APPENDIX 5A SOURCE AND EMISSION INVENTORY · 1. Conventional stacks are defined by location, base elevation, stack height, stack diameter, gas exit velocity, gas exit temperature,

Volume 2: Environmental and Sturgeon Upgrader ProjectSocio-economic Impact Assessment Appendix 5A: Source & Emission Inventory

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APPENDIX 5A SOURCE AND EMISSION INVENTORY

Sturgeon Upgrader Project Volume 2: Environmental andAppendix 5A: Source & Emission Inventory Socio-economic Impact Assessment

December 2006 Page 5A-2


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5A.1 Introduction The Project will be located in an airshed that is shared by other industrial and residential users. In order to assess the air quality effects associated with the Project, it is necessary to identify and document other industrial and non-industrial emission sources. This section identifies and characterizes emission sources in the vicinity of the Project site.

The Project emissions are presented for the Phase 1 and Phase 2/3 development scenarios. The other industrial source information is presented for a Base Case (existing and approved operations) and for a Future Case (Base Case plus disclosed but not yet approved operations).

5A.2 Approach

5A.2.1 General Considerations The preparation of a source and emission inventory involves the systematic identification of sources that discharge gaseous or particulate emissions into the atmosphere, and the characterization of these emission sources in terms of emission type, source type and emission magnitude. The source and emission inventory considers current and future sources. The following items provide an overview of the approach that was adopted for estimating emissions for the Sturgeon Upgrader: • Source and emission inventories for the region have been provided in recently filed

regulatory applications for the BA Energy Heartland Upgrader, the Shell Scotford Upgrader Expansion and the North West Upgrading Inc. North West Upgrader Project. Emission information for these and other projects were documented in the appendices of the respective applications and served as the basis for the emission inventory used for the this assessment. The information presented in this assessment is also sufficiently detailed so that it can be used as a basis for future assessments.

• For the purposes of preparing a source and emission inventory for industrial sources, a nominal 50 x 50 km area centered on the Project site was selected. The 50 x 50 km area is similar to the areas considered for the BA Energy, Shell Scotford and North West Upgrader assessments.

• Industrial facility operators were provided the opportunity to review and update the emission profiles provided in the recent assessments. The communication was undertaken by contacting representatives for the industrial facilities in the region.

• Emission sources types can be described as follows:

1. Conventional stacks are defined by location, base elevation, stack height, stack diameter, gas exit velocity, gas exit temperature, and contaminant emission rate. These stacks typically operate on a continuous basis with relatively constant emission rates.

2. Flare stacks typically discharge low volumes of gas to the atmosphere under normal operating conditions. Under plant start-up, shut-down, upset or emergency conditions, these stacks can discharge high volumes of gas to the atmosphere. Under these latter conditions, the release durations tend to be relatively short (approximately one hour or less) and infrequent (typically one event per year). The composition and flow rates of the gas streams to the flare are required to characterize the flare stacks. Conventional stack parameters were used to characterize the flare stacks once adjustments were made according to EUB Directive 60.



3. Fugitive emissions result from small leaks that while individually very small, can collectively be substantial for large, complex facilities. These leaks include pipeline flanges, valve packing, rotating seals, vents, and drains. Fugitive emissions are typically defined as area sources resulting from an individual process area or from an entire facility.

4. Community emission sources include traffic from local roadways and highways, and heating units used in residential and commercial buildings. Estimates of these emissions were obtained from emission inventory data for 2000 from Environment Canada.

• Combustion sources produce trace compounds such as SO2, NOx, CO, and PM2.5 as well as various VOC, TRS, and PAH compounds. Fugitive emission sources produce VOC and TRS compounds.

• Information for existing facilities can be obtained from measurements, and information for future sources can be obtained from a combination of extrapolation, engineering mass balance considerations, and process-specific emission factors. Extensive use of process-specific emission factors was used to estimate VOC and PAH emission for combustion and fugitive sources.

• This assessment focused on chemical compounds or chemical compound groups that are expected to be emitted in meaningful quantities from the Project.

• In some cases, there can be a considerable difference between normal emissions and maximum approved emissions for a given facility. The following are noted relative to this difference:

1. This assessment has the primary focus to evaluate the implication of the Project on local and regional air quality. For this reason; average, maximum and upset emission profiles specific to the Project are evaluated.

2. Other facilities have varying maximum approved emission rates for SO2 and for NOx. There can be a considerable difference between the maximum approved and actual values, especially for SO2. For non-Sturgeon Upgrader facilities, the average SO2 emission rates are used as it is unlikely that all facilities will be emitting at maximum approved rates simultaneously. The maximum approved rates are typically applicable to short term periods and are often expressed on a t/h basis. For NOx emissions, the assumed emission rates are based on those provided by the operators.

• All spatial information characterizing the locations of the emission sources are referenced to the UTM NAD 83 coordinate system.

The source and emission inventory preparation for this assessment focused on characterizing the Project’s emission sources and other sources in the region.

5A.3 Summary

5A.3.1 Study Area Industrial Facilities Figure 5A-1 identifies the major industrial emission sources within the 50 x 50 km airshed that were included in the Sturgeon evaluation. Specifically, industrial emissions within a nominal 20 to 25 km radius of the Project site were included; this is consistent with other similar assessments for the Fort Saskatchewan area (e.g., North West Upgrading Inc. 2006; Shell Canada Limited 2005; BA Energy Incorporated 2004). As the focus was on the FAP area emissions, industrial sources from the East Edmonton industrial area were not included.


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Table 5A-1 identifies the industrial facilities and the status relative to existing, approved or planned status. In this context, existing refers to a facility that is currently operating, approved refers to a facility that has regulatory approval but is not yet operating, and planned refers to a facility that is proposed but does not yet have regulatory approval.

Table 5A-1: Identification and Status of Industrial Emission Sources in the Air Quality Assessment Regional Study Area

Status

Operator Facility Existing

Approved but not

yet Operating

Planned but not

Approved Access Pipeline Redwater Trim Blending Facility Agrium Products Fort Saskatchewan Fertilizer Plant Agrium Products Redwater Fertilizer Plant Air Liquide Canada Scotford Cogeneration Power Plant ARC Resources Redwater Gas Conservation Plant ATCO Midstream Fort Saskatchewan Sour Gas Plant Aux Sable Canada Heartland Offgas Project BA Energy Heartland Bitumen Upgrader BP Canada Energy Fort Saskatchewan Fractionation Plant Bunge Canada Fort Sask. Oilseed Processing Plant Canexus Chemicals Canada Bruderheim Sodium Chlorate Plant CE Alberta BioClean Fort Saskatchewan Chemical Plant Degussa Canada Gibbons Hydrogen Peroxide Plant Dow Chemical Canada Fort Saskatchewan Chemical Plant ERCO Worldwide Bruderheim Sodium Chlorate Plant HAZCO Environmental Services Bruderheim Sulphur Forming Facility

Keyera Energy Fort Saskatchewan Fractionation Facility Marsulex Fort Saskatchewan Chemical Plant Newalta Corporation Redwater Disposal Facility North West Upgrading North West Upgrader Project FHELP Sturgeon Upgrader Project Prospec Chemicals Fort Saskatchewan Xanthate Plant Provident Energy Redwater Fractionation Facility Redwater Water Disposal Company Redwater Waste Disposal Facility Shell Canada Scotford Bitumen Upgrader E Shell Canada Products Scotford Oil Refinery Shell Chemicals Canada Scotford Styrene & MEG Plant Sherritt International Corporation Fort Saskatchewan Fertilizer Plant E Synenco Energy Northern Lights Upgrader Project

Terasen Pipelines Heartland Storage Tank Terminal

TransAlta Cogeneration Fort Sask. Cogeneration Power Plant TransCanada Energy Redwater Cogeneration Power Plant

NOTE: E refers to an expanded plant that had not yet received approval at the time of the assessment.



5A.3.2 Project Emissions A two-phased development is proposed for the Project. The bitumen processing capacities associated with Phase 1 and Phase 2/3 are 165,000 bbl/d and 340,000 bbl/d, respectively. In Phase 1, hydrogen will be produced using steam reforming of natural gas. In Phase 2/3, gasification technology will be used to produce hydrogen from asphaltene and/or petroleum coke.

Table 5A-2 provides a summary of total stack emissions associated with both phases of the Project. The SO2 emissions are provided for expected maximum (t/h and t/d) emission rates and average (t/d) emission rates to coincide with the regulatory process. In general, the Phase 2/3 emissions tend to be 2 to 3 times those associated with Phase 1. More details regarding the individual stack sources, potential upset flaring sources, and fugitive sources associated with the Project (Phases 1 and 2/3) are provided in Section 4.0.

Table 5A-2: Summary of Emissions Associated with the Project Substance (t/d) -

Phase 1 Conventional

Stacks Flare

Stacks Storage Tanks Process Areas Total

SO2 (1-h maximum) (t/h) 0.66 0.0003 0.0 0.0 0.66 SO2 (24-h maximum) (t/d) 11.96 0.007 0.0 0.0 11.96 SO2 (annual average) (t/d) 7.96 0.007 0.0 0.0 7.96 NOx (t/d) 4.72 0.009 0.0 0.0 4.73 CO (t/d) 1.18 0.011 0.0 0.0 1.192 VOC/PAH (t/d) 0.39 0.019 0.219 0.638 1.27 PM2.5 (t/d) 0.136 0.0 0.0 0.0 0.136 TRS/H2S (t/d) 0.044 0.0 0.0015 0.024 0.07 H2O (t/d) 5929 13.7 0.0 0.0 5942 CO2 (t/d) 7998 17.9 0.0 0.0 8016 Methane (t/d) 0.0 0.0 0.0695 0.37 0.44

Substance (t/d) - Phase 2/3

Conventional Stacks

Flare Stacks Storage Tanks

Process Areas Total

SO2 (1-h maximum) (t/h) 1.18 0.0004 0.0 0.0 1.18 SO2 (24-h maximum) (t/d) 23.71 0.0097 0.0 0.0 23.72 SO2 (annual average) (t/d) 10.11 0.0097 0.0 0.0 10.12 NOx (t/d) 14.36 0.0 0.0 0.0 14.36 CO (t/d) 9.49 0.0113 0.0 0.0 9.50 VOC/PAH (t/d) 0.96 0.0137 0.407 1.098 2.483 PM2.5 (t/d) 0.439 0.0232 0.0 0.0 0.463 TRS/H2S (t/d) 0.154 0.0 0.0024 0.0362 0.193 H2O (t/d) 19835 17.0 0.0 0.0 19852 CO2 (t/d) 24955 22.2 0.0 0.0 24977 Methane (t/d) 0.0 0.0 0.12 0.64 0.76

NOTE: Flare stack emissions reflect normal operations.


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5A.3.3 Other Industrial Source Stack Emissions Table 5A-3 provides a summary of existing and approved industrial stack emissions. The following are noted:

• There are two main industrial sources of SO2 emissions; the existing Scotford Upgrader (28.07 t/d) and the approved BA Energy Heartland Upgrader (28.10 t/d). These two sources account for about 80 percent of the regional SO2 emissions.

• The regional industrial NOx emissions are 50.85 t/d. The major NOx emitting facilities are the Dow Chemical Fort Saskatchewan Plant (11.85 t/d), the Sherritt Fort Saskatchewan Complex (7.28 t/d), the Shell Scotford Upgrader (5.73 t/d), the Agrium Redwater Fertilizer Plant (5.09 t/d) and the BA Energy Heartland Upgrader (4.70 t/d).

• The regional industrial CO emissions are 21.89 t/d. The largest regional source is the Dow Chemical Fort Saskatchewan Plant (6.31 t/d).

• Regional PM2.5 emissions are 3.39 t/d, with the largest source being the Dow Chemical Fort Saskatchewan Plant (1.10 t/d).

• Regional VOC emissions are 5.83 t/d, with the largest regional source being the Keyera Energy Fort Saskatchewan Fractionation Facility (1.53 t/d).

• Regional H2S emissions are 0.69 t/d. Approximately 70 percent of H2S emissions are from BA Energy Heartland Upgrader (0.47 t/d).

Table 5A-4 provides a summary of emission for a future planned scenario that includes the existing and approved facilities in Table 5A-3 as well as future planned facilities that have not yet received approval. The following are noted relative to the emission information:

• The regional SO2 emissions are projected to increase from 71.38 to 148.95 t/d. The major new contributions are the Project (23.72 t/d), the North West Upgrader (26.28 t/d) and the Synenco Upgrader (31.08 t/d).

• The regional NOx emissions are projected to increase from 50.85 to 97.60 t/d. The major new contributions are the Project (14.36 t/d), the North West Upgrader (19.42 t/d) and the Synenco Upgrader (9.39 t/d).

• The regional CO emissions are projected to increase from 21.89 to 45.98 t/d. The major new contributions are the Project (9.50 t/d) and the Synenco Upgrader (9.57 t/d).

• The regional PM2.5 emissions are projected to increase from 3.39 to 5.84 t/d. The major new contributions are the Project (0.46 t/d), the North West Upgrader (1.16 t/d) and the Synenco Upgrader (0.43 t/d).

• The regional VOC/PAH emissions are projected to increase from 5.83 to 11.07 t/d. The major new contributions are the Project (0.98 t/d), the North West Upgrader (1.14 t/d) and the Synenco Upgrader (2.17 t/d).

• The regional TRS/H2S emissions are projected to increase from 0.69 to 0.95 t/d. The major new contribution is the Project (0.154 t/d).

In summary, the future development scenario will lead to a doubling of the industrial emissions in the region. More details regarding the individual stack sources, potential upset flaring sources, and fugitive sources associated with the non FHELP industrial sources are provided in Section 5.0.



5A.3.4 Other Industrial Source Fugitive Emissions Table 5A-6 provides a summary of fugitive emissions that are available for industrial sources in the area. The following are noted:

• The regional PM2.5 emissions remain unchanged. • The regional VOC/PAH emissions are projected to increase by a factor of two. • The regional TRS/H2S emissions are projected to increase by a factor of two.

5A.3.5 Community Emissions Community or non-industrial sources include mobile sources (e.g., roadway, highway, railroads, off-road vehicles and aircraft) and non-mobile sources (e.g., residential and commercial fuel use). These sources are local (e.g., local roadways and the community of Fort Saskatchewan) and distant (e.g., the City of Edmonton). Table 5A-7 provides a summary of these sources and associated emission rates for the following areas:

• The primary 50 x 50 km assessment area centered on the Project site. This area includes the Community of Fort Saskatchewan and the northeast portion of the City of Edmonton.

• The extended 100 by 100 km assessment area centered on the Project site. This area includes a large portion of the City of Edmonton.

• Census Division 11 that includes the Fort Saskatchewan area, the City of Edmonton and the Wabamun area. The emission values represent 2000 emissions for industrial and non-industrial sources.

The information in Table 5A-6 indicates that community emissions are substantial sources of emissions. More details regarding these emissions sources are provided in Section 6.0.

5A.3.6 Regional Emission Summary Table 5A-8 provides a summary of the total emissions in the primary assessment area (i.e., the 50 x 50 km region) for the Base, Application and Future cases.


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335 340 345 350 355 360 365 370 375 380UTM kmE

5945

5950

5955

5960

5965

5970

5975

5980

5985

5990

UTM

km

N

0 5 10 15

Scale (km)

Project Development Area

Redwater Water Disposal

NewAltaARC Resources



HAZCOCanexus Chemicals

ERCO

Synenco

North West UpgradingAgrium Redwater

Terasen Pipelines

Aux SableBA EnergyAccess Pipeline

Petro-Canada

TransCanadaProvident

Shell ChemicalsAir LiquideShell Upgrader

Shell Refinery

BP CanadaCE Alberta

Dow Chemical

Keyera EnergyProspec Chemicals

TransAlta

Agrium Ft. Sask

Marsulex Inc.

ATCO Midstream

SherrittBunge Canada

Degussa

Figure 5A-1: Industrial Emission Sources in the Air Quality Assessment Regional Study Area



Table 5A-3: Summary of Emissions (t/d) Associated with Existing and Approved Emission Sources (Base Case – Stacks only)

Emission Rate (t/d)

Operator Facility SO2

(Peak) SO2

(Ave) NOx

(Peak) NOx

(Ave) CO PM2.5 VOC H2S Agrium Products Fort Saskatchewan Fertilizer Plant 0.00 0.00 3.08 2.32 0.68 0.00 0.04 0.00 Agrium Products Redwater Fertilizer Plant 7.66 4.39 5.09 3.27 1.34 0.42 0.04 0.00 Air Liquide Canada Scotford Cogeneration Power Plant 0.00 0.00 2.21 0.47 0.91 0.08 0.20 0.00 ARC Resources Redwater Gas Conservation Plant 0.59 0.59 1.07 0.75 1.83 0.01 0.02 0.0062 ATCO Midstream Fort Saskatchewan Sour Gas Plant 0.00 0.00 0.02 0.02 0.01 0.00 0.00 0.00 BA Energy Heartland Bitumen Upgrader 28.10 28.10 4.70 4.70 1.56 0.47 0.26 0.47 BP Canada Energy Fort Saskatchewan Fractionation Plant 1.04 1.04 0.64 0.32 0.54 0.02 0.01 0.00 Bunge Canada Fort Sask. Oilseed Processing Plant 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Canexus Chemicals Canada Bruderheim Sodium Chlorate Plant 0.00 0.00 0.02 0.02 0.01 0.00 0.00 0.00 CE Alberta BioClean Fort Saskatchewan Chemical Plant 0.03 0.03 1.58 1.58 0.99 0.11 0.06 0.00 Degussa Canada Gibbons Hydrogen Peroxide Plant 0.00 0.00 0.05 0.05 0.01 0.01 0.00 0.00 Dow Chemical Canada Fort Saskatchewan Chemical Plant 0.60 0.13 11.85 3.57 6.31 1.10 0.37 0.00 ERCO Worldwide Bruderheim Sodium Chlorate Plant 0.00 0.00 0.01 0.01 0.01 0.02 0.00 0.00 Keyera Energy Fort Saskatchewan Fractionation Facility 1.90 0.45 0.84 0.13 0.34 0.05 0.02 0.0002 Marsulex Fort Saskatchewan Chemical Plant 0.99 0.99 0.00 0.00 0.00 0.00 0.00 0.00 Newalta Corporation Redwater Disposal Facility 0.00 0.00 0.02 0.02 0.02 0.00 0.00 0.00 Prospec Chemicals Fort Saskatchewan Xanthate Plant 0.16 0.08 0.00 0.00 0.05 0.00 0.00 0.00 Provident Energy Redwater Fractionation Facility 0.77 0.74 0.10 0.07 0.08 0.01 0.01 0.00 Redwater Water Disposal Company Redwater Waste Disposal Facility 0.29 0.29 0.00 0.00 0.00 0.00 0.00 0.00 Shell Canada Scotford Bitumen Upgrader 28.07 19.05 5.73 2.54 2.29 0.34 0.19 0.1763 Shell Canada Products Scotford Oil Refinery 0.12 0.12 2.73 2.19 1.20 0.35 0.15 0.00 Shell Chemicals Canada Scotford Styrene & MEG Plant 0.00 0.00 1.43 1.15 1.01 0.20 0.30 0.00 Sherritt International Corporation Fort Saskatchewan Fertilizer Plant 1.04 1.04 7.28 7.28 1.87 0.15 0.24 0.00 TransAlta Cogeneration Fort Sask. Cogeneration Power Plant 0.03 0.03 1.87 0.23 0.69 0.02 0.02 0.00 TransCanada Energy Redwater Cogeneration Power Plant 0.00 0.00 0.52 0.34 0.12 0.01 0.00 0.00 Total (t/d) 71.38 57.06 50.85 31.03 21.89 3.36 1.94 0.65


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Table 5A-4: Summary of Emissions Associated with Base Case and Planned Emission Sources (Future Case - Stacks only)

Emission Rate (t/d)

Operator Facility SO2

(Peak) SO2

(Ave) NOx

(Peak) NOx

(Ave) CO PM2.5 VOC H2S Access Pipeline Redwater Trim Blending Facility 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Agrium Products Fort Saskatchewan Fertilizer Plant 0.00 0.00 3.08 2.32 0.68 0.00 0.04 0.00 Agrium Products Redwater Fertilizer Plant 7.66 4.39 5.09 3.27 1.34 0.42 0.04 0.00 Air Liquide Canada Scotford Cogeneration Power Plant 0.00 0.00 2.21 0.47 0.91 0.08 0.20 0.00 ARC Resources Redwater Gas Conservation Plant 0.59 0.59 1.07 0.75 1.83 0.01 0.02 0.0062 ATCO Midstream Fort Saskatchewan Sour Gas Plant 0.00 0.00 0.02 0.02 0.01 0.00 0.00 0.00 Aux Sable Canada Heartland Offgas Project 0.00 0.00 0.13 0.13 0.11 0.01 0.01 0.00 BA Energy Heartland Bitumen Upgrader 28.10 28.10 4.70 4.70 1.56 0.47 0.26 0.47 BP Canada Energy Fort Saskatchewan Fractionation Plant 1.04 1.04 0.64 0.32 0.54 0.02 0.01 0.00 Bunge Canada Fort Sask. Oilseed Processing Plant 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Canexus Chemicals Canada Bruderheim Sodium Chlorate Plant 0.00 0.00 0.02 0.02 0.01 0.00 0.00 0.00 CE Alberta BioClean Fort Saskatchewan Chemical Plant 0.03 0.03 1.58 1.58 0.99 0.11 0.06 0.00 Degussa Canada Gibbons Hydrogen Peroxide Plant 0.00 0.00 0.05 0.05 0.01 0.01 0.00 0.00 Dow Chemical Canada Fort Saskatchewan Chemical Plant 0.60 0.13 11.85 3.57 6.31 1.10 0.37 0.00 ERCO Worldwide Bruderheim Sodium Chlorate Plant 0.00 0.00 0.01 0.01 0.01 0.02 0.00 0.00 HAZCO Environmental Services Bruderheim Sulphur Forming Facility 0.00 0.00 0.01 0.01 0.01 0.02 0.00 0.00 Keyera Energy Fort Saskatchewan Fractionation Facility 1.90 0.45 0.84 0.13 0.34 0.05 0.02 0.0002 Marsulex Fort Saskatchewan Chemical Plant 0.99 0.99 0.00 0.00 0.00 0.00 0.00 0.00 Newalta Corporation Redwater Disposal Facility 0.00 0.00 0.02 0.02 0.02 0.00 0.00 0.00 North West Upgrading North West Upgrader Project 26.28 26.28 19.42 19.42 0.28 1.16 0.84 0.01 FHELP Sturgeon Upgrader Project (Phase 2/3) 23.72 10.12 14.36 14.36 9.50 0.46 0.978 0.154 Prospec Chemicals Fort Saskatchewan Xanthate Plant 0.16 0.08 0.00 0.00 0.05 0.00 0.00 0.00004 Provident Energy Redwater Fractionation Facility 0.77 0.74 0.10 0.07 0.08 0.01 0.01 0.00 Redwater Water Disposal Company Redwater Waste Disposal Facility 0.29 0.29 0.00 0.00 0.00 0.00 0.00 0.00 Shell Canada Scotford Bitumen Upgrader 24.55 24.55 8.82 5.48 6.71 0.34 0.19 0.1763 Shell Canada Products Scotford Oil Refinery 0.12 0.12 2.73 2.19 1.20 0.35 0.15 0.00 Shell Chemicals Canada Scotford Styrene & MEG Plant 0.00 0.00 1.43 1.15 1.01 0.20 0.30 0.00 Sherritt International Corporation Fort Saskatchewan Fertilizer Plant 1.04 1.04 7.64 7.64 2.09 0.16 0.25 0.00 Synenco Energy Northern Lights Upgrader Project 31.08 31.08 9.39 9.39 9.57 0.43 1.06 0.00 Terasen Pipelines Heartland Storage Tank Terminal 0.00 0.00 0.00 0.00 0.00 0.00 0.11 0.0001 TransAlta Cogeneration Fort Sask. Cogeneration Power Plant 0.03 0.03 1.87 0.23 0.69 0.00 0.00 0.00 TransCanada Energy Redwater Cogeneration Power Plant 0.00 0.00 0.52 0.34 0.12 0.00 0.00 0.00 Total (t/d) 148.95 130.05 97.6 77.64 45.98 5.43 4.92 0.82



