Sage Thermal Pilot Project Application Volume 1 December

SAGE
THERMAL PILOT PROJECT
ERCB & ESRD JOINT APPLICATION DECEMBER 2012
VOLUME 1 – APPLICATION

Birchwood Resources Inc.
Sage Pilot Application
December 2012
Contents
1 Sage Introduction and Overview ............................................................................................. 9
1.0 Introduction .................................................................................................................. 9
1.1 Project Proponent ........................................................................................................ 9
1.2 Project Background .....................................................................................................10
1.3 Guides to Application ..................................................................................................11
Volume 1: ERCB & Alberta ESRD Joint Application ...........................................................11
Volume 2: Consultant Reports ...........................................................................................11
1.4 Purpose ......................................................................................................................11
1.4.1 Project Need ........................................................................................................11
1.5 Location ......................................................................................................................12
1.5.1 Project Development Area ...................................................................................12
1.5.2 Resource Development Area ...............................................................................12
1.6 Project Overview .........................................................................................................12
1.7 Project Facilities ..........................................................................................................13
Table 1.7-1 Summary of Project Components ....................................................................13
1.7.1 Minimization of Land Disturbance ........................................................................13
1.8 Project Development Schedule ...................................................................................14
Table 1.8-1 Development Schedule Pending Regulatory Approval ....................................14
1.9 Regional Setting .........................................................................................................15
1.10 Environment, Health and Safety Program ...................................................................15
Figure 1.1-1 Birchwood Sage Project Map ..........................................................................16
Figure 1.1-2 Birchwood Sage Regional Project Map ...........................................................17
Figure 1.2-1 Regional Map ..................................................................................................18
Figure 1.2-2 Regional Satellite image ..................................................................................19
Figure 1.2-3 Local Aerial Image ...........................................................................................20
Figure 1.5-1 Project Aerial Photo Mosaic ............................................................................21
Figure 1.5-2 Aerial Photo Showing Existing Development and Pilot Site .............................22
2 Economics & Land Use ..........................................................................................................23
2.1 Economics .......................................................................................................................23
2.1.1 Capital and Operating Costs ................................................................................23
2.1.2 Taxes and Crown Royalty ....................................................................................23
2.1.3 Benefit Cost Analysis ...........................................................................................23
2.1.4 Marketing Arrangements ......................................................................................23
2.1.5 Commercial Viability ............................................................................................24
2.2 Socio-Economics ........................................................................................................24
2.2.1 Employment and Procurement .............................................................................24
Table 2.2.1-1 Employment Positions ..................................................................................24
2.3 Traffic and Access ......................................................................................................25
2.4 Integration with Other Land Uses ................................................................................25
2.4.1 Timber/Forestry ..................................................................................................26
2.4.2 Recreational Uses...............................................................................................26
2.4.3 Agriculture ..........................................................................................................26
2.4.4 Trapping .............................................................................................................26
2.4.5 Petroleum and Natural Gas Rights ......................................................................26
2.4.6 Oilsands Rights ...................................................................................................27
2.4.7 Ecological Resources .........................................................................................27
2.4.8 Wildlife ................................................................................................................27
2.4.9 Vegetation ..........................................................................................................27
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2.4.10 Historical Resources ...........................................................................................27
2.4.11 Wetlands .............................................................................................................28
2.4.12 Surface ownership ............................................................................................28
Figure 2.3-1 Access Sketch .................................................................................................29
Figure 2.4.5 PNG Lease Holders Map .................................................................................29
Figure 2.4.6 Oilsands Lease Holders Map ..........................................................................31
Figure 2.3.10A 1950 - Historical Aerial Photo ......................................................................32
Figure 2.3.10B 1977 - Historical Aerial Photo ........................................................................33
Figure 2.3.10C 1980 - Historical Aerial Photo ........................................................................34
Figure 2.3.10D 1988 - Historical Aerial Photo ........................................................................35
Figure 2.3.11 Wetlands Mapping & Potential Plant Locations .............................................36
Figure 2.4.12 Surface Ownership .......................................................................................37
3 Regulatory Approvals .............................................................................................................38
3.1 Existing Approvals ......................................................................................................38
3.2 Application for Approval ..............................................................................................38
3.2.1 ERCB Approvals Requested .....................................................................................38
3.2.2 ESRD Approvals Requested .....................................................................................39
3.4 Additional Approvals Associated With the Application. ................................................39
3.5 ERCB Application Checklist ........................................................................................39
3.6 EPEA Application Checklist ........................................................................................39
Appendix 3.5 ERCB Application Checklist .................................................................................40
Appendix 3.6 EPEA Application Checklist .................................................................................42
4 Geology .................................................................................................................................44
4.1 Area Description .............................................................................................................44
4.1.1 Resource Development Area ......................................................................................44
4.1.2 Project Development Area ..........................................................................................44
4.1.3 Geological Study Area ................................................................................................44
4.2 Reservoir Geology ..........................................................................................................44
4.2.1 Regional Stratigraphy .................................................................................................44
4.2.1.1 Granite Wash Formation (Cambrian) ................................................................44
4.2.1.2 Elk Point Group (Devonian) ..............................................................................44
4.2.1.3 Beaverhill Lake Group (Upper Devonian) .........................................................45
4.2.1.4 Mannville Group (Lower Cretaceous) ...............................................................45
4.2.1.4A McMurray Formation .....................................................................................45
4.2.1.4B Clearwater Formation ...................................................................................45
4.2.1.4C Grand Rapids Formation ...............................................................................46
4.2.1.5 Colorado Group Lea Park Formation (Upper Cretaceous) ................................46
4.2.1.6 Overburden (Quaternary) .................................................................................46
4.2.2 Well Control ................................................................................................................46
4.2.2.1 Seismic Data .............................................................................................................47
4.2.3 Geological Description of the Clearwater Formation ..................................................47
4.2.3.1 Clearwater Net Pay ..........................................................................................48
4.2.3.2 Clearwater Bottom Water .................................................................................48
4.2.3.3 Clearwater Top Gas .........................................................................................48
4.2.3.4 Caprock and Seal Integrity ...............................................................................48
4.4 Injection/Fall-off (“mini-frac”) Testing Results ..............................................................49
Table 4.4.1 Clearwater Shale Closure Pressure Regional Value ........................................49
Table 4.4.2 Summary of Closure Pressures per Zone Tested ............................................49
Figure 4.1.1 Resource Development Area (“RDA”) .............................................................50
Figure 4.1.2 Project Development Area (PDA) & Wells .......................................................51
Figure 4.1.3 Geological Study Area .....................................................................................52
Figure 4.2.1 Cold Lake Stratigraphy ....................................................................................53
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Figure 4.2.1.4A Schematic SW-NE cross-section Clearwater Formation ...............................54
Figure 4.2.1.4B Regional Cross Section Clearwater Formation .............................................55
Figure 4.2.1.4C Birchwood Clearwater Type Log ..................................................................56
Figure 4.2.2A Well Control Map ..........................................................................................57
Figure 4.2.2B Cross Section Birchwood Lease - Clearwater Formation ..............................58
Figure 4.2.2C Formation Imaging logs (FMI) - Clearwater Formation Interval .....................59
Figure 4.2.2D Log Analysis .................................................................................................60
Figure 4.2.2E Summary Core Data and Photos 100/03-02-064-04W400 ...........................61
Figure 4.2.2.1A Depth converted time structure map top of Clearwater Formation .................62
Figure 4.2.2.1B Interpreted Seismic Data ..............................................................................63
Figure 4.2.3B Structure on the Top of the Clearwater Formation ........................................64
Figure 4.2.3.1 Clearwater Net Pay .......................................................................................67
Figure 4.2.3.1B Clearwater Net Pay ......................................................................................68
Figure 4.2.3.2 Structure Clearwater Bottom Water ..............................................................69
Figure 4.2.3.4 Isopach Map Clearwater Formation Capping Shale ......................................70
5 Reservoir Recovery Process ..................................................................................................71
5.1 Reservoir Properties ...................................................................................................71
5.1 Table Sage Typical Reservoir Properties ....................................................................71
5.1.1 Recovery Process Selection ................................................................................71
5.1.2 Recovery Process Description .............................................................................71
5.2 SAGD Start-Up Phase ................................................................................................72
5.2.1 Warm Up/Circulating (60-90 days) .......................................................................72
5.2.2 Transition (30-90 days) ........................................................................................73
5.3 Steady State SAGD Operating Phase .........................................................................73
5.3.1 Operating Pressures ............................................................................................74
5.3.2 Maximum Operating Pressure (“MOP”) ................................................................74
5.3.3 Potential Follow-up Processes for Improved Recovery ........................................74
5.4 Reservoir Monitoring ...................................................................................................75
5.4.1 Temperature Measurement ..................................................................................75
5.4.2 Gas Blanket Pressure Measurement ...................................................................75
5.4.3 Micro-deformation Monitoring ..............................................................................75
5.4.4 Observation Wells ................................................................................................75
5.5 Recovery and Original Oil In Place .............................................................................76
5.5.1 Original Oil in Place (“OOIP”) ...............................................................................76
5.5-1 Original Oil In Place Summary Table ........................................................................76
5.5.1.1 Gas Reserves ........................................................................................................76
5.5.2 Drilling Constraints and By-passed Pay ...............................................................76
5.5.3 Drainage Pattern Layouts ....................................................................................77
5.5.4 Well Length and Spacing .....................................................................................77
5.6 Expected Well Performance ........................................................................................77
5.6.1 Typical SAGD Well-Pair Performance ..................................................................78
5.6.2 SAGD Well-Pair A1 Expected Performance Data - 1,053m Effective length ........78
5.6.3 SAGD Well-Pair A10 Expected Performance Data - 603m Effective length .........78
5.6.4 SAGD Well-Pairs Expected Pilot Performance Data ............................................79
5.7 Results of Numerical Simulation Studies ........................................................................79
5.7.1 Modeling Approach ..............................................................................................79
5.7.2 Model Production Performance ............................................................................80
Figure 5.5.3-1 CPF & SAGD Well Pair Layout .....................................................................81
Figure 5.5.3-2 SAGD Well Pair Layout & Net Pay ................................................................82
Figure 5.5.3-2 Future Development SAGD Well Pair Layout ................................................83
Figure 5.7.1 Grid Layout 200x200x40 ..................................................................................84
Figure 5.7.2 N - S Cross Section Showing Water Saturation and Horizontal Well Locations 85
Figure 5.7.3 E - W Cross Section Showing Water Saturation and Horizontal Well Locations 86
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Figure 5.7.4 Refined Grid East‐West Cross‐Section Water Saturation .................................87
Figure 5.7.5 Gas-Liquid Relative Permeability ......................................................................88
Figure 5.7.5 Water-Oil Relative Permeability ........................................................................88
Figure 5.7.6 Predicted Production Rates ..............................................................................89
Figure 5.7.7 Saturation and Temperature at 1.0 year X Section ...........................................90
Figure 5.7.8 Saturation and Temperature at 1.0 Year Well Length .......................................91
Figure 5.7.9 Saturation and Temperature at 3.6 years X Section .........................................92
Figure 5.7.10 Saturation and Temperature at 8.5 years X Section ......................................93
Figure 5.7.11 Predicted Cumulative Production ..................................................................94
Appendix 5.7.A1 Well Properties 100030206404W400 .........................................................95
Appendix 5.7.A2 Well Properties 100060206404W400 .........................................................96
Appendix 5.7.A3 Well Properties 100010306404W400 .........................................................97
Appendix 5.7.A4 Well Properties 100050106404W400 .........................................................98
Appendix 5.7.A5 Well Properties 102062606304W400 .........................................................99
Appendix 5.7.A6 Well Properties 102062406304W400 ....................................................... 100
Appendix 5.7.B1 Rock Grid Properties ................................................................................ 101
Appendix 5.7.B2 Measured Viscosity and Density ............................................................... 101
Appendix 5.7.B3 Extrapolated Viscosity used in Model ....................................................... 101
6 Drilling and Completions ...................................................................................................... 102
6.1 Overview ................................................................................................................... 102
6.2 Well Pad Layout ........................................................................................................ 103
6.2.1 Drilling SAGD Well Pairs .................................................................................... 103
6.2.2 Surface Section ................................................................................................. 104
6.2.3 Intermediate or Build Section ............................................................................. 104
6.2.4 Horizontal Section .............................................................................................. 105
6.3 Completions .............................................................................................................. 105
6.3.1 Production Well Completion ............................................................................... 105
6.3.2 Injection Well Completion................................................................................... 106
6.4 Cementing Program .............................................................................................. 106
6.4.1 Mud System ....................................................................................................... 106
6.4.2 Float Equipment ................................................................................................. 107
6.4.3 Cement and Cementing ..................................................................................... 107
6.5 Casing Failure Monitoring Program ....................................................................... 107
6.6 Vertical Wells ............................................................................................................ 108
6.6.1 Source Water Wells ........................................................................................... 108
6.6.2 Observation Wells .............................................................................................. 109
6.6.3 Disposal Well(s) ................................................................................................. 109
6.6.4 Abandonment Status of Wells Within the RDA ................................................... 109
6.5 Drilling Waste Management ...................................................................................... 109
Figure 6.2-1 Well Configuration and Spacing ..................................................................... 110
Figure 6.2-2 3D Model of Well Configuration ..................................................................... 111
Figure 6.2.1-1 Producer Wellhead ..................................................................................... 112
Figure 6.2.1-1B Producer Wellhead ..................................................................................... 113
Figure 6.2.1-2 Injector Wellhead ........................................................................................ 114
Figure 6.2.1-2B Injector Wellhead ....................................................................................... 115
Figure 6.3.1 Producer Well Schematic .............................................................................. 116
Figure 6.3.2 Injector Well Schematic ................................................................................. 117
Figure 6.6.1-1 Source Well: Utility Water Well Schematic .................................................. 118
Figure 6.6.1-2 Source Well: Brackish Water Well Schematic ............................................ 119
Figure 6.6.2-1 Observation Well Schematic ....................................................................... 120
Figure 6.6.3-1 Disposal Well Schematic ........................................................................... 121
Figure 6.6.4-1 Details of Existing Wells .............................................................................. 122
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7 Facilities ............................................................................................................................... 123
7.1 Overview ....................................................................................................................... 123
7.1.1 Central Processing Facility ................................................................................. 123
7.1.2 Well Pad Facility ................................................................................................ 124
7.1.3 Design Flow Rates ............................................................................................. 124
7.2 Steam Generation and Water Treatment .................................................................. 125
7.2.1 Steam Generation ................................................................................................... 125
7.2.2 Project Make-up and Boiler Feed Water Sources .............................................. 125
Table 7.2.2-1 Summary Water Sources and Uses at Maximum Capacity ..................... 126
7.2.3 Produced Water Treatment Process .................................................................. 126
7.2.3.1 Evaporation .................................................................................................... 127
7.2.3.2 Boiler Feed Water .......................................................................................... 127
7.2.4 Produced Water Disposal .................................................................................. 128
7.3 Bitumen Treatment ................................................................................................... 128
7.3.1 De-Oiling ........................................................................................................... 129
7.3.1.1 Skim Tanks .................................................................................................... 129
7.3.1.2 Induced Gas Flotation .................................................................................... 129
7.3.1.3 Oil Removal Filters ......................................................................................... 130
7.3.2 De-Sanding ........................................................................................................ 130
7.3.3 Sales Oil Management and LACT ...................................................................... 130
7.3.5 Slop Oil System ................................................................................................. 131
7.4 Inlet Cooling and Separation ..................................................................................... 132
7.5 Fuel and Produced Gas Recovery System ............................................................... 132
7.5.1 Sulfur Production and Recovery .............................................................................. 133
Table 7.5.1-1 Sulphur Production and Recovery Criteria .................................................. 133
7.6 Vapour Recovery and Flare Systems ........................................................................ 133
Table 7.6.1 Vapour Sources ............................................................................................ 134
7.7 Energy & Heat and Material Balances....................................................................... 134
7.7.1 Energy Balance .................................................................................................... 134
Table 7.7.1-1 Energy Balance .......................................................................................... 135
Table 7.7.2 Heating Values .............................................................................................. 135
7.8 MARP Conceptual Plan ............................................................................................ 135
7.8.1 Objectives .......................................................................................................... 135
7.8.2 Process Flow Metering Schematic ..................................................................... 136
7.8.3 Boundary Streams ............................................................................................. 137
7.8.4 Project Wells ...................................................................................................... 137
7.8.5 Project Meters .................................................................................................... 137
7.8.6 Facility Tankage ................................................................................................. 138
Table 7.8.6-1 Tank Listing ................................................................................................ 138
7.8.7 Project Dispositions and Receipts ...................................................................... 139
Table 7.8.7-1 Production Battery Disposition and Receipt Points ..................................... 139
7.9 Chemical Use ........................................................................................................... 139
7.9.1 Produced Water Treatment Stream ................................................................... 139
7.9.1.2 Feed Water .................................................................................................... 139
7.9.1.3 Boiler Feed Water .......................................................................................... 140
7.9.2 Bitumen Treatment ............................................................................................ 140
7.9.2.1 Free Water Knockout Tank ............................................................................. 140
7.9.2.5 Induced Gas Flotation .................................................................................... 140
7.9.2.5 Sales Oil ......................................................................................................... 141
7.10 Services and Utilities ................................................................................................. 141
7.10.1 Field Office Facility and Camps......................................................................... 141
7.10.2 Highways and Rights of Way ............................................................................ 141
7.10.3 Utilities .............................................................................................................. 141
7.10.3.1 Electrical Power ............................................................................................. 141
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7.10.3.2 Natural Gas .................................................................................................... 141
7.10.3.3 Pipelines ........................................................................................................ 142
7.10.3.3.1 Diluent Pipeline ........................................................................................... 142
7.10.3.3.2 Sales Pipeline ............................................................................................. 142
7.11 Health, Safety and Environmental Controls ............................................................... 142
7.11.1 Facility Emergency Response Plan ................................................................... 142
7.11.2 Fire Control Plan ............................................................................................... 143
7.11.2.1 Wildfire Prevention ......................................................................................... 143
7.11.2.2 Facilities Fire Protection ................................................................................. 143
7.11.3 Air Emissions Management ............................................................................ 143
7.11.4 Noise Emissions Management ....................................................................... 144
7.11.5 Spill Control and Leak Detection ..................................................................... 144
7.11.6 Surface Water Management ........................................................................... 144
7.12 Chemical and Waste Management ........................................................................... 144
7.12.1 Chemical Management ..................................................................................... 144
Table 7.12.1-1 Chemical Summary .................................................................................. 145
7.12.2 Waste Management .......................................................................................... 146
Figure 7.1.1 CPF and Well Pad Plot Plan .......................................................................... 147
Figure 7.1.2 3D Model of CPF and Well Pad ..................................................................... 148
Figure 7.2.2 Process Flowsheet 200-1 Wellpad ................................................................ 149
Figure 7.2.2-A Block Flow Diagram - De-Oiling, Water treatment and Steam Generation .. 150
Figure 7.2.2-B Water Balance - De-Oiling, Water treatment and Steam Generation ........... 151
Figure 7.2.1-1 Process Flowsheet 100-8 Steam Generation .............................................. 152
Figure 7.2.2-1 Process Flowsheet 100-6 Water Treatment ............................................... 153
Figure 7.2.3-1A Process Flowsheet 100-7A Water Treatment .............................................. 154
Figure 7.2.3-1B Process Flowsheet 100-7B Water Treatment .............................................. 155
Figure 7.2.3-2 Process Flowsheet 100-1 Inlet Process ...................................................... 156
Figure 7.3-1 Process Flowsheet 100-2 Bitumen Treating ................................................ 157
Figure 7.3.1-1 Process Flowsheet 100-4 De-Oiling ............................................................ 158
Figure 7.3.2-1 Process Flowsheet 100-5 Desand and Slop Oil .......................................... 159
Figure 7.3.3-1 Process Flowsheet 100-3 Bitumen Storage ................................................ 160
Figure 7.4-1 Process Flowsheet 100-9 Glycol System..................................................... 161
Figure 7.5-1 Process Flowsheet 100-10 Utilities Instrument Air/Fuel Gas ....................... 162
Figure 7.6-1 Process Flowsheet 100-11 Vapor Recovery ............................................... 163
Figure 7.8.2-1 Simplified MARP Schematic ....................................................................... 164
Appendix 7.1 Equipment List ............................................................................................ 165
Appendix 7.2 Heat and Material Balance .......................................................................... 169
Appendix 7.3 Waste Management Table .......................................................................... 182
8 Environmental Review and Baseline Assessment ................................................................ 186
8.1 Overview ................................................................................................................... 186
8.2 Historical Resources ................................................................................................. 187
8.2.1 Aerial Photograph Review.................................................................................. 187
8.2.2 Land Use ........................................................................................................... 187
8.2.2 Traditional Land Use .......................................................................................... 187
8.3 Air Resources ........................................................................................................... 188
8.3.1 Climate and Meteorology ................................................................................... 188
Table 8.3.1-1 Climate and Meterologic Data .................................................................... 188
8.3.2 Air Quality .......................................................................................................... 189
Table 8.3.2-1 Emission Sources and Physical Stack Parameters .................................... 189
Table 8.3.2-2 Dispersion Model Predictions ..................................................................... 190
Table 8.3.2-3 Emission Rates Used in Dispersion Modeling in (g/s) ................................. 190
8.3.2.1 Fugitive Emissions ......................................................................................... 190
8.3.2.2 Air Monitoring ................................................................................................. 190
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8.4 Noise Control ............................................................................................................ 191
Table 8.4-1 Predicted Noise Levels for the Project Application Case ............................... 191
8.4.2 Low Frequency Noise ........................................................................................ 191
Table 8.4-2 Low Frequency Noise Assessment Results ................................................... 192
8.5 Water Resources ...................................................................................................... 192
8.5.1 Surface Water .................................................................................................... 192
8.5.2 Surficial Geology and Shallow Aquifers (Hydrostratigraphic Units) ..................... 193
Table 8.5.2-1 Shallow Aquifer Geochemical Characteristics ............................................ 193
8.5.3 Bedrock Geology and Aquifers .......................................................................... 194
8.5.3.1 Brackish Water Resources ............................................................................. 194
8.5.3.2 Brackish Water Suitability ............................................................................... 194
8.5.4 Fresh Water Resources ..................................................................................... 195
8.5.4.1 Surface and Shallow Aquifer Use ................................................................... 195
Table 8.5.4-1 Groundwater Allocation in the Cold Lake Beaver River Basin .................... 195
Table 8.5.4-2 Groundwater Allocation in the Cold Lake Beaver River Basin Including
Livestock/domestic and Domestic Usage 2003 ................................................................ 195
8.5.5 Water Balance ................................................................................................... 196
8.5.6 Birchwood Water Usage .................................................................................... 196
8.5.7 Water Disposal .................................................................................................. 196
8.6 Soil and Terrain ........................................................................................................ 196
8.6.1 Surficial Geology and Landforms ....................................................................... 197
8.6.2 Soil Structure ..................................................................................................... 197
Table 8.6.2-1 Soil Types and Distribution in the Proposed Development Area ................. 197
8.6.3 Land Capability Ratings ..................................................................................... 198
Table 8.6.3-1 Land Capability Rating – Agricultural Crops ............................................... 198
8.6.4 Reclamation Suitability Rating ........................................................................... 198
Table 8.6.4-1 Reclamation Suitability Ratings for the Well and Facility Pad ..................... 199
8.7 Vegetation ................................................................................................................ 199
8.7.1 Methodology ...................................................................................................... 199
8.7.2 Ecosite Phases at the Proposed Project Development Area .............................. 200
8.7.3 Rare Plant and Plant Communities .................................................................... 204
8.7.4 Old Growth Forests ............................................................................................ 204
8.7.5 Summary of Potential Impacts and Mitigation Measures .................................... 204
8.7.5.1 Direct Vegetation Removal ............................................................................. 204
8.7.5.2 Impacts to Uncommon Vegetation .................................................................. 204
8.7.5.3 Soil Acidification ............................................................................................. 204
8.7.5.4 Introduced Plant Species Invasion ................................................................. 204
8.8 Wildlife Assessment .................................................................................................. 205
8.8.1 Methodology ...................................................................................................... 205
8.8.1.1 Wildlife Species Occurrence and Status ......................................................... 205
8.8.1.2 Wildlife Species of Management Concern ...................................................... 205
8.8.2 Wildlife Species Occurrence and Status ............................................................ 205
8.8.3 Species of Management Concern ...................................................................... 206
8.8.4 Summary of Potential Wildlife Impacts and Mitigation Measures........................ 206
8.8.4.1 Habitat Loss/Alteration ................................................................................... 206
8.8.4.2 Habitat Fragmentation .................................................................................... 206
8.8.4.3 Movement Obstruction ................................................................................... 206
8.8.4.4 Sensory Disturbance ...................................................................................... 207
8.8.4.5 Direct Mortality ............................................................................................... 208
8.9 Summary of Environmental Receptors and impact ratings ........................................ 209
8.10 Summary of Environmental Commitments ................................................................ 214
8.10.1 Air Monitoring..................................................................................................... 214
8.10.2 Noise ................................................................................................................. 214
8.10.3 Water ................................................................................................................. 214
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8.10.4 Vegetation ......................................................................................................... 214
8.10.5 Wildlife ............................................................................................................... 214
8.10.6 Emergency/Spill Response ................................................................................ 214
8.10.7 Participation in Area Research ........................................................................... 214
Figure 8.3.2-1 Maximum Predicted NO2 Contours for the 1-hour Averaging Period including
Ambient Background ............................................................................................................... 215
Figure 8.3.2-2 Maximum Predicted SO2 Contours for the 1-hour Averaging Period including
Ambient Background ............................................................................................................... 216
Figure 8.4-1 Noise Study Area and Receptor Locations .......................................................... 217
Figure 8.4-2 Predicted Nighttime Noise Levels........................................................................ 218
Figure 8.4-3 Relationships Between Everyday Sounds ........................................................... 219
Figure 8.5.3-1 Stratigraphic and hydrostratigraphic columns in the Cold Lake-Beaver River
Basin ....................................................................................................................................... 220
Figure 8.5.3-2 Location of the Project within the Beaver River Basin in Alberta....................... 221
Figure 8.5.3-3 Recharge and Discharge Areas in the Cold Lake-Beaver River Basin.............. 222
Figure 8.6.2-1 Soils Types and Locations ............................................................................... 223
Figure 8.7.2-1 Birchwood Study Area ...................................................................................... 224
Figure 8.7.2-2 Vegetation Cover Types ................................................................................... 225
Figure 8.7.2-3 Vegetation Plots .............................................................................................. 226
Figure 8.7.2-4 Rare Vascular Plant Survey Path ..................................................................... 227
9 Public and First Nations Consultation ................................................................................... 228
9.1 Overview ....................................................................................................................... 228
9.1.1 Goal of Consultation .......................................................................................... 228
9.1.2 Consultation Summary ....................................................................................... 228
9.2 Stakeholder Identification .......................................................................................... 229
9.3 Open House Summary ............................................................................................. 230
9.4 Stakeholder Comments and Responses ................................................................... 231
Table 9.4.1 Summary of Stakeholder Questions and Responses by Birchwood .............. 232
9.5 First Nation Consultation Framework ........................................................................ 237
9.5.1 First Nation Consultation Summary .................................................................... 238
9.5.1.1 Cold Lake First Nation .................................................................................... 238
9.5.1.2 Frog Lake First Nation .................................................................................... 238
9.5.1.3 Beaver Lake Cree Nation ............................................................................... 239
9.5.1.4 Kehewin Cree Nation ..................................................................................... 239
9.5.1.5 Heart Lake First Nation .................................................................................. 240
9.5.1.6 Whitefish – Goodfish First Nation ................................................................... 240
9.6 Meetings and Events ................................................................................................. 241
Table 9.6 List of Meetings and Events ............................................................................. 241
9.7 Birchwood Commitment to Consultation ................................................................... 243
10 References ................................................................................................................... 244
11 Acronyms and Abbreviations ........................................................................................ 253
Volume 2: Consultants Reports
CR1 – Hydrogeology
CR2 – Air Quality Modeling Report
CR3 – Noise impact Assessment
CR4 – Vegetation and Wildlife Assessment
CR5 – Soils Assessment
CR6 – Injection/Fall off testing results
CR7 – Conservation and Reclamation Plan
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1 Sage Introduction and Overview
1.0 Introduction
Birchwood Resources Inc. (“Birchwood”) is a privately owned Canadian energy company
operating in the Cold Lake Region of Alberta, Canada. This application is seeking approval to
construct, operate and reclaim the Sage Commercial Demonstration Pilot Project, a crude
bitumen recovery scheme that will utilize steam assisted gravity drainage (“SAGD”) technology
to produce bitumen at a rate of 795m 3 (5,000 barrels) per day. The life of the 10 well pair pilot
project is 5 years. Total Original Oil In Place (“OOIP”) in the Clearwater Formation is estimated
at 24,037 e3m3 (151 million barrels). Recoverable crude bitumen using SAGD recovery is
estimated to be up to 65%. The combined facility, well pad design and layout has incorporated
the potential for up to 36 well pairs to be drilled from the facility/well pad proposed herein, If the
project proves to be successful, the life of the project would be extended to at least 15 years.
Birchwood is proposing an in situ recovery operation that reduces environmental impacts, and
has taken additional steps to design the most efficient facility possible. Significant attention has
been put towards mitigating noise and odor concerns, utilizing brackish makeup water,
generating high produced water recycle ratios and managing ground water protection. The
information gathered from the pilot will allow an efficient and controlled development of the
provincial resource and facilitate continuous improvement at Sage.
Birchwood has actively engaged stakeholders to explain the project and to understand their
concerns. A Summary of Stakeholder Consultation results conducted to date is included as part
of this application in Section 9. Stakeholder consultation and communication will continue
throughout the life of the proposed project.
1.1 Project Proponent
Birchwood Resources Inc. is the project proponent. Birchwood owns a 100% working interest
oilsands leases located in the South half of Section 1, all of Section 2 and SE quarter of Section
3 in Township 064, Range 4 West of the 4th Meridian. The Resource Development Area
includes Section 2 and SE 3 Township 064, Range 4 West of the 4th Meridian. (Figure 1.1-1)
The legal name and address of the applicant for the project is:
Birchwood Resources Inc.
Suite 1200, 630 6 th Ave S.W.
Calgary, AB
T2P 0S8
Correspondence concerning this application should be directed to the above office address to
the attention of:
Kathryn Lundy
Manager, Safety Environment and Regulatory Compliance
Phone: 403-265-1244, ext. 221 Fax: 403 -265-1204
Email: klundy@birchwoodresources.ca
Authorization for submission:
“Original signed by”
Alex Lemmens P.Eng
President & CEO
Phone: 403-265-1244, ext. 225 Fax: 403-265-1204
Email: alemmens@birchwoodresources.ca
Sage Pilot Application Page 9

1.2 Project Background
Birchwood Resources Inc. has acquired the Mineral Lease #77497120898 for oilsands in the
Manville Group in the South ½ of Section 1, Section 2 and SE 1 /4 of Section 3, in Township 64,
Range 04 west of the 4th Meridian leased from the Alberta Government. The mineral lease
comprises approximately 448 hectares (“ha”) and is located within the Municipality of Bonnyville.
(See Figure 1.2-1)
Birchwood drilled three wells in the winter of 2011 targeting primary bitumen production from the
Grand Rapid Formation and evaluation of the Clearwater and McMurray Formations within the
Manville group. Both a Pre-disturbance Assessment and a Traditional Land Use study were
completed by third parties before this work was done. Also, before any disturbance occured,
meetings were held with the Cold Lake First Nation Chief and Council, the Lakeland Industry
and Community Association Board of Directors and the Councilors of the Municipal District of
Bonnyville.
The three wells were drilled and completed using conventional production methods. Due to the
high viscosity of the oil, only one of the wells achieved sub-economic production from the upper
Grand Rapids formation using conventional methods. The other two wells were shut in. All three
of these wells encountered clean, high porosity highly saturated bitumen sand within the
Clearwater formation. Core and log analysis indicated that the Clearwater Formation would
react very favorable to SAGD thermal recovery. Reservoir simulations and Pre-feed Engineering
were initiated and completed in March and August, respectively, of 2012.
In June of 2012 Birchwood hosted an open house at the local Riverhurst community center to
introduce the project and to seek preliminary feedback form stakeholders. The feedback was
used by Birchwood to augment the development to mitigate concerns and potential impacts to
affected stakeholders. In total Birchwood received 157 written comments and questions.
Frequently asked questions were posted on Birchwood’s website and detailed question were
responded to individually upon completing the necessary evaluations and data collection and
assessments in November of 2012. The assessments included 3D computer modeling, noise
impacts and air quality assessments, hydrogeology groundwater assessment, vegetation and
wildlife assessments, soils and geo-technical assessments, and injection testing to confirm cap
rock integrity.
The Sage project is proposing to develop the resources using a modular facility design and drill
10 horizontal well pairs for a commercial demonstration SAGD pilot recovery exploiting the
Clearwater Formation. If successful, plans will be developed and submitted to regulatory
authorities to develop the remaining resources within the RDA and to test thermal recovery
methods for bitumen bearing sands in the Grand Rapid Formation. The focus of this application
will be the initial commercial demonstration/pilot phase of bitumen recovery from the Clearwater
Formation.
Sage Pilot Application Page 10

1.3 Guides to Application
This application for the project is contained in two volumes and consists of the following
components:
Volume 1: ERCB & Alberta ESRD Joint Application
Section 1 – Project Introduction and Overview
Section 2 – Economics and Land Use
Section 3 – Regulatory Approvals
Section 4 – Geology
Section 5 – Reservoir Recovery process
Section 6 – Process Description
Section 7 – Drilling & Completions
Section 8 – Environmental Setting
Section 9 – Stakeholder Consultation
Section 10 – References
Section 11 – Acronyms and Abbreviations
Volume 2: Consultant Reports
CR1 – Hydrogeology
CR2 – Air Quality Modeling Report
CR3 – Noise impact Assessment
CR4 – Vegetation and Wildlife Assessment
CR5 – Soils Assessment
CR6 – Injection/Fall off Testing Results
CR7 – Conservation and Reclamation Plan
1.4 Purpose
The purpose of the project is to demonstrate commerciality of a small scale modular concept
development to recover crude bitumen from the Clearwater Formation.
1.4.1 Project Need
As declining conventional crude production continues, additional heavy oil production will benefit
global energy needs. The Project will specifically pilot small scale sustainable commercial
development to unlock smaller accumulations of bitumen in the province that were previously
considered uneconomic. If successful, this modular technology may be used on other oil sands
in situ projects leading to an increase in provincial reserves utilizing brackish water reducing
water required to maintain and grow in-situ heavy oil production in a sustainable manner.
The Project will provide benefits to the Provincial and Regional economies because of capital
expenditures in the order of $230 million prior to the commencement of production operations.
Once production begins additional expenditures for sustaining capital, operating costs including
salaries, royalties and taxes payable will be incurred throughout the life of the Project. (See
Economics in Section 2.1)
Sage Pilot Application Page 11

1.5 Location
1.5.1 Project Development Area
Birchwood has identified a Project Development Area ("PDA") and a Resource Development
Area ("RDA") for the Sage Project (see Figure 1.1-1). The PDA is the area of land on which
wells and surface facilities will reside. The PDA encompass 18.6 ha (580 m x 320 m) of land
area for the well pad and Central Processing Facility. The PDA will be located in the SW-02-
064-04W4M. (See Figure 1.5-1)
1.5.2 Resource Development Area
The RDA is the larger area that will support the pilot project as well as additional future wells
(from the existing PDA) should the project prove successful. The RDA contains the bitumen
resources required for the initial stages and future phases of SAGD development and totals
1.75 sections of land. The RDA is limited by the south boundary of Crane Lake; it is not
Birchwood's intent to drill the horizontal section of the wells under the lake as part of this
proposal. The RDA includes Section 02-064-04W4M & SE 03-064-04W4M (see Figure 1.1-1).
Birchwood has identified the locations and trajectories of the first well phase which will include
10 horizontal well pairs. The design provides an additional 24-26 well pairs utilizing the existing
PDA.
1.6 Project Overview
This application is seeking approval to construct, operate and reclaim the Sage Commercial
Demonstration Pilot Project, a crude bitumen recovery scheme that will utilize steam assisted
gravity drainage (“SAGD”) technology to produce bitumen at a rate of 795m3 (5,000 barrels) per
day. The life of the 10 well pair pilot project is 5 years. Total Original Oil In Place (“OOIP”) in the
Clearwater Formation is estimated at 24,037 e3m3 (151MM barrels). Recoverable crude
bitumen using SAGD recovery is estimated to be up to 65% of OOIP. The combined facility, well
pad design and layout has incorporated the potential for up to 36 well pairs to be drilled from the
facility/well pad proposed herein, If the project proves to be successful, the life of the project
would be extended to at least 15 years.
Birchwood has designed an operation that reduces environmental impacts, and has taken
additional steps to design the most efficient facility possible, including significant attention to
noise and odor concerns, brackish makeup water, high produced water recycle and ground
water protection. Production and recovery using in-Situ SAGD technologies without using fresh
water enhances oil sands sustainability. The information gathered from the pilot will allow an
efficient and controlled development of the provincial resource and facilitate continuous
improvement at Sage.
Under steady state operation the plant is designed to process 3140m 3 of water/day and
315m 3 /day of waste water disposal capacity will be required. Brackish source water for steam
generation will be obtained from the McMurray formation, pumped to and treated at the CPF.
Steam will be sent from the plant via above ground pipeline to each of the wells for injection into
the individual well pairs. Produced water will be treated and re-used. An initial volume of up to
50,000 m 3 fresh water will be required for project start-up and 5m 3 /day will be required for the
duration of the project, in order to service utility requirements. Produced water will be recycled
at a rate greater than 90% and spent saline water will be disposed of in deep formation disposal
wells located on the pad.
Sage Pilot Application Page 12

The facilities Birchwood is proposing for the SAGE Project include a common well and central
processing facility pad and associated infrastructure such as well pairs, roads, above ground
gathering and distribution systems and power lines. A plot plan showing the proposed facility
and well pad details is available in Figure 7.1.1. The project attempts to avoid native vegetation
to the extent feasible. The project footprint disproportionately (61%) comprises previously
disturbed land. The Project footprint will directly affect 18.6 ha of land of which 11.3 ha (61%)
was previously impacted by land clearing.
1.7 Project Facilities
Produced fluids (bitumen, water, solution gas) are also transported via above ground pipes from
the wells to the CPF. Produced gas will be burned in the steam generators. Bitumen will be
blended with diluent and shipped off site via an underground sales oil pipeline. Produced water
will de-oiled and treated for re-use as boiler feed make up water.
The project includes installation the following:
1 multi well pad location with 10 initial horizontal well pairs drilled for demonstration
purposes (36 well pairs possible form pad);
A modular Central Processing Facility (CPF) adjacent to the well pad, including brackish
water use for steam generation and produced water recycling technology;
Connection of well infrastructure to the CPF with above ground pipelines, and power
distribution lines;
A fuel gas line tied into a nearby existing Altagas pipeline;
An underground source water pipeline tied into source water wells located in the
development area;
An underground water disposal pipeline tied into CPF and water disposal wells.
The various components of the Project are listed in Table1.7-1
Table 1.7-1 Summary of Project Components
Project Component Area (ha)
Central Processing Facility and well pad (10 well pairs) 18.6
Access Road In place
Soil Storage Adjacent to CPF and well pad
Pipeline Corridor In place
Surface Water Run off Retention Pond On central pad
Source Water wells On central pad
Disposal Water Well(s) On central pad
Groundwater Monitoring Wells CPF and pad perimeter
TOTAL 18.6
1.7.1 Minimization of Land Disturbance
The project attempts to avoid native vegetation to the extent feasible. The project footprint
disproportionately (61%) comprises previously disturbed land. The Project footprint will directly
affect 18.6 ha of land of which 11.3 ha (61%) was previously significantly impacted by land
clearing.
Sage Pilot Application Page 13

Existing infrastructure, including the access road and the well site at 03-02-064-04W4M
constructed in 2011, will be utilized in order to eliminate clearing for roads for the proposed 10
well pairs and CPF. Should the pilot project prove successful, an additional 24 – 26 well pairs
may be developed from the same pad.
Other existing infrastructure in the area consists of:
A diluent line running adjacent to the east boundary of the PDA from the Husky terminal
at 04-26-063-04W4 to 12-28-064-04W4M
A crude oil sales pipeline running adjacent to the east boundary of the proposed PDA
from the Husky Tucker SAGD project at 12-28-064-04W4M to 04-26-063-04W4
Primary Highways # 28 from Bonnyville and # 55 from Cold Lake
Secondary Highway # 892 through the property to Birchwood's existing LOC
A fuel gas supply line owned by Altagas is located in 03-12-64-04W4M to the NE of the
PDA.
This infrastructure is presented in Figure 1.5-1.
1.8 Project Development Schedule
Table 1.8-1 Development Schedule Pending Regulatory Approval
Geological Evaluation &
Development plan
Public Consultation & Community
Relations
Environmental Baseline
Assessments
ASRD & ERCB Consultation –
Regulatory input integration
Community Open House – Public
input integration
Pilot Project Submission
Regulatory Process/ Decision
Off-site Modular Facility
Construction
Field Construction and Drilling
Initial Steam Circulation
SAGD Production
Phase II Development Plan
Decommissioning & reclamation
2011 2012 2013 2014 2015 2016
+
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Sage Pilot Application Page 14

1.9 Regional Setting
The proposed project site is located on Crown land designated for agricultural purposes within
the Dry Mixed Wood Sub-Region of the Lower Boreal Region in northern Alberta. The area is
characterized by undulating plains with aspen dominated forests and fens, with some areas
suitable for cultivation and/or grazing. There are numerous lakes and low lying water bodies in
the area. The proposed facility and well pad are situated primarily on land that is currently
cleared and used for cattle grazing. The lease area lies within the Cold Lake Beaver River
Basin. Surface water bodies within 2 km of the proposed pad include Crane Lake 750 meters
north of the facility, an un-named slough in section 1 and un-named slough approximately 300m
south east of the lease.
There are several offsetting thermal oilsands producers in the immediate area including Imperial
Resource’s Cold Lake CSS Operations, Husky’s Tucker Lake Thermal SAGD and Shell’s
SAGD, CNRL Primrose CSS and Wolf Lake SAGD, and the recently approved OSUM Taiga
SAGD & CSS project (see Figure 1.1-2 and Figure 1.1-3).
Substantial infrastructure is already in place to service the existing thermal in-situ operations
and the majority of the required infrastructure passes through Birchwood’s lease or is
immediately adjoining the Sage pilot site.
1.10 Environment, Health and Safety Program
Birchwood has formally documented EH&S programs that have been implemented to assist with
managing the health and safety of our employees, contractors, the general public and residents,
as well as manage environmental protection and stewardship, within our development areas:
Health & Safety Management Program
Environmental Protection and Management Program
Corporate Emergency Response Program
Quality Control Management Program
Conservation and Reclamation Plan
Additional management programs that will enhance the above and are being developed for
approval are:
Fire Protection and Response Program
Site Specific Emergency Response Program
Site Specific Safety Program (to address specific hazards, training and procedures required
to operate a SAGD facility safely)
Groundwater Monitoring Program
Details of Birchwood's safety program and how it will be integrated into the proposed pilot
project can be found in Section 7.
Sage Pilot Application Page 15

T64
T63
Figure 1.1-1 Birchwood Sage Project Map
Wells
29
20
17
8
5
32
29
20
17
Project Wells
Land Layer
28
21
16
33
28
21
16
Birchwood Lease Area
Development Area
9
4
R4 R3W4
27
22
15
10
3
34
27
22
15
26
23
14
11
2
35
26
23
14
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
Sage Pilot Application Page 16
25
24
13
12
1
36
25
24
13
30
19
18
7
6
31
30
19
18
29
20
17
8
5
32
29
20
17
T64
T63
SAGE Pilot Project
Birchwood Development Area
By : Jerry Babiuk, P.Geol Date : 2012/06/01
Scale = 1:65000 Project : Cold Lake
Figure 4.1

T68
T67
T66
T65
T64
T63
Land Layer
Boundaries
T62
T61
T60
Upper Mann Lake
Upper Mann Lake
T59
T58
Upper Mann Lake
Upper Mann Lake
Upper Mann Upper Lake Mann Lake
Upper Mann Lake
Upper Upper Mann Mann Lake Lake
Figure 1.1-2 Birchwood Sage Regional Project Map
R10 R9 R8 R7 R6 R5 R4 R3 R2 R1W4
Helina Area
BONNYVILLE NO. 87
Birchwood Lease Area
Development Area
Provincial Boundary
State Boundary
Map Boundary
Heritage Rangeland
Recreation Area
Wilderness Area
Wildland
Provincial Parks
State Parks
National Parks
Military Bases
Native Reserves
Cities
Towns
Villages
Rural Municipalities
Counties
28A
HORSESHOE HORSESHOE BAY BAY
Active Thermal Projects
CNRL Oil Sands Rights_01_01
Husky Oil Sands Rights_01
Imperial Resources_01
Pengrowth Energy
Shell Canada
55
GLENDON
ST. PAUL COUNTY NO. 19
Cold Lake Air Weapons Range
Moose Lake
Moose Lake
Moose Lake
Wolf Lake
55
Moose Lake
Moose Lake
Moose Lake
28A
Moose Lake
Moose Lake
Moose Lake
Moose Lake
Moose Lake
Moose Lake Islands
Moose Lake Islands
Moose Lake
Moose Lake Islands
Moose Lake
Moose Lake Islands
Moose Lake Islands
Moose Lake Islands
Moose Lake
Moose Lake
Moose Lake
Devon SAGD
Walleye
PELICAN PELICAN NARROWS
NARROWS
BONNYVILLE BONNYVILLE BEACH BEACH
KEHIWIN 123
28
Kehewin
CNRL SAGD
Wolf Lake
Sage Pilot Application Page 17
41
28 BONNYVILLE
CNRL CSS
Primrose
Husky SAGD
Tucker Lake
Muriel Lake
Pengrowth SAGD
Lindberg
Tucker Lake
Crane Lake
Shell SAGD
Orion
SAGE PROJECT
Muriel Lake
Doris Island
Moore Lake
Imperial Cold Lake
CSS project
Cold Lake Air Weapons Range
Marie Lake
Marie Lake
Cold Lake
First Nation
COLD LAKE 149
55
CFB Cold Lake
Cold Lake North Shore
Cold Lake North Shore
Cold Lake
First Nation
COLD LAKE 149B
COLD LAKE
28
Cold Lake
GRAND CENTRE
OSUM SAGD
TAIGA
COLD LAKE 149A
Cold Lake
Cold Lake
Cold Lake
R10 R9 R8 R7 R6 R5 R4 R3 R2 R1W4
Planned Thermal Projects
Osum Oils Sands
Hydrography
Major
Transportation
Wells
Primary Roads
Project Wells
Kilometres
0 10 20 30
0 10 20
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
Cold Lake
Cold Lake
Cold Lake
Cold Lake
Cold Lake
Cold Lake
Cold Lake
COLD LAKE 149C
Cold Lake
T68
T67
T66
T65
T64
T63
T62
T61
T60
T59
T58
Regional Map
Active/Planned Oil Sands Projects
By : Jerry Babiuk, P.Geol Date : 2012/12/04
Scale = 1:515000 Project : Cold Lake

Figure 1.2-1 Regional Map
Sage Pilot Application Page 18

Figure 1.2-2 Regional Satellite image
Sage Pilot Application Page 19

Figure 1.2-3 Local Aerial Image
Sage Pilot Application Page 20

Figure 1.5-1 Project Aerial Photo Mosaic
Sage Pilot Application Page 21

Figure 1.5-2 Aerial Photo Showing Existing Development and Pilot Site
Photo taken September 24, 2012 looking East
Sage Pilot Application Page 22

