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Appendix 7.1 Equipment List<br />
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Appendix 7.2 Heat and Material Balance<br />
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Appendix 7.3 Waste Management Table<br />
Waste Type ERCB Waste Code Storage<br />
<strong>Volume</strong><br />
Construction<br />
Location<br />
Month<br />
Absorbents OILABS BIN As<br />
generated<br />
Cardboard CONMAT/NDOW BIN As<br />
generated<br />
Electrical<br />
BIN As<br />
Wiring<br />
generated<br />
Glass CONMAT BIN As<br />
generated<br />
Insulation CONMAT BIN As<br />
generated<br />
Lube Oil LUBOIL Dedicated Container None<br />
Identified<br />
Oil filters FILLUB Dedicated Container None<br />
Identified<br />
Paint WPAINT Dedicated Container None<br />
Identified<br />
Packing<br />
DOMWST BIN As<br />
Materials<br />
generated<br />
Pallets CONMAT Dedicated<br />
As<br />
Container/BIN<br />
generated<br />
Welding Rods CONMAT BIN As<br />
generated<br />
Wood CONMAT BIN As<br />
generated<br />
Disposal<br />
responsibility<br />
Disposal<br />
Method<br />
Disposal Location<br />
Operator Recycle 3rd party-licensed facility holder<br />
Operator Recycle 3rd party –licensed facility holder<br />
Operator Recycle 3rd party –licensed facility holder<br />
Operator Recycle 3rd party - licensed facility holder<br />
Operator Dispose Class II landfill<br />
Operator Recycle 3rd party –licensed facility holder<br />
Operator Recycle 3rd party- licensed facility holder<br />
Operator Recycle 3rd party – licensed facility holder<br />
Operator Dispose Class II landfill<br />
Operator Recycle/<br />
Dispose<br />
Return to Supplier/Class II landfill<br />
Operator Dispose Class II landfill<br />
Operator Reuse/<br />
Dispose<br />
Some wood may be reusable (eg pallet<br />
material) Class II Landfill<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 182
Waste Type ERCB Waste Code Storage<br />
Location<br />
Drilling Operations<br />
Cement Cement/NDOW N/A<br />
Drilling Mud<br />
and Cuttings –<br />
surface hole<br />
(gel chem)<br />
Drilling Mud<br />
and Cuttings –<br />
intermediate<br />
and bottom<br />
hole (invert<br />
mud)<br />
NDOW Tank<br />
SOILCO Tank<br />
<strong>Volume</strong><br />
Month<br />
5-8m3 per<br />
well<br />
100-150m3<br />
per well<br />
200-300m 3<br />
per well<br />
Disposal<br />
responsibility<br />
Disposal<br />
Method<br />
Disposal Location<br />
Operator Bury Bury on-site<br />
Operator<br />
Operator<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 183<br />
Land<br />
spread<br />
Cavern<br />
Disposal<br />
NE-01-064-04W4M<br />
Approved processing facility - Tervita<br />
Lube Oil LUBOIL Dedicated container Variable Operator Recycle Approved processing facility (Tervita)<br />
Mud Pails EMTCON Bin Variable Operator<br />
Recycle/<br />
Dispose<br />
Class II landfill<br />
Mud Sacks EMTCON Bin Variable Operator Disposal Class II Landfill<br />
Pipe Dope<br />
Containers<br />
EMTCON Bin Variable Operator Recycle Return to supplier<br />
Pallets CONMAT Bin Variable Operator<br />
Recycle/<br />
disposal<br />
Return to mud company<br />
Scrap Metal SMATAL Bin Variable Operator Recycle Approved 3rd party
Waste Type ERCB Waste Code<br />
Storage<br />
Location<br />
<strong>Volume</strong><br />
Month<br />
Disposal<br />
responsibility<br />
Disposal<br />
Method<br />
Disposal Location<br />
Facility Operations<br />
Containers: Treating<br />
Demulsifier<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Deoiling<br />
Polymer<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Deoiling<br />
Coagulant<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Treating<br />
Reverse Demulsifier<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Water Treating<br />
Caustic<br />
CAUSTIC Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Water Treating<br />
Antifoam<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Disposal<br />
Treating MagOx<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Disposal Treating<br />
Sulphuric Acid<br />
ACID<br />
Sulphuric<br />
Acid Tank<br />
Vary with<br />
Production<br />
Operator Deep Well On facility pending approval<br />
Disposal Treating Sludge ORGCHM Sludge Bins 63 m 3 Operator Deep Well On facility pending approval<br />
Containers: Water/Disposal<br />
Treating Sodium<br />
Hypochlorite<br />
Containers: Water/Disposal<br />
Treating Sodium Bisulphite<br />
Containers: BFW System<br />
Oxygen Scavenger<br />
Containers: BFW System<br />
Chelant<br />
Containers: Steam<br />
Injection Filming Amine<br />
ORGCHM Bins<br />
ORGCHM Bins<br />
CORINH Bins<br />
ORGCHM Bins<br />
ORGCHM Bins<br />
As<br />
generated<br />
As<br />
generated<br />
As<br />
generated<br />
As<br />
generated<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Operator Recycle Return to supplier<br />
Operator Recycle Return to supplier<br />
Operator Recycle Return to supplier<br />
Operator Recycle Return to supplier<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 184
Containers:<br />
Fresh/Domestic Water<br />
Hypochlorite<br />
Containers: Utility Water<br />
SAC Salt<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
ORGCHM Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Herbicide PSTCON Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Containers: Pesticide PSTCON Bins<br />
As<br />
generated<br />
Operator Recycle Return to supplier<br />
Equipment Cleaning Waste WSHWTR Bins<br />
As<br />
generated<br />
Operator 3rd Party Class II landfill<br />
Evaporator Blowdown to<br />
Disposal wells<br />
WATER 10767.5 m 3 Operator<br />
Disposal Water<br />
Well<br />
On facility pending approval<br />
Batteries BATT Bins Variable Operator Recycle 3rd Party – licensed facility<br />
Empty Containers EMTCON Bins<br />
As<br />
generated<br />
Operator<br />
Recycle/<br />
disposal<br />
Class II landfill<br />
Filters FILOTH<br />
Dedicated<br />
Container<br />
0.22 m 3 Operator<br />
Recycle/<br />
disposal<br />
3rd Party licensed facility<br />
Garbage: Office DOMWST Bins 2.41 m 3 Operator Dispose Class II landfill<br />
Packing materials DOMWST Bins 2.3 m 3 Operator Dispose Class II landfill<br />
Pallets DOMWST Bin 2.17 m 3 Operator Recycle Return to supplier<br />
Process Blowdown Water<br />
(produced water)<br />
WATER<br />
Produced Sand SAND<br />
Rags: Oily OILRAG<br />
Rag Layer Waste SLGEML<br />
Septic Fluids WSTMIS<br />
Waste Lube Oil LUBOIL<br />
Storage not<br />
required<br />
Dedicated<br />
container<br />
Dedicated<br />
container<br />
Dedicated<br />
container<br />
Septic<br />
System<br />
Dedicated<br />
container<br />
10,754m3 Operator Recycle Return to process<br />
As<br />
Generated<br />
Operator Disposal<br />
Approved Cavern – testing required to<br />
determine handling/disposal<br />
0.23 m 3 Operator Recycle 3rd party – licensed facility<br />
As<br />
Generated<br />
Operator<br />
Recycle/<br />
Dispose<br />
Rag layer waste will return for<br />
processing/Approved Disposal cavern<br />
30-50m3 Operator Disposal Receipt at approved facility<br />
0.05 m 3 Operator Recycle Approved Processing Facility<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 185
8 Environmental Review and Baseline Assessment<br />
8.1 Overview<br />
The Resource Development Area (RDA) contains both private and public lands. The <strong>Project</strong><br />
Development Area (PDA) lies wholly within Public lands and it is designated as “white zone” in<br />
the Crown Land system.<br />
Birchwood utilized the Lower Athabasca Regional Plan, 2012 (“LARP”), the Cold Lake Sub<br />
Regional Integrated Resource Plan, 1996 (“CL SRIRP”), and the Crane Lake Area Structure<br />
Plan (2006) (“CLASP”), public/stakeholder input from Open Houses and direct contact and the<br />
various legislation as a baseline for determining the potential environmental issues and/or<br />
impacts that could occur as a result of the proposed development:<br />
Birchwood identified potential impacts in the following areas:<br />
Land and Resource Use,<br />
Traditional Land Use,<br />
Historical Resources,<br />
Air Quality Impacts,<br />
Noise Impacts,<br />
Water Quality Impacts (surface water, potable and non-potable groundwater)<br />
Soil and Terrain Impacts,<br />
Vegetation and Wildlife Impacts,<br />
Socio-Economic Impacts,<br />
Human Health, and<br />
Socio-Economic Impacts<br />
The proposed project is located at the southern portion of the Central Dry Mixed Wood Sub-<br />
Region of the Lower Boreal Forest Region of North Eastern Alberta. The area is characterized<br />
by "level to gently undulating glacial till, lacustrine plains and significant hummocky uplands in<br />
the southern extents"). In undisturbed conditions, the upland Eco region supports a wide variety<br />
of wildlife habitat including black bear, moose, fishers, numerous bird species and a small<br />
number of amphibians and reptiles. Vegetation is predominately comprised of trembling aspen,<br />
white spruce, low-bush cranberry on uplands. On lowlands vegetation is comprised of Jack<br />
pine/black spruce, Labrador tea, feathermosses and bog-cranberry transitioning to fens and<br />
bogs in the cold wet lower areas where black spruce, willow and bog birch, Labrador tea, few<br />
forbs, feathermosses and peat moss exist.<br />
Soils in the eco sub-region vary from coarse well drained Brunisols and Regosols, to medium to<br />
coarse and mix textured Grey luvisols in the uplands where warmer and drier conditions prevail.<br />
In colder wet areas soils range from variable textured imperfectly to poorly drained Luvisolic and<br />
Gleysolic soils to organic soils.<br />
There are numerous wetlands in the regional development area; Birchwood has located the<br />
central processing facility and well pad to ensure that there is a minimum 300 m setback from all<br />
existing wetlands. There is no requirement for the development of any water crossings.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 186
The latitude and longitude co-ordinates of the proposed facility is as follows:<br />
NW corner 54 o 30' 15.421" N<br />
110 o 29 ' 25.755" W<br />
SW corner 54 o 30 ' 05.074" N<br />
110 o 29' 25.683" W<br />
NE corner 54' 30 ' 15.418" N<br />
110 o 29' 53.526 W<br />
SE corner 54 o 30' 05.074 N<br />
110 o 29 53.455" W<br />
Figure 1.2-1 to Figure 1.2-3 illustrates the location of the proposed facility and the distance to<br />
surrounding communities, residences, water bodies, infrastructure and industrial development.<br />
8.2 Historical Resources<br />
8.2.1 Aerial Photograph Review<br />
The proposed Birchwood facility lies on predominantly cleared grazing land with forested land in<br />
the south western portion of the <strong>Project</strong> Development Area. A review of aerial photographs<br />
indicates that the land was undisturbed and forested from as late as 1949 to 1982. The aerial<br />
photograph taken in 1950 shows a trail coming through the PDA on the central west portion of<br />
the site, in 1977 the trail is no longer visual in the aerial photograph. The photograph taken in<br />
1988 indicates that 10 ha of the land in the proposed development area were cleared for use as<br />
pastureland for cattle grazing. Aerial Photographs of the location are provided in Section 2.4.10<br />
Figures Figure 2.4.10A – Figure 2.4.10D.<br />
8.2.2 Land Use<br />
The land has been used for hunting and trapping, and cattle grazing. The land to the north and<br />
northwest of the proposed development area, especially along the shore of Crane Lake, has<br />
been used for camping, boating and associated "lake" recreational activities, since the mid to<br />
late 1950's. There is a trail south of the lake shore and approximately 700-1000 m north of the<br />
proposed development area that is used for hiking and all-terrain vehicles. The <strong>Sage</strong> project has<br />
been placed to avoid interference with these activities.<br />
The Municipality of Bonnyville has a Range Improvement Plan (CNT010013) in place that<br />
expires in 2016.<br />
Interviews with the grazing lease holder indicate that the land has been used for cattle grazing<br />
for 10+ years and it was not productive from a vegetation point of view. In addition, there have<br />
been no First Nations requests for access since the grazing lease was issued in 1975.<br />
A detailed review of land use in the RDA and regional area is provided in Section 2.4.<br />
8.2.2 Traditional Land Use<br />
The proposed development area lies within First Nations Traditional Lands including possible<br />
historical usage by the following First Nations:<br />
Cold Lake First Nation<br />
Beaver Lake Cree Nation<br />
Heart Lake First Nation<br />
Kehewin First Nation<br />
Frog Lake First Nation<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 187
Whitefish – Goodfish First Nation<br />
Birchwood conducted a Traditional Knowledge Assessment with the Cold Lake First Nation in<br />
September, 2011 for the proposed access road and well sites. The report indicated that the land<br />
would provide territory hunting, trapping and gathering/forage activities. The report also<br />
indicated that there was a potential area of interest that lies on the northern edge of the<br />
proposed development site. Upon completing the aerial photographic review, the area of<br />
interest in question was determined to be a brush pile from logging activities.<br />
Based on interviews with occupants, historical aerial photographs, existing development and<br />
current land usage, the size of the proposed development area would have a little to no impact<br />
on the traditional land uses.<br />
8.3 Air Resources<br />
8.3.1 Climate and Meteorology<br />
The climate in the Central Dry Mixed-Wood sub-region is characterized by short dry summers<br />
and long cold winters. Due to the extent of the central mixed wood sub-region across Alberta,<br />
climatic and meteorological data is taken from Cold Lake A weather station; the average<br />
temperature low ranges from -21.7 o C in January to a temperature high of 22.9 0 C in July. The<br />
average mean temperature from May to September is 13.6 0 C and is -6.8 0 C from October to<br />
April. Summer precipitation in the form of rain occurs mostly in May through August, and winter<br />
precipitation in the form of snow occurs from September through to May. Average precipitation<br />
(rainfall and snowfall) over the year is ~ 427 mm with ~ 299 mm during the May to September<br />
growing season. A total volume of 8.3 billion m3 of water falls on the CLBRB each year and<br />
91.5% of this precipitation evaporates or is transpired by vegetation into the air.<br />
The average barometric pressure is 95 kPa. The area experiences low humidity, June, and July<br />
and August have a humidity index rating above 30 on an average of 1, 3 and 4 days per year.<br />
The area has not experienced a humidex over 35 in the past 30 years. Wind chill is mild relative<br />
to other eco-regions and rarely gets below -30.<br />
The following Table describes the design parameters for the plant to ensure that the facility can<br />
withstand the climate within which operation will occur:<br />
Table 8.3.1-1 Climate and Meterologic Data<br />
Plant Elevation 550m ASL<br />
Average Barometric Pressure 95 kPa (absolute)<br />
Basic hourly wind pressure 0.31 kPa (1/10 yrs)<br />
0.37 kPa (1/30 yrs)<br />
0.41 kPa (1/100 yrs)<br />
Earthquake Zone Za= 0<br />
V = 0<br />
Ambient Temperatures 30 0 C (summer design dry bulb)<br />
20 o C (summer winter design dry bulb)<br />
-40 o C (winter design dry bulb)<br />
Precipitation 15 mm (design 15 minute rainfall)<br />
94 mm (design one day rainfall)<br />
Annual Precipitation 460 mm<br />
Ground snow load: 1.6 kPa<br />
Rain falling on snow 0.1kPa<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 188
8.3.2 Air Quality<br />
Emissions from the facility will include Sulphur Dioxide (SO2), Carbon Monoxide CO, Nitric<br />
Oxide (NO) and Nitrogen Dioxide (NO2) and Particulate Matter (PM2.5). The environmental<br />
effects are described in detail in Consultant Report 2 Air Quality Assessment.<br />
Alberta ESRD has addressed the necessity of controlling and monitoring emissions through the<br />
development of the Alberta Ambient Air Quality Guidelines (AAAQG). Short term (1 hour)<br />
objectives have been established for emissions of SO2 and NOx to protect human health and an<br />
annual objective to protect ecosystem health. The ambient air guidelines also establish<br />
objectives for CO and PM2.5 based on health effect criteria and includes one hour and eight hour<br />
objectives for CO, and a 24 hour objective for PM2.5. These objectives are provided in Table<br />
8.3.2-1.<br />
Birchwood has completed a screening level dispersion assessment to determine if the<br />
emissions from the plant meet the AAAQG. The model used was the refined AERMOD<br />
dispersion model in accordance with the Air Quality Model Guideline (AQMG). The methodology<br />
used for the assessment was to identify potential sources of emissions from the proposed<br />
facility and pertinent associated data such as height, emission rate, etc., include building<br />
profiles, area, wind directions and speeds, and topography. As required by the AERMOD<br />
modelling system AERMET, a meteorological pre-processor that creates surface and data<br />
profiles, and AERMAP, a terrain pre-processor that incorporates topography using Digital<br />
Elevation Mapping (DEM) were used. The Building Profile Input Program (BPIP) was run to<br />
account for building downwash.<br />
The air quality modeling results indicate that the emission levels meet all the required AAAQG<br />
standards set by Alberta ESRD during normal, maximum and emergency operating conditions<br />
the summary is presented in Table 8.3.2-1. Dispersion modeling results are presented in Figure<br />
8.3.2-1 and Figure 8.3.2-2.<br />
Notes:<br />
Emission Source<br />
Table 8.3.2-1 Emission Sources and Physical Stack Parameters<br />
Source Information Physical Stack Parameters<br />
UTM NAD 83<br />
Zone 12 E (m)<br />
UTM NAD 83<br />
Zone 12 N (m)<br />
Height<br />
(m)<br />
Diameter<br />
(m)<br />
Exit<br />
Velocity<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 189<br />
(m/s)<br />
Exhaust<br />
Temperature<br />
(K)<br />
Glycol Heater 532242 6039661 6.1 0.61 10.1 481<br />
Drum Boiler 1 532322 6039660 30.5 1.52 15.0 428<br />
Drum Boiler 2 532333 6039660 30.5 1.52 15.0 428<br />
Emergency<br />
Generator 1<br />
High Pressure<br />
Flare 2<br />
Low Pressure<br />
532291 6039607 3.0 0.15 63.4 812<br />
532281 6029530 40.5 26.58 3.0 1295<br />
532281 6039530 21.9 15.63 0.3 1266<br />
Flare 2<br />
1<br />
Stack parameters were adopted from the CAT diesel Emergency Generator (300 ekW) Model 3406C TA<br />
2<br />
Stack parameters for the HP and LP flares represent pseudo parameters, as determined by the ERCB flare spreadsheets. The physical<br />
stack height for both the HP and LP flares is 20 m and the physical stack inner diameters for the HP and LP flares are 346.1 mm and 498.7<br />
mm, respectively.