Table 5A-5: Comparison of SO2 Emissions for Facilities in the Regional Study Area SO2 Emission

Alberta Approval NPRI

Database

Operator Facility 1-h (t/h)

24-h (t/d)

2004 (t/d)

2005 (t/d)

Value Used(t/d)

Agrium Products Redwater Fertilizer Plant 0.477 - 4.87 4.4 7.66 ARC Resources Redwater Gas Conservation Plant 0.14 2.40 0.58 0.58 0.59 BA Energy Heartland Bitumen Upgrader 1.40 28.10 - - 28.10 BP Canada Energy Fort Saskatchewan Fractionation Plant - 0.89 - - 1.04 CE Alberta BioClean Fort Saskatchewan Chemical Plant - - - - 0.03 Dow Chemical Canada Fort Saskatchewan Chemical Plant - - 0.14 0.13 0.60 Keyera Energy Fort Saskatchewan Fractionation Facility - 2.40 0.41 0.45 1.90 Marsulex Fort Saskatchewan Chemical Plant 0.08 - 0.716 0.987 0.99 North West Upgrading North West Upgrader Project - - - - 26.28 FHELP Sturgeon Upgrader (Phase 2/3) 1.18 23.72 - - 23.72 Prospec Chemicals Fort Saskatchewan Xanthate Plant - - 0.08 0.08 0.16 Provident Energy Redwater Fractionation Facility - 1.98 0.63 0.74 0.77 Redwater Water Disposal Company Redwater Waste Disposal Facility - - 0.50 0.29 0.29

Scotford Bitumen Upgrader (Existing/Approved) 2.0 28.00 18.14 18.95 28.07 Shell Canada

Scotford Bitumen Upgrader (Planned) - - - - 24.55 Shell Canada Products Scotford Oil Refinery - - 0.19 0.27 0.12

Fort Saskatchewan Fertilizer Plant (Existing/Approved) 0.117 - 0.89 1.05 1.04 Sherritt International Corporation

Fort Saskatchewan Fertilizer Plant (Planned) - - - - 1.04 Synenco Energy Northern Lights Upgrader Project - - - - 31.08 TransAlta Cogeneration Fort Sask. Cogeneration Power Plant - - - - 0.03 Total (Base Case) - - 27.15 27.93 71.38 Total (Future Case) - - - - 148.95

NOTE: For the FHELP Sturgeon Upgrader, the hourly, daily and annual average expected SO2 emission values were evaluated.


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Table 5A-6: Summary of Available Fugitive Emissions for Industrial Sources in the Region Base Case Future Case

Emission Rate (t/d) Operator Facility PM2.5 VOC H2S PM2.5 VOC H2S

Access Pipeline Redwater Trim Blending Facility 0.0 0.0 0.0 0.00 0.024 0.0000011 Agrium Products Fort Saskatchewan Fertilizer Plant 0.00 0.0362 0.00 0.00 0.0362 0.00 Agrium Products Redwater Fertilizer Plant 0.00 0.586 0.00 0.00 0.586 0.00 Air Liquide Canada Scotford Cogeneration Power Plant N/A N/A N/A N/A N/A N/A ARC Resources Redwater Gas Conservation Plant 0.00 0.208 0.0028 0.00 0.208 0.0028 ATCO Midstream Fort Saskatchewan Sour Gas Plant N/A N/A N/A N/A N/A N/A Aux Sable Canada Heartland Offgas Project 0.0 0.0 0.0 N/A N/A N/A BA Energy Heartland Bitumen Upgrader 0.00 0.082 0.0067 0.00 0.082 0.0067 BP Canada Energy Fort Saskatchewan Fractionation Plant 0.00 0.238 0.00 0.00 0.238 0.00 Bunge Canada Fort Sask. Oilseed Processing Plant 0.039 0.0226 0.00 0.039 0.0226 0.00 Canexus Chemicals Canada Bruderheim Sodium Chlorate Plant N/A N/A N/A N/A N/A N/A CE Alberta BioClean Fort Saskatchewan Chemical Plant N/A N/A N/A N/A N/A N/A Degussa Canada Gibbons Hydrogen Peroxide Plant N/A N/A N/A N/A N/A N/A Dow Chemical Canada Fort Saskatchewan Chemical Plant 0.00 0.157 0.0003 0.00 0.157 0.0003 ERCO Worldwide Bruderheim Sodium Chlorate Plant N/A N/A N/A N/A N/A N/A HAZCO Environmental Services Bruderheim Sulphur Forming Facility 0.0 0.0 0.0 N/A N/A N/A Keyera Energy Fort Saskatchewan Fractionation Facility 0.00 1.53 0.0004 0.00 1.53 0.0004 Marsulex Fort Saskatchewan Chemical Plant 0.00 0.00 0.00004 0.00 0.00 0.00004 Newalta Corporation Redwater Disposal Facility N/A N/A N/A N/A N/A N/A North West Upgrading North West Upgrader Project 0.0 0.0 0.0 0.00 0.301 0.00315 FHELP Sturgeon Upgrader Project 0.00 0.00 0.00 0.00 1.505 0.0386 Prospec Chemicals Fort Saskatchewan Xanthate Plant N/A N/A N/A N/A N/A N/A Provident Energy Redwater Fractionation Facility 0.00 0.071 0.00 0.00 0.071 0.00 Redwater Water Disposal Company Redwater Waste Disposal Facility N/A N/A N/A N/A N/A N/A Shell Canada Scotford Bitumen Upgrader 0.00 0.66 0.031 0.00 1.23 0.033 Shell Canada Products Scotford Oil Refinery 0.00 0.262 0.00266 0.00 0.262 0.00266 Shell Chemicals Canada Scotford Styrene & MEG Plant 0.00 0.07 0.00 0.00 0.07 0.00 Sherritt International Corporation Fort Saskatchewan Fertilizer Plant N/A N/A N/A N/A N/A N/A Synenco Energy Northern Lights Upgrader Project 0.0 0.0 0.0 0.00 1.11 0.00777 Terasen Pipelines Heartland Storage Tank Terminal 0.0 0.0 0.0 0.00 0.105 0.00011 TransAlta Cogeneration Fort Sask. Cogeneration Power Plant N/A N/A N/A N/A N/A N/A TransCanada Energy Redwater Cogeneration Power Plant N/A N/A N/A N/A N/A N/A Total (t/d) 0.039 3.92 0.0444 0.039 7.54 0.096

NOTES: N/A: Not Available



Table 5A-7: Summary of Community Source Emissions in the Regional Study Area

Emission Source (t/d)

50 x 50 km Assessment Area (For comparative

purposes)

100 x 100 km Extended Area

(Used in the Modelling)

Census Division 11 For comparative

purposes SO2 2.97 27.42 282 NOx 24.72 261.53 445 CO 84.72 905.42 557

PM2.5 6.62 47.11 72 VOC 36.95 348.51 366 NH3 0.0 0.0 109

NOTE: The Census Division 11 values include industrial and non-industrial emissions.

Table 5A-8: Summary of Emissions in the Regional Study Area SO2 (t/d) Base Case Application Case Future Case

Sturgeon Upgrader (Phase 2/3) 0.0 23.72 23.72 Other Industrial Sources – Stacks 71.38 71.38 125.23 Other Industrial Sources – Fugitive 0.0 0.0 0.0 Community (50 x 50 km) 2.97 2.97 2.97 Total 74.35 98.07 (+32%) 151.92 (+104%)

NOX (t/d) Base Case Application Case Future Case Sturgeon Upgrader (Phase 2/3) 0.0 14.36 14.36 Other Industrial Sources – Stacks 50.85 50.85 83.24 Other Industrial Sources – Fugitive 0.0 0.0 0.0 Community (50 x 50 km) 24.72 24.72 24.72 Total 75.57 89.93 (+19%) 122.32 (+62%)

CO (t/d) Base Case Application Case Future Case Sturgeon Upgrader (Phase 2/3) 0.0 9.50 9.50 Other Industrial Sources – Stacks 21.89 21.89 36.48 Other Industrial Sources – Fugitive 0.0 0.0 0.0 Community (50 x 50 km) 84.72 84.72 84.72 Total 106.61 116.11 (+9%) 130.70 (+23%)

PM2.5 (t/d) Base Case Application Case Future Case Sturgeon Upgrader (Phase 2/3) 0.0 0.46 0.46 Other Industrial Sources – Stacks 3.36 3.36 4.97 Other Industrial Sources – Fugitive 0.039 0.039 0.039 Community (50 x 50 km) 6.62 6.62 6.62 Total 10.02 10.48 (+4.6%) 12.09 (+21%)


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Table 5A-8: Summary of Emissions in the Regional Study Area (cont’d) VOC/PAH (t/d) Base Case Application Case Future Case

Sturgeon Upgrader (Phase 2/3) 0.0 2.48 2.48 Other Industrial Sources – Stacks 1.94 1.94 3.94 Other Industrial Sources – Fugitive 3.92 3.92 6.03 Community (50 x 50 km) 36.95 36.95 36.95 Total 42.81 45.29 (+6%) 49.4 (+15%)

H2S (t/d) Base Case Application Case Future Case Sturgeon Upgrader (Phase 2/3) 0.0 0.19 0.19 Other Industrial Sources – Stacks 0.65 0.65 0.67 Other Industrial Sources – Fugitive 0.044 0.044 0.057 Community (50 x 50 km) 0.0 0.0 0.0 Total 0.69 0.88 (+28%) 0.92 (+33%)

5A.4 Project The Jacques Whitford-AXYS air quality team worked closely with Petro-Canada Oil Sands Inc. (PCOSI) engineering staff to define the emission parameters required to characterize air quality due to the operation of the Upgrader. The detailed engineering was undertaken by Fluor Canada Ltd. and Clearstone Engineering Ltd. developed a fugitive emission profile for the Upgrader.

The following sections present the Phase 1 and Phase 2/3 emission profile for the Upgrader. While most of the identified facilities operate on a continuous basis, there are a few facilities that are only used for start up or maintenance operations. In order to be conservative, the facilities are assumed to operate continuously. Upset or emergency conditions were evaluated separately and in isolation due to the associated short-term and intermittent values.

For the purposes of assessment, the Project’s emission sources were grouped into the following categories:

• conventional stacks • flare stacks • storage tanks • process areas • cooling towers

The conventional stacks are the main sources of emissions from the Upgrader, with flare stacks being used primarily for plant maintenance, fugitive or emergency operations. Emissions from storage tanks and process areas are classified as fugitive emissions.



5A.4.1 Phase 1 Development

5A.4.1.1 Stack Emissions Table 5A-9 provides a summary of the emission sources associated with the Phase 1 conventional (12) and flare (4) stacks. The stack parameters were provided by Fluor Canada and the following comments can be made relative to the parameters and emissions associated with the conventional stacks:

• The heaters, furnaces and boilers are fired with a fuel gas whose composition is given in Table 5A-10. This fuel gas is comprised of 39 percent methane, 22 percent ethane, and 20 percent hydrogen.

• The SO2 emissions associated with heaters, furnaces and boilers are based on fuel gas with an H2S content of 30 ppm, a COS content of 73 ppm, and an RSH content of 265 ppm.

• The NOx emissions associated with heaters, furnaces and boilers are based on an NOx flue gas concentration of 40 ppm for units rated less than 105 GJ/h (100 MMBtu/h) and on an NOx flue gas concentration of 60 ppm for units rated more than 105 GJ/h. For the SMR furnace, the NOx concentration in the exhaust was assumed to be 75 ppm.

• The CO emissions associated with heaters, furnaces and boilers are based on CO flue gas concentration of 15 ppm.

• PM2.5, VOC, and PAH emissions are based on the application of US EPA and CARB emission factors. These are identified in Table 5A-11. The selected compound groupings are based on classification by the Human Health and Risk Assessment (HHRA) team to reflect potential human health effects.

• The stack exit temperatures and velocities are the minimum expected values and are selected to be conservative.

• The three utility boilers (650MF1, 650MF2, and 650MF3) are expected to be used one week every two years at maximum capacity of 583.5 GJ/h each. The rest of the time, they will be operating at a reduced capacity (i.e., ~233.4 GJ/h each). These boilers were assumed to operate on a continuous basis at maximum capacity for the purposes of this assessment to be conservative.

Tables 5A-12 and 5A-13 provide the emission parameters for the Phase 1 furnace, heater, and boiler stacks.

The thermal oxidizer services the sulphur recovery unit (SRU) and is the largest SO2 emission at the Upgrader. Table 5A-14 provides a summary of the thermal oxidizer parameters and emissions. The following are noted with respect to these parameters:

• The average SO2 emission rate of 6.0 t/d is based on an annual average sulphur recovery of 99.7 percent.

• The daily average SO2 emission rate of 10 t/d is based on a quarterly average sulphur recovery of 99.5 percent. While this lower quarterly average efficiency represents potential variability associated with the SRU, there is an expectation that the SRU will perform better than average for the other three quarters to ensure the more stringent annual sulphur recovery is maintained.


December 2006

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• The maximum hourly average value is based on the assumption that hour-by-hour variation of the SRU can lead to a maximum SO2 emission rate that is 1.4 times the equivalent daily average emission rate. The maximum hourly average SO2 emission is therefore 0.583 t/h (= [10 t /24 h] x 1.4 = 0.417 t/h x 1.4).

• The total reduced sulphur (TRS) compound emissions are based on a maximum expected concentration of 20 ppm in the flue gas. Of this amount, 10 ppm was assumed to be H2S and 10 ppm was assumed to be COS.

• NOx and CO emissions were based on flue gas concentrations of 50 and 150 ppm, respectively. PM2.5, VOC and PAH emissions were estimated in a manner similar to that for the heater, furnace and boilers.

• Sulphuric acid (H2SO4) emissions were estimated from the CPPI (2005) Code of Practice. Specifically 2 percent (wt.) conversion of SO2 to SO3 was first assumed. Based on a stack temperature of 538 °C and a flue gas water vapour composition of 11 percent, the estimated SO3 to H2SO4 conversion is 5 percent (vol.).

Under normal operating conditions, small volumes of purge and pilot gases are directed to the flares. The associated flare parameters and emissions for normal operating conditions are provided in Table 5A-15. Under upset conditions, which will be infrequent and of a short-term nature, larger volumes of gas will be directed to the flares. The associated flare parameters and emissions for upset conditions are provided in Table 5A-16. The following are noted relative to flaring:

• The normal operating conditions are evaluated for the suite of compounds listed Table 5A-15 since the HHRA addresses long-term exposures. The upset emergency cases are only evaluated to determine maximum 1-h average SO2 concentrations given the high H2S content of some of the upset cases that could occur.

• The largest SO2 emissions are associated with the H2S flare that services the SRU. Three intermittent emergency scenarios have been identified. Under these conditions, SO2 emissions will not be occurring from the thermal oxidizer stack. The natural gas addition represents the maximum amount of natural gas that would be available at the plant.

• The acid gas stream might contain ammonia; the ammonia is assumed to be completely oxidized to NOx.

• Two extreme high pressure (HP) and low pressure (LP) flare events are identified. While the volumes of gas to flare can be relatively large, the H2S content is lower than that associated with the SRU acid gas stream.

• The South Tank farm will be serviced by a flare. This flare, however, would not see any sour service and therefore would not be a source of SO2 emissions.

As dispersion models are not set up to evaluate flare stacks, the flare data has to be processed to produce “effective” parameters that can be used by the models. These parameters are provided in Tables 5A-15 and 5A-16.



5A.4.1.2 Storage Tank Emissions Tables 5A-17 and 5A-18 identify the 16 storage tanks associated with Phase 1. Fugitive emissions result from emptying and filling operations (referred to as working losses) and from diurnal heating and cooling of the tanks (referred to as breathing losses). Clearstone Engineering, based on parameters provided by Fluor Engineering, estimated the losses and the provided associated speciation information. The following are noted:

• The US EPA TANKS emission estimation program was used to calculate total hydrocarbon emissions based on the tank properties and the tank contents.

• For tanks that are tied into a vapour recovery system, a control efficiency of 95 percent was assumed. These tanks include the Diluted Bitumen Tanks, the Treated MGO Tank, the Untreated Naphtha Tank, the Untreated MGO Tank, the Slop Tank, and the Flushing Oil Tank.

• The compositions of the fugitive emissions are based on the application of speciation profiles derived from fugitive emission measurements conducted at the Syncrude Mildred Lake Upgrader. The Mildred Lake Upgrader was assumed to be a suitable analogue, given the similarity of the diluent used by Syncrude and that proposed by the Project.

The estimated fugitive VOC emissions due to the tanks are 80 t/a. The largest sources are the three Diluted Bitumen tanks (36.1 percent) and the Untreated Naphtha tank (36.4 percent). Tables 5A-17 and 5A-18 also provide representative emission for each tank. Emissions that fall in the “other” category (~0 to 58 percent) include the lighter hydrocarbons (C2 to C4,) that do not have health consequences of significance.

5A.4.1.3 Process Area Emissions Large volumes of gases are handled in the different process areas, and fugitive emissions will result from the numerous valves, flanges, rotating seals, and drains that are associated with these areas. Clearstone Engineering, based on parameters provided by Fluor Engineering, estimated the fugitive emissions and provided representative speciation profiles. The magnitude and composition of the fugitive emissions were based on measurements at the Syncrude Mildred Lake Upgraders.

Table 5A-19 provides a summary of the process area parameters and emissions. The total VOC emissions due to these sources are estimated to be 232.8 t/a. The effluent pond is expected to only be a source of small amounts of ammonia and H2S.

5A.4.1.4 Cooling Tower Emissions Phase 1 of the Project will be serviced by a five cell forced draft cooling tower to provide the cooling requirements of the Project. The cooling water circulation rate for each cell is 2020 m3/h or 2,020,000 kg/h, and the expected water vapour release rate for each cell is 41,200 kg/h. Table 5A-20 provides the parameters associated with the cooling tower. The total water vapour emission due to the cooling tower is 4944 t/d. For the purpose of comparison, the total water vapour emission from combustion sources is 5942 t/d. The distribution of water vapour emission for Phase I is therefore 45 percent due to cooling towers and 55 percent due to combustion sources.


