9 Emission Sources - Alberta...Joslyn North Mine Project Section 9: Emission Sources AI Project...

Joslyn North Mine ProjectAI Project Update Section 9: Emission Sources

TOTAL E&P Joslyn Ltd. February 2010 Page 9-1

9 Emission Sources

9.1 Introduction

This section describes the following:

• extraction process emissions • mining equipment emissions • tailings emissions • greenhouse gas emissions • acoustics

For a description of the revised emission parameters for the project, as well as the stack parameters and source locations, see Section 12.9.

9.2 Extraction Process Emissions The following extraction plant site components will be a source of air emissions during operations:

• cogeneration plant • auxiliary boilers • flare stack • heating system for the maintenance and administration building

For the predicted emission levels, see Table 9.2-1.

The release rate of sulphur oxides (SOX) is determined by the concentration of sulphur compounds in the natural gas used for fuel in the extraction process.

The auxiliary boilers will be designed to use low-nitrogen oxides (NOX) burners. Technology for reducing NOX emissions to approach Alberta Environment interim NOX management performance criteria will continue to be assessed.

Under normal operating conditions, flaring will make a negligible contribution to extraction plant site emissions. However, during a severe plant upset, emission of combustion gases from the flare will be considerable. For example, where controls or equipment fail or operator error occurs, hydrocarbon vapour (primarily solvent) could be burned and the combustion gases released to the atmosphere. However, because vapour discharge to the flare is infrequent, the contribution of these combustion products to the overall emissions rate is expected to be negligible. For the estimated worst-case intermittent flare gas volumes and composition, see Table 9.2-2.

Joslyn North Mine Project Section 9: Emission Sources AI Project Update

February 2010 TOTAL E&P Joslyn Ltd.Page 9-2

Table 9.2-1 Process Emission Sources and Predicted Emission Levels

Parameter Cogen Unit1 Auxiliary Boilers2 Flare Capacity rating of equipment (nominal)3 85 MW 200 tph steam N/A Heat duty (GJ/h) 14484 115 N/A Local elevation (masl) 300 300 300 Coordinates - local (N,E) coordinates or UTM

454239, 6346825 454268, 6346852

454267, 6346904 454280, 6346916

455078, 6347327

Stack height (m) 36.6 30 149 Stack diameter (m) 5.3 2.3 1.35 Maximum building/structure height 15.0 15.0 17.0 Exhaust temperature (°C) 127 116 12735 Exhaust velocity (m/s) 21.3 1.83 119.35 Thermal efficiency (Gj-h out/Gj-h in) (%) 85 85 N/A Emission rate (g/s)

SO2 0.0172 0.014 0.0 NOX 12.61 0.253 125.25 CO 4.67 1.02 N/A CO2 18,400 1600 N/A PM2.5 1.03 0.092 N/A VOCs 0.33 0.067 N/A

Steam generated (tph) 323 25 N/A Steam press kPa(a) 500 and 4200 500 and 4200 N/A Steam temperature (°C) 172 and 273 172 and 273 N/A

NOTES: 1 Two cogen units will be installed. The heat duty and emissions data provided are for each

cogen unit. 2 Two boilers will be installed. The heat duty and emissions data provided are for each boiler. 3 Cogen units and boilers will operate at design availability rates 90% of the time. 4 319 GJ/h of the 1448 GJ/h is allocated to duct firing. Both values are based on high heating

value (HHV). 5 Flare stack parameters are based on a worst-case flaring event lasting 20 minutes and do not

represent a continuous emission rate. N/A = Not applicable.



Table 9.2-2 Worst-Case Intermittent Flare Load Estimates

Component

Mole Fraction

Mass Fraction

Molecular Weight

Mass Flow (kg/h)

Air 0.0007 0.0003 29.0 330 H2O 0.1542 0.0422 18.0 45,039 N2 0.0001 0.0000 28.0 29 CO2 0.0000 0.0000 44.0 29 C1 0.0043 0.0010 16.0 1,115 C2 0.0002 0.0001 30.1 75 C3 0.0003 0.0002 44.1 186 iC4 0.0004 0.0004 58.1 389 nC4 0.0026 0.0023 58.1 2,422 iC5 0.2114 0.2319 72.2 247,294 nC5 0.6066 0.6651 72.2 709,372 Cyclopentane 0.0045 0.0048 70.1 5,135 2-Methyl pentane 0.0007 0.0010 86.2 1,013 2,2-Dimethyl butane 0.0012 0.0016 86.2 1,657 n-Hexane 0.0013 0.0017 86.2 1,792 Cyclohexane 0.0001 0.0001 84.2 159 Benzene 0.0001 0.0001 78.1 125 2,4-Dimethyl pentane 0.0002 0.0003 100.2 367 2-Methyl hexane 0.0001 0.0002 100.2 228 n-Heptane 0.0004 0.0006 100.2 590 Methyl cyclohexane 0.0001 0.0001 98.2 117 Toluene 0.0001 0.0002 92.1 171 C8+ (Bitumen) 0.0104 0.0458 289.2 48,854 Total sulphur 0.0000 0.0000 34.1 0.008Total 1.0000 1.0000 1,066,058



9.3 Mining Equipment Emissions Emissions from the project mining equipment will include NOX, particulate matter less than 25 µ in diameter (PM2.5), carbon monoxide (CO), non-methane hydrocarbons (NMHC) and SOX. Sulphur emissions will be proportional to the amount of sulphur present in the diesel fuel, and carbon dioxide (CO2) emissions will be proportional to the amount of diesel burned.