Table 8.3.2-2 Dispersion Model Predictions<br />
Averaging Predicted Ambient Cumulative AAAQG Percentage<br />
Period Concentration Background Concentration<br />
of AAAQG<br />
NO2 1 hour 156.1 20.7 176.8 300 58.9<br />
Annual 1.7 3.8 5.5 45 12.2<br />
SO2 1 hour 221.6 2.6 224.2 450 49.8<br />
24 hour 10.6 1.4 12.0 125 9.6<br />
Annual 0.8 0 0.8 20 3.8<br />
CO 1 hour 157.2 458.0 621.0 15,000 4.1<br />
8 hour 110.2 400.7 510.9 6,000 8.5<br />
PM2.5 24 hour 1.5 7.0 8.5 30 28.3<br />
Table 8.3.2-3 Emission Rates Used in Dispersion Modeling in (g/s)<br />
Source Name NOx SO2 CO PM2.5<br />
Glycol Heater1,2 0.133 0 0.667 0.014<br />
Drum Boiler 11,2 0.912 0.608 8.106 0.127<br />
Drum Boiler 21,2 0.912 0.608 8.106 0.127<br />
Emergency<br />
Generator3<br />
0.970 0.125 0.189 0.053<br />
HP Flare<br />
(emergency)4<br />
16.706 91.125 90.903 2.519<br />
LP Flare<br />
(emergency)4<br />
0.499 52.211 2.713 0.094<br />
Notes:<br />
1Emission Rates for the glycol heater and drum boilers were provided by Birchwood. The glycol heater PM2.5 emission rate was estimated using US<br />
EPA AP-42 (Chapter 1.4).<br />
2The glycol Heater NOx emission rate is based on 26 g/GJheating input (natural gas fired) compliance limit and the drum boiler NOx emission rate is based on<br />
15.8 g/GJ heating input (mixed gas fired) performance target (AESRD, 2007).<br />
3The emergency generator NOx, CO and PM2.5 emission rates are from CAT Diesel Emergency Generator (300 ekW) Model 3406C TA spec sheet. The<br />
SO2 emission rate was estimated using US EPA AP-42 (Chapter 3.3).<br />
4The SO2 emission rate was calculated by the ERCB spreadsheet based on approximately 2,400 ppm and 36,000 ppm of H2S in flared gas for HP and<br />
LP upsets, respectively. The NOx, CO and PM2.5 emission rates are estimated using US EPA AP-42 (Chapter 13.5).<br />
8.3.2.1 Fugitive Emissions<br />
Fugitive emissions will be monitored in accordance with the application of the Canadian Council<br />
of Ministers of the Environment (CCME) Code of Practice Measurement and Control of Fugitive<br />
Volatile Organic Chemicals (VOC) Emissions from Equipment Leaks and the CCME<br />
Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from<br />
Aboveground Storage Tanks.<br />
Prior to plant operations, Birchwood will have a capable third party conduct a facility inspection<br />
to determine where fugitive emissions may be of concern and develop a monitoring program for<br />
the facility in order to mitigate fugitive emissions.<br />
8.3.2.2 Air Monitoring<br />
Birchwood will install passive exposure stations for measurement of hydrogen sulphide (H2S)<br />
and sulphur dioxide concentrations. The steam generator exhaust stacks will be equipped with<br />
sampling facilities and will be installed, operated and maintained in accordance with the Alberta<br />
Stack Sampling Code and the Air Monitoring Directive.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 190
8.4 Noise Control<br />
The proposed facility lies within a rural area where landowners could be impacted by the noise<br />
that is generated at an industrial facility. There are two residences to the east of the proposed<br />
facility that are within 1.5 km. The east campground of Crane Lake is approximately 1.7 km to<br />
the west of the proposed facility and there are residences on the south west end of Crane Lake,<br />
approximately 1.9 - 4.8 km from the site. The Husky pipeline terminal is 2.7 km to the south.<br />
There are no other industrial facilities within 5 km of the proposed facility/well pad.<br />
Birchwood has designed the facility such that the equipment that could potentially result in noise<br />
related disturbance is housed within buildings or equipment specific enclosures and with the<br />
pumps, fans and boilers being placed on vibration absorbing mountings. Birchwood has<br />
conducted an initial noise impact assessment (see Consultant Report 3) which modeled<br />
cumulative noise and low frequency Noise based on existing receptors and corresponding<br />
permissible sound levels as per ERCB Directive 38 – Noise Control, and an estimation of sound<br />
emissions from the proposed facility using known source emission equipment that will be placed<br />
into the facility.<br />
The assessment method used is as follows:<br />
1. Identification of receptors and corresponding Permissible Sound Levels (PSL's),<br />
2. Estimation of sound emissions form the proposed project facility,<br />
3. Modeling of the sound emissions to predict sound levels at the receptors and to 1.5 km<br />
radius of the plant using calculation standards, source directivity, temperature and<br />
humidity, wind conditions and potential reflections, and<br />
4. Comparison of the predictions to Directive 38 permissible sound levels.<br />
The sound emissions were then modeled using Cadna/A (Version 4.0 135) noise prediction<br />
software which uses environmental sound propagation calculation methods as prescribed by the<br />
International Organization for Standardization Standard 9613.<br />
The results of the cumulative noise assessment (<strong>Project</strong> <strong>Application</strong> Case) are presented in<br />
Table 8.4-1:<br />
Table 8.4-1 Predicted Noise Levels for the <strong>Project</strong> <strong>Application</strong> Case Meets<br />
Receptor Ambient Sound<br />
Level<br />
<strong>Project</strong> Contribution<br />
Level<br />
PSL<br />
Yes/<br />
No?<br />
(a)<br />
Cumulative Sound<br />
Level (b)<br />
Permissible Sound<br />
Level (c)<br />
(dBa) (dBa) (dBa) (dBa)<br />
Daytime Nightime Daytime Nightime Daytime Nighttime Daytime Nighttime<br />
0700–2200 2200-0700 0700-2200 2200-0700 0700-2200 2200-0700 0700-2200 2200-0700<br />
NR 1 45 35 41.8 37.7 46.7 39.6 50 40 Yes<br />
NR 2 45 35 40.3 35.1 46.3 38.1 50 40 Yes<br />
The Cumulative Noise assessment results indicate that noise levels are below ERCB target<br />
levels of 50 dBA for daytime and 40 dBA for night time at receptors that are within the 1.5 km<br />
range from the proposed facility. The highest predicted daytime cumulative sound level is at<br />
receptor #1 and equals 46.7 dBa. The highest predicted nighttime cumulative sound level is also<br />
at receptor #1 and equals 39.6 dBa.<br />
8.4.2 Low Frequency Noise<br />
The modeling indicates that the requirements for low frequency noise levels are met as<br />
illustrated in Table 8.4-2. The low frequency noise assessment results indicate that the potential<br />
for a low frequency noise condition is unlikely; additional assessments as per ERCB Directive<br />
38 will be undertaken if required.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 191
Location<br />
Table 8.4-2 Low Frequency Noise Assessment Results<br />
C-Weighted Sound<br />
Level<br />
A- Weighted Sound<br />
Level<br />
Difference dBC-dBA<br />
(dBC) (dBA) dB<br />
Daytime Nighttime Daytime Nighttime Daytime Nighttime<br />
0700-2200 2200-0700 0700-2200 2200-0700 0700-2200 2200-0700<br />
Potential<br />
LFN<br />
Condition?<br />
(Y/N)<br />
NR 1 57.2 52.8 41.8 37.7 15.4 15.1 No<br />
NR 2 56.2 51.9 40.3 35.1 15.9 16.8 No<br />
Birchwood intends to conduct additional noise assessment studies in the summer of 2013<br />
(baseline ambient noise levels) and once the project is in operation. The latter studies will<br />
measure baseline noise at the receptors within 1.5 km of the plant as well as detailed noise<br />
measurement at the boundaries of the plant site and at other potential receptor locations if<br />
required.<br />
8.5 Water Resources<br />
The proposed development is located within the Cold Lake Beaver River Basin (CLBRB) in<br />
north central Alberta. The Basin is relatively small, covering approximately 3% of the province,<br />
and encompasses approximately 22,000 km 2 of surface land area in the Lower Athabasca<br />
region (see Figure 8.5.3-2). The area is has a wide variety of water uses including industrial,<br />
municipal, domestic, agricultural, and recreational. Drainage in the CLBRB occurs through the<br />
Beaver River which commences at Beaver Lake, runs eastward from Beaver Lake,<br />
approximately 250 km through Alberta to the border with Saskatchewan, continues eastward<br />
until joining the Churchill River at Isle a la Crosse then turns northward, enters Manitoba and<br />
ultimately drains into the Hudson's Bay. The mean annual discharge at the Saskatchewan<br />
Border is 653,000,000m 3 . The Basin is bordered to the north by the Athabasca River basin and<br />
to the south by the North Saskatchewan River Basin.<br />
The hydro stratigraphic units associated with each geological formation present in the study<br />
area, as well as the geological period and other pertinent data are illustrated in Figure 8.5-1.<br />
Figure 3.1 of Consultants Report 1.<br />
8.5.1 Surface Water<br />
Crane Lake is the nearest significant water body to the proposed development area and is<br />
approximately 750 m north. Crane Lake has a surface area of 9.28 km2 and holds 77.4 x 10 6 m<br />
of water. At its deepest point it measures 26 m, with a mean depth of 8.3 m. Water levels in the<br />
Lake have fluctuated around 549.5 meters above surface level since 1980. Other lakes in the<br />
area include Tucker Lake, 6 km north, Hilda Lake ~ 2km east and Ethel Lake ~ 5 km to east.<br />
Crane Lake is situated on a morainal plain. It is a headwater lake with two minor inlets on the<br />
northeast and west shores. The outlet is located on the east north east shore and flows<br />
eastward into Hilda Lake and Ethel and eventually into the Beaver River 8 km south of the<br />
proposed development site. Crane Lake is a popular recreational lake and is one of several<br />
within this basin. The outflow area is protected under the CLSRDP.<br />
The southern shore of Crane Lake is approximately 750 m from the edge of the proposed<br />
location. The high water mark of a Ducks Unlimited reserve (LOC 79028) is 1.5 km + to the NE.<br />
The nearest man made water surface body is a dugout currently used as a water source for the<br />
cattle that graze on the land.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 192
The selection of the proposed CPF and well pad was, in part, based on a review of the surface<br />
water hydrogeology in the surrounding area. Wetland complexes within the RDA and PDA were<br />
classified according to the Alberta Wetland Inventory Standards, see Figure 2.3.11. The area<br />
selected for the well pad and CPF exceed the minimum setback criteria that any wetland areas<br />
are outside the 100m buffer and primary lakes outside the 300m buffer zone for wetland<br />
protection.<br />
Appropriate site construction and grading, in conjunction with the industrial storm water<br />
collection pond, sited in the in the SE quadrant of the Facility pad will prevent migration of<br />
surface spills off the lease.<br />
8.5.2 Surficial Geology and Shallow Aquifers (Hydrostratigraphic Units)<br />
The surface geology of the CLBRB results from a series of preglacial and glacial erosion events<br />
that occurred during the Quaternary period. Preglacial events resulted in a network of buried<br />
valleys generally oriented in an east west direction; the valleys were created by east flowing<br />
rivers that originated in the Rocky Mountains.<br />
Preglacialand glacial channels in the CLBRB include the Beverly, Sinclair and Helina Valleys<br />
and the Big Meadow and Moore Lake Channels. The Moore Lake Channel underlies the Crane<br />
Lake area, including the proposed development area, and has a 2-3 km width and an average<br />
depth of 35 m.<br />
The surficial geology of the CLBRB area is classified into eight formations. Table 8.5.2-1<br />
provides a summary of each formation's geochemical characteristics. The freshwater resources<br />
in the regional development area are found in the Tertiary and Quaternary aquifers. The<br />
proposed development site appears to lie within a predominantly weak recharge area as<br />
illustrated in Figure 8.5.3-3 Recharge and Discharge Areas in the Cold Lake Beaver River<br />
Basin.<br />
Table 8.5.2-1 Shallow Aquifer Geochemical Characteristics<br />
Formation Grande<br />
Centre<br />
Sand<br />
River<br />
Ethel Lake Bonnyville<br />
Muriel<br />
Lake<br />
Empress<br />
Hydrostrategic Unit Intertill sand<br />
and gravel<br />
aquifer<br />
Sand and<br />
Gravel<br />
Aquifer<br />
Unit 1<br />
Aquifer<br />
Aquifer<br />
Unit 3<br />
Aquifer<br />
Unit 1<br />
Aquifer<br />
Depth local<br />
(m)<br />
0-20 20-30 10-50 20-60 50-110 60-130 120-160<br />
Thickness local<br />
approx. (m)<br />
0-2 0-10 2-8 1-20 10 0-10 0-20<br />
Hydraulic<br />
Conductivity<br />
Regional (m/s)<br />
- 1.4 x 10 -4 1.0 x 10 -4<br />
1.18 x 10- 4<br />
to 5 x10 -5<br />
1.30 x 10 -5<br />
to<br />
2.08 x 10 -4<br />
8.8 x 10 -5 to<br />
1.35 x10 -4<br />
Hydraulic<br />
Conductivity Local 2 x 10<br />
(m/s)<br />
-4 - 1.0 x 10 -4 8.5 x 10 -4 3.3 x 10 -4 3.9 x 10 -5<br />
1.6 x10 -5<br />
7.0 x 10 -5<br />
(max)<br />
Flow Direction SE - S S S, E S, E S, E<br />
Effective Porosity 0.2 - 0.2 0.25 0.2 0.2 0.2<br />
Average Gradients 0.004 - 0.004 0.002 0.003 0.004 0.0015<br />
Flow Velocity<br />
(m/yr)<br />
126 - 63 214 156 25 -<br />
TDS<br />
Regional Range<br />
238-963<br />
87 -<br />
10529<br />
151-3967 387-1260 348-1240 247-3080 146-1400<br />
TDS<br />
Local. Range<br />
248-530 - - 344-1080 407-1480 792-2120 678-1870<br />
Predominant Water<br />
Type<br />
Ca-Mg-<br />
HCO3<br />
Ca-Mg-<br />
HCO3<br />
Ca-Mg-<br />
HCO3<br />
Ca-Mg-<br />
HCO3<br />
Ca-Mg-<br />
HCO3<br />
Ca-Mg-<br />
HCO3<br />
Ca-Mg-HCO3<br />
Beneath or<br />
bordering Site<br />
Yes Yes Yes No Yes Yes No<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 193
The Lower Athabasca Regional Plan notes that, while the predominant water type is fresh water<br />
that can be used as drinking water as it meets the Guidelines for Canadian Drinking Water<br />
Quality, specific waters from the Bonnyville, Muriel Lake, and Empress 3 formations contain<br />
relatively high levels of naturally occurring arsenic and uranium.<br />
8.5.3 Bedrock Geology and Aquifers<br />
The bedrock geology of the CLBRB is characterized by Cretaceous, Devonian and Cambrian<br />
rock overlying the Precambrian basement. Figures 8.5.3-1 illustrates the stratigraphic and<br />
hydrostatic columns and rock formations associated with the bedrock and surficial aquifers in<br />
the area.<br />
Table 8.5.3-1 summarizes the physical and geochemical properties of the bedrock aquifers.<br />
Formation Upper and<br />
Middle<br />
Hydrostrategic<br />
Unit<br />
Table 8.5.3-1 Deep Aquifer Geochemical Characteristics.<br />
Cambrian<br />
Cambrian<br />
Aquifer<br />
Contact<br />
Rapids and<br />
Winnipegosis<br />
Winnipegosis<br />
Aquifer<br />
Beaverhill<br />
Lake<br />
Beaverhill<br />
Lake Aquifer<br />
McMurray Clearwater Grand<br />
Rapids<br />
McMurray<br />
Aquifer<br />
Clearwater<br />
Aquifer<br />
Grand<br />
Rapids<br />
Aquifer<br />
Depth local<br />
(m)<br />
Thickness local<br />
1300 - 520 480 440 300<br />
approx.<br />
(m)<br />
Hydraulic<br />
40 110 200 40 – 50 30 105<br />
Conductivity<br />
Regional<br />
(m/s)<br />
5 x 10 -7 1.3 x 10 -7 3.5 x 10 -8 3 x 10 -7 4.3 x 10 -7 -<br />
Hydraulic<br />
Conductivity Local<br />
(m/s)<br />
- - -<br />
2.5 x 10 -7 to<br />
1.0 x 10 -4 1.0 x 10 -6<br />
3.8 x 10 -9<br />
to 5.8 x<br />
10 -6<br />
Flow Direction E, NE NW,NE E W W SE<br />
TDS<br />
238,000 – ->300,000 20,000 – 20,000 – 20,000 30,000 –<br />
Regional Range 310,000<br />
50,000 50,000<br />
35,000<br />
Water Type Na-Cl Na-Cl Na-Cl Na-Cl Na-Cl Na-Cl<br />
8.5.3.1 Brackish Water Resources<br />
Brackish water in the region is used for thermal enhanced recovery projects in the CLRB in<br />
order to preserve freshwater for other uses. Brackish water in the region is found either within or<br />
at depths greater than the hydrocarbon reservoirs, mainly the McMurray, Clearwater and Grand<br />
Rapids formations of the Mannville Group. Ground water modelling completed for cumulative<br />
effects of the Husky Tucker operation, regarding the hydraulic head change for the McMurray<br />
aquifer after 25 yrs simultaneous pumping and injection was predicted to be less than 1m.<br />
Brackish water in the region is currently being sourced by Imperial Oil (Cold Lake), Husky Oil<br />
(Tucker), Shell Canada (Orion), and Canadian Natural Resources Ltd. (Wolf Lake).<br />
8.5.3.2 Brackish Water Suitability<br />
Brackish water used in SAGD operations for steam generation depends on the following<br />
parameters: Total Dissolved Solids (TDS), dissolved silica (Si), alkalinity and hardness.<br />
Suitable industry standards are TDS = 10,000 mg/l, Si = 50 mg/l, alkanity = 450 mg/l and<br />
hardness = 0.5 mg/l. The McMurray aquifer requires treatment to meet the above levels.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 194
8.5.4 Fresh Water Resources<br />
The amount of freshwater estimated to be present in the Quaternary and Tertiary aquifers in the<br />
CLBRB is 50 billion m 3 (Alta Env. 2006). An estimated 266 million m 3 of water recharges<br />
groundwater resources annually and results in fresh groundwater aquifers. The same amount of<br />
groundwater discharges into lakes and rivers in the same time period.<br />
8.5.4.1 Surface and Shallow Aquifer Use<br />
Table 8.5.4-1 provides a summary of Surface water allocation and existing licenses, excluding<br />
statutory domestic and non-registered agricultural users. Table 8.5.4-2 presents the<br />
groundwater allocations by user type and by number of wells, respectively Imperial Oil holds a<br />
license allocation to use water from Crane Lake; the license is limited by lake level parameters.<br />
Birchwood Resources will not be using water sourced from Crane Lake.<br />
Surface water is allocated to a number of users for various other uses such as conservation of<br />
wetlands, recreational facilities and tree farms. Within a five km radius of the proposed<br />
development area, Ducks Unlimited, Public Land Management, Canadian Forces Base (Cold<br />
Lake), Cold Lake Skiing Society, Bonnyville Golf Course and Bonnyville Forest Nursery have<br />
received licensed surface water allocations. The allocation, location, water source and license<br />
information can be found in Table 4.17 of Consultant's Report 1.<br />
There are numerous groundwater licenses issued for, and a variety of users of, groundwater in<br />
the CLBRB. Industrial, Agricultural, Municipal and Domestic users have allocations for<br />
groundwater in the shallow aquifers. The amount of water allocated under a license is not<br />
necessarily used; the actual water usage is significantly lower than licensed. Table 8.5.4-2<br />
provides perspective on the over allocation, including groundwater allocation for domestic and<br />
livestock use, in 2003.<br />
Table 8.5.4-1 Groundwater Allocation in the Cold Lake Beaver River Basin<br />
Type<br />
1985<br />
(1000's m3)<br />
%<br />
1992<br />
(1000's m3)<br />
%<br />
2003<br />
(1000's m3)<br />
%<br />
Industrial 10,534 98 9,259 95 14,950 94<br />
Agricultural/Irrigation 218 2 210 2 382 2<br />
Ag. Registrations 0 0 0 0 454 3<br />
Municipal 50 0 270 3 190 1<br />
Total 10,802 100 9,739 100 15,976 100<br />
Table 8.5.4-2 Groundwater Allocation in the Cold Lake Beaver River Basin<br />
Including Livestock/domestic and Domestic Usage 2003<br />
Type Number of Wells<br />
2003<br />
(1000's m3)<br />
%<br />
Industrial 20 (AGS 2005) 14950 53<br />
Agricultural/Irrigation 1460 (ESRD 2005) 9125 33<br />
Ag. Registrations 2971( SRD 2005) 3730 13<br />
Municipal 4 (AGS 2005) 190 1<br />
Total 27,995 100<br />
Specific current and historical allocations, location and Aquifer sourced can be found in Table<br />
4.3 of Consultant Report 1. A total of 185 groundwater wells were identified within a five km<br />
radius of the proposed project development.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 195
The actual amount of fresh groundwater used in the CLBR is unknown as domestic and<br />
agricultural users do not generally measure consumption and the exact number of active wells<br />