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Table 5A-9: Summary of Phase 1 Emission Sources NO. Identification Description

1 300MF101 Fractionator Feed Heater (DRU) 3 330MF1 Coker Heater 1 4 330MF2 Coker Heater 2 5 400MF1 Main NHT Reactor Feed Furnace 6 410F1A Train 1 Reactor Feed Furnace (MGO) 7 410F1B Train 2 Reactor Feed Furnace (MGO) 10 522MF4 Thermal Oxidizer 8 450MF1 SMR Furnace 13 650MF1 Utility Boiler 14 650MF2 Utility Boiler 43 650MF3 Utility Boiler 44 410MF2 MGO Stabilizer Feed Furnace 12 500MF1 H2S Flare 15 740MF1 HP Flare 16 740MF2 LP Flare 19 740MF3 South Tank Farm Flare

Table 5A-10: Plant Fuel Gas and Natural Gas Composition (mole %) for Phases 1 and 2/3

Plant Fuel Gas Natural Gas Component Phase 1 Phase 2/3 Phases 1 and 2/3

H2O 0.70 0.75 0.00 Hydrogen 20.01 29.13 0.00 Nitrogen 0.00 0.00 4.50

CO2 0.10 0.10 0.40 Methane 39.28 30.99 90.00 Ethane 22.03 19.86 3.00

Ethylene 2.78 2.22 0.00 Propane 8.03 10.85 1.50 Propene 3.98 3.39 0.00 Butanes 1.63 1.25 0.60 Butenes 1.45 1.46 0.00

H2S (ppm) 30 25 0.00 COS (ppm) 73 10 0.00 RSH (ppm) 265 15 0.00

Total 100.00 100.00 100.00 Molecular Mass 21.33 20.25 17.74

Low Heating Value (MJ/m3) 43.73 41.95 34.12



Table 5A-11: Emission Factors Used to Estimate Combustion Source Emissions Type of Combustion Equipment

Heater, Boiler and Steam Generator Turbine Engine

Flare (Landfill Gas)

Substance lb/MMscf lb/MMscf lb/MMscf

CO2 110676

(Phase 1) 97280

(Phase 2/3) 110676

(Phase 1) 97280

(Phase 2/3) 136411

H2O 81360

(Phase 1) 84812

(Phase 2/3) 81360

(Phase 1) 84812

(Phase 2/3) 104265 NOx 140 133 69.4 CO 84 3.47 - VOC 5.5 2.14 143 PM2.5 1.9 1.94 1.9 Acenaphthene Group 0.0000341 0.000205 0.112 Acetaldehyde 0.05 0.511 0.653 Acrolein 0.0222 0.0693 0.0933 Anthracene 0.0000024 0.000153 0.056 1,3-Butadiene - 0.000439 - Benzaldehyde 0.0272 - - Benzene 0.04 0.099 0.859 Benzo(a)anthracene 0.00000285 0.000134 0.056 Benzo(a)pyrene 0.0000012 0.0000916 0.056 Benzo(b)fluoranthene 0.0000018 0.0000672 0.056 Benzo(e)pyrene - 0.000000733 0.0000748 Benzo(g,h,i)perylene 0.00000142 0.0000825 0.056 Benzo(k)fluoranthene 0.0000018 0.0000672 0.056 2-Chloronaphthalene - 0.000000469 - C5-C8 Aliphatics 2.6 - - C17-C34 Aromatics 0.0000178 0.000000968 0.0000748 Chrysene 0.00000183 0.00015 0.056 Dibenz(a,h)anthracene 0.0000012 0.000134 0.056 Dichlorobenzene 0.0012 - - Ethylbenzene 0.00225 0.057 - Fluoranthene 0.0000179 0.000305 0.056 Fluorene 0.00000582 0.000458 0.056 Formaldehyde 0.672 6.87 67.4 Hexane 1.8 0.382 - Indeno(1,2,3-cd)pyrene 0.0000018 0.000134 0.056 2-Methylnaphthalene 0.000024 0.0000063 0.0164 Naphthalene 0.00247 0.00788 35.4 Phenanthrene 0.0000474 0.00235 0.056 Propylene Oxide - 0.0587 - Pyrene 0.0000116 0.000127 0.056 Toluene 0.0747 0.168 109 Xylenes 0.0297 0.0653 0.796

NOTES: U.S EPA AP-42 Emission Factors California Air Toxics Emission Factors (CATEF)


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Table 5A-12: Phase 1 Combustion Source Parameters and Emissions (Stacks 1, 3, 4, 5, 6, and 7)

Source identification # 1 3 4 5 6 7 Unit Identification # 300MF101 330MF1 330MF2 400MF1 410F1A 410F1B

Unit Name/Description

Fractionator Feed heater

(DRU) Coker

Heater 1 Coker

Heater 2

Main NHT Reactor

Feed Furnace

Train 1 Reactor

Feed Furnace (MGO)

Train 2 Reactor

Feed Furnace (MGO)

Temporal Variation Continuous Continuous Continuous Continuous Continuous Continuous Rating Heat Input (FIRED) GJ/h 309 362 362 40.6 58.6 58.6 Efficiency % 90 90 90 80 80 80 Fuel Type Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Consumption 103 Nm3/d 160 187 187 21.0 30.0 30.0 Stack Location UTM NAD 83 m N 5,967,482 5,967,626 5,967,601 5,967,651 5,967,783 5,967,783 UTM NAD 83 m E 357,868 358,210 358,209 357,911 357,861 357,846 Base Elevation of Stack m ASL 633 633 633 633 633 633 Stack Dimensions Height m 35 65 65 35 35 35 Inside Tip Diameter m 1.95 2.16 2.16 0.71 0.85 0.85 Exhaust Parameters Exit Velocity m/s 15 15 15 15 15 15 Exit Temperature K 448 473 473 448 448 448 Emission Rates CO2 t/d 326.309 381.374 381.374 42.828 61.183 61.183 H2O t/d 239.877 280.356 280.356 31.484 44.977 44.977 SO2 t/d 0.168 0.197 0.197 0.022 0.032 0.032 NOx t/d 0.290 0.340 0.340 0.025 0.037 0.037 CO t/d 0.044 0.052 0.052 0.006 0.008 0.008 VOC t/d 0.016 0.019 0.019 0.0021 0.003 0.003 PM2.5 t/d 0.0056 0.0066 0.0066 0.00074 0.0011 0.0011 Acenaphthene Group t/a 0.000037 0.000043 0.000043 0.0000048 0.0000069 0.0000069 Acetaldehyde t/a 0.054 0.063 0.063 0.0071 0.01 0.01 Acrolein t/a 0.024 0.028 0.028 0.0031 0.0045 0.0045 Anthracene t/a 0.0000026 0.000003 0.000003 0.00000034 0.00000048 0.00000048 Benzaldehyde t/a 0.029 0.034 0.034 0.0038 0.0055 0.0055 Benzene t/a 0.043 0.05 0.05 0.0057 0.0081 0.0081 Benzo(a)anthracene t/a 0.0000031 0.0000036 0.0000036 0.0000004 0.00000058 0.00000058 Benzo(a)pyrene t/a 0.0000013 0.0000015 0.0000015 0.00000017 0.00000024 0.00000024 Benzo(b)fluoranthene t/a 0.0000019 0.0000023 0.0000023 0.00000025 0.00000036 0.00000036 Benzo(g,h,i)perylene t/a 0.0000015 0.0000018 0.0000018 0.0000002 0.00000029 0.00000029 Benzo(k)fluoranthene t/a 0.0000019 0.0000023 0.0000023 0.00000025 0.00000036 0.00000036 C5-C8 Aliphatics t/a 2.80 3.27 3.27 0.37 0.53 0.53 C17-C34 Aromatics t/a 0.000019 0.000022 0.000022 0.0000025 0.0000036 0.0000036 Chrysene t/a 0.000002 0.0000023 0.0000023 0.00000026 0.00000037 0.00000037 Dibenz(a,h)anthracene t/a 0.0000013 0.0000015 0.0000015 0.00000017 0.00000024 0.00000024 Dichlorobenzene t/a 0.0013 0.0015 0.0015 0.00017 0.00024 0.00024 Ethylbenzene t/a 0.0024 0.0028 0.0028 0.00032 0.00045 0.00045 Fluoranthene t/a 0.000019 0.000023 0.000023 0.0000025 0.0000036 0.0000036 Fluorene t/a 0.0000063 0.0000073 0.0000073 0.00000082 0.0000012 0.0000012 Formaldehyde t/a 0.72 0.85 0.85 0.095 0.14 0.14 Hexane t/a 1.94 2.26 2.26 0.25 0.36 0.36 Indeno(1,2,3-cd)pyrene t/a 0.0000019 0.0000023 0.0000023 0.00000025 0.00000036 0.00000036 2-Methylnaphthalene t/a 0.000026 0.00003 0.00003 0.0000034 0.0000048 0.0000048 Naphthalene t/a 0.0027 0.0031 0.0031 0.00035 0.0005 0.0005 Phenanthrene t/a 0.000051 0.00006 0.00006 0.0000067 0.0000096 0.0000096 Pyrene t/a 0.000013 0.000015 0.000015 0.0000016 0.0000023 0.0000023 Toluene t/a 0.08 0.094 0.094 0.011 0.015 0.015 Xylenes t/a 0.032 0.037 0.037 0.0042 0.006 0.006



Table 5A-13: Phase 1 Combustion Source Parameters and Emissions (Stacks 8, 13, 14, 43, and 44)

Source identification # 8 13 14 43 44 Unit Identification # 450MF1 650MF1 650MF2 650MF3 410MF2

Unit Name/Description SMR Furnace Utility Boiler Utility Boiler Utility Boiler

MGO Stabilizer

Feed Furnace Temporal Variation Continuous 1 wk / 2 yrs 1 wk / 2 yrs 1 wk / 2 yrs Continuous

Rating Heat Input (FIRED) GJ/h 1361 583.5 583.5 583.5 90.8 Efficiency % 91.7 LHV 91.7 LHV 91.7 LHV 80 Fuel Type PSAT + FG Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Consumption 103 Nm3/d 2201 302 302 302 47.0 Stack Location UTM NAD 83 m N 5,968,624 5,968,267 5,968,266 5,968,266 5,967,842 UTM NAD 83 m E 357,916 357,860 357,873 357,885 357,849 Base Elevation of Stack m ASL 633 633 633 633 633 Stack Dimensions Height m 38 40 40 40 35 Inside Tip Diameter m 4.03 2.12 2.12 2.12 1.06 Exhaust Parameters Exit Velocity m/s 15 24 24 24 15 Exit Temperature K 422 448 448 448 448 Emission Rates CO2 t/d 4488.8 615.9 615.9 615.9 95.9 H2O t/d 3299.8 452.8 452.8 452.8 70.5 SO2 t/d 0.308 0.317 0.317 0.317 0.049 NOx t/d 1.651 0.548 0.548 0.548 0.057 CO t/d 0.201 0.083 0.083 0.083 0.013 VOC t/d 0.223 0.0306 0.0306 0.0306 0.00476 PM2.5 t/d 0.0771 0.0106 0.0106 0.0106 0.00165 Acenaphthene Group t/a 0.000505 0.0000693 0.0000693 0.0000693 0.0000108 Acetaldehyde t/a 0.74 0.102 0.102 0.102 0.0158 Acrolein t/a 0.329 0.0451 0.0451 0.0451 0.00702 Anthracene t/a 0.0000355 0.00000487 0.00000487 0.00000487 0.000000759 Benzaldehyde t/a 0.403 0.0552 0.0552 0.0552 0.0086 Benzene t/a 0.592 0.0812 0.0812 0.0812 0.0126 Benzo(a)anthracene t/a 0.0000422 0.00000579 0.00000579 0.00000579 0.000000901 Benzo(a)pyrene t/a 0.0000178 0.00000244 0.00000244 0.00000244 0.000000379 Benzo(b)fluoranthene t/a 0.0000266 0.00000366 0.00000366 0.00000366 0.000000569 Benzo(g,h,i)perylene t/a 0.000021 0.00000288 0.00000288 0.00000288 0.000000449 Benzo(k)fluoranthene t/a 0.0000266 0.00000366 0.00000366 0.00000366 0.000000569 C5-C8 Aliphatics t/a 38.5 5.28 5.28 5.28 0.822 C17-C34 Aromatics t/a 0.000264 0.0000362 0.0000362 0.0000362 0.00000563 Chrysene t/a 0.0000271 0.00000372 0.00000372 0.00000372 0.000000578 Dibenz(a,h)anthracene t/a 0.0000178 0.00000244 0.00000244 0.00000244 0.000000379 Dichlorobenzene t/a 0.0178 0.00244 0.00244 0.00244 0.000379 Ethylbenzene t/a 0.0333 0.00457 0.00457 0.00457 0.000711 Fluoranthene t/a 0.000265 0.0000364 0.0000364 0.0000364 0.00000566 Fluorene t/a 0.0000862 0.0000118 0.0000118 0.0000118 0.00000184 Formaldehyde t/a 9.95 1.36 1.36 1.36 0.212 Hexane t/a 26.6 3.66 3.66 3.66 0.569 Indeno(1,2,3-cd)pyrene t/a 0.0000266 0.00000366 0.00000366 0.00000366 0.000000569 2-Methylnaphthalene t/a 0.000355 0.0000487 0.0000487 0.0000487 0.00000759 Naphthalene t/a 0.0366 0.00502 0.00502 0.00502 0.000781 Phenanthrene t/a 0.000702 0.0000963 0.0000963 0.0000963 0.000015 Pyrene t/a 0.000172 0.0000236 0.0000236 0.0000236 0.00000367 Toluene t/a 1.11 0.152 0.152 0.152 0.0236 Xylenes t/a 0.44 0.0603 0.0603 0.0603 0.00939


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Table 5A-14: Phase 1 Thermal Oxidizer Parameters and Emissions Source identification # 10 Unit Identification # 522MF4 Unit Name/Description Thermal oxidizer Temporal Variation Continuous Sulphur Recovery Inlet Sulphur Equivalent t/d 1000 Annual S Recovery % 99.7 Quarterly S Recovery % 99.5 Stack Location UTM NAD 83 m N 5,967,947 UTM NAD 83 m E 358,330 Base Elevation of Stack m ASL 633 Stack Dimensions Height Above Base Elevation m 90.0 Inside Tip Diameter m 2.26 Exhaust Parameters Exit Velocity m/s 25.0 Exit Temperature K 811 Emission Rates CO2 t/d 311.7 H2O t/d 278.0 SO2 average t/d 6.0 SO2 24 h max t/d 10.0 SO2 1 h t/h 0.417 SO2 1h max (1.4 times 0.417 t/h) t/h 0.583 TRS t/d 0.089 H2S t/d 0.0445 COS t/d 0.0784 CS2 t/d 0.000 NOx t/d 0.300 CO t/d 0.548 VOC t/d 0.0118 PM2.5 t/d 0.00407 Acenaphthene Group t/a 0.0000267 Acetaldehyde t/a 0.039 Acrolein t/a 0.0174 Anthracene t/a 0.0000019 Benzaldehyde t/a 0.0213 Benzene t/a 0.031 Benzo(a)anthracene t/a 0.0000022 Benzo(a)pyrene t/a 0.0000009 Benzo(b)fluoranthene t/a 0.0000014 Benzo(g,h,i)perylene t/a 0.0000011 Benzo(k)fluoranthene t/a 0.0000014 C5-C8 Aliphatics t/a 2.034 C17-C34 Aromatics t/a 0.0000139 Chrysene t/a 0.00000143 Dibenz(a,h)anthracene t/a 0.00000094 Dichlorobenzene t/a 0.0009387 Ethylbenzene t/a 0.00176 Fluoranthene t/a 0.000014 Fluorene t/a 0.0000046 Formaldehyde t/a 0.5257 Hexane t/a 1.408 Indeno(1,2,3-cd)pyrene t/a 0.0000014 2-Methylnaphthalene t/a 0.00001877 Naphthalene t/a 0.00193 Phenanthrene t/a 0.000037 Pyrene t/a 0.00000907 Toluene t/a 0.058 Xylenes t/a 0.0232 Sulphuric Acid t/a 3.353



Table 5A-15: Phase 1 Flare Stack Parameters and Emissions (Normal) Source identification # 12 15 16 19 Unit Identification # 500MF1 740MF1 740MF2 740MF3 Unit Name/Description H2S Flare HP Flare LP Flare South Tank Farm Flare Event Normal Normal Normal Normal Frequency Continuous Continuous Continuous Continuous Duration Continuous Continuous Continuous Continuous Flow Rate Inlet Gas Stream Natural Gas Natural Gas Natural Gas Natural Gas Inlet Flow Rate 103 Nm3/d 0.76 2.8 3.5 0.08 Stack Location UTM NAD 83 m N 5,968,088 5,967,833 5,967,606 5,965,904 UTM NAD 83 m E 358,670 358,662 358,655 357,588 Base Elevation of Stack m ASL 633 631 631 642 Stack Dimensions Height Above Base Elevation m 90 65 116 20 Inside Tip Diameter m 0.81 1.37 1.52 0.2 Effective Parameters Stack Height m 91.0 66.8 118.0 20.3 Stack Diameter m 7.87 13.3 14.8 1.94 Exit Velocity m/s 0.017 0.022 0.022 0.029 Exit Temperature K 1273 1273 1273 1273 Emission Rates CO2 t/d 1.91 7.04 8.80 0.201 H2O t/d 1.46 5.38 6.72 0.154 SO2 t/d 0.00080 0.0029 0.0037 0.000084 NOx t/d 0.00097 0.00358 0.0044 0.00010 CO t/d 0.00118 0.00433 0.00542 0.000124 VOC t/d 0.002 0.00737 0.00921 0.000211 PM2.5 t/d 0.0000266 0.000098 0.000123 0.0000028 Acenaphthene Group t/a 0.000573 0.00211 0.00264 0.0000603 Acetaldehyde t/a 0.00334 0.0123 0.014 0.000351 Acrolein t/a 0.000477 0.00176 0.0022 0.00005 Anthracene t/a 0.000286 0.00105 0.00132 0.00003 Benzene t/a 0.00439 0.0162 0.0202 0.00046 Benzo(a)anthracene t/a 0.000286 0.00105 0.00132 0.0000301 Benzo(a)pyrene t/a 0.000286 0.00105 0.00132 0.0000301 Benzo(b)fluoranthene t/a 0.000286 0.00105 0.00132 0.0000301 Benzo(e)pyrene t/a 0.000000382 0.0000014 0.0000018 0.000000040 Benzo(g,h,i)perylene t/a 0.000286 0.00105 0.00132 0.000030132 Benzo(k)fluoranthene t/a 0.000286 0.00105 0.00132 0.000030132 C17-C34 Aromatics t/a 0.0000004 0.00000141 0.00000176 0.00000004 Chrysene t/a 0.000286 0.00105 0.00132 0.00003013 Dibenz(a,h)anthracene t/a 0.000286 0.00105 0.00132 0.00003013 Fluoranthene t/a 0.000286 0.00105 0.00132 0.0000301 Fluorene t/a 0.000286 0.00105 0.00132 0.0000301 Formaldehyde t/a 0.345 1.269 1.587 0.0363 Indeno(1,2,3-cd)pyrene t/a 0.000286 0.00105 0.00132 0.0000301 2-Methylnaphthalene t/a 0.0000838 0.000309 0.000386 0.0000088 Naphthalene t/a 0.181 0.667 0.833 0.019 Phenanthrene t/a 0.000286 0.00105 0.00132 0.0000301 Pyrene t/a 0.000286 0.00105 0.00132 0.0000301 Toluene t/a 0.557 2.0527 2.566 0.0586 Xylenes t/a 0.00407 0.015 0.0187 0.000428


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Table 5A-16: Phase 1 Flare Stack Parameters and Emissions (Emergency) Source identification # 12 15 16 19

Unit Identification # 500MF1 740MF1 740MF2 740MF3 Unit Name/Description H2S Flare HP Flare LP Flare South Tank Farm Flare

Event

Emergency – Total Power

Failure Emergency –

Fire

Emergency – Partial Power

Failure Emergency Emergency Fire case Frequency once / 2 y once / 25 y once / 2 y once / 5 y once / 5 y once / 50 y Duration 30 minutes 30 minutes 30 minutes 30 minutes 30 minutes 60 minutes Flow Rate Inlet Gas Stream Acid Gas Acid Gas Acid Gas Inlet Flow Rate 103 Nm3/d 3044 2207 1473 16016 8069 211 Supplemental Natural Gas Flow Rate 103 Nm3/d 1120 1120 1120 0.0 0.0 0.0 Inlet Gas Composition H2 Mole % 0.04 0.10 0.00 74.00 1.80 0.0 N2 Mole % 0.00 0.00 0.00 0.10 0.00 0.0 Ar Mole % 0.00 0.00 0.00 0.10 0.00 0.0 CO Mole % 0.00 0.00 0.00 0.80 0.00 0.0 CO2 Mole % 0.13 0.40 9.59 0.00 0.00 0.0 H2S Mole % 26.97 73.30 75.95 5.00 5.90 0.0 C1 Mole % 0.01 0.10 0.38 8.00 11.50 0.0 C2 Mole % 0.01 0.00 0.19 4.00 7.20 0.0 C3 Mole % 0.00 0.00 0.19 2.00 4.70 0.0 C4 Mole % 0.00 0.00 0.00 3.00 3.20 100.0 C5+ Mole % 0.00 0.00 0.00 2.00 43.60 0.0 H2O Mole % 63.41 25.90 7.74 1.00 22.10 0.0 NH3 Mole % 9.43 0.20 5.95 0.00 0.00 0.0 Total Mole % 100.00 100.00 99.99 100.00 100.00 100.00 Acid Gas Properties Molecular Mass kg/kmole 22.28 29.87 32.71 9.96 45.43 58.12 Heating Value MJ/m3 7.55 16.14 18.08 21.65 77.56 112.03 Combined Gas Properties Molecular Mass kg/kmole 21.08 25.8 26.27 9.96 45.43 58.12 Heating Value MJ/m3 14.75 22.26 25.10 21.65 77.56 112.03 Stack Location UTM NAD 83 m N 5,968,088 5,967,833 5,967,606 5,965,904 UTM NAD 83 m E 358,670 358,662 358,655 357,588 Base Elevation of Stack m ASL 633 631 631 642 Stack Dimensions Height Above Base Elevation m 90 65 116 20 Inside Tip Diameter m 0.81 1.37 1.52 0.2 Effective Parameters Stack Height m 129.2 132.9 130.3 154.6 234.9 44.8 Stack Diameter m 5.16 6.34 6.73 10.57 22.19 3.51 Exit Velocity m/s 93.5 74.7 58.24 125.75 51.467 77.735 Exit Temperature K 1273 1273 1273 1273 1273 1273 Emission Rate SO2 (equivalent 1-h) t/h 45.39 89.45 61.86 44.28 26.32 0.0



Table 5A-17: Summary of Phase 1 Tank Parameters and Emissions (Tanks 36 to 44) Source identification # 36 37 38 39 40 41 42 44 Process Area # 710MD1A 710MD1B 710MD1C 710MD2A 710MD3A 710MD4A 521MD2 720MD1A

Unit Name/Description Diluted Bitumen

Diluted Bitumen

Diluted Bitumen Diluent Treated

Naphtha Treated MGO

Liquid Sulphur Storage

Untreated Naphtha

Tank Farm South South South South South South South North m E 357311 357307 357302 357567 357625 357346 357890 357661 Volume Source Locations m N 5,966,408 5966264 5966120 5966364 5966619 5966654 5966566 5967616

Base Elevation of Source m ASL 642 642 642 642 642 642 642 633 Release Dimensions Tank Height m 19.5 19.5 19.5 18.3 17.1 19.5 9.0 17.1 Tank Diameter m 61.2 61.2 61.2 70.9 43.2 61.6 20.2 40.8 Sigma Y m 14.2 14.2 14.2 16.5 10.0 14.3 4.7 9.5 Sigma Z m 9.1 9.1 9.7 8.5 8.0 9.1 4.2 8.0 Emission Rates Total VOC t/a 9.62 9.62 9.62 5.69 4.928 5.085 0.009 0.939 1,3-butadiene t/a 0.307 0.307 0.307 0.121 0.105 0.000 0.000 0.0212 Aliphatic alcohols t/a 0.000 0.000 0.000 0.000 0.000 0.025 0.000 0.0024 Aliphatic aldehydes t/a 0.020 0.020 0.020 0.036 0.031 0.000 0.000 0.000 Aliphatic ketones t/a 0.00087 0.00087 0.00087 0.0135 0.0117 0.000 0.000 0.00436 Benzene t/a 0.125 0.125 0.125 0.104 0.009 0.000 0.000 0.00715 C17+ aliphatic group t/a 0.000 0.000 0.000 0.000 0.000 0.030 0.000 0.0063 C5-C8 aliphatic group t/a 2.054 2.054 2.054 1.447 1.254 0.026 0.000 0.043 C9-C16 aliphatic group t/a 0.042 0.042 0.042 0.100 0.087 2.475 0.000 0.222 C9-C16 aromatic group t/a 0.000 0.000 0.000 0.000 0.000 0.143 0.000 0.027 CS2 t/a 0.00098 0.00098 0.00098 0.00133 0.00115 0.000 0.000017 0.000 Ethylbenzene t/a 0.00102 0.00102 0.00102 0.0129 0.0112 0.014 0.000 0.00517 Hexane t/a 0.215 0.215 0.215 0.109 0.094 0.000 0.000 0.00464 Hydrogen sulphide t/a 0.003264 0.00326 0.00326 0.10016 0.0868 0.000 0.0088 0.000 Isopropylbenzene t/a 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.0024 Mercaptan group t/a 0.005 0.006 0.006 0.006 0.005 0.000 0.000 0.000 Other (C2 to C4) t/a 4.912 4.912 4.912 2.224 1.927 1.134 0.000 0.544 Thiophene group t/a 0.012 0.012 0.012 0.013 0.011 0.000 0.000 0.0068 Toluene t/a 0.155 0.155 0.155 0.206 0.178 0.662 0.000 0.019 Xylenes t/a 0.00069 0.00069 0.00069 0.0155 0.0134 0.077 0.000 0.024 Methane t/a 1.767 1.767 1.767 1.177 1.019 0.499 0.0000057 0.000