2 Economics & Land Use
2.1 Economics
2.1.1 Capital and Operating Costs
Initial capital investment for this project is estimated to be $230 million including $75 million for
drilling, completing and well tie in, $155 million for surface facilities, equipment and
infrastructure. The proposed development will contribute to the fiscal health of local, regional,
provincial and federal benefits through increased contributions to their tax bases and short and
long term job creation in addition to delivering royalties to the Government of Alberta. The
facilities will be fabricated in Airdrie Alberta using Alberta labor capacity.
Operating costs are projected to be $30 million annually, approximately one third of the annual
operating costs are expected to be spent locally.
2.1.2 Taxes and Crown Royalty
Effective March 31, 2012, independent estimates of royalties payable to the Government of
Alberta for the Birchwood Lease using SAGD recovery range from a low of $500 million to a
high estimate of $1.4 billion over a thirty year period. It should be noted that these estimates are
highly dependent on several factors including oil prices and are, therefore subject to uncertainty
and may change.
Corporate Federal and Provincial income taxes will vary substantially, especially during the
early years. Income taxes are estimates at approximately 15-20% of taxable income over the
life of the project.
Property taxes payable to MD of Bonnyville are estimated to be up to $1.7 million annually. Over
a 30 year life the project may generate $110 Million in taxes for benefit of MD of Bonnyville and
its residents.
2.1.3 Benefit Cost Analysis
A benefit cost analysis of the proposed project quantifies the creation of resources by the
project, and by comparing them, determines whether the benefits outweigh the costs.
The benefit of the project is represented by the projects outputs including bitumen produced
over the life of the project and its contribution to the local, provincial and federal economy.
The public cost associated with the project is expected to be minimal because impacts on
municipal and provincial infrastructure and services are expected to be small or non-existent.
The area has a substantial infrastructure created by nearly 30 years of offsetting in-situ
development. From a fiscal point of view these costs (if any) can be compared to the much
greater benefits derived including employment creation, use of local goods and services, and to
the municipal property taxes, school taxes, income taxes and royalties payable to the Alberta
Government generated by the project.
2.1.4 Marketing Arrangements
Produced bitumen will be blended with diluents supplied by Husky Oil at the CPF. The product
will be shipped via underground pipeline to the Husky terminal at 04-26-063-04W4M. Birchwood
is negotiating a sales arrangement with Husky Oil to purchase the resulting product.
Sage Pilot Application Page 23

2.1.5 Commercial Viability
SAGD technology is an accepted commercially viable form of bitumen extraction. Improvements
in drilling allowing longer wells and Improvements in water treating technology and modular
construction have reduced costs and the minimum size of commercial projects to below
10,000bopd. SAGD has lower operating temperatures and pressures compared to CSS and
therefore longer equipment and well lives. Birchwood has conducted an economic evaluation of
the project which shows it to be commercially viable; these results have been verified with an
independent third party geological engineering and economic evaluation.
2.2 Socio-Economics
2.2.1 Employment and Procurement
The project will provide direct economic benefits to the local and First Nations populations of
Bonnyville and Cold Lake through long term job creation and through sourcing of equipment,
labour and related services and logistics from local business. Modular surface facility
construction will be completed by an existing fabricator located in Airdrie, Alberta. It is estimated
that job creation during the construction and operational phases of the proposed project,
including plant construction, surface facility installation, drilling and well servicing, and plant
operations will result in 490 man years of employment over 30 years.
The construction phase of the project which will include lease development, facility construction
and drilling will employ approximately 50 people over 6 month period. Facility operations will
employ approximately 40 people over the life of the project. Types of employment will be varied
and include drilling and service rig personnel, completions engineers, construction supervisor
and associated crews, facility managers (steam, water, safety and environment, maintenance),
shift foremen, central room operators, office staff, operations personnel, technical specialists
(welders, pipefitters), general labour, security personnel and monitoring staff.
Employment positions that will be sourced from available personnel in the Municipality of
Bonnyville are as follows:
Table 2.2.1-1 Employment Positions
Position # of Positions Estimated Duration
Management staff 11 5 years
Administrative staff 6 5 years
Construction Supervisor 2 1 year
Surveyors 2 1 month
Welders 2 6 months
Pipefitters 8 2 months
Drilling Rig Personnel 24 6 months
Service Rig Personnel 16 3 months
General Labour 30 5 years
Heavy Equipment Operators 10 3 months
Plant technicians 18 5 years
Well Operators 6 5 years
Turnaround specialists 10 5 years
Sage Pilot Application Page 24

The above positions may require sourcing from other areas of Alberta and Canada if there is not
a sufficient pool of labour to meet technical and safety specific position requirements. There is
considerable activity in the Cold Lake and Lloydminster areas and Birchwood intends to follow a
project timeline such that Cold Lake hospitality services are capable of overnight housing of
workers.
2.3 Traffic and Access
The existing infrastructure shown in Figure 2.3-1 will facilitate movement of construction and
operations personnel during the various phases of the project. Hwy #28 and #41 from
Bonnyville to Hwy #55 and Hwy # 55 from Cold Lake provide access to Secondary Hwy #892
which link Birchwood’s existing road (LOC 112372), to the location of the facility/well pad. These
routes will provide access for the transport of personnel for construction as well as equipment,
and provide ongoing access for operations activities. There is no water crossings associated
with these access routes that require construction.
The placement of the pilot project has been selected in order to limit surface disturbance by
taking advantage of existing industrial infrastructure including highway 892 which is the primary
access to Imperial Resource’s Cold Lake CSS Operations, Husky’s Tucker Lake Thermal SAGD
and Shell’s SAGD projects. Considering the significantly smaller size of the operation compared
to the already existing development it is unlikely to cause any noticeable changes to traffic
volumes or road usage.
Transportation of the modular facilities for the CPF will utilize a route Highway 36 from Airdrie to
Highway 28. During construction, oversized loads will be utilized to transport equipment and
structures to the well pad and CPF. Communication with other industrial users, utilities and the
municipality will be undertaken to ensure that the loads can be transported safely and minimize
road burdens.
2.4 Integration with Other Land Uses
Land use documents relevant to the project are:
1. Lower Athabasca Regional Plan (2012) (“LARP”),
The proposed development is located in the southern area of the Lower Athabasca Regional
Plan; the plan, broadly, prescribes the overall activities that occur and are acceptable within the
region, specifies limits on land use to preserve habitat and biodiversity, specifies air, surface
water and groundwater management targets and provides strategic direction for the region in
order to achieve balanced growth objectives.
2. Cold Lake Sub Regional Integrated Resource Plan (1996) (“CL SRIRP”),
The proposed development is within the Nine Lakes Resources Management Area of the CL
SRIRP. Activities proposed in this application have integrated the management strategies and
guidelines presented in that Plan. Orderly development of oil and gas resources is a key
requirement for the plan. The objectives identified specifically highlight development which will
assist in exploiting oilsands reserves in concurrence with protection of other resources and
activities, which are consistent with this project.
Sage Pilot Application Page 25

3. Crane Lake Area Structure Plan (2006) (“CLASP”)
The focus of CLASP is predominately protection of the recreational aspects of Crane Lake and
shoreline ecosystem protection and development.
4. Recovery Strategy for The Woodland Caribou, Boreal Population, in Canada, (EC 2012)
The federal government's Caribou recovery strategy provides a comprehensive program and
strategic direction for re-establishing the species at risk in the boreal forests of northern
Canada. Range plans and action plans have not yet been developed or implemented; however
the location of Birchwood's proposed facility should not have a direct effect on the recovery
strategy.
2.4.1 Timber/Forestry
The RDA area contains both private and public lands. The PDA considered in this application
lies wholly within Public lands and it is designated as “white” in the CL SRIRP, as the available
timber for harvesting in the RDA is minimal. The Conservation and Reclamation Plan will
address various components required to maintain the sustainability of the land for grazing and
re-establishment of forest cover.
2.4.2 Recreational Uses
There is recreational activity on Crane Lake to the northwest and west of the proposed RDA.
The proposed setbacks (approximately 2km from existing residents and campgrounds and
750m from Crane Lake) will prevent interference with recreational activities.
Access and egress from the well pads and CPF will be restricted and monitored by camera in
order to ensure residents and visitors, as well as staff, safety.
2.4.3 Agriculture
Grazing is the primary land use in the proposed RDA. Crop cultivation is not currently
undertaken as a result of poor quality soils. The Conservation and Reclamation Plan addresses
requirements for landscape, soil, and water management in order to return the land to
equivalent land capacity in and use with respect to grazing and potential for using disturbed
lands within the RDA for cultivation purposes. The proposed PDA will be on land that is
currently utilized for cattle grazing.
The project development area lies within Grazing Lease GRL#40375. Birchwood has been in
consultation with the grazing lease holder since April of 2011 and has received consent for the
proposed development.
2.4.4 Trapping
The project development area lies within Registered Fur Management Area TPA#1473.
Birchwood has been in consultation with the trapper since April of 2011 and has not received
any objections or concerns for the proposed development.
2.4.5 Petroleum and Natural Gas Rights
Imperial Oil holds the PNG mineral rights in the RDA. A Map of Natural Gas lease holders is
presented in Figure 2.4.5
Sage Pilot Application Page 26

2.4.6 Oilsands Rights
Birchwood owns the mineral lease for oilsands in the mannville group. A map of oilsands lease
holders is presented in Figure 2.4.6
2.4.7 Ecological Resources
A review of various public information databases and third party studies has not identified any
significant ecological resources in the RDA. Additional plant and animal inventories of the RDA
will provide the baseline for protection of existing ecological resources that may be affected by
the development and are incorporated into the Conservation and Reclamation Plan.
2.4.8 Wildlife
The resource development area supports a variety of mammals, birds and a small number of
amphibians/reptiles as is noted in the Wildlife Assessment (see Section 8 and Consultant
Report 4 - Vegetation and Wildlife). The RDA is outside any designated "Key Diversity and
Wildlife Zones" as designated by ESRD. Specific surveys to verify species at risk occurrence
and the status and abundance of management species of concern will be completed during
winter and spring of 2013.
The project footprint occurs primarily on an existing cleared area and does not affect any natural
movement corridors. Effects on regional movement will be negligible because of the small
project footprint and avoidance of large blocks of native habitat.
2.4.9 Vegetation
The predominant ecosite phase on the PDA is comprised of pasture; open grassland and open
grassland with shrubby regeneration. The remaining land is comprised of a variety of forest
covered land and oil and gas infrastructure (pipelines and wells. The project attempts to avoid
native vegetation to the extent feasible. The Project footprint will directly affect 18.6 ha of land of
which 11.3 ha (61%) was previously impacted by existing land clearing.
The project footprint area was searched for rare plants and rare plant communities from August
13 to August 15, 2012. No rare plants species were found at the time of the survey. An
additional survey will be undertaken to capture early blooming plants and this work will be
undertaken in June 2013.
2.4.10 Historical Resources
There are a number of initiatives that have been undertaken to determine the existing historical
resources with the proposed RDA and specifically to the PDA.
In the fall of 2011, Birchwood conducted a study with the Cold Lake First Nations Traditional
Land Use prior to the construction and development of the surface lease areas and access for
drilling of the cold production wells. The study included recommendations for development and
preferred solutions for potential issues. Figure 2.4.10A – Figure 2.4.10D present a review of the
historical development of the project area.
The proposed well and Central Processing Facility pad lies outside the 400 m buffer zone
identified by the CLSIRP as having potential historical resources. In addition, the Alberta
conservation Information Management System database indicated that the RDA has low
potential for historical resources.
Sage Pilot Application Page 27

2.4.11 Wetlands
Wetland complexes within the RDA and PDA were classified according to the Alberta Wetland
Inventory Standards, see Figure 2.3.11. The area selected for the well pad and CPF exceed the
minimum setback criteria that any wetland areas were outside the 100m buffer and primary
lakes outside the 300m buffer zone for wetland protection.
2.4.12 Surface ownership
Surface ownership is presented in Figure 2.4.12.
2.5 Participation in Regional and Research Initiatives
Birchwood has established membership in various regional associations, including the Lakeland
Industry and Community Association (“LICA”), the Alberta Lake Management Society, in order
to facilitate the integration of their work into the project design monitoring systems. It is
Birchwood’s intent to actively participate in the various monitoring programs and incorporate its
data with these groups.
Sage Pilot Application Page 28

Figure 2.3-1 Access Sketch
Sage Pilot Application Page 29

T64
Land Layer
Wells
PNG Rights
T63
Figure 2.4.5 PNG Lease Holders Map
IP
RS
RS
WS WS IP IP S
Birchwood Lease Area
Project Wells
CNRL
Freehold Land
Frehold Resources
EOG Rsrcs
Crescnt Pnt & Conserve
Devon Canada
Conserve O&G & Waymar
CNRL Lands
Husky Lands
Open PN&G Lands
Imperial Lands
Shell Lands
Pipelines & Facilities
Crude Oil
Oil Well Effluent
Natural Gas
Sour Gas
Fuel Gas
Misc Gases
Fresh Water
Salt Water
HVP Products
LVP Products
Misc Liquids
S
R4 R3 R2W4
S
S
S
S
PS LR TF TL TL
SS
WP CT
S
S
S
S
S
S
S
IP
S
S
S
S
S
S
S S
Sage Pilot Application Page 30
S
IP S
S S
R4 R3 R2W4
Kilometres
0 1 2 3 4 5 6
0 1 2 3 4
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
S
S
S
S
S
IP S
IP S
WS IP SS
S
S
S
WP S
MS PS PS PS IP IP
SS
S
S
S
S
S
IP
S
S
S
S
S
S
S
MS CS
S
MS
IP
S
RS
S
S
WS
S
S
IP
MS CS GS
RS
MS CS GS
Regional Map
Held PN&G Rights
MS GS GS CS
T64
T63
By : Jerry Babiuk, P.Geol Date : 2012/12/05
Scale = 1:103000 Project : Cold Lake

T64
Land Layer
Wells
Figure 2.4.6 Oilsands Lease Holders Map
IP
RS
RS
WS WS IP IP S
Birchwood Lease Area
Project Wells
Oil Sands Rights
T63
Open Rights
Freehold Land
Keppoch Energy
Pengrowth Energy
CNRL Oil Sands Rights
Husky Oil Sands Rights
Imperial Resources
Osum Oils Sands
Shell Canada
Pipelines & Facilities
Crude Oil
Oil Well Effluent
Natural Gas
Sour Gas
Fuel Gas
Misc Gases
Fresh Water
Salt Water
HVP Products
LVP Products
Misc Liquids
S
R4 R3 R2W4
S
S
S
S
PS LR TF TL TL
SS
WP CT
S
S
S
S
S
S
S
IP
S
S
S
S
S
S
S S
Sage Pilot Application Page 31
S
IP S
S S
R4 R3 R2W4
Kilometres
0 1 2 3 4 5 6
0 1 2 3 4
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
S
S
S
S
S
IP S
IP S
WS IP SS
S
S
S
WP S
MS PS PS PS IP IP
SS
S
S
S
S
S
IP
S
S
S
S
S
S
S
MS CS
S
MS
IP
S
RS
S
S
WS
S
S
IP
GS MS CS
RS
MS GS CS
Regional Map
Held Oil Sands Rights
MS GS GS CS
T64
T63
By : Jerry Babiuk, P.Geol Date : 2012/12/05
Scale = 1:103000 Project : Cold Lake

Figure 2.3.10A 1950 - Historical Aerial Photo
Sage Pilot Application Page 32

Figure 2.3.10B 1977 - Historical Aerial Photo
Sage Pilot Application Page 33

Figure 2.3.10C 1980 - Historical Aerial Photo
Sage Pilot Application Page 34

Figure 2.3.10D 1988 - Historical Aerial Photo
Sage Pilot Application Page 35

Figure 2.3.11 Wetlands Mapping & Potential Plant Locations
Sage Pilot Application Page 36

Figure 2.4.12 Surface Ownership
T64
T63
9
4
33
Land Layer
Crown
Howatt Holdings
M Clements
Development Area
Surface Landowners
Grazing Leases
Crown
Freehold
Crown
R Howatt
D&E Pearson
J&D Healey
10
3
34
R Howatt
R Howatt
C&D Prediger
Crown
R4 R3W4
Sage Pilot Application Page 37
Crown
R Howatt
R Howatt
R Howatt
Crown
Kilometres
11
2
35
Crown
J Roux
Lazurko &
Geoffroy
Lazurko &
Geoffroy
Howatt Holdings
0 1 2 3
12
D Berg D Berg D Berg
D Berg
1
J Roux A&D Moon D&J McDaniel
G&B Crawford
G&B Crawford
36
D Berg
K Dodman
Crown
D Berg
Mclean
Guthrie
Moon
D&E Delmarter
Crown
7
6
31
R4 R3W4
0 1 2
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
Crown
Crown
R&C Pemarowski
G&R Felding
G&R Felding
SAGE Project
Surface Landholders
By : Jerry Babiuk, P.Geol Date : 2012/12/07
Scale = 1:39000 Project : Cold Lake
T64
T63

3 Regulatory Approvals
3.1 Existing Approvals
The existing approvals associated with the proposed development area are:
Existing Access Road - LOC # 112372 November 2011
Existing Access Road - LOC # 112288 November 2011
Existing Access Road - LOC # 112371 November 2011
Existing Well Site - MSL #112662 (03-02-064-04W4) November 2011
Existing Well Site - MSL #112568 (01-03-064-04W4) November 2011
Existing Well Site - MSL #112660 (06-02-064-04W4) November 2011
Undeveloped Well Site - MSL #112661 (10-02-064-04W4) November 2011
Birchwood has conducted exploratory drilling in 2011 within the lease. An access road was
constructed and vertical wellbores were drilled to evaluate potential for conventional production of
the bitumen resources on the lease. Well licenses from the ERCB and Surface leases from ESRD
were secured for all the wells drilled on the lease. Birchwood will re-use the following existing ESRD
approvals listed below as part of this application.
Existing Access Road - LOC # 112372 November 2011
Existing Access Road - LOC # 112371 November 2011
Existing Well Site - MSL #112662 (03-02-064-04W4) November 2011
Existing Well Site - MSL #112660 (06-02-064-04W4) November 2011
Birchwood has filed with Alberta ESRD a request for determination if an Environmental Impact
Assessment would be required for the Sage Thermal Pilot Project. Birchwood received notice dated
May 22, 2012 from the Designated Director of the Government of Alberta Environment and Water
that pursuant to Section 44 of the Environmental Protection and Enhancement Act (“EPEA”) an
environmental impact assessment is not required for the Sage Thermal Pilot Project.
The Canadian Environmental Assessment Agency has issued a letter dated June 15, 2012
indicating that a federal environmental impact assessment was not required for the Sage Thermal
Pilot Project.
3.2 Application for Approval
The approval application package herby submitted is for various types of approvals from the ERCB
and ESRD as follows:
3.2.1 ERCB Approvals Requested
Scheme approval to construct and operate pursuant to Section 10 of the Oil Sands
Conservation Act (“OSCA”), for approval to construct and operate its proposed Sage
commercial demonstration pilot project (795m 3 or 5,000 bbl/day) from the Cold Lake Oil
Sands Deposit in the Mannville Formation, an oil sands leases located in Townships 64,
Range 4W4M, consisting of a central processing facility adjoining a 10 SAGD well pair pad.
Approval in accordance with ERCB Directive 51 to drill and dispose waste water in the
Granite Wash (Cambrian) Formation, the single well would be located in Section 2 Township
64 Range 4, West of the 4th Meridian.
Sage Pilot Application Page 38

3.2.2 ESRD Approvals Requested
Approval to construct and operate and reclaim the Project facilities to recover and treat
bitumen and processed water, pursuant to Part 2, Division 2 of the Alberta Environmental
Protection and Enhancement Act (“EPEA”);
A Conservation and Reclamation Plan Approval from ESRD under Division 2 of Part 2 and
Part 6 of the EPEA to develop, operate and reclaim components of the Sage Project; and
Approval pursuant to Part 3, Division 1 of the Water Act, to divert up to 50,000 m 3 of
groundwater from the Muriel Lake Aquifer for initial start-up and up to 25,000 m 3 annually
thereafter, and up to 175,000 m 3 annually of brackish groundwater from the McMurray
Formation for the purpose of oilfield injection (i.e., SAGD). The proposed water source wells,
(one Muriel Lake Formation wells and one McMurray Formation wells), would be located in
Section 2 Township 64 Range 4, West of the 4th Meridian.
Surface water diversion licence to operate a storm water pond. Diversion licences are issued
pursuant to Part 3, Division 1 of the Water Act.
3.4 Additional Approvals Associated With the Application.
Separate applications will be filed by Birchwood for other parts of the project that are legislated
under various other statues. Application and approvals requirements under Provincial laws
applicable to the project for which separate applications will be filed under separate cover are:
Development permit pursuant to Section 17 of the Municipal Government Act, for the
Municipality of Bonnyville, for the construction and operation of the project and related
infrastructure
Public lands act, for surface rights
Historical Resources Act, for clearance to construct the facilities.
Oil and Gas conservation Act for Well Licenses
Pipelines Act for the construction and operation of pipelines between the central processing
facility and the well pads, water supply wells, water disposal wells, and fuel gas, diluent and
sales pipeline connections.
3.5 ERCB Application Checklist
Birchwood is making application under Section 10 of the Oil Sands Conservation Act (“OSCA”) for
approval to construct and operate the Sage Pilot Project. The information provided in this
application is in compliance with the requirements ERCB D-23. Each subsection in the regulation is
cross-referenced to the relevant section in the documentation to facilitate the review process is
found in Appendix 3.5.
3.6 EPEA Application Checklist
Birchwood is making application under Part 2, Division 2 of EPEA for approval to construct and
operate the Sage Pilot Project. The information provided in this application is in compliance with the
requirements of Alberta Regulation 113/93. Each subsection in the regulation is cross-referenced to
the relevant section in the documentation to facilitate the review process is found in Appendix 3.6.
Sage Pilot Application Page 39

Appendix 3.5 ERCB Application Checklist
D-23
Reference
Summary Requirement
Location in
Application
1.5 Project Description Section 1.6
1.5.1 Applicable Acts and Sections under which the application is made Section 3.2.1
1.5.2
Name and address of the application and any partners involved and the
details of company incorporation
Section 1.1
1.5.3 Statement of need and project timing Sections 1.4.1, 1.8
1.5.4 Overall project description and discussion of schedule Sections 1.6, 1.8
1.5.5
Description of the regional setting of the development and reference to
existing and proposed land use
Sections 1.9, 2.4
1.5.6
Map indicating the freehold, leasehold, mineral and surface rights of the
proposed scheme and surrounding area and maps showing land use and
landowners
Figure 1.1-2, 2.4.5, 2.4.6
2.4.12
1.5.7 Map showing topography and any development in the project area Figure 2.3.11,1.5-1, 1.5-2
1.5.8 Aerial photomosaic Figure 1.5-1, 1.5-2
1.5.9 Description of storage and transportation facilities including pipelines Sections 7.8.6 7.10.3.3
1.5.10 Proposed rate of production over the life of the Project Sections 1.6, 7.1.3
1.5.11 Description of the subject oil sands owned by or leased to the applicant Section 1.2
1.5.12 Status of negotiations N/A
1.5.13 Proposed energy source, alternatives, resource use, sources and supply
Sections 7.1.3,
7.5,7.7,7.10.3.1 7.10.3.2
1.5.14 Description and results of public information program Section 9
1.5.15
The term of the approval sought, including expected project start and
completion dates
Section 1.6
1.5.16 Name of responsible person to contact Section 1.1
2.1 Surface mining operations N/A
2.2 Underground access and development N/A
2.3 In-situ operations -
2.3.1 Geological description of zone of interest Section 4.2.3
2.3.2
Identification by name and depth of the target zone including any crude
bitumen zone or water zone immediately above or below the zone of
interest.
Section 4.2.1.4B, 4.2.3,
4.2.3.2
2.3.3 Criteria used in selecting the oil sands zone for recovery
A description of the cut off bitumen grade and thickness criteria used to
Section 4.2.3.1
2.3.4 establish the in-place resource potential of the project area supported by
reserve estimates and trends
A geological, engineering and economic evaluation of the bitumen reserves
Section 4.2.3.1
2.3.5 recoverable by the proposed scheme and a description of and rationale for
the criteria employed
Section 5.1.1
2.3.6
A geological, engineering and economic evaluation of bitumen reserves not
recoverable by the proposed scheme
Section 5.5.2
2.3.7
A discussion of the potential and requirements for any follow-up recovery of
reserves
Section 5.3.3
2.3.8 Evaluation of gas reserves associated with the oil sands to be developed
Appendix 5.7.B1, 4.2.3.3
5.1.1.1, 7.1.3
2.3.9
An evaluation of sand or fines production, the effects on recovery and
anticipated disposal methods as well as anticipated disposal methods
Section 6.2.4
2.3.10
A description of the recovery process to be used, including (2.3.11- 2.3.20,
as listed below):
Section 5.1.2
2.3.11 The recovery efficiency of the process and well spacing Sections 5.5, 5.5.4
2.3.12
A description of the Project layout with emphasis on equipment spacing and
surface disturbance.
Sections 1.7,1.7.1, 7.1
2.3.13
A description of the efforts to minimize land disturbance and the
collection, conservation or other disposition of produced gases
Section 1.7.1, 7.6
2.3.14
A diagram and description of proposed well drilling and completion
Methods
Sections 6.2, 6.3 Figures
6.3.1, 6.3.2
2.3.15 A description of the proposed well performance monitoring program Section 5.4
2.3.16
A description of geotechnical factors and techniques of monitoring, that may
affect operations
Section 5.4.3
Sage Pilot Application Page 40

2.3.17
The volume of fluids and solids produced and the proposed disposition of
each
Section 7.2.4 Figure 7.2.2-
A, 7.2.2-B
2.3.18
Material balances for hydrocarbons, sulphur and water in the central
processing facility
Appendix 7.2
Figures 7.2.2, 7.2.1-1
7.2.2-1, 7.2.3-1A,
2.3.19 A process flow diagram for the central processing facility
7.2.3-1B,7.2.3-2 7.3-1,
7.3.1-1, 7.3.2-1 7.3.3-1,
7.4-1, 7.5-1, 7.6-1
2.3.20
A sample set of production accounting reports for the central processing
facility
Section 7.8
2.4.1
A separate description of the bitumen extraction, upgrading, utilities, refining
and sulphur recovery facilities
Section 7.3, N/A, 7.10,
N/A, 7.5.1
2.4.2 Material and energy balances Appendix 7.2 Section 7.7.1
2.4.3 Products, by-products and waste and their disposition Section 7.3, 7.12.2
2.4.4
Surface drainage within the areas of the processing plant, product Storage
and waste treatment and disposal
Section 7.11.6
2.4.5 Comparison of proposed process to alternatives Section 5.1.1
2.4.6 This number has been omitted from D-23 N/A
2.4.7 Example of production accounting reports Section 7.8
2.5.1
A description of any facilities to be provided for the generation of electricity to
be used by the project.
Section 7.10.3.1
2.5.2
Identification of the source, quantity and quality of any fuel, electricity or
steam to be obtained from sources beyond the project site
Section 7.10
2.5.3
An appraisal of the options available to eliminate the need for offsite
resources
Section 7.10.3
2.6.1
A description of air and water pollution control and monitoring facilities, as
well as a liquid spill contingency plan
Section 8.3.2.2, 7.11.5
2.6.2 A description of the water management program
Section 7.2.2, 7.2.3, 7.2.4,
Figure 7.2.2-A
2.6.3
The manner in which surface water drainage within the Project area would
be collected, treated and disposed
Section 7.11.6
2.6.4 A description of the air and water pollution control and monitoring facilities Section 8.3.2,7.11
2.6.5 A description of the emission control system
Commercial Viability: An appraisal and projections, on an annual basis of
Section 7.6, 7.11.3, 7.11.4
3.1.1 revenues, capital and operating costs, royalties and taxes, net cash flow,
marketing arrangements, fuel and electric power arrangements
Section 2.1
3.1.2 A description of project costs which include capital and operating cost Section 2.1.1
3.2.1
Benefit-Cost Analysis: A summary of quantifiable public benefits and costs
incurred during the construction and operation of the Project
Section 2.1.3
3.2.2
A summary of non-quantifiable public benefits and costs incurred each year
during construction and operation of the Project
Section 2.2
3.3.1
Economic Impact: An appraisal of the economic impact of the Project on the
region, province and nation
Section 2.1
3.3.2
A discussion of any initiatives undertaken to accommodate regional
economic priorities and interests
Section 2.2.1, 2.4
3.3.3
An assessment of direct and indirect employment opportunities for all
groups associated with the Project
Section 2.2.1
4.0 Environmental Impact Assessment Section 3.1
5.0 Biophysical Impact Assessment Section 8
6.0 Social Impact Assessment Section 2.2
7.0
Describe the environmental protection plan including mitigation measures,
environmental monitoring and research
Section 8.10, 8.10.7
8.0 Conceptual Development and Reclamation Plan CR 7
9.0 Solid Waste Management Plan
Section 7.12
Appendix 7.3
Sage Pilot Application Page 41

Appendix 3.6 EPEA Application Checklist
EPEA
Guide
Summary Requirement
Location in
Application
1 Applicant Identification -
1.1
1.2
1.3
1.4
2
2.1
Applicant’s Name
Mailing address
Mailing address of the plant or facility / regional office
Contact information
Plant or Facility Identification
Description of plant or facility activities
Section 1.0
Section 1.1
Section 1.1
Section 1.1
-
Section 1.6, 7.1
2.2 Plant or facility location Section 1.5
2.3 Plant or facility location map
Figure 1.1-1, 1.2-1, 1.2-2,
1.5-1, 1.5-2
2.4 Area potentially affected by the plant or facility Section 8 Figure 1.2-3
3 Project Background Section 1.2
3.1 Government approved regional initiatives in the affected area Section 1.9
3.2 Hearing results or decisions N/A
3.3 Environmental Impact Assessment report for Hearing N/A
3.4 Authorizations related to the Project Section 3.1
3.5 Related EPEA applications for other plants N/A
3.6 Financial Security N/A
3.7 Proposed timelines Section 1.8
3.8 Public consultation process Section 9
4 Current State of the Environment -
4.1
Local and regional landscape features, drainage and surface watercourses,
and groundwater
Figure 2.3.11
Section 8.5, CR1
4.2 Ambient air quality Section 8.3.2, CR2
4.3 Baseline soil and vegetation Section 8.6, 8.7 CR4, CR5
4.4 Previous development and disturbance
Section 1.7.1
Figure 1.5-2
4.5 Baseline wildlife and wildlife habitat Section 8.8 CR4
4.6 Baseline watercourses Section 8.5.1 CR1
4.7
Current properties and suitability of the receiving soil properties for
irrigation/land application
Section 8.6.3
4.8 Restrictions to irrigation or land application of waste in the area N/A
4.9 Maps and diagrams of the local and regional environment
Figure 1.1-2, 1.2-1,
1.2-2. 1.2-3
4.10 Government regional initiatives obligations Section 2.4, 8.10
5 Project Design -
5.1 Process overview, major equipment and mass balances
Section 7.1 Appendix 7.1,
7.2
5.2 Substances generated Appendix 7.3
5.3 Options examined to optimize efficiency Section 7.10.3.1
5.4 Footprint minimization Section 1.7.1
5.5 Plot plan Figure 7.1.1
5.6
Materials storage, waste management, tanks, and runoff/wastewater
management system
Section 7.1 – 7.9, 7.3.3,
7.11.6, 7.12
Appendix 7.3 CR7
5.7 Monitoring and performance evaluation of collection and storage N/A
5.8 Wastewater and runoff treatment and control Section 7.11.6
5.9 Suitability and capacity of treatment and release control systems N/A
5.10 Location of proposed treatment facility and disposal Figures 7.1.1
5.11 Monitoring and performance evaluation of wastewater treatment and disposal Section 7.8
5.12 Monitoring and evaluation of treated wastewater release rates N/A
5.13 Ambient monitoring of released treated wastewater N/A
5.14 Data and models of released wastewater and disposal methods Section 4.2.1.4A
5.15 Air emissions Section 7.11.3, CR2
5.16 Air emissions streams Table 8.3.2-3
5.17 Environmental control systems Section 7.11
5.18 Emission source Table 8.3.2-3
5.19 Flare pits N/A
Sage Pilot Application Page 42

5.20 Fugitive emissions Section 8.3.2.1
5.21 Significant area or non-point emissions -
5.22 Dispersion modelling Tables 8.3.2-1, 8.3.2-2
5.23 Dispersion modelling diagrams Figures 8.3.2-1, 8.3.2-2
5.24
Proposed monitoring and performance evaluation of treatment and control
Section 7.8
equipment
5.25 Proposed monitoring and evaluation of ambient air quality Section 8.3.2.2, 8.10.1
5.26 Air emissions data, calculations and models Section 8.3.2 CR2
6 Construction -
6.1 Construction schedule Section 1.8
6.2 Construction site map and sensitive areas N/A
6.3 Location of construction activities Section 2.2.1
6.4 Reclamation materials salvage CR7
6.5 Storage location of reclamation materials during and after construction CR7
6.6 Timber salvage and woody debris management CR7
6.7 Construction on contaminated land N/A
6.8 Contamination avoidance during construction CR7
6.9 Process flow for releases during construction N/A
6.10 Environmental releases monitoring Section 8.10.3, 7.11.5
6.11 Ambient monitoring equipment Section 8.10.1
7 Operation -
7.1 Record keeping procedures Section 7.8
7.2 Operating procedures for release monitoring and performance evaluation Section 7.8
7.3 Joint monitoring network Section 8.10.7
7.4 Suitability of proposed ambient air-monitoring network N/A
7.5 Suitability of proposed ambient monitoring of the receiving environment N/A
7.6 Proposal for periodic wastewater characterization testing Section 7.8
7.7 Record keeping procedures to meet applicable requirements Section 7.8
7.8 Reporting procedures Section 7.8
7.9 Spill response and reporting plan development
Section 7.11.1, 7.11.5,
8.10.6
7.10 Storage, treatment and monitoring plan for wastewater, runoff and sludge Section 7.11.6
7.11 Air emission control equipment maintenance and repair plan Section 7.11.3
7.12 Monitoring programs for potential substance release to groundwater
Section 6.5, 7.8, 8.10.3,
8.10.6, 5.4.2
7.13 Management of releases to soils from other media Section 8.7.5
7.14 Third-party waste procedures Appendix 7.3
7.15 Classifying and characterizing waste methods Appendix 7.3
7.16 Soil storage protection measures from contamination and erosion CR7
7.17 Operator certification N/A
8 Reclamation -
8.1 End land-use and capability ratings CR7
8.2 Reclamation of landform, drainage and watercourses CR7
8.3 Soil reclamation plan CR7
8.4 Vegetation reclamation plan CR7
8.5 Effectiveness of alternatives for proposed “engineered” watercourses N/A
8.6 Short and long term effects of reclamation to watercourses N/A
8.7 Progressive reclamation plan CR7
8.8 Reclamation timeline CR7
8.9 Maximization of progressive reclamation CR7
8.10 Reclamation materials salvage and handling procedures CR7
8.11 Storage of reclamation materials CR7
8.12 Progressive reclamation plan for landforms, watercourses, soil and vegetation CR7
8.13 Wastewater and runoff releases during reclamation CR7
8.14 Waste management during reclamation CR7
8.15 Dust, odours, contaminants and noise control Section 7.1 – 7.11, 8.3.2.1
8.16
8.17
Remedial treatment systems vapour control
Existing and planned infrastructure for environmental monitoring
Section 7.6
N/A
8.18 Stakeholder involvement N/A
8.19 Contact information for reclamation activities Section 1.1
9 Continual Improvement Plan Section 8.10
Sage Pilot Application Page 43

4 Geology
4.1 Area Description
4.1.1 Resource Development Area
The Resource Development Area (“RDA”) is defined as Section 2 and SE 1 /4 of Section 3, in
Township 64, Range 04 west of the 4th Meridian. (Figure 4.1.1)
4.1.2 Project Development Area
The Project Development Area (“PDA”) is defined as the well pad and Central processing facility
encompassing 18.6 ha. (Figure 4.1.2)
4.1.3 Geological Study Area
The Geological Study area is defined in Figure 4.1.3
4.2 Reservoir Geology
4.2.1 Regional Stratigraphy
Sedimentary rocks that overly the Precambrian basement in the Sage area of Cold Lake are about
1200m thick and range from Cambrian to Quaternary in age (Figure 4.2.1).
The Clearwater Formation is the main bitumen reservoir within the Birchwood acreage and is part of
the Lower or Early Cretaceous Mannville Group. The Clearwater Formation deposition occurred
initially approximately 110Ma (Early Cretaceous), and was then capped by the Grand Rapids
Formation ending approximately 100Ma (Lower Cretaceous).
The Clearwater is the geologic time equivalent to the Lloydminster formation in south eastern region
of Alberta and time equivalent to the Bluesky and Spirit River Formation in the NW. Sediment into
the Basin during deposition of the Clearwater typically came from the south east and was deposited
into the basin in a NW direction.
4.2.1.1 Granite Wash Formation (Cambrian)
Cambrian aged sandstones rest unconformably on granites of the Precambrian basement. These
sandstones are quartzose, with well-developed porosity and permeability. Minor interbedded shales
and silts occur locally. Thicknesses of greater than 60 m have been observed. These sandstones
are used by various operators in the Cold Lake area for water disposal. This formation is anticipated
to be the primary water disposal zone for the thermal pilot at Sage.
4.2.1.2 Elk Point Group (Devonian)
Lower to Middle Devonian Elk Point group strata (evaporites) rests unconformably over the
Cambrian sandstones. The formations from oldest to youngest are:
• Lotsberg (240 m of salt, shale, and shaly dolomite)
• Ernestina (20 m of dolomitic limestone and anhydrite)
• Cold Lake (50 m of salt)
• Contact Rapids (40 m of shaly dolomite)
• Winnipegosis (50 m of dolomitic limestone)
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• Muskeg (170 m of salt)
• Watt Mountain (20 m of dolomitic limestone, shale, and anhydrite)
4.2.1.3 Beaverhill Lake Group (Upper Devonian)
The Beaverhill Lake Group rests unconformably over the Elk Point Group. Strata in this group are
composed of limestones, calcareous dolomites and argillaceous shales and comprise the
Waterways Formation. Dissolution of Devonian salts and subsidence of overlying strata resulted in a
structural low on top of the Waterways Formation. This represents the basement upon which the
Mannville Group sediments would accumulate.
4.2.1.4 Mannville Group (Lower Cretaceous)
Mannville Group was deposited over top of the Beaverhill Lake Group. Depositional sands or strata
represent the major reservoirs in the Cold Lake area. The formations from oldest to youngest are:
• McMurray (McMurray A, B, C)
• Clearwater
• Lower and Upper Grand Rapids (Rex, General Petroleum, Sparky, Waseca, McLaren and
Colony).
All formations are unconsolidated sands with varying amounts of interbedded silts and shales.
4.2.1.4A McMurray Formation
The McMurray Formation was deposited on the Paleozoic carbonate. The McMurray C sands at the
base is an unconformable surface and consists of approximately 15-30m of clean, quartz sand with
interbedded silts and shales. The McMurray can be broken down to three subunits within the
McMurray informally called the McMurray A, McMurray B, and McMurray C. The Lower McMurray
consists of thick fluvial sands with a large aeriel extent. The Upper McMurray consists of
interbedded silt, very fine sand, and shale, and is increasingly tidal in nature. These sands are wet
and brackish in nature. The Lower McMurray sandstone has been used as a brackish water source
and disposal zone for offsetting thermal projects such as Husky’s Tucker Lake and Shell’s Orion.
The Lower McMurray C sandstone is targeted to be the primary brackish water source for the
thermal pilot at Sage.
4.2.1.4B Clearwater Formation
The Clearwater Formation is the principal bitumen-bearing reservoir at Sage. Its average gross
thickness is 45 to 65m at an average depth of 400m. These sands are unconsolidated feldspathic
litharenites, and have a complex mineralogy. Clearwater sands at Sage were deposited in an
estuarine environment. A drop in sea level during Clearwater deposition resulted in formation of an
incised valley system, which removed older marine Clearwater sediments as well as some
underlying Wasbiskaw Member sediments. Sea level rose, and a transgression along the valley
system resulted in deposition of the Clearwater and Grand Rapids Formations. Marine shale caps
the Clearwater and a water leg underlies the Clearwater in the Sage area.
The Wabiskaw member lies beneath the base of the Clearwater Formation and overlies the
McMurray Formation. Over the Birchwood acreage the Wabiskaw is a marine shale 2.0 - 8.0m. The
Wabiskaw is often eroded by younger Clearwater strata. There is no reservoir potential associated
with the Wabiskaw.
A cross-section showing the zone of interest is provided (Figure 4.2.1.4A & Figure 4.2.1.4B) and a
type log is provided (Figure 4.2.1.4C).
Sage Pilot Application Page 45

4.2.1.4C Grand Rapids Formation
The Grand Rapids Formation consists of interbedded sands and shales deposited in a marginal
marine setting. Individual sands and shales can be 5-10m thick and are lithic, feldspathic, to
quarzose, in composition. The entire formation is approximately 100m thick. Individual sands can be
hydrocarbon bearing, with separate contacts for each sand unit.
Using nomenclature from the heavy oil area around Lloydminster the Lower Grand Rapids is
informally divided into the “A”, “B” and “C” units with the lowermost A (Rex sand) and B (General
Petroleum) and C (Sparky) sands typically wet.
The Upper Grand Rapids sands are thin and laterally discontinuous and separated by shales up to
10 m thick. The Upper Grand Rapids is informally divided into the “A”, “B” and “C” units with the
lowermost A (Waseca) followed by the B unit (McLaren) and the uppermost ‘C’ (Colony). The
Waseca sand and has been mapped over the Sage area. Birchwood has tested 100/01-03-64-
04W4M for primary production potential in the Waseca and McLaren and recovered bitumen at sub
economic rates. The Upper Grand Rapids can be gas bearing. These gas pools have limited aerial
extent are structurally controlled and are isolated from the Clearwater Formation.
4.2.1.5 Colorado Group Lea Park Formation (Upper Cretaceous)
The Colorado Group conformably overlies the Mannville strata. This Group is up to 180m thick and
consists of massive shales with minor silts deposited in a marine environment. From oldest to
youngest, the Formations are:
• Joli Fou
• Viking / Pelican
• Base Fish Scales
• Second White Specks
These formations provide a barrier between the productive zone and the groundwater resources
above.
4.2.1.6 Overburden (Quaternary)
Overburden sediments are approximately 100m thick and are composed of glacial and post-glacial
gravel, sand, silt, clays and tills. The sands and gravels are within channels eroded into the
Colorado and are the fresh water aquifers in the Sage area. The formations from oldest to youngest
are:
• Empress
• Muriel Lake (Durlingville)
• Bonnyville
• Ethel Lake
• Sand River
• Grand Centre
4.2.2 Well Control
Across the SAGE area there is sufficient well and core data to establish a stratigraphic framework
and to determine reservoir quality (Figure 4.2.2A). There are 19 cored wells from offsetting lands
and many open-hole logs that define the Clearwater reservoir on Birchwood’s property. To date
there have been 4 wells drilled within the Birchwood Oil Sands lease. These wells are as follows
Sage Pilot Application Page 46

100/01-03-64-04W4, 100/03-02-64-04W4, 100/06-02-64-04W4 and 100/05-01-64-04w4 (Figure
4.2.2B). All wells were logged with a full suite of open-hole logs (density, neutron, induction and
sonic). Formation Imaging logs (“FMI”) were run on each of 100/01-03-64-04W4, 100/03-02-64-
04W4, and 100/06-02-64-04W4, (Figure 4.2.2C). Petrophysical log analysis was completed on each
set of open-hole logs for wells within the property in addition to 3 offsetting wells (Figure 4.2.2D).
The 100/3-2-64-04W4 location was cored in both the Clearwater and the Waseca Formations. The
core has been analyzed for porosity, permeability and oil saturation and viscosity (Figure 4.2.2E).
Log analysis has been correlated against core data. Resulting net pay values from core and log
analysis were used to generate the net pay map (Figure 4.2.3.1).
Beyond the limits of the Sage lease, there is both log and core data which have been incorporated
into the Sage stratigraphic interpretation.
Additional drilling is planned. The objective of these wells is to refine the delineation of the bitumen
resource within the planned development area, and to advance development planning for the
remainder of the lease.
4.2.2.1 Seismic Data
Data from two 2D seismic lines was purchased by Birchwood in 2011 and interpreted to support the
geological interpretation.
A depth structure map of the top of the Clearwater was generated from Formation tops picked in
Geoscout. Wells were then integrated with the two 2D Birchwood seismic lines (Figure 4.2.2.1A).
Seismic confirmed that the top of the Clearwater remained relatively constant and consistent over
the development area. No significant lows were developed due to salt solution and collapse of the
underlying Devonian deposition (Figure 4.2.2.1B).
A seismic program is planned for the winter of 2012-2013 pending regulatory approval.
4.2.3 Geological Description of the Clearwater Formation
The Clearwater formation was deposited in a shallow marine prograding (or basinward) deltaic
system that was orientated towards the North/Northwest direction. Silica rich, fine to fine-medium
grained sandstones were deposited along low to horizontal angle bedding planes composition.
Occasional small scaled ripples and laminae are noted in Clearwater cores.
The most common diagenetic feature of the Clearwater is carbonate cement and shale rich and clay
laminations can occur and are found in certain areas of the Clearwater on the order of 1-10 cm in
thickness, but are not believed to be continuous over large areas. They are believed to be calcite
concretions and are not considered to be a barrier to steam chamber growth.
The main reservoir within the Clearwater is the valley-fill sediments. Reservoir quality is determined
by the shale content of the fill and the occurrence of early diagenetic pore filling clays. Over the
Birchwood Sage Project, Clearwater sediments range from 30 to 65 m as a result of the stacking of
sand rich valley fills with no significant shale breaks. A schematic W-E cross-section across the
Birchwood SAGE Project shows the stacking of the incised valleys and the nature and relationship
of the fill within and between each valley (Figure 4.2.1.4A). A W-E cross section including offsetting
thermal operations is presented in Figure 4.2.1.4B. The fill of valleys B and C is dominantly sandrich,
high energy channel flat facies. The fill of valley D is sediment deposited within tidal channels,
Sage Pilot Application Page 47

with varying amounts of shale clasts and beds that are characteristic of this facies. Bitumen
saturation within valley D is also variable when compared to valleys B and C.
Structure on the top of the Clearwater sand (Figure 4.2.3B) is fairly consistent across Birchwood’s
Property with the exception of a small localized dip to the South East of Birchwood’s land.
Structure on the base of the Clearwater sand (Figure 4.2.3C) varies across Birchwood’s Property.
The consistent water height provides a bitumen leg with minimal elevation variation.
The Clearwater isopach map (Figure 4.2.3D), illustrates where the Clearwater reaches a maximum
thickness of 65m.
4.2.3.1 Clearwater Net Pay
The Clearwater Net Pay map denotes a Northern trending Clearwater pay interval that lies directly
over Birchwood lands. The total bitumen thickness (Figure 4.2.3.1) across the development area at
Sage ranges from 20-30m. Effective pay in the Clearwater Formation is designated as the
continuously porous, oil-bearing zone that would be accessed by the steam chamber created
around a horizontal well pair. Pay was determined from core analysis utilizing a bulk mass oil
fraction of 0.07 as a pay cut-off. A porosity cutoff of 27 percent has been used along with a
resistivity cutoff of 7 ohm-metres and a minimum thickness of 8m. An average porosity of 33 percent
with an average bulk mass oil of 0.104 has been measured for the Clearwater pay from the 100/03-
02-064-04W4 well resulting in the an average net pay of 25m within the Resource Development
Area.
4.2.3.2 Clearwater Bottom Water
Across the Birchwood lease, the lowermost Clearwater sands are water saturated. Bitumen
reservoir saturated sands rest directly on top of the water saturated sands. Bottom water structural
dip is minimal over Birchwood’s Property, and averages around 1 m of structure variation across
Sections 1, 2, and 3-64-4W4. The structure map (Figure 4.2.3.2) identifies the bitumen-water
contact varies from +132.1m to + 133.0m.
4.2.3.3 Clearwater Top Gas
There appears to be no known gas identified over the Birchwood property in the Clearwater
Formation. Open hole logs show no cross over or approach between the Density and neutron log
indicating gas effect. Gas pockets have not been observed during drilling in the Clearwater
Formation.
The Upper Grand Rapids can be gas bearing. These gas pools have limited aerial extent are
structurally controlled and are isolated from the Clearwater Formation.
4.2.3.4 Caprock and Seal Integrity
A seal exists between the oil saturated Clearwater and the overlying Lower Grand Rapids, as well
as between the Upper Grand Rapids and the Quaternary fresh water aquifers.
Clearwater sands are capped by 4-6 m thick shale across the RDA (Figure 4.2.3.4). This shale acts
as a seal to hydrocarbon migration above the Clearwater and the lowermost Grand Rapids.
Overlying Colorado shale’s up to 180m thick act as a seal to hydrocarbon migration above the
Upper Grand Rapids and the Quaternary fresh water aquifers.
Sage Pilot Application Page 48