Air emission levels from the mining equipment will comply with the U.S. Environmental Protection Agency (U.S. EPA) rules that govern diesel engines sold in North America. For the U.S. EPA off-road emission standards, based on U.S. EPA Tier 2 and Tier 3 Emission Standards - Final Rule (1998) and the Clean Air Nonroad Diesel – Tier 4 Final Rule (2004), see Table 9.3-1. The emissions are based on engine power output and are phased in over time to provide engine manufacturers research and development time.

As project commissioning will occur in Q4 2016, equipment purchased for start-up will be compliant with the U.S. EPA Tier 4 emissions standard levels throughout the life of the project.

For the tier levels used for each of the evaluation years, see Table 9.3-2. For the maximum emissions in each of the categories, under the tier levels for the three input years for the emissions modelling, see Table 9.3-3.

For diesel consumption and the estimated CO2 production per day during project operations, see Table 9.3-4.

For sulphur production, based on fuel sulphur content of 15 mg/kg, and fuel consumed, see Table 9.3-5. TEPJ plans to use ultra-low sulphur diesel (less than 15 ppm sulphur) in the project mining equipment. The SO2 production is based on the maximum sulphur content in the fuel.



Table 9.3-1 U.S. EPA Off-Road Diesel Emission Standards Standards

NOX4 NMHC4 NMHC+NOX

5 CO PM2.5 Rated Power kW (hp)

EPA Tier

Model Year (g/kW-h) (g/bhp-h) (g/kW-h) (g/bhp-h) (g/kW-h) (g/bhp-h) (g/kW-h) (g/bhp-h) (g/kW-h) (g/bhp-h)

Tier 11 1997 9.2 6.9 N/A N/A N/A N/A N/A N/A N/A N/A Tier 2 2003 N/A N/A N/A N/A 6.6 4.9 5.0 3.7 0.30 0.22 Tier 3 2007 N/A N/A N/A N/A 4.0 3.0 5.0 3.7 0.30 0.22

75–130 (100–175)

Tier 42 2012–13 0.40 0.30 0.19 0.14 0.59 0.44 5.0 3.7 0.013 0.010 Tier 11 1996 9.2 6.9 1.3 1.0 10.5 7.8 11.4 8.5 0.54 0.40 Tier 2 2003 5.8 N/A 0.8 N/A 6.6 4.9 3.5 2.6 0.20 0.15 Tier 3 2006 3.5 N/A 0.5 N/A 4.0 3.0 3.5 2.6 0.20 0.15

130–225 (175–300)


225–450 (300–600)


450–560 (600–750)

Tier 43 2011–14 0.40 0.30 0.19 0.14 0.59 0.44 3.5 2.6 0.013 0.010 Tier 11 2000 9.2 6.9 1.3 1.0 10.5 7.8 11.4 8.5 0.54 0.40 Tier 2 2006 5.6 N/A 0.8 N/A 6.4 4.8 3.5 2.6 0.20 0.15 Tier 4 Phase 1 2011 3.49 2.6 0.40 0.30 3.89 2.90 3.5 2.6 0.101 0.075

>560 (>750)

Tier 4 Phase 2 2015 3.49 2.6 0.19 0.14 3.67 2.74 3.5 2.6 0.040 0.030

NOTES: Tier 3 engines require low-sulphur diesel (<500 ppm). Tier 4 engines require ultra-low-sulphur diesel (<15 ppm). 1 Tier 1 levels regulated total hydrocarbon not just NMHC. 2 PM standard in 2012 and phased implementation to 100% of engines compliant with NOX and NMHC in 2013. 3 PM standard in 2011 and phased implementation to 100% of engines compliant with NOX and NMHC standard in 2014. 4 NOX and NMHC splits for Tier 2 and Tier 3 are estimated based on Tier 1 ratio. 5 Where separate standards are shown for NOX and NMHC, the numbers shown in the NMHC+NOX column are for comparison only. CO = Carbon monoxide. N/A = Not applicable. NOX = Nitrogen oxides. NMHC = Non-methane hydrocarbons. PM = Particulate matter.