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Table 5A-18: Summary of Phase 1 Tank Parameters and Emissions (Tanks 45 to 51) Source identification # 45 46 47 48 48 49 50 51 Process Area # 720MD2A 720MD3A 720MD3B 720MD4 620MD1 620MD2A 650MD4 650MD5

Unit Name/Description Untreated MGO Slop Slop Flushing Oil Sodium

Hypochlorite Sulphuric

Acid Sulphuric

Acid Caustic

Tank Farm North North North North Utilities Utilities Utilities Utilities m E 357420 357697 357653 357609 358371 358369 357902 357911

Volume Source Locations m N 5967697 5967755 5967756 5967758 5968413 5968401 5966259 5968259 Base Elevation of Source m ASL 633 633 633 633 631 631 633 633 Release Dimensions Tank Height m 19.5 12.2 12.2 12.2 6.00 7.61 7.61 7.61 Tank Diameter m 63.9 28.9 28.9 29.8 3.25 2.54 2.54 2.54 Sigma Y m 14.9 6.7 6.7 6.9 0.8 0.6 0.6 0.6 Sigma Z m 9.1 5.7 5.7 5.7 2.8 3.5 3.5 3.5 Emission Rates Total VOC t/a 29.09 1.27 1.27 2.695 0.094 0.0000031 0.00000078 0.0034 1,3-butadiene t/a 0.000 0.207 0.207 0.000 0.0 0.0 0.0 0.0 Aliphatic alcohols t/a 0.000 0.00043 0.00043 0.00054 0.0 0.0 0.0 0.0 Aliphatic ketones t/a 0.000 0.000 0.000 0.000 0.0 0.0 0.0 0.0 Benzene t/a 0.494 0.014 0.014 0.0008 0.0 0.0 0.0 0.0 C17+ aliphatic group t/a 0.460 0.000 0.000 0.001 0.0 0.0 0.0 0.0 C5-C8 aliphatic group t/a 4.145 0.188 0.188 0.084 0.0 0.0 0.0 0.0 C9-C16 aliphatic group t/a 2.588 0.00576 0.00576 0.0811 0.0 0.0 0.0 0.0 C9-C16 aromatic group t/a 0.082 0.00021 0.00021 0.0278 0.0 0.0 0.0 0.0 CS2 t/a 0.057 0.0016 0.0016 0.00015 0.0 0.0 0.0 0.0 Cyclohexane t/a 0.000 0.0019 0.0019 0.00023 0.0 0.0 0.0 0.0 Ethylbenzene t/a 0.603 0.0014 0.0014 0.0092 0.0 0.0 0.0 0.0 Hexane t/a 0.663 0.0097 0.0097 0.0019 0.0 0.0 0.0 0.0 Hydrogen sulphide t/a 0.209 0.051 0.051 0.037 0.0 0.0 0.0 0.0 Isopropylbenzene t/a 0.0743 0.0000816 0.0000816 0.0015 0.0 0.0 0.0 0.0 Mercaptan group t/a 0.000 0.0132 0.0132 0.000788 0.0 0.0 0.0 0.0 Naphthalene t/a 0.000 0.000027 0.000027 0.000 0.0 0.0 0.0 0.0 Propylene oxide t/a 0.000 0.005942 0.005942 0.000 0.0 0.0 0.0 0.0 Other (C2 to C4) t/a 2.596 0.681 0.681 0.878 0.0 0.0 0.0 0.0 Thiophene group t/a 0.188 0.020 0.020 0.003 0.0 0.0 0.0 0.0 Toluene t/a 1.835 0.014 0.014 0.011 0.0 0.0 0.0 0.0 Xylenes t/a 1.57 0.0033 0.0033 0.032 0.0 0.0 0.0 0.0 NaOCl t/a 0.000 0.000 0.000 0.000 0.094 0.0 0.0 0.0 H2SO4 t/a 0.000 0.000 0.000 0.000 0.0 0.0000031 0.00000078 0.0 NaOH t/a 0.000 0.000 0.000 0.000 0.0 0.0 0.0 0.0034 Methane t/a 13.523 0.053 0.053 1.524 0.0 0.0 0.0 0.0



Table 5A-19: Summary of Phase 1 Process Area Parameters and Emissions Source identification # 1 3,4 8 10, 12 5 6, 7, 44

Unit Identification # 300MF101 330MF1 330MF2 330MF3

340 450MF1 500, 510, 520, 522 400MF1

410MF1A 410MF1B 410MF2

710,720

Unit Name/Description Diluent

Recovery Unit

(DRU)

Coker Gas

Recovery Unit

H2 Plant Sour Block Naphtha Hydrotreater

Medium Gas Oil Hydrotreater Tank Farm Effluent

Pond

Area Source Locations North South m E 357,852 358,095 358,095 357,888 358,099 357,905 357,836 357,681 357,592 358,936

Northwest m N 5,967,555 5,967,799 5,967,799 5,968,107 5,968,048 5,967,716 5,967,848 5,967,755 5,966,699 5,968,362 m E 358,007 358,364 358,364 358,028 358,418 358,019 358,023 357,697 357,612 358,976

Northeast m N 5,967,550 5,967,790 5,967,790 5,968,103 5,968,038 5,967,712 5,967,844 5,967,755 5,966,699 5,968,360 m E 358,004 358,355 358,355 358,025 358,412 358,016 358,019 357,688 357,588 358,976

Southeast m N 5,967,450 5,967,490 5,967,490 5,967,989 5,967,849 5,967,615 5,967,712 5,967,470 5,965,904 5,968,335 m E 357,849 358,085 358,085 357,886 358,095 357,902 357,832 357,672 357,569 358,936

Southwest m N 5,967,455 5,967,499 5,967,499 5,967,993 5,967,859 5,967,618 5,967,718 5,967,471 5,965,905 5,968,337 Base Elevation of Source m ASL 633 633 633 633 633 633 633 633 633 633 Release Dimensions Release Height m 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 1.0 Initial Sigma Z m 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 5.0 Emission Rates Total VOC t/a 20.39 34.77 7.72 48.82 42.43 26.34 32.61 8.73 11.03 0.00 1,3-butadiene t/a 0.000 0.000 0.000 0.701 0.086 0.000 0.144 0.013 0.017 0.000 Aliphatic alcohols t/a 0.000945 0.000 0.00012 0.000 0.000 0.000 0.000 0.00827 0.0104 0.000945 Aliphatic aldehydes t/a 0.066 0.049 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Aliphatic ketones t/a 0.007 0.000 0.000 0.0058 0.000 0.000499 0.00708 0.000 0.000 0.000 Ammonia t/a 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 8.541 Benzene t/a 0.709 0.18 0.00178 0.0024 0.00021 0.0217 0.00513 0.0952 0.120 0.000 C17-C34 aromatic group t/a 0.000 0.000 0.000 0.000 0.000 0.00078 0.000146 0.000 0.000 0.000 C5-C8 aliphatic group t/a 4.914 1.314 0.070 0.210 0.014 0.235 0.137 5.346 6.749 0.000 C9-C16 aromatic group t/a 0.0293 0.289 0.000223 0.00508 0.000 0.0196 0.0104 0.687 0.868 0.000 CS2 t/a 0.0101 0.475 0.0000842 0.0098 0.000852 0.174 0.0000146 0.000766 0.000967 0.000 Cyclohexane t/a 0.033 0.000 0.000304 0.000976 0.000 0.0119 0.000 0.1156 0.146 0.000 Ethylbenzene t/a 0.0132 0.000 0.00019 0.000606 0.0000137 0.00256 0.00884 0.193 0.244 0.000 Hexane t/a 0.739 0.000 0.0013 0.017 0.000186 0.039 0.0082 0.183 0.232 0.000 Hydrogen sulphide t/a 1.685 3.604 0.043 0.000041 0.709 1.913 0.0000046 0.016 0.020 0.7796 Isopropylbenzene t/a 0.000 0.000 0.000 0.000 0.000 0.00044 0.000 0.011 0.014 0.000 Mercaptan group t/a 0.064 0.000 0.002 0.005 0.037 0.002 0.000 0.002 0.002 0.000 Methylene chloride t/a 0.000 0.000 0.000 0.00000000012 0.000000000046 0.00000000016 0.000000000081 0.000 0.000 0.000 Propylene oxide t/a 0.00094 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Other (C2 to C4) t/a 10.163 0.000 1.704 20.668 13.771 2.613 8.397 0.653 0.824 0.000 Thiophene group t/a 0.074 2.108 0.0012 0.0031 0.0055 0.0088 0.016 0.017 0.021 0.000 Toluene t/a 0.366 0.216 0.0015 0.0033 0.00015 0.014 0.013 0.598 0.755 0.000 Xylenes t/a 0.022 0.101 0.0006 0.0014 0.000047 0.0078 0.019 0.442 0.559 0.000 Methane t/a 1.496 26.432 5.897 27.187 27.806 21.277 23.848 0.352 0.444 0.000


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Table 5A-20: Summary of Phase 1 Five Cell Cooling Tower Parameters and Water Vapour Emissions

Source identification # Unit 620ME (20) Cell Number 1 2 3 4 5 All Circulating Water Flow Rate Per Cell m3/h 2020 2020 2020 2020 2020 10,100 kg/h 2,020,000 2,020,000 2,020,000 2,020,000 2,020,000 10,100,000 Location UTM NAD 83 m N 5,968,444 5,968,444 5,968,444 5,968,444 5,968,444 - UTM NAD 83 m E 358,308 358,319 358,330 358,341 358,352 - Base Elevation m ASL 631 631 631 631 631 - Dimensions Cell Height (including fan stack) m 20 20 20 20 20 - Cell Top Internal Diameter m 8.6 8.6 8.6 8.6 8.6 - Cell Structure Height m 14.5 14.5 14.5 14.5 14.5 14.5 Cell Structure Width m 24.5 24.5 24.5 24.5 24.5 24.5 Cell Structure Length m 11 11 11 11 11 66 Exhaust Parameters Cell Exit Temperature °C 31 31 31 31 31 - Cell Exit Temperature K 304 304 304 304 304 - Cell Exit Velocity m/s 13 13 13 13 13 - Water Vapour Emission Rate kg/h 41,200 41,200 41,200 41,200 41,200 206,000

5A.4.1.5 Greenhouse Gas Emissions The greenhouse gas (GHG) emissions are mainly from two sources, namely CO2 from combustion sources and CH4 from combustion and fugitive sources. The total CO2 and CH4 emissions for Phase 1 are 8016 t/d and 0.44 t/d, respectively. The GHG emissions are normally reported as CO2-equivalents (CO2e) and the global warming potential for CH4 is 21. Therefore, the maximum CO2e emission rate for Phase 1, based on all the combustion equipment operating at full capacity, is 8025 t/d. Based on an annualized fuel use, however, the Phase 1 CO2e emission rate is 2448 kt/a (or 6707 t/d).

5A.4.2 Phase 2/3 Development The Phase 1 emission sources will generally continue to operate in a similar manner during Phase 2/3, and the Phase 2/3 emission profile includes the Phase 1 sources.

5A.4.2.1 Stack Emissions Table 5A-21 provides a summary of the emission sources associated with the Phase 2/3 conventional (25) and flare (5) stacks. The stack parameters were provided by Fluor Canada and the following additional (relative to Phase 1) comments can be made with respect to the parameters and emissions associated with the conventional stacks:

• The plant fuel gas changes for Phase 2/3, and the composition is given in Table 5A-10. This fuel gas is comprised of 31 percent methane, 20 percent ethane, and 29 percent hydrogen.



The total sulphur compound content has been reduced from 368 ppm (Phase 1) to 50 ppm (Phase 2/3).

• Phase 2/3 uses a gasifier instead of the SMR furnace to generate hydrogen that is used for upgrading. During normal Phase 2/3 operations, the SMR will not operate and will only be used as a backup for the gasifier. For this assessment, the SMR was conservatively assumed to operate continuously for Phase 2/3.

• The SO2, NOx, CO, PM2.5, VOC, and PAH emissions; and the stack exit temperatures and velocities emissions were estimated on the same basis as those for Phase 1.

• The five utility boilers (650MF1, 650MF2, 650MF3, 650MF4 and 650MF5) are expected to be used one week every two years at the maximum capacity of 583.5 GJ/h each. The rest of the time, the 650MF1, 650MF2 and 650MF3 boilers will be on standby; and the 650MF4 and 650MF5 boilers will be operating at a reduced capacity (i.e., ~47.9 GJ/h each). All boilers were assumed to operate on a continuous basis at maximum capacity for the purposes of this assessment to be conservative.

• The emissions for the three cogeneration units (GTG 1, GTG 2 and GTG 3) are shown for a maximum case due to additional fuel to the HRSG units. The normal fuel consumption for each HRSG is 281x103 m3/d, and for one week per year, this is expected to be increased to 281x103 m3/d. The HRSGs were assumed to operate on a continuous basis at maximum capacity in order to be conservative.

Tables 5A-22 to 5A-25 provide the emission parameters for the Phase 2/3 furnace, heater, and boiler stacks.

An additional thermal oxidizer will be required to service the two sulphur recovery units (SRU) and is the largest SO2 emission at the Upgrader. The annual and quarterly average sulphur recovery efficiencies are 99.8 percent and 99.5 percent, respectively. Table 5A-26 provides a summary of the Phase 2/3 thermal oxidizer parameters and emissions. The following are noted with respect to the thermal oxidizers:

• The annual average SO2 emission rate increases from 6.0 t/d (Phase 1) to 9.0 t/d (Phase 2/3).

• The maximum daily average SO2 emission rate has the potential to increase from 10 t/d (Phase 1) to 22.6 t/d (Phase 2/3). The Phase 2/3 emissions rate is based on both SRU trains simultaneously experiencing the lower 99.5 percent recovery efficiency.

• On a single thermal oxidizer basis, the maximum hourly average SO2 emission rate has the potential to increase from 0.583 t/h (Phase 1) to 0.661 t/h (Phase 2/3), based on the application of the “1.4 factor” discussed in the Phase 1 section. Given the occurrence of both Phase 2/3 SRUs resulting in simultaneous SO2 emissions of 0.661 t/h is unlikely to occur, the Phase 2/3 assessment is based on one thermal oxidizer emitting at the higher rate of 0.661 t/h, and the other at a more typical maximum rate of 0.472 t/h.

• The total reduced sulphur (TRS), H2S, COS, NOx, CO, PM2.5, VOC, PAH, and H2SO4 emissions were estimated in a manner similar to what was assumed for Phase 1.

The Phase 2/3 flares will be used in a similar manner as those for Phase 1, and the normal and upset emission parameters are provided in Tables 5A-27 and 5A-28, respectively. The following are noted relative to upset flaring:

• The largest SO2 emissions are associated with the H2S flare that services the two SRUs. Three intermittent emergency scenarios have been identified. Under these conditions, SO2


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emissions will not be occurring from the thermal oxidizer stacks. The natural gas addition amounts indicated in the table represents the maximum amount of natural gas that would be available at the plant.

• The acid gas stream might contain ammonia; the ammonia is assumed to be completely oxidized to NOx.

• The Phase 2/3 extreme high pressure (HP), low pressure (LP), and the South Tank farm flare events are similar to those associated with Phase 1.

• Two additional flaring events are provided for the Phase 2/3 flare stack; one of these events could result in SO2 emissions.

The “effective” flare parameters that can be used by the models are provided in Tables 5A-27 and 5A-28.

5A.4.2.2 Storage Tank Emissions Tables 5A-29 to 5A-31 identify the 25 storage tanks associated with Phase 2/3; the Phase 2/3 tank emissions were estimated in the same manner as those associated with Phase 1. The estimated fugitive VOC emissions due to the tanks are 148.7 t/a. The largest sources are the six Diluted Bitumen tanks (38.8 percent) and the two Untreated MGO tanks (39.1 percent). Tables 5A-29 to 5A-31 also provide representative emission for each tank. Emissions that fall in the “other” category (~0 to 58 percent) include the lighter hydrocarbons (C2 to C4) that do not have health consequences of significance.

5A.4.2.3 Process Area Emissions Large volumes of gases are handled in the different process areas, and fugitive emissions will result from the numerous valves, flanges, rotating seals, and drains that are associated with these areas. Table 5A-32 provides a summary of the process area parameters and emissions. The total VOC emissions due to these sources are 400.8 t/a.

5A.4.2.4 Cooling Tower Emissions Phase 2/3 of the Project will be serviced by the Phase 1 five cell forced draft cooling tower and an additional 16 cell forced draft cooling tower to provide the cooling requirements of the Project. For the five cell tower, the cooling water circulation rate for each cell is 2485 m3/h or 2,485,000 kg/h, and the expected water vapour release rate for each cell is 50,600 kg/h. For the 16 cell tower, the cooling water circulation rate for each cell is 2485 m3/h or 2,485,000 kg/h, and the expected water vapour release rate for each cell is 50,625 kg/h. Tables 5A-33 and 5A-34 provide the parameters associated with each cooling tower. The total water vapour emission due to the two cooling towers is 25512 t/d. For the purpose of comparison, the total water vapour emission from combustion sources is 19852 t/d. The distribution of water vapour emissions for Phase 2/3 is therefore 56 percent due to cooling towers and 44 percent due to combustion sources.

5A.4.2.5 Greenhouse Gas Emissions The greenhouse gas (GHG) emissions are mainly from two sources, namely CO2 from combustion sources, and CH4 from combustion and fugitive sources. The total CO2 and CH4 emissions for Phase 2/3 are 24977 t/d and 0.76 t/d, respectively. The GHG emissions are normally reported as CO2-equivalents (CO2e) and the global warming potential for CH4 is 21. Therefore, the maximum CO2e emission rate for Phase 2/3, based on all the combustion



equipment operating at full capacity, is 24993 t/d. Based on an annualized fuel use, however, the Phase 2/3 CO2e emission rate is 7769 kt/a (or 21285 t/d).

Table 5A-21: Summary of Phase 2/3 Emission Sources No. Identification Description

Conventional Stacks 1 300MF101 Fractionator Feed Heater (DRU) 21 310MF1 Fractionator Feed Heater (DRU #2) 22 320MF1 Feed Furnace (VDU) 3 330MF1 Coker Heater 1 4 330MF2 Coker Heater 2 23 330MF3 Coker Heater 3 5 400MF1 Main NHT Reactor Feed Furnace 6 410MF1A Train 1 Reactor Feed Furnace (MGO) 7 410MF1B Train 2 Reactor Feed Furnace (MGO) 44 410MF2 MGO Stabilizer Feed Furnace 24 420MF1A Train 1 Reactor Feed Furnace (HCU) 25 420MF1B Train 1 Reactor Feed Furnace (HCU) 10 522MF4 Thermal Oxidizer 11 522MF4A Thermal Oxidizer 8 450MF1 SMR Furnace 34 530MF1 Gasifier Superheater 26 350MF1 SDA Hot Oil Heater 13 650MF1 Utility Boiler 14 650MF2 Utility Boiler 43 650MF3 Utility Boiler 30 650MF4 1200# Utility Boiler 46 650MF5 1200# Utility Boiler 31 GTG #1 Turbine/HRSG 32 GTG #2 Turbine/HRSG 47 GTG #3 Turbine/HRSG

Flare Stacks 12 500MF1 H2S Flare 15 740MF1 HP Flare 45 740MF4 Phase 2/3 Flare 16 740MF2 LP Flare 19 740MF3 South Tank Farm


December 2006

Page 5A-33

Table 5A-22: Phase 2/3 Combustion Source Parameters and Emissions (Stacks 1, 21, 22, 3, 4, 23)

Source identification # 1 21 22 3 4 23 Unit Identification # 300MF101 310MF101 320MF1 330MF1 330MF2 330MF3

Unit Name/Description Fractionator

Feed Heater (DRU)

Fractionator Feed

Heater (DRU #2)

Feed Furnace (VDU)

Coker heater 1

Coker heater 2

Coker heater 3

Temporal Variation Continuous Continuous Continuous Continuous Continuous Continuous Rating Heat Input (FIRED) GJ/h 309 328 399 273 273 273 Fuel Type Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Consumption 103 Nm3/d 166 177 215 147 147 147 Stack Location UTM NAD 83 m N 5,967,482 5,968,593 5,968,592 5,967,626 5,967,601 5,967,563 UTM NAD 83 m E 357,868 358,009 358,041 358,210 358,209 358,208 Base Elevation of Stack m ASL 633 633 633 633 633 633 Stack Dimensions Height m 35 35 35 65 65 65 Inside Tip Diameter m 1.95 2.00 2.21 2.16 2.16 2.16 Exhaust Parameters Exit Velocity m/s 15 15 15 11.3 11.3 11.3 Exit Temperature K 448 448 448 473 473 473 Emission Rates CO2 t/d 285.5 304.4 369.7 252.8 252.8 252.8 H2O t/d 248.9 265.4 322.3 220.4 220.4 220.4 SO2 t/d 0.024 0.025 0.031 0.021 0.021 0.021 NOx t/d 0.288 0.306 0.372 0.254 0.254 0.254 CO t/d 0.044 0.047 0.057 0.039 0.039 0.039 VOC t/d 0.0161 0.0172 0.0209 0.0143 0.0143 0.0143 PM2.5 t/d 0.00558 0.00594 0.00722 0.00494 0.00494 0.00494 Acenaphthene Group t/a 0.0000365 0.0000389 0.0000473 0.0000323 0.0000323 0.0000323 Acetaldehyde t/a 0.0536 0.0571 0.0694 0.0474 0.0474 0.0474 Acrolein t/a 0.0238 0.0254 0.0308 0.0211 0.0211 0.0211 Anthracene t/a 0.00000257 0.00000274 0.00000333 0.00000228 0.00000228 0.00000228 Benzaldehyde t/a 0.0291 0.0311 0.0377 0.0258 0.0258 0.0258 Benzene t/a 0.0428 0.0457 0.0555 0.0379 0.0379 0.0379 Benzo(a)anthracene t/a 0.00000305 0.00000325 0.00000395 0.0000027 0.0000027 0.0000027 Benzo(a)pyrene t/a 0.00000129 0.00000137 0.00000166 0.00000114 0.00000114 0.00000114 Benzo(b)fluoranthene t/a 0.00000193 0.00000206 0.0000025 0.00000171 0.00000171 0.00000171 Benzo(g,h,i)perylene t/a 0.00000152 0.00000162 0.00000197 0.00000135 0.00000135 0.00000135 Benzo(k)fluoranthene t/a 0.00000193 0.00000206 0.0000025 0.00000171 0.00000171 0.00000171 C5-C8 Aliphatics t/a 2.78 2.97 3.61 2.47 2.47 2.47 C17-C34 Aromatics t/a 0.0000191 0.0000203 0.0000247 0.0000169 0.0000169 0.0000169 Chrysene t/a 0.00000196 0.00000209 0.00000254 0.00000174 0.00000174 0.00000174 Dibenz(a,h)anthracene t/a 0.00000129 0.00000137 0.00000166 0.00000114 0.00000114 0.00000114 Dichlorobenzene t/a 0.00129 0.00137 0.00166 0.00114 0.00114 0.00114 Ethylbenzene t/a 0.00241 0.00257 0.00312 0.00213 0.00213 0.00213 Fluoranthene t/a 0.0000192 0.0000204 0.0000248 0.000017 0.000017 0.000017 Fluorene t/a 0.00000623 0.00000665 0.00000807 0.00000552 0.00000552 0.00000552 Formaldehyde t/a 0.72 0.767 0.932 0.637 0.637 0.637 Hexane t/a 1.93 2.06 2.5 1.71 1.71 1.71 Indeno(1,2,3-cd)pyrene t/a 0.00000193 0.00000206 0.0000025 0.00000171 0.00000171 0.00000171 2-Methylnaphthalene t/a 0.0000257 0.0000274 0.0000333 0.0000228 0.0000228 0.0000228 Naphthalene t/a 0.00265 0.00282 0.00343 0.00234 0.00234 0.00234 Phenanthrene t/a 0.0000508 0.0000541 0.0000658 0.000045 0.000045 0.000045 Pyrene t/a 0.0000124 0.0000132 0.0000161 0.000011 0.000011 0.000011 Toluene t/a 0.08 0.0853 0.104 0.0709 0.0709 0.0709 Xylenes t/a 0.0318 0.0339 0.0412 0.0282 0.0282 0.0282