4.4 Injection/Fall-off (“mini-frac”) Testing Results
Taurus Reservoir Solution Ltd. (“Taurus”) was asked to perform a mini-frac analysis on tests
conducted by ET Technical Systems and Pure Energy on the well 100/06-02-064-04 W4M (06-02)
(CR6 – Injection/fall-off testing report). These tests covered 5 sand and shale intervals from the
Colorado Shale (271 – 271.5 m KB) down to the Clearwater Sand (409.0 – 409.53 m KB). It was
possible to interpret closure pressures for all zones from the tests except for the Clearwater shale
zone.
The Clearwater shale interval was tested twice and both tests showed rapid pressure drops after
each fall-off. This indicates a significant fluid mobility not normally seen in shale caprock. It is
concluded that fracture height growth occurred during testing to an external permeable zone. The
zone is likely downwards into the Clearwater sand. The Clearwater shale in the area is regionally
consistent and existing stress gradients can be used to calculate closure pressures for the
Clearwater shale. As such a search of publicly available offsetting data was conducted.
The search revealed that in 2009 Weatherford preformed a study for Osum on their Taiga project in
the Cold Lake area. As part of their work they documented publically available mini-frac work in the
Cold Lake area. The data includes information from a number of zones; the bulk of the data was
from the Clearwater sand and shale intervals. High quality mini-frac data is available from the
offsetting Imperial Oil lands and is specific to the Clearwater shale. Horizontal stress gradients of
20.9 kPa/m have been measured. This is the recommended value to pick for the Clearwater shale.
The Clearwater shale in the area is regionally consistent and stress gradients can be used to
calculate closure pressures for the Clearwater shale on the 06-02 well.
Table 4.4.1 Clearwater Shale Closure Pressure Regional Value
Zone
Depth
m GL TVD
Gradient
kPaa/m
Closure Pressure
kPaa
Clearwater Shale 407.35 20.9 8514
Table 4.4.2 Summary of Closure Pressures per Zone Tested
Source
Depth equal to MPP of
perforated interval
Zone
Depth
m GL TVD
Gradient
kPaa/m
Closure Pressure
kPaa
Source
Colorado Shale 269.35 24.6 6617 Birchwood FP_10_FO
Waseca Shale 329.35 19.5 6407 Birchwood FP_06_FO
Waseca Sand 336.65 22.3 7514 Birchwood FP_05_FO
Clearwater Sand 426.85 16.3 6969 Birchwood FP_06_FO
Sage Pilot Application Page 49

Figure 4.1.1 Resource Development Area (“RDA”)
T64
T63
Wells
29
20
17
8
5
32
29
20
17
Project Wells
Land Layer
28
21
16
33
28
21
16
Birchwood Lease Area
Development Area
9
4
R4 R3W4
27
22
15
10
3
34
27
22
15
Sage Pilot Application Page 50
26
23
14
11
2
35
26
23
14
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
25
24
13
12
1
36
25
24
13
30
19
18
7
6
31
30
19
18
29
20
17
8
5
32
29
20
17
T64
T63
SAGE Pilot Project
Birchwood Development Area
By : Jerry Babiuk, P.Geol Date : 2012/06/01
Scale = 1:65000 Project : Cold Lake
Figure 4.1

Figure 4.1.2 Project Development Area (PDA) & Wells
T64
T63
Land Layer
10
3
34
Birchwood Lease Area
Development Area
Hydrography
Major
Minor Lake
Minor River
Pad Layout
Wells
Hz well path
Faciity site
Build Section
Well heads
Project Wells
Kilometres
R4 R3W4
11
2
35
0 0.5 1 1.5
0 0.5 1
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
Sage Pilot Application Page 51
12
R4 R3W4
1
36
T64
T63
SAGE Pilot Project
CPF & SAGD Horizontal Well Pairs
By : Jerry Babiuk, P.Geol Date : 2012/09/17
Scale = 1:32493 Project : Cold Lake

T64
T63
Figure 4.1.3 Geological Study Area
30
19
18
31
30
19
Land Layer
Wells
7
6
29
20
17
32
29
20
Birchwood Lease Area
Development Area
Geological Study Area
Project Wells
Hydrography
Major
Minor Lake
Minor River
8
5
28
21
16
9
4
33
28
21
R4 R3W4
27
22
15
10
3
34
27
22
Sage Pilot Application Page 52
26
23
14
11
2
35
26
23
25
24
13
12
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
1
36
25
24
30
19
18
7
6
31
30
19
29
20
17
8
5
32
29
20
28
21
16
9
4
33
28
21
SAGE Pilot Project
Geological Study Area
27
22
T64
15
10
34
27
T63
By : Jerry Babiuk, P.Geol Date : 2012/09/17
Scale = 1:85000 Project : Cold Lake
22

Figure 4.2.1 Cold Lake Stratigraphy
(Modified from Husky-Tucker Thermal Project, 2003)
Sage Pilot Application Page 53

Figure 4.2.1.4A Schematic SW-NE cross-section Clearwater Formation
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Figure 4.2.1.4B Regional Cross Section Clearwater Formation
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Figure 4.2.1.4C Birchwood Clearwater Type Log
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Figure 4.2.2A Well Control Map
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Figure 4.2.2B Cross Section Birchwood Lease - Clearwater Formation
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Figure 4.2.2C Formation Imaging logs (FMI) - Clearwater Formation Interval
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Figure 4.2.2D Log Analysis
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Figure 4.2.2E Summary Core Data and Photos 100/03-02-064-04W400
Sage Pilot Application Page 61

Figure 4.2.2.1A Depth converted time structure map top of Clearwater Formation
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Figure 4.2.2.1B Interpreted Seismic Data
Sage Pilot Application Page 63

Figure 4.2.3B Structure on the Top of the Clearwater Formation
+177.3
+169.3 +170.7+170.7 +177.4 +179.0
+170.0
+167.2
+163.2
+169.8
+172.7+175.9
+174.2
T64
T63
+166.7 +167.1
+160.3
+153.9 +148.4 +152.0
Land Layer
Wells
29
+164.3 +161.4
20
17
8
5
32
29
+166.2
20
+163.3
+165.6 +164.2 +163.2+167.9
+161.1
+159.8
+163.2
+156.4
28
+164.3+165.0
21
16
+161.7 +161.0 +152.3
33
28
21
+164.4
+172.9,+172.9 +173.1,+172.6
Birchwood Land
Birchwood Lease Area
Development Area
Project Wells
9
4
+175.6
R4 R3W4
27
+179.8
22
15
10
3
34
+170.9
27
+156.8
+176.9
+176.4,+169.3
22
+175.7
+155.5
+157.2
+170.5,+170.2 +170.7
+176.6
26
23
14
11
2
35
26
23
150.0
150.0
+164.7
+179.8
+177.3,+177.5
150.0
Sage Pilot Application Page 64
+174.9
+178.2
+172.6
+158.2
+149.5
+159.0
+158.2
13
12
1
36
25
24
+174.0
+157.5
+164.6
+159.7
+169.7
+179.0
+164.2
+159.3
+147.6
30
+167.8
+167.6
19
+170.2
+162.5
18
+160.5
7
6
31
30
19
+171.6
+169.5
+172.3
+173.7 +175.0
+170.4
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
25
24
+169.7
+169.3
29
20
17
8
5
32
29
+167.9
+167.8 +164.6
+164.8
+170.5
+147.5
+172.2
+174.2
+172.4
20
SAGE Pilot Project
Structure Map
Clearwater Formation
T64
150.0
T63
By : Jerry Babiuk, P.Geol Date : 2012/09/11
Scale = 1:65000 Project : Cold Lake

115.0
T64
T63
Figure 4.2.3C Structure at Base of the Clearwater Formation
+109.2
90.0
115.0
115.0
+108.3 +113.9 ,+108.8,
+102.9
+104.6 +110.6
+98.3
Land Layer
Wells
29
+120.9
+114.5 +120.4 +121.2
+118.4
+112.4+116.1
+115.8
20
17
8
5
32
29
+106.7
20
+108.2
+104.5
+95.2
+87.5
+87.4
+106.0
+95.7
28
+107.7 +103.9+113.7
21
16
33
28
21
90.0
90.0
+120.1,+119.4 +119.4,+120.5
Birchwood Land
Birchwood Lease Area
Development Area
Project Wells
9
4
+118.5
+114.9
+111.5
+112.7
+105.3
115.0
R4 R3W4
27
+115.2
22
15
10
3
34
+116.9
27
+94.4
+139.1
+137.2,+137.3,
22
+111.9
+101.9
+104.4
--- +126.7,, +130.3
+124.3
+121.4
26
23
115.0
14
11
2
35
26
23
Sage Pilot Application Page 65
+112.4
115.0
115.0
+112.6
+114.7
+116.8
+109.8
+106.4
+117.5
+118.6
13
12
1
115.0
36
25
24
+132.6
+115.3
+112.1
+130.9
115.0
+116.7
+139.2
+117.9
+108.9
90.0
+123.1
30
+127.3
+124.5 +131.1
19
+130.6
+123.3
18
+121.0
7
6
31
115.0
30
+138.6,
19
+125.1
+125.8
+132.0
+128.5
+120.0
+134.5
+130.9
+120.5
+134.4 +134.7
+118.5
115.0
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
25
24
29
20
+133.1
+130.8 +124.9
+134.2
17
8
5
32
29
+128.7
+133.6
+127.8 ,+133.6
+137.2
+126.0
+120.6
+132.6
+134.5
+132.6
20
SAGE Pilot Project
Structure Cleawater Base
T64
T63
By : Jerry Babiuk, P.Geol Date : 2012/09/05
Scale = 1:65000 Project : Cold Lake
Frigure

Figure 4.2.3D Clearwater Isopach Map
53.0 53.5 56.2
56.4
57.0 57.8
58.0
56.8
59.2
51.6
60.3 59.858.4
T64
T63
55.6
58.4 53.2
57.4
Land Layer
Wells
29
57.9 57.3
20
17
8
5
70.0
32
29
59.5
20
53.4
57.4
56.6
64.6
74.2
61.0
59.7 54.4
57.2
60.7
28
56.5 59.3 54.2
21
16
33
28
70.0 70.0
21
45.0
52.8,53.5 53.7,52.1
Birchwood Land
Birchwood Lease Area
Development Area
Project Wells
9
4
57.1
59.1
R4 R3W4
64.6
27
22
15
10
3
34
27
54.0
37.8
39.2,32.0
22
62.4
63.8
53.6
52.8
43.8, 40.4
45.0
52.3
26
23
14
11
2
35
45.0
26
23
Sage Pilot Application Page 66
62.5
45.0
45.0
65.6
45.0
57.9
41.4
39.7
41.5
39.6
13
12
1
36
25
24
41.4
42.2
38.8
52.5
43.0
39.8
45.0
41.4
41.1
38.7
40.5
30
43.1
19
18
39.6
7
6
31
39.2
39.5
30
38.7,37.2
19
45.0
38.9
39.6
49.5
51.8
39.3 40.3
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
25
24
45.0
38.8
50.8
29
20
17
8
5
32
29
45.0
37.0
39.2
49.9
39.6
39.7
39.8
20
SAGE Pilot Project
Isopach Map
Clearwater Formation
39.7
38.8
T64
T63
By : Jerry Babiuk, P.Geol Date : 2012/09/11
Scale = 1:65000 Project : Cold Lake

Figure 4.2.3.1 Clearwater Net Pay
T64
T63
Land Layer
Wells
10
3
Birchwood Lease Area
Development Area
Project Wells
Clearwater Fm
34
Net Pay Contours
20.0m
ST= 155.9m
46.5/23.5/23.5
wtr line= 132.1m
ST= -157.0m
63.5/23.7/22
wtr line= 133.0m
Sage Pilot Application Page 67
25.0m
30.0m
R4 R3W4
11
2
ST= 157.3m
44.2/24.8/23
wtr line= 132.7m
35
30.0m
25.0m
Kilometres
0 0.5 1 1.5
0 0.5 1
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
ST= 155.7m
40/22.4/19.0
wtr line= 133.7m
20.0m
12
1
36
15.0m
SAGE Pilot Project
Net Pay Clearwater Formation
By : Jerry Babiuk, P.Geol Date : 2012/10/09
Scale = 1:23000 Project : Cold Lake
R4 R3W4
7
6
31
T64
T63

T64
ST= 149.4m
51.8/9.0/5.1
wtr line= 139.6m
T63
Figure 4.2.3.1B Clearwater Net Pay
ST= 153.9m
55.6/13.9/4.0
Land Layer
Wells
29
20
17
8
5
0.0m
ST= 148.8m
58.9/25.0/3.4
ST= 161.7m
70.4/16.6/11.8
wtr line= 130.8m
32
29
ST= 166.2m
20
61.6/24.8/9.9
wtr line=134.4m
NDE
ST= 160.8m
NDE/14.6/9.1
wtr line= NDE
NDE
ST= 163.2m
57.2/25.5/22.5
Wtr Line= 126.1m
ST= 156.4m
60.7/13/12.5
wtr line= 121.4m
5.0m
ST= 172.9m
28
21
16
10.0m
ST= -151.4m
NDE/NDE/12.0
33
28
21
53.50/33.6/19.0
wtr line= 137.1m
Birchwood Land
Birchwood Lease Area
Development Area
Project Wells
9
4
ST= 164.4m
59.1/19.6/13.0
wtr line= 135.2m
15.0m
20.0m
25.0m
30.0m
35.0m
ST= 155.9m
46.5/23.5/23.5
wtr line= 132.1m
ST= -157.0m ST= 157.3m
63.5/23.7/22
44.2/24.8/23
wtr line= 133.0m wtr line= 132.7m
ST= -170.6m
53.5/36.5/36.5
wtr line= 134.6m
ST= 176.9m
38.6/33.9/24.9
wtr line= 140.9m ST= 169.3m
32.0/24.6/21
ST= 173.1m
53.7/35.3/22.2
wtr line= 135.8m
R4 R3W4
27
22
15
10
3
34
27
22
NDE
wtr line= 140.2m
ST= 155.6m
ST= 175.7m
34.2/34.0/28
26
23
14
No Logs
11
2
35
35.0m
30.0m
ST= 181.8m
26
Sage Pilot Application Page 68
25.0m
51.4/46.8/33.4
wtr line= 135.0m
ST= 155.7m
40/22.4/19.0
wtr line= 133.7m
20.0m
NDE
ST= 148.9m
NDE/NDE/>11.0m
wtr line NDE
15.0m
ST= 149.1m
32.6/16.7/13.5
wtr line=132.8m
10.0m
ST= 159.7m
43.0/24.9/21.0
wtr line 131.5m
15.0m
5.0m
ST= 169.7m
ST= 149.5m
ST= 174.1m
NDE/NDE/>15.0
38.8/30.3/17.3m
wtr line= 139.4m
wtr line= NDE ST= 179.0m
23
ST= 176.7m
52.4/35.9/14.1
wtr line= 136.5m
25
24
ST= 159.0m
60.5/26.1/21.0
wtr line= 130.6m
ST= 159.3m
ST= 158.2m
41.4/25.5/24.5
wtr line= 133.9m
40.5/25.0/21.1
wtr line= 133.2m
13
12
1
36
25
ST= 174.0m
ST= 157.5m
42.2/24.9/22.5
wtr line= 131.4m
24
41.4/26.5/18.2
wtr line= 143.9m
39.8/27.5/18.6
wtr line= 147.6m
40.6/15.6/12.8
Wtr line= 133.5m
0.0m
30
19
18
ST= 160.5m
51.0/25.5/20.9
7
6
31
30
ST= 164.7m
ST= 168.2m
38.9/27.4/17
wtr line= 137.3m
ST= 171.9m
19
31.6/25.1/17.5
wtr line=146.8m
ST= 166.2m
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
29
20
17
8
5
32
29
20
NDE
NDE
T64
T63
ST= 172.2m
39.6/30.6/20
wtr line= 138.5m
SAGE Pilot Project
Net Pay Clearwater Formation
By : Jerry Babiuk, P.Geol Date : 2012/09/05
Scale = 1:65000 Project : Cold Lake
Figure 4.3.1

T64
wtr line= 139.6m
T63
Figure 4.2.3.2 Structure Clearwater Bottom Water
130m
Wtr Line= 133.9m
Land Layer
Wells
29
20
17
8
5
32
29
20
wtr line=134.4m
NDE
Wtr Line= 126.1m
wtr line= 121.4m wtr line= 135.2m
Wtr line= 134.4m
NDE
28
21
16
wtr line= 130.8m wtr line= NDE
33
28
21
wtr line= 137.1m
Birchwood Land
Birchwood Lease Area
Development Area
Project Wells
9
4
135m
140m
wtr line= 140.9m
wtr line= 135.8m
R4 R3W4
27
22
15
10
3
34
wtr line= 132.1m
wtr line= 133.0m wtr line= 132.7m
wtr line= 134.6m
27
22
wtr line= 140.2m
Wtr Line= 137.8m
NDE
26
23
14
No Logs
11
2
35
26
wtr line= 135.0m
wtr line= NDE
23
wtr line= 136.5m
130m
wtr line= 130.6m
wtr line= 133.2m
wtr line= 133.7m
Sage Pilot Application Page 69
25
NDE
24
13
12
1
wtr line=132.8m
wtr line= 131.4m
wtr line NDE
36
25
24
wtr line 131.5m
wtr line= 139.4m
wtr line= 143.9m
wtr line= 133.9m
wtr line= 147.6m
30
19
18
Wtr line= 133.5m
Wtr Line=132.6m
7
6
31
30
wtr line= 137.3m
19
wtr line=146.8m
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
29
20
17
8
5
32
29
20
NDE
NDE
T64
T63
wtr line= 138.5m
SAGE Pilot Project
Structure Cleawater Bottom Water
By : Jerry Babiuk, P.Geol Date : 2012/09/05
Scale = 1:65000 Project : Cold Lake
Frigure

T64
T63
Figure 4.2.3.4 Isopach Map Clearwater Formation Capping Shale
4.3
Land Layer
Wells
3.5
29
20
17
8
5
32
29
1.4
20
Birchwood Lease Area
Development Area
Project Wells
Clrwtr Shale Unit
3.7
4.5
Clwtr Shale Isopach Contours
5.8
28
21
16
9
4
33
28
21
6.0
2.5 3.2
4.1
R4 R3W4
27
22
15
10
3
34
3.5
27
22
3.2
2.1
4.3
5.3
5.0
2.8
2.9 2.6
2.9
3.83.0
1.9
3.1
26
23
14
11
2
35
26
23
3.5
Sage Pilot Application Page 70
2.4
3.5
4.7
3.2
4.0
1
3.4
36
25
24
3.0
6.5
2.3
2.5
2.4
2.7
3.6
3.5
R4 R3W4
Kilometres
0 1 2 3 4 5
0 1 2 3
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
25
24
13
12
30
19
18
7
6
31
30
2.9
1.7
19
2.8
2.0
1.4
29
20
17
8
5
3.5
32
3.5
29
20
3.2
3.5
SAGE Pilot Project
Isopach Map
Shale Unit Above Clearwater
3.8
T64
T63
By : Jerry Babiuk, P.Geol Date : 2012/12/04
Scale = 1:65000 Project : Cold Lake

5 Reservoir Recovery Process
5.1 Reservoir Properties
The Clearwater Formation for the Sage project is encountered at a true vertical depth (“TVD”) of
approximately 400mKB. The Clearwater formation within the proposed development area has
gross pay thickness varying between 45 m to 64 m with bottom water thickness varying from 22
m to 37 m and net / SAGD exploitable pay ranging from 20-30 meters.
5.1 Table Sage Typical Reservoir Properties
Gross Pay Thickness (m) 45 – 64
Bottom Water Thickness (m) 22 – 37
Net Pay / OOIP / SAGD Exploitable Pay Thickness (m) 20 – 30
Porosity (%) 33 – 36
Water Saturation in SAGD Exploitable Pay (%) 30 – 40
Oil Saturation in SAGD Exploitable Pay (%) 60 – 70
Horizontal Permeability (mD) 1,000 – 3,000
Vertical Permeability (mD) 550 – 1,500
Reservoir Temperature ( o C) 16
Dead Oil Viscosity @ Reservoir Temperature (mPa.sec) 60,000 – 3,600,000
Oil Gravity ( o API) 8.0 – 10.5
Initial Reservoir Pressure (kPa) 2,700 - 2,900
Initial Gas saturation 0
5.1.1 Recovery Process Selection
Generally accepted methods for recovering bitumen form the Clearwater Formation include
Steam Assisted Gravity Drainage (“SAGD”) and Cyclic Steam Stimulation (“CSS”) both of which
have commercial operations in close proximity to the project recovering bitumen from the
Clearwater. CSS is historically the more developed method for recovery in the Clearwater
formation in the area but this process has limited application in reservoirs with bottom water.
CSS Recovery in reservoirs absent of bottom water is potentially 30% of the Original Oil In
Place.
The SAGD process is a high efficiency recovery process that may potentially recover 65% of the
Original Oil In Place and is considered the most viable process for bitumen recovery from the
Clearwater Formation on the Birchwood Lease. Data from offsetting operations utilizing SAGD
with well pairs placed in pay with bitumen weight percent similar to those occurring in this
project, within the Clearwater provide a reasonable basis for recovery projections.
5.1.2 Recovery Process Description
The Project will utilize a SAGD process for bitumen recovery by drilling pairs of horizontal wells
near the base of the oil sands net pay. Each well pair comprises of two horizontal wells, which
include an injector placed approximately 5 m directly above the producer, which is placed near
the base of the bitumen zone. The SAGD process involves continuous injection of high quality
steam which heats the reservoir and produces a steam chamber. The latent heat of the
condensing steam is transferred to the sand and bitumen in the formation. The viscosity of the
bitumen drops as the temperature rises. The reduced viscosity allows the bitumen to move
down through the sand matrix to the production well using gravity as the driving force; hence the
term, “Steam Assisted Gravity Drainage”.
Sage Pilot Application Page 71

Because of the presence of bottom water, the lower horizontal producing well will be placed
between 2 - 5 m above the oil-water contact (OWC) to maximize bitumen recovery. The
application of the SAGD process near bottom water in oil sands reservoir requires the careful
monitoring and control of the steam chamber pressure, aquifer pressure and producing
backpressure for optimum production performance.
It is estimated that the viscosity of the bitumen near the bottom water is 3.6MM centipoise (cp)
which will provide a “tar matt” that should limit vertical migration of bottom water. Additionally,
vertical permeability in the Clearwater is substantially lower than horizontal permeability, again
limiting vertical migration of bottom water.
Gas saturation is assumed to be 0 initially, when steam is introduced into the reservoir; solution
gas will be produced that is mainly methane. As the process continues, aquathermolysis occurs
and both CO2 (often in larger amounts than solution gas) and a small amount of H2S are
produced with the solution gas. As the solubility of these products becomes the same in the
water as in the bitumen at steam temperatures, and substantially more water is produced than
bitumen, solution gas, C02 and H2S will also be collected in the water treatment system. All of
the gas produced from either the water or bitumen processing stream is conserved and used as
fuel gas in the boilers.
5.2 SAGD Start-Up Phase
The Clearwater Formation at original reservoir temperature has bitumen with a viscosity of
60,000 cp at the top of the reservoir and as much as 3.6MM cp at the base, and is therefore
immobile around the two wells. Both injector and producer well bores must be heated evenly to
establish oil mobility before injection into the reservoir can commence. During initial cold startup,
attempting to inject steam into a cold formation will cause the steam in the wellbore to
condense and the combination of steam pressure at surface and hydrostatic pressure can
potentially fracture the reservoir leading to bottom water production and communication
between the injection well and the production well near the heel of the injector. This can lead to
undesirable steam distribution and poor steam chamber development. To ensure the well bores
are heated evenly the steam control manifolds will be configured to allow steam to be fed into
any of the wells to accommodate the start-up strategy.
5.2.1 Warm Up/Circulating (60-90 days)
In order to achieve uniform heating along the horizontal sections and the area vertically between
injector and producer, a circulation program of both injector and producer will be deployed.
Steam will initially be circulated in the injection and producing wells during the initial phase.
Circulating is achieved in the well bore by sending steam down the long string located near the
toe and returning steam and condensate to surface through the short string located at the heel,
which will heat up the well bore and adjacent rock formation. Conduction is the main heating
mechanism during the warm up phase. Circulation will continue until inter-well communication is
established at which time the injector well will then be converted to transition SAGD. Start-up
procedures for the proposed well pairs will be similar to that of the latest start-up procedures at
other SAGD operations.
Proposed operating parameters for the circulation phase are summarized below:
• Both injector and producer will be circulated with steam injected into the long production
string and fluid return through short production string.
• Circulating duration to be no less than 90 days with injection rates at 100 - 200 t/d per
well or 200 - 400 t/d per pair.
Sage Pilot Application Page 72

• Target total steam volume of 30,000 – 36,000 m 3 cold water equivalent (CWE) per well
pair at the conclusion of circulation.
• Primary control during circulation is circulation pressure in both injector and producer.
• Proposed circulation pressures will be gradually increased throughout the circulation
phase with a bottom-hole pressure not exceeding 5,000 kPa (maximum).
Operating challenges include accurate and continuous down-hole pressure monitoring, transient
temperature and pressure gradients. These challenges are managed by well sensors for
temperature measurement and by surface gas lift or blanket gas measurement to ensure
continuous, accurate and reliable pressure measurement in the producer and injector.
5.2.2 Transition (30-90 days)
Transition SAGD is achieved by continued steam circulation in the production well and the
injection well is converted to injecting steam into both long and short strings in the reservoir at a
controlled rate with strict management of injection pressures. Transition SAGD results in a
differential pressure applied between the injector and producer, to promote movement of fluid,
as well as heat, between the wells. Start-up steaming operations are maintained until the
bitumen region between the injector well and producer well becomes mobile. The time required
to establish fluid communication is well-pair dependent and relates to:
• injector-to-producer well separation along the horizontal well length;
• inter-wellbore reservoir quality;
• injected steam temperatures; and
• pressure.
Maximum bottom-hole pressure for circulation and transition start-up of a SAGD well pair will be
limited to 5,000kpa. Water volumes injected into and produced from the wells during circulation
will be continuously monitored along with bottom-hole pressures and the total net injection into
the formation.
5.3 Steady State SAGD Operating Phase
After communication has been established between the SAGD injection and production wells,
steam is injected into the injection well at a constant pressure while mobilized oil, condensed
steam, formation water and produced gas are removed from the production well. During this
period the zone of communication between the wells is expanded axially along the full well pair
length and the steam chamber is expected to expand vertically up to the top of the bitumen
zone, at which point lateral growth becomes the dominant mechanism for recovering oil.
Bitumen mobilization predominantly occurs at the boundary of the steam chamber. As the
steam chamber grows and bitumen flow decreases, new well pairs will be required to maintain
consistent production to the facility.
The following are the proposed injection strategies and production control philosophy:
• Steam chamber pressures will be targeted at the range of 3,000 – 3,500 kPa but will not
exceed 5,000 kPa in all injectors with various steam injection rate bias to heel and toe.
• Effective production well sub-cool will be targeted in the range of 0 – 20 o C. Subcool may
vary at different operating stages depending on maturity of steam chamber development.
• Reservoir material balance between fluid production and steam injection will be maintained
by monitoring water production to steam injection ratio (WSR ~1.0).
Sage Pilot Application Page 73

Production from the well pairs will be regularly monitored with a test separator that will measure
oil, water and gas production. A cooling loop will be added to differentiate between produced
gas and steam.
It is anticipated that conventional SAGD operations will be sustained until the optimal amount of
heat has been supplied to the well-pair. When this occurs, it is estimated that 65% of the OOIP,
will have been produced, and the steam injection will be ramped down to zero.
The field operating strategy will be monitored and revised based on temperature and pressure
data collected from instrument strings in the producer and pressure monitoring injection wells.
The data would provide information on steam chamber growth, direction of preferential steam
movement (if any), injector-producer steam distribution and coning and other pertinent
conditions. The information can then be utilized to modify and optimize the SAGD recovery
process for each well pair.
5.3.1 Operating Pressures
Birchwood is planning to operate the steam chamber over a range of bottom hole pressures;
however, there are essentially two pressure conditions: initial pressure (4,000-4,500 kPa) during
the start-up stage to establish the steam chamber, followed by a lower pressure (3,000-3,500
kPa) during the conventional SAGD stage. A complete description of the SAGD stages is
provided in Section 5.2.
5.3.2 Maximum Operating Pressure (“MOP”)
The fracture gradient of the Clearwater capping shale calculated based on offsetting cap rock
integrity testing is 20.9 kPa /m resulting in a calculated closure pressure at 407.35 m GL TVD or
8,514 kPa. The fracture limits of the Clearwater sand measured using injection/fall-off testing is
6,969 kPa at 426.85 m GL TVD. (Section 4.4) It is proposed that 5,000 kPa will be used as
MOP to ensure Clearwater sand formation stress limits are not exceeded.
Zone
Clearwater
Shale
Clearwater
Sand
Depth
m GL
TVD
Gradient
kPaa/m
Closure
Pressure
(“CP”)
kPaa
MOP % of
Closure
Pressure
80%
factor
(kpa)
407.35 20.9 8514 59% 6,811
Source
Offsetting testing &
Depth equal to MPP of
perforated interval
426.85 16.3 6969 72% 5,575 Birchwood FP_06_FO
5.3.3 Potential Follow-up Processes for Improved Recovery
Birchwood is monitoring several industry programs underway to investigate the use of noncondensable
gases to provide additional in-situ bitumen recovery. It is expected that once
steam injection is terminated or reaches uneconomic Steam Oil Ratios, a non-condensable gas
may be injected into the steam chambers to maintain pressure. This activity is subject to ERCB
approval; thus, Birchwood expects to apply for co-injection as required at a later date. During
co-injection, bitumen production continues with operations maintained under the same control
scheme employed in conventional SAGD. Bitumen production rates decline over time as the
growth rate of the steam front slows under gas injection. Available steam is then directed to new
SAGD well pairs.
Sage Pilot Application Page 74

5.4 Reservoir Monitoring
5.4.1 Temperature Measurement
Sensors will be provided to monitor the down-hole operating temperatures in the well bore of
each production and injection well. Fibre-optic temperature cables will be encased in 1” Inconel
coiled tubing for insertion into each well to discretely measure temperature from the toe to the
heel of each producer.
5.4.2 Gas Blanket Pressure Measurement
All wells are equipped with a blanket gas distribution header that will be used to feed a slow
stream of blanket gas into the annulus of each well. The blanket gas will provide a slow
downward sweep of the annulus to provide the following benefits during steam injection:
1. The dry gas provides an insulation effect to substantially reduce heat loss from the
steam injection tubing to the vertical region where formation heating is undesirable,
2. Inhibits transient thermal stresses on the well bore casing and cement sheath,
3. Prevents the accumulation of corrosive gases that could damage the well bore casing,
4. The gas blanket in the injector will also prevent accumulation of corrosive fluids at shutdown
of injection as steam condenses, causes a vacuum and refluxes produced fluids
into the annulus,
5. The gas blanket allows the bottom-hole pressure to be monitored in both producer and
injector using a pressure transmitter on the annulus wing valve,
6. Continuous monitoring of gas volumes and recoveries would also provide an early
warning of intermediate casing failure.
7. In the producing well the blanket gas will also provide gas lift for the short string.
5.4.3 Micro-deformation Monitoring
Micro-deformation monitoring seeks to precisely monitor rock deformation to infer hydraulicfracture
orientation and geometry. Changes in reservoir volumes, such as those produced by
fluid production, injection, and thermal processes such as CSS and SAGD generate unique and
measurable patterns. These patterns can be measured at the earth’s surface with
instrumentation, such as tilt-meters, InSAR, and GPS. In particular, tilt-meters are used to
detect subtle deformation changes to help characterize out-of-zone fluid flow while it can still be
mitigated. The monitoring purpose includes;
1. Risk mitigation, specifically identifying, characterizing, and reporting on fluid migration
before movements can occur,
2. Improve production surveillance, and;
3. Increase operational efficiency.
Birchwood will use a combination of tilt-meters, and InSAR monitoring technology to take
advantage of the strengths and mitigate the weaknesses of each respective technology. Realtime
surveillance is employed to help ensure that Birchwood can identify and react quickly to
undesirable fluid flow and migration.
5.4.4 Observation Wells
Vertical observation wells are planned in order to monitor the formation pressures and
temperatures. The wells will be completed with fibre optic temperature sensors for monitoring
allowing for distribution and retrieval of internal temperature monitoring equipment Birchwood
Sage Pilot Application Page 75

considers that at least one well per well pad leg (12 pairs) within the pattern is sufficient, in
addition to at least one well completed to monitor reservoir pressures per pad (36 pairs).
5.5 Recovery and Original Oil In Place
5.5.1 Original Oil in Place (“OOIP”)
Birchwood defines OOIP as the amount of bitumen resource originally in place from the oil
water contact to the top of the formation, over the designated lease area. Birchwood uses OOIP
as a benchmark for as well as an indicator of resource volumes amenable to recovery, and for
the development planning, sequencing and field optimization of well-pairs. Potential recovery is
based on the actual well-bore geometry (perforated portion of the producer horizontal section
plus 50m at each end).
5.5-1 Original Oil In Place Summary Table
Area Acres
Net Pay
(m)
average
Sw
average Porosity
OOIP
E3M3
Potential
Recovery
E3M3
Potential
Recovery
%
Total Lease Area 1,140 23 35 33 24,037 15,384 64
Resource
Development Area
Pilot Project
(10 wells)
5.5.1.1 Gas Reserves
787 24 35 33 18,301 11,713 64
117 25 35 33 2,918 1,871 64
Any gas recovered (exclusive of by-products of the SAGD process) is assumed to methane
which is in solution in the bitumen at saturation conditions. No gas resource or reserve, either in
place or recoverable, is assumed.
5.5.2 Drilling Constraints and By-passed Pay
The following list details the drilling constraints Birchwood will use for all of its well-pairs
- directional changes in the horizontal section are typically planned at 6-9°/30 m to
minimize drilling and completion difficulties such as liner placement,
- a depth separation of 5 m is used between the injection well and production well,
- the production well must be no closer than 2 meters from the bottom water,
- proposed well profiles will likely be different from final drilled/surveyed trajectories,
- surface casing will be set into a competent formation below the quaternary sands at
approximately 160m,
- a tangent section is built into the heel of the build section to allow for pumps at some
future date,
- horizontal wells will be terminated at the shore-line of Crane Lake to accommodate
stakeholder concerns,
- the combined well pad and CPF will be located approximately 750m from Crane Lake
and approximately 2,000 m from residents to accommodate stakeholders concerns.
Sage Pilot Application Page 76

5.5.2.2 By-passed pay - Crane/Moore Lake
Solely as the result of concerns expressed by the public and residents during the consultation
process, Birchwood has not included plans to access pay located beneath Crane/Moore Lake.
Birchwood believes that the thick layer of Colorado shale and the Clearwater shale above the
affected formation provide an impenetrable barrier between groundwater and the producing
formation and there is virtually no risk of affecting the lake. The by-passed pay results in 1,049
e3m3 of Original Oil In Place not being developed.
5.5.2.3 By-passed pay – 100m boundary
The 100m boundary normally used in the Cold Lake area, largely as a result of high impact CSS
operations utilized to date results in 3,428 e3m3 of Original Oil In Place that is not able to be
developed. Given the high degree of separation from CSS operations in the vicinity of this
project, it is anticipated that this may be relaxed by offset leaseholders in the future. The primary
rationale behind drilling the first 10 well pairs north is to allow only the lake area to constrain
initial recovery. It is Birchwood’s intention to seek strategic partnerships with area operators to
access the entire Clearwater play area and to limit boundaries as much as possible.
5.5.3 Drainage Pattern Layouts
The pattern of well pads and well-pairs was determined by jointly minimizing the SOR and
maximizing the volume swept by the well pad proposed (Figure 5.5.3-1). Overall the elevation
change within the resources development area is minimal. The pattern selected was designed
to achieve a high number of wells from a single pad and minimize surface disturbances (Figure
5.5.3-2).
5.5.4 Well Length and Spacing
Birchwood is expecting to use an inter-pair spacing of approximately 60 m for the initial
implementation of the Project. This spacing is within the optimum range to balance the reserves
developed by a single well-pair and the scheme CSOR. As the spacing is increased, oil
recovered from a single well-pair may increase; however, depletion time also increases,
resulting in additional heat loss and an increase in the CSOR. Additionally, analysis of the Orion
I1P1 well pair, with 4 observation wells near well bore and a lengthy operating history would
indicate that, for the Clearwater formation in this area, lateral heat transfer has been limited.
The optimal horizontal well length will be verified by the different length wells utilized in the initial
layout of the pilot phase. Birchwood estimates that the optimal well length is 800-1,000 m based
on the limited additional time required to drill this section of the well, the absence of drilling
problems with RSS tools, the pressure drop associated with the liner and tubing sizes, and the
high initial cost of well tie-ins of up to 75% of well pair drilling and completion cost.
5.6 Expected Well Performance
The following table summarize the performance of the initial 10 wells proposed based upon
numerical computer simulation and actual wellbore geometry.
Sage Pilot Application Page 77

5.6.1 Typical SAGD Well-Pair Performance
Parameter Unit Well-Pair A1 Well-Pair A10
Well-Pair Length m 1,053 601
Well-Pair Spacing m 60 60
SAGD Pay Thickness m 25 25
Sw % 35 35
Porosity % 33 33
Permeability D 0.5-3 0.5-3
SAGD Operating Pressure Kpa 3,000-3,500 3,000-3,500
Original Oil In Place M 3 364,513 208,242
Expected Recovery M 3 233,597 133,451
Expected Recovery % 64% 64%
Expected Recovery time 9 yrs 9 yrs
CSOR times 3.27 3.27
5.6.2 SAGD Well-Pair A1 Expected Performance Data - 1,053m Effective length
Year
Average Rates (m3/d)
Oil Water Steam
Cumulative Volumes (m3)
Oil Water Steam
Recovery
Factor
(%)
CSOR
(m3/m3)
1 111 243 314 40,352 88,793 114,716 11 2.84
2 99 217 250 76,377 167,988 205,830 21 2.69
3 93 223 235 110,374 249,368 291,651 30 2.64
4 85 223 231 141,311 330,914 375,925 39 2.66
5 66 223 224 165,250 412,239 457,552 45 2.77
6 53 219 216 184,711 492,196 536,521 51 2.90
7 48 214 211 202,405 570,224 613,701 56 3.03
8 44 210 207 218,500 646,743 689,155 60 3.15
9 41 206 203 233,597 721,779 763,126 64 3.27
5.6.3 SAGD Well-Pair A10 Expected Performance Data - 603m Effective length
Year
Average Rates (m3/d) Cumulative Volumes (m3)
Oil Water Steam Oil Water Steam
Recovery
Factor
Sage Pilot Application Page 78
(%)
CSOR
(m3/m3)
1 63 139 180 23,053 50,726 65,536 11 2.84
2 56 124 143 43,633 95,970 117,588 21 2.69
3 53 127 134 63,056 142,461 166,616 30 2.64
4 48 128 132 80,729 189,047 214,761 39 2.66
5 37 127 128 94,405 235,507 261,393 45 2.77
6 30 125 124 105,523 281,185 306,508 51 2.90
7 28 122 121 115,631 325,762 350,599 56 3.03
8 25 120 118 124,826 369,476 393,705 60 3.15
9 24 117 116 133,451 412,343 435,964 64 3.27

5.6.4 SAGD Well-Pairs Expected Pilot Performance Data
Year
Average Rates (m 3 /d) Cumulative Volumes (m 3 )
Oil Water Steam Oil Water Steam
Recovery
Factor
Sage Pilot Application Page 79
(%)
CSOR
(m3/m3)
1 885 1,948 2,517 323,119 711,009 918,590 11 2.84
2 790 1,737 1,999 611,591 1,345,168 1,648,189 21 2.69
3 746 1,785 1,883 883,824 1,996,815 2,335,393 30 2.64
4 679 1,789 1,849 1,131,552 2,649,792 3,010,219 39 2.66
5 525 1,784 1,791 1,323,238 3,301,007 3,663,847 45 2.77
6 427 1,754 1,723 1,479,074 3,941,259 4,296,194 51 2.90
7 388 1,712 1,693 1,620,759 4,566,073 4,914,212 56 3.03
8 353 1,679 1,655 1,749,640 5,178,799 5,518,409 60 3.15
9 331 1,646 1,623 1,870,525 5,779,649 6,110,736 64 3.27
5.6.5 Expected Individual Well Recovery
Well ID
East-
West
Effective
HZ Well
Length
(M)
Original
Oil In
Place
(M3)
Expected
Recovery
(M3)
Recovery
%
A10 601 208,242 133,451 64%
A9 655 226,954 145,442 64%
A8 709 245,659 157,430 64%
A7 763 264,371 169,421 64%
A6 817 283,080 181,411 64%
A5 871 301,792 193,402 64%
A4 925 320,501 205,392 64%
A3 979 339,213 217,383 64%
A2 1,053 364,513 233,597 64%
A1 1,053 364,513 233,597 64%
Total M3 2,918,838 1,870,525 64%
5.7 Results of Numerical Simulation Studies
Numerical simulation, prepared by Dr. John K. Donnolly P.Eng, is being used to model the
SAGD response of the Clearwater sandstone reservoir on Birchwood’s Cold Lake lease. The
purpose of this work is to provide a design basis for a commercial development of the lease.
The model is based on the petrophysical information available on four wells on Birchwood’s
lease and three wells off the lease on surrounding properties. The properties associated with
these seven wells are summarized in Appendix 5.7.A.
5.7.1 Modeling Approach
A three dimensional model was used to model the SAGD performance. The reservoir was
divided into 40 one-meter layers. Porosity and initial water saturation were assigned to each
layer based on petrophysical analysis of logs and cores. Inverse square distance weighting was
used to interpolate the reservoir properties between the wells. An x-y Rectangular grid was
placed over a portion of the lease as shown in Figure 5.7.1, where the x-direction is East-West
and the y-direction is North-South. The horizontal production well was placed approximately two
meters above the oil-water contact. The horizontal injection well was placed five meters above
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
being approximately 100 meters from the lease boundary. The length of the well pair was
approximately 994 meters. This is shown in Figure 5.7.2, which is a North South cross-section
of the Property. Figure 5.7.3 shows an East-West cross-section.
Figures 5.7.2 and Figure 5.7.3 also show that the reservoir quality is fairly uniform across the
property based on water saturation. The other properties show the same result. A refined grid
was placed normal to the wells and large sections of the grid were made inactive to reduce the
active model size as shown in Figure 5.7.4.
Oil properties were determined from measurements taken on samples obtained from the core.
The solution gas was assumed to have the properties similar to methane. The reservoir was
assumed to be initially at 2700 kPa at top of the Clearwater, which is at a depth of
approximately 400 meters, and at a temperature of 16 degress C. The fluid and rock properties
developed from literature values and are given in Appendix 5.7.B.
The relative permeability curves used are typical of those used for other projects exploiting the
Clearwater reservoir such as Husky’s Tucker project and Shell’s Orion project an example of
which is shown in Figure 5.7.5.
It was assumed that the wells would be completed with a 7 inch liner. A skin of 5 was used for
the injector and 15 for the producer. In the model source/sink wells were used. For the first 90
days heater wells were used to approximate steam circulation. After 90 days the wells were
operated in SAGD mode. In the SAGD mode the following constraints were used: For the
injector 95% quality steam was injected at a maximum pressure of 3500 kPa and a maximum
rate of 600 m3 per day and the production well was restricted to a maximum steam production
rate of 20 tonnes per day and minimum operating pressure of 2500 kPa.
5.7.2 Model Production Performance
The forecast oil production rate, water production rate and Instantaneous Steam Oil Ratio
(ISOR) are shown in Figure 5.7.6 from the beginning of SAGD at 90 days to 6000 days (16.4
years). During the first 1330 days (3.6 years) the oil rate starts at over 130 m3 per day (820
BPD) and declines to 80 m3 per day (500 BPD) and the ISOR remains below three. After one
year the development of the SAGD steam chamber is shown in Figure 5.7.7 which illustrates the
phase saturations, the gas saturation, the oil saturation and the temperature distribution normal
to the well pair. The same parameters along the well are shown in Figure 5.7.8. These Figures
indicate that the steam chamber development is fairly uniform along the wells as well as normal
to them. Figure 5.7.9 shows the same parameters at 1330 days. At this time the steam chamber
has grown into the lower quality reservoir near the top of the Clearwater and is approaching the
top of the formation.
After the steam chamber reaches the top of the formation the oil production declines and the
ISOR increases. After 3110 days (8.5 years) the oil production has declined to 40 m 3 per day
(250 BPD) and the ISOR has climbed to five. At this point the steam has expanded to a width of
60 meters as shown in Figure 5.7.10. Based on this it is recommended that SAGD be
terminated when the steam chamber to a width of 60 meters and that a well spacing of 60
meters employed.
Figure 5.7.11 shows the cumulative oil production, water production, liquid production and
Cumulative Steam Oil Ratio (CSOR). At 3110 days the cumulative oil production is 229,000 m 3
(1.44 million barrels) and the CSOR is 3.01.
Sage Pilot Application Page 80

Figure 5.5.3-1 CPF & SAGD Well Pair Layout
T64
T63
Land Layer
10
3
34
Birchwood Lease Area
Development Area
Hydrography
Major
Minor Lake
Minor River
Pad Layout
Wells
Hz well path
Faciity site
Build Section
Well heads
Project Wells
Kilometres
R4 R3W4
11
2
35
0 0.5 1 1.5
0 0.5 1
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
Sage Pilot Application Page 81
12
R4 R3W4
1
36
T64
T63
SAGE Pilot Project
CPF & SAGD Horizontal Well Pairs
By : Jerry Babiuk, P.Geol Date : 2012/09/17
Scale = 1:32493 Project : Cold Lake

Figure 5.5.3-2 SAGD Well Pair Layout & Net Pay
T64
T63
Land Layer
Wells
3
Birchwood Lease Area
Development Area
Project Wells
Hydrography
Major
Minor Lake
Minor River
Pad Layout
Hz Well Path
Facility Site
Build Section
Well Head
20.0m
25.0m
Sage Pilot Application Page 82
30.0m
2
Kilometres
R4 R3W4
30.0m
35.0m
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8
0 0.25 0.5
Miles
25.0m
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
20.0m
15.0m
R4 R3W4
1
SAGE Pilot Project
Initial SAGD Well Pairs
By : Jerry Babiuk, P.Geol Date : 2012/09/27
Scale = 1:17500 Project : Cold Lake
T64
T63

Figure 5.5.3-2 Future Development SAGD Well Pair Layout
T64
T63
Land Layer
Wells
3
100m buffer
34
Birchwood Lease Area
Development Area
Project Wells
Hydrography
Major
Minor Lake
Minor River
Pad Layout
Hz Well Path
Facility Site
Build Section
Well Head
Future Hz Well Path
Future Build Section
100m buffer
35
Sage Pilot Application Page 83
2
100m buffer
Kilometres
0 0.5 1 1.5
R4 R3W4
100m buffer
R4 R3W4
0 0.5 1
Miles
Datum: NAD 83 Spheroid: GRS 80
Projection: 6 degrees TM (Transverse Mercator)
1
36
SAGE Pilot Project
Full Development Plan
By : Jerry Babiuk, P.Geol Date : 2012/09/27
Scale = 1:18000 Project : Cold Lake
T64
T63