Table 9.3-2 Equipment EPA Tier Level and Power Rating EPA Tier Level Compliance for Engines

Diesel Equipment Category

Equipment Type and Size Range

Gross Power Rating (kW)

EPA Power Range

(hp)

Year 1 2017

Year 2 2018

Year 3 2019

Year 4 2020

Year 5 2021

Year 6 2022

Large haul truck (380 t – 400 t) 2,610 >560 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2

Haul trucks Utility truck (100 t) 746 >560 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2 Large 433 450–560 4 4 4 4 4 4

Dozers Medium 231 225–450 4 4 4 4 4 4

Hydraulic shovels Shovel (40 m3) 2,893 >560 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2 Loaders Medium 597 >560 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2 4 ph2

Large 373 225–450 4 4 4 4 4 4 Graders

Medium 194 130–225 4 4 4 4 4 4 Large 470 450–560 4 4 4 4 4 4

Excavators Medium 254 225–450 4 4 4 4 4 4 Rubber-tired dozer 470 450–560 4 4 4 4 4 4 Cable reeler 395 225–450 4 4 4 4 4 4 Soil compactor 231 225–450 4 4 4 4 4 4 Pipehandler 225 225–450 4 4 4 4 4 4

Support

Misc. other 261 to 1,743 225–450 to >560 4/4 ph 2 4/4 ph 2 4/4 ph 2 4/4 ph 2 4/4 ph 2 4/4 ph 2



Table 9.3-3 Maximum Emissions Under Tier Level Year 1 2017 (kg/d)

Year 3 2019 (kg/d)

Year 6 2022 (kg/d)


Equipment Type

and Size Range

Gross Power Rating (kW)

EPA Power Range

(hp) NOX NMHC PM CO NOX NMHC PM CO NOX NMHC PM CO Large haul truck (380 t–400 t)

2610 >560 2,628 142 30 2,602 4,913 265 57 4,865 4,799 258 55 4,752 Haul trucks

Utility truck (100 t) 746 >560 57 3 1 56 57 3 1 56 57 3 1 56

Large 433 450–560 17 8 1 143 26 12 1 225 26 12 1 225 Dozers Medium 231 225–450 5 2 0 44 8 4 0 66 8 4 0 66

Hydraulic shovels

Shovel (40 m3) 2893 >560 124 7 1 123 186 10 2 185 186 10 2 185

Loaders Medium 597 >560 34 2 0 34 34 2 0 34 34 2 0 34 Large 373 225–450 10 5 0 88 16 8 1 141 14 7 0 123 Graders Medium 194 130–225 2 1 0 16 2 1 0 16 2 1 0 16 Large 470 450–560 3 1 0 24 3 1 0 24 3 1 0 24 Excavators Medium 254 225–450 15 7 1 131 15 7 1 131 15 7 1 131 Rubber-tired dozer 470 450–560 5 2 0 40 7 3 0 60 7 3 0 60

Cable reeler 395 225–450 1 1 0 11 3 1 0 22 3 1 0 22 Soil compactor 231 225–450 1 0 0 8 2 1 0 15 2 1 0 15

Pipehandler 225 225–450 1 1 0 13 1 1 0 13 1 1 0 13

Support

Misc. other 261 to 1743

225–450 to >560 15 7 0 73 16 8 1 81 16 8 1 81

Total 2,919 188 35 3,407 5,290 326 63 5,935 5,174 319 62 5,804

NOTES: CO = Carbon monoxide. N/A = Not applicable. NOX = Nitrogen oxides. NMHC = Non-methane hydrocarbons. PM = Particulate matter.



Table 9.3-4 Total Fuel Consumed and CO2 Production Yearly Diesel Fuel Consumed

(kL/a) Estimated Daily CO2 Produced1

(kg/d) Diesel Equipment

Category Equipment Type and

Size Range Year 12017

Year 22018

Year 32019

Year 42020

Year 52021

Year 6 2022

Year 12017

Year 22018

Year 32019

Year 42020

Year 52021

Year 62022

Large haul truck (380 t–400 t) 46,704 45,084 44,585 60,358 38,651 41,423 349,319 337,205 333,473 451,444 289,088 309,820Haul trucks

Utility truck (100 t) 3,328 4,049 3,592 5,787 4,856 5,380 24,889 30,286 26,865 43,287 36,324 40,239Large 7,362 6,844 6,969 9,435 7,115 7,481 55,062 51,190 52,124 70,566 53,219 55,954

Dozers Medium 1,226 1,226 1,226 1,226 1,226 1,226 9,173 9,173 9,173 9,173 9,173 9,173

Hydraulic shovels Shovel (40 m3) 10,793 10,473 10,245 13,693 10,438 11,145 80,729 78,336 76,629 102,419 78,072 83,360Loaders Medium 1,421 1,658 1,846 2,139 2,048 2,001 10,632 12,404 13,809 16,000 15,315 14,963

Large 2,064 2,000 1,980 2,532 1,764 1,859 15,441 14,957 14,806 18,938 13,194 13,906Graders

Medium 294 316 326 353 325 353 2,196 2,361 2,437 2,638 2,433 2,641Large 2,997 2,997 2,997 2,997 2,997 2,997 22,416 22,416 22,416 22,416 22,416 22,416

Excavators Medium 790 790 790 790 790 790 5,912 5,912 5,912 5,912 5,912 5,912Rubber-tired dozer 932 879 858 1,141 878 932 6,970 6,578 6,416 8,532 6,564 6,974Cable reeler 148 136 134 172 136 144 1,105 1,020 999 1,286 1,019 1,074Soil compactor 76 106 120 157 120 103 570 796 900 1,177 895 772Pipehandler 498 498 498 498 498 498 3,727 3,727 3,727 3,727 3,727 3,727

Support

Miscellaneous other 4,051 4,041 4,040 4,316 3,942 4,009 30,300 30,223 30,221 32,285 29,481 29,988Total 82,685 81,100 80,207 105,596 75,785 80,342 618,439 606,582 599,906 789,799 566,832 600,917

NOTE: 1 CO2 production estimated at: 2.73 kg/L of diesel fuel consumed.