Table 5A-23: Phase 2/3 Combustion Source Parameters and Emissions (Stacks 8, 5, 6, 7, 44, 24, 25)

Source identification # 8 5 6 7 44 24 25 Unit Identification # 450MF1 400MF1 410MF1A 410MF1B 410MF2 420MF1A 420MF1B

Unit Name/Description SMR Furnace

Main NHT Reactor Feed

Furnace

Train 1 Reactor

Feed Furnace (MGO)

Train 2 Reactor

Feed Furnace (MGO)

MGO Stabilizer

Feed Furnace

Train 1 Reactor

Feed Furnace (HCU)

Train 2 Reactor

Feed Furnace (HCU)

Temporal Variation 2 wks / y Continuous Continuous Continuous Continuous Continuous Continuous Rating Heat Input (FIRED) GJ/h 1361 40.6 58.6 58.6 90.8 96.6 96.6

Fuel Type

PSA Tail Gas + Fuel

Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Consumption 103 Nm3/d 2337 22.0 32.0 32.0 49.0 52.0 52.0 Stack Location UTM NAD 83 m N 5,968,024 5,967,651 5,967,783 5,967,783 5,967,842 5,968,598 5,968,599 UTM NAD 83 m E 357,916 357,911 357,861 357,846 357,849 357,883 357,850 Base Elevation of Stack m ASL 633 633 633 633 633 633 633 Stack Dimensions Height m 38 35 35 35 35 35 35 Inside Tip Diameter m 4.03 0.71 0.85 0.85 1.06 1.09 1.09 Exhaust Parameters Exit Velocity m/s 15.0 14.7 14.8 14.8 14.8 15.0 15.0 Exit Temperature K 422 448 448 448 448 448 448 Emission Rates CO2 t/d 4018.8 37.8 55.0 55.0 84.3 89.4 89.4 H2O t/d 3503.7 33.0 48.0 48.0 73.5 78.0 78.0 SO2 t/d 0.044 0.003 0.004 0.004 0.007 0.007 0.007 NOx t/d 1.646 0.025 0.036 0.036 0.056 0.060 0.060 CO t/d 0.200 0.006 0.008 0.008 0.013 0.014 0.014 VOC t/d 0.227 0.00214 0.00311 0.00311 0.00476 0.00506 0.00506 PM2.5 t/d 0.0785 0.000739 0.00107 0.00107 0.00165 0.00175 0.00175 Acenaphthene Group t/a 0.000514 0.0000048 0.00000704 0.00000704 0.0000108 0.0000114 0.0000114 Acetaldehyde t/a 0.754 0.0071 0.0103 0.0103 0.0158 0.0168 0.0168 Acrolein t/a 0.335 0.00315 0.00458 0.00458 0.00702 0.00745 0.00745 Anthracene t/a 0.0000362 0.00000034 0.00000050 0.00000050 0.00000076 0.00000081 0.00000081 Benzaldehyde t/a 0.41 0.00386 0.00562 0.00562 0.0086 0.00913 0.00913 Benzene t/a 0.603 0.00568 0.00826 0.00826 0.0126 0.0134 0.0134 Benzo(a)anthracene t/a 0.000043 0.000000405 0.00000059 0.00000059 0.00000090 0.00000096 0.00000096 Benzo(a)pyrene t/a 0.0000181 0.00000017 0.00000024 0.00000024 0.00000038 0.00000040 0.000000403Benzo(b)fluoranthene t/a 0.0000271 0.000000256 0.00000037 0.00000037 0.00000057 0.00000060 0.000000604Benzo(g,h,i)perylene t/a 0.0000214 0.000000202 0.00000029 0.00000029 0.00000045 0.000000476 0.000000476Benzo(k)fluoranthene t/a 0.0000271 0.000000256 0.00000037 0.00000037 0.00000057 0.0000006 0.0000006 C5-C8 Aliphatics t/a 39.2 0.369 0.537 0.537 0.822 0.872 0.872 C17-C34 Aromatics t/a 0.000268 0.00000253 0.00000368 0.00000368 0.00000563 0.00000597 0.00000597 Chrysene t/a 0.0000276 0.00000026 0.00000038 0.00000038 0.00000058 0.000000614 0.000000614Dibenz(a,h)anthracene t/a 0.0000181 0.00000017 0.00000025 0.00000025 0.00000038 0.000000403 0.000000403Dichlorobenzene t/a 0.0181 0.00017 0.000248 0.000248 0.000379 0.000403 0.000403 Ethylbenzene t/a 0.0339 0.000319 0.000465 0.000465 0.000711 0.000755 0.000755 Fluoranthene t/a 0.00027 0.00000254 0.0000037 0.0000037 0.00000566 0.00000601 0.00000601 Fluorene t/a 0.0000878 0.000000826 0.0000012 0.0000012 0.00000184 0.00000195 0.00000195 Formaldehyde t/a 10.1 0.0954 0.139 0.139 0.212 0.225 0.225 Hexane t/a 27.1 0.256 0.372 0.372 0.569 0.604 0.604 Indeno(1,2,3-cd)pyrene t/a 0.0000271 0.000000256 0.00000037 0.00000037 0.00000057 0.000000604 0.0000006042-Methylnaphthalene t/a 0.000362 0.00000341 0.00000496 0.00000496 0.00000759 0.00000805 0.00000805 Naphthalene t/a 0.0372 0.000351 0.00051 0.00051 0.000781 0.000829 0.000829 Phenanthrene t/a 0.000715 0.00000673 0.00000979 0.00000979 0.000015 0.0000159 0.0000159 Pyrene t/a 0.000175 0.00000165 0.0000024 0.0000024 0.00000367 0.00000389 0.00000389 Toluene t/a 1.13 0.0106 0.0154 0.0154 0.0236 0.0251 0.0251 Xylenes t/a 0.448 0.00422 0.00613 0.00613 0.00939 0.00996 0.00996


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Table 5A-24: Phase 2/3 Combustion Source Parameters and Emissions (Stacks 34, 26, 13, 14, 43)

Source identification # 34 26 13 14 43 Unit Identification # 530MF1 350MF1 650MF1 650MF2 650MF3 Unit Name/Description Superheater Hot Oil Heater Utility Boiler Utility Boiler Utility Boiler Temporal Variation Continuous Continuous 1 wk / 2 yr 1 wk / 2 yr 1 wk / 2 yr Rating Heat Input (FIRED) GJ/h 173.6 295.7 583.5 583.5 583.5 Fuel Type Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Consumption 103 Nm3/d 94 159.0 314 314 314 Stack Location UTM NAD 83 m N 5,968,863 5,968,718 5,968,267 5,968,266 5,968,266 UTM NAD 83 m E 358,404 358,246 357,860 357,873 357,885 Base Elevation of Stack m ASL 633 633 633 633 633 Stack Dimensions Height m 35 35 40 40 40 Inside Tip Diameter m 1.6 1.90 2.11 2.11 2.11 Outside Tip Diameter m 1.72 2.02 2.23 2.23 2.23 Exhaust Parameters Exit Velocity m/s 15 15 24 24 24 Exit Temperature K 448 448 448 448 448 Emission Rates CO2 t/d 161.6 273.4 540.0 540.0 540.0 H2O t/d 140.9 238.4 470.8 470.8 470.8 SO2 t/d 0.013 0.023 0.045 0.045 0.045 NOx t/d 0.162 0.276 0.544 0.544 0.544 CO t/d 0.025 0.042 0.083 0.083 0.083 VOC t/d 0.00914 0.0155 0.0305 0.0305 0.0305 PM2.5 t/d 0.00316 0.00534 0.0105 0.0105 0.0105 Acenaphthene Group t/a 0.0000207 0.000035 0.0000691 0.0000691 0.0000691 Acetaldehyde t/a 0.0303 0.0513 0.101 0.101 0.101 Acrolein t/a 0.0135 0.0228 0.045 0.045 0.045 Anthracene t/a 0.00000146 0.00000246 0.00000486 0.00000486 0.00000486 Benzaldehyde t/a 0.0165 0.0279 0.0551 0.0551 0.0551 Benzene t/a 0.0243 0.041 0.081 0.081 0.081 Benzo(a)anthracene t/a 0.00000173 0.00000292 0.00000577 0.00000577 0.00000577 Benzo(a)pyrene t/a 0.000000728 0.00000123 0.00000243 0.00000243 0.00000243 Benzo(b)fluoranthene t/a 0.00000109 0.00000185 0.00000365 0.00000365 0.00000365 Benzo(g,h,i)perylene t/a 0.000000861 0.00000146 0.00000288 0.00000288 0.00000288 Benzo(k)fluoranthene t/a 0.00000109 0.00000185 0.00000365 0.00000365 0.00000365 C5-C8 Aliphatics t/a 1.58 2.67 5.27 5.27 5.27 C17-C34 Aromatics t/a 0.0000108 0.0000183 0.0000361 0.0000361 0.0000361 Chrysene t/a 0.00000111 0.00000188 0.00000371 0.00000371 0.00000371 Dibenz(a,h)anthracene t/a 0.000000728 0.00000123 0.00000243 0.00000243 0.00000243 Dichlorobenzene t/a 0.000728 0.00123 0.00243 0.00243 0.00243 Ethylbenzene t/a 0.00136 0.00231 0.00456 0.00456 0.00456 Fluoranthene t/a 0.0000109 0.0000184 0.0000363 0.0000363 0.0000363 Fluorene t/a 0.00000353 0.00000597 0.0000118 0.0000118 0.0000118 Formaldehyde t/a 0.408 0.689 1.36 1.36 1.36 Hexane t/a 1.09 1.85 3.65 3.65 3.65 Indeno(1,2,3-cd) pyrene t/a 0.00000109 0.00000185 0.00000365 0.00000365 0.00000365 2-Methylnaphthalene t/a 0.0000146 0.0000246 0.0000486 0.0000486 0.0000486 Naphthalene t/a 0.0015 0.00253 0.005 0.005 0.005 Phenanthrene t/a 0.0000287 0.0000486 0.000096 0.000096 0.000096 Pyrene t/a 0.00000704 0.0000119 0.0000235 0.0000235 0.0000235 Toluene t/a 0.0453 0.0766 0.151 0.151 0.151 Xylenes t/a 0.018 0.0305 0.0602 0.0602 0.0602



Table 5A-25: Phase 2/3 Combustion Source Parameters and Emissions (Stacks 30, 46, 31, 32, 47)

Source identification # 30 46 31 32 47 Unit Identification # 650MF4 650MF5 GTG 1 GTG 2 GTG 2

Unit Name/Description 1200# Utility Boiler

1200# Utility Boiler Turbine HRSG Turbine HRSG Turbine HRSG

Temporal Variation 1 wk / 2 yr 1 wk / 2 yr 1 wk / yr 1 wk / yr 1 wk / yr Rating Heat Input (FIRED) GJ/h 109.2 109.2 - - - Fuel Type Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Gas Fuel Consumption 103 Nm3/d 59 59 1671 886 1671 886 1671 886 Stack Location UTM NAD 83 m N 5,968,910 5,968,909 5,968,527 5,968,550 5,968,491 UTM NAD 83 m E 358,186 358,194 357,702 357,703 357,700 Base Elevation of Stack m ASL 633 633 633 633 633 Stack Dimensions Height m 40 40 30 30 30 Inside Tip Diameter m 0.91 0.91 4.1 4.1 4.10 Outside Tip Diameter m 1.03 1.03 4.24 4.24 4.24 Exhaust Parameters Exit Velocity m/s 24 24 20 20 20 Exit Temperature K 448 448 448 448 448 Emission Rates CO2 t/d 101.5 101.5 4397.1 4397.1 4397.1 H2O t/d 88.5 88.5 3833.5 3833.5 3833.5 SO2 t/d 0.0084 0.0084 0.232 0.232 0.232 Nox t/d 0.102 0.102 2.47 2.47 2.47 CO t/d 0.016 0.016 2.24 2.24 2.24 VOC t/d 0.00574 0.00574 0.149 0.149 0.149 PM2.5 t/d 0.00198 0.00198 0.087 0.087 0.087 Acenaphthene Group t/a 0.000013 0.000013 0.0024 0.0024 0.0024 Acetaldehyde t/a 0.019 0.019 5.8 5.8 5.8 Acrolein t/a 0.00845 0.00845 0.874 0.874 0.874 Anthracene t/a 0.000000914 0.000000914 0.00166 0.00166 0.00166 1,3-Butadiene t/a 0.00 0.00 0.00473 0.00473 0.00473 Benzaldehyde t/a 0.0104 0.0104 0.155 0.155 0.155 Benzene t/a 0.0152 0.0152 1.30 1.30 1.30 Benzo(a)anthracene t/a 0.00000108 0.00000108 0.00146 0.00146 0.00146 Benzo(a)pyrene t/a 0.000000457 0.000000457 0.000994 0.000994 0.000994 Benzo(b)fluoranthene t/a 0.000000685 0.000000685 0.000735 0.000735 0.000735 Benzo(e)pyrene t/a 0.00 0.00 0.0000079 0.0000079 0.0000079 Benzo(g,h,i)perylene t/a 0.000000541 0.000000541 0.000898 0.000898 0.000898 Benzo(k)fluoranthene t/a 0.000000685 0.000000685 0.000735 0.000735 0.000735 2-Chloronaphthalene t/a 0.00 0.00 0.00000506 0.00000506 0.00000506 C5-C8 Aliphatics t/a 0.99 0.99 14.86 14.86 14.86 C17-C34 Aromatics t/a 0.00000678 0.00000678 0.000112 0.000112 0.000112 Chrysene t/a 0.000000697 0.000000697 0.00163 0.00163 0.00163 Dibenz(a,h)anthracene t/a 0.000000457 0.000000457 0.00145 0.00145 0.00145 Dichlorobenzene t/a 0.000457 0.000457 0.00686 0.00686 0.00686 Ethylbenzene t/a 0.000857 0.000857 0.627 0.627 0.627 Fluoranthene t/a 0.00000681 0.00000681 0.00339 0.00339 0.00339 Fluorene t/a 0.00000222 0.00000222 0.00497 0.00497 0.00497 Formaldehyde t/a 0.256 0.256 77.91 77.91 77.91 Hexane t/a 0.685 0.685 14.41 14.41 14.41 Indeno(1,2,3-cd)pyrene t/a 0.000000685 0.000000685 0.00146 0.00146 0.00146 2-Methylnaphthalene t/a 0.00000914 0.00000914 0.000205 0.000205 0.000205 Naphthalene t/a 0.00094 0.00094 0.0991 0.0991 0.0991 Phenanthrene t/a 0.000018 0.000018 0.0256 0.0256 0.0256 Propylene Oxide t/a 0.00 0.00 0.633 0.633 0.633 Pyrene t/a 0.00000442 0.00000442 0.00144 0.00144 0.00144 Toluene t/a 0.0284 0.0284 2.24 2.24 2.24 Xylenes t/a 0.0113 0.0113 0.874 0.874 0.874


December 2006

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Table 5A-26: Phase 2/3 Thermal Oxidizer Parameters and Emissions Source identification # 10 11 Unit Identification # 522MF4 522MF4A Unit Name/Description Thermal oxidizer Thermal oxidizer Temporal Variation Continuous Continuous Sulphur Recovery Inlet Sulphur Equivalent t/d 1132.5 1132.5 Annual S Recovery % 99.8 99.8 Quarterly S Recovery % 99.5 99.5 Stack Location UTM NAD 83 m N 5,967,947 5,968,148 UTM NAD 83 m E 358,330 358,339 Base Elevation of Stack m ASL 633 633 Stack Dimensions Height Above Base Elevation m 90 90 Inside Tip Diameter m 2.98 2.98 Exhaust Parameters Exit Velocity m/s 25 25 Exit Temperature K 811.15 811.15 Emission Rates CO2 t/d 1679.2 1679.2 H2O t/d 502.9 502.9 SO2 average t/d 4.5 4.5 SO2 24 h max t/d 11.3 11.3 SO2 1 h t/h 0.47 0.47 SO2 1h max t/h 0.66 0.47 TRS t/d 0.154 0.154 H2S t/d 0.077 0.077 COS t/d 0.136 0.136 NOx t/d 0.520 0.520 CO t/d 0.950 0.950 VOC t/d 0.0204 0.0204 PM2.5 t/d 0.00706 0.00706 Acenaphthene Group t/a 0.0000462 0.0000462 Acetaldehyde t/a 0.0678 0.0678 Acrolein t/a 0.0301 0.0301 Anthracene t/a 0.00000325 0.00000325 Benzaldehyde t/a 0.0369 0.0369 Benzene t/a 0.0542 0.0542 Benzo(a)anthracene t/a 0.00000386 0.00000386 Benzo(a)pyrene t/a 0.00000163 0.00000163 Benzo(b)fluoranthene t/a 0.00000244 0.00000244 Benzo(g,h,i)perylene t/a 0.00000192 0.00000192 Benzo(k)fluoranthene t/a 0.00000244 0.00000244 C5-C8 Aliphatics t/a 3.52 3.52 C17-C34 Aromatics t/a 0.0000241 0.0000241 Chrysene t/a 0.00000248 0.00000248 Dibenz(a,h)anthracene t/a 0.00000163 0.00000163 Dichlorobenzene t/a 0.00163 0.00163 Ethylbenzene t/a 0.00305 0.00305 Fluoranthene t/a 0.0000243 0.0000243 Fluorene t/a 0.00000789 0.00000789 Formaldehyde t/a 0.911 0.911 Hexane t/a 2.44 2.44 Indeno(1,2,3-cd)pyrene t/a 0.00000244 0.00000244 2-Methylnaphthalene t/a 0.0000325 0.0000325 Naphthalene t/a 0.00335 0.00335 Phenanthrene t/a 0.0000643 0.0000643 Pyrene t/a 0.0000157 0.0000157 Toluene t/a 0.101 0.101 Xylenes t/a 0.0403 0.0403 Sulphuric Acid t/a 2.52 2.52



Table 5A-27: Phase 2/3 Flare Stack Parameters and Emissions (Normal) Source identification # 12 15 16 19 45 Unit Identification # 500MF1 740MF1 740MF2 740MF3 740MF4

Unit Name/Description H2S Flare HP Flare LP Flare South Tank Farm Flare

Phase 2/3 Flare

Event Normal Normal Normal Normal Normal Frequency Continuous Continuous Continuous Continuous Continuous Duration Continuous Continuous Continuous Continuous Continuous Flow Rate Inlet Gas Stream Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Inlet Flow Rate 103 Nm3/d 1.2 2.8 3.5 0.08 5.2 Stack Location UTM NAD 83 m N 5968088 5967833 5967606 5965904 5969054 UTM NAD 83 m E 358670 358662 358655 357588 358615 Base Elevation of Stack m ASL 633 631 631 642 633 Stack Dimensions Height Above Base Elevation m 90 65 116 20 60 Inside Tip Diameter m 0.81 1.37 1.52 0.2 1.72 Effective Parameters Stack Height m 91.2 66.8 118 20.3 62.4 Stack Diameter m 7.87 13.3 14.8 1.94 16.7 Exit Velocity m/s 0.027 0.022 0.022 0.029 0.026 Exit Temperature K 1273 1273 1273 1273 1273 Emission Rates CO2 t/d 2.89 6.75 8.44 0.193 12.5 H2O t/d 2.21 5.16 6.45 0.147 9.58 SO2 t/d 0.00126 0.00294 0.00367 0.000084 0.00546 NOx t/d 0.00147 0.00343 0.00429 0.0000981 0.00638 CO t/d 0.00178 0.00416 0.0052 0.000119 0.00772 VOC t/d 0.00303 0.00707 0.00884 0.000202 0.0131 PM2.5 t/d 0.0000403 0.000094 0.000118 0.00000269 0.000175 Acenaphthene Group t/a 0.000867 0.00202 0.00253 0.0000578 0.00376 Acetaldehyde t/a 0.00506 0.0118 0.0147 0.000337 0.0219 Acrolein t/a 0.000722 0.00169 0.00211 0.0000482 0.00313 Anthracene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Benzene t/a 0.00665 0.0155 0.0194 0.000443 0.0288 Benzo(a)anthracene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Benzo(a)pyrene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Benzo(b)fluoranthene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Benzo(e)pyrene t/a 0.000000579 0.00000135 0.00000169 0.0000000386 0.00000251 Benzo(g,h,i)perylene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Benzo(k)fluoranthene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 C17-C34 Aromatics t/a 0.000000579 0.00000135 0.00000169 0.0000000386 0.00000251 Chrysene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Dibenz(a,h)anthracene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Fluoranthene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Fluorene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Formaldehyde t/a 0.522 1.22 1.52 0.0348 2.26 Indeno(1,2,3-cd)pyrene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 2-Methylnaphthalene t/a 0.000127 0.000296 0.00037 0.00000847 0.00055 Naphthalene t/a 0.274 0.64 0.799 0.0183 1.19 Phenanthrene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Pyrene t/a 0.000434 0.00101 0.00126 0.0000289 0.00188 Toluene t/a 0.844 1.97 2.46 0.0563 3.66 Xylenes t/a 0.00616 0.0144 0.018 0.000411 0.0267


December 2006

Page 5A-39

Table 5A-28: Phase 2/3 Flare Stack Parameters and Emissions (Emergency) Source identification # 12 15 16 19 45 Unit Identification # 500MF1 740MF1 740MF2 740MF3 740MF4 Unit Name/Description H2S Flare HP Flare LP Flare South Tank Farm Flare Phase 2/3 Flare