Figure 5.7.1 Grid Layout 200x200x40
Well Locations are indicated
Locations K1‐K8 are Lease Boundary Corners
Sage Pilot Application Page 84

Figure 5.7.2 N - S Cross Section Showing Water Saturation and Horizontal Well Locations
Sage Pilot Application Page 85

Figure 5.7.3 E - W Cross Section Showing Water Saturation and Horizontal Well Locations
Sage Pilot Application Page 86

Figure 5.7.4 Refined Grid East‐West Cross‐Section Water Saturation
Sage Pilot Application Page 87

Figure 5.7.5 Gas-Liquid Relative Permeability
Figure 5.7.5 Water-Oil Relative Permeability
Sage Pilot Application Page 88

Figure 5.7.6 Predicted Production Rates
Sage Pilot Application Page 89

Figure 5.7.7 Saturation and Temperature at 1.0 year X Section
Sage Pilot Application Page 90

Figure 5.7.8 Saturation and Temperature at 1.0 Year Well Length
Sage Pilot Application Page 91

Figure 5.7.9 Saturation and Temperature at 3.6 years X Section
Sage Pilot Application Page 92

Figure 5.7.10 Saturation and Temperature at 8.5 years X Section
Sage Pilot Application Page 93

Figure 5.7.11 Predicted Cumulative Production
Sage Pilot Application Page 94

Appendix 5.7.A1 Well Properties 100030206404W400
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv
M M M M avg avg avg mD mD
404.00 398.78 156.74 1.00 1.00 0.5845 0.3365 0.1024 2364.80 1061.30
405.00 399.78 155.74 2.00 1.00 0.4449 0.3632 0.1498 2610.70 1109.84
406.00 400.78 154.74 3.00 1.00 0.4664 0.3895 0.1205 2879.34 1266.19
407.00 401.78 153.74 4.00 1.00 0.4358 0.3818 0.1391 2798.21 1204.42
408.00 402.78 152.74 5.00 1.00 0.4549 0.3830 0.1130 2810.43 1246.39
409.00 403.78 151.74 6.00 1.00 0.4507 0.3769 0.1186 2747.99 1211.09
410.00 404.78 150.74 7.00 1.00 0.4684 0.3678 0.1232 2656.25 1164.52
411.00 405.78 149.74 8.00 1.00 0.5042 0.3436 0.2209 2428.03 945.85
412.00 406.78 148.74 9.00 1.00 0.3832 0.3863 0.0495 2845.49 1352.32
413.00 407.78 147.74 10.00 1.00 0.3239 0.3781 0.0000 2760.18 1380.09
414.00 408.78 146.74 11.00 1.00 0.2842 0.3963 0.0000 2952.43 1476.22
415.00 409.78 145.74 12.00 1.00 0.2461 0.3933 0.0000 2919.90 1459.95
416.00 410.78 144.74 13.00 1.00 0.2481 0.4225 0.0000 3255.03 1627.52
417.00 411.78 143.74 14.00 1.00 0.3362 0.3841 0.0403 2821.85 1354.10
418.00 412.78 142.74 15.00 1.00 0.4397 0.3211 0.2596 2233.26 826.70
419.00 413.78 141.74 16.00 1.00 0.4105 0.3674 0.1186 2652.57 1169.00
420.00 414.78 140.74 17.00 1.00 0.2534 0.4230 0.0000 3260.98 1630.49
421.00 415.78 139.74 18.00 1.00 0.2417 0.3942 0.0000 2929.98 1464.99
422.00 416.78 138.74 19.00 1.00 0.2389 0.3901 0.0000 2886.16 1443.08
423.00 417.78 137.74 20.00 1.00 0.2378 0.4101 0.0000 3108.12 1554.06
424.00 418.78 136.74 21.00 1.00 0.2463 0.4039 0.0000 3038.04 1519.02
425.00 419.78 135.74 22.00 1.00 0.2738 0.3945 0.0000 2932.75 1466.38
426.00 420.78 134.74 23.00 1.00 0.3017 0.4132 0.0000 3144.67 1572.33
427.00 421.78 133.74 24.00 1.00 0.3808 0.4079 0.0000 3083.44 1541.72
428.00 422.78 132.74 25.00 1.00 0.6172 0.3801 0.0000 2780.87 1390.43
429.00 423.78 131.74 26.00 1.00 0.7924 0.3744 0.0000 2722.49 1361.24
430.00 424.78 130.74 27.00 1.00 0.7708 0.3998 0.0000 2991.49 1495.75
431.00 425.78 129.74 28.00 1.00 0.7918 0.3943 0.0000 2931.46 1465.73
432.00 426.78 128.74 29.00 1.00 0.9500 0.3037 0.0000 2092.85 1046.42
433.00 427.78 127.74 30.00 1.00 0.8531 0.3845 0.0000 2826.43 1413.21
434.00 428.78 126.74 31.00 1.00 0.9043 0.3885 0.0000 2868.95 1434.48
435.00 429.78 125.74 32.00 1.00 0.9255 0.3864 0.0000 2846.36 1423.18
436.00 430.78 124.74 33.00 1.00 0.9115 0.3949 0.0000 2937.31 1468.66
437.00 431.78 123.74 34.00 1.00 0.9293 0.3889 0.0000 2872.73 1436.37
438.00 432.78 122.74 35.00 1.00 0.9091 0.3962 0.0000 2951.74 1475.87
439.00 433.78 121.74 36.00 1.00 0.8852 0.4039 0.0000 3037.63 1518.81
440.00 434.78 120.74 37.00 1.00 0.8816 0.4056 0.0000 3056.37 1528.18
441.00 435.78 119.74 38.00 1.00 0.8981 0.3991 0.0000 2983.32 1491.66
442.00 436.78 118.74 39.00 1.00 0.9135 0.3923 0.0000 2909.66 1454.83
443.00 437.78 117.74 40.00 1.00 0.9415 0.3797 0.0000 2776.17 1388.09
444.00 438.78 116.74 41.00 1.00 0.9286 0.3837 0.0002 2818.04 1408.79
445.00 439.78 115.74 42.00 1.00 0.9216 0.3891 0.0000 2875.45 1437.73
446.00 440.78 114.74 43.00 1.00 0.9126 0.3978 0.0124 2969.24 1466.26
447.00 441.78 113.74 44.00 1.00 0.9933 0.2137 0.5025 1498.28 372.73
448.00 442.78 112.74 45.00 1.00 1.0000 0.1682 0.5580 1265.23 279.59
449.00 443.78 111.74 46.00 1.00 1.0000 0.1642 0.5356 1246.27 289.39
450.00 444.78 110.74 47.00 1.00 1.0000 0.2057 0.3648 1454.20 461.85
Sage Pilot Application Page 95

Appendix 5.7.A2 Well Properties 100060206404W400
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSHL Kh Kv
M M M M avg avg avg mD mD
412.00 397.13 155.09 1.00 1.00 0.5363 0.3035 0.26 2091.22 777.07
413.00 398.13 154.09 2.00 1.00 0.4786 0.3301 0.21 2309.22 915.85
414.00 399.13 153.09 3.00 1.00 0.4658 0.3535 0.12 2518.94 1111.94
415.00 400.13 152.09 4.00 1.00 0.4768 0.3315 0.24 2320.79 879.98
416.00 401.13 151.09 5.00 1.00 0.4521 0.3382 0.21 2379.55 940.53
417.00 402.13 150.09 6.00 1.00 0.4661 0.3243 0.25 2259.59 843.94
418.00 403.13 149.09 7.00 1.00 0.5080 0.2903 0.32 1991.58 681.36
419.00 404.13 148.09 8.00 1.00 0.5080 0.3095 0.25 2138.95 805.99
420.00 405.13 147.09 9.00 1.00 0.4303 0.3319 0.24 2324.56 885.55
421.00 406.13 146.09 10.00 1.00 0.3396 0.3760 0.08 2738.81 1259.26
422.00 407.13 145.09 11.00 1.00 0.3142 0.3986 0.05 2977.88 1417.27
423.00 408.13 144.09 12.00 1.00 0.3222 0.3848 0.09 2829.68 1293.84
424.00 409.13 143.09 13.00 1.00 0.3380 0.3795 0.04 2774.58 1329.59
425.00 410.13 142.09 14.00 1.00 0.3712 0.3266 0.22 2278.99 885.30
426.00 411.13 141.09 15.00 1.00 0.4589 0.2760 0.40 1888.50 571.05
427.00 412.13 140.09 16.00 1.00 0.3733 0.3794 0.08 2772.80 1271.74
428.00 413.13 139.09 17.00 1.00 0.2747 0.4037 0.01 3035.68 1499.39
429.00 414.13 138.09 18.00 1.00 0.2733 0.3798 0.00 2777.49 1388.74
430.00 415.13 137.09 19.00 1.00 0.2540 0.3939 0.00 2926.42 1461.13
431.00 416.13 136.09 20.00 1.00 0.2656 0.3935 0.00 2921.87 1460.94
432.00 417.13 135.09 21.00 1.00 0.3077 0.3818 0.00 2797.73 1398.87
433.00 418.13 134.09 22.00 1.00 0.3395 0.3883 0.00 2866.53 1433.26
434.00 419.13 133.09 23.00 1.00 0.4831 0.3945 0.00 2933.05 1466.52
435.00 420.13 132.09 24.00 1.00 0.7083 0.3907 0.00 2891.72 1445.86
436.00 421.13 131.09 25.00 1.00 0.7569 0.3928 0.00 2914.97 1457.48
437.00 422.13 130.09 26.00 1.00 0.7797 0.3917 0.00 2902.59 1451.29
438.00 423.13 129.09 27.00 1.00 0.8219 0.3872 0.01 2855.12 1414.75
439.00 424.13 128.09 28.00 1.00 0.8972 0.3843 0.00 2823.75 1409.53
440.00 425.13 127.09 29.00 1.00 0.9540 0.3690 0.07 2667.58 1245.32
441.00 426.13 126.09 30.00 1.00 0.9502 0.3753 0.04 2731.15 1305.87
442.00 427.13 125.09 31.00 1.00 0.9305 0.3852 0.02 2833.12 1393.15
443.00 428.13 124.09 32.00 1.00 0.9160 0.3942 0.00 2930.08 1462.73
444.00 429.13 123.09 33.00 1.00 0.9326 0.3841 0.02 2821.56 1378.45
445.00 430.13 122.09 34.00 1.00 0.9625 0.3730 0.03 2708.27 1314.78
446.00 431.13 121.09 35.00 1.00 0.9505 0.3807 0.02 2786.60 1359.05
447.00 432.13 120.09 36.00 1.00 0.9474 0.3789 0.06 2768.21 1301.59
448.00 433.13 119.09 37.00 1.00 0.9728 0.3663 0.10 2641.66 1187.87
449.00 434.13 118.09 38.00 1.00 0.9663 0.3806 0.02 2785.85 1358.96
450.00 435.13 117.09 39.00 1.00 0.9613 0.3866 0.00 2848.09 1424.05
451.00 436.13 116.09 40.00 1.00 0.9479 0.3931 0.00 2917.63 1458.81
452.00 437.13 115.09 41.00 1.00 0.9407 0.3937 0.03 2925.03 1415.04
453.00 438.13 114.09 42.00 1.00 0.9367 0.3976 0.01 2966.93 1470.14
454.00 439.13 113.09 43.00 1.00 0.9555 0.3885 0.00 2868.66 1427.56
455.00 440.13 112.09 44.00 1.00 0.9533 0.3883 0.01 2866.33 1417.53
456.00 441.13 111.09 45.00 0.90 0.9791 0.3763 0.05 2741.31 1295.91
456.90 442.13 110.19 46.00 1.10 0.9995 0.2134 0.51 1496.46 366.33
458.00 443.13 109.09 47.00 1.00 1.0000 0.0065 0.96 693.60 12.69
Sage Pilot Application Page 96

Appendix 5.7.A3 Well Properties 100010306404W400
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv
M M M M avg avg avg mD mD
399.00 399.00 156.96 1.00 1.00 0.5585 0.2535 0.3580 1736.72 557.50
400.00 400.00 155.96 2.00 1.00 0.5199 0.3071 0.2158 2119.96 831.28
401.00 401.00 154.96 3.00 1.00 0.5097 0.3160 0.2666 2190.88 803.40
402.00 402.00 153.96 4.00 1.00 0.4855 0.3263 0.2410 2276.68 864.04
403.00 403.00 152.96 5.00 1.00 0.4444 0.3435 0.1301 2426.64 1055.51
404.00 404.00 151.96 6.00 1.00 0.5090 0.2867 0.1312 1965.31 853.74
405.00 405.00 150.96 7.00 1.00 0.4486 0.3325 0.2268 2329.91 900.71
406.00 406.00 149.96 8.00 1.00 0.4731 0.3418 0.2130 2411.84 949.10
407.00 407.00 148.96 9.00 1.00 0.5280 0.3115 0.2788 2154.69 777.02
408.00 408.00 147.96 10.00 1.00 0.5040 0.3212 0.2625 2234.01 823.79
409.00 409.00 146.96 11.00 1.00 0.4357 0.3400 0.2036 2395.19 953.79
410.00 410.00 145.96 12.00 1.00 0.3758 0.3583 0.0287 2564.37 1245.41
411.00 411.00 144.96 13.00 1.00 0.5065 0.2795 0.0000 1912.84 956.42
412.00 412.00 143.96 14.00 1.00 0.4197 0.3412 0.1138 2405.74 1065.93
413.00 413.00 142.96 15.00 1.00 0.5334 0.2843 0.3369 1947.27 645.63
414.00 414.00 141.96 16.00 1.00 0.4991 0.3321 0.2374 2326.37 887.02
415.00 415.00 140.96 17.00 1.00 0.3258 0.3890 0.0207 2874.19 1407.32
416.00 416.00 139.96 18.00 1.00 0.2741 0.3952 0.0012 2940.59 1468.56
417.00 417.00 138.96 19.00 1.00 0.2611 0.3991 0.0006 2984.23 1491.23
418.00 418.00 137.96 20.00 1.00 0.2660 0.3874 0.0208 2856.47 1398.54
419.00 419.00 136.96 21.00 1.00 0.2835 0.3732 0.0000 2709.82 1354.91
420.00 420.00 135.96 22.00 1.00 0.3096 0.3809 0.0000 2788.58 1394.29
421.00 421.00 134.96 23.00 1.00 0.3521 0.3824 0.0000 2804.74 1402.37
422.00 422.00 133.96 24.00 1.00 0.4856 0.3842 0.0000 2823.28 1411.64
423.00 423.00 132.96 25.00 1.00 0.7180 0.3746 0.0075 2723.68 1351.60
424.00 424.00 131.96 26.00 1.00 0.7714 0.3539 0.0238 2522.86 1231.35
425.00 425.00 130.96 27.00 1.00 0.9763 0.1149 0.0000 1037.52 518.76
426.00 426.00 129.96 28.00 1.00 1.0000 0.0630 0.0000 855.66 427.83
427.00 427.00 128.96 29.00 1.00 0.8594 0.3065 0.0065 2115.24 1050.70
428.00 428.00 127.96 30.00 1.00 0.8674 0.3776 0.0183 2754.31 1352.00
429.00 429.00 126.96 31.00 1.00 0.9321 0.3767 0.0130 2745.86 1355.09
430.00 430.00 125.96 32.00 1.00 0.9681 0.3700 0.0000 2678.06 1339.03
431.00 431.00 124.96 33.00 1.00 0.9688 0.3749 0.0012 2727.46 1362.14
432.00 432.00 123.96 34.00 1.00 0.9782 0.3681 0.0267 2659.48 1294.29
433.00 433.00 122.96 35.00 1.00 0.9728 0.3679 0.0196 2656.79 1302.41
434.00 434.00 121.96 36.00 1.00 0.9902 0.3671 0.0164 2648.99 1302.82
435.00 435.00 120.96 37.00 1.00 0.9788 0.3709 0.0009 2686.76 1342.18
436.00 436.00 119.96 38.00 1.00 0.9726 0.3720 0.0056 2698.13 1341.51
437.00 437.00 118.96 39.00 1.00 0.9770 0.3770 0.0329 2748.55 1329.11
438.00 438.00 117.96 40.00 1.00 0.9650 0.3840 0.0224 2821.27 1378.99
439.00 439.00 116.96 41.00 1.00 0.9821 0.3782 0.0248 2760.37 1345.95
440.00 440.00 115.96 42.00 1.00 0.9571 0.3890 0.0071 2873.90 1426.72
441.00 441.00 114.96 43.00 1.00 0.9663 0.3837 0.0289 2817.37 1368.02
442.00 442.00 113.96 44.00 1.00 0.9935 0.3642 0.0640 2620.77 1226.57
443.00 443.00 112.96 45.00 1.00 0.9934 0.3653 0.0499 2631.95 1250.32
444.00 444.00 111.96 46.00 1.00 0.9963 0.3708 0.0303 2686.03 1302.32
445.00 445.00 110.96 47.00 1.00 0.9546 0.3954 0.0010 2942.87 1470.03
446.00 446.00 109.96 48.00 1.00 0.9783 0.3804 0.0360 2783.50 1341.63
447.00 447.00 108.96 49.00 1.00 0.9850 0.3762 0.0312 2740.39 1327.49
453.00 453.00 102.96 55.00 1.00 0.9927 0.3633 0.0216 2612.20 1277.89
454.00 454.00 101.96 56.00 1.00 0.9965 0.3588 0.0468 2569.22 1224.48
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Appendix 5.7.A4 Well Properties 100050106404W400
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv
M M M M avg avg avg mD mD
401.20 397.54 155.50 1.00 1.00 0.5012 0.2834 0.3035 1940.96 675.91
402.20 398.54 154.50 2.00 1.00 0.4792 0.3486 0.1560 2473.15 1043.69
403.20 399.54 153.50 3.00 1.00 0.5436 0.3547 0.1475 2529.94 1078.38
404.20 400.54 152.50 4.00 1.00 0.5193 0.3546 0.1286 2528.75 1101.73
405.20 401.54 151.50 5.00 1.00 0.4695 0.3535 0.1283 2518.35 1097.56
406.20 402.54 150.50 6.00 1.00 0.4832 0.3589 0.0538 2569.74 1215.71
407.20 403.54 149.50 7.00 1.00 0.4618 0.3271 0.0139 2283.38 1125.78
408.20 404.54 148.50 8.00 1.00 0.4416 0.3557 0.0817 2539.71 1166.05
409.20 405.54 147.50 9.00 1.00 0.4323 0.3785 0.0798 2764.29 1271.89
410.20 406.54 146.50 10.00 1.00 0.4201 0.3671 0.1153 2649.62 1172.06
411.20 407.54 145.50 11.00 1.00 0.4344 0.3501 0.1541 2486.98 1051.90
412.20 408.54 144.50 12.00 1.00 0.4373 0.4028 0.0435 3025.65 1446.96
413.20 409.54 143.50 13.00 1.00 0.3968 0.3906 0.0259 2890.65 1407.84
414.20 410.54 142.50 14.00 1.00 0.3900 0.3582 0.0081 2562.72 1271.04
415.20 411.54 141.50 15.00 1.00 0.4861 0.3152 0.1282 2184.60 952.32
416.20 412.54 140.50 16.00 1.00 0.3333 0.3679 0.1003 2656.79 1195.14
417.20 413.54 139.50 17.00 1.00 0.3127 0.3814 0.0000 2793.86 1396.93
418.20 414.54 138.50 18.00 1.00 0.2952 0.3938 0.0000 2925.23 1462.61
419.20 415.54 137.50 19.00 1.00 0.3192 0.3871 0.0000 2853.39 1426.69
420.20 416.54 136.50 20.00 1.00 0.3463 0.3981 0.0000 2973.16 1486.58
421.20 417.54 135.50 21.00 1.00 0.3957 0.3935 0.0000 2922.27 1461.13
422.20 418.54 134.50 22.00 1.00 0.6379 0.3946 0.0000 2933.94 1466.97
423.20 419.54 133.50 23.00 1.00 0.7611 0.3998 0.0000 2992.10 1496.05
424.20 420.54 132.50 24.00 1.00 0.8048 0.3889 0.0000 2873.32 1436.66
425.20 421.54 131.50 25.00 1.00 0.8124 0.3844 0.0032 2825.09 1408.06
426.20 422.54 130.50 26.00 1.00 0.8181 0.3812 0.0000 2791.41 1395.70
427.20 423.54 129.50 27.00 1.00 0.8656 0.3726 0.0000 2704.33 1352.17
428.20 424.54 128.50 28.00 1.00 0.8932 0.3644 0.0291 2622.45 1273.13
429.20 425.54 127.50 29.00 1.00 0.8670 0.3760 0.0099 2737.98 1355.41
430.20 426.54 126.50 30.00 1.00 0.8276 0.3504 0.0000 2489.50 1244.75
431.20 427.54 125.50 31.00 1.00 0.8847 0.3134 0.0268 2170.33 1056.10
432.20 428.54 124.50 32.00 1.00 0.9779 0.2169 0.4003 1515.80 454.53
433.20 429.54 123.50 33.00 1.00 0.8837 0.3198 0.1365 2222.49 959.56
434.20 430.54 122.50 34.00 1.00 0.8011 0.3832 0.0252 2812.99 1371.05
435.20 431.54 121.50 35.00 1.00 0.8249 0.3669 0.0322 2647.56 1281.11
436.20 432.54 120.50 36.00 1.00 0.8783 0.2757 0.1244 1886.08 825.75
437.20 433.54 119.50 37.00 1.00 0.9021 0.2576 0.2291 1763.26 679.63
438.20 434.54 118.50 38.00 1.00 0.8676 0.2491 0.3319 1708.84 570.81
439.20 435.54 117.50 39.00 1.00 0.8972 0.1234 0.6549 1071.04 184.81
440.20 436.54 116.50 40.00 1.00 0.9713 0.0061 0.9796 692.60 7.07
441.20 437.54 115.50 41.00 1.00 1.0000 0.0000 1.0000 677.05 0.00
442.20 438.54 114.50 42.00 1.00 0.9922 0.0059 0.9787 691.94 7.35
443.20 439.54 113.50 43.00 1.00 0.8820 0.0805 0.7078 913.04 133.37
444.20 440.54 112.50 44.00 1.00 0.8873 0.1819 0.4056 1331.01 395.55
445.20 441.54 111.50 45.00 1.00 0.7620 0.2712 0.0884 1854.92 845.52
446.20 442.54 110.50 46.00 1.00 0.7698 0.3121 0.0006 2159.80 1079.28
447.20 443.54 109.50 47.00 1.00 0.8633 0.3314 0.0035 2319.93 1155.92
448.20 444.54 108.50 48.00 1.00 0.8581 0.3456 0.0006 2445.90 1222.25
449.20 445.54 107.50 49.00 1.00 0.7717 0.2028 0.4948 1438.56 363.39
450.20 446.54 106.50 50.00 1.00 0.6194 0.0506 0.9121 817.27 35.90
451.20 447.54 105.50 51.00 1.00 0.6758 0.0542 0.8890 828.27 45.99
452.20 448.54 104.50 52.00 1.00 0.9609 0.0047 0.9927 689.10 2.52
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Appendix 5.7.A5 Well Properties 102062606304W400
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv
M M M M avg avg avg mD mD
381.00 413.04 171.00 1.00 1.00 0.8904 0.2600 0.3073 1779.30 616.27
382.00 414.04 170.00 2.00 1.00 0.7428 0.3093 0.1878 2137.00 867.82
383.00 415.04 169.00 3.00 1.00 0.6460 0.3208 0.1733 2230.47 922.01
384.00 416.04 168.00 4.00 1.00 0.5467 0.3402 0.1280 2397.38 1045.21
385.00 417.04 167.00 5.00 1.00 0.5146 0.3415 0.1326 2408.67 1044.67
386.00 418.04 166.00 6.00 1.00 0.5357 0.3341 0.1293 2343.80 1020.33
387.00 419.04 165.00 7.00 1.00 0.5845 0.3087 0.2030 2132.17 849.66
388.00 420.04 164.00 8.00 1.00 0.5366 0.3239 0.1606 2256.08 946.90
389.00 421.04 163.00 9.00 1.00 0.4789 0.3126 0.1529 2163.89 916.54
390.00 422.04 162.00 10.00 1.00 0.4151 0.3559 0.0632 2541.68 1190.57
391.00 423.04 161.00 11.00 1.00 0.3436 0.3644 0.0000 2623.25 1311.63
392.00 424.04 160.00 12.00 1.00 0.3480 0.3643 0.0000 2621.83 1310.92
393.00 425.04 159.00 13.00 1.00 0.3849 0.3401 0.0090 2396.33 1187.37
394.00 426.04 158.00 14.00 1.00 0.4328 0.2870 0.1162 1967.30 869.35
395.00 427.04 157.00 15.00 1.00 0.4408 0.3192 0.1891 2217.39 898.99
396.00 428.04 156.00 16.00 1.00 0.4794 0.3317 0.1626 2322.44 972.35
397.00 429.04 155.00 17.00 1.00 0.5420 0.2941 0.1755 2019.50 832.53
398.00 430.04 154.00 18.00 1.00 0.4076 0.3409 0.0963 2403.87 1086.23
399.00 431.04 153.00 19.00 1.00 0.3929 0.3533 0.0584 2516.81 1184.90
400.00 432.04 152.00 20.00 1.00 0.5178 0.2447 0.0442 1681.01 803.38
401.00 433.04 151.00 21.00 1.00 0.3469 0.3515 0.1139 2499.70 1107.51
402.00 434.04 150.00 22.00 1.00 0.3797 0.3401 0.1316 2396.08 1040.39
403.00 435.04 149.00 23.00 1.00 0.4768 0.3489 0.0639 2475.74 1158.74
404.00 436.04 148.00 24.00 1.00 0.5083 0.3475 0.0365 2462.98 1186.60
405.00 437.04 147.00 25.00 1.00 0.5038 0.3459 0.0523 2448.13 1160.09
406.00 438.04 146.00 26.00 1.00 0.4959 0.3318 0.0983 2323.38 1047.50
407.00 439.04 145.00 27.00 1.00 0.5269 0.3363 0.0914 2363.12 1073.60
408.00 440.04 144.00 28.00 1.00 0.5449 0.3431 0.0748 2423.11 1120.99
409.00 441.04 143.00 29.00 1.00 0.5165 0.3168 0.1656 2197.93 916.93
410.00 442.04 142.00 30.00 1.00 0.4841 0.3349 0.1136 2350.54 1041.79
411.00 443.04 141.00 31.00 1.00 0.4751 0.3307 0.1506 2313.90 982.66
412.00 444.04 140.00 32.00 1.00 0.5180 0.3278 0.1693 2289.64 950.96
413.00 445.04 139.00 33.00 1.00 0.5470 0.3024 0.2769 2083.04 753.17
414.00 446.04 138.00 34.00 1.00 0.6000 0.2836 0.2942 1942.80 685.58
415.00 447.04 137.00 35.00 1.00 0.6376 0.2985 0.1351 2053.21 887.91
416.00 448.04 136.00 36.00 1.00 0.7112 0.3025 0.0736 2083.46 965.11
417.00 449.04 135.00 37.00 1.00 0.7903 0.3109 0.1605 2149.97 902.40
418.00 450.04 134.00 38.00 1.00 0.9684 0.2418 0.3258 1663.16 560.61
419.00 451.04 133.00 39.00 1.00 0.9858 0.1787 0.4588 1315.54 356.01
420.00 452.04 132.00 40.00 1.00 0.9108 0.0406 0.8321 787.42 66.11
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Appendix 5.7.A6 Well Properties 102062406304W400
DEPT Ref TDE Sub Sea Layer Thickness Sw Phie VSH Kh Kv
M M M M avg avg avg mD mD
421.90 401.67 159.63 1.00 1.00 0.8490 0.1815 0.5291 1329.34 312.97
422.90 402.67 158.63 2.00 1.00 0.5801 0.2969 0.2366 2040.69 778.88
423.90 403.67 157.63 3.00 1.00 0.5177 0.3478 0.1473 2465.73 1051.32
424.90 404.67 156.63 4.00 1.00 0.4640 0.3953 0.0070 2942.38 1460.92
425.90 405.67 155.63 5.00 1.00 0.4293 0.4015 0.0000 3010.76 1505.38
426.90 406.67 154.63 6.00 1.00 0.4276 0.3759 0.0000 2737.52 1368.76
427.90 407.67 153.63 7.00 1.00 0.4123 0.3820 0.0000 2799.81 1399.91
428.90 408.67 152.63 8.00 1.00 0.3947 0.3767 0.0000 2745.67 1372.84
429.90 409.67 151.63 9.00 1.00 0.3955 0.3823 0.0000 2803.32 1401.66
430.90 410.67 150.63 10.00 1.00 0.3746 0.3903 0.0000 2887.43 1443.71
431.90 411.67 149.63 11.00 1.00 0.3443 0.4094 0.0000 3100.04 1550.02
432.90 412.67 148.63 12.00 1.00 0.3903 0.3561 0.0000 2543.23 1271.61
433.90 413.67 147.63 13.00 1.00 0.3781 0.3454 0.0000 2444.33 1222.16
434.90 414.67 146.63 14.00 1.00 0.3551 0.3890 0.0000 2874.38 1437.19
435.90 415.67 145.63 15.00 1.00 0.3541 0.3957 0.0000 2945.86 1472.93
436.90 416.67 144.63 16.00 1.00 0.3418 0.4030 0.0046 3026.87 1506.47
437.90 417.67 143.63 17.00 1.00 0.3656 0.3790 0.0024 2769.24 1381.26
438.90 418.67 142.63 18.00 1.00 0.3463 0.3904 0.0000 2889.18 1444.59
439.90 419.67 141.63 19.00 1.00 0.3444 0.4013 0.0000 3008.83 1504.41
440.90 420.67 140.63 20.00 1.00 0.3700 0.4008 0.0000 3002.83 1501.42
441.90 421.67 139.63 21.00 1.00 0.3804 0.3865 0.0000 2847.80 1423.90
442.90 422.67 138.63 22.00 1.00 0.3873 0.3928 0.0000 2914.38 1457.19
443.90 423.67 137.63 23.00 1.00 0.4310 0.3868 0.0000 2850.88 1425.44
444.90 424.67 136.63 24.00 1.00 0.4784 0.3802 0.0035 2781.81 1386.06
445.90 425.67 135.63 25.00 1.00 0.5040 0.3854 0.0000 2835.80 1417.90
446.90 426.67 134.63 26.00 1.00 0.5241 0.3755 0.0248 2733.73 1333.02
447.90 427.67 133.63 27.00 1.00 0.5429 0.3830 0.0029 2811.00 1401.44
448.90 428.67 132.63 28.00 1.00 0.5436 0.3965 0.0627 2954.63 1384.67
449.90 429.67 131.63 29.00 1.00 0.5974 0.3803 0.0541 2782.75 1316.10
450.90 430.67 130.63 30.00 1.00 0.7168 0.3848 0.0000 2829.10 1414.55
451.90 431.67 129.63 31.00 1.00 0.8029 0.3808 0.0000 2787.54 1393.77
452.90 432.67 128.63 32.00 1.00 0.7774 0.3711 0.0156 2689.12 1323.52
453.90 433.67 127.63 33.00 1.00 0.7372 0.3499 0.1441 2485.63 1063.68
454.90 434.67 126.63 34.00 1.00 0.8346 0.3231 0.1793 2249.31 923.00
455.90 435.67 125.63 35.00 1.00 0.9153 0.2739 0.3091 1873.44 647.14
456.90 436.67 124.63 36.00 1.00 0.8893 0.2968 0.2787 2040.14 735.79
457.90 437.67 123.63 37.00 1.00 0.8825 0.3267 0.1479 2279.76 971.26
458.90 438.67 122.63 38.00 1.00 0.9404 0.2715 0.3273 1856.87 624.54
459.90 439.67 121.63 39.00 1.00 0.8972 0.2824 0.3066 1933.76 670.42
460.90 440.67 120.63 40.00 1.00 0.9143 0.2960 0.2048 2034.29 808.82
461.90 441.67 119.63 41.00 1.00 0.8495 0.3589 0.0471 2570.18 1224.57
462.90 442.67 118.63 42.00 1.00 0.9376 0.2591 0.3685 1773.48 559.94
463.90 443.67 117.63 43.00 2.00 0.9977 0.1844 0.5374 1343.66 310.76
465.90 444.67 115.63 44.00 1.00 0.9804 0.2019 0.5084 1433.66 352.40
466.90 445.67 114.63 45.00 1.00 0.9657 0.2179 0.4532 1521.44 415.93
467.90 446.67 113.63 46.00 1.00 0.9929 0.1781 0.5256 1312.39 311.32
468.90 447.67 112.63 47.00 1.00 0.9652 0.2026 0.4895 1437.78 366.99
469.90 448.67 111.63 48.00 1.00 0.9947 0.2095 0.2683 1474.98 539.61
470.90 449.67 110.63 49.00 1.00 0.9245 0.2485 0.2857 1704.63 608.78
471.90 450.67 109.63 50.00 1.00 0.9483 0.2253 0.4484 1564.23 431.45
472.90 451.67 108.63 51.00 1.00 0.9869 0.2243 0.3876 1558.06 477.11
473.90 452.67 107.63 52.00 1.00 0.9736 0.2501 0.3094 1715.08 592.26
474.90 453.67 106.63 53.00 1.00 0.9026 0.3002 0.1917 2066.36 835.15
475.90 454.67 105.63 54.00 2.00 0.9559 0.2405 0.3472 1654.69 540.08
Sage Pilot Application Page 100

Sample
Depth
(m)
Appendix 5.7.B1 Rock Grid Properties
PARAMETER VALUE
ROCK HEAT CAPACITY kJ/m3/oK 2350
ROCK COMPRESSIBILITY v/v/kPa 4.50E‐07
THERMAL CONDUCTIVITY kJ/D‐m‐oK 150
INITIAL DATUM PRESSURE kPa 2700
DATUM DEPTH metres 400
GAS‐OIL CONTACT DEPTH metres 400
WATER‐OIL CONTACT DEPTH metres 440
INITIAL GAS SATURATION 0
INITIAL RESERVOIR TEMPERATURE deg C 16
Appendix 5.7.B2 Measured Viscosity and Density
Gushor
Analysis
Date
Measured Oil Viscosity (cP) Density API Gravity
25°C 35°C 45°C Measured
Temp °C
@
Measured
Temp
@ 15°C
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
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
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
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
Appendix 5.7.B3 Extrapolated Viscosity used in Model
Temperature ( C ) Viscosity (cP)
10 5907393.819
20 1270709.017
30 302499.0365
40 78924.47301
50 22377.59489
60 6843.481463
70 2242.486234
80 782.751522
90 289.5293193
100 112.95663
120 19.84885948
140 4.127369795
160 0.992195926
180 0.270500421
200 0.082310492
220 0.027583772
240 0.010066137
260 0.003962029
280 0.001668228
300 0.000746123
@
15°C
@
20°C
Sage Pilot Application Page 101
@
60°F

6 Drilling and Completions
6.1 Overview
The well pad will be contiguous with the producing facilities pad which will also include source
water wells for start-up and for domestic purposes, brackish source water for steam generation
from the McMurray sand and a Granite Wash salt water disposal well. The well pad is designed
to accommodate up to 36 well pairs in the Clearwater Formation.
Based on the high quality of the Clearwater formation under this lease, it is anticipated that
SAGD will result in recovery factors of 65% or more of the oil in place. SAGD is a continuous
process that minimizes thermal stress on the well bores by eliminating the need for continuous
heating and cooling cycles. Reservoir integrity is preserved by continuously injecting low
pressure steam below reservoir fracture pressure. The horizontal well spacing reduces the
number of wells and surface pads required for the project full development, resulting in less land
disturbance and fewer environmental impacts. Surface facilities will be required to distribute
steam, gather and test well production, process oil and emulsions, treat water for maximum
recycle and generate steam.
The SAGD process involves drilling pairs of horizontal wells with both the producer and injector
well bores located in high enough oil saturation to economically initiate effective SAGD. The
producer horizontal well bore will be placed near the base of the effective pay using rotary
steerable directional tools and logging while drilling tools to ensure competent formation and
limit sinuosity in the well bore. Proper well placement is crucial to the project. In order to achieve
proper well placement in the producing well a resistivity tool will be used to keep the well bore in
effective pay and above the Clearwater high water saturation line. The producer well will be
positioned approximately 2-5 meters above the bitumen/water interface to avoid interference of
formation water with the SAGD process. The second well of the pair that will be drilled is the
injector. Its purpose is to inject high quality steam into the formation. This horizontal portion of
the injector well will be drilled using measurement while drilling tools and a mud motor along
with a ranging tool run in the accompanying producer well bore which will allow a very accurate
trajectory again minimizing sinuosity and maintaining a consistent offset above the already
drilled producer of approximately 5m.
Dual tubing strings will be installed in both the injector and producer to both the toe and heel of
each well to accommodate circulation while pre-heating and to optimize both injection of steam
and production of emulsion.
Natural gas will be injected into the injector annulus with a minimum flow into short tubing string
in order to provide both a bottom-hole pressure measurement and to ensure that there is a gas
blanket in the annulus for all of thermal insulation, leak detection and corrosion protection in the
event of a shut- down of steam injection.
The producer well will be equipped with an Inconel coil tubing string to the toe of the well inside
the long tubing string with fibre optic cable to discretely measure temperatures along the well
bore. Natural gas will be injected into the producer annulus with a minimum flow into the short
tubing string in order to provide both a bottom-hole pressure measurement and to ensure that
there is a gas blanket in the annulus for thermal insulation, leak detection, prevent pitting in the
tubing resulting from flashing to steam and corrosion protection in the event of a shut- down.
Wellheads, casing, tubing and other down-hole equipment as well as surface equipment will be
designed for sour service. Use of gas lift and gas blankets will substantially protect those
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components associated with test production from corrosion and corrosion allowance, at or
beyond, specifications as set out by the ERCB.
6.2 Well Pad Layout
Birchwood plans to use existing clearings for the production facility and well pad sites in order to
minimize the overall footprint of the project as indicated in Figure 1.5-1.
The well pad(s) will be directly adjacent to the CPF pad as shown in Figure 7.1.1 CPF & SAGD
Well Pair Layout. In selecting the production facility/well pad, consideration was given to surface
topography, surface hydrology and area wetlands, distance from Crane Lake, regional and
ERCB setback requirements, access, steam line traverse route, and reservoir characteristics.
The selected location of the pad will minimize impact on other area activities, environmental
disturbance and optimize bitumen recovery.
On surface the wellhead spacing will be 7m between the well pairs and offset 20m between
injector and producer to ensure sufficient room for test separator and header buildings as shown
in Figure 6.2-1 well configuration and spacing & Figure 6.2-2 3D model of well configuration.
Horizontal well spacing will be at 60m inter-well spacing.
The horizontal section of the producers and injectors will be drilled as noted above and will vary
in length in accordance with surface proximity to the Crane Lake. In order to avoid drilling
underneath the lake the horizontal leg will be stopped short of the lake. Of the ten pilot wells the
maximum horizontal well path is 952 m and the shortest horizontal well path is 501 m as shown
in Figure 6.2-1.
The well pad will be constructed to contain surface water for testing, and treatment in
accordance with regulatory requirements.
6.2.1 Drilling SAGD Well Pairs
Due to the presence of bottom water, the lower producing wells will be placed 2-5 m above the
oil-water contact (“OWC”) to limit the influence of bottom water.
The application of SAGD technology in a reservoir with bottom water will require careful
monitoring of the steam chamber pressure, aquifer pressure and producing backpressure for
optimum well performance. Monitoring of the well bores, including pressure and steam chamber
development is addressed in Section 5.4.
The SAGD wells will have surface, intermediate and horizontal sections and both surface and
intermediate casing strings will be thermally cemented and bond logged. Batch drilling is
proposed to optimize drilling and to allow sufficient time for cement to cure prior to bond logging.
Surface casing of the producing well will be landed in competent shale at approximately 160m
and the intermediate casing will be landed at a true vertical depth of approximately 427 mTVD.
Surface casing of the injection well will also be landed at approximately 160 m and the
intermediate casing will be landed at a true vertical depth of approximately 422 mTVD.
Production wells will be drilled first using Measurement While Drilling (“MWD”) tools and a mud
motor for the build section to TD of the intermediate hole, then Rotary Steerable directional
drilling (“RSS”) technology for the horizontal section. In addition a gamma ray and resistivity
Logging While Drilling (“LWD”) tool will be used as set out above to manage both offset from
bottom water and well trajectory. Given the importance of accurate horizontal well placement on
reservoir recovery, Birchwood will be generating a magnetic survey of the area for In-Field
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Referencing (“IFR”) MWD tool correction purposes, using observatory data to generate IFR for
diurnal corrections, performing Multi-Station Analysis (“MSA”) continuously and roll tests on a
regular basis to ensure accurate well placement. The Cold Lake area is fortunate to have actual
Observatory data available nearby that will improve the accuracy of diurnal corrections.
Injector wells will be drilled after the production wells and will utilize the MWD tools and mud
motor for both the build section and the horizontal section of the well. A magnetic tracer system
(or ranging tool) will be run in the offset production well to maintain a constant specified vertical
separation between the producer and its associated injection well. The specified separation
target is 5.0 m with a deviation tolerance of 0.5 m.
Well head design for typical SAGD wells are shown in Figures 6.1.1-1 and Figure 6.1.1-2.
Wellhead specifications are AP6A, LY, DD-NL, PR-1, PSL1 rated at 9860 kPa at 343C trim for
exposure to high pressure/high temperature fluids. High temperature swivel joints will be used
for wellhead connection flanges to all injection and production flow lines to allow for thermal
expansion of the wellhead components without stressing the flow lines.
6.2.2 Surface Section
Surface sections/holes for both the injection and production wells will be batch drilled and
339.7mm, 81.1kg/m, Grade J-55 surface casing and an appropriate float equipment package
will be set at approximately 160m and cemented with thermal cement. A cement bond log will
be run to confirm both cement integrity and fall back, if any. Fall back will be top cemented to
ensure that the entire interval is protected. The depth of groundwater protection is 160m.
6.2.3 Intermediate or Build Section
Drilling of the intermediate hole for the producer wells will be on a batch basis with a drilling rig
equipped with a top drive. The bottom-hole assembly (“BHA”) for the intermediate hole on the
producer wells drilled on the Birchwood well pad will be equipped with RSS and LWD tools as
set out above.
Drilling of the intermediate hole for the injector wells will also be on a batch basis with a drilling
rig equipped with a top drive. The injector well BHA will set up with MWD tools, a mud motor
and LWD tools as well as a ranging tool run in the offset producer of the pair in order to range
5m away from the producer well drilled lower in the Clearwater formation.
Kick off Point (“KOP”) depth where directional drilling will commence for both producer and
injector wells will be at approximately 190m. A tangent section will be built at or near horizontal
in the producer well bore to allow for running pumps in the future.
Depending on the surface location of each well and landing point of each intermediate casing
point the doglegs in the build section will vary on each wellbore. The wells will be drilled at a
build rate of approximately 7.0 degrees to 9.25 degrees per 30.0m. In order to further assess
the reservoir quality and saturation a gamma ray and azimuthal direction resistivity will be run in
conjunction with the RSS and MWD tools. Two experienced horizontal well-site Geologists will
be on site 24hrs a day that will work closely with the directional drillers and well-site supervisors
on site. The Geologists will monitor the gamma ray response, directional well path, drill cuttings,
and penetration rate to assess the path of the intermediate casing landing point and well path of
the horizontal well.
Designs for the intermediate casing will be the same for the injection and producer wells.
244.5mm, 59.53kg/m, Grade L-80 intermediate casing with appropriate high strength thermal
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grade couplings torqued to strict specifications and with an appropriate centralization package
will be set at approximately 750m MD and cemented with thermal cement.
6.2.4 Horizontal Section
The horizontal length of the wellbore will be dependent on each of the individual landing points
from each well drilled off the Birchwood pad site and the distance from there to lakeshore of
Crane Lake. Every well pair drilled will have a different measured depth based on the different
lengths of each build section. The true vertical depth should be relatively consistent over the
RDA and in the producing wells will be approximately 426m true vertical depth and the injectors
will be at a true vertical depth of 421.7m.
Once the horizontal wells are drilled each of the open-hole horizontal sections will be lined with
177.8mm, 43.16kg/m, Grade L-80 casing also equipped with appropriate high strength thermal
grade couplings torqued to strict specifications and a stainless steel bullnose. The liner will be
set approximately 10m short of TD, will overlap intermediate casing by approximately 30m, and
be landed in the intermediate casing with a high temperature pack off assembly.
Experience in the area from IOL, Shell and Husky indicates that sand production has not been
an issue in the Clearwater near Cold Lake. Fines production combined with Calcium Carbonate
and bitumen released by pressure drop across slotted liners in producing wells has been an
issue. Plugging of production liners often occurs over time. Acid and/or EDTA treatments have
had limited success, but pulling liners (IOL) and perforating liners (Husky and Shell) all without
significant sand production has had long term success in resolving the plugging issue. The
nature of the reservoir with its higher clay contents and lithic fragments appears to consolidate
the formation over time after steaming without significantly affecting flow rates or producing
sand. Based on this, a liner design that maximizes open flow without allowing sand production
early in the life of the well before consolidation occurs appears to the optimal solution.
Producer wells will be lined with a perforated base pipe equipped with wire-wrapped screen
utilizing 7 micron spacing to minimize sand production early in the well life and both maximize
open flow area and limit plugging during the producer well life. A single blank joint and two blank
joints will be installed at the toe and heel, respectively. Perforations will be designed to
maximize torque capacity for liner installation. Injector wells will be lined with base pipe slotted
utilizing 24 micron keystone slots. A single blank joint and two blank joints will be installed at the
toe and heel, respectively. The liner perforations, wire wrap spacing, slot size, material strength
and size are engineered to optimize both steam injection and emulsion production, to control the
production of solids, and maintain well bore integrity.
6.3 Completions
6.3.1 Production Well Completion
Dual tubing strings will be inserted into the well. The secondary or short string will be 73mm
tubing to the heel of the well above the 177.8mm liner with a 60.3mm “stinger” landed inside the
liner just before the first perforations. Gas injection ports will be installed at slightly above TVD
to allow small amounts of gas injection for both bottom hole pressure measurement and to
provide a gas blanket in the annulus of the producer well bore. The primary or long string will be
88.9mm tubing and will be landed at the toe of the well just past the perforations. Fibre optic
cable sensors will be installed in each wellbore to monitor the down-hole operating temperature.
The fibre optic cable sensors will be encased in 1” Inconel coiled tubing for insertion into the
long string of each well. The coil tubing string will be equipped with gas ports to provide gas lift
and to limit tubing damage from produced water flashing to steam. Figure 6.3.1 provides a
schematic of the well bore completion for production wells.
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As noted above, a tangent section will be designed into the intermediate well path. This will be
done so that, in the future, a mechanical lift system may be installed. Birchwood would notify the
Board should this be the case and request an amendment to the scheme (if approved). Briefly,
a service rig will be brought in to convert the well to a mechanical artificial lift system. The short
and long string tubing will be removed from the well. Either an Electric Submersible Pump (ESP)
or a metal-to-metal Progressive Cavity Pump (PCP) will be run on the 88.9 mm tubing to the
tangent section depending on flow rate and absence of sand. A pump suction “stinger” string
may also be attached to the pump to draw the produced fluids evenly throughout the liner. Gas
would still be injected into the annulus to provide a gas blanket and also at the wellhead to dilute
corrosive produced gas in surface flow-lines.
6.3.2 Injection Well Completion
Dual tubing strings will be inserted into the well. The secondary or short string will be 73mm
tubing to the heel of the well above the 177.8mm liner with a 60.3mm “stinger” landed inside the
liner at just before the first perforations. Gas injection ports will be installed at slightly above
TVD to allow small amounts of gas injection for both bottom hole pressure measurement and to
provide a gas blanket in the annulus of the injector well bore. The primary or long string will be
88.9mm tubing and will be landed at the toe of the well just past the perforations. No additional
instrumentation will be run. Figure 6.3.2 provides a well bore completion schematic for the
injection wells.
At all times the steam pressure in the steam chamber will be maintained below the formation
fracture pressure. Steam splitter valves will be evaluated to optimize steam quality (by reducing
pressure drop) and optimize steam distribution in the reservoir.
6.4 Cementing Program
Based on recent experience in the area and the high level of importance of well integrity, the
mud system design, float equipment design and cementing practices need to be designed in
concert and are outlined below. The mud system will require properties that generate sufficient
hole cleaning to avoid drilling problems, but also stabilize the clay and shale intervals, while
treating the bitumen to avoid blinding the shale shaker screens and (most importantly) avoiding
accretion of the bitumen on drilling tools and casing. The float equipment will need be designed
to ensure that a good cement bond is created throughout the well and at TD and that the high
strength pipe is adequately centralized especially in the high deviation parts of the hole and
near surface. Finally, cement properties and (most importantly) circulation rates must be
managed to ensure that sufficient annular velocity is achieved without generating equivalent
circulating density high enough to fracture formations. Target annular velocities should be 20 –
30m/minute to ensure proper mud removal.
6.4.1 Mud System
The mud system for the surface hole will be gel-chemical maintaining density and pump rates
as low as possible to protect the conductor from washing out and still provide adequate hole
cleaning. Water dilution and solids control equipment, including centrifuges, will be used to
control density, which will be decreased to 40-45 s/l at TD prior to running casing.
The mud system for the intermediate hole to the Viking formation will be floc water with calcium
nitrate to maintain Ca > 400mg/l and clay stabilizer to inhibit shales. The hole will be displaced
to Bitumax, or equivalent, fluid including chemicals and mud products to control bitumen
accretion and clay stability throughout.
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The mud system for the intermediate hole from the top of the Mannville to TD will be the
Bitumax system above. Solids will be controlled to 7% using fine mesh screens, high g force
shakers, and centrifuges. Mud sweeps will take place at TD to clean the hole, minimize
accretion, and control viscosity prior to running casing.
6.4.2 Float Equipment
Surface casing float equipment will consist of a weld on double valve float shoe, a float collar,
339.7mm x 444mm latch-on bell spring centralizers on a stop collar at the mid-point of the shoe
joint and every 40m to surface. One 444mm rigid centralizer will be installed on the top joint,
inside the conductor barrel and below the casing cut-off point.
Intermediate casing float equipment will consist of a weld on double valve float shoe, a float
collar, 2-311mm semi-rigid centralizers per joint (with a stop collar in the middle of the casing
joint) for 2 joints or the start of the tangent section. 1-311mm semi-rigid centralizer per joint to
200m MD, 1-311mm semi-rigid centralizer every second casing joint from 200m to 13m, and 2-
311mm positive bar centralizers on the top joint below the casing cut-off point.
6.4.3 Cement and Cementing
Surface casing cement will be Steam Cem 1800, or equivalent, with 1% CaCl2, with a pre-flush
of fresh water and pumped at 2m 3 /min (estimated 10-30m/min annular velocity) maintaining
equivalent circulating density below the fracture gradient at TD. The estimated TVD hydrostatic
pressure at plug down is 3002 kPa or 17.7 kPa/m at 2m 3 /min.
Intermediate casing cement will be Steam Seal 1270, or equivalent, plus 20% glass beads, 20%
micro sand, and 4% CaCl2 pre-flushed with a 6m 3 spacer and 10m 3 scavenger and pumped at
1-2m 3 /min (estimated 15-30 m/min annular velocity) maintaining equivalent circulating density
below fracture gradient at TD. The estimated TVD hydrostatic pressure at plug down is 7000
kPa or 18.1kpa/m at 1m 3 /min.
6.5 Casing Failure Monitoring Program
Unlike the CSS (Cyclic Steam Stimulation) methods used in the cold lake area, the SAGD
process reduces thermal impact due to lower temperature associated with lower pressures that
occur in SAGD. Casing failures have occurred largely during the CCS process or in wells with
inadequate casing connection quality or poor cement jobs.
Birchwood does not anticipate casing failures and is taking measures that will mitigate the risk
of casing failure including:
Use of premium thermal connections which are stronger than the pipe body and have a
metal to metal seal in order to resist steam leakage and subsequent stress and
corrosion cracking and recoding of torque readings during make-up.
Use of high grade L80 steel for intermediate casing which will isolate the producing
formation from the overlying geological formations.
Use of thermal grade cement, management of equivalent circulating density to avoid
fracturing, maximizing annular velocity, reciprocation and rotation (if possible) of the
intermediate casing string during cementing operations and acquisition of bond logs for
each well to ensure thermal cement integrity
Operating of both the injection and producer wells at below the fracture pressure of the
producing formation.
Managing injection pressure at surface. While the facility boilers will not produce steam
in excess of 7000kpa, ensuring that no cold water column exists the wellbore when
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7000kpa is reached will ensure pressure at the reservoir face does not exceed fracture
pressure.
Managing the impact of the reflux of potentially corrosive fluids into injection wells at
shutdown with a gas blanket and pressure maintenance.
Development of a corrosion control and monitoring program including inhibitor injection
and corrosion coupons in piping to and from the wellheads.
Birchwood will monitor well bore integrity by:
Ensuring control personnel will continuously monitor and permanently record the steam
injection data and pressure relationships for each injector well as well as production rate
vs. pressure and temperature in the producer wells. This data will change over time;
however, if anomalies are noted by technical staff then the well(s) will be flagged for
operators as this could be an indicator of an intermediate casing leak.
Continuously monitoring gas blanket material balances to provide early indication of
casing or coupling failure.
Regularly monitoring casing vents and analyzing releases (if any).
Installing a network of tilt-meters that will continuously monitor micro-deformation at
surface as both an early warning system and a reservoir monitoring program to detect
anomalous production and injection patterns.
Upon the occurrence of any of: well bore temperature anomalies, gas blanket material
imbalances, casing vent flow, anomalous micro-deformation, Birchwood would immediately
inform local ERCB personnel, shut-in the well and provide a measurement and/or remediation
program to mitigate the failure or potential failure.
6.6 Vertical Wells
6.6.1 Source Water Wells
Source water wells are necessary for the project; a fresh water well to be utilized primarily for
utility water during continuous operations, but also to assist in start- up operations. A brackish
water source well will be utilized for both start-up and continuous operations as a make-up
water source. In order to start the boilers and before any re-cycled water is available from
production, an estimated volume of 4,000m 3 /day of fresh water will be required for a period of 5-
10 days to fill the plant and the Boiler Feed Water Tank. As soon as practical, the brackish
water well will be integrated as the primary make-up water source. Source water wells will be
completed in the Murial Lake Formation (~80-90m fresh water) and the McMurray formation
(~480-500m brackish water).
The source water wells have been, or will be, drilled on the proposed facility/well pad. The
schematic for the fresh water well and the brackish water wells are shown in Figures 6.6.1-1
and Figure 6.6.1-2.
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6.6.2 Observation Wells
A vertical observation well has been drilled and cased with thermal cement to the base of the
McMurray formation in order to monitor the formation temperatures. The wells will be completed
with fibre optic temperature sensors for monitoring. The wells will allow for distribution and
retrieval of internal temperature monitoring equipment and will provide a conduit for running
cased hole logging tools. Figure 6.6.2-1 illustrates a schematic of the well bore completion of
the observation wells.
6.6.3 Disposal Well(s)
One disposal well is required to dispose of the produced water used in steam generation. The
location of the disposal well is identified on the site plot plan in Section 7, Figure 7.1-1. The well
will be drilled to a depth that will allow disposal into the Granite Wash formation. A full length
casing log will be run to determine casing integrity. The Clearwater, Grand Rapids and
Wabiskaw formations as well as the McMurrray formation which is the proposed brackish
source water zone will be isolated using thermal cement. Prior to commencing disposal
operations hydraulic isolation will be tested. No monitoring instrumentation will be place
internally or externally on the casing however annual packer isolation tests will be run and
submitted to the ERCB. Figure 6.6.3-1 provides a well completion schematic for the disposal
well contemplated herein.
The disposal well will be drilled and completed in compliance with meeting the Class Ib
requirements indicated for disposal wells as set out in Directive 51. In order to ensure reservoir
containment of injected fluids, as well as wellbore integrity, the wellhead injection pressure will
be compatible with the bottomhole injection pressure.
Birchwood will apply for approval of the disposal scheme under Directive 65. Additional above
ground pipelines will be installed to move the waste water from the CPF to the disposal well.
6.6.4 Abandonment Status of Wells Within the RDA
There is one abandoned well within the Birchwood lease, located at 05-01-064-04W4M. This
well is approximately 400 meters outside the boundary of the RDA. Details of existing wells are
presented in Figure 6.6.4-1. All wells on the Birchwood lease are thermally compatible.
6.5 Drilling Waste Management
The wells will be drilled using a water based drilling mud system. All Drilling waste generated
from the wells will be managed in compliance with Directive 50.
Drilling waste will be stored in steel tanks during drilling operations. Surface hole mud will be
land sprayed on nearby cultivated land provided the fluids pass all analytical requirements.
Once the bitumen zone is penetrated, the cuttings and drilling fluid will evidence hydrocarbons.
All oil contaminated cuttings will be dried using on-site centrifuges, stored in above ground tanks
and, prior to testing and disposal, mixed with wood fibre. Confirmatory testing will be undertaken
to ensure the waste can be sent to the Tervita Class II Bonnyville Landfill. Oil contaminated
liquid mud residues that cannot be recycled will be hauled to the Tervita Lindbergh Salt Cavern
for Disposal.
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Figure 6.2-1 Well Configuration and Spacing
2 future well pairs
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A10
10 Pilot Pair wells
A1