is unknown. Industrial users are required to submit annual water usage to Alberta ESRD as<br />
outlined in their license terms. The relationship between ground water allocation and actual<br />
usage for industrial users is presented in Consultants Report 1. Table 4.5 and indicates that<br />
industry was using 28.9% of license allocation. Municipal fresh groundwater usage has<br />
significantly decreased as municipal licensees have connected the local regional surface water<br />
supply system.<br />
8.5.5 Water Balance<br />
See Figure 7.2.2-B Water Balance - De-Oiling, Water treatment and Steam Generation<br />
8.5.6 Birchwood Water Usage<br />
Birchwood is applying for licenses to source freshwater from the Muriel Formation and brackish<br />
water from the McMurray Formation. Maximum fresh water during startup will be 4035 m 3 /day<br />
for 5-10 days, with steady state operations averaging 5m 3 /day, or 42,135 m 3 during the first year<br />
of operations and 1,825 m 3 /year thereafter Table 7.2.2.1. The Groundwater Assessment<br />
concluded that total estimated freshwater usage was 8,000,000 (±1,000,000) m 3 /year.<br />
Birchwood's proposed development is equivalent to 0.0053% of that total during the first year of<br />
operations and 0.00023% thereafter.<br />
The use of the Muriel formation as a source should not affect other users as the general<br />
direction of flow from this aquifer is south and east and the majority of domestic use water wells<br />
in the area are to the north and west of the proposed development location.<br />
Although groundwater allocations and uses increase steadily with time, the total estimated<br />
groundwater use in the basin is approximately 8 + 1 million m 3 /yr and equals only 30% of the<br />
groundwater allocated in the basin, 4% of the estimated annual groundwater recharge in the<br />
basin and 1% of the average annual flow in the Beaver River. The use of groundwater in the<br />
CLBR Basin is a small percentage of natural flows and is a minor part of water availability.<br />
Thus, groundwater use at these levels is considered sustainable.<br />
8.5.7 Water Disposal<br />
The two options for water disposal, as indicated by the Assessment, are the McMurray<br />
formation and the Cambrian (Granite Wash) formation. Both are indicated as acceptable<br />
aquifers. Due to the high usage of the McMurray formation as the disposal aquifer, the<br />
Cambrian aquifer is the preferred disposal formation. All water sourced from and disposed into<br />
this formation will be measured and reported as per the MARP program.<br />
8.6 Soil and Terrain<br />
The terrestrial footprint of the proposed development area is approximately 18.6 ha of which<br />
10.0 ha is cleared and 1.3 ha is currently disturbed. The elevation trend is generally from the NE<br />
to the SW. Figure 2.3.11 shows the topography of the proposed development and surrounding<br />
area.<br />
Birchwood has conducted a Soil Survey in the July of 2012. The methodology used included:<br />
1. Classification of soils in accordance with criteria established by the Soil Classification<br />
Working Group (1998).<br />
2. Investigation of soils on foot with a shovel and hand auger to a depth of approximately 1<br />
m at all inspection points.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 196
3. Extrapolation of soil inspections using the principles of geomorphology and surficial<br />
geology in concert with the vegetation patterns to delineate individual soil map units.<br />
Soil map units provided for the area 60 m adjacent to the proposed PDA area are based<br />
on aerial photograph interpretation and extrapolation of inspection site data.<br />
4. Analysis the soils to confirm soil classification and determine Land Capability<br />
Classification (LCC) ratings and Reclamation Suitability Ratings (RSR). (see Consultants<br />
Report 5 for specific parameters),<br />
5. Classify the soils in accordance with the Land Capability Rating System.<br />
8.6.1 Surficial Geology and Landforms<br />
Andriashek and Fenton (1989) described the area as a having discontinuous eolian material<br />
overlying sandy glaciofluvial deposits; and discontinuous sandy glaciofluvial deposits overlying<br />
undivided moraine. The morphology is rolling with alternative concave and convex elements<br />
with a length to width ratio of more than two; elements parallel to non-oriented with low to<br />
moderate local relief (
A complete description of the each soil type can be found in Consultants Report 5 and includes:<br />
Dominant Soil Series<br />
Classification of Dominant Soil Series<br />
Inclusions (
RSRs are not calculated for organic horizons because they would always be rated unsuitable<br />
due to saturation percentage and texture. RSRs are also not calculated for C and Lower Subsoil<br />
(LS) horizons because these horizons will not be salvaged. Therefore, any organic or C/LS<br />
horizons are assigned an RSR of “not applicable”.<br />
Table 8.6.4-1 Reclamation Suitability Ratings for the Well and Facility Pad<br />
Soil<br />
Series<br />
Site ID<br />
Soil<br />
Map<br />
Unit<br />
Reclamation Suitability<br />
Topsoil Subsoil<br />
Organic<br />
B<br />
A Horizon<br />
C Horizon (if no B exits)<br />
(LFH/O)<br />
Horizon<br />
ABC LNBW-44 M1<br />
-<br />
Poor to<br />
Good<br />
Fair to<br />
Good<br />
-<br />
LIZ LNBW-47 M2 - Poor Poor -<br />
DRNaa LNBW-47 M2 - Poor Poor -<br />
DRNaa LNBW-47 M3<br />
NWBaa LNBW-33 S1 - Poor Fair -<br />
SLN LNBW-46 O1<br />
Not<br />
Applicable<br />
- - Not Applicable<br />
The Conservation and Reclamation (see Consultants Report 7) plan addresses the required soil<br />
salvage, storage and required management during storage during the project operation. Soils<br />
rated in the M1 soil profile should respond well to reclamation at closure as Birchwood will<br />
provide the proper reclamation techniques at closure. Soils with poor RSR's will require<br />
segregation and management to ensure viability at the project closure.<br />
8.7 Vegetation<br />
Birchwood conducted a Vegetation and Wildlife Assessment in August, 2012 in order to obtain a<br />
baseline description of vegetation resources in the proposed development area and across the<br />
Mineral Surface Lease held by the company. The assessment was conducted over the<br />
Birchwood Mineral Surface Lease Area (study area) which surrounds the PDA.<br />
8.7.1 Methodology<br />
The methodology used was consistent with the recommended practices specified in the<br />
Guidelines for Submission of a PDA/C&R Plan as published by Alberta Environment, 2009. The<br />
study consisted of Vegetation Cover Type Inventory and Mapping as well as Rare Plant and<br />
Rare Plant Community Assessment.<br />
The methodology used for the vegetation assessment component was, briefly, as follows:<br />
1. Delineation of different land cover types using the Ecological Land Classification<br />
method.<br />
2. Conducting a field vegetation survey during which dominant eco-site phases were<br />
classified within initial map signatures and new vegetation cover polygons identified<br />
and mapped.<br />
3. Mapping vegetation plots within several representative eco-site polygons with<br />
canopy cover measurements conducted at each site.<br />
4. Recording data pertinent to plant species, dead cover, woody debris, snags, canopy<br />
cover and composition.<br />
5. Assigning a new code and describing habitats that did not fit into eco-site phase<br />
classes,<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 199
6. Reporting of Findings.<br />
The methodology used for the Rare Plant and Rare Plant Community Assessment was based<br />
on the proposed "Guideline for Rare Plant Surveys" (Alberta Native Plant Council, ANPC 2012)<br />
and conducted as follows:<br />
1. Literature Review to determine what, if any, rare plants and rare plant communities<br />
could occur within the Birchwood study area and determination of habitat affiliations,<br />
2. Compilation of a list of potential rare plants and rare plant communities using the<br />
Alberta Conservation Information Management System (2012) and Committee on<br />
the Status of Endangered Species in Canada (COSEWIC (2012), and review of the<br />
ACIMS occurrence data,<br />
3. Examination of taxonomic descriptions, illustrations/photographs and herbarium<br />
specimens occurred to ensure that field observations would allow for identification of<br />
each species,<br />
4. Review of aerial photography to determine likely sites of rare plants/rare plant<br />
communities for field orientation,<br />
5. Field inspection of the study area including a meandering and "hands and knees"<br />
ground search, and<br />
6. Reporting of findings.<br />
8.7.2 Ecosite Phases at the Proposed <strong>Project</strong> Development Area<br />
The field investigation and mapping shows that there are 22 eco-site phases within the study<br />
area and 13 that are directly affected by the proposed development. The main ecosystem<br />
within the development area is identified as Pasture – Graminoid, occupying 8.5 ha of the total<br />
18.6 ha proposed for development. Table 8.7-1 provides a breakdown of the ecosite phase<br />
type, brief description using common names, the total area (ha) occupied by the eco-site in the<br />
within the proposed project development area. A complete description of all eco-site phases<br />
found within the study area can be found in Consultants report 4.<br />
Figure 8.7.2-1 illustrates the Birchwood study area. Figure 8.7.2-2 illustrates the distribution of<br />
eco-sites phase distribution across the site with specific reference made to the project<br />
development area. Figure 8.7.2-3 illustrates the vegetation plots of the Birchwood Study area.<br />
Figure 8.7.2-4 illustrates the Rare Vascular Plant Survey path for the Birchwood study area.<br />
A total of 22 eco-phase sites were identified during the assessment; seventeen are natural,<br />
three are man-made and three are wetlands/riparian areas. Within the proposed project<br />
development area the three man-made eco phase sites are present, specifically, anthropogenic<br />
habitat and two types of pasture habitat. There are six naturally occurring habitats as follows:<br />
1. Trembling Aspen- White Spruce/Low Bush Cranberry Forest<br />
2. Trembling Aspen/Low Bush Cranberry Forest<br />
3. Subhygric Black Spruce – Jackpine /Labrador Tree Forest<br />
4. White Spruce/Dogwood Forest<br />
5. White Spruce/Jackpine Forest, and<br />
6. Jackpine Lichen Forest<br />
There are no wetlands or riparian areas within the proposed project footprint.<br />
The assessment identified 158 plant species including 144 native species, 10 exotic species<br />
and four species of unknown/undetermined origin. A complete list of species can be found in<br />
Consultants Report 4 in Table 6.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 200
The dominant eco-phase site in the project development area is Pastureland – Graminoid,<br />
which forms 8.6 ha of the proposed development site. An additional 2.2 ha of land within the<br />
proposed development area is already disturbed (AN). The largest areas of disturbance to the<br />
natural habitat will occur in Trembling Aspen-White Spruce/Low Cranberry Forest (d2) and<br />
Trembling Aspen/Low Cranberry Forest (d1), 2.51 and 1.69 ha respectively, both of which are<br />
abundant in the region. Additional habitat loss will equal 8.4 ha, however, the habit loss will not<br />
result in splitting of large batches of undisturbed land into smaller patches and thereby habitat<br />
loss due to fragmentation is expected to be minimal. All habitats that occur within the proposed<br />
development area occur outside of the area so seed harvesting at reclamation will be possible.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 201
Table 8.7-1 Ecosite Phase Types, Descriptions and Area Coverage with the Proposed Development Area<br />
Eco Phase Description ha<br />
Pasture – Graminoid Open grassland used for agricultural grazing. Common species include common yarrow, red 8.6<br />
pl-g<br />
clover, common dandelion, smooth aster, common pepper grass, wild strawberry, cicer milk<br />
vetch, hemp nettle, northern bedstraw and rough cinquefoil. Grasses commonly in this eco<br />
phase include western wheat grass, short awned foxtail, slender wheat grass, Kentucky<br />
bluegrass and smooth brome. Most of the species were non-native at the time of the survey.<br />
Anthropogenic<br />
An<br />
Human origin structures and land covers (eg. Houses, infrastructure, oil and gas facilities) 1.3<br />
Trembling Aspen- This eco site consisted of White Spruce 60% and Trembling Aspen 40%. Canopy closure<br />
2.51<br />
White Spruce/Low averaged 70%. Mean age stand = 64 yrs and average tree height = 21 m. The most common<br />
Bush Cranberry shrub species included green alder, Saskatoon, white spruce, trembling aspen and prickly<br />
Forest<br />
wild rose. Tall shrubs averaged 1.4 m in height with 25% cover. Herbaceous species<br />
d2<br />
averaged 60% cover and were composed of bunchberry, twinflower, wild strawberry,<br />
palmate-leaved coltsfoot and wild sasaparilla. Coarse woody debris was common, averaging<br />
14.7 cm in diameter and in variable stages of decay. All snags were trembling aspen.<br />
Trembling Aspen- Habitat was dominated by trembling aspen trees with a canopy closure averaging 60%. The 1.69<br />
/Low Bush Cranberry mean age of the stand was 47 years and average tree height was 19 m. Most commonly<br />
Forest<br />
observed tall shrub species included choke cherry, pin cherry, Saskatoon and Willow species,<br />
d1<br />
which averaged 2.1 m in height and 33% cover. Low shrubs averaged 65 cm and 25% cover<br />
and included raspberry, low bush cranberry, beaked hazelnut, common snowberry, and pin<br />
cherry, however Prickly Wild Rose and common wild rose dominated the low shrub canopy.<br />
Common herbaceous species included dewberry, bunchberry, showy aster, wild strawberry,<br />
wild sarsaparilla, northern bedstraw, twinflower, wild vetch, and wild lily-of-the-valley. Coarse<br />
woody debris was uncommon. Snags were common and consisted exclusively of trembling<br />
aspen<br />
Subhygric Black Habitat was dominated by dense canopy of Black Spruce. Shrub occurrence was sparse and 1.46<br />
Spruce – Jackpine consisted of Labrador tea, black spruce and Prickly Wild Rose when present. Herbaceous<br />
/Labrador Tree Forest plants were rare and only bunchberry occurred consistently. Feather moss covered the<br />
g1<br />
majority of the forest floor.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 202
Table 8.7-1 (continued) Ecosite Phase Types, Descriptions and Area Coverage with the Proposed Development Area<br />
Pasture – Shrubby<br />
Pl-s<br />
White<br />
Spruce/Dogwood<br />
Forest<br />
e3<br />
White Spruce-<br />
Jackpine/Blueberry<br />
Forest<br />
b4<br />
Jackpine Lichen<br />
Forest<br />
a1<br />
Open grassland with a varying amount of shrub regeneration which have in the past been<br />
used for agricultural grazing. Common shrub regeneration included beaked willow, autumn<br />
willow, trembling aspen, and balsam poplar with some Saskatoon, snowberry and prickly wild<br />
rose. Herbaceous species included fowl bluegrass, Kentucky bluegrass, tufted hair grass,<br />
short awned foxtail, graceful sedge, wild strawberry, hemp nettle, common plantain, narrow-<br />
leaved hawkwood, northern bedstraw, starflowered Solomen's seal and common horsetail.<br />
White spruce dominated canopy with small amounts of basalm poplar. Canopy cover<br />
averaged 58% and the stand age was approximately 72 years. Tall shrub cover included<br />
willow species, currant species raspberry, prickly wild rose and Saskatoon. Herbaceous<br />
plants consisted of wild sasparilla, bishop's cap, twinflower, bunchberry and dewberry.<br />
Feather moss was common. Coarse woody debris was common and averaged 14.8 cm in<br />
diameter. In areas where balsam poplar occurred snags were more common and averaged<br />
6.4 m in height and 11.8 cm in diameter, with a variable decay rating of (3-5).<br />
White Spruce dominated canopy (90%) with (10%) Jackpine. Canopy closure was 45%,<br />
stand age equalled 65 years and heights average 17.6 m. Tall shrubs averaged 1.7 m I<br />
height with 2% cover and consisted of Saskatoon and White Spruce. Low shrubs averaged<br />
13 cm in height and 65% cover. Common species were blueberry, bearberry, bog cranberry,<br />
Saskatoon and prickly wild rose. Herbaceous species present were wild lily-of-the-valley,<br />
cow-wheat, rough-leaved rice grass, twinflower and narrow leaved hackweed. Coarse woody<br />
debris and snags were absent.<br />
The tree canopy consisted of 80% Jackpine, 15% White Spruce and 5% Trembling Aspen<br />
with 15% canopy closure and a stand age of 57yrs. Tall shrubs covered 5% of the area and<br />
consisted of only Trembling Aspen. Low shrub cover was 65% and consisted of bog<br />
cranberry, common bearberry, common blueberry, prickly wild rose and Saskatoon. Common<br />
herbaceous species were lilly-of-the-valley, cow wheat, hairy wild rye, northern rice grass,<br />
and mountain goldenrod. Ground lichens were abundant in this habitat type. Coarse woody<br />
debris was absent and only one trembling aspen snag was recorded.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 203<br />
1.04<br />
0.92<br />
0.52<br />
0.21
8.7.3 Rare Plant and Plant Communities<br />
The study area was searched for rare vascular plants and rare plant communities. No plant<br />
species were located and one rare plant community, a Saskatoon/common bearberry/northern<br />
rice grass was found to the outside of the proposed development area, to the north near the<br />
lake, and measured approximately 30 m x 15 m.<br />
8.7.4 Old Growth Forests<br />
There are no old growth forests within the Birchwood Study area.<br />
8.7.5 Summary of Potential Impacts and Mitigation Measures<br />
The Assessment reviewed the potential impacts on the vegetation within the study area. The<br />
impacts and mitigation measures are outlined below.<br />
8.7.5.1 Direct Vegetation Removal<br />
Vegetation will be cleared for the proposed development. Of the nineteen identified vegetation<br />
types within the study area, only six types will be affected by clearing. Birchwood has sited the<br />
well pad and facility together and will utilize existing infrastructure in the area to avoid additional<br />
clearing for pipeline right of ways. Measures will be put in place to minimize erosion and provide<br />
runoff control during construction, to avoid disruption of vegetation and soils that are adjacent to<br />
the proposed development area.<br />
8.7.5.2 Impacts to Uncommon Vegetation<br />
The White Spruce/Dogwood Forest, White Spruce-Jackpine/Blueberry Forest and Subhygric<br />
Black Spruce – Jackpine /Labrador Tree Forest are relatively uncommon in the study area.<br />
Birchwood will be clearing a total of 2.9 ha of these types of vegetation. Birchwood has<br />
minimized the clearing of these types of natural vegetation to the extent possible.<br />
8.7.5.3 Soil Acidification<br />
Certain soils and associated vegetation are susceptible to soil acidification which is deposited<br />
by emissions of SO2 and NO2. The "Land Systems and Soils Sensitivity to Acid Input in the<br />
LICA Area" (AMEC, March 2007) indicates that the proposed development is within an area<br />
where soils are sensitive to acidic inputs however the soils directly to the south have low<br />
sensitivity. Birchwood will monitor soils surrounding the plant footprint to measure changes in<br />
soils chemistry (pH) related to acid deposition.<br />
8.7.5.4 Introduced Plant Species Invasion<br />
There were no invasive species listed as prohibitive noxious weeds or noxious weeds under the<br />
Alberta Weed Control Act. One exotic species, bladder campion, was found within the proposed<br />
development area and could be considered a potential threat.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 204
8.8 Wildlife Assessment<br />