Event Emergency – Total Power Failure Emergency – Fire

Emergency – Partial Power

Failure Emergency Fire case Fire case Maximum Emergency

Frequency once / 2 y once / 25 y once / 2 y once / 5 y once / 5 y once / 50 y once / y once / 50 y Duration 30 minutes 30 minutes 30 minutes 30 minutes 30 minutes 60 minutes 2 days 30 minutes Flow Rate Inlet Gas Stream Acid Gas Acid Gas Acid Gas Inlet Flow Rate 103 Nm3/d 5328 2207 3706 16016 9224 211 5864 1096 Supplemental Natural Gas Flow Rate 103 Nm3/d 1120 1120 1120 0.0 0.0 0.0 1120 432 Inlet Gas Composition H2 Mole % 0.03 0.10 1.30 74.00 1.80 0.0 41.0 47.2 N2 Mole % 0.00 0.00 3.39 0.10 0.00 0.0 0.5 0.3 Ar Mole % 0.00 0.00 0.00 0.10 0.00 0.0 0.0 0.1 CO Mole % 0.00 0.00 0.00 0.80 0.00 0.0 4.1 0.9 CO2 Mole % 0.13 0.40 36.26 0.00 0.00 0.0 35.2 26.6 H2S Mole % 26.13 73.30 48.08 5.00 6.00 0.0 0.0 1.3 COS Mole % 0.00 0.00 0.41 0.00 0.00 0.0 0.0 0.0 C1 Mole % 0.01 0.10 1.48 8.00 11.60 0.0 8.7 0.7 C2 Mole % 0.01 0.00 0.85 4.00 7.20 0.0 5.8 0.3 C3 Mole % 0.00 0.00 0.17 2.00 4.80 0.0 3.8 6.1 C4 Mole % 0.00 0.00 0.04 3.00 3.20 100.0 0.4 2.3 C5+ Mole % 0.00 0.00 0.00 2.00 44.10 0.0 0.3 0.9 H2O Mole % 63.41 25.90 5.10 1.00 21.20 0.0 0.2 13.3 NH3 Mole % 9.43 0.20 2.92 0.00 0.00 0.0 0.0 0.0 Total Mole % 99.15 100.00 100.00 100.00 99.90 100.00 100.00 100.00 Acid Gas Properties Molecular Mass kg/kmole 21.99 29.87 35.33 9.96 45.72 16.04 21.76 20.46 Heating Value MJ/m3 7.37 16.14 12.38 21.65 78.40 112.03 14.80 14.63 Combined Gas Properties Molecular Mass kg/kmole 21.26 25.80 31.26 9.96 45.72 16.04 21.12 19.70 Heating Value MJ/m3 12.05 22.26 17.47 21.65 78.40 112.03 17.93 20.19 Stack Location UTM NAD 83 m N 5,968,088 5,967,833 5,967,606 5,965,904 5,969,054 UTM NAD 83 m E 358,670 358,662 358,655 357,588 358,615 Base Elevation of Stack m ASL 633 631 631 642 633 Stack Dimensions Height Above Base Elevation m 90 65 116 20 60 Inside Tip Diameter m 0.81 1.37 1.52 0.2 1.72 Effective Parameters Stack Height m 133.9 132.9 135.6 154.6 243.4 44.8 115.1 88.2 Stack Diameter m 4.66 6.34 5.61 10.57 22.31 3.51 12.07 12.81 Exit Velocity m/s 144.8 74.73 108.4 125.75 58.834 77.735 34.79 7.61 Exit Temperature K 1273 1273 1273 1273 1273 1273 1273 1273 Emission Rate SO2 (equivalent 1-h) t/h 76.98 89.45 98.52 44.28 30.60 0.0 0.0 0.788



Table 5A-29: Summary of Phase 2/3 Tank Parameters and Emissions (Tanks 36, 37, 38, 83, 84, 18) Source identification # 36 37 38 83 39 84 18 Process Area # 710MD1A 710MD1B 710MD1C 710MD1C 710MD1C 710MD1C 710MD2A 710MD2B 710MD3A

Unit Name/Description Diluted Bitumen

Diluted Bitumen

Diluted Bitumen

Diluted Bitumen

Diluted Bitumen

Diluted Bitumen Diluent Diluent Treated

Naphtha Tank Farm South South South South South South South South South

m E 357,311 357,307 357,302 357,298 357,294 357,289 357,567 357,556 357,625 Volume Source Locations m N 5,966,408 5,966,264 5,966,120 5,965,976 5,965,832 5,965,688 5,966,362 5,966,112 5,966,619 Base Elevation of Source m ASL 642 642 642 642 642 642 642 642 642 Release Dimensions Tank Height m 19.5 19.5 19.5 19.5 19.5 19.5 18.3 18.3 17.1 Tank Diameter m 61.2 61.2 61.2 61.2 61.2 61.2 70.9 70.9 43.2 Sigma Y m 14.23 14.23 14.23 14.23 14.23 14.23 16.49 16.49 10.05 Sigma Z m 9.07 9.07 9.07 9.07 9.07 9.07 8.51 8.51 7.95 Emission Rates Total VOC t/a 9.62 9.62 9.62 9.62 9.62 9.62 5.69 5.69 2.46 1,3-butadiene t/a 0.3072 0.3072 0.3072 0.3072 0.3072 0.3072 0.121 0.1211 0.0524 Aliphatic aldehydes t/a 0.0200 0.0200 0.0200 0.0200 0.0200 0.0200 0.0355 0.0355 0.0154 Aliphatic ketones t/a 0.00086 0.00086 0.00086 0.00086 0.00086 0.00086 0.0135 0.0135 0.0058 Benzene t/a 0.125 0.125 0.125 0.125 0.125 0.125 0.104 0.104 0.0448 C5-C8 aliphatic group t/a 2.053 2.053 2.053 2.053 2.053 2.053 1.45 1.45 0.627 C9-C16 aliphatic group t/a 0.0422 0.0422 0.0422 0.0422 0.0422 0.0422 0.0999 0.0999 0.0433 CS2 t/a 0.00098 0.00098 0.00098 0.00098 0.00098 0.00098 0.0013 0.0013 0.00058 Ethylbenzene t/a 0.0010 0.0010 0.0010 0.0010 0.0010 0.0010 0.0129 0.0129 0.0056 Hexane t/a 0.215 0.215 0.215 0.215 0.215 0.2145 0.109 0.109 0.0471 Hydrogen sulphide t/a 0.0033 0.0033 0.0033 0.0033 0.0033 0.0033 0.1002 0.1002 0.0434 Isopropylbenzene t/a 0.00 0.00 0.00 0.00 0.00 0.00 0.00017 0.00017 0.0000745 Mercaptan group t/a 0.0052 0.0052 0.0052 0.0052 0.0052 0.0052 0.0056 0.0056 0.0024 Other (C2 to C4) t/a 4.91 4.91 4.91 4.91 4.91 4.91 2.22 2.22 0.963 Thiophene group t/a 0.0124 0.0124 0.0124 0.0124 0.0124 0.0124 0.013 0.013 0.0056 Toluene t/a 0.155 0.155 0.155 0.155 0.155 0.155 0.206 0.206 0.089 Xylenes t/a 0.00069 0.00069 0.00069 0.00069 0.00069 0.00069 0.0155 0.0155 0.0067 Methane t/a 1.77 1.77 1.77 1.77 1.77 1.77 1.177 1.177 0.51


December 2006

Page 5A-41

Table 5A-30: Summary of Phase 2/3 Tank Parameters and Emissions (Tanks 85, 41, 86, 42, 44, 87, 45) Source identification # 85 41 86 42 44 87 45 Process Area # 710MD3B 710MD4A 710MD4B 521MD2 720MD1A 720MD1B 720MD2A

Unit Name/Description Treated Naphtha Treated MGO Treated MGO Liquid Sulphur Storage

Untreated Naphtha

Untreated Naphtha

Untreated MGO

Tank Farm South South South South North North North m E 357,531 357,346 357,091 357,890 357,661 357,658 357,420

Volume Source Locations m N 5,966,622 5,966,654 5,966,662 5,966,566 5,967,616 5,967,502 5,967,697 Base Elevation of Source m ASL 642 642 642 642 633 633 633 Release Dimensions Tank Height m 17.1 19.5 19.5 9.0 17.1 17.1 19.5 Tank Diameter m 43.2 61.6 61.6 20.2 40.8 40.8 63.9 Sigma Y m 10.05 14.33 14.33 4.70 9.49 9.49 14.86 Sigma Z m 7.95 9.07 9.07 4.19 7.95 7.95 9.07 Emission Rates Total VOC t/a 2.46 5.09 5.09 0.088 0.47 0.47 29.09 1,3-butadiene t/a 0.0524 0.00 0.00 0.00 0.0106 0.0106 0.00 Aliphatic alcohols t/a 0.00 0.0246 0.0246 0.00 0.0012 0.0012 0.00 Aliphatic aldehydes t/a 0.0154 0.00 0.00 0.00 0.00 0.00 0.00 Aliphatic ketones t/a 0.0058 0.00 0.00 0.00 0.0022 0.0022 0.00 Benzene t/a 0.0448 0.00 0.00 0.00 0.0036 0.0036 0.494 C17+ aliphatic group t/a 0.00 0.0303 0.0303 0.00 0.0032 0.0032 0.46 C5-C8 aliphatic group t/a 0.627 0.026 0.026 0.00 0.0217 0.0217 4.14 C9-C16 aliphatic group t/a 0.0433 2.47 2.47 0.00 0.111 0.111 2.59 C9-C16 aromatic group t/a 0.00 0.143 0.143 0.00 0.0136 0.0136 0.0823 CS2 t/a 0.00058 0.00 0.00 0.000017 0.00 0.00 0.0573 Ethylbenzene t/a 0.0056 0.0138 0.0138 0.00 0.0026 0.0026 0.603 Hexane t/a 0.0471 0.00 0.00 0.00 0.0023 0.0023 0.663 Hydrogen sulphide t/a 0.0434 0.00 0.00 0.0088 0.00 0.00 0.209 Isopropylbenzene t/a 0.0000745 0.00 0.00 0.00 0.0012 0.0012 0.0743 Mercaptan group t/a 0.0024 0.00 0.00 0.00 0.00 0.00 0.00 Other (C2 to C4) t/a 0.963 1.134 1.134 0.00 0.272 0.272 2.596 Thiophene group t/a 0.0056 0.00 0.00 0.00 0.0034 0.0034 0.188 Toluene t/a 0.0891 0.662 0.662 0.00 0.0095 0.0095 1.835 Xylenes t/a 0.0067 0.0771 0.0771 0.00 0.0119 0.0119 1.57 Methane t/a 0.51 0.499 0.499 0.0000057 0.00 0.00 13.52



Table 5A-31: Summary of Phase 2/3 Tank Parameters and Emissions (Tanks 46, 47, 48, 49, 50, 51, 52, 88) Source identification # 88 46 47 48 48 49 52 50 51 Process Area # 720MD2B 720MD3A 720MD3B 720MD4 620MD1 620MD2A 620MD2B 650MD4 650MD5

Unit Name/Description Untreated MGO Slop Slop Flushing Oil Sodium

Hypochlorite Sulphuric

Acid Sulphuric

Acid Sulphuric

Acid Caustic

Tank Farm North North North North Utilities Utilities Utilities Utilities Utilities m E 357,224 357,697 357,653 357,609 358,371 358,369 358,368 357,902 357,911

Volume Source Locations m N 5,967,704 5,967,755 5,967,756 5,967,758 5,968,413 5,968,401 5,968,512 5,968,259 5,968,259 Base Elevation of Source m ASL 633 633 633 633 631 631 631 633 633 Release Dimensions Tank Height m 19.5 12.2 12.2 12.2 6.00 7.61 7.61 7.61 7.61 Tank Diameter m 63.9 28.9 28.9 29.8 3.25 2.54 2.54 2.54 2.54 Sigma Y m 14.86 6.72 6.72 6.93 0.76 0.59 0.59 0.59 0.59 Sigma Z m 9.07 5.67 5.67 5.67 2.79 3.54 3.54 3.54 3.54 Emission Rates Total VOC t/a 29.09 1.27 1.27 2.70 0.094 0.000003 0.000003 0.000001 0.003 1,3-butadiene t/a 0.00 0.207 0.207 0.00 0.00 0.00 0.00 0.00 0.00 Aliphatic alcohols t/a 0.00 0.00 0.00 0.00054 0.00 0.00 0.00 0.00 0.00 Aliphatic aldehydes t/a 0.00 0.00043 0.00043 0.00 0.00 0.00 0.00 0.00 0.00 Benzene t/a 0.494 0.0136 0.0136 0.00080 0.00 0.00 0.00 0.00 0.00 C17+ aliphatic group t/a 0.46 0.00 0.00 0.0011 0.00 0.00 0.00 0.00 0.00 C5-C8 aliphatic group t/a 4.14 0.188 0.188 0.0843 0.00 0.00 0.00 0.00 0.00 C9-C16 aliphatic group t/a 2.59 0.0058 0.0058 0.0811 0.00 0.00 0.00 0.00 0.00 C9-C16 aromatic group t/a 0.0823 0.00021 0.00021 0.0278 0.00 0.00 0.00 0.00 0.00 CS2 t/a 0.0573 0.0016 0.0016 0.00015 0.00 0.00 0.00 0.00 0.00 Cyclohexane t/a 0.00 0.0019 0.0019 0.00023 0.00 0.00 0.00 0.00 0.00 Ethylbenzene t/a 0.603 0.0014 0.0014 0.0093 0.00 0.00 0.00 0.00 0.00 Hexane t/a 0.663 0.0097 0.0097 0.0019 0.00 0.00 0.00 0.00 0.00 Hydrogen sulphide t/a 0.209 0.0515 0.0515 0.0367 0.00 0.00 0.00 0.00 0.00 Isopropylbenzene t/a 0.0743 0.000082 0.000082 0.0015 0.00 0.00 0.00 0.00 0.00 Mercaptan group t/a 0.00 0.0132 0.0132 0.00079 0.00 0.00 0.00 0.00 0.00 Naphthalene t/a 0.00 0.0000268 0.0000268 0.00 0.00 0.00 0.00 0.00 0.00 Propylene oxide t/a 0.00 0.00594 0.00594 0.00 0.00 0.00 0.00 0.00 0.00 Other (C1 to C4) t/a 2.596 0.6809 0.681 0.878 0.00 0.00 0.00 0.00 0.00 Styrene t/a 0.00 0.000077 0.000077 0.00 0.00 0.00 0.00 0.00 0.00 Thiophene group t/a 0.188 0.020 0.020 0.0029 0.00 0.00 0.00 0.00 0.00 Toluene t/a 1.835 0.0142 0.0142 0.0114 0.00 0.00 0.00 0.00 0.00 Xylenes t/a 1.57 0.0033 0.0033 0.0323 0.00 0.00 0.00 0.00 0.00 NaOCl t/a 0.00 0.0000 0.00 0.00 0.094 0.00 0.00 0.00 0.00 H2SO4 t/a 0.00 0.0000 0.00 0.00 0.00 0.000003 0.000003 0.000001 0.00 NaOH t/a 0.00 0.0000 0.00 0.00 0.00 0.00 0.00 0.00 0.003 Methane t/a 13.52 0.0527 0.0527 1.52 0.00 0.00 0.00 0.00 0.00


December 2006

Page 5A-43

Table 5A-32: Summary of Phase 2/3 Process Area Parameters and Emissions Source identification # 1 3,4,23 21, 22 8 10, 11, 12

Unit Identification # 300 330 340 310 450 500,510,520,522 Unit Name/Description Diluent Recovery Unit (DRU) Coker Gas Recovery Unit Vacuum Unit H2 Plant Sour Block Area Source Locations

m E 357,852 358,095 358,095 357,975 357,888 358,104 Northwest m N 5,967,555 5,967,799 5,967,799 5,968,618 5,968,107 5,968,202

m E 358,007 358,364 358,364 358,075 358,028 358,425 Northeast m N 5,967,550 5,967,790 5,967,790 5,968,615 5,968,103 5,968,192

m E 358,004 358,355 358,355 358,070 358,025 358,412 Southeast m N 5,967,450 5,967,490 5,967,490 5,968,445 5,967,989 5,967,849

m E 357,849 358,085 358,085 357,970 357,886 358,095 Southwest m N 5,967,455 5,967,499 5,967,499 5,968,448 5,967,993 5,967,859

Base Elevation of Source m ASL 633 633 633 633 633 633 Release Dimensions Release Height m 6.0 6.0 6.0 6.0 6.0 6.0 Initial Sigma Z m 10.0 10.0 10.0 10.0 10.0 10.0 Emission Rate Total VOC t/a 40.79 43.46 7.72 27.18 48.82 84.86 1,3-butadiene t/a 0.00 0.00 0.00 0.58 0.702 0.173 Aliphatic alcohols t/a 0.0019 0.00 0.00012 0.00 0.00 0.00 Aliphatic aldehydes t/a 0.132 0.0619 0.00 0.17 0.00 0.00 Aliphatic ketones t/a 0.0141 0.00 0.00 0.0644 0.0058 0.00 Benzene t/a 1.418 0.225 0.0018 0.495 0.0024 0.0004 C5-C8 aliphatic group t/a 9.83 1.642 0.0696 6.61 0.21 0.0271 C9-C16 aromatic group t/a 0.0586 0.362 0.00022 0.78 0.0051 0.00 CS2 t/a 0.0203 0.593 0.000084 0.0064 0.0098 0.0017 Cyclohexane t/a 0.0662 0.00 0.00030 0.00 0.00098 0.00 Ethylbenzene t/a 0.0264 0.00 0.00019 0.062 0.00061 0.000027 Hexane t/a 1.479 0.00 0.0013 0.519 0.0171 0.00037 Hydrogen sulphide t/a 3.371 4.505 0.043 0.479 0.000041 1.42 Isopropylbenzene t/a 0.00 0.00 0.00 0.00082 0.00 0.00 Mercaptan group t/a 0.129 0.00 0.0016 0.0265 0.0048 0.0737 Methylene chloride t/a 0.00 0.00 0.00 0.00 0.000000000121 0.000000000092 Propylene oxide t/a 0.0019 0.00 0.00 0.00 0.00 0.00 Other (C2 to C4) t/a 20.33 0.00 1.70 10.63 20.67 27.54 Thiophene group t/a 0.148 2.63 0.0012 0.062 0.0031 0.011 Toluene t/a 0.732 0.27 0.0015 0.983 0.0033 0.00030 Xylenes t/a 0.0444 0.126 0.0006 0.0739 0.0014 0.000095 Methane t/a 2.993 33.04 5.90 5.62 27.19 55.61



Table 5A-32: Summary of Phase 2/3 Process Area Parameters and Emissions (cont’d) Source identification # 30,34,46 5 6,7,44 24,25

Unit Identification # 400 410 420 710, 720

Unit Name/Description Gasifier Naphtha Hydrotreater Medium Gas Oil Hydrotreater Medium Gas Oil Hydrocracker Tank Farm Effluent Pont

Area Source Locations North South m E 358,176 357,905 357,836 357,819 357,139 356,946 358,936

Northwest m N 5,968,897 5,967,716 5,967,848 5,968,618 5,967,764 5,966,746 5,968,362 m E 358,427 358,019 358,023 357,914 357,697 357,613 358,976

Northeast m N 5,968,889 5,967,712 5,967,844 5,968,615 5,967,755 5,966,726 5,968,360 m E 358,423 358,016 358,019 357,909 357,688 357,588 358,976

Southeast m N 5,968,786 5,967,615 5,967,712 5,968,450 5,967,460 5,965,904 5,968,335 m E 358,173 357,902 357,832 357,814 357,130 356,921 358,936

Southwest m N 5,968,794 5,967,618 5,967,718 5,968,453 5,967,469 5,965,924 5,968,337 Base Elevation of Source m ASL 633 633 633 633 633 633 633 Release Dimensions Release Height m 6.0 6.0 6.0 6.0 6.0 6.0 1.0 Initial Sigma Z m 10.0 10.0 10.0 10.0 10.0 10.0 5.0 Emission Rate Total VOC t/a 32.65 26.34 32.61 32.61 11.81 11.91 0.00 1,3-butadiene t/a 0.4691 0.00 0.144 0.144 0.0179 0.0181 0.00 Aliphatic alcohols t/a 0.00 0.00 0.00 0.00 0.0112 0.0113 0.00 Aliphatic ketones t/a 0.0039 0.00050 0.0071 0.0071 0.00 0.00 0.00 Ammonia t/a 0.00 0.00 0.00 0.00 0.00 0.00 31.54 Benzene t/a 0.0016 0.0217 0.0051 0.0051 0.129 0.13 0.00 C17-C34 aromatic group t/a 0.00 0.00078 0.00015 0.00015 0.00 0.00 0.00 C5-C8 aliphatic group t/a 0.1407 0.235 0.137 0.137 7.23 7.29 0.00 C9-C16 aromatic group t/a 0.0034 0.0196 0.0104 0.0104 0.93 0.937 0.00 CS2 t/a 0.0066 0.1741 0.0000146 0.0000146 0.0010 0.0010 0.00 Cyclohexane t/a 0.00065 0.0119 0.00 0.00 0.156 0.158 0.00 Ethylbenzene t/a 0.00041 0.0026 0.0088 0.0088 0.261 0.263 0.00 Hexane t/a 0.0114 0.0391 0.0082 0.0082 0.248 0.25 0.00 Hydrogen sulphide t/a 0.000027 1.9129 0.0000046 0.0000046 0.0215 0.0217 1.44 Isopropylbenzene t/a 0.00 0.00044 0.00 0.00 0.0152 0.0153 0.00 Mercaptan group t/a 0.0032 0.0019 0.00042 0.00042 0.0026 0.0027 0.00 Methylene chloride t/a 0.000000000081 0.000000000161 0.000000000081 0.000000000081 0.00 0.00 0.00 Other (C2 to C4) t/a 13.82 2.613 8.396 8.40 0.883 0.89 0.00 Thiophene group t/a 0.0021 0.0088 0.0162 0.0162 0.0224 0.0225 0.00 Toluene t/a 0.0022 0.0141 0.0133 0.0133 0.809 0.816 0.00 Xylenes t/a 0.00091 0.0078 0.0189 0.0189 0.60 0.603 0.00 Methane t/a 18.18 21.28 23.85 23.85 0.48 0.48 0.00