Figure 6.2-2 3D Model of Well Configuration
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Figure 6.2.1-1 Producer Wellhead
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Figure 6.2.1-1B Producer Wellhead
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Figure 6.2.1-2 Injector Wellhead
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Figure 6.2.1-2B Injector Wellhead
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Figure 6.3.1 Producer Well Schematic
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Figure 6.3.2 Injector Well Schematic
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Figuure
6.6.1-1
Sage Pilot Applicatio on
Source Well: Utility
Water Well Schematic
Page 118

Figure 6.6.1-2 Source Well: Brackish Water Well Schematic
Notes :
Surface Hole
349.00mm
Depth
Grand Center 547.3 mKB
Sand River 537.3 mKB
Ethe l Lak e 517.3 mKB
Muriel Lake 507.3 mKB
Em pre s s
244.5 mm
Cemented
477.3 mKB
Suface Casing 399.3 mKB
Colorado 429.7 mKB
2WS
222.0mm Main Hole
177.8 mm Casing
389.0 mKB
Viking 300.8 mKB
Joli Fou 292.2 mKB
Colony 255.7 mKB
McLaren 243.9 mKB
Waseca 231.8 mKB
Sparky coal
Sparky 213.9 mKB
GP 185.4 mKB
Rex 168.2 mKB
Clearw ater 155.8 mKB
Tubing Stng
88.9mm
Wabiscaw 102.2 mKB
McMurray 93.9 mKB
Perforations
(BHL) Paleo 44.8 mKB
TD 29.8 mKB
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Figure 6.6.2-1 Observation Well Schematic
Note s:
Surface Hole
349.00mm
Grand Center 547.3 mKB
Sand River 537.3 mKB
Ethel Lake 517.3 mKB
Muriel Lake 507.3 mKB
Em pr e s s
244.5 mm
Cemented
477.3 mKB
Suface Casing 399.3 mKB
Colorado 429.7 mKB
2WS
222.0mm Main Hole
177.8 mm Casing
389.0 mKB
Viking 300.8 mKB
Joli Fou 292.2 mKB
Colony 255.7 mKB
McLaren 243.9 mKB
Waseca 231.8 mKB
Sparky coal
Sparky 213.9 mKB
GP 185.4 mKB
Rex 168.2 mKB
Clearw ater 155.8 mKB
Tubing Stng
88.9mm
Wabiscaw 102.2 mKB
McMurray 93.9 mKB
(BHL) Paleo 44.8 mKB
TD 29.8 mKB
Fiber Optic Cable
Depth
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Figure 6.6.3-1 Disposal Well Schematic
Note s:
349.0mm
Surface Hole
Grand Center 547.3 mKB
Sand River 537.3 mKB
Ethe l Lak e 517.3 mKB
Muriel Lake 507.3 mKB
Empress 477.3 mKB
244.5 mm Csg
(cemented)
Suface Casing 399.3 mKB
222.0mm Main Hole
Colorado 429.7 mKB
2WS 389.0 mKB
Viking 300.8 mKB
Joli Fou 292.2 mKB
Colony 255.7 mKB
McLaren 243.9 mKB
Waseca 231.8 mKB
Spky coal
Sparky 213.9 mKB
GP 185.4 mKB
Rex 168.2 mKB
Clearwater 155.8 mKB
Wabiscaw 102.2 mKB
McMurray 93.9 mKB
(BHL) Paleo 44.8 mKB
Christina 33.8 mKB
Calumet -5.4 mKB
Firebag -32.7 mKB
Watt Mtn -98.9 mKB
Daw son Bay -103.2 mKB
Praire Evap -112.7 mKB
Winnipegosis -266.7 mKB
Contact Rapids -313.4 mKB
Cold Lake -355.3 mKB
Ernest Lake -412.4 mKB
Lotsberg -428.4 mKB
Red Beds -603.7 mKB
Packer
Cambrian -651.2 mKB
PreCambrian -735.6 mKB
TD
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Depth

Figure 6.6.4-1 Details of Existing Wells
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
Date Well Spudded 8/9/1991 12/4/2011 12/12/2011 12/16/2011
Lic/WA/WID/Permit # 149592 438597 438596 438585
Well Status Drilled & ABD Drilled & Cased Observation Pump Cr-Bitumen
Current Operator Code 0R46 A5YL A5YL A5YL
Casing - Surface
Casing - Production
177.8mm SRF @ 155.0m
None - ABD
244.5mm SRF @ 175.0m;
177.8mm PRD @ 518.0m
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244.5mm SRF @ 167.0m;
177.8mm PRD @ 524.0m
244.5mm SRF @ 166.0m;
177.8mm PRD @ 520.0m
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)
Casing Collars (Surface) ST&C ST&C ST&C ST&C
Cement Returns (Surface) 3.0m3 5.0m3 0.5m3 5.0m3
Cement Type (Surface) Expando mix 0:1:0 Class G 0:1:0 Class G 0:1:0 Class G
Casing Collars (Production) N/A ST&C ST&C ST&C
Casing Grade (Production) N/A J-55 (29.76 kg/m3) J-55 (29.76 kg/m3) J-55 (29.76 kg/m3)
Cement Returns (Production) N/A 2.0m3 3.0m3 3.0m3
Cement Type (Production/ABD) Thermal Thermal T-Mix TS Thermal T-Mix TS Thermal T-Mix TS
Surface Vent Flows None None None None
Thermal Compatible (Yes/No) Yes Yes Yes Yes
Closest Proposed SAGD Well 1,250m 200m 5-30m 500m

7 Facilities
7.1 Overview
7.1.1 Central Processing Facility
The Central Processing Facility (“CPF”) consists of an injection facility and an oil production
battery. The purpose of the injection/disposal facility is to process and recycle water for steam
generation and includes water treatment, water disposal, and solids dewatering and handling
facilities. The purpose of the production battery is to process bitumen and includes separation,
produced water de-oiling, slop oil recovery and diluent handling facilities. The facility integrates
the following process:
Bitumen and slop oil treatment,
Produced water de-oiling and recycling,
Water recovery and treatment for (re)use as boiler feed water,
Steam generation,
Surplus produced water treatment and disposal, produced water regeneration waste and
boiler blow down disposal,
Vapor recovery & produced gas treatment and blending for use as steam generator fuel,
Heat recovery,
Utilities (flare ignition, sweet fuel and lift gas, instrument air, heating/cooling medium,
safety and office fresh water),
Diluent and chemical injection.
The CPF will be located adjacent to the well pad in the SW quarter of Section 02-064-04W4M
and the combined lease will occupy an estimated 19 hectares (“ha”) (320 m X 580m) of land
(see Figure 1.1-1 Plot Plan and 3D model in Figure 1.1-2). The CPF will occupy an estimated 8
ha (380 m X 280m) of land on the eastern half of the lease.
Under steady state operating conditions the plant is expected to produce 795 m 3 (5,000 bbl/day)
of 8.7° API bitumen and process produced water at a rate of 3,140 m 3 /day (20,000bbl/day) (±
10%). The Free Water Knockout (“FWKO”) and treater have been designed to accommodate
bitumen production rates of 954 m 3 /day (6,000 bbl/day) to allow for recycling of off spec product
and should also provide flexibility if the reservoir has a steam/oil ratio better than expected.
The best option for handling the produced gas is to burn it as fuel in the boilers. Apart from fuel
savings the high temperature, high turbulence, and long residence time in the chambers
provides H2S destruction efficiency that is comparable to engineered waste gas incinerators.
Detailed information regarding equipment and Heat and Material Balances can be found in the
following appendixes.
Appendix 7.1 Equipment list
Appendix 7.2 Heat and Material Balance
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7.1.2 Well Pad Facility
Figure 7.1.2-1 Process Flowsheet 200-1 Wellpad.
The well pad will be located directly adjacent to the CPF and constructed with the following
features:
• Ten SAGD well pairs (future drilling potential to 36 pairs on the same pad)
• A steam distribution header
• A blanket gas distribution header
• A group production header
• A test header with a de-gasser, flow meter, and water cut analyzer to generate ERCB
production accounting data.
• Each well pair will have a control manifold to manage the flow of each fluid.
• Instrument air will be used to operate automated control and switching valves.
• The production wells will be equipped with lift gas. Each production well can be diverted
to a test header equipped with a flow meter and water cut analyzer.
Steam will flow from the CPF to the well pads via above ground steam pipelines at a maximum
pressure of 7000 kPa. The manifold buildings located at the well pad will then distribute the
steam to each well pair through flow-lines. There will be one steam control manifold per well
pair. Steam will be flow controlled to each production and each injection well during the project’s
circulation warm up phase (Section 5.2) to optimize the initiation of the SAGD process and to
each injection well during steady state operations (Section 5.3).
During steady state operations at full production, steam will be fed into dual tubing strings set at
the toe and at the heel of each injection well at a rate of 318.5 t/day. Control values and
metering instruments will be configured to allow the steam injection rates to be controlled, in the
range of 72 t/day to 408 t/day per steam injection well. Normally the steam will be injected at a
flow rate set in the Digital Control System (“DCS”) by the operator. A high pressure override will
be programmed into the logic to prevent the wellhead injection pressure from exceeding the limit
prescribed by the well license.
Each injection and production line at the well pad will be equipped with external electric tracing
in segments where liquids can become trapped during a cold weather shutdown. To enhance
freeze protection, minimize temperature transients and avoid water hammer issues, a steam
cross over may be provided to feed steam into production lines at suitable locations.
7.1.3 Design Flow Rates
• Ten SAGD well pairs.
• Average bitumen production per well pair = 79.5 m 3 /day (500 bbl/day).
• Average water production per well pair = 318 m 3 /day (2,000 bbl/d CWE; WOR = 4.0).
• Average reservoir gas production per well pair = 1,590 sm3/day (GOR = 20 sm 3 / m 3 ).
• H2S production = 0.203 kg H2S per m3 of dry bitumen (0.141 sm 3 H2S / m 3 bitumen).
• H2S concentration in the reservoir gas = 4400 – 7,050 ppm (dry basis; due to
aquathermolysis)
• Average steam injection per well pair = 318 tonnes/day (2,000 bbl/day CWE; SOR =4.0).
• Bottom Hole Pressure = 2900 kPa.
• Bottom Hole Temperature = 234°C in the steam chamber; 226°C in the horizontal
segment of the production well.
• Design down-hole sub-cool = 5 °C.
• Well head temperature = 195°C.
• Production pressure at the wellhead (upstream of choke) = 1,490 kPa.
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• Lift gas per well = 3000 sm 3 /day
• Average produced gas recovered, excluding lift gas = 15,355 sm3/day (dry basis);
design for maximum 30,710 sm 3 /day.
• H2S production (fully developed steam chambers) = 161.4 kg/day; design for 201.8
kg/day max.
7.2 Steam Generation and Water Treatment
Figure 7.2-2 Block Flow Diagram of the De-oiling, Water Treatment and Steam Generation.
Figure 7.2-2B Water Balance of the De-oiling, Water Treatment and Steam Generation
7.2.1 Steam Generation
Figure 7.2.1-1 Process Flowsheet 100-06 Steam Generation
The drum boiler packages include a steam drum, blowdown drum, air pre-heater, forced draft
fan, burner and a burner management system. A mixture of produced gas and pipeline quality
make-up gas will fuel the main burner of each boiler; pilot flames will receive only sweet dry
natural gas. During initial start-up only a small volume of produced gas will be available
therefore only pipeline quality natural gas will also be used to fuel the main boilers.
The small amount of produced gas (co-produced with the bitumen from the reservoir) is not
expected to have any significant commercial value. During normal operation, the produced gas
Is expected to contain mostly steam, carbon dioxide, and methane. The steam will be
condensed and removed from the gas. The gas will then be blended with sweet dry natural gas
to fuel the main burners in the steam generators. In addition to exploiting the marginal amount
of fuel value from the produced gas, the steam generator combustion chamber will provide
complete destruction of noxious and toxic components such as H2S.
7.2.2 Project Make-up and Boiler Feed Water Sources
Figure 7.2.2-1 Process Flowsheet 100-6 Water Treatment
The facility will generate high quality steam from predominately brackish water sourced from the
McMurray formation and sent to the plant via pipeline. Annual brackish water requirements are
expected to be 150,000 m 3 . Fresh make up water will be required for the initial start-up period;
it is anticipated that no more than 50,000 m 3 of fresh water will be required for start-up;
thereafter a volume of approximately 5 m 3 /day of fresh water will be necessary to meet utility
requirements. Two drum boilers (B-5000/B-5010) rated at 165 GJ/hr., will produce high pressure
steam saturated vapor, also referred to as 100% quality steam.
The CPF design is based on receipt of water from the following sources: make-up water (fresh
and brackish), produced water from the production wells, and steam condensate. It is
anticipated that shallow water from the Empress Formations (80-100 m) and brackish water
from the McMurray Formation (480-500 m) will be utilized and transported to the facility via pipe
lines from wells located on the combined wellpad and CPF site. A summary of water sources
and uses is shown in Table 7.2.1-1, a detailed water balance can be found in Figure 7.2.2B.
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Table 7.2.2-1 Summary Water Sources and Uses at Maximum Capacity
Boiler
Reservoir
Fresh
Make- Brackish
Time Feed Utility Loss Recycle up Water
Phase Frame Water Water 5% 92.5% Water Make Up Notes
(Days) M3/day M3/day M3/day M3/day M3/day M3/day
Plant Fill 5–10 4,030 5 (4,030) 0 3,640 395
Start-up Water
required
Assumes
Warm Up 90–180 4,030 5 0 3,829 5 201
injection equals
returns for 2
wells
Assumes
Transition
Steady
30–90 4,030 5 (2,015) 1,914 1,728 395 injection equals
returns for 1 well
State
SAGD
3000+ 4,030 5 (202) 3,635 5 395 Steady State
Water from both the fresh and the brackish water pipelines will be filtered as it enters the
treating system. Produced water will be recovered from the condensable portion of the
produced gas condensing train and from the bitumen treating system; this water will form the
bulk of the boiler feed water (BFW) after is de-oiled and treated. It is anticipated that the total
produced water will vary from 92% to 105% of the steam injected. On occasion (such as startup)
make up water will be required. De-oiled water will require disposal when steam recycle
rates exceed 100%.
7.2.3 Produced Water Treatment Process
Figure 7.2.3-1A Process Flowsheet 100-7A Water Treatment
Figure 7.2.3-1B Process Flowsheet 100-7B Water Treatment
Figure 7.2.3-2 Process Flowsheet 100-1 Inlet
The produced water treatment process is designed to create high quality boiler feed water. The
process utilizes falling film evaporator technology, which operates at a moderately high pH and
results in the removal of silica, dissolved solids, and hardness in order to meet drum boiler feed
specifications.
Steam sent to the wells is generated through the following process: BFW is pumped first by the
low pressure BFW Pumps (P-4020 A/B) to the Emulsion/BFW Heat Exchanger (E-1040) where
the BFW is preheated by recovering heat from emulsion at the CPF inlet. The BFW then flows
to the HP BFW Pumps (P4040 A/B), which increases the BFW pressure to 7400 kPa. Dry steam
leaving the Drum Boilers (B-5000/B-5010) is sent to the wells via a high pressure steam line,
where the high pressure steam will be injected into the formation via injection wells. A small
portion of the high pressure steam is diverted, its pressure reduced, and used as utility steam.
Steam blow-down from the Drum Boilers will be sent to the Evaporator. The blow-down rate is
expected to be 4-7.5%.
Produced emulsion from the wells will be routed to the inlet de-gasser (V-1000) where vapours,
pre-dominently water vapour, will be condensed in an aerial cooler. Produced gas, lift gas and
hydrocarbon vapours from the vapour recovery system will be recovered for re-use as fuel gas.
Emulsion is treated chemically (Section 7.8.2) then sent to the Free Water Knock Out Vessel (V-
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1100) where water with some hydrocarbons is sent to the produced water/glycol heat exchanger
(E- 1140 A/B) for commencement of the bitumen treatment process (Section 7.3) and then to
the produced water skim tanks (T-2000/2010). The hydrocarbons with some water will be sent
to a treater (V-1110) where it is treated with chemicals and diluent, cooled in the sales oil/glycol
heat exchanger (E-1130) and sent to the sales oil tanks (T-7000, T7010). Vapours from the
treater are cooled in a produced gas/glycol heat exchanger (E-1150) and sent to a diluent
recovery separator (V-1160) with produced gas going to the fuel gas mix drum, water to the
produced water skim tanks and hydrocarbons to the sales oil tanks.
In the de-oiling area, produced water enters the skim tanks where oil and water are separated
by gravity. The produced water is sent to the Induced Gas Flotation (IGF) vessel (V 2100)
where additional oil recovery occurs. The produced water leaving the IGF vessel is fed to the Oil
Removal Filters (“ORF's”) (V2200 A/B) then flows to the de-oiled water tank (T-3000) and
undergoes additional chemical treatment (see Sections 7.12) to allow for separation of water,
hydrocarbons and solids removal. De-oiled water from the bitumen treatment process, as well
as drum boiler blowdown water and make up brackish water, is sent to an evaporator.
7.2.3.1 Evaporation
The mixed flow of de-oiled produced water and boiler blow-down is combined with heated
brackish water and is fed to a de-aerator (C-3100) where a small amount of excess steam from
the evaporator condenser or low pressure steam line is used to strip the oxygen, carbon
dioxide, nitrogen and other non-condensable gas to prevent downstream equipment corrosion.
The water then enters a falling film evaporator (V-3400) where the brine water is recirculated
from the vapour body/retention chamber through an internal return circuit and then flows as a
thin film down the heat transfer tubes. The heat from condensing vapours on the shell side of
the evaporator heat exchanger causes a portion of the water in the re-circulating liquid to
vapourize. The majority of the vapour production occurs in the heater tubes and flows down the
tubes with the liquid film in the same direction as the vapour body. This two phase co-current
flow helps to stabilize the liquid film on the inner surface of the tube and accelerates the liquid
flow down the tubes, creating turbulence and augmenting heat transfer.
Chemicals are injected into the evaporator include magnesium oxide and caustic in order to
precipitate silica and other scaling constituents as well as preventing scale formation (see
Section 7.12).
The water slurry entering the evaporator is significantly concentrated (~5 concentration factors)
during the evaporation process. Disposal brine from the system is neutralized and sent to the
disposal system.
The clean vapours are compressed (K-3440) and the vapour pressure increased to the
condensing temperature of the heater shell. The compressed vapour is then cooled to provide a
consistent heat transfer rate at the entrance to the condenser. The distillate is cooled and
pumped through the raw water exchanger (E-3450 A/B) to the BFW tank.
7.2.3.2 Boiler Feed Water
The Boiler Feed Water (“BFW”) pump system provides decoupling between the water treatment
and boilers. The BFW tank is blanketed with gas to prevent the ingress of oxygen and insulated
to conserve heat and to avoid freezing during cold weather shut downs. Tank vapours are
routed to the VRU to avoid emissions and odour concerns. The Low Pressure BFW booster
pump is then used to draw water from the tank and send it through the heat recovery system.
The Low Pressure BFW booster pumps (P-4020A/B) discharge at a pressure of about 1200 kPa
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and a rated flow of 165 m 3 /hr which ensures that the BFW will not boil and there will be
adequate suction at the head of the High Pressure BFW pumps (P-4040A/B). The booster pump
will be equipped with a suitable minimum flow bypass system. The pre- heated, pressurized
water is sent to the drum boilers for steam generation. Concentrated brine is collected in the
evaporator sump for subsequent treatment and disposal.
7.2.4 Produced Water Disposal
Concentrated brine from the evaporator sump is pumped to a neutralization tank where it is
treated with hydrochloric acid. Hydrochloric acid is stored in a separate tank equipped with a
water wash vent scrubber. Circulation pumps (P 3450 A/B) and a glycol cooler (E-3480)
ensures the tank temperature does not exceed 83 o C. The neutralized product is flocculated and
pumped to a decanting centrifuge where the majority of spent magnesium oxide is concentrated
and dumped to a designated bin for off-site disposal at an approved facility. The concentrate is
pumped to a waste water disposal tank and subsequently disposed of in an approved disposal
well. See Figure 7.2.2 Block Flow diagram and Figure 7.2.2B Water Balance.
7.3 Bitumen Treatment
Figures 7.3-1 Process Flowsheet 100-2 Bitumen Treating
The bitumen treatment system is designed to separate produced fluids into sales oil and
produced water, while recovering produced gas for use in the plant. The sales oil produced by
the bitumen treatment process is must meet the following minimum pipeline specifications:
BS&W: 0.5% by volume
Specific Gravity: 0.940
Temperature: 60 o C, Maximum 65 o C
Viscosity: 350 centistokes at 4 o C
Emulsion composed of bitumen, produced water and produced gas is sent to the CPF in an
above ground pipeline and is routed to an inlet de-gassing vessel. The vapour phase which is
composed primarily of condensable water vapour, produced gas, lift gas and lighter
hydrocarbons is transferred to a condenser (E-1020), then to a produced gas separator (V-
9210) cooled by the produced gas cooler (E-1140) and eventually recovered as fuel gas
(Section 7.5).
The emulsion from the de-gasser will be cooled to ~120 o C in the emulsion/boiler feed water
exchanger (E-1040). The heat from the emulsion will be transferred to the boiler feed water to
reduce generator fuel consumption. Emulsion along with diluent enters the FWKO where
produced water is separated from the emulsion after which diluent is added again to the
emulsion which then enters the treater where final separation of produced water from the
bitumen occurs through the addition of clarifiers and demulsifers. The FWKO allows large
droplets and slugs of water to drop out of the emulsion. The water stream leaving the FWKO
vessel should contain