Birchwood conducted a Vegetation and Wildlife Assessment in August, 2012 in order to obtain a<br />
baseline description of vegetation resources in the proposed development area and across the<br />
Mineral Surface Lease held by the company. The assessment was conducted over the<br />
Birchwood Mineral Surface Lease Area (study area) which surrounds the proposed<br />
development area.<br />
8.8.1 Methodology<br />
The wildlife assessment has two components, species potential occurrence and identification<br />
and identification of wildlife species of management concern. The methodologies for each<br />
component are summarized below:<br />
8.8.1.1 Wildlife Species Occurrence and Status<br />
1. Development of a list of vertebrate wildlife species known or expected to occur within the<br />
Birchwood study area using regional and provincial species distribution sources.<br />
2. Utilization of professional judgement to classify the status and abundance of each<br />
species,<br />
3. Refined list to identify provincially and federally listed species at risk (SAR) using current<br />
status assessments made by Alberta ESRD, COSEWIC and SARA as well as the Fish<br />
and Wildlife Information Management System.<br />
8.8.1.2 Wildlife Species of Management Concern<br />
1. Professional judgment was used to select specifies of management concern based the<br />
following:<br />
on public or scientific concern,<br />
potential to reside in the habitat of the study area, (referenced field data obtained<br />
from vegetation assessment to determine if suitable habitat for species exists)<br />
relevance to key issues<br />
potential to represent the habitat of other species, and<br />
ease of monitoring.<br />
2. Prepare rationale for selection for each species identified, and<br />
3. Provide detailed reports regarding the species status and habitat.<br />
8.8.2 Wildlife Species Occurrence and Status<br />
The Birchwood study area holds potential for a total 303 vertebrate wildlife species, 246 of<br />
which are birds, 49 are mammals, six are amphibians and two are reptiles. The status<br />
abundance and at risk designations are contained in Table 7 of Consultant's Report 4 provides<br />
a list of species, listed under their common names, that have potential to live in the Birchwood<br />
Study area and are listed as "Sensitive", "At Risk" or "May be at Risk" provincially and<br />
"Endangered", "Threatened", or of "Special Concern" federally.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 205
8.8.3 Species of Management Concern<br />
The Vegetation and Wildlife Assessment also reviewed species of management concern. The<br />
following species were identified based on the criteria specified above:<br />
Moose<br />
Black Bear<br />
Fisher<br />
Northern Long Eared Bat<br />
Yellow Rail<br />
Great Grey Owl<br />
Canadian Toad, and<br />
Mixed Forest Birds.<br />
Detailed descriptions of these species relative to the specific habitat observed at the proposed<br />
development site and the larger project area are contained with the Vegetation and Wildlife<br />
Report. The Woodland Caribou was not selected as a species of management concern as the<br />
habitat in the study area would not support this species.<br />
The Great Blue Heron has been observed on the island situated in Crane Lake. The proposed<br />
development area is outside the buffer zone stipulated in the Cold Lake Sub Regional<br />
Integrated Resource Plan.<br />
8.8.4 Summary of Potential Wildlife Impacts and Mitigation Measures<br />
Although the amount of additional disturbance required for the proposed project is small, wildlife<br />
habitat will be removed and wildlife existing outside the project area may be affected. Birchwood<br />
will utilize the following mitigation procedures to ensure that the affect is minimized.<br />
8.8.4.1 Habitat Loss/Alteration<br />
Minimal additional clearing is required for the proposed development. The proposed<br />
development area is outside of any designated Key Wildlife and Biodiversity Zones.<br />
8.8.4.2 Habitat Fragmentation<br />
Habitat fragmentation occurs when large continuous tracts of land are completely or partially<br />
removed resulting in smaller, dispersed or isolated patches of habitat. The proposed project<br />
footprint has been sited on an existing disturbed portion of land to minimize fragmentation and<br />
subsequent effects of wildlife sustainability in the area.<br />
8.8.4.3 Movement Obstruction<br />
Wildlife daily and seasonal movement, as well as and range, varies in accordance with<br />
requirements to obtain sustenance, escape predators, respond to natural and artificial habitat<br />
alterations (eg., fire, clearing) and species propagation and associated genetic exchange. Intact<br />
movement corridors can enhance, as well as be critical too, ensuring that the likelihood of<br />
species survival. Due to the existing state of habitat occurrence on predominantly cleared land,<br />
the proposed project area does not interfere with any known wildlife movement corridors and<br />
effects on regional movement are predicted to be minimal.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 206
8.8.4.4 Sensory Disturbance<br />
Wildlife species are affected by human activity that causes sensory disturbance (such as noise,<br />
light, smell, etc); the affects can be positive, negative or neutral. The degree to which wildlife is<br />
affected depends upon numerous factors including habitat quality or the site occupied, distance<br />
to an quality of other appropriate and available sites, relative risk of predation at other sites,<br />
relative competitor density at other sites, and amount of investment the wildlife has mad to<br />
procure the site. In order to minimize sensory disturbance, Birchwood will implement the<br />
following measures:<br />
Conduct species specific and species at risk assessments to determine if species are<br />
present and any related management and monitoring should be conducted during plant<br />
construction activities,<br />
Conduct a pre-disturbance assessment modify construction activity so as to reduce<br />
sensory disturbance on species in the adjacent areas during plant construction activities,<br />
Develop and implement management plans for species that may be attracted to the<br />
anthropogenic activities at the site (eg. Bears, small mammals and birds),<br />
Conduct construction activity in the winter months to avoid disruption of nesting activity<br />
of birds adjacent to the facility,<br />
Use on demand lighting and downward directional shading will be used to minimize light<br />
on nocturnal species,<br />
Install a vapour recovery system will be used to capture emissions and minimize odors<br />
associated with the proposed operations,<br />
Mitigate noise levels using vibration absorption mountings and encasement within<br />
buildings, and<br />
Minimize Air emissions in order to meet the ambient air quality requirements set by<br />
Alberta ESRD, conduct on-going air emission monitoring and use low NOx emission<br />
equipment, and conduct sir and soil monitoring to determine if soils are affected by acid<br />
deposition and initiate a soil management program to reverse effects if required.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 207
8.8.4.5 Direct Mortality<br />
Direct mortality is caused by human activity that immediately results in the death of an animal,<br />
hunting, trapping and vehicle collisions can cause instant death. It may also be caused by<br />
industrial and recreational activities that release chemicals into the environment through air or<br />
water emissions that result in inhalation or contaminated air or water, or consumption of<br />
impacted vegetation, fish other wildlife or invertebrates. Birchwood will mitigate direct mortality<br />
using the following measures:<br />
Avoidance of clearing vegetation during migratory bird nesting/fledging season,<br />
Fencing of the proposed development site to prevent migration onto the site and<br />
inadvertent contact with equipment or machinery, and prevent the use of the site as a<br />
base for hunters/workers,<br />
Construct the proposed facility with an impermeable base and berms to prevent spills<br />
from migrating off the surface and lease development area,<br />
Construct an Industrial surface runoff collection pond on site to capture surface water<br />
conduct testing of the surface water and control release. Water that does not meet<br />
Alberta ESRD standards will be diverted to process use,<br />
Implement a management plan for the Industrial run-off pond such that birds to not<br />
attempt to use,<br />
Enforce speed limits of 40 km an hour on access roads and 10 km per hour on lease,<br />
Removal of garbage from construction/facility site promptly to avoid attracting bears and<br />
small mammals to the site and potential habituation,<br />
Employ bear proof disposal bins, and<br />
Prohibit workers from feeding wildlife to prevent habituation; this will include proving<br />
housekeeping facilities and practices that prohibit feeding of birds.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 208
8.9 Summary of Environmental Receptors and impact ratings<br />
Birchwood has conducted assessments related to Historical Impacts, Hydrology and Hydrogeology, Air, Noise, Vegetation, Wildlife<br />
and prepared this table to summarize the receptors identified, the geographic extent, the magnitude, duration and frequency of the<br />
impact, the likelihood of permanence, and the level of confidence.<br />
TABLE 8.9-1 Environmental Receptors and Impact Ratings<br />
RECEPTOR Direction<br />
of Impact<br />
Geographic<br />
Extent<br />
Magnitude<br />
of Impact<br />
Duration<br />
of Impact<br />
Frequency<br />
of Impact<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 209<br />
Reversibility<br />
of Impact<br />
Confidence<br />
Level<br />
Final<br />
Impact<br />
Rating<br />
Historical Resources<br />
None identified Neutral - - - - - - Low<br />
Traditional Land<br />
Use<br />
Traditional Plant<br />
Harvesting activities<br />
in traditional lands<br />
Hunting Activities for<br />
traditionally hunted<br />
species in the area<br />
Fishing in traditional<br />
lands<br />
Trapping on trap lines<br />
in traditional lands<br />
Negative Local Low Long<br />
Term<br />
Negative Local Low Long<br />
Term<br />
Seasonal Reversible Good Low<br />
Continuous Reversible Good Low<br />
Neutral - - - - - - -<br />
Neutral to<br />
Negative<br />
Air Quality<br />
SO2 Negative Regional Low Long<br />
NO2 Negative Regional Low<br />
Term<br />
Long<br />
Term<br />
CO Negative Regional Low Long<br />
Term<br />
PM2 Negative Regional Low Long<br />
Term<br />
- - - - - - -<br />
Continuous Reversible Good Low<br />
Continuous Reversible Good Low<br />
Continuous Reversible Good Low<br />
Continuous Reversible Good Low
RECEPTOR Direction<br />
of Impact<br />
Noise<br />
Noise Receptor<br />
(Residence 1)<br />
Noise Receptor<br />
(Residence 2)<br />
1.5 Km from facility<br />
boundary<br />
Geographic<br />
Extent<br />
Magnitude<br />
of Impact<br />
Duration<br />
of Impact<br />
Frequency<br />
of Impact<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 210<br />
Reversibility<br />
of Impact<br />
Confidence<br />
Level<br />
Final<br />
Impact<br />
Rating<br />
Negative Local Low Long<br />
Term<br />
Continuous Reversible Good Low<br />
Negative Local Low Long<br />
Term<br />
Continuous Reversible Good Low<br />
Neutral Local Negligible Long term Continuous Reversible Good Low<br />
Soils Terrain and Surficial Geology<br />
Disturbance Negative Local Low Mid-term Infrequent Reversible Good Low<br />
Admixing Negative Local Low Long-term Infrequent Irreversible Good Low<br />
Compaction Negative Local Low Long-term Infrequent Reversible Good Low<br />
Moisture Negative Local Low Long-term Infrequent Reversible Good Low<br />
Soil Erosion Negative Local Low Long-term Infrequent Reversible Good Low<br />
Contamination Negative Local Low Long-term Infrequent Reversible Good Low<br />
Forest Capability Negative Local Low Long-term Infrequent Reversible Good Low<br />
Reclamation Negative Local Low Long-term Infrequent Reversible Good Moderate<br />
Suitability<br />
Soil Acidification Negative Local Low Long-term Infrequent Reversible Moderate Low<br />
Unique Soils, Terrain Negative Local Low Long-term Infrequent Reversible Good Low<br />
Geology and Hydrogeology<br />
Surface Facilities Neutral - - - - - - -<br />
Water disposal Neutral - - - - - - -<br />
SAGD Operations Neutral to Local Low Long term Continuous Reversible Good Low<br />
Groundwater<br />
withdrawal and<br />
changes in run-off<br />
Negative<br />
Neutral to<br />
negative<br />
Local Low Long-term Continuous Reversible Good Low
RECEPTOR Direction<br />
of Impact<br />
Geographic<br />
Extent<br />
Magnitude<br />
of Impact<br />
Duration<br />
of Impact<br />
Frequency<br />
of Impact<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 211<br />
Reversibility<br />
of Impact<br />
Confidence<br />
Level<br />
Surface Water Quality<br />
Construction Activities Neutral - - - - - - -<br />
Runoff N/A - - - - - - -<br />
Final<br />
Impact<br />
Rating<br />
Borrow Pits N/A<br />
Subsurface Neutral to Local Low Long term Continuous Reversible Good Low<br />
Operations negative<br />
Wastewater Release Neutral - - - - - -<br />
Groundwater Neutral to Local Low Long term Continuous Reversible Good Low<br />
Withdrawal and<br />
changes in run-off<br />
Negative<br />
Acid Deposition Negative Local Moderate Long<br />
Term<br />
Continuous Reversible Good Low<br />
Fish and Aquatic Resources<br />
None identified<br />
Vegetation, Wetlands and Biodiversity<br />
Habitat Diversity Neutral to Local Low Mid to Continuous Reversible Good Low<br />
Negative<br />
Long and<br />
Term Seasonal<br />
Species Diversity Neutral to Local Low Mid to Continuous Reversible Moderate Low<br />
Negative<br />
Long and<br />
Term Seasonal<br />
Landscape Diversity Neutral to Local Low Mid to Continuous Reversible Good Low<br />
Negative<br />
Long and<br />
Term Seasonal<br />
Traditional Use Plants Neutral to Local Low Mid to Continuous Reversible Good Low<br />
Negative<br />
Long and<br />
Term Seasonal
RECEPTOR Direction<br />
of Impact<br />
Geographic<br />
Extent<br />
Magnitude<br />
of Impact<br />
Duration of<br />
Impact<br />
Wildlife (Species of Management Concern)<br />
Moose Negative Local Low Mid to Long<br />
Term<br />
Black Bear Negative Local Low Mid to Long<br />
Term<br />
Frequency<br />
of Impact<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 212<br />
Reversibility<br />
of Impact<br />
Confidence<br />
Level<br />
Final<br />
Impact<br />
Rating<br />
Continuous Reversible Good Low<br />
Continuous Reversible Good Low<br />
Fisher Neutral - - - - - - -<br />
Northern Eared Neutral to Local Low Mid to Long Continuous Reversible Moderate Low<br />
Bat Negative<br />
Term<br />
Yellow Rail Neutral - - - - - - -<br />
Great Grey Owl Neutral to Local Low Mid to Long Continuous Reversible Moderate Low<br />
Negative<br />
Term<br />
Canadian Toad Neutral to Local Low Mid to Long Continuous Reversible Moderate Low<br />
Negative<br />
Term<br />
Mixedwood Forest Neutral to Local Low Mid to Long Seasonal Reversible Moderate Low<br />
Birds Negative<br />
Term and<br />
Continuous<br />
Other Wildlife Species of Concern<br />
Ungulates Negative Local Low Mid to Long<br />
Term<br />
Continuous Reversible Good Low<br />
Terrestial Fur Negative Local Low Mid to Long Continuous Reversible Good Low<br />
bearers<br />
Term<br />
Semi aquatic<br />
mammals<br />
Neutral - - - - - - -<br />
Small mammals Negative Local Low Mid to Long<br />
Term<br />
Continuous Reversible Moderate Low<br />
Raptors Negative Local Low Mid to Long<br />
Term<br />
Continuous Reversible Good Low<br />
Waterfowl and<br />
Waterbirds<br />
Neutral - - - - - - -
RECEPTOR Direction<br />
of Impact<br />
Geographic<br />
Extent<br />
Magnitude<br />
of Impact<br />
Duration of<br />
Impact<br />
Frequency<br />
of Impact<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 213<br />
Reversibility<br />
of Impact<br />
Confidence<br />
Level<br />
Other Wildlife Species of Concern (continued)<br />
Amphibians Neutral - - - - - - -<br />
Land and Resource Use<br />
Protected Areas Neutral - - - - - - -<br />
Land Use<br />
Dispositions<br />
Neutral - - - - - - -<br />
Increase in Negative Local Low Mid to Long Continuous Reversible Good Low<br />
disturbance<br />
Term<br />
Access Neutral - - - - - - -<br />
Forestry Neutral - - - - - - -<br />
Trapping Neutral to Local Low Mid to Long Continuous Reversible Good Low<br />
Negative<br />
Term<br />
Hunting Neutral to Local Low Mid to Long Continuous Reversible Good Low<br />
Negative<br />
Term<br />
Fishing N/A - - - - - - -<br />
Non- Consumptive<br />
Recreation<br />
Neutral - - - - - - -<br />
Aggregates and<br />
Minerals<br />
N/A - - - - - - -<br />
Visual/esthetics Neutral to Local Low Mid to Long Continuous Reversible Good Low<br />
Human Health<br />
Negative<br />
Term<br />
Air Contaminants Negative Regional Low Long Term Continuous Partially<br />
Reversible<br />
Final<br />
Impact<br />
Rating<br />
Moderate Low
8.10 Summary of Environmental Commitments<br />
Birchwood is committed to ensuring that the environmental impacts of the proposed<br />
development are eliminated or minimized and monitored. To that end, the company will<br />
undertake the following to achieve compliance with regulatory requirements, industry standards<br />
and on-going continuous improvement:<br />
8.10.1 Air Monitoring<br />
Install passive exposure stations for measurement of hydrogen sulphide (H2S) and sulphur<br />
dioxide concentrations. The steam generator exhaust stacks will be equipped with sampling<br />
facilities and will be installed, operated and maintained in accordance with the Alberta Stack<br />
Sampling Code and the Air Monitoring Directive.<br />
8.10.2 Noise<br />
Baseline Noise Assessment will be undertaken in 2013 to establish ambient noise levels in the<br />
area. Noise surveys will be undertaken upon commencement of plant operations to validate the<br />
Noise Modeling Assessment conclusions presented herein.<br />
8.10.3 Water<br />
Shallow aquifer testing will be completed in 2013 in order to verify the static head, flow rates<br />
and chemical parameters of the Muriel aquifer in order to confirm that the potential draw does<br />
not affect residence use of this freshwater resource. Baseline sampling of landowners wells in<br />
the area will also proceed to gather local area concentrations for various parameters.<br />
Develop a Groundwater Monitoring Program and Management Plan for monitoring the shallow<br />
fresh aquifers in the regional development area, and provide to Alberta ESRD for approval prior<br />
to commencement of facility operations. Submit a Measurement Accounting and Reporting Plan<br />
to the ERCB for approval prior to the commencement of licensing.<br />
8.10.4 Vegetation<br />
Conduct a Rare Plant Survey to determine if there are any early flowering rare plants in the<br />
project development area, or within a 60 m boundary of the proposed site, in June of 2013.<br />
Develop a management plan if the presence is confirmed. Conduct pre-disturbance assessment<br />
prior to construction.<br />
8.10.5 Wildlife<br />
Conduct species specific surveys to determine the presence or absence of certain species in<br />
the project development area, in accordance with species occurrence data. Develop a<br />
management plan if the presence is confirmed.<br />
8.10.6 Emergency/Spill Response<br />
Develop a Site Specific Emergency Response Plan, based on the existing Corporate Response<br />
Plan, to include high pressure vapour (HPV) hazards and management, locations of spill<br />
response equipment and use/training requirements and monitoring of tanks and lines for<br />
spillage. A site specific Preventative Maintenance plan will also be developed for facility<br />
equipment and monitoring equipment.<br />
8.10.7 Participation in Area Research<br />