Table 9.3-5 Total Fuel Consumed and SO2 Production Yearly Diesel Fuel Consumed

(kL/a) Estimated Daily SO2 Produced1

(kg/d) Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6


Equipment Type and Size Range 2017 2018 2019 2020 2021 2022 2017 2018 2019 2020 2021 2022

Large-haul truck (380 t–400 t) 46,704 45,084 44,585 60,358 38,651 41,423 3.365 3.249 3.213 4.349 2.785 2.985

Haul Trucks Utility truck (100 t) 3,328 4,049 3,592 5,787 4,856 5,380 0.240 0.292 0.259 0.417 0.350 0.388 Large 7,362 6,844 6,969 9,435 7,115 7,481 0.530 0.493 0.502 0.680 0.513 0.539

Dozers Medium 1,226 1,226 1,226 1,226 1,226 1,226 0.088 0.088 0.088 0.088 0.088 0.088

Hydraulic Shovels Shovel (40 m3) 10,793 10,473 10,245 13,693 10,438 11,145 0.778 0.755 0.738 0.987 0.752 0.803

Loaders Medium 1,421 1,658 1,846 2,139 2,048 2,001 0.102 0.119 0.133 0.154 0.148 0.144 Large 2,064 2,000 1,980 2,532 1,764 1,859 0.149 0.144 0.143 0.182 0.127 0.134

Graders Medium 294 316 326 353 325 353 0.021 0.023 0.023 0.025 0.023 0.025 Large 2,997 2,997 2,997 2,997 2,997 2,997 0.216 0.216 0.216 0.216 0.216 0.216

Excavators Medium 790 790 790 790 790 790 0.057 0.057 0.057 0.057 0.057 0.057 Rubber-tired dozer 932 879 858 1,141 878 932 0.067 0.063 0.062 0.082 0.063 0.067 Cable reeler 148 136 134 172 136 144 0.011 0.010 0.010 0.012 0.010 0.010 Soil compactor 76 106 120 157 120 103 0.005 0.008 0.009 0.011 0.009 0.007 Pipehandler 498 498 498 498 498 498 0.036 0.036 0.036 0.036 0.036 0.036

Support

Misc. other 4,051 4,041 4,040 4,316 3,942 4,009 0.292 0.291 0.291 0.311 0.284 0.289 Total 82,685 81,100 80,207 105,596 75,785 80,342 5.958 5.844 5.779 7.609 5.461 5.789

NOTE: 1 SO2 estimated production at: 0.0263 g/L of diesel fuel; diesel fuel sulphur content: 15 mg/kg maximum.



9.4 Tailings The extraction process will generate coarse sand tailings, thickened tailings (TT) and froth treatment tailings (FTT). The coarse sand tailings and the TT are not expected to contribute substantially to air emissions. The FTT will contain residual solvent and maltenes that will contribute to fugitive volatile organic compound (VOC) emissions. It is estimated that the FTT will result in VOC emissions of about 500 g/s (for peak summer rates). This estimate is based on the ERCB expectation that solvent losses to the tailings pond will be limited to an average 4 volumes per 1000 volumes of dry bitumen. The asphaltenes deposited in the ponds are not expected to contribute to VOCs.

The FTT will be deposited subaqueously in Pond 1 and Pond 2 according to the tailings deposition schedule (see Figure 6.4-1). The tailings ponds will contain fluid fine tailings (FFT), process-affected water and FTT.

For a summary of the surface area at the end of filling for each tailings pond and the range in elevation of the pond surfaces over time during filling, see Table 9.4-1.

For the flow rates of various components in the FTT from the extraction plant to Pond 1 and Pond 2, and the resulting emission rates for each component, see Table 9.4-2. The area of each pond was used to calculate the concentration of emissions from either pond given the loading rates in kg/d. The emission rates shown in Table 9.4-2 apply to Pond 1 and Pond 2.

Table 9.4-1 Area and Elevation of the Froth Treatment Tailings Ponds

Wetted Pond Surfaces Parameter Pond 11,2 Pond 21,2

Tailings pond surface area at end of filling (km2) 2.4 1.3 Tailings pond water surface elevation (masl) Varies from

328 to 338 over time Varies from

221 to 256 over time

NOTES: Surface areas represent wetted pond areas. 1 Pond 1 and Pond 2 will contain FFT, recycle water and FTT. 2 FTT will be deposited subaqueously.