initiate decanting of the treater rag layer until the operating profile is established and the rag can
be drawn on a continuous basis. This design also:
Compensates for low temperatures and high viscosity during plant start-up.
Increases the density differential between oil and water,
Reduces fouling in the glycol heat exchangers, and
Results in lower viscosity of the emulsion thereby improving heat transfer performance.
The piping design also incorporates recycling of off-spec product and slop oil at the front of the
treating system. A recycle line will be tied into the emulsion line upstream of the FWKO tank.
Recycle rates are not expected to exceed 10% of the treating system.
7.3.1 De-Oiling
Figures 7.3.1-1 Process Flowsheet 100-4 De-oiling
Produced water from the FWKO and Treater undergoes three separate de-oiling treatments:
cascading produced water skim tanks (T-2000/T-2010) with polymer injection, Induced Gas
Floatation (“IGF”) (V-2100) with polymer injection and oil recovery filtration (V-2200A/B) with
provision for back-wash.
7.3.1.1 Skim Tanks
Oil recovered from the treater is sent to the sales oil tank (T-7000/7010). Produced water from
the glycol heat exchangers, the VRU liquids pump, the slop water tank, and the decant water
pump is sent to the skim tanks for recovery using gravity. The skim tanks are designed to utilize
chemical injection and mechanical separation to allow the small oil droplets to coalese into large
oil droplets and accumulate on the water surface for skimming.
A chemical injection port is provided upstream of each skim tank to allow a water clarifier
(polymer solution see Section 7.9.2) to be added to the water. A low shear static mixer
downstream of the clarifier injection point disperses the chemicals into the water as well as
helping the oil droplets collide allowing them to agglomerate into larger oil droplets. A vortex will
be utilized in the skim tanks to prevent the small oil droplets from short circuiting to the bottom
of the tank; the vortex flow pattern rotates at a rate that extends the residence time in the tank
thereby extending the coalescence period. The bottoms of the tanks are equipped with an
internal cone shaped baffle over the produced water discharge. The baffle acts as a barrier to
short circuiting as it ensures that the emulsion flow is redirected around the periphery of the tank
prior to discharge.
Each skim tank is equipped with an interface probe and sampling valves in order to monitor the
rag emulsion in the skim tank and prevent the rag emulsion from hindering the separation
process. Floating skimmers will be utilized to remove the rag layer.
Pumps will be provided to transfer the remaining emulsion from the primary skim tank to
secondary skim tank, as well as from the secondary skim tank to the IGF unit, and from the IGF
unit to the ORF if required, for additional treatment.
7.3.1.2 Induced Gas Flotation
The emulsion stream from the skim tanks is then sent to the IGF Vessel (V-2100) where natural
gas is bubbled through the water to allow the oil to rise to the top of the vessel and skimmed off.
The IGF can typically recover up to 90% of the residual oil in the produced water from the skim
tanks.
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A circulation pump in the IGF feeds an in-line educator that induces blanket gas into the
educator which then disperses fine bubble of blanket gas into the produced water via an in-line
disperser set across the flow path in the IGF unit. This facilitates contact and adsorption of the
oil droplets to the surface of the gas bubbles. The blanket gas pressure is controlled with a pilot
gas regulator. A globe valve on the piping is used to adjust the supply of gas to the educators.
Gas bubbles adhere to oil droplets and rise to the top of the IGF's internal compartment and
produced water flows downward through the outer compartment and is pumped to the oil
recovery filters. The froth oil flows over a weir around the top of the vessel and is pumped to the
oil recovery via the oil recovery pump (P-2120A/B). The skim oil/IGF froth may be returned to
the slop oil tank for more aggressive treatment.
The IGF liquid level controller adjusts feed to the unit. An interface controller regulates the IGF
froth. A chemical injection quill is incorporated into the design of the plant and will allow the
injection of polymer into the system via the IGF charge pumps if required during start up.
7.3.1.3 Oil Removal Filters
The water stream is then sent through the oil recovery filters (ORF's V-2200 A/B) where oil is
adsorbed onto a filter matrix in 2 vessels so that 1 is in service at all times and 1 can be treated
and backwashed. The water stream is sent to the de-oiled water tank (T-3000). The backwash
from the ORF's and quenched desand slurry from the FWKO and treater is piped to the desand
tank (T-2300) to remove solids.
7.3.2 De-Sanding
Figure 7.3.2-1 Process Flowsheet 100-5 De-sanding and Slop Oil
Sand and sludge will accumulate in the FWKO and treater vessels, as well as in the ORF
backwash. Both the FWKO and treater will be equipped with automated flush and drain stations
that can be remove sand without taking the equipment out of service. Water to flush the sand
will be supplied from the de-oiled water tank through a desand jet pump (P2320). Desand drains
will include internal sand pans to catch sands disturbed by the water flush. The slurry of
produced water and sand will be sent to the de-sand tank after it is blended with de-oiled water.
Sand and sludge from the ORF backwash and desand slurry is sent to the desand tank
equipped with blanket gas where the solids settle and are sent for disposal. Oil is skimmed and
pumped to the Oil Recovery Tank. Water is decanted and sent to the Skim Tank, and slop oil
sent to the FWKO vessel.
Vapours from the de-sand tank are routed to the VRU for recovery.
7.3.3 Sales Oil Management and LACT
Figures 7.3.3-1 Process Flowsheet 100-3 Bitumen Storage
Oil product is pumped from the sales oil tanks to the Lease Automatic Custody Transfer unit
(“LACT”) (P-7200) unit. There are two sales oil tanks (T-7000, T-7010) and one off spec tank
(T7100) with a design pressure of no less than 3.5 kPa (-0.5 kPa vacuum). While one is feeding
the pipeline the others are taking production. Each tank will have capacity to accommodate
eight (8) hours of production and should normally operate at 50% capacity. The tanks will be
bottom sloped toward the tank wall to facilitate decanting of bottom water. A slop oil tank with
recycle pump and collection header will be piped to draw bottom water from the sales tanks and
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off spec tank as well as transfer off-spec material to treatment area. The combined volume of
the tanks will allow for 24 hours of storage should a pipeline upset occur. Each sales tank will
include the following:
Insulation to conserve heat and minimize headspace breathing due to sudden weather
changes as well as glycol tracing around the bottom 2 m of the tank wall to prevent
freezing of the inlet and outlet nozzles. PSVS's will be traced and insulated to prevent
freeze up.
Fuel gas blanketing to prevent the ingress of oxygen.
Traced and insulated sample box to allow samples to be drawn from various levels
within the tank. A blow-case will be installed to return oily sample waste to the tank.
Level transmitters. A high level alarm and shutdown system will reduce the risk of
overfilling the tank(s) and a low level alarm and shutdown will prevent damage to the
pumps drawing from the tank(s).
Clean sales oil headers and off spec headers upstream and downstream of the sales
and off-spec tanks; the sales oil headers will be piped with a tank bypass line to the
LACT booster pump.
Two 100% duty LACT booster pumps (one operating, one standby).
A water cut analyzer to monitor sales oil BS&W flowing to the LACT unit prior to diluent
blending.
A sales oil diluent blending station with a static mixer to ensure pipeline viscosity
specifications can be maintained.
During startup, feedstock fluctuations or plant upset, the sales oil may go off-spec.The off-spec
tank will provide storage space and a means to isolate off-spec product from the clean sales oil.
The treated sales oil must be blended with diluent to reduce viscosity and frictional drag in the
market pipeline. The system will be designed to operate with normal diluent to bitumen blend
ration of 23:73 in order to produce a 350 cST blend at 4 o C pipeline flowing temperature. Static
mixers will be installed downstream of the diluent injection quills to promote uniform mixing of
the blend.
The diluent pipeline into the CPF is expected to operate at sufficient pressure and with sufficient
reliability that there should be no requirement for a diluent tank or diluent injection pumps. An
emergency shutoff valve will be installed at the diluent injection pipeline riser entering the CPF.
The flow will be measured and totalized to reconcile custody transfer records.
7.3.5 Slop Oil System
Slop oil is a mixture of rag draws, off-spec oil, emulsions, sludge, tank bottom and any other oily
liquid waste. On-site treatment of slop oil is the prefer option for slop oil treatment as it allows for
maximizing the recovery process however composition and characteristics of the slop oil may
require occasional off-site disposal.
The slop oil tank will assist in management of the oily emulsions from the above noted sources.
The tank will be equipped with a heating coil to maintain contents at 79 o C with hot glycol used
as the heating medium.
Plant piping has been configured to allow decanting of rag emulsion from the interface layer in
the FWKO vessel or treater into the slop tank (see Figure 7.3.2-1). A slop oil recirculation pump
will allow for chemical treatment of the slop emulsion. Slop oil will often contain a high
percentage of water and may require long settling times to break the emulsions. As the
emulsion breaks, the slop oil recirculation pump can be used to transfer skim oil to the FWKO
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inlet, or bottom water to the skim oil system. A network of slop oil headers will be provided to
allow fluid to be transferred to the slop oil tank and the oil recovery tanks. This will allow
decanting of the emulsion layer from one tank to the next where further chemical treatment can
be applied.
The slop oil and oil recovery tanks will be fuel gas blanketed to prevent ingress of oxygen. Tank
vapours will be routed to the VRU through a common header. Tanks will be designed for
pressures no less than 3.5kpa (-0.5 kpa vacuum) and be equipped with PVSV’s traced and
insulated to prevent freezing.
7.4 Inlet Cooling and Separation
Figures 7.4-1 Process Flowsheet 100-4 Glycol Circuit
In order to achieve high levels of energy efficiency for the project, a closed loop ethylene/glycol
water system is one of the CPF components and it will be used for cooling and to recover and
utilize low grade heat which would otherwise be released or lost to the atmosphere. The heat
recovered will be used to heat various process streams such as boiler combustion air,
purchased fuel gas, HP and LP flare knock out drums, tank heaters, tracing stations, and
building heaters. Cold glycol will be used to cool the various VRU inlet streams along with
providing the medium required to cool the inlet streams, largely produced water, to meet
process cooling requirements.
Produced water is typically a high fouling service. Sediment in the produced water is expected
to contribute to fouling. Traces of dispersed oil in the water will bind sediment to the exchanger
tubes and internal passages. An extra exchanger bundle is anticipated to be available at all
times so that one shell can be taken out of service for cleaning while maintaining flow through
the other shells. All exchangers in the produced water cooling train will be heat traced and
insulated. The exchangers will be drained as soon as a failure in the glycol system is detected.
7.5 Fuel and Produced Gas Recovery System
Figures 7.5-1 Process Flowsheet 100-10 Instrument Air/Fuel Gas
Two sources of gas will be utilized for various processes on the well pad and within the CPF;
produced gas from the reservoir and dry natural gas supplied by a third party for all of lift gas,
blanket gas and boiler fuel gas. No alternative sources of fuel are being considered as the
natural gas infrastructure exists within close proximity to the plant and establishing other
infrastructure would be economically infeasible and cause unnecessary environmental
disturbance.
Produced gas will be recovered from the inlet degassing system, the VRU, the FWKO and
treater and used for fuel in the drum boilers. The main produced gas stream will be recovered
after condensing water from the inlet degasser. After the gas is cooled it will separate into noncondensable
recovered vapour and liquids, the latter composed primarily of water. The liquids
are sent to the de-oiling system. Produced gas will contain CO2 and small amounts of H2S due
to the occurrence of aquathermolysis in the reservoir. The high volumes of lift gas anticipated
will substantially reduce the concentrations of both at surface. The high temperature, high
turbulence and long residence time in the boiler fire box chambers will provide H2S destruction
efficiency that is equivalent to engineered waste gas incinerators. Additional vapour streams will
be recovered from plant tanks and other sources of low pressure vapours via a header system
that feeds the VRU. To minimize the vapour load to the VRU compressor the inlet stream is
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cooled with cold glycol and the vapour and liquid are separated in the suction scrubber. All liquid
streams will be collected and sent to the de-oiling system.
Commercial natural gas (odorized) will be piped into the plant from the Alta Gas pipeline
terminating at a suspended well at 6-12-64-4W4M line. The riser into the CPF will be equipped
with an emergency shut down valve and a flow metering station. The primary use of this high
pressure gas is for lift gas; once the gas is heated with glycol it will be piped to the well pad.
Once a portion of the remaining gas has its pressure reduced, it will also be used for heating the
office/warehouse, glycol heater fuel, pilot for the flare(s) and for blanketing tanks and vessels.
The balance, and bulk, of the pipeline quality fuel gas will be used to fire the drum boilers.
All produced and lift gas will be recovered and, with the use of a vapour recovery system, all
blanket gas will be directed to the fuel gas system, mixed with fuel gas and used for fuelling the
steam generators.
All vents from all equipment in the CPF will be directed to the fuel gas and produced gas
recovery system. This will minimize fugitive emissions and ensure maximum recovery of this
resource.
7.5.1 Sulfur Production and Recovery
For in situ thermal facilities, the sulphur inlet rate is the sulphur content of the produced gas. At
Sage, produced gas includes gas produced from the reservoir and lift gas. This produced gas is
combined with gas recovered from the VRU collected from various parts of the process train
and is used as a part of the mixed fuel gas stream for steam generation. Lift gas and the bulk of
the fuel gas used for steam generation is sourced from pipeline quality fuel gas and has no
sulphur content.
Produced gas from the bitumen in the Clearwater zone in this area has no sulphur content
initially. It develops a sulphur component as sulphur is released from the bitumen to form
hydrogen sulphide in the reservoir through a process known as aquathermolysis.
The following table, from ERCB Interim Directive ID 2003, provides specifications for Inlet
sulphur rates and minimum required recovery criteria.
Table 7.5.1-1 Sulphur Production and Recovery Criteria
Sulphur Inlet Rate
(T/D)
Design Sulphur Recovery Criteria
(%)
Calendar Quarter Year Sulphur
Recovery Guideline (%)
5 to 10 79 69.7
>10 96.2 95.9
The design inlet sulphur rate is based on predictions of the effect of aquathermolysis and is
estimated to be 190 kg/d based on the maximum daily H2S production of 201.8 kg/d or 0.239
kg/m 3 of bitumen produced see Section 7.1.3, as such no sulphur recovery is required.
7.6 Vapour Recovery and Flare Systems
Figure 7.6-1 Process Flowsheet 100-11 Flares and VRU
The vapour recovery system consists of various operations in the plant that will capture vapours
as per Table 7.6.1:
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Table 7.6.1 Vapour Sources
Dearator Overhead Separator (V-3130) Sales Oil Tanks (T-70000 & T 7100)
Produced Water Skim Tanks (T-2000 & T-2010) Slop Tank (T-2400)
Desand Tank (T-2300) De-Oiled Water Tank (D-3000)
Fresh Water Tank (T-3240) Brackish Make-up Water Tank (T-3210)
Boiler Feed Water Tank (T-4000) Off- Spec Oil Tank (T-7100)
Induced Gas Flotation Vessel (V-2100) Oil Recovery Tank (T-2500)
Fuel Gas Header Make-up Purge Gas
The vapour recovery unit (VRU PKG 9100) will collect vapours from the above sources through
a header system that feeds into the VRU. Vapours will be cooled with glycol and then sent to an
inlet scrubber where gases and liquids will be separated. Gases will be compressed in the VRU
compressor (K 9120A/B/C) and sent to the outlet scrubber for injection into the produced gas
separator and burned in the steam generators. Liquids will be pumped (P9130 A/B) to the
produced water skim tank and/or slop oil tank for further treatment and hydrocarbon recovery.
The VRU will be equipped with three compressors (K9120 A/B/C); two – 50% use electric drive
compressors will be utilized on regular service, the third electric drive compressor will be utilized
should one of the regular service compressors fail. An emergency generator will be sized to
accommodate one of the VRU compressors along with other critical plant functions. Should all
of these fail, a shutdown will be initiated immediately. This will facilitate mitigating upset
conditions as well as maintenance without using the low pressure flare.
Both a high pressure and low pressure flare system will be installed at the plant for emergency
relief flows. Each system will include a knock-out vessel, pumps from the vessel and a flare
complete with pilot, flame monitoring and a closed circuit television. The high pressure flare (F-
9020) will only be utilized in emergency situations where the inlet degasser requires relief due to
well operations. The low pressure flare is designed to handle VRU vapour, in case of VRU
compressor failure. The emergency generator will provide power to the VRU in the event of a
power failure. A shutdown will be initiated upon an emergency generator failure. The LP flare
will be utilized to vent off any remaining vapours during shut down. Liquids recovered in the flare
knock out drums will be sent to the slop oil tank for treatment.
7.7 Energy & Heat and Material Balances
The Heat and Material Balances for the Project are presented in Appendix 7.2.
7.7.1 Energy Balance
The energy sources required to operate the facilities and wells consist of produced natural gas,
pipeline quality natural gas and electricity. Pipeline quality gas is routed to the wells to act as a
medium for all of lift gas, bottom hole pressure measurement, gas blanketing in the annulus of
the wells for thermal insulation, well integrity monitoring, and to provide a buffering agent in the
production tubing against pinholes created by steam flashing. Wellhead produced gas
consisting of solution gas and by products of aquathermolysis is combined with tank and vessel
vapors, additional pipeline quality gas and is used to fire the boilers. Steady state demand for
gas is expected to be in the order of 210 e3m3/day. Electricity is used for all pumps and motors
to limit both greenhouse gas emissions and noise. The steady state electrical load is expected
to be in the order of 5MW, well below the demand that would make cogeneration feasible.
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Table 7.7.1-1 Energy Balance
Total Energy In
Bitumen from Wells
Chemical Energy Flow (GJ/day)
31 363 GJ/day
Diluent Feed
Chemical Energy Flow (GJ/day) =
8861 GJ/day
Reservoir Gas
Chemical Energy Flow (GJ/day)
761 GJ/day
Natural Gas
Chemical Energy Flow (GJ/day) =
7197 GJ/day
Electricity Import
Electrical Power (GJ/day) =
335 GJ/day`
Total Energy Out
Saleable Product (Dil-Bit Blend)
Chemical Energy Flow (GJ/day) =
40586 GJ/day
Total Energy In (GJ/day) =
Total Energy Out (GJ/day) =
Energy Efficiency (%) =
Efficiency
48522 GJ/day
40586 GJ/day
84%
Table 7.7.2 Heating Values
Bitumen 0.0399 GJ/kg
Diluent 0.0426 GJ/kg
Reservoir Gas 0.0305 GJ/kg
Natural Gas 0.0457 GJ/kg
7.8 MARP Conceptual Plan
The Measurement and Reporting Plan reporting plan includes both the production battery and
injection facility for the purposes of the ERCB registry reporting.
All flow streams that cross the CPF boundary limit will be measured or estimated depending on
volumes and operational requirements.
The metering requirements are presented on the attached Process Flow Diagrams with the
notes. Oil, water and gas production will be based on the production battery balance of
inventory, dispositions and receipts, and the injection facility will have zero production. Oil, water
and gas production will be pro-rated to wells based on individual well metering. The simplified
reporting structure and water reporting will be based on ERCB Bulletin 2006-11 (ERCB 2006),
the ERCB draft directive Requirements for Water Measurement, Reporting and Use for Thermal
In Situ Oil Sands Schemes (ERCB 2009) and Directive 17.
7.8.1 Objectives
The project metering objective is to ensure that the required flow meters are properly selected,
installed and configured to accurately determined volumes of all the liquids and gases entering
or leaving the plant as required by ERCB.
The following methodology is considered for measuring report of the plant to ERCB Registry:
A Distributed Control System (“DCS”) receives process data for the plant control. Flow
data are stored for a daily reporting;
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Process and volume data will be stored in a production accounting drive or process
historian;
Volume data, well tests, tickets, and receipts will be fed into the production volume
reporting system. A manual upload, using Microsoft Excel, is performed to load data into
production accounting software;
Measured data (volume) with manual inputs, will be fed into the production volume
reporting system for daily production and allocation totals; and
Production accounting generates ERCB registry database.
7.8.2 Process Flow Metering Schematic
The process flow metering, which is laid out on the process flow diagrams, covers both the
production battery and injection facility parts of the plant requiring measurement and reporting to
ERCB. These drawings will be part of the MARP and contain the following major equipment and
information required for accounting and measuring all relevant flows and levels throughout the
plant.
All wells associated with the scheme, representing each well tie-in to the surface
facilities; crude bitumen wells, steam injection wells, disposal wells, and brackish and
fresh water wells.
All surface facilities associated with the scheme, including process equipment for
bitumen treating (free water knock-out drum, treater and diluent recovery separator),
test facility, produced gas handling & mixing and flares, produced water de-oiling (skim
tank, induced gas flotation unit and oil removal filters), water treatment (process water
and fresh water treatment systems), steam generation (drum boiler), disposal and waste
handling (neutralization and dewatering unit),
All applicable receipt points includes gas pipeline, diluent pipeline and truck in (at this
stage only chemicals) and associated LACT,
All applicable disposition points includes pipeline and associated LACT,
All applicable flow lines such as, fuel lines, flare lines, recycle lines, skim lines, steam
and utility lines,
All applicable bitumen, slop oil, and water tanks,
All applicable flow measurement devices and product analyzers (type of devices will be
determined when selected). All flow measurement will be of an electronic type. The
measured signals will be sent to the DCS. All meter compensation, correction factors
and totalizing will be done in the DCS with the exception of a few (e.g. devices located at
the well pad area as a remote location relative to the central processing facility) that
depend on the location of the instruments that could be reporting back to the plant DCS
by a wired data or radio link, and
Manual emulsion sampling at the producers, manual input of result into the DCS, store
to history drive and feed to the production accounting system.
Figure 7.8.2-1 shows a simplified MARP schematic.
The production battery will be a multi-well proration battery, with bitumen, water and gas
production rates being determined by a volumetric balance of the battery limits. This will include
lease fuel as well as an estimation of light ends transferred to the gas system. This will be
accomplished through flow measurement of the total gas stream and gas chromatography
analysis of the stream for light ends. The battery is the main custody transfer for diluent,
blended sales and fuel gas streams associated with the Project. Condensate with a density of
approximate 711 kg/ m 3 is the type of diluent planned for use in treating and blending activities.
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The injection facility will be a water facility and will not include any oil production or inventory. It
will be set-up to allow for zero gas production. Gas co-injection and lease fuel at the end-users
will provide the total volume transferred from the production battery. The water balance will not
fully “close”, but is expected to have a closure error less than two percent. If the closure error
grows to, or exceeds, five percent, Birchwood will rectify the error through review of applicable
data and meter calibration. Disposal water will be trucked out until the disposal injection well is
ready and approved for use.
7.8.3 Boundary Streams
The following flow streams cross the boundary between the production battery and the injection
facility:
Produced water downstream of the oil removal filter;
Utility water and seal flushes from fresh water treatment system;
Steam from drum boiler to the well injection pads;
Mixed fuel gas to drum boiler; and
Sweet fuel gas to well injection.
Produced water will be directly metered, as this is a critical number in the water balance. Utility
streams will be metered where flow magnitude dictates, and will be estimated based on
engineering design numbers where volumes are less than 3% of the total water. These
estimations will be verified annually or more frequently as required. Steam for well injection
pads is calculated by measuring total-in flow of boiler feed water and total-out flow of boiler blow
down and utility steam use.
7.8.4 Project Wells
Injection and production wells are associated with both the injection facility and the production
battery during the circulation phase (usually a few months). Once the wells are turned to steam
assisted gravity drainage mode, production wells are associated with the battery and injection
wells are associated with the injection facility. All water source and disposal wells are
associated with the injection facility. All water production wells and water reinjection wells are
associated with the injection facility.
A test separator will be used to measure and prorate water and oil production. The proration
factor for both water and oil will be kept within the regulated range of 0.85 to 1.15. It is expected
that the proration error will average less than 10%.
7.8.5 Project Meters
Metering groups associated with the Project are listed below:
• Boiler blowdown;
• Boiler feed water;
• Brackish water source;
• Casing gas;
• HP & LP flares;
• Fresh water source;
• Gas co-injection;
• Gas injection (and co-injection);
• Injection facility lease fuel;
• Pipeline blend;
• Pipeline diluent;
• Pipeline gas;
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• Produced gas;
• Produced water;
• Produced water disposal;
• Test separator liquid and gas streams;
• Evaporator blowdown;
• Steam injection;
• Utility water and steam.
7.8.6 Facility Tankage
All applicable accounting tanks are listed in the following Table.
Table 7.8.6-1 Tank Listing
Tank Tag Product Volume Diameter Height
(m3) (mm) (mm)
Injection Facility
T-4000 Boiler Feed Water Tank 2690 16764 12192
T-2000 PW skim Tank 2050 14630 12192
T-2010 PW Skim Tank 2050 14630 12192
T-3000 Deoiled Water Tank 2690 16764 12192
T-2300 Desand Tank 475 7045 12192
T-3440 Neutralization Waste Tank 100 TBD TBD
T-3210 Brackish Make-up Water Tank 80 4572 4877
T-3240 Raw Fresh Water Tank 80 4572 4877
T-9450 Utility Water Tank 11 TBD TBD
T-9650 Domestic Water Tank 5 TBD TBD
T-3500 Waste Water Tank 450 6857 12192
Production Battery
T-7000 Sales Oil Tank 450 6857 12192
T-7010 Sales Oil Tank 450 6857 12192
T-2500 Slop Oil Tank 410 6900 10973
T-2400 Oil Recovery Tank 410 6900 10973
Tanks associated with the injection facility are considered to be 100% water, and vessels or
tanks with consistent inventory are not included.
Tanks associated with the production battery are typically considered to be an emulsion type
(both oil and water). Vessels assumed to have relatively constant make-up and volume are not
included for accounting. These include, but are not limited to, treater, induced gas flotation unit,
oil removal filters, pad test vessel and pipeline inventory.
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7.8.7 Project Dispositions and Receipts
The following table outlines the planned disposition and receipt points for the production battery.
Table 7.8.7-1 Production Battery Disposition and Receipt Points
7.9 Chemical Use
Product Disposition/Receipt Name
Water Disposition SAGE Injection Facility
Dilbit Disposition Husky
Condensate Receipt Husky
Gas Disposition SAGE Injection Facility
Gas Receipt Alta Gas
Chemicals will be added to the produced water treatment, the bitumen treatment, water disposal
and the utility water treatment systems. At each point of injection, a static mixer will be installed
downstream of the chemical injection quills to enhance the penetration of chemicals into tight
emulsions.
7.9.1 Produced Water Treatment Stream
The steam generation plant will be equipped with three chemical injection packages; a Sulphite
Injection Package, a Chelant Injection Package and an Amine Injection Package. The chemical
injection rate will be automatically adjusted in relation to the BFW flow rate. Oxygen scavenger
and chelant will be injected into the BFW pumps suction header.
7.9.1.2 Feed Water
Magnesium Oxide, caustic, scale inhibitor/dispersant and antifoam/foam control chemicals are
added to the feed water at various stages of feed water processing.
Magnesium oxide slurry is used to condition the feed water prior to commencing steam
generation or water treatment as an elevated suspended solids level is required to initiate the
steam generation and water/bitumen treatment processes. Magnesium oxide is added to the
system from the Mag Ox silo (T-3330). This is shown in Figure 7.2.3-1B. Magnesium oxide
prevents scaling while rapidly allowing for the development of silica and other potentially scaling
constituents including magnesium hydroxide and calcium carbonate. Magnesium oxide demand
is proportional to the amount of silica in the produced water stream and is metered via a screw
conveyor into a slurry mix tank.
Caustic is required to maintain the proper pH for silica precipitation. Caustic is added to the
incoming feed to control the pH in the evaporator. The system consists of two metered pumps
and a tank; the two pumps are dedicated to the incoming feed and can be used to adjust the pH
in the feed conditioning tank (start-up) or to trim pH in the evaporator.
Scale Inhibitor/dispersant is utilized to control suspended solids and mineral build up that occurs
on heat exchange surfaces. The scale inhibitor/dispersant can be added in small doses to
prevent scaling on the de-aerator. The scale inhibitor can be dosed to the feed line prior to the
in-line mixer on a continuous basis.
The foam control package will control the foam that can occur due to the presence of organic
compounds carrying over with the vapour and potentially impacting the compressor operation
and distillate quality. The package will include two metering pumps, video cameras, lights and
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monitors for the evaporator. Antifoam can be added to the evaporator feed or sump, on an as
needed or continuous basis; this will depend on the foaming propensity of the produced water.
7.9.1.3 Boiler Feed Water
Boiler Feed Water will be treated with a sulphite oxygen scavenger, chelant and amine. The
sulphite scavenger will remove residual dissolved oxygen in the BFW. The scavenger will
minimize corrosion.
Chelants bond to various cations such as iron, magnesium and calcium and will minimize the
deposition of chrystalline deposits in the boilers. Amine is added to steam condensate to protect
piping from corrosion by neutralizing acidic compounds and by forming a protective film on
metal surfaces.
7.9.2 Bitumen Treatment
7.9.2.1 Free Water Knockout Tank
Clarifier, diluent and demulsifiers must be added to the produced fluid (oil and water) stream
prior to entering the FWKO tank, in order to ensure oil separation.
1. Clarifiers, in the form of polymers, will assist in coalescence of oil droplets in the skim
tanks and will be added to the system upstream of the FWKO vessel and treater. The
rate of addition will be dependent on the water fraction of the emulsion and is estimated
to range between 100 ppm to 200 ppm.
2. Diluent will be injected into the system to upstream of the FWKO and treater as well as
prior to entering the LACT unit. In the water treatment phase, the diluent will increase the
density differential between the oil and water phases of the emulsion and thereby allow
separation via gravity and ensure the oil phase floats on the water phase. The injection
rate will be designed to produce a blended dry oil-phase gravity of about 12 o API or ~
27% diluent fraction in the dil-bit blend. The injection system will be designed to deliver
twice this rate to respond to variations in bitumen density as well optimizing treater
performance and managing treatment upsets.
During abnormal operating conditions the diluent injection rate will be kept at a minimum
dosage that can produce sales oil product that meets pipeline specifications. Over
dosing with diluent can lead to excessive vapour generation during the treatment
process. The FWKO and treater pressure must be maintain above 400 kPa to control
flashing and prevent the diluent from boiling.
3. Demulsifiers will help coalese water droplets in the oil phase. Demulsifiers will be
injected upstream of the FWKO and treater. The rate of injection will vary in accordance
with the oil fraction of the emulsion and is estimated to range between 200 ppm to 400
ppm.
7.9.2.5 Induced Gas Flotation
A chemical injection quill is provided on the suction portion of the IGF for injection of clarifier if
required during start up.
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7.9.2.5 Sales Oil
Injection of diluent prior will also occur prior to the sales oil entering the LACT unit in order to
reduce viscosity of the treated oil and frictional drag in the market pipeline.
7.10 Services and Utilities
7.10.1 Field Office Facility and Camps
A small area, as shown in the NE area of the facility design in Figure 7.1-1, will be developed to
accommodate workers needs for administration, sanitization, washrooms facilities and meals
and a separate storage area.
Birchwood does not propose to utilize a construction camp for the housing of workers during the
preparation of the well pad and central processing facility, for the assembly of the modular
central processing facility or the drilling of the well pairs. Workers can be adequately housed in
Cold Lake existing facilities. Birchwood has given due consideration to other industrial activity in
the area and has planned the construction phase, which will require approximately 100
employees over a three month period, to be timed such that we avoid conflicts with other
industrial, municipal and commercial developments. In addition, Birchwood has been in contact
with hotels in both the Bonnyville and Cold Lake area and has tentative arrangements to book
room blocks for personnel.
7.10.2 Highways and Rights of Way
Access to the site for construction and operations are specified in Section 2.3. Highway 892
and Birchwood's access roads will provide the routes necessary to access the site from Cold
Lake and Bonnyville.
7.10.3 Utilities
7.10.3.1 Electrical Power
The normal operating electrical load is estimated at 5 MW. Power will be brought to the site via
an electrical connection from Atco Electric. Atco will supply 25 kV line up to the plant boundary
and tie-in the connection with an above ground 25kV cable. Low power distribution transformers
(25kV-480 V) fed from the 25 kV disconnect switch will provide the low voltage power
distribution for the CPF and well pad. Given the accessibility of low interruptible electrical supply
and the limited demand, cogeneration not considered to be economically feasible.
The main consumers of power are motors. The equipment list is Appendix 7-1 includes all the
known motors and electrical demand. A full service backup generator for emergency upset
conditions is not included in the design however a temporary power generator set for
emergency lighting, glycol circulation, and vapor recovery.
The grounding resistor for the 480 Volt system consists of high resistance grounded at 5 amps
through a 5 amp neutral grounding resistor connected to each transformer.
7.10.3.2 Natural Gas
Natural Gas will be provided to the facility by Altagas. The natural gas will be piped to the CPF
at a minimum delivery pressure of 5000 kPa.
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7.10.3.3 Pipelines
7.10.3.3.1 Diluent Pipeline
Diluent from the Husky diluent line, license # 19114-73, running adjacent to the eastern edge
(see Figure 1.2-3) of the CPF pad will be utilized as the diluent source for the plant. The diluent
pipeline into the plant site is expected to operate with sufficient pressure and reliability that there
will be no requirement for a diluent storage tank or diluent injection pump(s). The Diluent riser
will be equipped with an emergency shut-off valve and the flow will be measured and totalized
to reconcile with custody transfer records. Space has been allowed should there be a
requirement for Diluent storage.
7.10.3.3.2 Sales Pipeline
The Husky crude oil emulsion line, license 19115-73, will be utilized to access sales markets.
7.11 Health, Safety and Environmental Controls
Protection of the health and safety of community residents, Birchwood and contractor personnel
and the environment are of fundamental importance to Birchwood Resources Inc. To this end,
safety and environmental management programs will be developed which provide general
direction for protecting human and natural elements as well as very specific training
requirements and safe work operating procedures for controlling and/or mitigating hazards and
environmental degradation. The various components identified include:
Health and Safety Program
Codes of Practice Program
Corporate Emergency Response Plan
Employee Health Safety and Environment Handbook
Domestic and Hazardous Waste Management Program
Pipeline Installation and Monitoring Program
Quality Control Program
In addition, Birchwood follows the requirements laid out in various IRP's and Manuals
developed by industry associations in conjunction with government agencies.
7.11.1 Facility Emergency Response Plan
A Corporate ERP has been developed and implemented. The plan will be further expanded to
incorporate evacuation requirements for residences in proximity to the well pad and CPF,
escalation of alerts and call down procedures, external emergency involvement (eg., registration
with STARS, agreement with local area hospitality organization for establishment of a local
emergency response center), and additional training will be provided to Birchwood's staff to
ensure they remain current with the plans elements. As well, participation in a desk top
simulation with the ERCB and other third parties will be scheduled to be conducted prior to the
commencement of the project's circulation phase.
The current ERP addresses incidents and accidents outlined in ERCB Directive D-71.
Amendments to the ERP will have to address following additional incidents:
Central Processing Facility Shut Down
Well Pad and/or Well bore shut down
Fire in or on company facilities
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Wildfire Prevention
Steam Line Rupture
High Pressure Vapour Equipment
The site specific Emergency Response Plan will be forwarded to the ERCB for approval prior to
commencement of plant operation.
7.11.2 Fire Control Plan
There are two potential fire types that could occur at or near the Birchwood proposed facilities; a
wildfire could break out in the area or a fire could start at an ignition source in the company's
facilities. As part of the site specific ERP, Birchwood will developed a Fire Control Plan to be
approved by Forest Protection Division of ESRD. The following provides a summary of
protection measures for both types of fires.
7.11.2.1 Wildfire Prevention
The leading cause of fires in or around oilfield facilities are brush burning, flaring, ATV use and
cooking. All such fires are preventable using various mitigation and Best Management Practice
techniques. Other fire control issues will be identified, along with mitigation measures, in
Birchwood's Fire Control Plan that will be approved by AESRD prior to construction.
7.11.2.2 Facilities Fire Protection
The potential sources of fire resulting from the project, and associated mitigation strategy are as
follows:
Internal operations in the CPF:
Non-combustible materials will be used in building construction where possible,
Buildings will be placed to allow adequate spacing between buildings to prevent fires
from spreading,
Every building in which hydrocarbon liquids and/or produced gas vapours will be
equipped with Lower Explosive (LEL) and/or H2S detection monitors.
All internal combustion engines will be equipped with flame arrestors.
Fire alarms will be installed in areas where there is potential for fire to occur. Fire eye
sensors capable of detecting open flame will also be placed in critical areas of the CPF.
Detectors, alarms and sensors will be tied into the process control system allowing for
prompt response should an incident occur.
7.11.3 Air Emissions Management
The CPF will utilize a Vapour Recovery System to capture all continuous vapours and re-use
them as a fuel source. Fugitive emission monitoring will be in compliance with the Canadian
Council of Ministers of the Environment (CCME) Code of Practice Measurement and Control of
Fugitive Volatile Organic Chemicals (VOC) Emissions from Equipment Leaks.
The plant will be equipped with air monitoring devices as required by Section 14 of the AEPEA,
specifically the "Alberta Ambient Air Quality Guidelines", the Lower Athabasca Regional Plan
(LARP), and Environment Canada's "Protocals and Performance Specifications for Continuous
Monitoring of Gaseous Emissions from Thermal Power Generation".
All NOx emitting equipment will utilize low NOx burner technology as required by the LARP.
Specific air monitoring requirements, including sampling locations, frequency, parameters to be
monitored and reporting requirements will be issued by AESRD upon approval of the facility.
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Birchwood will participate in LICA air monitoring initiatives to assist in monitoring cumulative and
regional air quality information.
Air quality model results are summarized in Section 8.3.2 – Environment Conditions and in
Consultants Report 2 Air Quality Model Results.
7.11.4 Noise Emissions Management
Noise levels at the plant will be maintained at or under the conditions prescribed in ERCB
Directive 38 "Noise Control", the "Alberta Occupational Health and Safety Act" and the "Alberta
Occupational Health and Safety Regulations".
The primary sources of noise release in the proposed project are compressors, pumps,
generators, blowers, coolers (fans) and control, switching and vent valves. This equipment is
housed in buildings or equipment specific enclosures providing mitigation. Initial noise modeling
indicates that the daytime and nighttime noise levels are within the limits required by the ERCB
(See Section 8.4 – Environment Conditions and Consultants Report 3 Noise Assessment).
Noise levels inside buildings may not meet OH&S requirements for personal safety and as such
safety equipment (ear plugs/muffs) will be required in certain areas of the facility to prevent of
hearing loss.
7.11.5 Spill Control and Leak Detection
Engineered containment systems will be utilized wherever there is the potential for a release
from process equipment. Where practical, all systems that contain hydrocarbons, chemicals and
brackish water will be designed to allow for visual inspection for leaks. All containment systems
will be in compliance with Directive 55 "Storage Requirements for the Upstream Petroleum
Industry". In addition, above ground lines will allow for leaks to be readily observed.
The base of the facility and well pad will be composed of clay or cement thereby preventing
migration of spills into the soils below facilities. The site will be bermed to provide adequate
retention of any spills on location. Spills will be reported to the ERCB/AESRD as required by
regulatory requirements. Any incident are required to be investigated as per the Corporate ERP
and quality assurance programs.
7.11.6 Surface Water Management
It is anticipated that the site will be bermed and that a contoured, compacted clay base will
underlay all of the wellhead, pipeline, production and storage modules. A surface water run off
drainage pond has been included in the plot plan design sized to manage seasonal
precipitation. Water in the pond will tested, treated and either released off site or, if untreatable
for release, used in the process or hauled to an approved disposal facility. Site contouring will
ensure that all run off is collected in the pond.
7.12 Chemical and Waste Management
7.12.1 Chemical Management
A Chemical Management Program has been established to effectively control on-site chemical
hazards, usage and inventory. Chemicals used on site will be managed in accordance with
Transportation of Dangerous Goods Act and Regulations (TDG) and Workplace Hazardous
Materials Information System (WHMIS), with individuals trained in accordance with
requirements.
Sage Pilot Application Page 144

Table 7.12.1-1 provides the required chemicals for the proposed SAGD process as well as the
injection point, storage and estimated annual useage:
Table 7.12.1-1 Chemical Summary
Chemical
Delivery
Method
Injection Point Storage Method
Annual Volume
Treating Demulsifier Trucked In FWKO/Treater Bin on Site 126.5
Reverse Demulsifier Trucked in FWKO/Treater Bin on Site 100.5
De-oiling Polymer (c/w
Dilution Water)
De-oiling Coagulent (c/w
Dilution Water)
Caustic (Sodium Hydroxide
- 50%)
Water Treatment Anti-
Foam Agent
Disposal Treating
Magnesium Oxide
DisposaL Treating
Hydrochloric Acid
Disposal Treating Sodium
Hypochlite
Disposal Treating Sodium
Bisulphate
BFW System Oxygen
Scavenger
Trucked In
Skim Tanks - A & B
IGF In
IGF Out
Sage Pilot Application Page 145
M3
Bin on Site 157.0
Trucked In ORF Back Wash Bin on Site 10.1
Trucked In Evaporator Bin on Site 384.0
Trucked In De-aerator Bin on Site 10.3
Trucked In Evaporator Silo on Site 319.0
Trucked In Neutralization Tank Bin on Site 230.0
Trucked In Disposal Water Tank Bin on Site 10.0
Trucked In Disposal Water Tank Bin on Site 0.8
Trucked In Boiler Feed Water Bin on Site 24.4
BFW System Chelant Trucked In Boiler Feed Water Bin on Site 9.7
Steam Injection Filming
Amine
Domestic Water
Hypochlorite
Trucked In HP Steam/ Utility Steam Bin on Site 3.7
Trucked In
Domestic Fresh Water
Feed
Bin on Site 2.5
Utility Water SAC Salt Trucked In Utility Water Feed Sacks on Site 107.7

7.12.2 Waste Management
A Waste Management Program has been established for the proposed project in order to
effectively limit potentially hazardous waste generation as well as minimize other waste
generation and the associated waste disposal required. In accordance with Directive 58, the
primary goals of the program will be to reduce, re-use, recycle and recover. In accordance with
Directive 58 as well the Waste Control Regulation, the following program requires the following:
Classification of DOW and NDOW wastes, measurement of waste and controlling waste
generation,
Proper handling, storage, treatment (if required) and disposal,
Ensuring waste transporters are trained in handling the waste streams they are
accepting for transport,
Ensuring facilities that accept various waste streams are properly approved/licensed to
accept such streams for further treatment, recycling or disposal, and
Documenting, tracking and reporting of waste streams generated at company facilities
including the disposal method proposed and actually used at various facilities.
Construction Waste will be minimal as the buildings, associated facilities and pipes will be
prefabricated in a facility in Airdrie. The waste generated at that location is currently recycled or
disposed of at approved facilities. Small volumes of waste will be generated at the facility
location during construction. This waste will be contained in bins which are segregated. Wastes
will be sorted and placed into the relevant container in order for transport to a recycling facility,
wherever possible. If recycling is not an option, the waste will be transported to a suitable,
approved where required, disposal facility. Various options exist within a relatively close area to
the facility and well pad location, including the Tervita Class II landfill, the Beaver River Regional
Waste Management Commission transfer stations, Lindbergh Salt Cavern, and Ardmore
Landfill.
Sage Pilot Application Page 146

Figure 7.1.1 CPF and Well Pad Plot Plan
Sage Pilot Application Page 147

Figure 7.1.2 3D Model of CPF and Well Pad
Sage Pilot Application Page 148

Figure 7.2.2 Process Flowsheet 200-1 Wellpad
Sage Pilot Application Page 149

Figure 7.2.2-A Block Flow Diagram - De-Oiling, Water treatment and Steam Generation
Sage Pilot Application Page 150

Figure 7.2.2-B Water Balance - De-Oiling, Water treatment and Steam Generation
Sage Pilot Application Page 151

Figure 7.2.1-1 Process Flowsheet 100-8 Steam Generation
Sage Pilot Application Page 152

Figure 7.2.2-1 Process Flowsheet 100-6 Water Treatment
Sage Pilot Application Page 153

Figure 7.2.3-1A Process Flowsheet 100-7A Water Treatment
Sage Pilot Application Page 154

Figure 7.2.3-1B Process Flowsheet 100-7B Water Treatment
Sage Pilot Application Page 155

Figure 7.2.3-2 Process Flowsheet 100-1 Inlet Process
Sage Pilot Application Page 156

Figure 7.3-1 Process Flowsheet 100-2 Bitumen Treating
Sage Pilot Application Page 157

Figure 7.3.1-1 Process Flowsheet 100-4 De-Oiling
Sage Pilot Application Page 158

Figure 7.3.2-1 Process Flowsheet 100-5 Desand and Slop Oil
Sage Pilot Application Page 159

Figure 7.3.3-1 Process Flowsheet 100-3 Bitumen Storage
Sage Pilot Application Page 160

Figure 7.4-1 Process Flowsheet 100-9 Glycol System
Sage Pilot Application Page 161

Figure 7.5-1 Process Flowsheet 100-10 Utilities Instrument Air/Fuel Gas
Sage Pilot Application Page 162

Figure 7.6-1 Process Flowsheet 100-11 Vapor Recovery
Sage Pilot Application Page 163

Figure 7.8.2-1 Simplified MARP Schematic
Sage Pilot Application Page 164

Appendix 7.1 Equipment List
Sage Pilot Application Page 165

Sage Pilot Application Page 166

Sage Pilot Application Page 167

Sage Pilot Application Page 168

Appendix 7.2 Heat and Material Balance
Sage Pilot Application Page 169

Sage Pilot Application Page 170

Sage Pilot Application Page 171

Sage Pilot Application Page 172

Sage Pilot Application Page 173

Sage Pilot Application Page 174

Sage Pilot Application Page 175

Sage Pilot Application Page 176

Sage Pilot Application Page 177

Sage Pilot Application Page 178

Sage Pilot Application Page 179

Sage Pilot Application Page 180

Sage Pilot Application Page 181

Appendix 7.3 Waste Management Table
Waste Type ERCB Waste Code Storage
Volume
Construction
Location
Month
Absorbents OILABS BIN As
generated
Cardboard CONMAT/NDOW BIN As
generated
Electrical
BIN As
Wiring
generated
Glass CONMAT BIN As
generated
Insulation CONMAT BIN As
generated
Lube Oil LUBOIL Dedicated Container None
Identified
Oil filters FILLUB Dedicated Container None
Identified
Paint WPAINT Dedicated Container None
Identified
Packing
DOMWST BIN As
Materials
generated
Pallets CONMAT Dedicated
As
Container/BIN
generated
Welding Rods CONMAT BIN As
generated
Wood CONMAT BIN As
generated
Disposal
responsibility
Disposal
Method
Disposal Location
Operator Recycle 3rd party-licensed facility holder
Operator Recycle 3rd party –licensed facility holder
Operator Recycle 3rd party –licensed facility holder
Operator Recycle 3rd party - licensed facility holder
Operator Dispose Class II landfill
Operator Recycle 3rd party –licensed facility holder
Operator Recycle 3rd party- licensed facility holder
Operator Recycle 3rd party – licensed facility holder
Operator Dispose Class II landfill
Operator Recycle/
Dispose
Return to Supplier/Class II landfill
Operator Dispose Class II landfill
Operator Reuse/
Dispose
Some wood may be reusable (eg pallet
material) Class II Landfill
Sage Pilot Application Page 182

Waste Type ERCB Waste Code Storage
Location
Drilling Operations
Cement Cement/NDOW N/A
Drilling Mud
and Cuttings –
surface hole
(gel chem)
Drilling Mud
and Cuttings –
intermediate
and bottom
hole (invert
mud)
NDOW Tank
SOILCO Tank
Volume
Month
5-8m3 per
well
100-150m3
per well
200-300m 3
per well
Disposal
responsibility
Disposal
Method
Disposal Location
Operator Bury Bury on-site
Operator
Operator
Sage Pilot Application Page 183
Land
spread
Cavern
Disposal
NE-01-064-04W4M
Approved processing facility - Tervita
Lube Oil LUBOIL Dedicated container Variable Operator Recycle Approved processing facility (Tervita)
Mud Pails EMTCON Bin Variable Operator
Recycle/
Dispose
Class II landfill
Mud Sacks EMTCON Bin Variable Operator Disposal Class II Landfill
Pipe Dope
Containers
EMTCON Bin Variable Operator Recycle Return to supplier
Pallets CONMAT Bin Variable Operator
Recycle/
disposal
Return to mud company
Scrap Metal SMATAL Bin Variable Operator Recycle Approved 3rd party

Waste Type ERCB Waste Code
Storage
Location
Volume
Month
Disposal
responsibility
Disposal
Method
Disposal Location
Facility Operations
Containers: Treating
Demulsifier
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Containers: Deoiling
Polymer
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Containers: Deoiling
Coagulant
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Containers: Treating
Reverse Demulsifier
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Containers: Water Treating
Caustic
CAUSTIC Bins
As
generated
Operator Recycle Return to supplier
Containers: Water Treating
Antifoam
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Containers: Disposal
Treating MagOx
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Disposal Treating
Sulphuric Acid
ACID
Sulphuric
Acid Tank
Vary with
Production
Operator Deep Well On facility pending approval
Disposal Treating Sludge ORGCHM Sludge Bins 63 m 3 Operator Deep Well On facility pending approval
Containers: Water/Disposal
Treating Sodium
Hypochlorite
Containers: Water/Disposal
Treating Sodium Bisulphite
Containers: BFW System
Oxygen Scavenger
Containers: BFW System
Chelant
Containers: Steam
Injection Filming Amine
ORGCHM Bins
ORGCHM Bins
CORINH Bins
ORGCHM Bins
ORGCHM Bins
As
generated
As
generated
As
generated
As
generated
As
generated
Operator Recycle Return to supplier
Operator Recycle Return to supplier
Operator Recycle Return to supplier
Operator Recycle Return to supplier
Operator Recycle Return to supplier
Sage Pilot Application Page 184

Containers:
Fresh/Domestic Water
Hypochlorite
Containers: Utility Water
SAC Salt
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
ORGCHM Bins
As
generated
Operator Recycle Return to supplier
Containers: Herbicide PSTCON Bins
As
generated
Operator Recycle Return to supplier
Containers: Pesticide PSTCON Bins
As
generated
Operator Recycle Return to supplier
Equipment Cleaning Waste WSHWTR Bins
As
generated
Operator 3rd Party Class II landfill
Evaporator Blowdown to
Disposal wells
WATER 10767.5 m 3 Operator
Disposal Water
Well
On facility pending approval
Batteries BATT Bins Variable Operator Recycle 3rd Party – licensed facility
Empty Containers EMTCON Bins
As
generated
Operator
Recycle/
disposal
Class II landfill
Filters FILOTH
Dedicated
Container
0.22 m 3 Operator
Recycle/
disposal
3rd Party licensed facility
Garbage: Office DOMWST Bins 2.41 m 3 Operator Dispose Class II landfill
Packing materials DOMWST Bins 2.3 m 3 Operator Dispose Class II landfill
Pallets DOMWST Bin 2.17 m 3 Operator Recycle Return to supplier
Process Blowdown Water
(produced water)
WATER
Produced Sand SAND
Rags: Oily OILRAG
Rag Layer Waste SLGEML
Septic Fluids WSTMIS
Waste Lube Oil LUBOIL
Storage not
required
Dedicated
container
Dedicated
container
Dedicated
container
Septic
System
Dedicated
container
10,754m3 Operator Recycle Return to process
As
Generated
Operator Disposal
Approved Cavern – testing required to
determine handling/disposal
0.23 m 3 Operator Recycle 3rd party – licensed facility
As
Generated
Operator
Recycle/
Dispose
Rag layer waste will return for
processing/Approved Disposal cavern
30-50m3 Operator Disposal Receipt at approved facility
0.05 m 3 Operator Recycle Approved Processing Facility
Sage Pilot Application Page 185

8 Environmental Review and Baseline Assessment
8.1 Overview
The Resource Development Area (RDA) contains both private and public lands. The Project
Development Area (PDA) lies wholly within Public lands and it is designated as “white zone” in
the Crown Land system.
Birchwood utilized the Lower Athabasca Regional Plan, 2012 (“LARP”), the Cold Lake Sub
Regional Integrated Resource Plan, 1996 (“CL SRIRP”), and the Crane Lake Area Structure
Plan (2006) (“CLASP”), public/stakeholder input from Open Houses and direct contact and the
various legislation as a baseline for determining the potential environmental issues and/or
impacts that could occur as a result of the proposed development:
Birchwood identified potential impacts in the following areas:
Land and Resource Use,
Traditional Land Use,
Historical Resources,
Air Quality Impacts,
Noise Impacts,
Water Quality Impacts (surface water, potable and non-potable groundwater)
Soil and Terrain Impacts,
Vegetation and Wildlife Impacts,
Socio-Economic Impacts,
Human Health, and
Socio-Economic Impacts
The proposed project is located at the southern portion of the Central Dry Mixed Wood Sub-
Region of the Lower Boreal Forest Region of North Eastern Alberta. The area is characterized
by "level to gently undulating glacial till, lacustrine plains and significant hummocky uplands in
the southern extents"). In undisturbed conditions, the upland Eco region supports a wide variety
of wildlife habitat including black bear, moose, fishers, numerous bird species and a small
number of amphibians and reptiles. Vegetation is predominately comprised of trembling aspen,
white spruce, low-bush cranberry on uplands. On lowlands vegetation is comprised of Jack
pine/black spruce, Labrador tea, feathermosses and bog-cranberry transitioning to fens and
bogs in the cold wet lower areas where black spruce, willow and bog birch, Labrador tea, few
forbs, feathermosses and peat moss exist.
Soils in the eco sub-region vary from coarse well drained Brunisols and Regosols, to medium to
coarse and mix textured Grey luvisols in the uplands where warmer and drier conditions prevail.
In colder wet areas soils range from variable textured imperfectly to poorly drained Luvisolic and
Gleysolic soils to organic soils.
There are numerous wetlands in the regional development area; Birchwood has located the
central processing facility and well pad to ensure that there is a minimum 300 m setback from all
existing wetlands. There is no requirement for the development of any water crossings.
Sage Pilot Application Page 186

The latitude and longitude co-ordinates of the proposed facility is as follows:
NW corner 54 o 30' 15.421" N
110 o 29 ' 25.755" W
SW corner 54 o 30 ' 05.074" N
110 o 29' 25.683" W
NE corner 54' 30 ' 15.418" N
110 o 29' 53.526 W
SE corner 54 o 30' 05.074 N
110 o 29 53.455" W
Figure 1.2-1 to Figure 1.2-3 illustrates the location of the proposed facility and the distance to
surrounding communities, residences, water bodies, infrastructure and industrial development.
8.2 Historical Resources
8.2.1 Aerial Photograph Review
The proposed Birchwood facility lies on predominantly cleared grazing land with forested land in
the south western portion of the Project Development Area. A review of aerial photographs
indicates that the land was undisturbed and forested from as late as 1949 to 1982. The aerial
photograph taken in 1950 shows a trail coming through the PDA on the central west portion of
the site, in 1977 the trail is no longer visual in the aerial photograph. The photograph taken in
1988 indicates that 10 ha of the land in the proposed development area were cleared for use as
pastureland for cattle grazing. Aerial Photographs of the location are provided in Section 2.4.10
Figures Figure 2.4.10A – Figure 2.4.10D.
8.2.2 Land Use
The land has been used for hunting and trapping, and cattle grazing. The land to the north and
northwest of the proposed development area, especially along the shore of Crane Lake, has
been used for camping, boating and associated "lake" recreational activities, since the mid to
late 1950's. There is a trail south of the lake shore and approximately 700-1000 m north of the
proposed development area that is used for hiking and all-terrain vehicles. The Sage project has
been placed to avoid interference with these activities.
The Municipality of Bonnyville has a Range Improvement Plan (CNT010013) in place that
expires in 2016.
Interviews with the grazing lease holder indicate that the land has been used for cattle grazing
for 10+ years and it was not productive from a vegetation point of view. In addition, there have
been no First Nations requests for access since the grazing lease was issued in 1975.
A detailed review of land use in the RDA and regional area is provided in Section 2.4.
8.2.2 Traditional Land Use
The proposed development area lies within First Nations Traditional Lands including possible
historical usage by the following First Nations:
Cold Lake First Nation
Beaver Lake Cree Nation
Heart Lake First Nation
Kehewin First Nation
Frog Lake First Nation
Sage Pilot Application Page 187

Whitefish – Goodfish First Nation
Birchwood conducted a Traditional Knowledge Assessment with the Cold Lake First Nation in
September, 2011 for the proposed access road and well sites. The report indicated that the land
would provide territory hunting, trapping and gathering/forage activities. The report also
indicated that there was a potential area of interest that lies on the northern edge of the
proposed development site. Upon completing the aerial photographic review, the area of
interest in question was determined to be a brush pile from logging activities.
Based on interviews with occupants, historical aerial photographs, existing development and
current land usage, the size of the proposed development area would have a little to no impact
on the traditional land uses.
8.3 Air Resources
8.3.1 Climate and Meteorology
The climate in the Central Dry Mixed-Wood sub-region is characterized by short dry summers
and long cold winters. Due to the extent of the central mixed wood sub-region across Alberta,
climatic and meteorological data is taken from Cold Lake A weather station; the average
temperature low ranges from -21.7 o C in January to a temperature high of 22.9 0 C in July. The
average mean temperature from May to September is 13.6 0 C and is -6.8 0 C from October to
April. Summer precipitation in the form of rain occurs mostly in May through August, and winter
precipitation in the form of snow occurs from September through to May. Average precipitation
(rainfall and snowfall) over the year is ~ 427 mm with ~ 299 mm during the May to September
growing season. A total volume of 8.3 billion m3 of water falls on the CLBRB each year and
91.5% of this precipitation evaporates or is transpired by vegetation into the air.
The average barometric pressure is 95 kPa. The area experiences low humidity, June, and July
and August have a humidity index rating above 30 on an average of 1, 3 and 4 days per year.
The area has not experienced a humidex over 35 in the past 30 years. Wind chill is mild relative
to other eco-regions and rarely gets below -30.
The following Table describes the design parameters for the plant to ensure that the facility can
withstand the climate within which operation will occur:
Table 8.3.1-1 Climate and Meterologic Data
Plant Elevation 550m ASL
Average Barometric Pressure 95 kPa (absolute)
Basic hourly wind pressure 0.31 kPa (1/10 yrs)
0.37 kPa (1/30 yrs)
0.41 kPa (1/100 yrs)
Earthquake Zone Za= 0
V = 0
Ambient Temperatures 30 0 C (summer design dry bulb)
20 o C (summer winter design dry bulb)
-40 o C (winter design dry bulb)
Precipitation 15 mm (design 15 minute rainfall)
94 mm (design one day rainfall)
Annual Precipitation 460 mm
Ground snow load: 1.6 kPa
Rain falling on snow 0.1kPa
Sage Pilot Application Page 188

8.3.2 Air Quality
Emissions from the facility will include Sulphur Dioxide (SO2), Carbon Monoxide CO, Nitric
Oxide (NO) and Nitrogen Dioxide (NO2) and Particulate Matter (PM2.5). The environmental
effects are described in detail in Consultant Report 2 Air Quality Assessment.
Alberta ESRD has addressed the necessity of controlling and monitoring emissions through the
development of the Alberta Ambient Air Quality Guidelines (AAAQG). Short term (1 hour)
objectives have been established for emissions of SO2 and NOx to protect human health and an
annual objective to protect ecosystem health. The ambient air guidelines also establish
objectives for CO and PM2.5 based on health effect criteria and includes one hour and eight hour
objectives for CO, and a 24 hour objective for PM2.5. These objectives are provided in Table
8.3.2-1.
Birchwood has completed a screening level dispersion assessment to determine if the
emissions from the plant meet the AAAQG. The model used was the refined AERMOD
dispersion model in accordance with the Air Quality Model Guideline (AQMG). The methodology
used for the assessment was to identify potential sources of emissions from the proposed
facility and pertinent associated data such as height, emission rate, etc., include building
profiles, area, wind directions and speeds, and topography. As required by the AERMOD
modelling system AERMET, a meteorological pre-processor that creates surface and data
profiles, and AERMAP, a terrain pre-processor that incorporates topography using Digital
Elevation Mapping (DEM) were used. The Building Profile Input Program (BPIP) was run to
account for building downwash.
The air quality modeling results indicate that the emission levels meet all the required AAAQG
standards set by Alberta ESRD during normal, maximum and emergency operating conditions
the summary is presented in Table 8.3.2-1. Dispersion modeling results are presented in Figure
8.3.2-1 and Figure 8.3.2-2.
Notes:
Emission Source
Table 8.3.2-1 Emission Sources and Physical Stack Parameters
Source Information Physical Stack Parameters
UTM NAD 83
Zone 12 E (m)
UTM NAD 83
Zone 12 N (m)
Height
(m)
Diameter
(m)
Exit
Velocity
Sage Pilot Application Page 189
(m/s)
Exhaust
Temperature
(K)
Glycol Heater 532242 6039661 6.1 0.61 10.1 481
Drum Boiler 1 532322 6039660 30.5 1.52 15.0 428
Drum Boiler 2 532333 6039660 30.5 1.52 15.0 428
Emergency
Generator 1
High Pressure
Flare 2
Low Pressure
532291 6039607 3.0 0.15 63.4 812
532281 6029530 40.5 26.58 3.0 1295
532281 6039530 21.9 15.63 0.3 1266
Flare 2
1
Stack parameters were adopted from the CAT diesel Emergency Generator (300 ekW) Model 3406C TA
2
Stack parameters for the HP and LP flares represent pseudo parameters, as determined by the ERCB flare spreadsheets. The physical
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
mm, respectively.