Birchwood will participate in LICA initiatives, and ALMS Lake Watch program.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 214
Figure 8.3.2-1 Maximum Predicted NO2 Contours for the 1-hour Averaging Period<br />
including Ambient Background<br />
Source: RWDI Air Quality Assessment report dated <strong>December</strong> 5, 2012<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 215
Figure 8.3.2-2 Maximum Predicted SO2 Contours for the 1-hour Averaging Period<br />
including Ambient Background<br />
Source: RWDI Air Quality Assessment report dated <strong>December</strong> 5, 2012<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 216
Figure 8.4-1 Noise Study Area and Receptor Locations<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 217
Figure 8.4-2 Predicted Nighttime Noise Levels<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 218
Figure 8.4-3 Relationships Between Everyday Sounds<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 219
Figure 8.5.3-1 Stratigraphic and hydrostratigraphic columns in the Cold Lake-<br />
Beaver River Basin<br />
CENOZOIC<br />
QUATERNARY<br />
TERTIARY<br />
McMURRAY<br />
(Consultant’s Report 1 Modified from Husky-Tucker <strong>Thermal</strong> <strong>Project</strong>, 2003)<br />
McMURRAY<br />
McMURRAY /<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 220
Figure 8.5.3-2 Location of the <strong>Project</strong> within the Beaver River Basin in Alberta<br />
(Source Lemay et al. 2005, EUB/AGS report)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 221
Figure 8.5.3-3 Recharge and Discharge Areas in the Cold Lake-Beaver River Basin<br />
Birchwood<br />
SAGD <strong>Pilot</strong><br />
<strong>Project</strong><br />
area<br />
(Crane<br />
(Source Map: Lemay and al. 2005, approximate location of Birchwood SAGD <strong>Pilot</strong> project added)<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 222
Figure 8.6.2-1 Soils Types and Locations<br />
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Figure 8.7.2-1 Birchwood Study Area<br />
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Figure 8.7.2-2 Vegetation Cover Types<br />
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Figure 8.7.2-3 Vegetation Plots<br />
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Figure 8.7.2-4 Rare Vascular Plant Survey Path<br />
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9 Public and First Nations Consultation<br />
9.1 Overview<br />
Birchwood believes that public consultation among all stakeholders is an essential, integral and<br />
ongoing part of the <strong>Sage</strong> pilot project development. Birchwood has made an effort to consult in<br />
a transparent manner built upon establishing mutual trust and respectful relationships with<br />
stakeholders.<br />
Since the summer of 2011, Birchwood has had, and will continue to have, ongoing consultation<br />
with stakeholders who may have a direct and/or potential interest in the <strong>Sage</strong> project including,<br />
government authorities, First Nations, Metis, landowners, occupants and other land users and<br />
stakeholders.<br />
Birchwood’s consultation has involved individuals, small groups, as well as a public information<br />
session regarding the <strong>Sage</strong> pilot project. Throughout the consultation process Birchwood has,<br />
and will continue to, invite all stakeholders to request information or ask project related<br />
questions, preferably in written format in order to allow us to respond in writing. As part of this<br />
information exchange Birchwood has summarized and made available a list of most frequently<br />
asked questions on the Birchwood corporate website.<br />
Where possible and permissible, stakeholder’s concerns regarding avoidance and/or mitigation<br />
have been incorporated into the <strong>Sage</strong> pilot project design or development plans. These efforts<br />
by Birchwood to respond to and to mitigate concerns brought forth will be ongoing throughout<br />
the duration of the <strong>Sage</strong> project.<br />
9.1.1 Goal of Consultation<br />
The primary goal of the Birchwood public consultation process is to ensure that stakeholders<br />
have access to information about the proposed development, and have the opportunity to ask<br />
questions and provide comments for improving the project and mitigating potential impacts on<br />
other stakeholders. Birchwood is committed to open communication with stakeholders during<br />
the planning and regulatory review process, construction, operation and reclamation.<br />
Birchwood believes that successful consultation requires active participation and commitment<br />
from all parties to identify issues and work towards resolutions. Birchwood is committed to<br />
continue the consultation process with the affected parties as the project develops.<br />
9.1.2 Consultation Summary<br />
Birchwood’s stakeholder and First Nation consultation program began in the summer of 2011<br />
and included:<br />
Holding personal consultation meetings;<br />
Holding a public information session regarding project specifics;<br />
Inviting stakeholders to communicate on any aspect of the <strong>Sage</strong> pilot project via<br />
telephone, verbal queries at meetings, letter, facsimile, or email;<br />
Disseminating information on Birchwood’s website;<br />
Providing responses to frequently asked questions (“FAQ’s”) via the Birchwood website;<br />
Providing a toll free number.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 228
9.2 Stakeholder Identification<br />
In order to commence the consultation process, Birchwood identified stakeholders by reviewing<br />
regional development plans, reports prepared by government and other agencies, and land<br />
titles. This involved meetings with several Government departments or regulators such as the<br />
Alberta Government, the Municipality of Bonnyville, ASRD (Alberta Sustainable Resources and<br />
Development), Alberta Environment, the ERCB (Energy Resources Conservation Board) and<br />
LICA (Lakeland Industry Community Association) as well as reviewing the Public Land Standing<br />
Report for the area.<br />
To date, the stakeholders and organizations that Birchwood has either engaged through direct<br />
consultation or identified as having potential interest in the project are:<br />
First Nations & Metis:<br />
Cold Lake First Nation.<br />
Frog Lake First Nation.<br />
Kehewin Cree Nation.<br />
Beaver Lake Cree Nation.<br />
Heart Lake First Nation.<br />
Whitefish – Goodfish First Nation.<br />
Zone 2 Metis.<br />
Land Users:<br />
Registered Trapper.<br />
Lease Holders and Occupants.<br />
Residents and Landowners:<br />
Residents and landowners within 5km, specifically over twenty (24) sections of land:<br />
Township 63 Range 3 W4M: Sections 30 and 31.<br />
Township 63 Range 4 W4M: Sections 25, 26, 27, 28, 31, 32, 33, 34, 35 and 36.<br />
Township 64 Range 4 W4M: Sections 1, 2, 3, 4, 5, 6, 9, 10, 11 and 12.<br />
Township 64 Range 3 W4M: Sections 6 and 7.<br />
Government:<br />
Municipal District of Bonnyville.<br />
Alberta Environment and Water.<br />
Alberta Sustainable Resource Development.<br />
Energy Resources Conservation Board<br />
Department of Fisheries and Oceans.<br />
Department of Transportation.<br />
Canadian Environmental Assessment Agency.<br />
MLA for Bonnyville/Cold Lake<br />
Mayor of Bonnyville.<br />
Mayor of Cold Lake.<br />
County of Vermillion.<br />
County of Two Hills.<br />
County of St. Paul.<br />
Mayor of Elk Point.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 229
Industry:<br />
Enbridge Pipelines (Athabasca) Ltd.<br />
Husky Oil Operations Ltd.<br />
Imperial Oil.<br />
Canadian Natural Resources Ltd.<br />
OSUM Oil Sands.<br />
Shell Canada Ltd.<br />
Non-Governmental Organizations:<br />
Alberta Lake Management Society.<br />
Crane Lake Advisory and Stewardship Society (CLASS).<br />
Lakeland Industry Community Association (LICA).<br />
Beaver River Watershed Alliance.<br />
Ducks Unlimited.<br />
Western Canada Spill Services (WCSS).<br />
9.3 Open House Summary<br />
Birchwood held an open house on June 7, 2012, in the Riverside community hall outside of Cold<br />
Lake. Notification and invitations to the Birchwood open house were sent out by mail to all of the<br />
land title owners in the 24 sections listed above, various government authorities, First Nation<br />
Councils, industrial companies operating near the potential development and NGO.s. All of<br />
these mailed notifications included the following three items:<br />
1) Written invitation giving the date, time and location of the open house,<br />
2) Birchwood pilot project comment form (to be mailed in, emailed, or brought to the open<br />
house), and;<br />
3) A Birchwood <strong>Sage</strong> SAGD <strong>Thermal</strong> <strong>Pilot</strong> <strong>Project</strong> May 2012 Public Disclosure Document.<br />
Print advertisements for the Birchwood Open House were placed in the following papers with<br />
two runs done in each paper.<br />
Bonnyville Nouvelle;<br />
The Cold Lake Sun;<br />
Cold Lake Courier.<br />
At the open house Birchwood and Propak Systems Ltd., (Birchwood’s engineering, fabrication<br />
and construction partner), had several staff members, including the President, Managing<br />
director and senior managers). The hall was set up in a circular fashion such that the attendees<br />
could work their way around the room and ask questions at each set-up. Materials on display<br />
included environmental information (including air emissions, water, noise, light and chemical<br />
substances and wastes), a schematic showing domestic use water well protection, aerial<br />
photographs, maps of the area, LICA guiding principles for oil-sands development, geological<br />
information, bitumen core and oil samples, the <strong>Sage</strong> pilot plant design and reference materials.<br />
Copies of the Birchwood <strong>Sage</strong> pilot project comment form and the Birchwood <strong>Sage</strong> SAGD<br />
<strong>Thermal</strong> <strong>Pilot</strong> <strong>Project</strong> Public Disclosure Document were provided. It is estimated that<br />
approximately 250 attendees participated in the open house. Responses ranged from support of<br />
the <strong>Sage</strong> project to outright rejection of the project. Most of the support for the project came<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 230
from the economic and employment benefits. Concerns/objections were based on water<br />
(domestic ground water and Crane Lake water pollution), air, noise, light, operational and “not in<br />
my backyard” concerns (which is some cases is partly a fear of the unknown and in some based<br />
on inaccurate information put forth by certain individuals opposed to the project).<br />
In some of the consultative exchanges Birchwood encountered challenges in building or<br />
creating a trustful and/or respectful relationship. Birchwood is cognitive after this open house of<br />
this “lack of trust” factor but continues to believe that after all of the supporting studies, reports<br />
and information of the pilot project application is reviewed this trust concern the and fear of the<br />
unknown should be alleviated.<br />
There were a small number of vocal attendees who felt Birchwood had not properly notified<br />
them of their activities and the open house meeting. Birchwood has advised landowners that the<br />
address used for contact was obtained from the land titles office and, if incorrect, the land title<br />
should be updated to reflect the current address.<br />
Birchwood received about 51 comment forms and/or emails from individual stakeholders. The<br />
vast majority of these came from Crane Lake full and part time residents. These concerns were<br />
responded to by Birchwood and a summary is provided in Section 9.4.<br />
9.4 Stakeholder Comments and Responses<br />
Throughout the consultation process Birchwood has asked for written stakeholders comments,<br />
concerns or questions on the <strong>Sage</strong> pilot project. Stakeholder questions and Birchwood<br />
responses are provided below in Table 9.4.1<br />
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Table 9.4.1 Summary of Stakeholder Questions and Responses by Birchwood<br />
Issue<br />
AIR<br />
Question Response<br />
Have you assessed the potential Yes the assessment is included in the Sulfur<br />
Hydrogen Sulphide for hydrogen sulphide gas Production and Recovery, and the Vapour<br />
Gas Generation generation as a result of the Recovery and Flare Systems detailed in Section<br />
bitumen extraction process?<br />
What contingency plan has been<br />
7.6.<br />
Hydrogen Sulphide<br />
Gas Generation<br />
made in the plant design for the<br />
potential of hydrogen sulphide<br />
gas generation?<br />
See above.<br />
Hydrogen Sulphide<br />
Gas Generation<br />
What modeling has been done<br />
with respect to the potential for<br />
the release of hydrogen sulphide<br />
gas from tanks and process<br />
equipment?<br />
Birchwood has conducted an Air Modeling<br />
Assessment to determine baseline emissions. Air<br />
modeling indicates that the Birchwood<br />
development is under Alberta Ambient Air Quality<br />
Guidelines (AAAWG) and the limits prescribed by<br />
the Lower Athabasca Regional Plan.<br />
Smells / Vent<br />
Gases<br />
What vapor recovery methods will<br />
be employed with the warm<br />
bitumen tanks to control odor?<br />
What type of tank will the<br />
A complete closed loop Vapor Recovery System<br />
is included in the design and no odor issues are<br />
anticipated.<br />
Smells / Vent<br />
Gases<br />
condensate for the diluent be<br />
stored in and what methods are<br />
planned to be employed to control<br />
odor from these tanks?<br />
There is no diluent storage. Diluent will be<br />
supplied by an existing underground pipeline.<br />
What about odor issues from the A complete closed loop Vapor Recovery System<br />
Odour<br />
plant and their effect on the is included in the design and no odor issues are<br />
NOISE<br />
residences of Crane Lake? anticipated.<br />
A noise impact assessment has been completed.<br />
The impact study show that sound levels will from<br />
Noise from Plant<br />
Facility/ Noise<br />
Modeling<br />
Will the noise from the facilities<br />
impact residents near Crane<br />
Lake?<br />
What noise modeling has been<br />
done on the proposed facility?<br />
the proposed development will be 35.1 dBA<br />
(nighttime) at 1.1 km distance from the facility and<br />
as such noise levels should not be audible by<br />
residents in the East Campground area or west<br />
residential area of Crane Lake.<br />
Birchwood will conduct an ambient noise<br />
monitoring project in the summer of 2013 as well<br />
as noise monitoring during plant operations.<br />
The drum boilers are not considered “noisy”. The<br />
Drum Boilers<br />
HYDROGEOLOGY<br />
Will the drum boilers be audible to<br />
the Crane Lake residents?<br />
equipment included in the Noise Assessment<br />
includes "noisy" equipment associated with the<br />
drum boilers and will be available in Section 8.4 of<br />
the <strong>Application</strong>.<br />
Birchwood is proposing to use brackish water for<br />
Source Water<br />
Will the project use any fresh<br />
water?<br />
steam generation. Fresh water usage is proposed<br />
for initial start-up and utility purposes (toilets,<br />
showers, chemical mixing, firefighting)<br />
Source Water<br />
How close will your wells be<br />
located to Crane Lake? How<br />
close will the end of the well bore<br />
be to the actual lake?<br />
The wellheads will be 700m from the lakeshore.<br />
The toes of the wells will be 420m below the<br />
surface and not under the lake.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 232
Surface Run-off<br />
Water Withdrawal<br />
Rate<br />
Steady State Water<br />
Withdrawal Rate<br />
Annual Water<br />
Withdrawal <strong>Volume</strong><br />
Water Demand<br />
Rates<br />
Experience<br />
Aquifer Interaction<br />
Aquifer Research<br />
Aquifer<br />
Where will surface run-off be<br />
disposed of from the facility?<br />
What will the initial water<br />
withdrawal rates from the<br />
freshwater aquifer which also<br />
feeds Crane Lake?<br />
What is the steady state water<br />
withdrawal rate from the<br />
freshwater aquifer?<br />
What is the estimated annual<br />
water withdrawal necessary to<br />
sustain the facility?<br />
What reliability assumptions are<br />
built into these rates?<br />
Has any reliability modeling been<br />
done on the facility?<br />
Will Birchwood shut down the<br />
facility if it cannot meet the water<br />
demand rates from the freshwater<br />
aquifer?<br />
What experience does Birchwood<br />
have operating water reclamation<br />
facilities as described in your<br />
literature?<br />
Will Birchwood be drilling through<br />
the Beverly Aquifer to develop<br />
producing and injection wells?<br />
What research have you done<br />
regarding aquifers?<br />
Introduced dissolved gases in the<br />
groundwater such as methane,<br />
ethane, propane, propene, butane<br />
and butene, how do you deal with<br />
these?<br />
Surface runoff will be collected on site. The<br />
industrial run-off pond will be subject to testing. If<br />
the water meets release requirements it will be<br />
released in a designated approved area. If it does<br />
not meet release requirements it will be treated or<br />
used in the production process.<br />
A Hydrogeology and Hydrology study has been<br />
completed and indicates that proposed ground<br />
water usage is sustainable and will not affect<br />
Crane Lake.<br />
Steady state withdrawal from the freshwater<br />
aquifers will be for utility and safety purposes only.<br />
The withdrawal rate is estimated to be less than 5<br />
m 3 /day.<br />
It is estimated that approximately 150,000 m 3 of<br />
brackish water will be withdrawn annually.<br />
(Assuming reservoir loss of 5% and blow down of<br />
7.5%). The fresh water withdrawal rate is<br />
estimated to be less than 2,000 m 3 /year during<br />
steady state operations<br />
Reliability modeling will be conducted in the Front<br />
End Engineering and Design (FEED) phase of the<br />
project.<br />
Freshwater demand will be for utility water, safety<br />
and firefighting purposes only. The withdrawal<br />
rate is estimated to be 5 m 3 /day. Water usage will<br />
met all requirements of the water diversion license<br />
including withdrawal limits.<br />
Management and consultants have extensive<br />
previous experience in drilling wells, constructing<br />
and operating these types of projects world-wide.<br />
The Hydrogeology and Hydrology Assessment<br />
does not indicate the presence of the Beverly<br />
Aquifer under the Birchwood property.<br />
A Hydrogeology and Hydrology Assessment has<br />
been prepared and included as part of the<br />
application.<br />
To ensure groundwater is protected Birchwood<br />
will undertake the following:<br />
Set surface Casing to a depth of 160 -180<br />
m below surface to protect fresh water<br />
aquifers.<br />
Use of premium thermal casing joints,<br />
high strength casing and thermal cement.<br />
Use of gas blanketing to protect from<br />
thermal transfer and monitor casing<br />
integrity.<br />
Install Micro-deformation monitoring as an<br />
early warning system for fluid migration.<br />
Birchwood has developed a casing monitoring<br />
plan. In the unlikely event that well integrity is<br />
compromised, the well would be shut in pursuant<br />
to ERCB requirements.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 233
Aquifer<br />
Aquifer<br />
Aquifer<br />
Aquifer<br />
Mud Systems<br />
Lake Use<br />
Lake Temperature<br />
Nearby Lakes<br />
Arsenic Levels<br />
Groundwater<br />
Monitoring<br />
How do you ensure that there is<br />
no contamination between the<br />
brackish water aquifers and the<br />
aquifer feeding the lake?<br />
What will Birchwood do if there is<br />
a drop in the static fluid level of<br />
our water well?<br />
How will Birchwood protect<br />
against thermal heating of the<br />