Table 9.4-2 Predicted Froth Treatment Tailings Composition and Emissions

Component

Flow Rate to Tailings Pond

(kg/d)

Emissions from Tailings Pond

(kg/d) Propane 0.0076 0.0053 i-Butane 0.1653 0.1630 n-Butane 20.08 19.6 2,2-Mbutane 55.26 54.2 i-Pentane 16,780 16,495 n-Pentane 23,358 22,914 Mcyclopentane 380.5 356.3 n-Hexane 299.3 295 Cyclohexane 274 240.5 Mcyclohexane 211 198.9 n-Heptane 507 501.6 n-Octane 706 701.1 n-Nonane 433 431.1 n-Decane 350 347.9 n-C11 191 188.9 n-C12 84.7 84.2 n-C13 68.4 67.4 n-C14 41.7 40.8 n-C15 182 181.5 Benzene 91.6 17 Toluene 114.2 24.5 E-benzene 20.6 4.93 m-Xylene 52.2 11.15 p-Xylene 52.3 10.63 o-Xylene 52.3 8.53 1,2,4-Mbenzene 14.6 2.84 1,2,3-trimethylbenzene N/A N/A 1,2,4-trimethylbenzene N/A N/A 1,3,5-triethylbenzene N/A N/A 1-methyl-2-ethylbenzene N/A N/A 1-methyl-4-ethylbenzene N/A N/A n-propylbenzene N/A N/A Isopropylbenzene N/A N/A Total 44,340 43,197

NOTE: N/A = Not applicable.



9.5 Greenhouse Gas Emissions

Greenhouse gas (GHG) emissions from the project will be primarily generated from the following sources:

• combustion of natural gas in the cogeneration units and auxiliary boilers for electricity and steam generation – estimated to account for approximately 60% of total GHG emissions

• combustion of diesel by vehicle operations (primarily mine fleet) – estimated to account for approximately 15% of total GHG emissions

• direct release of GHGs (mainly methane) emitted from exposed oil sands and tailings (mine face, tailings and disposal area) – estimated to account for approximately 20% of total GHG emissions

• other minor sources of GHG emissions, including construction activities, facilities, decommissioning activities, reclamation activities – estimated to account for approximately 5% of total GHG emissions

Greenhouse gas emissions are reported as carbon dioxide equivalent emissions (CO2e). Calculated emission values for CH4 and N2O are adjusted by the global warming potentials (GWP) for those gases. The GWPs used in the calculations (see Table 9.5-1) were obtained from Canada’s Greenhouse Gas Inventory: 1990-2001 (Environment Canada 2003).

Table 9.5-1 Global Warming Potential of Gases Gas GWP CO2 1 CH4 21 N2O 310

The carbon dioxide equivalent emission is calculated using the following equation: CO2e = Mass CO2 + (Mass CH4 x GWPCH4) + (Mass N2O x GWPN2O) [tonnes]

For an estimate of annual GHG emissions from project sources, see Table 9.5-2.

For annual GHG emissions, and their relative contribution in a provincial, national and global context, see Table 9.5-3.



Table 9.5-2 Annual Greenhouse Gas Emissions from the Project

Project Component Year 1 2017

Year 2 2018

Year 3 2019

Year 4 2020

Year 5 2021

Years 6-212022–2037

Mine Fleet Mine fleet diesel use (kL/a) 82,685 81,100 80,207 105,596 75,785 80,342 Mine fleet CO2 emissions (kg/d)

618,439 606,582 599,906 789,799 566,832 600,917

Annual Mine Fleet Emissions CO2 (t/a) 225,730 221,403 218,966 288,277 206,894 219,335

CH4 (t CO2e/a) 243 238 235 310 222 236 N2O (t CO2e/a) 28,194 27,653 27,349 36,006 25,841 27,395

Total (t CO2e/a) 254,167 249,294 246,550 324,592 232,957 246,966 Cogen Units Cogen unit emissions (g/s) (avg. operating)

29,032 36,290 36,290 36,290 36,290 36,290

Cogen unit service factor 0.9 0.9 0.9 0.9 0.9 0.9Annual Cogen Unit Emissions At Capacity

CO2 (t/a) 824,000 1,030,000 1,030,000 1,030,000 1,030,000 1,030,000 CH4 (t CO2e/a) 4483 5603 5603 5603 5603 5603 N2O (t CO2e/a) 6617 8271 8271 8271 8271 8271

Total (t CO2e/a) 835,099 1,043,874 1,043,874 1,043,874 1,043,874 1,043,874 Capacity (GW/h) 1018 1272 1272 1272 1272 1272 Process electricity consumption (GW/h)

598 747 747 747 747 747

Annual Emissions for Operations CO2 (t/a) 648,440 810,550 810,550 810,550 810,550 810,550

CH4 (ts CO2e/a) 3528 4409 4409 4409 4850 4409 N2O (t CO2e/a) 5207 6509 6509 6509 7160 6509

Total (t CO2e/a) 657,174 821,468 821,468 821,468 903,615 821,468 Annual Emissions for Electricity Sales

CO2 (t/a) 175,560 219,450 219,450 219,450 219,450 219,450 CH4 (t CO2e/a) 955 1194 1194 1194 1194 1194 N2O (t CO2e/a) 1410 1762 1762 1762 1762 1762