Table 8.3.2-2 Dispersion Model Predictions
Averaging Predicted Ambient Cumulative AAAQG Percentage
Period Concentration Background Concentration
of AAAQG
NO2 1 hour 156.1 20.7 176.8 300 58.9
Annual 1.7 3.8 5.5 45 12.2
SO2 1 hour 221.6 2.6 224.2 450 49.8
24 hour 10.6 1.4 12.0 125 9.6
Annual 0.8 0 0.8 20 3.8
CO 1 hour 157.2 458.0 621.0 15,000 4.1
8 hour 110.2 400.7 510.9 6,000 8.5
PM2.5 24 hour 1.5 7.0 8.5 30 28.3
Table 8.3.2-3 Emission Rates Used in Dispersion Modeling in (g/s)
Source Name NOx SO2 CO PM2.5
Glycol Heater1,2 0.133 0 0.667 0.014
Drum Boiler 11,2 0.912 0.608 8.106 0.127
Drum Boiler 21,2 0.912 0.608 8.106 0.127
Emergency
Generator3
0.970 0.125 0.189 0.053
HP Flare
(emergency)4
16.706 91.125 90.903 2.519
LP Flare
(emergency)4
0.499 52.211 2.713 0.094
Notes:
1Emission Rates for the glycol heater and drum boilers were provided by Birchwood. The glycol heater PM2.5 emission rate was estimated using US
EPA AP-42 (Chapter 1.4).
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
15.8 g/GJ heating input (mixed gas fired) performance target (AESRD, 2007).
3The emergency generator NOx, CO and PM2.5 emission rates are from CAT Diesel Emergency Generator (300 ekW) Model 3406C TA spec sheet. The
SO2 emission rate was estimated using US EPA AP-42 (Chapter 3.3).
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
LP upsets, respectively. The NOx, CO and PM2.5 emission rates are estimated using US EPA AP-42 (Chapter 13.5).
8.3.2.1 Fugitive Emissions
Fugitive emissions will be monitored in accordance with the application of the Canadian Council
of Ministers of the Environment (CCME) Code of Practice Measurement and Control of Fugitive
Volatile Organic Chemicals (VOC) Emissions from Equipment Leaks and the CCME
Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from
Aboveground Storage Tanks.
Prior to plant operations, Birchwood will have a capable third party conduct a facility inspection
to determine where fugitive emissions may be of concern and develop a monitoring program for
the facility in order to mitigate fugitive emissions.
8.3.2.2 Air Monitoring
Birchwood will install passive exposure stations for measurement of hydrogen sulphide (H2S)
and sulphur dioxide concentrations. The steam generator exhaust stacks will be equipped with
sampling facilities and will be installed, operated and maintained in accordance with the Alberta
Stack Sampling Code and the Air Monitoring Directive.
Sage Pilot Application Page 190

8.4 Noise Control
The proposed facility lies within a rural area where landowners could be impacted by the noise
that is generated at an industrial facility. There are two residences to the east of the proposed
facility that are within 1.5 km. The east campground of Crane Lake is approximately 1.7 km to
the west of the proposed facility and there are residences on the south west end of Crane Lake,
approximately 1.9 - 4.8 km from the site. The Husky pipeline terminal is 2.7 km to the south.
There are no other industrial facilities within 5 km of the proposed facility/well pad.
Birchwood has designed the facility such that the equipment that could potentially result in noise
related disturbance is housed within buildings or equipment specific enclosures and with the
pumps, fans and boilers being placed on vibration absorbing mountings. Birchwood has
conducted an initial noise impact assessment (see Consultant Report 3) which modeled
cumulative noise and low frequency Noise based on existing receptors and corresponding
permissible sound levels as per ERCB Directive 38 – Noise Control, and an estimation of sound
emissions from the proposed facility using known source emission equipment that will be placed
into the facility.
The assessment method used is as follows:
1. Identification of receptors and corresponding Permissible Sound Levels (PSL's),
2. Estimation of sound emissions form the proposed project facility,
3. Modeling of the sound emissions to predict sound levels at the receptors and to 1.5 km
radius of the plant using calculation standards, source directivity, temperature and
humidity, wind conditions and potential reflections, and
4. Comparison of the predictions to Directive 38 permissible sound levels.
The sound emissions were then modeled using Cadna/A (Version 4.0 135) noise prediction
software which uses environmental sound propagation calculation methods as prescribed by the
International Organization for Standardization Standard 9613.
The results of the cumulative noise assessment (Project Application Case) are presented in
Table 8.4-1:
Table 8.4-1 Predicted Noise Levels for the Project Application Case Meets
Receptor Ambient Sound
Level
Project Contribution
Level
PSL
Yes/
No?
(a)
Cumulative Sound
Level (b)
Permissible Sound
Level (c)
(dBa) (dBa) (dBa) (dBa)
Daytime Nightime Daytime Nightime Daytime Nighttime Daytime Nighttime
0700–2200 2200-0700 0700-2200 2200-0700 0700-2200 2200-0700 0700-2200 2200-0700
NR 1 45 35 41.8 37.7 46.7 39.6 50 40 Yes
NR 2 45 35 40.3 35.1 46.3 38.1 50 40 Yes
The Cumulative Noise assessment results indicate that noise levels are below ERCB target
levels of 50 dBA for daytime and 40 dBA for night time at receptors that are within the 1.5 km
range from the proposed facility. The highest predicted daytime cumulative sound level is at
receptor #1 and equals 46.7 dBa. The highest predicted nighttime cumulative sound level is also
at receptor #1 and equals 39.6 dBa.
8.4.2 Low Frequency Noise
The modeling indicates that the requirements for low frequency noise levels are met as
illustrated in Table 8.4-2. The low frequency noise assessment results indicate that the potential
for a low frequency noise condition is unlikely; additional assessments as per ERCB Directive
38 will be undertaken if required.
Sage Pilot Application Page 191

Location
Table 8.4-2 Low Frequency Noise Assessment Results
C-Weighted Sound
Level
A- Weighted Sound
Level
Difference dBC-dBA
(dBC) (dBA) dB
Daytime Nighttime Daytime Nighttime Daytime Nighttime
0700-2200 2200-0700 0700-2200 2200-0700 0700-2200 2200-0700
Potential
LFN
Condition?
(Y/N)
NR 1 57.2 52.8 41.8 37.7 15.4 15.1 No
NR 2 56.2 51.9 40.3 35.1 15.9 16.8 No
Birchwood intends to conduct additional noise assessment studies in the summer of 2013
(baseline ambient noise levels) and once the project is in operation. The latter studies will
measure baseline noise at the receptors within 1.5 km of the plant as well as detailed noise
measurement at the boundaries of the plant site and at other potential receptor locations if
required.
8.5 Water Resources
The proposed development is located within the Cold Lake Beaver River Basin (CLBRB) in
north central Alberta. The Basin is relatively small, covering approximately 3% of the province,
and encompasses approximately 22,000 km 2 of surface land area in the Lower Athabasca
region (see Figure 8.5.3-2). The area is has a wide variety of water uses including industrial,
municipal, domestic, agricultural, and recreational. Drainage in the CLBRB occurs through the
Beaver River which commences at Beaver Lake, runs eastward from Beaver Lake,
approximately 250 km through Alberta to the border with Saskatchewan, continues eastward
until joining the Churchill River at Isle a la Crosse then turns northward, enters Manitoba and
ultimately drains into the Hudson's Bay. The mean annual discharge at the Saskatchewan
Border is 653,000,000m 3 . The Basin is bordered to the north by the Athabasca River basin and
to the south by the North Saskatchewan River Basin.
The hydro stratigraphic units associated with each geological formation present in the study
area, as well as the geological period and other pertinent data are illustrated in Figure 8.5-1.
Figure 3.1 of Consultants Report 1.
8.5.1 Surface Water
Crane Lake is the nearest significant water body to the proposed development area and is
approximately 750 m north. Crane Lake has a surface area of 9.28 km2 and holds 77.4 x 10 6 m
of water. At its deepest point it measures 26 m, with a mean depth of 8.3 m. Water levels in the
Lake have fluctuated around 549.5 meters above surface level since 1980. Other lakes in the
area include Tucker Lake, 6 km north, Hilda Lake ~ 2km east and Ethel Lake ~ 5 km to east.
Crane Lake is situated on a morainal plain. It is a headwater lake with two minor inlets on the
northeast and west shores. The outlet is located on the east north east shore and flows
eastward into Hilda Lake and Ethel and eventually into the Beaver River 8 km south of the
proposed development site. Crane Lake is a popular recreational lake and is one of several
within this basin. The outflow area is protected under the CLSRDP.
The southern shore of Crane Lake is approximately 750 m from the edge of the proposed
location. The high water mark of a Ducks Unlimited reserve (LOC 79028) is 1.5 km + to the NE.
The nearest man made water surface body is a dugout currently used as a water source for the
cattle that graze on the land.
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The selection of the proposed CPF and well pad was, in part, based on a review of the surface
water hydrogeology in the surrounding area. Wetland complexes within the RDA and PDA were
classified according to the Alberta Wetland Inventory Standards, see Figure 2.3.11. The area
selected for the well pad and CPF exceed the minimum setback criteria that any wetland areas
are outside the 100m buffer and primary lakes outside the 300m buffer zone for wetland
protection.
Appropriate site construction and grading, in conjunction with the industrial storm water
collection pond, sited in the in the SE quadrant of the Facility pad will prevent migration of
surface spills off the lease.
8.5.2 Surficial Geology and Shallow Aquifers (Hydrostratigraphic Units)
The surface geology of the CLBRB results from a series of preglacial and glacial erosion events
that occurred during the Quaternary period. Preglacial events resulted in a network of buried
valleys generally oriented in an east west direction; the valleys were created by east flowing
rivers that originated in the Rocky Mountains.
Preglacialand glacial channels in the CLBRB include the Beverly, Sinclair and Helina Valleys
and the Big Meadow and Moore Lake Channels. The Moore Lake Channel underlies the Crane
Lake area, including the proposed development area, and has a 2-3 km width and an average
depth of 35 m.
The surficial geology of the CLBRB area is classified into eight formations. Table 8.5.2-1
provides a summary of each formation's geochemical characteristics. The freshwater resources
in the regional development area are found in the Tertiary and Quaternary aquifers. The
proposed development site appears to lie within a predominantly weak recharge area as
illustrated in Figure 8.5.3-3 Recharge and Discharge Areas in the Cold Lake Beaver River
Basin.
Table 8.5.2-1 Shallow Aquifer Geochemical Characteristics
Formation Grande
Centre
Sand
River
Ethel Lake Bonnyville
Muriel
Lake
Empress
Hydrostrategic Unit Intertill sand
and gravel
aquifer
Sand and
Gravel
Aquifer
Unit 1
Aquifer
Aquifer
Unit 3
Aquifer
Unit 1
Aquifer
Depth local
(m)
0-20 20-30 10-50 20-60 50-110 60-130 120-160
Thickness local
approx. (m)
0-2 0-10 2-8 1-20 10 0-10 0-20
Hydraulic
Conductivity
Regional (m/s)
- 1.4 x 10 -4 1.0 x 10 -4
1.18 x 10- 4
to 5 x10 -5
1.30 x 10 -5
to
2.08 x 10 -4
8.8 x 10 -5 to
1.35 x10 -4
Hydraulic
Conductivity Local 2 x 10
(m/s)
-4 - 1.0 x 10 -4 8.5 x 10 -4 3.3 x 10 -4 3.9 x 10 -5
1.6 x10 -5
7.0 x 10 -5
(max)
Flow Direction SE - S S S, E S, E S, E
Effective Porosity 0.2 - 0.2 0.25 0.2 0.2 0.2
Average Gradients 0.004 - 0.004 0.002 0.003 0.004 0.0015
Flow Velocity
(m/yr)
126 - 63 214 156 25 -
TDS
Regional Range
238-963
87 -
10529
151-3967 387-1260 348-1240 247-3080 146-1400
TDS
Local. Range
248-530 - - 344-1080 407-1480 792-2120 678-1870
Predominant Water
Type
Ca-Mg-
HCO3
Ca-Mg-
HCO3
Ca-Mg-
HCO3
Ca-Mg-
HCO3
Ca-Mg-
HCO3
Ca-Mg-
HCO3
Ca-Mg-HCO3
Beneath or
bordering Site
Yes Yes Yes No Yes Yes No
Sage Pilot Application Page 193

The Lower Athabasca Regional Plan notes that, while the predominant water type is fresh water
that can be used as drinking water as it meets the Guidelines for Canadian Drinking Water
Quality, specific waters from the Bonnyville, Muriel Lake, and Empress 3 formations contain
relatively high levels of naturally occurring arsenic and uranium.
8.5.3 Bedrock Geology and Aquifers
The bedrock geology of the CLBRB is characterized by Cretaceous, Devonian and Cambrian
rock overlying the Precambrian basement. Figures 8.5.3-1 illustrates the stratigraphic and
hydrostatic columns and rock formations associated with the bedrock and surficial aquifers in
the area.
Table 8.5.3-1 summarizes the physical and geochemical properties of the bedrock aquifers.
Formation Upper and
Middle
Hydrostrategic
Unit
Table 8.5.3-1 Deep Aquifer Geochemical Characteristics.
Cambrian
Cambrian
Aquifer
Contact
Rapids and
Winnipegosis
Winnipegosis
Aquifer
Beaverhill
Lake
Beaverhill
Lake Aquifer
McMurray Clearwater Grand
Rapids
McMurray
Aquifer
Clearwater
Aquifer
Grand
Rapids
Aquifer
Depth local
(m)
Thickness local
1300 - 520 480 440 300
approx.
(m)
Hydraulic
40 110 200 40 – 50 30 105
Conductivity
Regional
(m/s)
5 x 10 -7 1.3 x 10 -7 3.5 x 10 -8 3 x 10 -7 4.3 x 10 -7 -
Hydraulic
Conductivity Local
(m/s)
- - -
2.5 x 10 -7 to
1.0 x 10 -4 1.0 x 10 -6
3.8 x 10 -9
to 5.8 x
10 -6
Flow Direction E, NE NW,NE E W W SE
TDS
238,000 – ->300,000 20,000 – 20,000 – 20,000 30,000 –
Regional Range 310,000
50,000 50,000
35,000
Water Type Na-Cl Na-Cl Na-Cl Na-Cl Na-Cl Na-Cl
8.5.3.1 Brackish Water Resources
Brackish water in the region is used for thermal enhanced recovery projects in the CLRB in
order to preserve freshwater for other uses. Brackish water in the region is found either within or
at depths greater than the hydrocarbon reservoirs, mainly the McMurray, Clearwater and Grand
Rapids formations of the Mannville Group. Ground water modelling completed for cumulative
effects of the Husky Tucker operation, regarding the hydraulic head change for the McMurray
aquifer after 25 yrs simultaneous pumping and injection was predicted to be less than 1m.
Brackish water in the region is currently being sourced by Imperial Oil (Cold Lake), Husky Oil
(Tucker), Shell Canada (Orion), and Canadian Natural Resources Ltd. (Wolf Lake).
8.5.3.2 Brackish Water Suitability
Brackish water used in SAGD operations for steam generation depends on the following
parameters: Total Dissolved Solids (TDS), dissolved silica (Si), alkalinity and hardness.
Suitable industry standards are TDS = 10,000 mg/l, Si = 50 mg/l, alkanity = 450 mg/l and
hardness = 0.5 mg/l. The McMurray aquifer requires treatment to meet the above levels.
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8.5.4 Fresh Water Resources
The amount of freshwater estimated to be present in the Quaternary and Tertiary aquifers in the
CLBRB is 50 billion m 3 (Alta Env. 2006). An estimated 266 million m 3 of water recharges
groundwater resources annually and results in fresh groundwater aquifers. The same amount of
groundwater discharges into lakes and rivers in the same time period.
8.5.4.1 Surface and Shallow Aquifer Use
Table 8.5.4-1 provides a summary of Surface water allocation and existing licenses, excluding
statutory domestic and non-registered agricultural users. Table 8.5.4-2 presents the
groundwater allocations by user type and by number of wells, respectively Imperial Oil holds a
license allocation to use water from Crane Lake; the license is limited by lake level parameters.
Birchwood Resources will not be using water sourced from Crane Lake.
Surface water is allocated to a number of users for various other uses such as conservation of
wetlands, recreational facilities and tree farms. Within a five km radius of the proposed
development area, Ducks Unlimited, Public Land Management, Canadian Forces Base (Cold
Lake), Cold Lake Skiing Society, Bonnyville Golf Course and Bonnyville Forest Nursery have
received licensed surface water allocations. The allocation, location, water source and license
information can be found in Table 4.17 of Consultant's Report 1.
There are numerous groundwater licenses issued for, and a variety of users of, groundwater in
the CLBRB. Industrial, Agricultural, Municipal and Domestic users have allocations for
groundwater in the shallow aquifers. The amount of water allocated under a license is not
necessarily used; the actual water usage is significantly lower than licensed. Table 8.5.4-2
provides perspective on the over allocation, including groundwater allocation for domestic and
livestock use, in 2003.
Table 8.5.4-1 Groundwater Allocation in the Cold Lake Beaver River Basin
Type
1985
(1000's m3)
%
1992
(1000's m3)
%
2003
(1000's m3)
%
Industrial 10,534 98 9,259 95 14,950 94
Agricultural/Irrigation 218 2 210 2 382 2
Ag. Registrations 0 0 0 0 454 3
Municipal 50 0 270 3 190 1
Total 10,802 100 9,739 100 15,976 100
Table 8.5.4-2 Groundwater Allocation in the Cold Lake Beaver River Basin
Including Livestock/domestic and Domestic Usage 2003
Type Number of Wells
2003
(1000's m3)
%
Industrial 20 (AGS 2005) 14950 53
Agricultural/Irrigation 1460 (ESRD 2005) 9125 33
Ag. Registrations 2971( SRD 2005) 3730 13
Municipal 4 (AGS 2005) 190 1
Total 27,995 100
Specific current and historical allocations, location and Aquifer sourced can be found in Table
4.3 of Consultant Report 1. A total of 185 groundwater wells were identified within a five km
radius of the proposed project development.
Sage Pilot Application Page 195

The actual amount of fresh groundwater used in the CLBR is unknown as domestic and
agricultural users do not generally measure consumption and the exact number of active wells
is unknown. Industrial users are required to submit annual water usage to Alberta ESRD as
outlined in their license terms. The relationship between ground water allocation and actual
usage for industrial users is presented in Consultants Report 1. Table 4.5 and indicates that
industry was using 28.9% of license allocation. Municipal fresh groundwater usage has
significantly decreased as municipal licensees have connected the local regional surface water
supply system.
8.5.5 Water Balance
See Figure 7.2.2-B Water Balance - De-Oiling, Water treatment and Steam Generation
8.5.6 Birchwood Water Usage
Birchwood is applying for licenses to source freshwater from the Muriel Formation and brackish
water from the McMurray Formation. Maximum fresh water during startup will be 4035 m 3 /day
for 5-10 days, with steady state operations averaging 5m 3 /day, or 42,135 m 3 during the first year
of operations and 1,825 m 3 /year thereafter Table 7.2.2.1. The Groundwater Assessment
concluded that total estimated freshwater usage was 8,000,000 (±1,000,000) m 3 /year.
Birchwood's proposed development is equivalent to 0.0053% of that total during the first year of
operations and 0.00023% thereafter.
The use of the Muriel formation as a source should not affect other users as the general
direction of flow from this aquifer is south and east and the majority of domestic use water wells
in the area are to the north and west of the proposed development location.
Although groundwater allocations and uses increase steadily with time, the total estimated
groundwater use in the basin is approximately 8 + 1 million m 3 /yr and equals only 30% of the
groundwater allocated in the basin, 4% of the estimated annual groundwater recharge in the
basin and 1% of the average annual flow in the Beaver River. The use of groundwater in the
CLBR Basin is a small percentage of natural flows and is a minor part of water availability.
Thus, groundwater use at these levels is considered sustainable.
8.5.7 Water Disposal
The two options for water disposal, as indicated by the Assessment, are the McMurray
formation and the Cambrian (Granite Wash) formation. Both are indicated as acceptable
aquifers. Due to the high usage of the McMurray formation as the disposal aquifer, the
Cambrian aquifer is the preferred disposal formation. All water sourced from and disposed into
this formation will be measured and reported as per the MARP program.
8.6 Soil and Terrain
The terrestrial footprint of the proposed development area is approximately 18.6 ha of which
10.0 ha is cleared and 1.3 ha is currently disturbed. The elevation trend is generally from the NE
to the SW. Figure 2.3.11 shows the topography of the proposed development and surrounding
area.
Birchwood has conducted a Soil Survey in the July of 2012. The methodology used included:
1. Classification of soils in accordance with criteria established by the Soil Classification
Working Group (1998).
2. Investigation of soils on foot with a shovel and hand auger to a depth of approximately 1
m at all inspection points.
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3. Extrapolation of soil inspections using the principles of geomorphology and surficial
geology in concert with the vegetation patterns to delineate individual soil map units.
Soil map units provided for the area 60 m adjacent to the proposed PDA area are based
on aerial photograph interpretation and extrapolation of inspection site data.
4. Analysis the soils to confirm soil classification and determine Land Capability
Classification (LCC) ratings and Reclamation Suitability Ratings (RSR). (see Consultants
Report 5 for specific parameters),
5. Classify the soils in accordance with the Land Capability Rating System.
8.6.1 Surficial Geology and Landforms
Andriashek and Fenton (1989) described the area as a having discontinuous eolian material
overlying sandy glaciofluvial deposits; and discontinuous sandy glaciofluvial deposits overlying
undivided moraine. The morphology is rolling with alternative concave and convex elements
with a length to width ratio of more than two; elements parallel to non-oriented with low to
moderate local relief (

A complete description of the each soil type can be found in Consultants Report 5 and includes:
Dominant Soil Series
Classification of Dominant Soil Series
Inclusions (

RSRs are not calculated for organic horizons because they would always be rated unsuitable
due to saturation percentage and texture. RSRs are also not calculated for C and Lower Subsoil
(LS) horizons because these horizons will not be salvaged. Therefore, any organic or C/LS
horizons are assigned an RSR of “not applicable”.
Table 8.6.4-1 Reclamation Suitability Ratings for the Well and Facility Pad
Soil
Series
Site ID
Soil
Map
Unit
Reclamation Suitability
Topsoil Subsoil
Organic
B
A Horizon
C Horizon (if no B exits)
(LFH/O)
Horizon
ABC LNBW-44 M1
-
Poor to
Good
Fair to
Good
-
LIZ LNBW-47 M2 - Poor Poor -
DRNaa LNBW-47 M2 - Poor Poor -
DRNaa LNBW-47 M3
NWBaa LNBW-33 S1 - Poor Fair -
SLN LNBW-46 O1
Not
Applicable
- - Not Applicable
The Conservation and Reclamation (see Consultants Report 7) plan addresses the required soil
salvage, storage and required management during storage during the project operation. Soils
rated in the M1 soil profile should respond well to reclamation at closure as Birchwood will
provide the proper reclamation techniques at closure. Soils with poor RSR's will require
segregation and management to ensure viability at the project closure.
8.7 Vegetation
Birchwood conducted a Vegetation and Wildlife Assessment in August, 2012 in order to obtain a
baseline description of vegetation resources in the proposed development area and across the
Mineral Surface Lease held by the company. The assessment was conducted over the
Birchwood Mineral Surface Lease Area (study area) which surrounds the PDA.
8.7.1 Methodology
The methodology used was consistent with the recommended practices specified in the
Guidelines for Submission of a PDA/C&R Plan as published by Alberta Environment, 2009. The
study consisted of Vegetation Cover Type Inventory and Mapping as well as Rare Plant and
Rare Plant Community Assessment.
The methodology used for the vegetation assessment component was, briefly, as follows:
1. Delineation of different land cover types using the Ecological Land Classification
method.
2. Conducting a field vegetation survey during which dominant eco-site phases were
classified within initial map signatures and new vegetation cover polygons identified
and mapped.
3. Mapping vegetation plots within several representative eco-site polygons with
canopy cover measurements conducted at each site.
4. Recording data pertinent to plant species, dead cover, woody debris, snags, canopy
cover and composition.
5. Assigning a new code and describing habitats that did not fit into eco-site phase
classes,
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6. Reporting of Findings.
The methodology used for the Rare Plant and Rare Plant Community Assessment was based
on the proposed "Guideline for Rare Plant Surveys" (Alberta Native Plant Council, ANPC 2012)
and conducted as follows:
1. Literature Review to determine what, if any, rare plants and rare plant communities
could occur within the Birchwood study area and determination of habitat affiliations,
2. Compilation of a list of potential rare plants and rare plant communities using the
Alberta Conservation Information Management System (2012) and Committee on
the Status of Endangered Species in Canada (COSEWIC (2012), and review of the
ACIMS occurrence data,
3. Examination of taxonomic descriptions, illustrations/photographs and herbarium
specimens occurred to ensure that field observations would allow for identification of
each species,
4. Review of aerial photography to determine likely sites of rare plants/rare plant
communities for field orientation,
5. Field inspection of the study area including a meandering and "hands and knees"
ground search, and
6. Reporting of findings.
8.7.2 Ecosite Phases at the Proposed Project Development Area
The field investigation and mapping shows that there are 22 eco-site phases within the study
area and 13 that are directly affected by the proposed development. The main ecosystem
within the development area is identified as Pasture – Graminoid, occupying 8.5 ha of the total
18.6 ha proposed for development. Table 8.7-1 provides a breakdown of the ecosite phase
type, brief description using common names, the total area (ha) occupied by the eco-site in the
within the proposed project development area. A complete description of all eco-site phases
found within the study area can be found in Consultants report 4.
Figure 8.7.2-1 illustrates the Birchwood study area. Figure 8.7.2-2 illustrates the distribution of
eco-sites phase distribution across the site with specific reference made to the project
development area. Figure 8.7.2-3 illustrates the vegetation plots of the Birchwood Study area.
Figure 8.7.2-4 illustrates the Rare Vascular Plant Survey path for the Birchwood study area.
A total of 22 eco-phase sites were identified during the assessment; seventeen are natural,
three are man-made and three are wetlands/riparian areas. Within the proposed project
development area the three man-made eco phase sites are present, specifically, anthropogenic
habitat and two types of pasture habitat. There are six naturally occurring habitats as follows:
1. Trembling Aspen- White Spruce/Low Bush Cranberry Forest
2. Trembling Aspen/Low Bush Cranberry Forest
3. Subhygric Black Spruce – Jackpine /Labrador Tree Forest
4. White Spruce/Dogwood Forest
5. White Spruce/Jackpine Forest, and
6. Jackpine Lichen Forest
There are no wetlands or riparian areas within the proposed project footprint.
The assessment identified 158 plant species including 144 native species, 10 exotic species
and four species of unknown/undetermined origin. A complete list of species can be found in
Consultants Report 4 in Table 6.
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The dominant eco-phase site in the project development area is Pastureland – Graminoid,
which forms 8.6 ha of the proposed development site. An additional 2.2 ha of land within the
proposed development area is already disturbed (AN). The largest areas of disturbance to the
natural habitat will occur in Trembling Aspen-White Spruce/Low Cranberry Forest (d2) and
Trembling Aspen/Low Cranberry Forest (d1), 2.51 and 1.69 ha respectively, both of which are
abundant in the region. Additional habitat loss will equal 8.4 ha, however, the habit loss will not
result in splitting of large batches of undisturbed land into smaller patches and thereby habitat
loss due to fragmentation is expected to be minimal. All habitats that occur within the proposed
development area occur outside of the area so seed harvesting at reclamation will be possible.
Sage Pilot Application Page 201

Table 8.7-1 Ecosite Phase Types, Descriptions and Area Coverage with the Proposed Development Area
Eco Phase Description ha
Pasture – Graminoid Open grassland used for agricultural grazing. Common species include common yarrow, red 8.6
pl-g
clover, common dandelion, smooth aster, common pepper grass, wild strawberry, cicer milk
vetch, hemp nettle, northern bedstraw and rough cinquefoil. Grasses commonly in this eco
phase include western wheat grass, short awned foxtail, slender wheat grass, Kentucky
bluegrass and smooth brome. Most of the species were non-native at the time of the survey.
Anthropogenic
An
Human origin structures and land covers (eg. Houses, infrastructure, oil and gas facilities) 1.3
Trembling Aspen- This eco site consisted of White Spruce 60% and Trembling Aspen 40%. Canopy closure
2.51
White Spruce/Low averaged 70%. Mean age stand = 64 yrs and average tree height = 21 m. The most common
Bush Cranberry shrub species included green alder, Saskatoon, white spruce, trembling aspen and prickly
Forest
wild rose. Tall shrubs averaged 1.4 m in height with 25% cover. Herbaceous species
d2
averaged 60% cover and were composed of bunchberry, twinflower, wild strawberry,
palmate-leaved coltsfoot and wild sasaparilla. Coarse woody debris was common, averaging
14.7 cm in diameter and in variable stages of decay. All snags were trembling aspen.
Trembling Aspen- Habitat was dominated by trembling aspen trees with a canopy closure averaging 60%. The 1.69
/Low Bush Cranberry mean age of the stand was 47 years and average tree height was 19 m. Most commonly
Forest
observed tall shrub species included choke cherry, pin cherry, Saskatoon and Willow species,
d1
which averaged 2.1 m in height and 33% cover. Low shrubs averaged 65 cm and 25% cover
and included raspberry, low bush cranberry, beaked hazelnut, common snowberry, and pin
cherry, however Prickly Wild Rose and common wild rose dominated the low shrub canopy.
Common herbaceous species included dewberry, bunchberry, showy aster, wild strawberry,
wild sarsaparilla, northern bedstraw, twinflower, wild vetch, and wild lily-of-the-valley. Coarse
woody debris was uncommon. Snags were common and consisted exclusively of trembling
aspen
Subhygric Black Habitat was dominated by dense canopy of Black Spruce. Shrub occurrence was sparse and 1.46
Spruce – Jackpine consisted of Labrador tea, black spruce and Prickly Wild Rose when present. Herbaceous
/Labrador Tree Forest plants were rare and only bunchberry occurred consistently. Feather moss covered the
g1
majority of the forest floor.
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Table 8.7-1 (continued) Ecosite Phase Types, Descriptions and Area Coverage with the Proposed Development Area
Pasture – Shrubby
Pl-s
White
Spruce/Dogwood
Forest
e3
White Spruce-
Jackpine/Blueberry
Forest
b4
Jackpine Lichen
Forest
a1
Open grassland with a varying amount of shrub regeneration which have in the past been
used for agricultural grazing. Common shrub regeneration included beaked willow, autumn
willow, trembling aspen, and balsam poplar with some Saskatoon, snowberry and prickly wild
rose. Herbaceous species included fowl bluegrass, Kentucky bluegrass, tufted hair grass,
short awned foxtail, graceful sedge, wild strawberry, hemp nettle, common plantain, narrow-
leaved hawkwood, northern bedstraw, starflowered Solomen's seal and common horsetail.
White spruce dominated canopy with small amounts of basalm poplar. Canopy cover
averaged 58% and the stand age was approximately 72 years. Tall shrub cover included
willow species, currant species raspberry, prickly wild rose and Saskatoon. Herbaceous
plants consisted of wild sasparilla, bishop's cap, twinflower, bunchberry and dewberry.
Feather moss was common. Coarse woody debris was common and averaged 14.8 cm in
diameter. In areas where balsam poplar occurred snags were more common and averaged
6.4 m in height and 11.8 cm in diameter, with a variable decay rating of (3-5).
White Spruce dominated canopy (90%) with (10%) Jackpine. Canopy closure was 45%,
stand age equalled 65 years and heights average 17.6 m. Tall shrubs averaged 1.7 m I
height with 2% cover and consisted of Saskatoon and White Spruce. Low shrubs averaged
13 cm in height and 65% cover. Common species were blueberry, bearberry, bog cranberry,
Saskatoon and prickly wild rose. Herbaceous species present were wild lily-of-the-valley,
cow-wheat, rough-leaved rice grass, twinflower and narrow leaved hackweed. Coarse woody
debris and snags were absent.
The tree canopy consisted of 80% Jackpine, 15% White Spruce and 5% Trembling Aspen
with 15% canopy closure and a stand age of 57yrs. Tall shrubs covered 5% of the area and
consisted of only Trembling Aspen. Low shrub cover was 65% and consisted of bog
cranberry, common bearberry, common blueberry, prickly wild rose and Saskatoon. Common
herbaceous species were lilly-of-the-valley, cow wheat, hairy wild rye, northern rice grass,
and mountain goldenrod. Ground lichens were abundant in this habitat type. Coarse woody
debris was absent and only one trembling aspen snag was recorded.
Sage Pilot Application Page 203
1.04
0.92
0.52
0.21

8.7.3 Rare Plant and Plant Communities
The study area was searched for rare vascular plants and rare plant communities. No plant
species were located and one rare plant community, a Saskatoon/common bearberry/northern
rice grass was found to the outside of the proposed development area, to the north near the
lake, and measured approximately 30 m x 15 m.
8.7.4 Old Growth Forests
There are no old growth forests within the Birchwood Study area.
8.7.5 Summary of Potential Impacts and Mitigation Measures
The Assessment reviewed the potential impacts on the vegetation within the study area. The
impacts and mitigation measures are outlined below.
8.7.5.1 Direct Vegetation Removal
Vegetation will be cleared for the proposed development. Of the nineteen identified vegetation
types within the study area, only six types will be affected by clearing. Birchwood has sited the
well pad and facility together and will utilize existing infrastructure in the area to avoid additional
clearing for pipeline right of ways. Measures will be put in place to minimize erosion and provide
runoff control during construction, to avoid disruption of vegetation and soils that are adjacent to
the proposed development area.
8.7.5.2 Impacts to Uncommon Vegetation
The White Spruce/Dogwood Forest, White Spruce-Jackpine/Blueberry Forest and Subhygric
Black Spruce – Jackpine /Labrador Tree Forest are relatively uncommon in the study area.
Birchwood will be clearing a total of 2.9 ha of these types of vegetation. Birchwood has
minimized the clearing of these types of natural vegetation to the extent possible.
8.7.5.3 Soil Acidification
Certain soils and associated vegetation are susceptible to soil acidification which is deposited
by emissions of SO2 and NO2. The "Land Systems and Soils Sensitivity to Acid Input in the
LICA Area" (AMEC, March 2007) indicates that the proposed development is within an area
where soils are sensitive to acidic inputs however the soils directly to the south have low
sensitivity. Birchwood will monitor soils surrounding the plant footprint to measure changes in
soils chemistry (pH) related to acid deposition.
8.7.5.4 Introduced Plant Species Invasion
There were no invasive species listed as prohibitive noxious weeds or noxious weeds under the
Alberta Weed Control Act. One exotic species, bladder campion, was found within the proposed
development area and could be considered a potential threat.
Sage Pilot Application Page 204

8.8 Wildlife Assessment
Birchwood conducted a Vegetation and Wildlife Assessment in August, 2012 in order to obtain a
baseline description of vegetation resources in the proposed development area and across the
Mineral Surface Lease held by the company. The assessment was conducted over the
Birchwood Mineral Surface Lease Area (study area) which surrounds the proposed
development area.
8.8.1 Methodology
The wildlife assessment has two components, species potential occurrence and identification
and identification of wildlife species of management concern. The methodologies for each
component are summarized below:
8.8.1.1 Wildlife Species Occurrence and Status
1. Development of a list of vertebrate wildlife species known or expected to occur within the
Birchwood study area using regional and provincial species distribution sources.
2. Utilization of professional judgement to classify the status and abundance of each
species,
3. Refined list to identify provincially and federally listed species at risk (SAR) using current
status assessments made by Alberta ESRD, COSEWIC and SARA as well as the Fish
and Wildlife Information Management System.
8.8.1.2 Wildlife Species of Management Concern
1. Professional judgment was used to select specifies of management concern based the
following:
on public or scientific concern,
potential to reside in the habitat of the study area, (referenced field data obtained
from vegetation assessment to determine if suitable habitat for species exists)
relevance to key issues
potential to represent the habitat of other species, and
ease of monitoring.
2. Prepare rationale for selection for each species identified, and
3. Provide detailed reports regarding the species status and habitat.
8.8.2 Wildlife Species Occurrence and Status
The Birchwood study area holds potential for a total 303 vertebrate wildlife species, 246 of
which are birds, 49 are mammals, six are amphibians and two are reptiles. The status
abundance and at risk designations are contained in Table 7 of Consultant's Report 4 provides
a list of species, listed under their common names, that have potential to live in the Birchwood
Study area and are listed as "Sensitive", "At Risk" or "May be at Risk" provincially and
"Endangered", "Threatened", or of "Special Concern" federally.
Sage Pilot Application Page 205

8.8.3 Species of Management Concern
The Vegetation and Wildlife Assessment also reviewed species of management concern. The
following species were identified based on the criteria specified above:
Moose
Black Bear
Fisher
Northern Long Eared Bat
Yellow Rail
Great Grey Owl
Canadian Toad, and
Mixed Forest Birds.
Detailed descriptions of these species relative to the specific habitat observed at the proposed
development site and the larger project area are contained with the Vegetation and Wildlife
Report. The Woodland Caribou was not selected as a species of management concern as the
habitat in the study area would not support this species.
The Great Blue Heron has been observed on the island situated in Crane Lake. The proposed
development area is outside the buffer zone stipulated in the Cold Lake Sub Regional
Integrated Resource Plan.
8.8.4 Summary of Potential Wildlife Impacts and Mitigation Measures
Although the amount of additional disturbance required for the proposed project is small, wildlife
habitat will be removed and wildlife existing outside the project area may be affected. Birchwood
will utilize the following mitigation procedures to ensure that the affect is minimized.
8.8.4.1 Habitat Loss/Alteration
Minimal additional clearing is required for the proposed development. The proposed
development area is outside of any designated Key Wildlife and Biodiversity Zones.
8.8.4.2 Habitat Fragmentation
Habitat fragmentation occurs when large continuous tracts of land are completely or partially
removed resulting in smaller, dispersed or isolated patches of habitat. The proposed project
footprint has been sited on an existing disturbed portion of land to minimize fragmentation and
subsequent effects of wildlife sustainability in the area.
8.8.4.3 Movement Obstruction
Wildlife daily and seasonal movement, as well as and range, varies in accordance with
requirements to obtain sustenance, escape predators, respond to natural and artificial habitat
alterations (eg., fire, clearing) and species propagation and associated genetic exchange. Intact
movement corridors can enhance, as well as be critical too, ensuring that the likelihood of
species survival. Due to the existing state of habitat occurrence on predominantly cleared land,
the proposed project area does not interfere with any known wildlife movement corridors and
effects on regional movement are predicted to be minimal.
Sage Pilot Application Page 206

8.8.4.4 Sensory Disturbance
Wildlife species are affected by human activity that causes sensory disturbance (such as noise,
light, smell, etc); the affects can be positive, negative or neutral. The degree to which wildlife is
affected depends upon numerous factors including habitat quality or the site occupied, distance
to an quality of other appropriate and available sites, relative risk of predation at other sites,
relative competitor density at other sites, and amount of investment the wildlife has mad to
procure the site. In order to minimize sensory disturbance, Birchwood will implement the
following measures:
Conduct species specific and species at risk assessments to determine if species are
present and any related management and monitoring should be conducted during plant
construction activities,
Conduct a pre-disturbance assessment modify construction activity so as to reduce
sensory disturbance on species in the adjacent areas during plant construction activities,
Develop and implement management plans for species that may be attracted to the
anthropogenic activities at the site (eg. Bears, small mammals and birds),
Conduct construction activity in the winter months to avoid disruption of nesting activity
of birds adjacent to the facility,
Use on demand lighting and downward directional shading will be used to minimize light
on nocturnal species,
Install a vapour recovery system will be used to capture emissions and minimize odors
associated with the proposed operations,
Mitigate noise levels using vibration absorption mountings and encasement within
buildings, and
Minimize Air emissions in order to meet the ambient air quality requirements set by
Alberta ESRD, conduct on-going air emission monitoring and use low NOx emission
equipment, and conduct sir and soil monitoring to determine if soils are affected by acid
deposition and initiate a soil management program to reverse effects if required.
Sage Pilot Application Page 207

8.8.4.5 Direct Mortality
Direct mortality is caused by human activity that immediately results in the death of an animal,
hunting, trapping and vehicle collisions can cause instant death. It may also be caused by
industrial and recreational activities that release chemicals into the environment through air or
water emissions that result in inhalation or contaminated air or water, or consumption of
impacted vegetation, fish other wildlife or invertebrates. Birchwood will mitigate direct mortality
using the following measures:
Avoidance of clearing vegetation during migratory bird nesting/fledging season,
Fencing of the proposed development site to prevent migration onto the site and
inadvertent contact with equipment or machinery, and prevent the use of the site as a
base for hunters/workers,
Construct the proposed facility with an impermeable base and berms to prevent spills
from migrating off the surface and lease development area,
Construct an Industrial surface runoff collection pond on site to capture surface water
conduct testing of the surface water and control release. Water that does not meet
Alberta ESRD standards will be diverted to process use,
Implement a management plan for the Industrial run-off pond such that birds to not
attempt to use,
Enforce speed limits of 40 km an hour on access roads and 10 km per hour on lease,
Removal of garbage from construction/facility site promptly to avoid attracting bears and
small mammals to the site and potential habituation,
Employ bear proof disposal bins, and
Prohibit workers from feeding wildlife to prevent habituation; this will include proving
housekeeping facilities and practices that prohibit feeding of birds.
Sage Pilot Application Page 208

8.9 Summary of Environmental Receptors and impact ratings
Birchwood has conducted assessments related to Historical Impacts, Hydrology and Hydrogeology, Air, Noise, Vegetation, Wildlife
and prepared this table to summarize the receptors identified, the geographic extent, the magnitude, duration and frequency of the
impact, the likelihood of permanence, and the level of confidence.
TABLE 8.9-1 Environmental Receptors and Impact Ratings
RECEPTOR Direction
of Impact
Geographic
Extent
Magnitude
of Impact
Duration
of Impact
Frequency
of Impact
Sage Pilot Application Page 209
Reversibility
of Impact
Confidence
Level
Final
Impact
Rating
Historical Resources
None identified Neutral - - - - - - Low
Traditional Land
Use
Traditional Plant
Harvesting activities
in traditional lands
Hunting Activities for
traditionally hunted
species in the area
Fishing in traditional
lands
Trapping on trap lines
in traditional lands
Negative Local Low Long
Term
Negative Local Low Long
Term
Seasonal Reversible Good Low
Continuous Reversible Good Low
Neutral - - - - - - -
Neutral to
Negative
Air Quality
SO2 Negative Regional Low Long
NO2 Negative Regional Low
Term
Long
Term
CO Negative Regional Low Long
Term
PM2 Negative Regional Low Long
Term
- - - - - - -
Continuous Reversible Good Low
Continuous Reversible Good Low
Continuous Reversible Good Low
Continuous Reversible Good Low

RECEPTOR Direction
of Impact
Noise
Noise Receptor
(Residence 1)
Noise Receptor
(Residence 2)
1.5 Km from facility
boundary
Geographic
Extent
Magnitude
of Impact
Duration
of Impact
Frequency
of Impact
Sage Pilot Application Page 210
Reversibility
of Impact
Confidence
Level
Final
Impact
Rating
Negative Local Low Long
Term
Continuous Reversible Good Low
Negative Local Low Long
Term
Continuous Reversible Good Low
Neutral Local Negligible Long term Continuous Reversible Good Low
Soils Terrain and Surficial Geology
Disturbance Negative Local Low Mid-term Infrequent Reversible Good Low
Admixing Negative Local Low Long-term Infrequent Irreversible Good Low
Compaction Negative Local Low Long-term Infrequent Reversible Good Low
Moisture Negative Local Low Long-term Infrequent Reversible Good Low
Soil Erosion Negative Local Low Long-term Infrequent Reversible Good Low
Contamination Negative Local Low Long-term Infrequent Reversible Good Low
Forest Capability Negative Local Low Long-term Infrequent Reversible Good Low
Reclamation Negative Local Low Long-term Infrequent Reversible Good Moderate
Suitability
Soil Acidification Negative Local Low Long-term Infrequent Reversible Moderate Low
Unique Soils, Terrain Negative Local Low Long-term Infrequent Reversible Good Low
Geology and Hydrogeology
Surface Facilities Neutral - - - - - - -
Water disposal Neutral - - - - - - -
SAGD Operations Neutral to Local Low Long term Continuous Reversible Good Low
Groundwater
withdrawal and
changes in run-off
Negative
Neutral to
negative
Local Low Long-term Continuous Reversible Good Low

RECEPTOR Direction
of Impact
Geographic
Extent
Magnitude
of Impact
Duration
of Impact
Frequency
of Impact
Sage Pilot Application Page 211
Reversibility
of Impact
Confidence
Level
Surface Water Quality
Construction Activities Neutral - - - - - - -
Runoff N/A - - - - - - -
Final
Impact
Rating
Borrow Pits N/A
Subsurface Neutral to Local Low Long term Continuous Reversible Good Low
Operations negative
Wastewater Release Neutral - - - - - -
Groundwater Neutral to Local Low Long term Continuous Reversible Good Low
Withdrawal and
changes in run-off
Negative
Acid Deposition Negative Local Moderate Long
Term
Continuous Reversible Good Low
Fish and Aquatic Resources
None identified
Vegetation, Wetlands and Biodiversity
Habitat Diversity Neutral to Local Low Mid to Continuous Reversible Good Low
Negative
Long and
Term Seasonal
Species Diversity Neutral to Local Low Mid to Continuous Reversible Moderate Low
Negative
Long and
Term Seasonal
Landscape Diversity Neutral to Local Low Mid to Continuous Reversible Good Low
Negative
Long and
Term Seasonal
Traditional Use Plants Neutral to Local Low Mid to Continuous Reversible Good Low
Negative
Long and
Term Seasonal

RECEPTOR Direction
of Impact
Geographic
Extent
Magnitude
of Impact
Duration of
Impact
Wildlife (Species of Management Concern)
Moose Negative Local Low Mid to Long
Term
Black Bear Negative Local Low Mid to Long
Term
Frequency
of Impact
Sage Pilot Application Page 212
Reversibility
of Impact
Confidence
Level
Final
Impact
Rating
Continuous Reversible Good Low
Continuous Reversible Good Low
Fisher Neutral - - - - - - -
Northern Eared Neutral to Local Low Mid to Long Continuous Reversible Moderate Low
Bat Negative
Term
Yellow Rail Neutral - - - - - - -
Great Grey Owl Neutral to Local Low Mid to Long Continuous Reversible Moderate Low
Negative
Term
Canadian Toad Neutral to Local Low Mid to Long Continuous Reversible Moderate Low
Negative
Term
Mixedwood Forest Neutral to Local Low Mid to Long Seasonal Reversible Moderate Low
Birds Negative
Term and
Continuous
Other Wildlife Species of Concern
Ungulates Negative Local Low Mid to Long
Term
Continuous Reversible Good Low
Terrestial Fur Negative Local Low Mid to Long Continuous Reversible Good Low
bearers
Term
Semi aquatic
mammals
Neutral - - - - - - -
Small mammals Negative Local Low Mid to Long
Term
Continuous Reversible Moderate Low
Raptors Negative Local Low Mid to Long
Term
Continuous Reversible Good Low
Waterfowl and
Waterbirds
Neutral - - - - - - -

RECEPTOR Direction
of Impact
Geographic
Extent
Magnitude
of Impact
Duration of
Impact
Frequency
of Impact
Sage Pilot Application Page 213
Reversibility
of Impact
Confidence
Level
Other Wildlife Species of Concern (continued)
Amphibians Neutral - - - - - - -
Land and Resource Use
Protected Areas Neutral - - - - - - -
Land Use
Dispositions
Neutral - - - - - - -
Increase in Negative Local Low Mid to Long Continuous Reversible Good Low
disturbance
Term
Access Neutral - - - - - - -
Forestry Neutral - - - - - - -
Trapping Neutral to Local Low Mid to Long Continuous Reversible Good Low
Negative
Term
Hunting Neutral to Local Low Mid to Long Continuous Reversible Good Low
Negative
Term
Fishing N/A - - - - - - -
Non- Consumptive
Recreation
Neutral - - - - - - -
Aggregates and
Minerals
N/A - - - - - - -
Visual/esthetics Neutral to Local Low Mid to Long Continuous Reversible Good Low
Human Health
Negative
Term
Air Contaminants Negative Regional Low Long Term Continuous Partially
Reversible
Final
Impact
Rating
Moderate Low

8.10 Summary of Environmental Commitments
Birchwood is committed to ensuring that the environmental impacts of the proposed
development are eliminated or minimized and monitored. To that end, the company will
undertake the following to achieve compliance with regulatory requirements, industry standards
and on-going continuous improvement:
8.10.1 Air Monitoring
Install passive exposure stations for measurement of hydrogen sulphide (H2S) and sulphur
dioxide concentrations. The steam generator exhaust stacks will be equipped with sampling
facilities and will be installed, operated and maintained in accordance with the Alberta Stack
Sampling Code and the Air Monitoring Directive.
8.10.2 Noise
Baseline Noise Assessment will be undertaken in 2013 to establish ambient noise levels in the
area. Noise surveys will be undertaken upon commencement of plant operations to validate the
Noise Modeling Assessment conclusions presented herein.
8.10.3 Water
Shallow aquifer testing will be completed in 2013 in order to verify the static head, flow rates
and chemical parameters of the Muriel aquifer in order to confirm that the potential draw does
not affect residence use of this freshwater resource. Baseline sampling of landowners wells in
the area will also proceed to gather local area concentrations for various parameters.
Develop a Groundwater Monitoring Program and Management Plan for monitoring the shallow
fresh aquifers in the regional development area, and provide to Alberta ESRD for approval prior
to commencement of facility operations. Submit a Measurement Accounting and Reporting Plan
to the ERCB for approval prior to the commencement of licensing.
8.10.4 Vegetation
Conduct a Rare Plant Survey to determine if there are any early flowering rare plants in the
project development area, or within a 60 m boundary of the proposed site, in June of 2013.
Develop a management plan if the presence is confirmed. Conduct pre-disturbance assessment
prior to construction.
8.10.5 Wildlife
Conduct species specific surveys to determine the presence or absence of certain species in
the project development area, in accordance with species occurrence data. Develop a
management plan if the presence is confirmed.
8.10.6 Emergency/Spill Response
Develop a Site Specific Emergency Response Plan, based on the existing Corporate Response
Plan, to include high pressure vapour (HPV) hazards and management, locations of spill
response equipment and use/training requirements and monitoring of tanks and lines for
spillage. A site specific Preventative Maintenance plan will also be developed for facility
equipment and monitoring equipment.
8.10.7 Participation in Area Research
Birchwood will participate in LICA initiatives, and ALMS Lake Watch program.
Sage Pilot Application Page 214

Figure 8.3.2-1 Maximum Predicted NO2 Contours for the 1-hour Averaging Period
including Ambient Background
Source: RWDI Air Quality Assessment report dated December 5, 2012
Sage Pilot Application Page 215