December 2006

Page 5A-45

Table 5A-33: Summary of Phase 2/3 Five Cell Cooling Tower Parameters and Water Vapour Emissions Source identification # Unit 620ME (20) Cell Number 1 2 3 4 5 All Circulating Water Flow Rate Per Cell m3/h 2485 2485 2485 2485 2485 12,425 kg/h 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 12,425,000 Location UTM NAD 83 m N 5,968,444 5,968,444 5,968,444 5,968,444 5,968,444 - UTM NAD 83 m E 358,308 358,319 358,330 358,341 358,352 - Base Elevation m ASL 631 631 631 631 631 - Dimensions Cell Height (including fan stack) m 20 20 20 20 20 - Cell Top Internal Diameter m 8.6 8.6 8.6 8.6 8.6 - Cell Structure Height m 14.5 14.5 14.5 14.5 14.5 14.5 Cell Structure Width m 24.5 24.5 24.5 24.5 24.5 24.5 Cell Structure Length m 11 11 11 11 11 55 Exhaust Parameters Cell Exit Temperature °C 31 31 31 31 31 - Cell Exit Temperature K 304 304 304 304 304 - Cell Exit Velocity m/s 13 13 13 13 13 - Water Vapour Emission Rate kg/h 50,600 50,600 50,600 50,600 50,600 253,000



Table 5A-34: Summary of Phase 2/3 Sixteen Cell Cooling Tower Parameters and Water Vapour Emissions (Cells 1 to 8) Source identification # Phase 2/3 (38) Cell Number 1 2 3 4 5 6 7 8 Circulating Water Flow Rate Per Cell m3/h 2485 2485 2485 2485 2485 2485 2485 2485 kg/h 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 Location UTM NAD 83 m N 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 UTM NAD 83 m E 358,257 358,268 358,279 358,290 358,301 358,312 358,323 358,334 Base Elevation m ASL 631 631 631 631 631 631 631 631 Dimensions Cell Height (including fan stack) m 20 20 20 20 20 20 20 20 Cell Top Internal Diameter m 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6 Cell Structure Height m 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 Cell Structure Width m 24.5 24.5 24.5 24.5 24.5 24.5 24.5 24.5 Cell Structure Length m 11 11 11 11 11 11 11 11 Exhaust Parameters Cell Exit Temperature °C 31 31 31 31 31 31 31 31 Cell Exit Temperature K 304 304 304 304 304 304 304 304 Cell Exit Velocity m/s 13 13 13 13 13 13 13 13 Water Vapour Emission Rate kg/h 50,625 50,625 50,625 50,625 50,625 50,625 50,625 50,625


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Table 5A-35: Summary of Phase 2/3 Sixteen Cell Cooling Tower Parameters and Water Vapour Emissions (Cells 9 to 16) Source identification # Phase 2/3 (38) Cell Number 9 10 11 12 13 14 15 16 All Circulating Water Flow Rate Per Cell m3/h 2485 2485 2485 2485 2485 2485 2485 2485 39,760 kg/h 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 2,485,000 39,760,000 Location UTM NAD 83 m N 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 5,968,549 - UTM NAD 83 m E 358,345 358,356 358,367 358,378 358,389 358,400 358,411 358,422 -

Base Elevation m

ASL 631 631 631 631 631 631 631 631 - Dimensions Cell Height (including fan stack) m 20 20 20 20 20 20 20 20 - Cell Top Internal Diameter m 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6 - Cell Structure Height m 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 Cell Structure Width m 24.5 24.5 24.5 24.5 24.5 24.5 24.5 24.5 24.5 Cell Structure Length m 11 11 11 11 11 11 11 11 176 Exhaust Parameters Cell Exit Temperature °C 31 31 31 31 31 31 31 31 - Cell Exit Temperature K 304 304 304 304 304 304 304 304 - Cell Exit Velocity m/s 13 13 13 13 13 13 13 13 - Water Vapour Emission Rate kg/h 50,625 50,625 50,625 50,625 50,625 50,625 50,625 50,625 810,000



5A.5 Other Industrial Sources This section provides a brief discussion identifying each facility and provides a comparison of the emissions provided by the facility with those obtained from the 2004 and 2005 NPRI database. The NPRI database is only applicable to existing sources. In some cases, the maximum approved emission limits identified in the Alberta Environment environmental approvals are compared to the average values. Detailed emission data are summarized at the end of this section in Tables 5A-67 and 5A-68 for the Base Case and the Future Case, respectively.

5A.5.1 Access Pipeline Redwater Trim Blending Facility Access Pipeline Inc. is a joint venture between MEG Energy Corp and Devon ARL Canada Corp. The Redwater Trim Blending Facility site is located about 2.5 km to the East of the Project site. The facility is designed to deliver synthetic diluent to the production batteries facilities at the north end of the line. Detailed emission parameters are provided in Table 5A-68.

The emission information was provided by Access Pipeline Inc. The emission profile summary is provided in Table 5A-36 and is applicable to the Future Case. The facility is expected to be a small source of VOC emissions. As the facility has not yet been constructed, there are no NPRI values.

Table 5A-36: Summary of the Redwater Trim Blending Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Access Inc. Supplied (Planned)

NPRI (2004)

NPRI (2005)

SO2 0.00 NA NA NOx 0.00 NA NA CO 0.00 NA NA

PM2.5 0.00 NA NA VOC 0.02 NA NA

NOTE:

NA = Not Applicable

5A.5.2 Agrium Fort Saskatchewan Fertilizer Plant The Agrium Inc. Fort Saskatchewan fertilizer plant is located about 13 km to the Southwest of the Project site. The facility produces anhydrous ammonia and urea. Emission information for this facility was supplied by Agrium. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-37 compares the emission information provided by Agrium with corresponding information obtained from the 2004 and 2005 NPRI database. For NOx, the Agrium supplied values are larger than the corresponding information NPRI data. For CO and VOC, the Agrium supplied data are close to the NPRI values. For PM2.5, the Agrium supplied values are less than the NPRI data. The NPRI database indicates the Redwater facility is also a source of ammonia emissions to the atmosphere (1.55 and 1.39 t/d for 2004 and 2005, respectively).


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Table 5A-37: Summary of the Agrium Fort Saskatchewan Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Agrium Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R NOx 3.08 2.59 2.32 CO 0.68 0.76 1.55

PM2.5 0.00 0.041 0.014 VOC 0.08 0.050 0.036

NOTE: N/R = Not Reported

5A.5.3 Agrium Redwater Fertilizer Plant The Redwater fertilizer plant is located about 4.5 km to the east of the Project site. The facility produces ammonia, ammonium nitrate, ammonium sulphate, urea ammonium nitrate solutions and urea. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

The SO2 emission results primarily from two stacks: the sulphur acid tail gas stack #1 (4.07 t/d) and the sulfur acid tail gas stack #2 (3.58 t/d). The maximum approved SO2 emission for these two stacks are 6.768 t/d and 4.680 t/d, respectively for a total of 11.448 t/d. The maximum approved NOx emission from the two ammonia units and the nitric acid unit is equal to 13.44 t/d (Alberta Environment Approval NO. 210-01-00). The maximum approved SO2 and NOx rates are expressed in a kg/h basis.

Table 5A-38 compares the emission information provided by Agrium with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2 and NOx, the Agrium supplied values are larger than the corresponding NPRI data. The Agrium supplied and NPRI SO2 and NOx emissions are less than the respective maximum approved values of 11.448 t/d and 13.44 t/d. For CO and PM2.5, the Agrium supplied data are close to the NPRI values. For VOC, the Agrium supplied values are less than the NPRI data. The NPRI database indicates the Fort Saskatchewan facility is also a source of ammonia (6.22 and 6.76 t/d for 2004 and 2005, respectively) and methanol (0.58 and 0.52 t/d for 2004 and 2005, respectively).

Table 5A-38: Summary of the Agrium Redwater Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Agrium Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 7.66 4.87 4.40 NOx 5.09 3.68 3.28 CO 1.34 1.18 1.36

PM2.5 0.42 1.40 0.27 VOC 0.63 0.66 0.59



5A.5.4 Air Liquide Canada Scotford Cogeneration Power Plant Air Liquide operates a cogeneration power plant at Scotford. The cogeneration plant has a capacity of 200 tonnes of steam per hour and 80-megawatts of electricity supplying the Shell Chemical and Air Liquide facilities. The plant is located adjacent to Shell Chemical facilities on site 32-55-21-W4M, which is about 6.5 km to the southeast of the Project site. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-39 compares the emission information provided by Air Liquide Inc. with corresponding information obtained from the 2004 and 2005 NPRI database. For all criteria air contaminants, the Air Liquide supplied values are larger than the corresponding NPRI data. The maximum approved NOx emission from the gas turbine/HRSG exhaust stack is 1.512 t/d (or 63 kg/h, Alberta Environment Approval NO. 68179-00-00). A value of 0.70 t/d results from an auxiliary boiler exhaust stack that does not have a maximum approved limit.

Table 5A-39: Summary of the Air Liquide Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Air Liquide Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R NOx 2.21 0.58 0.47 CO 0.91 0.183 0.149

PM2.5 0.08 0.017 0.016 VOC 0.20 N/R N/R


5A.5.5 ARC Resource Gas Conversation Plant ARC Resources Redwater gas conservation plant is located about 13.5 km to the northeast of the Project site. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-40 compares the emission information provided by ARC with corresponding information obtained from the 2004 and 2005 NPRI database. For CO, the ARC supplied values are larger than the corresponding NPRI data. For SO2, NOx, PM2.5 and VOC, the ARC supplied data are similar to the NPRI values. The maximum approved SO2 emissions are 0.14 t/h and 2.4 t/d (Alberta Environment Approval NO. 150-02-00).

Table 5A-40: Summary of the ARC Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

ARC Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.59 0.58 0.58 NOx 1.07 1.12 0.76 CO 1.83 0.070 0.539

PM2.5 0.01 0.004 0.003 VOC 0.22 0.222 0.014


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5A.5.6 ATCO Midstream Fort Saskatchewan Sour Gas Plant The ATCO Midstream Fort Saskatchewan sour gas plant is located about 14.5 km to the southwest of the Project site. ATCO Midstream provides gas gathering, processing, storage and natural gas liquids solutions to the Canadian natural gas producing sector. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-41 compares the emission information provided by ATCO with corresponding information obtained from the 2004 and 2005 NPRI database. The ATCO Midstream facility is a small source of NOx, CO and PM2.5 emissions. The maximum approved SO2 emissions are 0.044 t/d (Alberta Environment Approval NO. 240-02-00).

Table 5A-41: Summary of the ATCO Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

ATCO Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R NOx 0.02 N/R N/R CO 0.01 N/R N/R

PM2.5 0.00 0.001 N/R VOC 0.00 N/R N/R


5A.5.7 Aux Sable Canada Heartland Offgas Project The Aux Sable Canada Heartland offgas plant site is located about 8 km to the southeast of the Project site. Aux Sable proposes to extract the natural gas liquids created from the upgrading process and sell them to petrochemical and NGL industries located in the Fort Saskatchewan area as feedstocks. The detailed emission parameters provided in Table 5A-68 are applicable to the Future Case.

Table 5A-42 summarizes the emission information provided by Aux Sable. The facility is a small source of NOx, CO, PM2.5 and VOC emissions. As the facility has not yet been constructed, there are no NPRI values.

Table 5A-42: Summary of the Aux Sable Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Aux Sable Supplied (Planned)

NPRI (2004)

NPRI (2005)

SO2 0.00 NA NA

NOx 0.13 NA NA CO 0.11 NA NA

PM2.5 0.01 NA NA

VOC 0.01 NA NA

NOTE: NA = Not Applicable



5A.5.8 BA Energy Heartland Upgrader The Heartland Upgrader is located about 7.5 km to the southeast of the Project site. This Project represents the next generation of bitumen upgrading technology, which will upgrade extra-heavy asphaltic crude oils from the oil sands into lighter synthetic crude oil blends. The Project will be designed to process up to 41,400 m3 per stream day of oil sands bitumen blend. Light, residue-free synthetic crude oil blends and medium blends with low asphaltene content will be produced and transported by pipeline to refinery markets. The plant has been approved and is currently under construction. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-43 summarizes the emission information provided by BA Energy. The facility is a large source of SO2 emissions. The maximum approved emissions for SO2 are 1.4 t/h or 28.1 t/d, and for NOx are 4.7 t/d (Alberta Environment Approval NO. 203303-00-00). As the facility is under construction, there are no NPRI values.

Table 5A-43: Summary of the BA Energy Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

BA Energy Supplied (Approved)

NPRI (2004)

NPRI (2005)




5A.5.9 BP Canada Energy Fort Saskatchewan Fractionation Plant The BP Canada Energy Fort Saskatchewan fractionation plant is located in northern portion of Section 14 and southern portion of Section 23 of Township 55, Range 22, West of the 4th Meridian, which is about 9 km to the south of the Project site. The plant is the hub for the processing, transportation, and marketing of natural gas liquids. Natural gas liquids are received by pipeline, stored in hydrocarbon storage caverns, fractionated, treated and dried for shipment to market. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-44 compares the emission information provided by BP Energy Inc. with corresponding information obtained from the 2004 and 2005 NPRI database. For NOx and CO, the BP Energy supplied values are larger than the corresponding NPRI data. For PM2.5 and VOC, the BP Energy supplied data are close to the NPRI values. The SO2 emissions from two acid gas incinerators are consistent with the maximum approved value (0.892 t/d, Alberta Environmental Approval No. 10081-01-00). The value of 0.15 t/d results from two Debut heaters and one FRAC heater that do not have a maximum approved limit.


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Table 5A-44: Summary of the BP Canada Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

BP Energy Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 1.04 N/R N/R NOx 0.64 0.32 0.32 CO 0.54 0.253 0.277

PM2.5 0.02 0.006 0.007 VOC 0.25 0.591 0.255


5A.5.10 Bunge Canada Fort Saskatchewan Oilseed Processing Plant The Bunge Canada Fort Saskatchewan oilseed processing plant is located about 14 km to the southwest of the Project site. The main products are crude super-degummed canola oil and canola meal. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases. Table 5A-45 compares the emission information provided by Bunge Canada with corresponding information obtained from the 2004 and 2005 NPRI database. For PM2.5 and VOC, the Bunge Canada supplied data are close to the NPRI values. The NPRI database indicates the Fort Saskatchewan Oilseed Processing Plant is also a source of n-Hexane (0.18 and 0.19 t/d for 2004 and 2005, respectively).

Table 5A-45: Summary of the Bunge Canada Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Bunge Canada Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R

NOx 0.00 N/R N/R CO 0.00 N/R N/R

PM2.5 0.04 0.039 0.042 VOC 0.00 0.273 0.325


5A.5.11 Canexus Chemicals Canada Ltd., Partnership Bruderheim Sodium Chlorate Plant

The Canexus Chemicals sodium chlorate plant is located about 19 km to the southeast of the Project site. Canexus Bruderheim Operation produces sodium chlorate which is used for bleaching purposes by the pulp and paper industry. The Bruderheim Facility has a production capacity of 70,000 tonnes per year. Crystal product from the plant is sold to North American customers and is exported overseas to customers in Asia. The Bruderheim Operation is also a major distribution terminal for hydrochloric acid. The hydrochloric acid is used in Western



Canada for enhancing production in existing oil and gas wells. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-46 compares the emission information provided by Canexus Canada with corresponding information obtained from the 2004 and 2005 NPRI database. The Canexus Canada facility is a small source of NOx emissions.

Table 5A-46: Summary of the Canexus Canada Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Canexus Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R NOx 0.02 0.02 0.01 CO 0.01 N/R N/R

PM2.5 0.00 N/R N/R

VOC 0.00 N/R N/R

NOTE: N/R= Not Reported

5A.5.12 CE Alberta BioClean Ltd., Fort Saskatchewan Chemical Plant The CE Alberta BioClean Ld. Fort Saskatchewan chemical plant site is located about 10 km to the southeast of the Project site. BioClean proposes to produce MTBE/ETBE and ethanol from butane and natural gas. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-47 summarizes the emission information provided by BioClean. As the facility has not yet been constructed, there are no NPRI values. The NOx emission is consistent with the maximum approval value (1.5648 t/d or 65.2 kg/h, Alberta Environment Approval NO. 46706-00-00). As the facility is not yet constructed, there are no NPRI values.

Table 5A-47: Summary of the BioClean Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

CE Supplied (Approved)

NPRI (2004)

NPRI (2005)

SO2 0.03 NA NA

NOx 1.58 NA NA CO 0.99 NA NA

PM2.5 0.11 NA NA

VOC 0.06 NA NA


5A.5.13 Degussa Canada Inc., Gibbons Hydrogen Peroxide Plant The Degussa Canada Inc. Gibbons hydrogen peroxide manufacturing plant is located about 2 km to the east of the Project site. Degussa Gibbons Site is the largest Hydrogen Peroxide facility in Canada. Hydrogen Peroxide is sold into the pulp and paper, mining, textile, detergent,


December 2006

Page 5A-55

cosmetic, chemical synthesis, electronics, environmental, food and space industries. Substance releases reported from the site are low-level ammonia and chlorine (NPRI 2004). The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-48 compares the emission information provided by Degussa Canada with corresponding information obtained from the 2004 and 2005 NPRI database. For NOx, the Degussa Canada supplied data are close to the NPRI values. For CO and PM2.5, the Degussa Canada supplied data are larger than the NPRI values. The maximum approved NOx emission from the hydrogen plant reformer stack is 0.0207 t/d (or 0.24 g/s, Alberta Environment Approval NO. 1034-02-00). The value of 0.04 t/d results from two SCM boilers that do not have a maximum approved limit.

Table 5A-48: Summary of the Degussa Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Degussa Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R NOx 0.05 0.06 0.05 CO 0.01 0.050 0.046

PM2.5 0.01 0.001 0.001 VOC 0.00 N/R N/R


5A.5.14 Dow Chemical Canada Inc. Fort Saskatchewan Chemical Plant The Dow chemical Canada Inc. Fort Saskatchewan chemical plant is located about 11 km to the south of the Project site. Dow Chemical operates the largest petrochemical manufacturing site at its Fort Saskatchewan location. The plant produces caustic soda, polyethylene, ethylene, ethylene dichloride, vinyl chloride monomer, power generation.

Natural gas liquids are separated producing ethane, propane-plus, propane, butane and pentane-plus. The ethane remains on site to make ethylene, which is an important feedstock for other onsite plants to make other chemical products. Ethylene is a primary building block for many consumer products, including vinyl products, polyethylene plastics, polyester fabric for clothes, ethylene oxide products including clear pop bottles and ethylene glycol (antifreeze) for vehicles. More than three million tones of product leave the Fort Saskatchewan site each year.

A cogeneration plant at Dow Chemical uses combined gas and steam turbines to generate approximately 300 megawatts of power. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-49 compares the emission information provided by Dow with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2, NOx, CO and PM2.5, the Dow supplied values are larger than the corresponding NPRI data. The NOx emission is consistent with the maximum approved value (698 kg/h or 16.752 t/d, Alberta Environment Approval No. 236-01-04). For VOC, the Dow supplied data is less than the NPRI values.

The NPRI database indicates the Fort Saskatchewan facility is also a source of HCFC-142b (0.30 and 0.38 t/d for 2004 and 2005, respectively).



Table 5A-49: Summary of the Dow Chemical Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Dow Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.60 0.14 0.13 NOx 11.85 5.81 3.58 CO 6.31 2.960 2.278

PM2.5 1.10 0.200 0.044 VOC 0.53 1.244 1.085

5A.5.15 ERCO Worldwide Bruderheim Sodium Chlorate Plant The ERCO Bruderheim sodium chlorate plant is located about 18 km to the southeast of the Project site. The Bruderheim plant produces approximately 80,000 tonnes of sodium chlorate per year. Sodium chlorate is used primarily in the bleaching of kraft pulp and water treatment and is shipped to pulp mills throughout North America. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-50 compares the emission information provided by ERCO with corresponding information obtained from the 2004 and 2005 NPRI database. For PM2.5, the ERCO supplied values are close to the NPRI data.

Table 5A-50: Summary of the ERCO Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

ERCO Supplied (Existing)

NPRI (2004)

NPRI (2005)


PM2.5 0.02 0.011 0.005 VOC 0.00 N/R N/R


5A.5.16 HAZCO Environmental Service Ltd., Bruderheim Sulphur Forming Facility

The HAZCO Bruderheim sulphur forming facility site is located about 20 km to the southeast of the Project site. HAZCO utilizes a sulphur management facility to process sulphur generated by oil and gas related refining operations in Bruderheim. The Project includes facilities for sulphur forming and shipping, as well as facilities for storage of manufactured product (i.e. sulphur pellets). The detailed emission parameters provided in Table 5A-68 are applicable to the Future Case.

Table 5A-51 summarizes the emission information provided by HAZCO. As the facility has not yet been constructed, there are no NPRI values.


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Table 5A-51: Summary of the HAZCO Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

HAZCO Supplied (Planned)

NPRI (2004)

NPRI (2005)




5A.5.17 Keyera Energy Ltd., Fort Saskatchewan Fractionation Facility The Keyera Energy Ltd. Fort Saskatchewan fractionation facility is located about 10 km to the south of the Project site. The Keyera Energy operated Fort Saskatchewan Fractionation and Storage Facility receives natural gas liquids from connected pipeline systems and truck offloading. These streams are fractionated into propane, butane and pentane plus products. Following fractionation the products are shipped to customers through pipeline systems or truck loading facilities. Products that are not immediately delivered to customers are stored in deep underground storage caverns for subsequent delivery to market. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-52 compares the emission information provided by Keyera with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2, NOx, CO and PM2.5, the Keyera supplied values are larger than the corresponding NPRI data. For VOC, the Keyera supplied data are close to the NPRI values. The maximum approved SO2 emission is 2.4 t/d (Alberta Environment Approval No. 10235-01-01).

Table 5A-52: Summary of the Keyera Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Keyera Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 1.90 0.41 0.45 NOx 0.84 0.13 0.13 CO 0.34 0.080 0.093

PM2.5 0.05 0.002 0.005 VOC 1.54 0.860 1.540

5A.5.18 Marsulex Inc., Fort Saskatchewan Chemical Plant The Marsulex Inc. Fort Saskatchewan Chemical Plant is located about 13.5 km to the southwest of the Project site. The plant produces aluminum sulphate (Alum), sodium, bisulphate, carbon disulphite and hydrogen sulphide. The range of chemicals is used in a variety of industrial applications such as water and sewage treatment, pulp and paper, power generation and oil and gas production. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.



Table 5A-53 compares the emission information provided by Marsulex with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2, the Marsulex supplied values are less than the NPRI data. For NOx, CO, PM2.5 and VOC, the Marsulex supplied data are close to the NPRI values. The maximum approved SO2 emission is 1.92 t/d (or 80 kg/h, Alberta Environment Approval NO. 1636-01-00).

Table 5A-53: Summary of the Marsulex Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Marsulex Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.99 0.716 0.987 NOx 0.00 0.005 0.004 CO 0.00 0.004 0.003

PM2.5 0.00 0.0002 0.0002 VOC 0.00 0.007 0.006

5A.5.19 NewAlta Corporation Redwater Disposal Facility The Newalta Redwater disposal facility is located about 13 km to the northeast of the Project site. Newalta is an industrial waste management company operating an incinerator and two boilers on the Dow Chemical site. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-54 summarizes the emission information provided by Newalta. The facility is a small source of NOx and CO emission.