Total (t CO2e/a) 177,925 222,406 222,406 222,406 222,406 222,406 Auxiliary Boilers Auxiliary boiler emissions (g/s) (avg. operating)

1,057 1,057 1,057 1,057 1,057 1,057

Number of boilers 2 2 2 2 2 2 Service factor 0.9 0.9 0.9 0.9 0.9 0.9Annual Auxiliary Boiler Emissions

CO2 (t/a) 24,000 30,000 30,000 30,000 30,000 30,000 CH4 (t CO2e/a) 131 163 163 163 163 163 N2O (t CO2e/a) 193 241 241 241 241 241

Total (t CO2e/a) 24,323 30,404 30,404 30,404 30,404 30,404



Table 9.5-2 Annual Greenhouse Gas Emissions from the Project (cont’d)


Year 2 2018

Year 3 2019

Year 4 2020

Year 5 2021

Years 6-212022–2037

Emissions Adjusted for Production Level CO2 (t/a) 21,600 27,000 27,000 27,000 27,000 27,000

CH4 (t CO2e/a) 118 147 147 147 147 147 N2O (t CO2e/a) 173 217 217 217 217 217

Total (t CO2e/a) 21,891 27,364 27,364 27,364 27,364 27,364 Upset Flaring Flaring Emissions Per Incident Hour

CO2 (t/h) 7,668 7,668 7,668 7,668 7,668 7,668 CH4 (t CO2e/h) 2.2 2.2 2.2 2.2 2.2 2.2 N2O (t CO2e/h) 134 134 134 134 134 134

Total (t CO2e/h) 7,805 7,805 7,805 7,805 7,805 7,805 Minor incidents per year 0.33 0.33 0.33 0.33 0.33 0.33Hours per incident 0.25 0.25 0.25 0.25 0.25 0.25Major incidents per year 0.20 0.20 0.20 0.20 0.20 0.20Hours per incidents 0.50 0.50 0.50 0.50 0.50 0.50Annual Flaring Emissions

CO2 (t/a) 1,136 1,449 1,449 1,449 1,449 1,449 CH4 (t CO2e/a) 0.33 0.42 0.42 0.42 0.42 0.42N2O (t CO2e/a) 20 25 25 25 25 25

Total (t CO2e/a) 1,156 1,475 1,475 1,475 1,475 1,475 Space Heating Space heating emissions (g/s)

1,072 1,072 1,072 1,072 1,072 1,072

Annual Space Heating Emissions CO2 (t/a) 33,807 33,807 33,807 33,807 33,807 33,807

CH4 (t CO2e/a) 181 181 181 181 181 181 N2O (t CO2e/a) 267 267 267 267 267 267

Total (t CO2e/a) 34,254 34,254 34,254 34,254 34,254 34,254 Total Emissions Total CO2e emissions (t/a) 1,146,567 1,356,261 1,353,517 1,431,559 1,339,924 1,353,933 Emissions from electricity sales

177,925 222,406 222,406 222,406 222,406 222,406

Emissions from production 968,642 1,133,855 1,131,111 1,209,153 1,117,518 1,131,527 Emission Factors Bitumen production (Mbbl/a)

29.2 36.5 36.5 36.5 36.5 36.5

Including electricity sales 39.3 37.2 37.1 39.2 36.7 37.1 Excluding electricity sales 33.2 31.1 31.0 33.1 30.6 31.0

Annual direct emissions 968,642 1,133,855 1,131,111 1,209,153 1,117,518 1,131,527 Annual indirect emissions 177,925 222,406 222,406 222,406 222,406 222,406 Total emissions 1,146,567 1,356,261 1,353,517 1,431,559 1,339,924 1,353,933



Table 9.5-2 Annual Greenhouse Gas Emissions from the Project (cont’d)


Year 2 2018

Year 3 2019

Year 4 2020

Year 5 2021

Years 6-212022–2037

Mine Face Methane Tonnes per day (as methane)

5.64 4.71 3.77 2.84 1.91 0.98

Tonnes per year (as methane)

2,058 1,718 1,378 1,038 697 357

Methane GWP factor 21 21 21 21 21 21 Methane emissions as CO2e (t CO2e/a)

43,227 36,081 28,934 21,788 14,641 7,495

Tailings Methane Tonnes per day (as methane)

14.3 14.3 14.3 14.3 14.3 10.8


5,208 5,208 5,208 5,208 5,208 3,955


109,368 109,368 109,368 109,368 109,368 83,055

Disposal Area Methane Tonnes per day (as methane)

7.55 7.55 7.55 7.55 7.55 5.22


2,755 2,755 2,755 2,755 2,755 1,906


57,861 57,861 57,861 57,861 57,861 40,034

Total Methane Emissions Total non-process methane emissions (t CO2e)

210,456 203,310 196,163 189,017 181,870 130,584

Overall total direct GHG emissions (t CO2e)

1,179,098 1,337,165 1,327,274 1,398,170 1,299,388 1,262,111

Total direct + indirect GHG emissions (t CO2e)