groundwater aquifers<br />
What chemical parameters will<br />
Birchwood be including in the<br />
ground water monitoring<br />
program? Will this include<br />
Isotopic fingerprinting?<br />
Is the mud system used to drill<br />
through the Aquifers non-toxic?<br />
Will you be drilling into a portion<br />
of Crane Lake?<br />
How will Birchwood protect the<br />
Lake from heating up and<br />
becoming contaminated with<br />
algae blooms?<br />
Will this affect the quantity and<br />
quality of the water in Crane<br />
Lake?<br />
How are you planning on<br />
containing the high levels of<br />
arsenic that will result as a byproduct<br />
from SAGD operations?<br />
What is the plan for this and how<br />
will my domestic water wells be<br />
monitored and protected?<br />
Brackish source water wells have multiple layers<br />
of casing and associated cement providing<br />
barriers between the fresh water aquifers and<br />
brackish water sources. Additionally the space<br />
between the casing and the tubing is filled with<br />
gas to monitor containment.<br />
Birchwood has conducted a Hydrogeology and<br />
Hydrology Assessment of the areas groundwater<br />
and it indicates that the aquifer from which fresh<br />
water will be drawn can support a significant<br />
volume of withdrawal without affecting static water<br />
levels in the area. Birchwood will be conducting a<br />
Baseline water assessment in 2013 to determine<br />
existing aquifer parameters.<br />
Domestic water wells will be protected by setting<br />
surface casing for the production and injection<br />
wells to a depth of 160 m, approximately 80 m<br />
below base of the domestic use wells in the area.<br />
<strong>Thermal</strong> cement will be used on the wells along<br />
with high grade tubulars and gas blanketing to<br />
minimize heat transfer.<br />
Chemical parameters are prescribed by Alberta<br />
Environment and include metals, salinity<br />
petroleum hydrocarbons and dissolved organic<br />
compounds.<br />
Birchwood will be using an inert non-toxic mud<br />
system to drill the surface hole (from surface to<br />
base of groundwater protection (0 – 160 m).<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 234<br />
No.<br />
Wells are located 400m below the surface and do<br />
not cross under the lake. There is minimal, if any<br />
risk of heat transfer to the lake.<br />
Gas blanketing will be used to minimize<br />
undesirable heat transfer away from the well bore.<br />
The Hydrological and Hydrogeological study and<br />
the Alberta Lake Management Society annual<br />
reports on Crane Lake have provided Birchwood<br />
with initial information to monitor the water quality<br />
at Crane Lake.<br />
Birchwood will use monitoring wells to ensure an<br />
area of protection and monitoring exists between<br />
the facility and all water bodies. The Groundwater<br />
protection program is designed to minimize the<br />
risk for potential effects on the groundwater by<br />
early detection and prevention.<br />
Birchwood will develop a Groundwater Monitoring<br />
and Management Program and submit this<br />
program to Alberta ESRD subsequent to initial<br />
approval of the scheme. Birchwood will include<br />
arsenic monitoring as part of the proposal as<br />
consultation with Alberta ESRD, ALMS and<br />
landholders have indicated the importance of<br />
addressing the issues of high levels of existing<br />
arsenic in the area.<br />
Birchwood is required to develop a Groundwater<br />
Monitoring and Management Program that will be<br />
submitted to Alberta ESRD for approval and must
Soils and Wildlife<br />
Ground Level<br />
Disruption<br />
Impact on wildlife<br />
Ecosystems<br />
Operational<br />
Visual Impact<br />
Visual Impact<br />
Plant Expansion<br />
Infrastructure<br />
Organizational<br />
Overview<br />
Oil spills<br />
Have you assessed the<br />
probability of a ground level<br />
disruption as a result of using high<br />
pressure steam in the wells?<br />
What is the result of the<br />
assessment?<br />
What will the repercussions be on<br />
wildlife?<br />
What impact will this plant have<br />
on Crane lake and the entire<br />
ecosystem?<br />
What light will be emitted from the<br />
plant?<br />
Will the plume from the steam be<br />
visible?<br />
What will be the expansion plan<br />
for the facility?<br />
What infrastructure will be put in<br />
place other than the plant?<br />
Describe your organization<br />
including the number of<br />
employees and an overview of<br />
your organizational structure.<br />
What if an oil spill goes into Crane<br />
Lake?<br />
be initiated prior to operations commencing.<br />
Domestic water wells will be protected by setting<br />
surface casing for the production and injection<br />
wells to a depth of 160 m, approximately 80 m<br />
below base of the majority of the domestic use<br />
wells in the area. <strong>Thermal</strong> cement will be used on<br />
the wells along with high grade tubulars. Micro<br />
deformation equipment will be used to monitor<br />
well integrity way from the well bore allowing<br />
Birchwood to shut in wells prior to loss of integrity<br />
and thereby preventing potential contamination.<br />
Birchwood will monitor the ground levels for<br />
surface heave using Satellite (InSAR) technology<br />
and GPS or Tiltmeters. The project is a low<br />
pressure (SAGD) steam injection and ground level<br />
disturbance is not considered a risk. A microdeformation<br />
monitoring program is planned to<br />
provide reservoir and well integrity monitoring.<br />
A vegetation and wildlife assessment has been<br />
completed, as the project has a small foot print<br />
and utilizes primarily previously disturbed land<br />
(61%) the impact on wildlife is assessed to be<br />
minimal as very little habitat displacement occurs.<br />
Birchwood has designed an operation to minimize<br />
the impact on the entire ecosystem including all of<br />
the lakes in the area.<br />
Light emissions will be minimized where possible<br />
by using on demand and focused lighting.<br />
Visibility will depend on location, ambient light,<br />
temperature and wind. No visibility is expected in<br />
the spring, summer and fall months.<br />
The proposed plant and well pad footprint will<br />
allow for the development of 36 well pairs. If the<br />
pilot is successful no additional lands would be<br />
required for approximately 15 years.<br />
The pilot proposes that 10 well pairs be put on<br />
location as well as an industrial storm water<br />
drainage pond and soil salvage piles.<br />
Birchwood is a private company with a small staff<br />
in Calgary, field operators and several<br />
contractors.<br />
The topography of the land is flowing south away<br />
from the lake, and the large distance of 700+<br />
meters away results in minimal (if any) risk to a<br />
spill contaminating Crane lake. A Site Specific<br />
Emergency Response Plan for the facility will be<br />
developed and will include a site specific spill<br />
response plan. Birchwood is a member of the<br />
Western Canadian Spill Services, Area VR-1 oil<br />
spill coop. Birchwood is required by the ERCB to<br />
follow the requirements of Directive 71.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 235
Drilling<br />
What experience does Birchwood<br />
have in the design and operation<br />
of SAGD wells, particularly at the<br />
shallow depths proposed for<br />
these wells?<br />
Drilling Coupling failures in casing<br />
Storage<br />
Storage<br />
Waste<br />
Management<br />
Production facilities<br />
Waste<br />
Management<br />
Troubleshooting<br />
Emergency<br />
Response<br />
Fire Protection<br />
Fire Protection<br />
Insurance<br />
What temperature will the bitumen<br />
be stored in the facility?<br />
What are the approximate<br />
volumes of onsite bitumen and<br />
condensate storage?<br />
What are the waste by-products<br />
from this water reclamation and<br />
where are they disposed of?<br />
Production with pumps and grid<br />
load?<br />
What other wastes will be<br />
generated and where will they be<br />
disposed of?<br />
What technical experience has<br />
Birchwood secured to provide<br />
ongoing troubleshooting and<br />
expertise in the operation of the<br />
plant?<br />
What emergency response<br />
capability does Birchwood have?<br />
Is there an emergency response<br />
plan that you have used in the<br />
past?<br />
What is planned for firefighting<br />
capabilities on the site?<br />
What is the source of firewater for<br />
the facility?<br />
What insurance will be in place to<br />
indemnify claimants in the event<br />
that there is a significant incident<br />
at the facility and Birchwood finds<br />
itself in receivership?<br />
Birchwood through management and contractors<br />
has extensive experience and expertise, including<br />
the drilling, operations and construction of SAGD<br />
operations.<br />
Birchwood would not consider these wells at 400+<br />
meters deep to be “shallow”.<br />
The use of high strength thermal grade couplings<br />
combined with a high grade cementing program<br />
should address this concern.<br />
Approximately 45 degrees C.<br />
Sales and Off Spec Bitumen – 1350m3. There is<br />
No Condensate/diluent storage.<br />
Spent water and waste from the evaporator will be<br />
disposed of into a deep (Granite Wash) disposal<br />
well, and waste will be disposed at an approved<br />
third party facility.<br />
Birchwood is proposing gas lift and will likely not<br />
be utilizing bottom hole pumps. The total<br />
operating grid load is currently estimated to be 5<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 236<br />
MW.<br />
Wastes will be disposed of off-site at approved<br />
third party facilities (Appendix 7.3). For further<br />
information on required waste management<br />
practices that Birchwood must be in compliance<br />
with see ERCB Directive 58.<br />
Birchwood management, contractors and partners<br />
have significant experience and will be engaging<br />
technically qualified field personnel with extensive<br />
experience and expertise as required.<br />
Birchwood is a member of the Western Canadian<br />
Spill Society Coop. The coop provides emergency<br />
spill response for spills. Birchwood has an existing<br />
Corporate Emergency Response Plan. A Site<br />
Specific Emergency Response Plan will be<br />
developed. Requirements regarding emergency<br />
response can be found in ERCB Directive 71.<br />
Birchwood will develop a Fire Response Program<br />
in accordance with Alberta ESRD/CAPP "Fire<br />
Smart Guidebook for the Oil and Gas Industry" as<br />
well as the CAPP "Best Management Practices for<br />
Wildfire Prevention" (2007). This program will be<br />
submitted to Alberta ESRD for approval prior to<br />
commencement of the plant operations.<br />
Birchwood will work with the MD of Bonnyville and<br />
cooperate with other neighboring industrial users<br />
to coordinate fire protection resources.<br />
In the event of fire utility water will be utilized.<br />
Full insurance will be in place.
Land Reclamation<br />
Security and<br />
Access<br />
CONSULTATION<br />
Open House<br />
Prior Wells drilled.<br />
LOCATION<br />
How can I find public documents<br />
on Birchwood’s land reclamation<br />
track record?<br />
How will you prevent<br />
unauthorized access to the area<br />
as a result of the increased<br />
access created by such an<br />
operation?<br />
Why I was not notified of the open<br />
house?<br />
Why I was not notified of the first<br />
three wells drilled by Birchwood?<br />
Plant Site location. Why was this location picked?<br />
TRADITIONAL LAND USE<br />
Land Use<br />
SOCIO ECONOMIC<br />
Property Values<br />
Traffic<br />
Will a Traditional Land Use (TLU)<br />
study be completed?<br />
What will happen to the value of<br />
our properties when this plant is<br />
built?<br />
How much increased traffic will<br />
there be on the access highway?<br />
9.5 First Nation Consultation Framework<br />
A conservation and reclamation plan is included<br />
as Consultants Report 7.<br />
There will be 24 hour security on site and all traffic<br />
will be monitored controlled and recorded.<br />
Birchwood has contacted parties based upon<br />
current land title records, however on occasion<br />
notices have been returned to sender for various<br />
reasons, mostly incorrect addresses on land titles.<br />
Notifications and Non-objection letters were<br />
completed and obtained, as required by ERCB<br />
Directive 56 and ESRD consultation requirements.<br />
The placement of the project has been selected to<br />
recover bitumen on the mineral lease and also<br />
limit surface disturbance by taking advantage of<br />
existing highways, access roads, cleared areas<br />
and industrial infrastructure, such as the Sales<br />
Pipelines and the Diluent Pipeline, and third party<br />
utility supply.<br />
Birchwood has completed a TKA/TLU for the Cold<br />
Lake First Nations on the well sites and access<br />
roads developed in 2011.<br />
Birchwood sees no reason for any change in<br />
property value given much smaller size of the<br />
<strong>Sage</strong> project when compared to existing Oilsands<br />
development in the area.<br />
Birchwood will access the development from<br />
Highway 892 and will not affecting Crane Lake<br />
residential access. Birchwood will work with<br />
contractors and other operators to promote<br />
procedures that will reduce peak traffic volumes.<br />
Mitigation could include staggered hours, carpooling<br />
and bus transportation.<br />
Considering the significantly smaller size of the<br />
operation compared to the already existing<br />
development using Highway 892 the project is<br />
unlikely to cause any noticeable changes to traffic<br />
volumes or road usage for Crane Lake residents.<br />
Birchwood, as the project proponent and in accordance with AESRD’s Policies and Guidelines<br />
for consultation with First Nations, works within an internal First Nations Consultation Plan. This<br />
plan is designed to ensure that Birchwood meets both the Guiding Principles and expectations<br />
of industry put forth by the Alberta Government and ERCB.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 237
9.5.1 First Nation Consultation Summary<br />
Birchwood has consulted (and will continue to do so as required) with the following First Nations<br />
with respect to the <strong>Sage</strong> pilot project as identified by the framework:<br />
Cold Lake First Nation;<br />
Frog Lake First Nation;<br />
Beaver Lake Cree Nation;<br />
Kehewin Cree Nation;<br />
Heart Lake First Nation;<br />
Whitefish – Goodfish First Nation;<br />
Birchwood has, and will continue to track and respond to any written information requests,<br />
concerns or questions brought forth by First Nations. A summary of consultation meetings and<br />
events is provided in Table 9.6.<br />
9.5.1.1 Cold Lake First Nation<br />
Birchwood provided a <strong>Project</strong> Description Letter to the Cold Lake First Nation on its proposed<br />
drilling program on June 24, 2011. It met with the Chief and Council and their legal counsel in<br />
August 2011 to formally discuss the Cold Lake First Nation Consultation Guidelines. A<br />
presentation on the project was provided by Birchwood and formal Consultation Protocols along<br />
with a Traditional Territory Map and guidelines for the consultation process were presented by<br />
the Chief on behalf of the Nation. Through the Cold Lake First Nation JV partner, Stantec Nu-<br />
Nenni, a traditional knowledge and traditional land use study was commissioned and traditional<br />
knowledge holders and elders participated in a field visit to the area. In May 2012, an invitation<br />
to the open house and a copy of the Public Disclosure Document was sent. In June 2012, an<br />
Open House was held for the Nation and the general public at which a Public Disclosure<br />
Document was presented on the Birchwood <strong>Sage</strong> SAGD <strong>Project</strong>. In August 2012, notification of<br />
a proposed 3D Seismic program was delivered to counsel for the Cold Lake First Nation by<br />
registered mail. In October 2012, follow up notification of the <strong>Sage</strong> SAGD project complete with<br />
the Public Disclosure Document and a copy of a Comment Form were delivered to the Cold<br />
Lake First Nation by registered mail.<br />
While engaging in consultation efforts with the Cold Lake First Nation, it became clear that the<br />
Nation was firm on its moral and legal rights to consultation and participation by the Nation in<br />
future development in the area. In efforts to both understand and assist in this process,<br />
opportunities to participate were presented to the Nation and assistance was provided in its<br />
relations with other operators in the area. The Cold Lake First Nation appears to be pleased<br />
with the results of this process and willing to work with Birchwood in developing the project.<br />
9.5.1.2 Frog Lake First Nation<br />
In May 2012, an invitation to the open house and a copy of the Public Disclosure Document was<br />
sent. In June 2012, an Open House was held for the Nation and the general public at which a<br />
Public Disclosure Document was presented on the Birchwood <strong>Sage</strong> SAGD <strong>Project</strong>. In October<br />
2012, follow up notification of the <strong>Sage</strong> SAGD project complete with the Public Disclosure<br />
Document and a copy of a Comment Form were delivered to the Frog Lake First Nation by<br />
registered mail.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 238
As part of the Cold Lake First Nation’s drive to participate in development, it hosted a number of<br />
meetings with other First Nations which Birchwood attended by invitation. At these meetings it<br />
was clear that the Frog Lake First Nation was well advanced in its participation objectives as it<br />
had developed a junior oil and gas company with substantial production on reserve land. At<br />
meetings with Frog Lake Energy Limited, it was apparent that development off reserve would<br />
follow and that Birchwood could assist in this.<br />
9.5.1.3 Beaver Lake Cree Nation<br />
Birchwood provided a <strong>Project</strong> Description Letter to the Beaver Lake Cree Nation on its proposed<br />
drilling program on June 24, 2011. As no response was received by the end of the notice period<br />
and all approvals and consents were in place, Birchwood commenced its proposed drilling<br />
program in <strong>December</strong> 2011. In May 2012, an invitation to the open house and a copy of the<br />
Public Disclosure Document was sent. In June 2012, an Open House was held for the Nation<br />
and the general public at which a Public Disclosure Document was presented on the Birchwood<br />
<strong>Sage</strong> SAGD <strong>Project</strong>. In August 2012, notification of a proposed 3D Seismic program was<br />
delivered to the Beaver Lake Cree Nation by registered mail. In October 2012, follow up<br />
notification of the <strong>Sage</strong> SAGD project complete with the Public Disclosure Document and a<br />
copy of a Comment Form were delivered to the Beaver Lake Cree Nation by registered mail.<br />
Formal notices were sent to the Beaver Lake Cree Nation and a formal written consultation<br />
protocol was returned indicating that unless and until the Governments of Alberta and of<br />
Canada responded to concerns of the Nation regarding Treaty 6 and the rights of Aboriginal<br />
Peoples, no progress would be made on the Birchwood project. The application addresses<br />
substantially all of the information requested, a copy of which will be sent to all identified<br />
stakeholders.<br />
9.5.1.4 Kehewin Cree Nation<br />
Birchwood provided a <strong>Project</strong> Description Letter to the Kehewin Cree Nation on its proposed<br />
drilling program on June 24, 2011. As no response was received by the end of the notice period<br />
