Joslyn North Mine Project AI 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 (SO X ) 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 (NO X ) burners. Technology for reducing NO X emissions to approach Alberta Environment interim NO X 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.
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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.
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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
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.
Joslyn North Mine ProjectAI Project Update Section 9: Emission Sources
Joslyn North Mine Project Section 9: Emission Sources AI Project Update
February 2010 TOTAL E&P Joslyn Ltd.Page 9-4
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.
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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)
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.
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Table 9.3-2 Equipment EPA Tier Level and Power Rating EPA Tier Level Compliance for Engines
NOTE: 1 SO2 estimated production at: 0.0263 g/L of diesel fuel; diesel fuel sulphur content: 15 mg/kg maximum.
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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
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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.
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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)
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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
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Table 9.6-1 Mine Equipment Sound Sources
Item
Equipment
Model
2020 Quantity
2020 Fleet Allocation
2033 Quantity
2030 Fleet Allocation
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
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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.
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.
Joslyn North Mine Project Section 9: Emission Sources AI Project Update