1,357,023 1,559,571 1,549,680 1,620,576 1,521,794 1,484,517

GHG emission intensity (kg CO2e/bbl dilbit) Including electricity sales 46.5 42.7 42.5 44.4 41.7 40.7 Excluding electricity sales

40.4 36.6 36.4 38.3 35.6 34.6



Table 9.5-3 Project Greenhouse Gas Emissions and Proportion of Provincial/National/Global Greenhouse Gas Emissions

Project Greenhouse Gas Emissions Direct + indirect GHG emissions – annual average (t/CO2e/a) 1,493,377 Direct + indirect GHG emissions over life of project (t/CO2e) 31,360,916 Net GHG emissions – annual average (t/CO2e/a)1 1,273,089 Net GHG emissions over life of project (t/CO2e)1 26,734,871 GHG emission intensity based on net (kg CO2e/bbl bitumen) 35.2

Project Proportion of Greenhouse Gas Emissions Annual net as percentage of Alberta GHG emissions2 1% Annual net percentage of Canada GHG emissions3 0.17% Annual net as percentage of global emissions4 0.0038%

NOTES: 1 Net GHG emissions exclude emissions associated with electricity export. 2 Alberta GHG emissions in 2007: 114.4 Mt/CO2e/a (from Alberta Environment). 3 Canada GHG emissions in 2007: 747 Mt/CO2e/a (from Environment Canada). 4 Global GHG emissions: 33,000 Mt/CO2e/a (from Canadian Association of Petroleum Producers).

9.6 Acoustics This section describes the project acoustic emission sources. For results of the acoustic assessment for the Joslyn North Mine Project, see Section 14.9 and Appendix H.

The expected acoustic emissions from the mining equipment are based on standard operating parameters. Acoustic emissions from stationary sources such as the extraction plant, ore preparation plant (OPP) and activities at the mine face were considered to be continuous. Acoustic emissions from mobile mine equipment was based on the quantity, operating efficiency, usability factor, haulage routes, site road speed limits, pit terrain and mine face locations. Acoustic emissions from bird-deterrent cannons were evaluated by estimating the number of shots per cannon per hour during peak use in the ice-free period.

For the overall sound power level and mine equipment acoustic emission sources used in the assessment, see Table 9.6-1. The quantity provided in the table represents values for the mine years 2020 and 2033, years in which the mine equipment quantities are highest and activities are near the receptor locations.

For overall sound power level and other outdoor acoustic emission sources used in the evaluation, see Table 9.6-2.

The sound power level from the extraction plant was determined based on the operations of similar developments. Major extraction plant areas considered in the assessment were:

• froth production plant • froth treatment plant • tailings production • centrifuge plant • water treatment plant • cogeneration plant • substation • tank farm



Table 9.6-1 Mine Equipment Sound Sources

Item

Equipment

Model

2020 Quantity

2020 Fleet Allocation

2033 Quantity


Model Source Type

Sound Power Level1

(dBA) Reference

1 Cable shovel Bucyrus International 495HF

6 • Mine pit (4) • Overburden

prestripping (2) 7

• Mine pit (7x) Area 124 2

2 Hydraulic shovel Hitachi EX8000 3

• Mine pit (2) • Overburden

prestripping (1) 3

• Mine pit (3x) Area 125 2

3 Loader CAT 992G 1

• Overburden stockpile, OPP, maintenance and administration building and extraction plant area

1

• Overburden stockpile, OPP, maintenance and administration building and extraction plant area

Point 113 3

4 Large haul trucks CAT 797 42

• Between mine pit and crusher (30)

• Between mine pit and EDA-C (3)

• Between mine pit and DDA 1 (6)

• Between overburdenprestripping and DDA 1 (3)

30

• Between mine pit and crusher (24)

• Between mine pit and in-pit disposal areas (2)

• Between mine pit and in-pit disposal areas (2)

• Between mine pit and SBA 2 (2)

Line 118 (loaded) 121 (unloaded)

2

5 Haul trucks CAT 777D 2

• Between overburdenprestripping and EDA-C (2) 2

• Between overburden prestripping and in-pit disposal areas (2)

Line 109 4

6 CAT 24H 7 • Along haul road 6 • Along haul road Line 106 4

7 Grader CAT 16H 2 • Between DDA 1 and

Pond 1 (2) 2 • Between DDA 2 and Pond 2 (2) Point 103 4

8 Dozer CAT D11 11

• Mine pit (3) • EDA-C (2) • SBA 1 (2) • DDA 1 (2) • Pond 1 (2)

11

• Mine pit (7) • SBA 1 (2) • Pond 1 (2) Area 116 4



Table 9.6-1 Mine Equipment Sound Sources (cont’d)

Item

Equipment

Model

2020 Quantity


2033 Quantity


Model Source Type

Sound Power Level1

(dBA) Reference

9 CAT D10 4 • EDA-C (1) • SBA 1 (2) • DDA 1 (1)

3 • SBA 1 (1) • In-pit disposal

areas (2) Area 120 4

10

Dozer

CAT D8 2 • Pond 1 (1) • SBA 1 (2)