and all approvals and consents were in place, Birchwood commenced its drilling program in<br />
<strong>December</strong> 2011. In May 2012, an invitation to the open house and a copy of the Public<br />
Disclosure Document was sent. In June 2012, an Open House was held for the Nation and the<br />
general public at which a Public Disclosure Document was presented on the Birchwood <strong>Sage</strong><br />
SAGD <strong>Project</strong>. In August 2012, notification of a proposed 3D Seismic program was delivered to<br />
the Kehewin Cree Nation by registered mail. In October 2012, follow up notification of the <strong>Sage</strong><br />
SAGD project complete with the Public Disclosure Document and a copy of a Comment Form<br />
were delivered to the Kehewin Cree Nation by registered mail.<br />
After formal notices were sent to the Kehewin Cree Nation, a meeting was held with the Chief<br />
and his councilors on August 24, 2012. At that meeting and at meetings attended by the Nation<br />
at the invitation of the Cold Lake First Nation, it was clear that the Kehewin Cree Nation was<br />
anxious to participate in development on and off the reserve in order to provide long term<br />
opportunity to its citizens. Joint ventures in construction, service rig fabrication, drilling rig<br />
operations and oil and gas development were discussed along with a Traditional<br />
Knowledge/Traditional Land Use study. Birchwood explained that much of the land was either<br />
freehold or developed grazing lease and that Stantec/Nu Nenni had already been engaged to<br />
provide this and a report was available upon approval of the Cold Lake First Nation. At a<br />
subsequent meeting with the Chief and Council, Birchwood’s assistance was sought to work<br />
with a major operator and the Nation to construct a service rig.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 239
9.5.1.5 Heart Lake First Nation<br />
Birchwood provided a <strong>Project</strong> Description Letter to the Heart lake First Nation on its proposed<br />
drilling program on June 24, 2011. As no response was received by the end of the notice period<br />
and all approvals and consents were in place, Birchwood commenced its drilling program in<br />
<strong>December</strong> 2011. In May 2012, an invitation to the open house and a copy of the Public<br />
Disclosure Document was sent. In June 2012, an Open House was held for the Nation and the<br />
general public at which a Public Disclosure Document was presented on the Birchwood <strong>Sage</strong><br />
SAGD <strong>Project</strong>. In August 2012, notification of a proposed 3D Seismic program was delivered to<br />
the Heart Lake First Nation by registered mail. In October 2012, follow up notification of the<br />
<strong>Sage</strong> SAGD project complete with the Public Disclosure Document and a copy of a Comment<br />
Form were delivered to the Heart Lake First Nation by registered mail.<br />
After formal notices were sent to the Heart Lake First Nation, a meeting was held with the<br />
Nation’s advisors on August 20, 2012. At that meeting, the history of the Nation, the effect of the<br />
Air Weapons Range agreements, the long tenure of the Chief and some of his accomplishments<br />
in the area of economic development for the Nation as well as the consultation protocols<br />
required were discussed. The nation had engaged a number of consultants that had clearly<br />
defined traditional lands and migration patterns in an electronic format. The Birchwood project<br />
was discussed and no substantive issues were identified. At a follow up meeting the councilors<br />
brought along the Nation’s construction JV partner who presented its credentials. It was agreed<br />
that the Nation would provide Birchwood with a Traditional Land use study and framework. As of<br />
<strong>December</strong> 20, 2012 the information has yet to be received.<br />
9.5.1.6 Whitefish – Goodfish First Nation<br />
In May 2012, an invitation to the open house and a copy of the Public Disclosure Document was<br />
sent. In June 2012, an Open House was held for the Nation and the general public at which a<br />
Public Disclosure Document was presented on the Birchwood <strong>Sage</strong> SAGD <strong>Project</strong>. In August<br />
2012, notification of a proposed 3D Seismic program was delivered to the Whitefish - Goodfish<br />
First Nation by registered mail. In October 2012, follow up notification of the <strong>Sage</strong> SAGD project<br />
complete with the Public Disclosure Document and a copy of a Comment Form were delivered<br />
to the Whitefish - Goodfish First Nation by registered mail.<br />
After formal notices were sent to the Whitefish - Goodfish First Nation, a meeting was held with<br />
a Councilor and staff on August 23, 2012. At that meeting, Birchwood presented the project and<br />
the Nation provided a traditional territory map, Economic development through on reserve<br />
service businesses was discussed along with an MOU and TLU study. At a follow up meeting<br />
with the Councilor and legal counsel the concept of a formal Memorandum of Understanding<br />
was discussed and legal counsel was to provide it to Birchwood at its earliest opportunity.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 240
9.6 Meetings and Events<br />
Table 9.6 List of Meetings and Events<br />
Date Meeting or Event<br />
Alberta Environment and Sustainable Resources Development<br />
February 8, 2012 Meeting with representatives from Alberta Environment and Alberta<br />
Sustainable Resources to introduce Birchwood Resources Inc., and the SAGE<br />
project.<br />
Alberta Lake Management Society<br />
October , 2012 Conference call to discuss ALMS role in Beaver River Watershed/LARP projects,<br />
Crane Lake monitoring program that ALSM conducts, membership<br />
opportunities and how to integrate monitoring requirements with association<br />
objectives.<br />
Alberta Sustainable Resource Development<br />
June 28, 2012 Meeting at the Bonnyville ASRD office to discuss SAGE project including access,<br />
project footprint, emergency response, fish and wildlife potential concerns.<br />
Energy Resources Conservation Board<br />
April 5, 2012 Meeting with various representatives of the ERCB to introduce Birchwood<br />
Resources Inc. and discuss the SAGE project.<br />
April, 2012 Meeting with various representatives of the ERCB to discuss geological<br />
requirements associated with SAGD applications.<br />
June 7, 2012 Open House at Riverhurst Community Association<br />
June 27, 2012 Meeting with Bonnyville ERCB staff. Detailed discussion on the SAGE project.<br />
MLA for Bonnyville-Cold Lake<br />
June 27, 2012 Introduction to Birchwood Resources Inc. and discussion of the SAGE project.<br />
Lakeland Industry and Community Association<br />
October , 2011 Meeting to present well development and introduce Birchwood Resources Inc.<br />
to LICA Board of Directors.<br />
<strong>December</strong>, 2011 LICA Christmas Party – general discussion of industry activity.<br />
April/May, 2012 Discussion of Groundwater monitoring parameters.<br />
June 7, 2012 Open House at Riverhurst Community Association<br />
June 27, 2012 General discussion of SAGE project and discussion on LICA/Beaver River air and<br />
watershed monitoring.<br />
Municipality of Bonnyville<br />
November, 2011 Special council meeting to discuss cold well development and SAGE, specifically<br />
access development and road use.<br />
June 2012 Open House at Riverhurst Community Association<br />
June 2012 Site Visit at SW-02-064-04W4m with Representative from Municipality of<br />
Bonnyville.<br />
Cold Lake First Nation<br />
August 23, 2011 Meeting with Chief and Council at Counsel’s Office – consultation and history<br />
August 26/27, 2011 Attend and Support NANCA Rodeo<br />
September 23, 2011 Meeting with Members of Council – Economic Development<br />
<strong>December</strong> 08, 2011 Meeting at Band Office – Status of project and economic development<br />
<strong>December</strong> 13, 2011 Meeting with Chief and Council and BOD Tri Rez Oil and Gas – Economic Dev.<br />
January 16, 2012 Meeting with Members of Council and BOD Tri Rez – <strong>Sage</strong> <strong>Project</strong> and Other<br />
January 20, 2012 Meeting with Chief and Council and Bod Tri Rez – Business Development<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 241
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel<br />
March 29, 2012 Meeting with Council and JV Partners – Economic Development<br />
April 12, 2012 Attend Industry and Nation Meeting on behalf of CLFN<br />
April 19, 2012 Attend Meeting with Nation’s Environmental Consultants<br />
April 24, 2012 Attend Meeting with Counsel for Nation on Environmental Cumulative Effects<br />
May 25, 2012 Conference with Chief and Council and Counsel – Industry Relations<br />
May 29, 2012 Meeting with Nation’s Counsel and Environmental Consultants – Impacts<br />
June 4, 2012 Meeting with Nation’s Counsel and Environmental Consultants – Data Source<br />
June 7, 2012 Open House at Riverhurst Community Hall – <strong>Sage</strong> <strong>Project</strong><br />
June 19, 2012 Meeting with Chief and Councillors – Review Economic Parameters – Industry<br />
June 26, 2012 Attend Nation’s Camp and Catering JV Partner Industry Event<br />
July 12, 2012 Meeting with Nation’s Counsel and Environmental Consultant – Impacts<br />
July 25, 2012 Joint Bid Oil Sands Production Acquisition<br />
October 10, 2012 Meeting with Councillors – <strong>Project</strong> Update and Economic Development<br />
Frog Lake First Nation<br />
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel<br />
April 11, 2012 Meeting with CLFN and Frog Lake Energy Technical Teams – Economic Dev.<br />
April 11, 2012 Meeting with Frog Lake Energy Investors – Economic Development<br />
April 26, 2012 Meeting with Frog Lake Energy – Business Development Opportunity<br />
May 28, 2012 Meeting with CLFN and Frog Lake Energy Representatives – Business Dev.<br />
June 7 2012 Open House at Riverhurst Community Hall – <strong>Sage</strong> <strong>Project</strong><br />
June 12, 2012 Meeting with CLFN and Frog Lake Energy – Business Development<br />
June 19, 2012 Meeting with CLFN and Frog Lake Energy – Business Development<br />
July 12, 2012 Meeting with Frog Lake Energy Investors – Economic Development<br />
July 25, 2012 Joint Bid Oil Sands Production Acquisition<br />
November 29, 2012 Meeting with Fog Lake Energy Board Members – Economic Development<br />
Kehewin Cree Nation<br />
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
March 22, 2012 Conference – Keyano Pimee Board of Directors – Economic Development<br />
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel<br />
August 24, 2012 Meeting Chief and Councillor – TLU, Economic Development, <strong>Sage</strong> <strong>Project</strong><br />
September 25, 2012 Meeting with Chief and Council at Band Office – <strong>Project</strong>, Economic Benefit<br />
Onion Lake First Nation<br />
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel<br />
Saddle Lake First Nation<br />
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel<br />
April 4, 2012 Meeting with Councillors, JV Partners and Financial Advisors – Economic Dev.<br />
April 26, 2012 Meeting with Councillor – Economic Development and Joint Venture<br />
Samson Cree Nation<br />
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
IOGC<br />
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 242
IRCC<br />
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity<br />
Heart Lake First Nation<br />
August 20, 2012 Meeting with Councillors and Advisors, Edmonton – <strong>Sage</strong> <strong>Project</strong>, History, TLU<br />
November 22, 2012 Meeting with Councillors and JV Partner – Business Development Opportunity<br />
Whitefish – Goodfish First Nation<br />
August 23, 2012 Meeting with Councillor at Band Office – <strong>Sage</strong> <strong>Project</strong>, History, TLU, MOU<br />
August 29, 2012 Meeting with Councillor and Counsel – TLU, MOU, Economic Development<br />
Metis Zone II<br />
June 7, 2012 Open House at Riverhurst Community Hall – <strong>Sage</strong> <strong>Project</strong> – JV Partner<br />
August 22, 2012 Meeting with Councillor and Advisor – History, Background, TLU, Economics<br />
August 23, 2012 Meeting with Rupertsland Institute Director – Educational Assistance JV<br />
September 26, 2012 Meeting with Rupertsland Institute Director – Specific Education <strong>Project</strong><br />
9.7 Birchwood Commitment to Consultation<br />
Birchwood will make available a copy of the <strong>Sage</strong> pilot project application on the Birchwood<br />
website and continue to maintain a list of FAQ’s and provide updates as the <strong>Sage</strong> pilot project<br />
develops.<br />
Birchwood will track and respond to all written information requests, concerns or questions<br />
brought forth by any stakeholder and will continue to engage and consult with any stakeholder<br />
throughout the application and operation phase of the <strong>Sage</strong> project.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 243
10 References<br />
Agriculture and Agri-Food Canada. 2006. Alberta Soil Names Generation 3. Users Handbook.<br />
J.A. Brierley, B.D. Walker, C.J. Tomas and P.E. Smith and M.D. Bock (Eds.). Land Resource<br />
Unit, Research Branch, Agriculture and Agri-Food Canada, Edmonton, Alberta.<br />
Alberta Agriculture. 1987. Soil Quality Criteria Relative to Disturbance and Reclamation<br />
(Revised). Prepared by the Soil Quality Criteria Working Group, Soil Reclamation Subcommittee,<br />
Alberta Soils Advisory Committee, Alberta Agriculture. Edmonton, Alberta. 56 pp.<br />
Alberta Agriculture, Food and Rural Development 2001, Native Plant Revegetation Guidelines for<br />
Alberta. Edmonton, Ab.<br />
AGRASID (Agricultural Region of Alberta Soil Inventory Database). 2007. Agricultural Region of<br />
Alberta Soil Inventory Database, Last reviewed/Revised on January 17, 2007. Available at:<br />
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Agriculture and Rural Development, 2010. The Agricultural Region of Alberta Soil Inventory<br />
Database. Edmonton, AB.<br />
Agronomic Interpretations Working Group. 1995. Land Suitability Rating System for Agricultural<br />
Crops: 1. Spring-seeded small grains. Edited by W.W. Pettapiece. Tech. Bull. 1995-6E. Center<br />
for Land and Biological Research, Agriculture and Agri-Food Canada, Ottawa.<br />
Alberta Conservation Information Management System, 2012. List of Tracked and Watched<br />
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Alberta Energy, 2000. Oil and Gas Conservation Act. Edmonton, AB.<br />
Alberta Energy, 2000. Oil and Gas Conservation Regulations (AR151/71). Edmonton, Ab<br />
Alberta Energy, 2000. Oil Sands Conservation Act. Edmonton, AB.<br />
Alberta Energy, 1988. Oil Sands Conservation Regulations (AR 76/1988). Edmonton, AB.<br />
Alberta Environmental Protection, 1989. Air Monitoring Directive. Edmonton, AB.<br />
Alberta Environment, 2009. Air Quality Model Guideline. Climate Change and Land Policy<br />
Branch, Alberta Environment. Edmonton, AB.<br />
Alberta Environment, 1995. Alberta Stack Sampling Code. Edmonton, AB.<br />
Alberta Environment, 1996. <strong>Application</strong>s for Sour Gas and Heavy Oil Operating Plants.<br />
Edmonton, AB.<br />
Alberta Environment, 2007. Approvals Program Interim Policy. Interim Emission Guidelines for<br />
Oxides of Nitrogen (NOx) for New Boilers, Heaters and Turbines using Gaseous Fuels for the Oil<br />
Sands Region Municipality of Wood Buffalo North of Fort McMurray based upon a review of Best<br />
Available Technology Economically Feasible (BATEF), App. 1, <strong>December</strong> 2007<br />
Alberta Environment, 1998. C&R Information Letter 98-4: Voluntary Shut Down Criteria for<br />
Construction Activity or Operations. Edmonton, AB.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 244
Alberta Environment, 2000, Environmental Protection and Enhancement Act (EPEA). Edmonton,<br />
AB.<br />
Alberta Environment, 2003. Groundwater Evaluation Guidelines (Information Required when<br />
Submitting and <strong>Application</strong> under the Water Act.) Edmonton, AB.<br />
Alberta Environment, 2011. Guide to Groundwater Authorization. Edmonton, AB.<br />
Alberta Environment, 2010. Guidelines for Reclamation to Forest Vegetation in the Athabasca Oil<br />
Sands Region. Edmonton, AB.<br />
Alberta Environment, 2009. Guidelines for Submission of a Pre-Disturbance Assessment and<br />
Conservation & Reclamation Plan (PDA/C&R Plan). Edmonton, AB.<br />
Alberta Environment, 2008. Guidelines for Wetland Establishment on Reclaimed Oil Sands<br />
Leases. 2nd ed. Fort McMurray: Alberta Environment, prepared by Cumulative Environmental<br />
Management Association.<br />
Alberta Environment, 2009. Soil Monitoring Directive. Edmonton, AB.<br />
Alberta Environmental Protection, 1993. EPEA Activities Designation Regulation (AR 113/93).<br />
Edmonton, AB.<br />
Alberta Environmental Protection, 2010. EPEA Conservation and Reclamation Regulation (AR<br />
115/93). Edmonton, AB.<br />
Alberta Environmental Protection, 1993. EPEA Substance Release Reporting Regulation (AR<br />
117/93). Edmonton, AB.<br />
Alberta Environment, 2002. Environmental Protection Guidelines for Oil Production Sites –<br />
Revised. Edmonton, AB.<br />
Alberta Environment, 1988. Hazardous Waste Storage Guidelines. Edmonton, AB.<br />
Alberta Environmental Protection, 1996. EPEA Waste Control Regulation. Edmonton, AB.<br />
Alberta Environment and Water, 2011. Alberta Ambient Air Quality Guidelines. Edmonton, AB.<br />
Alberta Environment and Water, 2011. Directive for Monitoring the Impact of Sulphur Dust on<br />
Soils. Edmonton, AB.<br />
Alberta Environment, 2006. Cold Lake Beaver River Groundwater Quality State of the Basin<br />
Report.<br />
Alberta Environmental Protection, 1996. Alberta User Guide for Waste Managers, 1996<br />
Edmonton, AB.<br />
Alberta Environmental Protection, 1996. Cold Lake Sub Regional Integrated Resource Plan, 1996<br />
Alberta Environmental Protection, 1997. Conservation and Reclamation Guidelines, 1997<br />
Edmonton, AB.<br />
Alberta Sustainable Resource Development (ASRD), 2003. Alberta Regeneration Survey Manual.<br />
Edmonton: Alberta Sustainable Resource Development.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 245
Alberta Environmental Protection, 1995, Environmental Protection Guidelines for Electric<br />
Transmission. Edmonton, AB.<br />
Alberta Environment. 2009. Guidelines for Submission of a Pre-Disturbance Assessment and<br />
Conservation & Reclamation Plan (PDA / C&R Plan), 2009 Edmonton, AB.<br />
Alberta Lake Management Society, 2008. Crane (Moore) Lake 2008 Report. Volunteer Lake<br />
Monitoring Program.<br />
Alberta Native Plant Council, 2012. ANCP Guidelines for Rare Vascular Plant Surveys in Alberta<br />
– 2012 Update.<br />
Alberta Lake Management Society, 2008. Crane (Moore) Lake 2011 Report (Draft). Volunteer<br />
Lake Monitoring Program.<br />
Alberta Soils Advisory Committee. 1987. Land Capability Classification for Arable Agriculture in<br />
Alberta. W.W. Pettapiece (ed.). Alberta Agriculture, Edmonton, Alberta.<br />
Alberta Environment and Sustainable Resource Development, 2012. Interim Guideline for<br />
Content for Industrial Approval <strong>Application</strong>s – New Renewal and Amendment.: Edmonton, AB.<br />
Alberta Municipal Affairs, 2006. Alberta Fire Code 2006. Edmonton, AB.<br />
Alberta Municipal Affairs, 2000, S-1. Safety Codes Act. Edmonton, AB.<br />
Alberta Sustainable Resource Development, 2010. Alberta Wild Species General Status Listing<br />
2010. Edmonton, AB.<br />
Alberta Sustainable Resource Development, 2008. FireSmart Guidebook for the Oil and Gas<br />
Industry. Edmonton, AB.<br />
Alberta Sustainable Resources Development, 2005. First Nations Consultation Policy on Land<br />
Management and Resource Development (the Policy). Edmonton, AB.<br />
Alberta Sustainable Resources Development, 2007. First Nations Consultation Policy on Land<br />
Management and Resource Development (the Guidelines) Edmonton, AB.<br />