Figure 8.3.2-2 Maximum Predicted SO2 Contours for the 1-hour Averaging Period
including Ambient Background
Source: RWDI Air Quality Assessment report dated December 5, 2012
Sage Pilot Application Page 216

Figure 8.4-1 Noise Study Area and Receptor Locations
Sage Pilot Application Page 217

Figure 8.4-2 Predicted Nighttime Noise Levels
Sage Pilot Application Page 218

Figure 8.4-3 Relationships Between Everyday Sounds
Sage Pilot Application Page 219

Figure 8.5.3-1 Stratigraphic and hydrostratigraphic columns in the Cold Lake-
Beaver River Basin
CENOZOIC
QUATERNARY
TERTIARY
McMURRAY
(Consultant’s Report 1 Modified from Husky-Tucker Thermal Project, 2003)
McMURRAY
McMURRAY /
Sage Pilot Application Page 220

Figure 8.5.3-2 Location of the Project within the Beaver River Basin in Alberta
(Source Lemay et al. 2005, EUB/AGS report)
Sage Pilot Application Page 221

Figure 8.5.3-3 Recharge and Discharge Areas in the Cold Lake-Beaver River Basin
Birchwood
SAGD Pilot
Project
area
(Crane
(Source Map: Lemay and al. 2005, approximate location of Birchwood SAGD Pilot project added)
Sage Pilot Application Page 222

Figure 8.6.2-1 Soils Types and Locations
Sage Pilot Application Page 223

Figure 8.7.2-1 Birchwood Study Area
Sage Pilot Application Page 224

Figure 8.7.2-2 Vegetation Cover Types
Sage Pilot Application Page 225

Figure 8.7.2-3 Vegetation Plots
Sage Pilot Application Page 226

Figure 8.7.2-4 Rare Vascular Plant Survey Path
Sage Pilot Application Page 227

9 Public and First Nations Consultation
9.1 Overview
Birchwood believes that public consultation among all stakeholders is an essential, integral and
ongoing part of the Sage pilot project development. Birchwood has made an effort to consult in
a transparent manner built upon establishing mutual trust and respectful relationships with
stakeholders.
Since the summer of 2011, Birchwood has had, and will continue to have, ongoing consultation
with stakeholders who may have a direct and/or potential interest in the Sage project including,
government authorities, First Nations, Metis, landowners, occupants and other land users and
stakeholders.
Birchwood’s consultation has involved individuals, small groups, as well as a public information
session regarding the Sage pilot project. Throughout the consultation process Birchwood has,
and will continue to, invite all stakeholders to request information or ask project related
questions, preferably in written format in order to allow us to respond in writing. As part of this
information exchange Birchwood has summarized and made available a list of most frequently
asked questions on the Birchwood corporate website.
Where possible and permissible, stakeholder’s concerns regarding avoidance and/or mitigation
have been incorporated into the Sage pilot project design or development plans. These efforts
by Birchwood to respond to and to mitigate concerns brought forth will be ongoing throughout
the duration of the Sage project.
9.1.1 Goal of Consultation
The primary goal of the Birchwood public consultation process is to ensure that stakeholders
have access to information about the proposed development, and have the opportunity to ask
questions and provide comments for improving the project and mitigating potential impacts on
other stakeholders. Birchwood is committed to open communication with stakeholders during
the planning and regulatory review process, construction, operation and reclamation.
Birchwood believes that successful consultation requires active participation and commitment
from all parties to identify issues and work towards resolutions. Birchwood is committed to
continue the consultation process with the affected parties as the project develops.
9.1.2 Consultation Summary
Birchwood’s stakeholder and First Nation consultation program began in the summer of 2011
and included:
Holding personal consultation meetings;
Holding a public information session regarding project specifics;
Inviting stakeholders to communicate on any aspect of the Sage pilot project via
telephone, verbal queries at meetings, letter, facsimile, or email;
Disseminating information on Birchwood’s website;
Providing responses to frequently asked questions (“FAQ’s”) via the Birchwood website;
Providing a toll free number.
Sage Pilot Application Page 228

9.2 Stakeholder Identification
In order to commence the consultation process, Birchwood identified stakeholders by reviewing
regional development plans, reports prepared by government and other agencies, and land
titles. This involved meetings with several Government departments or regulators such as the
Alberta Government, the Municipality of Bonnyville, ASRD (Alberta Sustainable Resources and
Development), Alberta Environment, the ERCB (Energy Resources Conservation Board) and
LICA (Lakeland Industry Community Association) as well as reviewing the Public Land Standing
Report for the area.
To date, the stakeholders and organizations that Birchwood has either engaged through direct
consultation or identified as having potential interest in the project are:
First Nations & Metis:
Cold Lake First Nation.
Frog Lake First Nation.
Kehewin Cree Nation.
Beaver Lake Cree Nation.
Heart Lake First Nation.
Whitefish – Goodfish First Nation.
Zone 2 Metis.
Land Users:
Registered Trapper.
Lease Holders and Occupants.
Residents and Landowners:
Residents and landowners within 5km, specifically over twenty (24) sections of land:
Township 63 Range 3 W4M: Sections 30 and 31.
Township 63 Range 4 W4M: Sections 25, 26, 27, 28, 31, 32, 33, 34, 35 and 36.
Township 64 Range 4 W4M: Sections 1, 2, 3, 4, 5, 6, 9, 10, 11 and 12.
Township 64 Range 3 W4M: Sections 6 and 7.
Government:
Municipal District of Bonnyville.
Alberta Environment and Water.
Alberta Sustainable Resource Development.
Energy Resources Conservation Board
Department of Fisheries and Oceans.
Department of Transportation.
Canadian Environmental Assessment Agency.
MLA for Bonnyville/Cold Lake
Mayor of Bonnyville.
Mayor of Cold Lake.
County of Vermillion.
County of Two Hills.
County of St. Paul.
Mayor of Elk Point.
Sage Pilot Application Page 229

Industry:
Enbridge Pipelines (Athabasca) Ltd.
Husky Oil Operations Ltd.
Imperial Oil.
Canadian Natural Resources Ltd.
OSUM Oil Sands.
Shell Canada Ltd.
Non-Governmental Organizations:
Alberta Lake Management Society.
Crane Lake Advisory and Stewardship Society (CLASS).
Lakeland Industry Community Association (LICA).
Beaver River Watershed Alliance.
Ducks Unlimited.
Western Canada Spill Services (WCSS).
9.3 Open House Summary
Birchwood held an open house on June 7, 2012, in the Riverside community hall outside of Cold
Lake. Notification and invitations to the Birchwood open house were sent out by mail to all of the
land title owners in the 24 sections listed above, various government authorities, First Nation
Councils, industrial companies operating near the potential development and NGO.s. All of
these mailed notifications included the following three items:
1) Written invitation giving the date, time and location of the open house,
2) Birchwood pilot project comment form (to be mailed in, emailed, or brought to the open
house), and;
3) A Birchwood Sage SAGD Thermal Pilot Project May 2012 Public Disclosure Document.
Print advertisements for the Birchwood Open House were placed in the following papers with
two runs done in each paper.
Bonnyville Nouvelle;
The Cold Lake Sun;
Cold Lake Courier.
At the open house Birchwood and Propak Systems Ltd., (Birchwood’s engineering, fabrication
and construction partner), had several staff members, including the President, Managing
director and senior managers). The hall was set up in a circular fashion such that the attendees
could work their way around the room and ask questions at each set-up. Materials on display
included environmental information (including air emissions, water, noise, light and chemical
substances and wastes), a schematic showing domestic use water well protection, aerial
photographs, maps of the area, LICA guiding principles for oil-sands development, geological
information, bitumen core and oil samples, the Sage pilot plant design and reference materials.
Copies of the Birchwood Sage pilot project comment form and the Birchwood Sage SAGD
Thermal Pilot Project Public Disclosure Document were provided. It is estimated that
approximately 250 attendees participated in the open house. Responses ranged from support of
the Sage project to outright rejection of the project. Most of the support for the project came
Sage Pilot Application Page 230

from the economic and employment benefits. Concerns/objections were based on water
(domestic ground water and Crane Lake water pollution), air, noise, light, operational and “not in
my backyard” concerns (which is some cases is partly a fear of the unknown and in some based
on inaccurate information put forth by certain individuals opposed to the project).
In some of the consultative exchanges Birchwood encountered challenges in building or
creating a trustful and/or respectful relationship. Birchwood is cognitive after this open house of
this “lack of trust” factor but continues to believe that after all of the supporting studies, reports
and information of the pilot project application is reviewed this trust concern the and fear of the
unknown should be alleviated.
There were a small number of vocal attendees who felt Birchwood had not properly notified
them of their activities and the open house meeting. Birchwood has advised landowners that the
address used for contact was obtained from the land titles office and, if incorrect, the land title
should be updated to reflect the current address.
Birchwood received about 51 comment forms and/or emails from individual stakeholders. The
vast majority of these came from Crane Lake full and part time residents. These concerns were
responded to by Birchwood and a summary is provided in Section 9.4.
9.4 Stakeholder Comments and Responses
Throughout the consultation process Birchwood has asked for written stakeholders comments,
concerns or questions on the Sage pilot project. Stakeholder questions and Birchwood
responses are provided below in Table 9.4.1
Sage Pilot Application Page 231

Table 9.4.1 Summary of Stakeholder Questions and Responses by Birchwood
Issue
AIR
Question Response
Have you assessed the potential Yes the assessment is included in the Sulfur
Hydrogen Sulphide for hydrogen sulphide gas Production and Recovery, and the Vapour
Gas Generation generation as a result of the Recovery and Flare Systems detailed in Section
bitumen extraction process?
What contingency plan has been
7.6.
Hydrogen Sulphide
Gas Generation
made in the plant design for the
potential of hydrogen sulphide
gas generation?
See above.
Hydrogen Sulphide
Gas Generation
What modeling has been done
with respect to the potential for
the release of hydrogen sulphide
gas from tanks and process
equipment?
Birchwood has conducted an Air Modeling
Assessment to determine baseline emissions. Air
modeling indicates that the Birchwood
development is under Alberta Ambient Air Quality
Guidelines (AAAWG) and the limits prescribed by
the Lower Athabasca Regional Plan.
Smells / Vent
Gases
What vapor recovery methods will
be employed with the warm
bitumen tanks to control odor?
What type of tank will the
A complete closed loop Vapor Recovery System
is included in the design and no odor issues are
anticipated.
Smells / Vent
Gases
condensate for the diluent be
stored in and what methods are
planned to be employed to control
odor from these tanks?
There is no diluent storage. Diluent will be
supplied by an existing underground pipeline.
What about odor issues from the A complete closed loop Vapor Recovery System
Odour
plant and their effect on the is included in the design and no odor issues are
NOISE
residences of Crane Lake? anticipated.
A noise impact assessment has been completed.
The impact study show that sound levels will from
Noise from Plant
Facility/ Noise
Modeling
Will the noise from the facilities
impact residents near Crane
Lake?
What noise modeling has been
done on the proposed facility?
the proposed development will be 35.1 dBA
(nighttime) at 1.1 km distance from the facility and
as such noise levels should not be audible by
residents in the East Campground area or west
residential area of Crane Lake.
Birchwood will conduct an ambient noise
monitoring project in the summer of 2013 as well
as noise monitoring during plant operations.
The drum boilers are not considered “noisy”. The
Drum Boilers
HYDROGEOLOGY
Will the drum boilers be audible to
the Crane Lake residents?
equipment included in the Noise Assessment
includes "noisy" equipment associated with the
drum boilers and will be available in Section 8.4 of
the Application.
Birchwood is proposing to use brackish water for
Source Water
Will the project use any fresh
water?
steam generation. Fresh water usage is proposed
for initial start-up and utility purposes (toilets,
showers, chemical mixing, firefighting)
Source Water
How close will your wells be
located to Crane Lake? How
close will the end of the well bore
be to the actual lake?
The wellheads will be 700m from the lakeshore.
The toes of the wells will be 420m below the
surface and not under the lake.
Sage Pilot Application Page 232

Surface Run-off
Water Withdrawal
Rate
Steady State Water
Withdrawal Rate
Annual Water
Withdrawal Volume
Water Demand
Rates
Experience
Aquifer Interaction
Aquifer Research
Aquifer
Where will surface run-off be
disposed of from the facility?
What will the initial water
withdrawal rates from the
freshwater aquifer which also
feeds Crane Lake?
What is the steady state water
withdrawal rate from the
freshwater aquifer?
What is the estimated annual
water withdrawal necessary to
sustain the facility?
What reliability assumptions are
built into these rates?
Has any reliability modeling been
done on the facility?
Will Birchwood shut down the
facility if it cannot meet the water
demand rates from the freshwater
aquifer?
What experience does Birchwood
have operating water reclamation
facilities as described in your
literature?
Will Birchwood be drilling through
the Beverly Aquifer to develop
producing and injection wells?
What research have you done
regarding aquifers?
Introduced dissolved gases in the
groundwater such as methane,
ethane, propane, propene, butane
and butene, how do you deal with
these?
Surface runoff will be collected on site. The
industrial run-off pond will be subject to testing. If
the water meets release requirements it will be
released in a designated approved area. If it does
not meet release requirements it will be treated or
used in the production process.
A Hydrogeology and Hydrology study has been
completed and indicates that proposed ground
water usage is sustainable and will not affect
Crane Lake.
Steady state withdrawal from the freshwater
aquifers will be for utility and safety purposes only.
The withdrawal rate is estimated to be less than 5
m 3 /day.
It is estimated that approximately 150,000 m 3 of
brackish water will be withdrawn annually.
(Assuming reservoir loss of 5% and blow down of
7.5%). The fresh water withdrawal rate is
estimated to be less than 2,000 m 3 /year during
steady state operations
Reliability modeling will be conducted in the Front
End Engineering and Design (FEED) phase of the
project.
Freshwater demand will be for utility water, safety
and firefighting purposes only. The withdrawal
rate is estimated to be 5 m 3 /day. Water usage will
met all requirements of the water diversion license
including withdrawal limits.
Management and consultants have extensive
previous experience in drilling wells, constructing
and operating these types of projects world-wide.
The Hydrogeology and Hydrology Assessment
does not indicate the presence of the Beverly
Aquifer under the Birchwood property.
A Hydrogeology and Hydrology Assessment has
been prepared and included as part of the
application.
To ensure groundwater is protected Birchwood
will undertake the following:
Set surface Casing to a depth of 160 -180
m below surface to protect fresh water
aquifers.
Use of premium thermal casing joints,
high strength casing and thermal cement.
Use of gas blanketing to protect from
thermal transfer and monitor casing
integrity.
Install Micro-deformation monitoring as an
early warning system for fluid migration.
Birchwood has developed a casing monitoring
plan. In the unlikely event that well integrity is
compromised, the well would be shut in pursuant
to ERCB requirements.
Sage Pilot Application Page 233

Aquifer
Aquifer
Aquifer
Aquifer
Mud Systems
Lake Use
Lake Temperature
Nearby Lakes
Arsenic Levels
Groundwater
Monitoring
How do you ensure that there is
no contamination between the
brackish water aquifers and the
aquifer feeding the lake?
What will Birchwood do if there is
a drop in the static fluid level of
our water well?
How will Birchwood protect
against thermal heating of the
groundwater aquifers
What chemical parameters will
Birchwood be including in the
ground water monitoring
program? Will this include
Isotopic fingerprinting?
Is the mud system used to drill
through the Aquifers non-toxic?
Will you be drilling into a portion
of Crane Lake?
How will Birchwood protect the
Lake from heating up and
becoming contaminated with
algae blooms?
Will this affect the quantity and
quality of the water in Crane
Lake?
How are you planning on
containing the high levels of
arsenic that will result as a byproduct
from SAGD operations?
What is the plan for this and how
will my domestic water wells be
monitored and protected?
Brackish source water wells have multiple layers
of casing and associated cement providing
barriers between the fresh water aquifers and
brackish water sources. Additionally the space
between the casing and the tubing is filled with
gas to monitor containment.
Birchwood has conducted a Hydrogeology and
Hydrology Assessment of the areas groundwater
and it indicates that the aquifer from which fresh
water will be drawn can support a significant
volume of withdrawal without affecting static water
levels in the area. Birchwood will be conducting a
Baseline water assessment in 2013 to determine
existing aquifer parameters.
Domestic water wells will be protected by setting
surface casing for the production and injection
wells to a depth of 160 m, approximately 80 m
below base of the domestic use wells in the area.
Thermal cement will be used on the wells along
with high grade tubulars and gas blanketing to
minimize heat transfer.
Chemical parameters are prescribed by Alberta
Environment and include metals, salinity
petroleum hydrocarbons and dissolved organic
compounds.
Birchwood will be using an inert non-toxic mud
system to drill the surface hole (from surface to
base of groundwater protection (0 – 160 m).
Sage Pilot Application Page 234
No.
Wells are located 400m below the surface and do
not cross under the lake. There is minimal, if any
risk of heat transfer to the lake.
Gas blanketing will be used to minimize
undesirable heat transfer away from the well bore.
The Hydrological and Hydrogeological study and
the Alberta Lake Management Society annual
reports on Crane Lake have provided Birchwood
with initial information to monitor the water quality
at Crane Lake.
Birchwood will use monitoring wells to ensure an
area of protection and monitoring exists between
the facility and all water bodies. The Groundwater
protection program is designed to minimize the
risk for potential effects on the groundwater by
early detection and prevention.
Birchwood will develop a Groundwater Monitoring
and Management Program and submit this
program to Alberta ESRD subsequent to initial
approval of the scheme. Birchwood will include
arsenic monitoring as part of the proposal as
consultation with Alberta ESRD, ALMS and
landholders have indicated the importance of
addressing the issues of high levels of existing
arsenic in the area.
Birchwood is required to develop a Groundwater
Monitoring and Management Program that will be
submitted to Alberta ESRD for approval and must

Soils and Wildlife
Ground Level
Disruption
Impact on wildlife
Ecosystems
Operational
Visual Impact
Visual Impact
Plant Expansion
Infrastructure
Organizational
Overview
Oil spills
Have you assessed the
probability of a ground level
disruption as a result of using high
pressure steam in the wells?
What is the result of the
assessment?
What will the repercussions be on
wildlife?
What impact will this plant have
on Crane lake and the entire
ecosystem?
What light will be emitted from the
plant?
Will the plume from the steam be
visible?
What will be the expansion plan
for the facility?
What infrastructure will be put in
place other than the plant?
Describe your organization
including the number of
employees and an overview of
your organizational structure.
What if an oil spill goes into Crane
Lake?
be initiated prior to operations commencing.
Domestic water wells will be protected by setting
surface casing for the production and injection
wells to a depth of 160 m, approximately 80 m
below base of the majority of the domestic use
wells in the area. Thermal cement will be used on
the wells along with high grade tubulars. Micro
deformation equipment will be used to monitor
well integrity way from the well bore allowing
Birchwood to shut in wells prior to loss of integrity
and thereby preventing potential contamination.
Birchwood will monitor the ground levels for
surface heave using Satellite (InSAR) technology
and GPS or Tiltmeters. The project is a low
pressure (SAGD) steam injection and ground level
disturbance is not considered a risk. A microdeformation
monitoring program is planned to
provide reservoir and well integrity monitoring.
A vegetation and wildlife assessment has been
completed, as the project has a small foot print
and utilizes primarily previously disturbed land
(61%) the impact on wildlife is assessed to be
minimal as very little habitat displacement occurs.
Birchwood has designed an operation to minimize
the impact on the entire ecosystem including all of
the lakes in the area.
Light emissions will be minimized where possible
by using on demand and focused lighting.
Visibility will depend on location, ambient light,
temperature and wind. No visibility is expected in
the spring, summer and fall months.
The proposed plant and well pad footprint will
allow for the development of 36 well pairs. If the
pilot is successful no additional lands would be
required for approximately 15 years.
The pilot proposes that 10 well pairs be put on
location as well as an industrial storm water
drainage pond and soil salvage piles.
Birchwood is a private company with a small staff
in Calgary, field operators and several
contractors.
The topography of the land is flowing south away
from the lake, and the large distance of 700+
meters away results in minimal (if any) risk to a
spill contaminating Crane lake. A Site Specific
Emergency Response Plan for the facility will be
developed and will include a site specific spill
response plan. Birchwood is a member of the
Western Canadian Spill Services, Area VR-1 oil
spill coop. Birchwood is required by the ERCB to
follow the requirements of Directive 71.
Sage Pilot Application Page 235

Drilling
What experience does Birchwood
have in the design and operation
of SAGD wells, particularly at the
shallow depths proposed for
these wells?
Drilling Coupling failures in casing
Storage
Storage
Waste
Management
Production facilities
Waste
Management
Troubleshooting
Emergency
Response
Fire Protection
Fire Protection
Insurance
What temperature will the bitumen
be stored in the facility?
What are the approximate
volumes of onsite bitumen and
condensate storage?
What are the waste by-products
from this water reclamation and
where are they disposed of?
Production with pumps and grid
load?
What other wastes will be
generated and where will they be
disposed of?
What technical experience has
Birchwood secured to provide
ongoing troubleshooting and
expertise in the operation of the
plant?
What emergency response
capability does Birchwood have?
Is there an emergency response
plan that you have used in the
past?
What is planned for firefighting
capabilities on the site?
What is the source of firewater for
the facility?
What insurance will be in place to
indemnify claimants in the event
that there is a significant incident
at the facility and Birchwood finds
itself in receivership?
Birchwood through management and contractors
has extensive experience and expertise, including
the drilling, operations and construction of SAGD
operations.
Birchwood would not consider these wells at 400+
meters deep to be “shallow”.
The use of high strength thermal grade couplings
combined with a high grade cementing program
should address this concern.
Approximately 45 degrees C.
Sales and Off Spec Bitumen – 1350m3. There is
No Condensate/diluent storage.
Spent water and waste from the evaporator will be
disposed of into a deep (Granite Wash) disposal
well, and waste will be disposed at an approved
third party facility.
Birchwood is proposing gas lift and will likely not
be utilizing bottom hole pumps. The total
operating grid load is currently estimated to be 5
Sage Pilot Application Page 236
MW.
Wastes will be disposed of off-site at approved
third party facilities (Appendix 7.3). For further
information on required waste management
practices that Birchwood must be in compliance
with see ERCB Directive 58.
Birchwood management, contractors and partners
have significant experience and will be engaging
technically qualified field personnel with extensive
experience and expertise as required.
Birchwood is a member of the Western Canadian
Spill Society Coop. The coop provides emergency
spill response for spills. Birchwood has an existing
Corporate Emergency Response Plan. A Site
Specific Emergency Response Plan will be
developed. Requirements regarding emergency
response can be found in ERCB Directive 71.
Birchwood will develop a Fire Response Program
in accordance with Alberta ESRD/CAPP "Fire
Smart Guidebook for the Oil and Gas Industry" as
well as the CAPP "Best Management Practices for
Wildfire Prevention" (2007). This program will be
submitted to Alberta ESRD for approval prior to
commencement of the plant operations.
Birchwood will work with the MD of Bonnyville and
cooperate with other neighboring industrial users
to coordinate fire protection resources.
In the event of fire utility water will be utilized.
Full insurance will be in place.

Land Reclamation
Security and
Access
CONSULTATION
Open House
Prior Wells drilled.
LOCATION
How can I find public documents
on Birchwood’s land reclamation
track record?
How will you prevent
unauthorized access to the area
as a result of the increased
access created by such an
operation?
Why I was not notified of the open
house?
Why I was not notified of the first
three wells drilled by Birchwood?
Plant Site location. Why was this location picked?
TRADITIONAL LAND USE
Land Use
SOCIO ECONOMIC
Property Values
Traffic
Will a Traditional Land Use (TLU)
study be completed?
What will happen to the value of
our properties when this plant is
built?
How much increased traffic will
there be on the access highway?
9.5 First Nation Consultation Framework
A conservation and reclamation plan is included
as Consultants Report 7.
There will be 24 hour security on site and all traffic
will be monitored controlled and recorded.
Birchwood has contacted parties based upon
current land title records, however on occasion
notices have been returned to sender for various
reasons, mostly incorrect addresses on land titles.
Notifications and Non-objection letters were
completed and obtained, as required by ERCB
Directive 56 and ESRD consultation requirements.
The placement of the project has been selected to
recover bitumen on the mineral lease and also
limit surface disturbance by taking advantage of
existing highways, access roads, cleared areas
and industrial infrastructure, such as the Sales
Pipelines and the Diluent Pipeline, and third party
utility supply.
Birchwood has completed a TKA/TLU for the Cold
Lake First Nations on the well sites and access
roads developed in 2011.
Birchwood sees no reason for any change in
property value given much smaller size of the
Sage project when compared to existing Oilsands
development in the area.
Birchwood will access the development from
Highway 892 and will not affecting Crane Lake
residential access. Birchwood will work with
contractors and other operators to promote
procedures that will reduce peak traffic volumes.
Mitigation could include staggered hours, carpooling
and bus transportation.
Considering the significantly smaller size of the
operation compared to the already existing
development using Highway 892 the project is
unlikely to cause any noticeable changes to traffic
volumes or road usage for Crane Lake residents.
Birchwood, as the project proponent and in accordance with AESRD’s Policies and Guidelines
for consultation with First Nations, works within an internal First Nations Consultation Plan. This
plan is designed to ensure that Birchwood meets both the Guiding Principles and expectations
of industry put forth by the Alberta Government and ERCB.
Sage Pilot Application Page 237

9.5.1 First Nation Consultation Summary
Birchwood has consulted (and will continue to do so as required) with the following First Nations
with respect to the Sage pilot project as identified by the framework:
Cold Lake First Nation;
Frog Lake First Nation;
Beaver Lake Cree Nation;
Kehewin Cree Nation;
Heart Lake First Nation;
Whitefish – Goodfish First Nation;
Birchwood has, and will continue to track and respond to any written information requests,
concerns or questions brought forth by First Nations. A summary of consultation meetings and
events is provided in Table 9.6.
9.5.1.1 Cold Lake First Nation
Birchwood provided a Project Description Letter to the Cold Lake First Nation on its proposed
drilling program on June 24, 2011. It met with the Chief and Council and their legal counsel in
August 2011 to formally discuss the Cold Lake First Nation Consultation Guidelines. A
presentation on the project was provided by Birchwood and formal Consultation Protocols along
with a Traditional Territory Map and guidelines for the consultation process were presented by
the Chief on behalf of the Nation. Through the Cold Lake First Nation JV partner, Stantec Nu-
Nenni, a traditional knowledge and traditional land use study was commissioned and traditional
knowledge holders and elders participated in a field visit to the area. In May 2012, an invitation
to the open house and a copy of the Public Disclosure Document was sent. In June 2012, an
Open House was held for the Nation and the general public at which a Public Disclosure
Document was presented on the Birchwood Sage SAGD Project. In August 2012, notification of
a proposed 3D Seismic program was delivered to counsel for the Cold Lake First Nation by
registered mail. In October 2012, follow up notification of the Sage SAGD project complete with
the Public Disclosure Document and a copy of a Comment Form were delivered to the Cold
Lake First Nation by registered mail.
While engaging in consultation efforts with the Cold Lake First Nation, it became clear that the
Nation was firm on its moral and legal rights to consultation and participation by the Nation in
future development in the area. In efforts to both understand and assist in this process,
opportunities to participate were presented to the Nation and assistance was provided in its
relations with other operators in the area. The Cold Lake First Nation appears to be pleased
with the results of this process and willing to work with Birchwood in developing the project.
9.5.1.2 Frog Lake First Nation
In May 2012, an invitation to the open house and a copy of the Public Disclosure Document was
sent. In June 2012, an Open House was held for the Nation and the general public at which a
Public Disclosure Document was presented on the Birchwood Sage SAGD Project. In October
2012, follow up notification of the Sage SAGD project complete with the Public Disclosure
Document and a copy of a Comment Form were delivered to the Frog Lake First Nation by
registered mail.
Sage Pilot Application Page 238

As part of the Cold Lake First Nation’s drive to participate in development, it hosted a number of
meetings with other First Nations which Birchwood attended by invitation. At these meetings it
was clear that the Frog Lake First Nation was well advanced in its participation objectives as it
had developed a junior oil and gas company with substantial production on reserve land. At
meetings with Frog Lake Energy Limited, it was apparent that development off reserve would
follow and that Birchwood could assist in this.
9.5.1.3 Beaver Lake Cree Nation
Birchwood provided a Project Description Letter to the Beaver Lake Cree Nation on its proposed
drilling program on June 24, 2011. As no response was received by the end of the notice period
and all approvals and consents were in place, Birchwood commenced its proposed drilling
program in December 2011. In May 2012, an invitation to the open house and a copy of the
Public Disclosure Document was sent. In June 2012, an Open House was held for the Nation
and the general public at which a Public Disclosure Document was presented on the Birchwood
Sage SAGD Project. In August 2012, notification of a proposed 3D Seismic program was
delivered to the Beaver Lake Cree Nation by registered mail. In October 2012, follow up
notification of the Sage SAGD project complete with the Public Disclosure Document and a
copy of a Comment Form were delivered to the Beaver Lake Cree Nation by registered mail.
Formal notices were sent to the Beaver Lake Cree Nation and a formal written consultation
protocol was returned indicating that unless and until the Governments of Alberta and of
Canada responded to concerns of the Nation regarding Treaty 6 and the rights of Aboriginal
Peoples, no progress would be made on the Birchwood project. The application addresses
substantially all of the information requested, a copy of which will be sent to all identified
stakeholders.
9.5.1.4 Kehewin Cree Nation
Birchwood provided a Project Description Letter to the Kehewin Cree Nation on its proposed
drilling program on June 24, 2011. As no response was received by the end of the notice period
and all approvals and consents were in place, Birchwood commenced its drilling program in
December 2011. In May 2012, an invitation to the open house and a copy of the Public
Disclosure Document was sent. In June 2012, an Open House was held for the Nation and the
general public at which a Public Disclosure Document was presented on the Birchwood Sage
SAGD Project. In August 2012, notification of a proposed 3D Seismic program was delivered to
the Kehewin Cree Nation by registered mail. In October 2012, follow up notification of the Sage
SAGD project complete with the Public Disclosure Document and a copy of a Comment Form
were delivered to the Kehewin Cree Nation by registered mail.
After formal notices were sent to the Kehewin Cree Nation, a meeting was held with the Chief
and his councilors on August 24, 2012. At that meeting and at meetings attended by the Nation
at the invitation of the Cold Lake First Nation, it was clear that the Kehewin Cree Nation was
anxious to participate in development on and off the reserve in order to provide long term
opportunity to its citizens. Joint ventures in construction, service rig fabrication, drilling rig
operations and oil and gas development were discussed along with a Traditional
Knowledge/Traditional Land Use study. Birchwood explained that much of the land was either
freehold or developed grazing lease and that Stantec/Nu Nenni had already been engaged to
provide this and a report was available upon approval of the Cold Lake First Nation. At a
subsequent meeting with the Chief and Council, Birchwood’s assistance was sought to work
with a major operator and the Nation to construct a service rig.
Sage Pilot Application Page 239

9.5.1.5 Heart Lake First Nation
Birchwood provided a Project Description Letter to the Heart lake First Nation on its proposed
drilling program on June 24, 2011. As no response was received by the end of the notice period
and all approvals and consents were in place, Birchwood commenced its drilling program in
December 2011. In May 2012, an invitation to the open house and a copy of the Public
Disclosure Document was sent. In June 2012, an Open House was held for the Nation and the
general public at which a Public Disclosure Document was presented on the Birchwood Sage
SAGD Project. In August 2012, notification of a proposed 3D Seismic program was delivered to
the Heart Lake First Nation by registered mail. In October 2012, follow up notification of the
Sage SAGD project complete with the Public Disclosure Document and a copy of a Comment
Form were delivered to the Heart Lake First Nation by registered mail.
After formal notices were sent to the Heart Lake First Nation, a meeting was held with the
Nation’s advisors on August 20, 2012. At that meeting, the history of the Nation, the effect of the
Air Weapons Range agreements, the long tenure of the Chief and some of his accomplishments
in the area of economic development for the Nation as well as the consultation protocols
required were discussed. The nation had engaged a number of consultants that had clearly
defined traditional lands and migration patterns in an electronic format. The Birchwood project
was discussed and no substantive issues were identified. At a follow up meeting the councilors
brought along the Nation’s construction JV partner who presented its credentials. It was agreed
that the Nation would provide Birchwood with a Traditional Land use study and framework. As of
December 20, 2012 the information has yet to be received.
9.5.1.6 Whitefish – Goodfish First Nation
In May 2012, an invitation to the open house and a copy of the Public Disclosure Document was
sent. In June 2012, an Open House was held for the Nation and the general public at which a
Public Disclosure Document was presented on the Birchwood Sage SAGD Project. In August
2012, notification of a proposed 3D Seismic program was delivered to the Whitefish - Goodfish
First Nation by registered mail. In October 2012, follow up notification of the Sage SAGD project
complete with the Public Disclosure Document and a copy of a Comment Form were delivered
to the Whitefish - Goodfish First Nation by registered mail.
After formal notices were sent to the Whitefish - Goodfish First Nation, a meeting was held with
a Councilor and staff on August 23, 2012. At that meeting, Birchwood presented the project and
the Nation provided a traditional territory map, Economic development through on reserve
service businesses was discussed along with an MOU and TLU study. At a follow up meeting
with the Councilor and legal counsel the concept of a formal Memorandum of Understanding
was discussed and legal counsel was to provide it to Birchwood at its earliest opportunity.
Sage Pilot Application Page 240

9.6 Meetings and Events
Table 9.6 List of Meetings and Events
Date Meeting or Event
Alberta Environment and Sustainable Resources Development
February 8, 2012 Meeting with representatives from Alberta Environment and Alberta
Sustainable Resources to introduce Birchwood Resources Inc., and the SAGE
project.
Alberta Lake Management Society
October , 2012 Conference call to discuss ALMS role in Beaver River Watershed/LARP projects,
Crane Lake monitoring program that ALSM conducts, membership
opportunities and how to integrate monitoring requirements with association
objectives.
Alberta Sustainable Resource Development
June 28, 2012 Meeting at the Bonnyville ASRD office to discuss SAGE project including access,
project footprint, emergency response, fish and wildlife potential concerns.
Energy Resources Conservation Board
April 5, 2012 Meeting with various representatives of the ERCB to introduce Birchwood
Resources Inc. and discuss the SAGE project.
April, 2012 Meeting with various representatives of the ERCB to discuss geological
requirements associated with SAGD applications.
June 7, 2012 Open House at Riverhurst Community Association
June 27, 2012 Meeting with Bonnyville ERCB staff. Detailed discussion on the SAGE project.
MLA for Bonnyville-Cold Lake
June 27, 2012 Introduction to Birchwood Resources Inc. and discussion of the SAGE project.
Lakeland Industry and Community Association
October , 2011 Meeting to present well development and introduce Birchwood Resources Inc.
to LICA Board of Directors.
December, 2011 LICA Christmas Party – general discussion of industry activity.
April/May, 2012 Discussion of Groundwater monitoring parameters.
June 7, 2012 Open House at Riverhurst Community Association
June 27, 2012 General discussion of SAGE project and discussion on LICA/Beaver River air and
watershed monitoring.
Municipality of Bonnyville
November, 2011 Special council meeting to discuss cold well development and SAGE, specifically
access development and road use.
June 2012 Open House at Riverhurst Community Association
June 2012 Site Visit at SW-02-064-04W4m with Representative from Municipality of
Bonnyville.
Cold Lake First Nation
August 23, 2011 Meeting with Chief and Council at Counsel’s Office – consultation and history
August 26/27, 2011 Attend and Support NANCA Rodeo
September 23, 2011 Meeting with Members of Council – Economic Development
December 08, 2011 Meeting at Band Office – Status of project and economic development
December 13, 2011 Meeting with Chief and Council and BOD Tri Rez Oil and Gas – Economic Dev.
January 16, 2012 Meeting with Members of Council and BOD Tri Rez – Sage Project and Other
January 20, 2012 Meeting with Chief and Council and Bod Tri Rez – Business Development
Sage Pilot Application Page 241

January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel
March 29, 2012 Meeting with Council and JV Partners – Economic Development
April 12, 2012 Attend Industry and Nation Meeting on behalf of CLFN
April 19, 2012 Attend Meeting with Nation’s Environmental Consultants
April 24, 2012 Attend Meeting with Counsel for Nation on Environmental Cumulative Effects
May 25, 2012 Conference with Chief and Council and Counsel – Industry Relations
May 29, 2012 Meeting with Nation’s Counsel and Environmental Consultants – Impacts
June 4, 2012 Meeting with Nation’s Counsel and Environmental Consultants – Data Source
June 7, 2012 Open House at Riverhurst Community Hall – Sage Project
June 19, 2012 Meeting with Chief and Councillors – Review Economic Parameters – Industry
June 26, 2012 Attend Nation’s Camp and Catering JV Partner Industry Event
July 12, 2012 Meeting with Nation’s Counsel and Environmental Consultant – Impacts
July 25, 2012 Joint Bid Oil Sands Production Acquisition
October 10, 2012 Meeting with Councillors – Project Update and Economic Development
Frog Lake First Nation
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel
April 11, 2012 Meeting with CLFN and Frog Lake Energy Technical Teams – Economic Dev.
April 11, 2012 Meeting with Frog Lake Energy Investors – Economic Development
April 26, 2012 Meeting with Frog Lake Energy – Business Development Opportunity
May 28, 2012 Meeting with CLFN and Frog Lake Energy Representatives – Business Dev.
June 7 2012 Open House at Riverhurst Community Hall – Sage Project
June 12, 2012 Meeting with CLFN and Frog Lake Energy – Business Development
June 19, 2012 Meeting with CLFN and Frog Lake Energy – Business Development
July 12, 2012 Meeting with Frog Lake Energy Investors – Economic Development
July 25, 2012 Joint Bid Oil Sands Production Acquisition
November 29, 2012 Meeting with Fog Lake Energy Board Members – Economic Development
Kehewin Cree Nation
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
March 22, 2012 Conference – Keyano Pimee Board of Directors – Economic Development
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel
August 24, 2012 Meeting Chief and Councillor – TLU, Economic Development, Sage Project
September 25, 2012 Meeting with Chief and Council at Band Office – Project, Economic Benefit
Onion Lake First Nation
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel
Saddle Lake First Nation
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
March 26/27, 2012 Attend and Present at Aboriginal Economic Summit – River Cree Hotel
April 4, 2012 Meeting with Councillors, JV Partners and Financial Advisors – Economic Dev.
April 26, 2012 Meeting with Councillor – Economic Development and Joint Venture
Samson Cree Nation
January 27, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
IOGC
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
Sage Pilot Application Page 242

IRCC
February 8, 2012 Multi Nation Conference at River Cree – Business Development Opportunity
Heart Lake First Nation
August 20, 2012 Meeting with Councillors and Advisors, Edmonton – Sage Project, History, TLU
November 22, 2012 Meeting with Councillors and JV Partner – Business Development Opportunity
Whitefish – Goodfish First Nation
August 23, 2012 Meeting with Councillor at Band Office – Sage Project, History, TLU, MOU
August 29, 2012 Meeting with Councillor and Counsel – TLU, MOU, Economic Development
Metis Zone II
June 7, 2012 Open House at Riverhurst Community Hall – Sage Project – JV Partner
August 22, 2012 Meeting with Councillor and Advisor – History, Background, TLU, Economics
August 23, 2012 Meeting with Rupertsland Institute Director – Educational Assistance JV
September 26, 2012 Meeting with Rupertsland Institute Director – Specific Education Project
9.7 Birchwood Commitment to Consultation
Birchwood will make available a copy of the Sage pilot project application on the Birchwood
website and continue to maintain a list of FAQ’s and provide updates as the Sage pilot project
develops.
Birchwood will track and respond to all written information requests, concerns or questions
brought forth by any stakeholder and will continue to engage and consult with any stakeholder
throughout the application and operation phase of the Sage project.
Sage Pilot Application Page 243

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Beckingham, J.D. and J.H. Archibald. 1996. Field Guide to Ecosites of Northern Alberta.
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Sands Conservation Regulation. Calgary, AB.
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Sage Pilot Application Page 247

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Conservation Act and Regulations, Oil and Gas Conservation Act and Regulations, Oils Sands
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Energy Resources Conservation Board (ERCB), 2007. Directive 038 - Noise Control. Calgary,
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and Reporting Plan (MARP) Requirements for Thermal Bitumen Schemes. Calgary, AB.
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Management. Calgary, AB.
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Wells – Well Classifications, Completions, Logging and Testing Requirements. Calgary, AB.
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the Upstream Petroleum Industry. Calgary, AB.
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Requirements for the Upstream Petroleum Industry. Calgary, AB.
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and Response Requirements for the Petroleum Industry Calgary, AB.
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Reporting Requirements. Calgary, AB.
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Memorandum of Understanding between Alberta Environmental protection and the Alberta
Energy and Utilities Board Regarding Coordination of Release Notification Requirements and
Subsequent Regulatory Response. Calgary, AB.
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the Requirements for the Appropriate Management of Oilfield Wastes. Calgary, AB.
Sage Pilot Application Page 248

Energy Resources Conservation Board (ERCB), 1999, Interim Directive 99-04 – Deposition of
Oilfield Waste into Landfills. Calgary, AB.
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Memorandum of Understanding on the Regulation of Oil Sands Developments. Calgary, AB.
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Production in Oil Sands Areas – Application, Notification and Drilling Requirements. Including
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of Waste Management and Memorandum of Understanding Between the Alberta Energy and
Utilities Board and Alberta Environment. Calgary, AB.
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Sands Operations. Calgary, AB.
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Recovery Guidelines for the Province of Alberta. Calgary, AB.
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Sage Pilot Application Page 249

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Heritage Rangelands Act W-9. Edmonton, AB
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Sage Pilot Application Page 250

Hamilton, W.N., Price M.C., and Langenburg C.W. (compilers). 1999. "Geological Map of
Alberta. Alberta Geological Survey, Alberta Energy and Utilities Board, Map No. 236."
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Alberta Environment and the ERCB.
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Input in the LICA Area (Map), Edmonton, AB
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Impacts on Soils and surface Water Within the LICA AREA. Edmonton, AB.
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Edmonton, AB.
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Alberta Chapter), Federation of Alberta Naturalists, Keepers of the Athabasca, and Pembina
Institute. Global Forest Watch Canada
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Sage Pilot Application Page 251

United States Environmental Protection Agency. Emission Factors and AP-42, Compilation of Air
Pollutant Emission Factors, Chapter 1.4: Natural Gas Combustion, July, 1998; Chapter 3.3:
Gasoline and Diesel Industrial Engines, October, 1996; chapter 13.5 Industrial Flares,
September, 1991
All references contained herein include amendments to cited works to November 30, 2012.
Sage Pilot Application Page 252

11 Acronyms and Abbreviations
2D
LIST OF ACRONYMS
Two dimensional
3D Three Dimensional
AAAQO Alberta Ambient Air Quality Objectives
AAAGO Alberta Ambient Air Guidelines and Objectives
ABMI Alberta Biodiversity Monitoring Institute
AESRD Alberta Environment and Sustainable Resources
ACIMS Alberta Conservation Information Management System
ALMS Alberta Lake Management Society
ANPC Alberta Native Plant Council
API American Petroleum Institute
ASIC Alberta Soil Information Council
ASRD Alberta Sustainable Resources Development
ATV All-Terrain Vehicle
AUC Alberta Utilities Commission
BATEA Best Available Technology Economically Achievable
bbl Barrels
bbl/day Barrels per day
BFW Boiler Feed Water
BHA Bottom Hole Assembly
bopd Barrels oil per day
BS & W Basic Sediments and Water
C&R Conservation and Reclamation
Ca Calcium
CaCl2 Calcium Chloride
CEC Cation Exchange Capacity
CERP Corporate Emergency Response Plan
CCME Canadian Council Of Ministers of the Environment
CEMA Cumulative Environmental Management Association
CL SRIRP Cold Lake Sub Regional Integrated Resources Plan
CLASP Crane Lake Area Structure Plan
CLBRB Cold Lake Beaver River Basin
CO2 Carbon dioxide
COSEWIC Committee on the Status of Endangered Wildlife in Canada
cP Centipoise
CPF Central Processing Facility
CSOR Cumulative Steam Oil Ratio
CSS Cyclic Steam Stimulation
cST Centistokes
DA Development Area
DCS Distributed Control System
DOW Dangerous Oilfield Waste
EC Electrical Conductivity
EC Electrical Conductivity
ESP Electric Submersible Pump
EPEA Environmental Protection and Enhancement Act
ERCB Energy Resources Conservation Board
ERP Emergency Response Plan
ESRD Environment and Sustainable Resource Development
FWKO Free Water Knock Out
Sage Pilot Application Page 253

FWMIS Fish and Wildlife Management Information System
GOR Gas-Oil Ratio
GSA Geological Study Area
IGF Induced Gas floatation
GJ/day Gigajoules/day
Ha Hectare
H2S Hydrogen Sulphide
HPV High Pressure Vapours
Hwy Highway
ID Interim Directive
IFR IN-Field Referencing
IOL Imperial Oil Limited
IRP Industry Recommended Practice
ISOR Instant Steam to Oil Ratio
Kg/day Kilograms per day
kPa Kilopascals
KOP Kick Off Point
kV Kilo Volt
kW Kilowatt
LACT Lease Automated Custody Transfer
LARP Lower Athabasca Regional Plan
LCC Land Capability Classification System
LEL Lower Exposure Level
LFN Low Frequency Noise
LICA Lakeland Industry Community Association
LOC License Of Occupation
LSA Local Study Area
LWD Logging While Drilling
mD Meters Depth
m 3 /day Meters cubed per day
MARP Measurement, Accounting and Reporting Plan
MagOx Magnesium oxide
MD Municipal District
MOP Maximum Operating Pressure
MSL Mineral Surface Lease
MSA Multi Station Analysis
MW Mega Watts
MWD Measurement While Drilling
NDOW Non Dangerous Oilfield Waste
NOx Nitrogen Oxides
NO2 Nitrogen Dioxide
NPS Nominal Pipe Size
OBIP Original Bitumen in Place
OOIP Original Oil in Place
ORF Oil Removal Filters
OSCA Oil Sands Conservation Act
OWC Oil Water Contact
PA Project Area
PDA Project Development Area
P&NG Petroleum and Natural Gas
PCP Progressive Cavity Pump
PDA/C&R Pre-Disturbance Assessment/Conservation & Reclamation Plan
Sage Pilot Application Page 254

PM Inhalable Particulate Matter
ppm Parts per million
PSV Pressure Safety Valve
RDA Resource Development Area
RFMA Registered Forestry Management Agreement
RGS Regional Geological Study
RoW Right of Way
RSS Rotary Steerable Systems
SAC Strong Acid Cation
SAGD Steam Assisted Gravity Drainage
SAR Sodium Absorption Ratio
SARA Species at Risk Act
s/l Seconds per liter
SO2 Sulphur Dioxide
SOR Steam to Oil Ratio
sm 3 /day Standard cubic meters per day
t/day Tonnes/day
TDG Transportation of Dangerous Goods
TDS Total Dissolved Solids
TN Total Nitrogen
TOC Total Organic Carbon
TVD Total Vertical Depth
TD Total Depth
UPS Uninterruptible Power Supply
VAC Volts Alternating Current
VAD Volts Direct Current
VOC Volatile Organic Compounds
VRU Vapour Recovery Unit
WHMIS Workplace Hazardous Materials Information System
WSR Water to Steam Ratio
Sage Pilot Application Page 255

contact
for more information or to provide us your views or input on the
proposed Sage Thermal Pilot Project or on any aspect of our operations
please contact Kathryn Lundy at:
Telephone: 403.265.1244 x 221
Facsimilie: 403.265.1204
Email: klundy@birchwoodresources.ca
Website: www.birchwoodresources.ca
Mail: Suite 1200, 630 - 6th Ave SW
Calgary, Alberta T2P 0S8

suite 1200, 630 - 6th avenue south west, calgary alberta t2P 0s8
P. 403-265-1244 F. 403-265-1204 www.birchwoodresources.ca