2 • Pond 2 (2) Area 108 5

11 Rubber-tired dozer CAT 844 3 • Mine pit (3) 3 • Mine pit (3) Area 113 5

12 Hitachi 1100 1 • Mine pit (1) 1 • Mine pit (1) Area 112 5

13 CAT 385B 5 • Mine pit (5) 5 • Mine pit (5) Area 112 5

14 Backhoe

CAT 335 3 • Along haul road (3) 3 • Along haul road (3) Point 108 5

15 Cable reeler CAT 988H 2 • Mine pit (2) 2 • Mine pit (2) Area 118 5

16 Pipe handler CAT 583R 2 • Pond 1 (1) • SBA 1 (1)

2 • Pond 2 (1) and DDA 2 (1) Area 106 6

17 Water truck CAT 793 3 • Along haul road (3) 2 • Along haul road (3) Line 116 6, 7

18 Tow truck CAT 793 1 • Along haul road (1) 1 • Along haul road (1) Line 116 6, 7

19 Float truck CAT 784 1 • Along haul road (1) 1 • Along haul road (1) Line 116 6, 7

20 Scrappers CAT 637G 4 • Overburden

prestripping (4) 4 • Mine pit (2)

Overburden prestripping (2)

Area 116 6

21 Side boom for tailings pipes CAT 583R 2 • Pond 1 (1)

• SBA 1 (1) 2 • Pond 2 (1)

• SBA 2 (1) Area 106 6

22 Compactor CAT 825G 2 • SBA 1 (1) • EDA-C (1)

1 • SBA 1 and in-pit disposal areas (1) Area 110 8, 9

NOTES: 1 Sound power level as per equipment description in source column. 2 Shell 2008. 3 EPCOR 2001. 4 Golder mine equipment noise measurement database. 5 TransAlta 2007. 6 Total 2007.

7 Herring Storer Acoustics 2005. 8 ERM 2008. 9 Hegley Acoustic Consultants 2007. OPP = Ore preparation plant. EDA = External disposal area. DDA = Dedicated disposal area. SBA = Sand beach area.



Table 9.6-2 Extraction Plant and Bird Cannon Noise Sources

Item

Equipment

Quantity

Model Source Type

Sound Power Level1 (dBA)

1 Cogen units - 2 GE 7 EA2 1 Area 113 2 Water treatment/utilities2 1 Area 117 3 Tank farm2 1 Area 113 4 Froth treatment plant2 1 Area 123 5 Froth production plant and tailings2 1 Area 117 6 Ore preparation plant (OPP)2 1 Area 121 7 Centrifuge plant2 1 Area 117 8 River water intake2 2 Point 76 9 Bird-deterrent cannon3 30 Point 123 10 Crusher4 1 Point 118

NOTES: 1 Sound power level as per equipment description in source column. 2 Noise emission based on the sound power level of a similar mine facility. 3 Fraser et al. 1998. 4 Beranek and Ver 1992. dBA = A-weighted decibels.

9.7 References Beranek, L.L. and I.L. Ver. 1992. Prediction of machinery noise. In: Noise and Vibration Control

Engineering: Principals and Applications. John Wiley & Sons Inc. 804 p. Environment Canada.2003. Canada’s Greenhouse Gas Inventory: 1990-2001. EPCOR. 2001. Genesee Generating Station, Phase 3, Noise Impact Assessment. June 2001. ERM (Environmental Resources Management). 2008. Riverside at Tea Gardens – Construction Noise

Assessment. Prepared for Crighton Properties Pty Ltd. July 2008. Fraser, H., K. Fisher and I. Frensch. 1998. Bird Control on Grape and Tender Fruit Farms. Ontario

Ministry of Agriculture and Food. 17 p. Hegley Acoustic Consultants. 2007. Rodney Power Station Inland Road Assessment of Noise.

Prepared for Genesis Energy. Auckland, New Zealand. July 2007. Report No. 7465. Herring Storer Acoustics. 2005. Acoustic Assessment – Golden Pike Development Including Noise Bund

Construction. Prepared for Kalgoorlie Consolidated Gold Mines, June 2005. REF: 4389-4-05033-01v.

Shell (Shell Canada Limited). 2008. Jackpine Mine Expansion and Pierre River Mine Project Responses to ERCB Request for Supplemental Information Request. Prepared by Shell Canada Limited and Golder Associates Ltd. Calgary, Alberta. Submitted April 2008.

Total (Total E&P Canada Ltd.). 2007. Integrated Application for Approval of the Total Upgrader Project. Volume 2: Environmental Impact Assessment, Section 4: Noise. Submitted to Alberta Energy and Utilities Board and Alberta Environment. December 2007.

TransAlta (TransAlta Utilities Corporation). 2007. Highvale Mine Pit 08 Environmental Impact Assessment. Appendix J: Noise Impact Assessment.

U.S. EPA (United States Environmental Protection Agency). 1998. Tier 1 and Tier 3 Emission Standards - Final Rule. Available at: http://epa.gov/nonroad-diesel/regulations.htm#tier2.

U.S. EPA. 2004. Clean Air Nonroad Diesel Rule – Tier 4. Available at: http://epa.gov/nonroad-diesel/regulations.htm#5.



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