Alberta Sustainable Resources Development, 2009. Management of Wood Chips on Public Land.<br />
Edmonton, AB.<br />
Alberta Sustainable Resources Development, 2005. Natural Regions and Sub-regions of Alberta.<br />
Edmonton, AB.<br />
Alberta Sustainable Resource Development, 2008. Wildfire Prevention. Edmonton, AB.<br />
Andriashek, L.D. and Fenton, M.M. 1989. Quaternary Stratigraphy and Surficial Geology of the<br />
Sand River Area 73L. Alberta Research Council. Edmonton, Alberta.<br />
ARDA. 1965. Canada Land Inventory. Soil Capability Classification for Agriculture. The Canada<br />
Land Inventory Report No. 2. Department of Forestry and Rural Development, Ottawa (Reprinted<br />
by Dept. of Environment 1969 and 1972).<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 246
Beckingham, J.D. and J.H. Archibald. 1996. Field Guide to Ecosites of Northern Alberta.<br />
Northern Forestry Centre, Forestry Canada, Northwest Region. Edmonton, Alberta.<br />
Brocke, L.K. 1977. The Canada Land Inventory Soil Capability for Agriculture in Alberta. Alberta<br />
Environment, Edmonton, Alberta.<br />
Canadian Association of Petroleum Producers, 2007. Best Management Practises for Fugitive<br />
Emissions Management. Calgary, AB<br />
Canadian Association of Petroleum Producers, 2007. Best Management Practises for Wildifire<br />
Prevention. Calgary, AB<br />
Canadian Council of Ministers of the Environment, 1999. Canadian Environmental Quality<br />
Guidelines. Ottawa, ON.<br />
Canadian Council of Ministers of the Environment, 2003. Code of Practice for Above and<br />
Underground Tanks systems Containing Petroleum and Allied Petroleum Products. Ottawa, ON.<br />
Canadian Council of Ministers of the Environment, 1990. Environmental Guidelines for Controlling<br />
Emissions of Volatile Organic Compounds from Aboveground Storage Tanks. Ottawa, ON.<br />
Canadian Council of Ministers of the Environment, 2006. A Framework for Ecological Risk<br />
Assessment: General Guidance. Ottawa, ON.<br />
Canadian Council of Ministers of the Environment, 1993. Environmental Code of Practice<br />
Measurement and Control of Fugitive Volatile Organic Chemicals (VOC) Emissions from<br />
Equipment Leaks. Ottawa, ON.<br />
Canadian Council of Ministers of the Environment, 1998. National Emission Guidelines for<br />
Commercial/Industrial Boiler and Heater Sources. Ottawa, ON.<br />
Canadian Environmental Assessment Agency, 2012. Regulations Designating Physical Activities<br />
(SOR 2012/147). Ottawa, ON.<br />
Canadian Environmental Assessment Agency,2012. Prescribed Information for the Description of<br />
a Designated <strong>Project</strong> Regulations (SOR 2012 – 148). Ottawa, ON<br />
Committee on the Status of Endangered Wildlife in Canada, 2012. Species at Risk.<br />
Donnelly, Dr. J., 1999. Hilda Lake, a Gravity Drainage Success, presented to the SPE<br />
conference, Bekersfield, CA.<br />
Donnelly, Dr. J., 2000. The Best Process for Cold Lake: CSS vs. SAGD. Journal of Petroleum<br />
Technology.<br />
Energy Resources Conservation Board (ERCB), 2011. Bulletin 2011-23 – Amendments to the<br />
Coal Conservation Act and Regulations, Oil and Gas Conservation Act and Regulations, Oils<br />
Sands Act, and Pipeline Act. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2011. Bulletin 2011-19 – Amendments to the Oil<br />
Sands Conservation Regulation. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2010. Bulletin 2010-46 – New Directive 008 –<br />
Surface Casing Requirements, Issued. Calgary, AB.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 247
Energy Resources Conservation Board (ERCB), 2. Bulletin 2011-23 – Amendments to the Coal<br />
Conservation Act and Regulations, Oil and Gas Conservation Act and Regulations, Oils Sands<br />
Act, and Pipeline Act. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2006b. Bulletin 2006-1 – Water Recycle<br />
Reporting and Balancing Information for In Situ <strong>Thermal</strong> Schemes. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2010. Directive 008 - Surface Casing Depth<br />
Requirements. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1990. Directive 009 - Casing Cementing<br />
Minimum Requirements. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2009. Directive 010 - Minimum Casing Design<br />
Requirements Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1991. Directive 023 - Guidelines Respecting an<br />
<strong>Application</strong> for a Commercial Crude Bitumen Recovery and Upgrading <strong>Project</strong>,) Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2007. Directive 038 - Noise Control. Calgary,<br />
AB.<br />
Energy Resources Conservation Board (ERCB), 2006. Directive 042 – Measurement, Accounting<br />
and Reporting Plan (MARP) Requirements for <strong>Thermal</strong> Bitumen Schemes. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1996. Directive 050 – Drilling Waste<br />
Management. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2012. Directive 051 - Injection and Disposal<br />
Wells – Well Classifications, Completions, Logging and Testing Requirements. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2001. Directive 055 - Storage Requirements for<br />
the Upstream Petroleum Industry. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2011. Directive 056 - Energy Development<br />
<strong>Application</strong>s and Schedules. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2008. Directive 058 -Oilfield Waste Management<br />
Requirements for the Upstream Petroleum Industry. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2012. Directive 071 - Emergency Preparedness<br />
and Response Requirements for the Petroleum Industry Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2012. Directive 081 – Water Disposal Limits and<br />
Reporting Requirements. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1998. Information Letter 98-01 – A<br />
Memorandum of Understanding between Alberta Environmental protection and the Alberta<br />
Energy and Utilities Board Regarding Coordination of Release Notification Requirements and<br />
Subsequent Regulatory Response. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2000. Interim Directive 2000-04 – An Update to<br />
the Requirements for the Appropriate Management of Oilfield Wastes. Calgary, AB.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 248
Energy Resources Conservation Board (ERCB), 1999, Interim Directive 99-04 – Deposition of<br />
Oilfield Waste into Landfills. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1996, Information Letter 96-07 – EUB/AEP<br />
Memorandum of Understanding on the Regulation of Oil Sands Developments. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1999. Interim Directive 99-01 – Gas/Bitumen<br />
Production in Oil Sands Areas – <strong>Application</strong>, Notification and Drilling Requirements. Including<br />
amendments March 1999, November 1999, November 2000 and July 2003 Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2000, Interim Directive 2000-03 – Harmonization<br />
of Waste Management and Memorandum of Understanding Between the Alberta Energy and<br />
Utilities Board and Alberta Environment. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1991, Interim Directive 91-03 – Heavy Oil/Oil<br />
Sands Operations. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1994, Information Letter 94-02 – Injection and<br />
Disposal Wells, Well Classifications Completion, Logging & Testing. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1996, Interim Directive 96-03 – Oilfield Waste<br />
Management Requirements for the \upstream Petroleum Industry. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2001. Interim Directive 2001 - 03 – Sulphur<br />
Recovery Guidelines for the Province of Alberta. Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 2000, Information Letter 89-05 – Water Recycle<br />
Guidelines and Water Use Information – Reporting for In Situ Oil Sands Facilities in Alberta.<br />
Calgary, AB.<br />
Energy Resources Conservation Board (ERCB), 1985, Information Letter 85-12 – Oil Sands<br />
Primary Production – Well Spacing, Primary Recovery Scheme Approvals. Calgary, AB.<br />
Enform, 2002. Heavy Oil and Oil Sands Production - Industry Recommended Practise <strong>Volume</strong> 3.<br />
Calgary, AB.<br />
Environment Canada, 2000. Canadian Environmental Protection Act. Ottawa, ON.<br />
Environment Canada, 2012. Canadian Environmental Assessment Act. Ottawa, ON.<br />
Environment Canada, 2010. Guide for Reporting to the National Pollutant Release Inventory<br />
(NPRI) 2010. Ottawa, ON.<br />
Environment Canada, 2012. National Climate Data and Information Archive. Canadian Climate<br />
Normals or Averages. Ottawa, ON.<br />
Federation of Alberta Naturalists, 2007. The Atlas of Breeding Birds of Alberta – A Second Look.<br />
Gregorich, E.G., Turchenek, L.W., Carter, M.R., and Angers, D.A (eds). 2001. Soil and<br />
Environmental Science Dictionary. CRC Press, Boca Raton. 577 pp.<br />
Government of Alberta, 2011, Alberta Land Stewardship Act. Edmonton, AB<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 249
Government of Alberta, 2010. Alberta Tier One Soil and Groundwater Remediation Guidelines.<br />
Edmonton, AB<br />
Government of Alberta, 2010. Alberta Tier Two Soil and Groundwater Remediation Guidelines.<br />
Edmonton, AB<br />
Government of Alberta, 2012b. Fisheries and Wildlife Management Information System.<br />
Edmonton, AB<br />
Government of Alberta, 2000. Forest and Prairie Protection Act – F19. Edmonton, AB<br />
Government of Alberta, 2007. Forest and Prairie Protection Regulations 135/72. Edmonton, AB<br />
Government of Alberta, 2012. Lower Athabasca Regional Plan. Edmonton, AB<br />
Government of Alberta, 2012. Lower Athabasca Region Air Quality Management Framework for<br />
Nitrogen Dioxide (NO2) and Sulphur Dioxide (SO2). Edmonton, AB<br />
Government of Alberta, 2012. Lower Athabasca Region Groundwater Quality Management<br />
Framework. Edmonton, AB<br />
Government of Alberta, 2012. Lower Athabasca Region Surface Water Quality Management<br />
Framework. Edmonton, AB<br />
Government of Alberta, 2000. Municipal Government Act. Edmonton, AB<br />
Government of Alberta, 2000. Occupational Health and Safety Act. Edmonton, AB<br />
Government of Alberta, 2003. Occupational Health and Safety Regulations 62/2003 Edmonton,<br />
AB.<br />
Government of Alberta, 2009. Occupational Health and Safety Code. Edmonton, AB<br />
Government of Alberta, 2010. Weed Control Act. Edmonton, AB<br />
Government of Alberta, 2010. Weed Control Act: Weed Control Regulation (AR 19/2010).<br />
Edmonton, AB<br />
Government of Alberta, 2009. Wilderness Areas, Ecological Reserves, Natural Areas and<br />
Heritage Rangelands Act W-9. Edmonton, AB<br />
Government of Alberta, 2000 W-10. Wildlife Act. Edmonton, AB<br />
Government of Alberta,1997. Wildlife Regulation 143. Edmonton, AB<br />
Government of Canada, 2010. National Building Code. Ottawa, ON.<br />
Government of Canada, 2010. National Fire Code. Ottawa, ON.<br />
Government of Canada, 2002. Species at Risk Act. Schedule 1. Ottawa, ON.<br />
Government of Canada, 1982. The Constitution Act. Ottawa, ON.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 250
Hamilton, W.N., Price M.C., and Langenburg C.W. (compilers). 1999. "Geological Map of<br />
Alberta. Alberta Geological Survey, Alberta Energy and Utilities Board, Map No. 236."<br />
Halsey L.A., Vitt D.H., Beilman D., Crow S., Mehelcic S. and R. Wells, 2003. Alberta Wetland<br />
Inventory Classification System Version 2.0. Alberta Sustainable Resource Development.<br />
Edmonton, AB<br />
Husky Oil Operations Ltd., 2003. Tucker <strong>Thermal</strong> Development <strong>Project</strong>, Joint application to<br />
Alberta Environment and the ERCB.<br />
Jiang, Q., Thornton, B., Houston, J.R., Spence, S., 2009. Review of <strong>Thermal</strong> Recovery<br />
Technologies for the Clearwater and Lower Grand Rapids Formations in the Cold Lake Area in<br />
Alberta. Canadian International Petroleum Conference (ICIP) 2009, Calgary, AB<br />
Lakeland Industry and Community Association, 2007. Land Systems and Soil Sensitivity to Acid<br />
Input in the LICA Area (Map), Edmonton, AB<br />
Lakeland Industry and Community Association, 2007. Exploratory Potential of Acidification<br />
Impacts on Soils and surface Water Within the LICA AREA. Edmonton, AB.<br />
Lancaster J. 2000. ANCP Guidelines for Rare Plant Surveys. Alberta Native Plant Council,<br />
Edmonton, AB.<br />
Lee PG, Hanneman, M., 2009. Conservation Priorities for the Lower Athabasca Region, Alberta.<br />
Prepared for: Alberta Wilderness Association, Canadian Parks and Wilderness Society (Northern<br />
Alberta Chapter), Federation of Alberta Naturalists, Keepers of the Athabasca, and Pembina<br />
Institute. Global Forest Watch Canada<br />
Marsic, S., Roadarmel W., Machovoe, M., Davis, E., 2011. Improving Reservoir Monitoring in<br />
EOR Using Microdeformation-Based Technologies. Presented to the SPE conference,<br />
Maracaibo, Venezuela.<br />
Municipality of Bonnyville #87, 2006. Crane Lake Area Structure Plan<br />
Municipality of Bonnyville #87, 2005. "Land Use Bylaw".<br />
Native Plant Working Group, 2001. Native Plant Revegetation Guidelines for Alberta (H. Sinton-<br />
Gerling, Editor), Alberta Agriculture, Food And Rural Development and Alberta Environment.<br />
Natural Regions Committee, 2006. Natural Regions and Sub-regions of Alberta. Compiled by D.J.<br />
Downing and W.W. Pettapiece. Government of Alberta Pub. T/852.<br />
Pedocan Land Evaluation Ltd., 1993. Soil Series Information for Reclamation Planning in Alberta.<br />
Alberta Conservation and Reclamation Council Report No. RRTAC 93-7. ISBN 0-7732-6041-2.<br />
Various pages.<br />
Pedosphere.ca., 2012. Bulk Density Calculator based on the Canadian Texture Triangle.<br />
www.pedosphere.ca<br />
Soil Classification Working Group,1998. The Canadian System of Soil Classification. Agric. And<br />
Agri-Food Can. Publ. 1646 (Revised).<br />
The Weather Network, 2012. Cold Lake AB Station: Overview: Temperature, Precipitation.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 251
United States Environmental Protection Agency. Emission Factors and AP-42, Compilation of Air<br />
Pollutant Emission Factors, Chapter 1.4: Natural Gas Combustion, July, 1998; Chapter 3.3:<br />
Gasoline and Diesel Industrial Engines, October, 1996; chapter 13.5 Industrial Flares,<br />
September, 1991<br />
All references contained herein include amendments to cited works to November 30, 2012.<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 252
11 Acronyms and Abbreviations<br />
2D<br />
LIST OF ACRONYMS<br />
Two dimensional<br />
3D Three Dimensional<br />
AAAQO Alberta Ambient Air Quality Objectives<br />
AAAGO Alberta Ambient Air Guidelines and Objectives<br />
ABMI Alberta Biodiversity Monitoring Institute<br />
AESRD Alberta Environment and Sustainable Resources<br />
ACIMS Alberta Conservation Information Management System<br />
ALMS Alberta Lake Management Society<br />
ANPC Alberta Native Plant Council<br />
API American Petroleum Institute<br />
ASIC Alberta Soil Information Council<br />
ASRD Alberta Sustainable Resources Development<br />
ATV All-Terrain Vehicle<br />
AUC Alberta Utilities Commission<br />
BATEA Best Available Technology Economically Achievable<br />
bbl Barrels<br />
bbl/day Barrels per day<br />
BFW Boiler Feed Water<br />
BHA Bottom Hole Assembly<br />
bopd Barrels oil per day<br />
BS & W Basic Sediments and Water<br />
C&R Conservation and Reclamation<br />
Ca Calcium<br />
CaCl2 Calcium Chloride<br />
CEC Cation Exchange Capacity<br />
CERP Corporate Emergency Response Plan<br />
CCME Canadian Council Of Ministers of the Environment<br />
CEMA Cumulative Environmental Management Association<br />
CL SRIRP Cold Lake Sub Regional Integrated Resources Plan<br />
CLASP Crane Lake Area Structure Plan<br />
CLBRB Cold Lake Beaver River Basin<br />
CO2 Carbon dioxide<br />
COSEWIC Committee on the Status of Endangered Wildlife in Canada<br />
cP Centipoise<br />
CPF Central Processing Facility<br />
CSOR Cumulative Steam Oil Ratio<br />
CSS Cyclic Steam Stimulation<br />
cST Centistokes<br />
DA Development Area<br />
DCS Distributed Control System<br />
DOW Dangerous Oilfield Waste<br />
EC Electrical Conductivity<br />
EC Electrical Conductivity<br />
ESP Electric Submersible Pump<br />
EPEA Environmental Protection and Enhancement Act<br />
ERCB Energy Resources Conservation Board<br />
ERP Emergency Response Plan<br />
ESRD Environment and Sustainable Resource Development<br />
FWKO Free Water Knock Out<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 253
FWMIS Fish and Wildlife Management Information System<br />
GOR Gas-Oil Ratio<br />
GSA Geological Study Area<br />
IGF Induced Gas floatation<br />
GJ/day Gigajoules/day<br />
Ha Hectare<br />
H2S Hydrogen Sulphide<br />
HPV High Pressure Vapours<br />
Hwy Highway<br />
ID Interim Directive<br />
IFR IN-Field Referencing<br />
IOL Imperial Oil Limited<br />
IRP Industry Recommended Practice<br />
ISOR Instant Steam to Oil Ratio<br />
Kg/day Kilograms per day<br />
kPa Kilopascals<br />
KOP Kick Off Point<br />
kV Kilo Volt<br />
kW Kilowatt<br />
LACT Lease Automated Custody Transfer<br />
LARP Lower Athabasca Regional Plan<br />
LCC Land Capability Classification System<br />
LEL Lower Exposure Level<br />
LFN Low Frequency Noise<br />
LICA Lakeland Industry Community Association<br />
LOC License Of Occupation<br />
LSA Local Study Area<br />
LWD Logging While Drilling<br />
mD Meters Depth<br />
m 3 /day Meters cubed per day<br />
MARP Measurement, Accounting and Reporting Plan<br />
MagOx Magnesium oxide<br />
MD Municipal District<br />
MOP Maximum Operating Pressure<br />
MSL Mineral Surface Lease<br />
MSA Multi Station Analysis<br />
MW Mega Watts<br />
MWD Measurement While Drilling<br />
NDOW Non Dangerous Oilfield Waste<br />
NOx Nitrogen Oxides<br />
NO2 Nitrogen Dioxide<br />
NPS Nominal Pipe Size<br />
OBIP Original Bitumen in Place<br />
OOIP Original Oil in Place<br />
ORF Oil Removal Filters<br />
OSCA Oil Sands Conservation Act<br />
OWC Oil Water Contact<br />
PA <strong>Project</strong> Area<br />
PDA <strong>Project</strong> Development Area<br />
P&NG Petroleum and Natural Gas<br />
PCP Progressive Cavity Pump<br />
PDA/C&R Pre-Disturbance Assessment/Conservation & Reclamation Plan<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 254
PM Inhalable Particulate Matter<br />
ppm Parts per million<br />
PSV Pressure Safety Valve<br />
RDA Resource Development Area<br />
RFMA Registered Forestry Management Agreement<br />
RGS Regional Geological Study<br />
RoW Right of Way<br />
RSS Rotary Steerable Systems<br />
SAC Strong Acid Cation<br />
SAGD Steam Assisted Gravity Drainage<br />
SAR Sodium Absorption Ratio<br />
SARA Species at Risk Act<br />
s/l Seconds per liter<br />
SO2 Sulphur Dioxide<br />
SOR Steam to Oil Ratio<br />
sm 3 /day Standard cubic meters per day<br />
t/day Tonnes/day<br />
TDG Transportation of Dangerous Goods<br />
TDS Total Dissolved Solids<br />
TN Total Nitrogen<br />
TOC Total Organic Carbon<br />
TVD Total Vertical Depth<br />
TD Total Depth<br />
UPS Uninterruptible Power Supply<br />
VAC Volts Alternating Current<br />
VAD Volts Direct Current<br />
VOC Volatile Organic Compounds<br />
VRU Vapour Recovery Unit<br />
WHMIS Workplace Hazardous Materials Information System<br />
WSR Water to Steam Ratio<br />
<strong>Sage</strong> <strong>Pilot</strong> <strong>Application</strong> Page 255
contact<br />
for more information or to provide us your views or input on the<br />
proposed <strong>Sage</strong> <strong>Thermal</strong> <strong>Pilot</strong> <strong>Project</strong> or on any aspect of our operations<br />
please contact Kathryn Lundy at:<br />
Telephone: 403.265.1244 x 221<br />
Facsimilie: 403.265.1204<br />
Email: klundy@birchwoodresources.ca<br />
Website: www.birchwoodresources.ca<br />
Mail: Suite 1200, 630 - 6th Ave SW<br />
Calgary, Alberta T2P 0S8
suite 1200, 630 - 6th avenue south west, calgary alberta t2P 0s8<br />
P. 403-265-1244 F. 403-265-1204 www.birchwoodresources.ca