Table 5A-54: Summary of the NewAlta Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Newalta Supplied (Existing)

NPRI (2004)

NPRI (2005)


PM2.5 0.00 N/R N/R VOC 0.00 N/R N/R

NOTE: N/R = Not reported

5A.5.20 North West Upgrader The North West Upgrader facility site is located about 3 km to the east of the Project site. North West Upgrading is a Calgary-based company planning to build a heavy oil Upgrader in Sturgeon County. The plant will produce synthetic crude oil with a planned capacity of 50,000 barrels per day (bpd) per phase (three phases). The first phase of the Project is expected to come on stream in 2010. Two additional phases are expected to be built by 2015 to meet market demand for merchant upgrading services. The detailed emission parameters provided in Table 5A-68 are applicable to the Future Case.


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Table 5A-55 summarizes the emission information provided by North West. As the facility has not yet been constructed, there are no NPRI values.

Table 5A-55: Summary of the North West Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

North West Supplied (Planned)

NPRI (2004)

NPRI (2005)




5A.5.21 Prospec Chemicals Fort Saskatchewan Xanthate Plant The Prospec Chemicals Fort Saskatchewan Xanthate Plant is located about 11 km to the southwest of the Project site. The Fort Saskatchewan plant produces 7000 MT of Xanthates annually as well as a growing number of Specialty Collectors. The facility also produces Thionocarbamates and Xanthogen Formates. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-56 compares the emission information provided by Prospec Chemicals with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2, the Prospec supplied values are larger than the corresponding NPRI data. For NOx and CO, the Prospec supplied values are close to the corresponding NPRI data.

Table 5A-56: Summary of the Prospec Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Prospec Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.16 0.08 0.08 NOx 0.00 0.002 0.003 CO 0.05 0.027 0.007

PM2.5 0.00 N/R N/R VOC 0.00 N/R N/R


5A.5.22 Provident Energy Ltd., Redwater Fractionation Facility The Provident Energy Limited Redwater Fractionation Facility is located about 3.5 km to the southeast of the Project site. The Redwater Fractionation and Storage Facility is equipped to collect, extract, transport, fractionate, store, distribute and market natural gas liquids, as well as fractionate olefin’s, such as propylene, for William’s Energy. The natural gas separation process produces numerous products including ethane, propane and butane. Condensates are also



produced at the plant to be mainly used in Alberta to speed the flow of heavy oil through pipelines. The facility has an annual production capacity of approximately 65,000 barrels per day. The detailed emission parameters provided in Table 5A-68 are applicable to the Base and Future cases.

Table 5A-57 compares the emission information provided by Provident with corresponding information obtained from the 2004 and 2005 NPRI database. For all criteria air contaminant substances, the Provident supplied values are close to the corresponding NPRI data. The maximum approved SO2 emission is 1.98 t/d (Alberta Environment Approval NO. 9995-01-01).

Table 5A-57: Summary of the Provident Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Provident Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.77 0.63 0.74 NOx 0.10 0.08 0.065 CO 0.08 0.15 0.078

PM2.5 0.01 0.003 0.002 VOC 0.08 0.114 0.085

5A.5.23 Redwater Water Disposal Company The Redwater Company has a number of neighbouring industrial facilities that produce SO2 and NOx emission. One is located about 14.5 km to the north of the Project site. The other two are located about 10 and 14 km to the Northeast of the Upgrader site, respectively. Emissions are primarily generated from incinerators or pump stations. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases. Table 5A-58 compares the emission information provided by Redwater waste disposal with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2, the Redwater water disposal company supplied datum is less than the NPRI value in 2004, but close to the NPRI value in 2005.

Table 5A-58: Summary of the Redwater Disposal Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Redwater Disposal Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.29 0.50 0.29 NOx 0.00 N/R N/R CO 0.00 N/R N/R

PM2.5 0.00 N/R N/R VOC 0.00 N/R N/R



December 2006

Page 5A-61

5A.5.24 Shell Canada Scotford Bitumen Upgrader The Shell Canada Scotford Bitumen Upgrader is located about 6 km to the southeast of the Project site. The Scotford plant has recently applied to increase bitumen production, which will change the emission profile. The detailed emission parameters provided in Table 5A-67 and Table 5A-68 are applicable to the Base and Future cases, respectively.

Table 5A-59 compares the emission information provided by Shell Canada with corresponding information obtained from the 2004 and 2005 NPRI database. For all criteria air contaminant substances, the Shell Canada Scotford supplied data are larger than the corresponding NPRI data. The maximum approved emission for NOx is 199.4 kg/h (or 4.7856 t/d, Alberta Environment Approval NO. 77375-00-00 and NO. 49587-00-01) and for SO2 is 2.0 t/h or 28.0 t/d (Alberta Environment Approval NO. 49587-00-01). The maximum approved NOx emissions are applicable to the gas turbine/HRSG exhaust stack, atmospheric column charge heaters common exhaust stack and steam methane reformer (H24101, H24201) flue stacks; while the maximum approved SO2 emission is applicable to the SRU incinerator stack.

Table 5A-59: Summary of the Shell Scotford Facility Emissions and a Comparison to NPRI Database Values

Shell Canada Supplied Emission Rate

(t/d) Existing/Approved

Planned

NPRI (2004)

NPRI (2005)

SO2 28.07 24.55 18.14 18.95 NOx 5.73 8.82 3.12 2.54 CO 2.29 6.71 2.884 1.738

PM2.5 0.34 0.68 0.070 0.04 VOC 0.85 1.09 1.013 0.775

5A.5.25 Shell Canada Products Scotford Oil Refinery The Shell Canada Products Scotford Oil Refinery is located about 6.5 km to the southeast of the Project site. The Scotford plant refines synthetic crude from the Alberta oil sands into a wide range of petroleum products including jet fuel, gasoline, diesel, propane, butane and petrochemicals. The refinery produces 100,000 barrels per day of refined products. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-60 compares the emission information provided by Shell Scotford oil refinery with corresponding information obtained from the 2004 and 2005 NPRI database. For NOx and PM2.5 the Scotford Oil Refinery supplied values are larger than the corresponding NPRI data. For SO2, CO and VOC, the Scotford Oil Refinery supplied values are close to the corresponding NPRI data.



Table 5A-60: Summary of the Shell Oil Refinery Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Shell Canada Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.12 0.19 0.27 NOx 2.73 2.35 2.20 CO 1.20 1.348 1.275

PM2.5 0.35 0.030 0.029 VOC 0.41 0.314 0.296

5A.5.26 Shell Chemicals Canada Scotford Styrene and MEG Plant The Shell Chemicals Canada Scotford Styrene & MEG Plant is located about 6.5 km to the southeast of the Project site. The chemical plant manufactures principally styrene monomers and mono-ethylene glycols. On site storage of benzene, styrene residues and ethyl benzene also occurs. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-61 compares the emission information provided by Shell Scotford Styrene & MEG with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2 and NOx, the Shell Chemicals Canada supplied data are close to the NPRI values. For CO, PM2.5 and VOC, the Shell Chemicals Canada supplied data are larger than the NPRI values.

Table 5A-61: Summary of the Shell Chemicals Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Shell Chemicals Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 0.01 0.01 NOx 1.43 1.28 1.15 CO 1.01 0.451 0.457

PM2.5 0.20 0.039 0.033 VOC 0.37 0.287 0.141

5A.5.27 Sherritt International Corporation Fort Saskatchewan Fertilizer Plant The Sherritt International Corporation Fort Saskatchewan Fertilizer Plant is located about 13.5 km to the southwest of the Project site. The Sherritt plant produces ammonia, urea and ammonium sulphate. The detailed emission parameters provided in Table 5A-67 and Table 5A-68 are applicable to the Base and Future cases, respectively.

Table 5A-62 compares the emission information provided by Sherritt with corresponding information obtained from the 2004 and 2005 NPRI database. For SO2 and NOx, the Sherritt supplied data are close to the corresponding NPRI data. For CO and PM2.5, the Sherritt supplied data are larger than the corresponding NPRI data. The maximum approved SO2 emission is 2.808 t/d (or 117 kg/h, Alberta Environment Approval NO. 211-01-00).


December 2006

Page 5A-63

Table 5A-62: Summary of the Sherritt Facility Emissions and a Comparison to NPRI Database Values Sherritt Supplied

Emission Rate (t/d)

Existing/Approved

Planned

NPRI (2004)

NPRI (2005)

SO2 1.04 1.04 0.89 1.05 NOx 7.28 7.64 5.92 7.30 CO 1.87 2.09 0.466 0.496

PM2.5 0.15 0.16 0.020 0.020 VOC 0.24 0.25 N/R N/R


5A.5.28 Synenco Energy Northern Lights Upgrader Project The Synenco Energy Northern Lights Upgrader project site is located about 7.5 km to the northeast of the Project site. The Project proposes to produce a high grade synthetic crude oil product. The detailed emission parameters provided in Table 5A-68 are applicable to the Future Case.

Table 5A-63 summarizes the emission information provided by Synenco. The facility is a source of SO2, NOx and CO emissions.

Table 5A-63: Summary of the Synenco Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Synenco Supplied (Planned)

NPRI (2004)

NPRI (2005)




5A.5.29 Terasen Pipelines Heartland Storage Tank Terminal The Terasen Pipelines Heartland Storage Tank Terminal plant site is located about 8 km to the southeast of the Project site. Terasen proposes to collect and store crude oil from the Alberta Oil sands region. The detailed emission parameters provided in Table 5A-68 are applicable to the Future Case.

Table 5A-64 summarizes the emission information provided by Terasen. The facility is expected to be a small source of VOC emissions. As the facility has not yet been constructed, there are no NPRI values.



Table 5A-64: Summary of the Terasen Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

Terasen Supplied (Planned)

NPRI (2004)

NPRI (2005)




5A.5.30 TransAlta Cogeneration L.P. Fort Saskatchewan Cogeneration Power Plant

The TransAlta Fort Saskatechwan Cogeneration Power Plant is located about 11.5 km to the southwest of the Project site. The cogeneration facility uses natural gas to produce 120 megawatts of electricity and 100 tonnes of steam per hour. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-65 compares the emission information provided by TransAlta with corresponding information obtained from the 2004 and 2005 NPRI database. For NOx and CO, the TransAlta supplied data are larger than the NPRI values. For PM2.5, the TransAlta supplied data are close to the NPRI values. The NOx emission is consistent with the maximum approved value (1.872 t/d or 78 kg/h, Alberta Environment Approval NO. 48325-00-00).

Table 5A-65: Summary of the TransAlta Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

TransAlta Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.03 N/R N/R NOx 1.87 0.32 0.23 CO 0.69 0.248 0.235

PM2.5 0.02 0.048 0.019 VOC 0.02 N/R N/R

5A.5.31 TransCanada Cogeneration L.P. Fort Saskatchewan Cogeneration Power Plant

The TransCanada Redwater Cogeneration Power Plant is located about 3.5 km to the southeast of the Project site. The plant operates a 40-megawatt natural gas-fired cogeneration plant. The detailed emission parameters provided in Table 5A-67 are applicable to the Base and Future cases.

Table 5A-66 compares the emission information provided by TransCanada with corresponding information obtained from the 2004 and 2005 NPRI database. For NOx, the TransCanada supplied data are larger than the NPRI values. For CO and PM2.5, the TransCanada supplied


December 2006

Page 5A-65

data are close to the NPRI values. The maximum approved NOx emission is 0.8323 t/d (or 34.3 kg/h, Alberta Environment Approval NO. 136951-00-00).

Table 5A-66: Summary of the TransCanada Facility Emissions and a Comparison to NPRI Database Values

Emission Rate (t/d)

TransCanada Supplied (Existing)

NPRI (2004)

NPRI (2005)

SO2 0.00 N/R N/R NOx 0.52 0.30 0.35 CO 0.12 0.115 0.104

PM2.5 0.01 0.009 0.008 VOC 0.00 N/R N/R


5A.5.32 Detailed Emission Parameters (Base Case) Table 5A-67 provides the detailed emission parameters for the Base Case on a stack-by-stack basis that were used for this assessment. The Base Case includes existing and approved industrial facilities.

5A.5.33 Detailed Emission Parameters (Future Case) For new facilities or for facilities that are proposing an expansion, the detailed emission parameters for the additional Future Case facilities are provided in Table 5A-68 on a stack by stack basis. The parameters in Table 5A-68 replace the parameters in Table 5A-67 for the identified facilities; for all other facilities, the Base Case parameters are still applicable.



Table 5A-67: Detailed Stack and Emission Parameters for the Base Case Stack Emissions

Company/Facility/Unit

UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Agrium Products, Fort Saskatchewan Ammonia Primary Reformer Stack 355222 5955272 625 36.6 3.40 17.6 445 0.00 3.00 0.68 0.00 Urea Stack 355262 5955123 628 67.1 2.70 23.0 324 0.00 0.08 0.00 0.00 Total 0.00 3.08 0.68 0.00 Agrium Products, Redwater Fertilizer Plant Sulphuric Acid Tail Gas Stack #1 362551 5968342 626 76.2 2.29 13.2 346 4.07 0.00 0.00 0.03 Sulphuric Acid Tail Gas Stack #2 362553 5968290 626 45.1 2.13 6.6 341 3.58 0.00 0.00 0.02 Ammonia-1 North Reformer Stack 362478 5968060 626 29.0 1.47 20.0 475 0.00 1.47 0.09 0.00 Ammonia-1 South Reformer Stack 362478 5968053 626 29.0 1.47 20.0 475 0.00 1.47 0.09 0.00 Ammonia-2 Reformer Stack 362448 5967838 626 25.9 3.66 15.0 460 0.01 1.91 0.42 0.03 Ammonium Nitrate Process Vent 362357 5968100 626 42.7 1.37 19.7 331 0.00 0.00 0.00 0.02 Prill Tower Scrubber Stack 362361 5968091 626 42.7 1.52 34.3 311 0.00 0.00 0.00 0.03 Ammonium Nitrate Prill Tower Fan #1 362364 5968096 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #2 362366 5968096 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #3 362366 5968094 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #4 362366 5968092 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #5 362364 5968092 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #6 362362 5968092 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #7 362362 5968094 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Ammonium Nitrate Prill Tower Fan #8 362362 5968096 626 36.1 1.83 17.0 304 0.00 0.00 0.00 0.01 Nitric Acid Tail Gas Stack 362340 5968040 626 45.4 1.22 24.9 442 0.00 0.12 0.00 0.00 Urea Granulation Scrubber Stack 362346 5967879 626 54.9 3.51 12.8 316 0.00 0.00 0.60 0.07 Reactor/Granulator Scrubber East Stack 362372 5968321 626 30.5 1.52 13.1 352 0.00 0.00 0.00 0.00 Reactor/Granulator Scrubber West Stack 362328 5968320 626 30.5 1.52 19.5 341 0.00 0.00 0.00 0.00 Dryer Scrubber East Stack 362375 5968320 626 35.1 2.74 12.6 325 0.00 0.03 0.02 0.01 Dryer Scrubber West Stack 362329 5968302 626 35.1 2.13 8.0 330 0.00 0.02 0.02 0.00 Phosphoric Acid Granulation East Baghouse 362361 5968323 626 30.5 1.02 9.5 345 0.00 0.00 0.00 0.03 Phosphoric Acid Granulation West Baghouse 362343 5968323 626 30.5 1.02 9.5 345 0.00 0.00 0.00 0.03 Phosphoric Acid South Filter L-602 Scrubber Stack 362502 5968397 626 28.7 1.22 18.0 300 0.00 0.00 0.00 0.02 Phosphoric Acid Attack Tank Scrubber Stack 362502 5968339 626 28.7 1.10 8.0 305 0.00 0.00 0.00 0.02 Phosphoric Acid Filter Scrubber Stack 362499 5968312 626 28.7 1.20 14.1 301 0.00 0.00 0.00 0.02 Boiler 1 362529 5968090 626 19.0 1.20 1.0 408 0.00 0.00 0.00 0.00 Boiler 3 362551 5968090 626 18.0 1.50 1.0 393 0.00 0.01 0.01 0.00 CGT-902 Compressor 362418 5967855 626 25.9 3.17 2.5 810 0.00 0.05 0.08 0.00 Utilities Ammonia Flare 362706 5967896 626 15.2 0.30 5.0 1273 0.00 0.00 0.00 0.00 Total 7.66 5.09 1.34 0.42


December 2006

Page 5A-67

Table 5-67: Detailed Stack and Emission Parameters for the Base Case Stack Emissions (cont’d)


UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Air Liquide Canada Inc. Scotford Cogeneration Power Plan

Auxiliary Boiler Exhaust Stack 362682 5963154 624 22.9 1.83 24.1 435 0.00 0.70 0.46 0.04 Gas Turbine/HRSG Exhaust Stack 362694 5963170 624 32.3 5.60 16.6 438 0.00 1.51 0.46 0.04 Total 0.00 2.21 0.91 0.08 ARC Resources Ltd. Redwater Gas Conversion Plant #1 Fieldgate Treaters (combined) 363439 5980298 617 8.7 0.60 6.8 753 0.00 0.01 0.01 0.00 Compressor K50RA (1,119 kW) 363446 5980252 617 10.0 0.30 57.2 919 0.00 0.31 0.52 0.00 Compressor K50RB (1,119 kW) 363434 5980252 617 10.0 0.30 57.2 919 0.00 0.38 0.52 0.00 Compressor K8R (629 kW) 363472 5980265 617 10.0 0.24 48.0 844 0.00 0.33 0.36 0.00 Compressor K9R (656 kW) 363460 5980265 617 6.6 0.24 48.0 844 0.00 0.00 0.38 0.00 Heating and Vent Boiler F92R (1,716 kW) 363489 5980175 617 4.6 0.50 10.0 693 0.00 0.01 0.01 0.00 Hot Oil Heater F90R 363464 5980181 617 21.2 1.50 4.2 633 0.00 0.04 0.03 0.00 SRU Incinerator 363470 5980160 617 45.7 0.86 5.1 278 0.59 0.00 0.00 0.00 Total 0.59 1.07 1.83 0.01 ATCO Midstream, Fort Saskatchewan Sour Gas Plant Regenerator Gas Heater (466 kW) 355890 5953580 624 7.2 0.45 3.2 876 0.00 0.01 0.009 0.00 Glycol Heater (170 kW) 355830 5953605 624 4.9 0.39 3.1 529 0.00 0.01 0.006 0.00 Continuous Flare 355910 5953600 624 30.1 0.36 0.1 1273 0.00 0.00 0.00 0.00 Total 0.00 0.02 0.01 0.00 BA Energy, Heartland Bitumen Upgrader Sulphur Recovery Unit 365573 5965731 619 100.0 5.00 16.0 423 28.10 4.70 1.56 0.47 BP Canada Energy, Fort Saskatchewan Fractionation Plant Butane Treater Heater 357590 5959069 626 9.1 0.41 1.5 493 0.000 0.001 0.001 0.000 CORP 2 Heater 357632 5959097 626 18.0 1.20 4.0 553 0.000 0.010 0.014 0.001 CORP Heater 357526 5959023 626 17.3 1.22 1.5 653 0.000 0.047 0.019 0.002 CORP Acid Gas Incinerator 357733 5959215 626 27.4 0.61 12.0 285 0.446 0.003 0.166 0.002 Debut 1 Heater 357706 5959011 626 24.0 1.42 3.3 491 0.058 0.336 0.041 0.004 Debut 2 Heater 357529 5959110 626 28.2 1.75 4.4 463 0.073 0.045 0.053 0.005 FRAC Heater 357629 5959017 626 44.7 2.13 3.1 453 0.017 0.188 0.077 0.007 PSU Heater 357611 5959130 626 5.0 0.64 3.3 653 0.000 0.008 0.005 0.000 PSU Acid Gas Incinerator 357729 5959066 626 27.4 0.61 12.0 285 0.446 0.003 0.166 0.002 Total 1.04 0.64 0.54 0.023





UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Canexus Chemicals Canada, Bruderheim Sodium Chlorate Plant

Boiler Exhaust Vent 376025 5961906 646 9.0 0.61 8.0 281 0.00 0.016 0.014 0.001 Flare Stack (Pilot) 375829 5961871 646 18.3 0.51 0.1 273 0.00 0.00 0.00 0.00 Fluidized Bed Dryer Unit Scrubber Vent (horizontal) 376042 5961885 646 23.5 0.46 1.0 274 0.00 0.00 0.00 0.001 Sodium Chlorate Hopper Baghouse Vent #1 (horizontal) 376045 5961938 646 20.4 0.10 1.0 274 0.00 0.00 0.00 0.00 Sodium Chlorate Hopper Baghouse Vent #2 (horizontal) 376052 5961938 646 20.4 0.10 1.0 274 0.00 0.00 0.00 0.00 Vaculoader Vent #1 (horizontal) 376046 5961944 646 10.7 0.08 1.0 274 0.00 0.00 0.00 0.00 Vaculoader Vent #2 (horizontal) 376051 5961945 646 10.7 0.08 1.0 274 0.00 0.00 0.00 0.00 Total 0.00 0.02 0.014 0.002 CE Alberta BioClean, Fort Saskatchewan Chemical Plant Methanol Reformer (H-1201) 360073 5957842 628 19.8 1.68 8.4 281 0.002 0.182 0.153 0.014 Butamer Unit Regenerator Heater (H-2101) 360093 5957959 628 19.8 0.69 7.9 281 0.00 0.012 0.010 0.001 Oleflex Unit Heater (H-2201/2/3) 360079 5957883 628 65.0 2.95 9.9 283 0.006 0.240 0.202 0.018 Oleflex Unit Regenerator Heater (H-2204) 360098 5957933 628 19.8 0.69 7.0 280 0.00 0.010 0.008 0.001 Oleflex Unit Drier Heater (H-2205) 360093 5957932 628 19.8 1.45 7.4 280 0.001 0.046 0.038 0.003 Continuous Flare 360335 5957702 628 120.0 1.07 4.3 277 0.001 0.011 0.009 0.001 TEN/CLA Utility Boiler 360307 5958227 628 25.0 1.37 13.8 287 0.008 0.384 0.323 0.029 TEN/CLA Gas Turbine 360293 5958247 628 11.8 2.20 31.5 305 0.002 0.576 0.148 0.029 Drier Exhaust Scrubber (V-3127) 360454 5958131 628 32.0 2.44 9.8 283 0.004 0.115 0.097 0.009 Total 0.03 1.58 0.99 0.11 Degussa Canada, Gibbons Hydrogen Peroxide Plant Hydrogen Plant Reformer Stack 359751 5967373 634 30.0 0.75 13.6 455 0.00 0.013 0.011 0.001 SCM Boiler 1 359738 5967410 634 30.0 0.65 12.8 446 0.00 0.029 0.001 0.004 SCM Boiler 2 359746 5967410 634 30.0 0.65 6.7 489 0.00 0.008 0.00 0.001 Total 0.00 0.05 0.01 0.01


December 2006

Page 5A-69



UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Dow Chemical Canada, Fort Saskatchewan Chemical Plant

Brine Incinerator (IN-650) 360242 5957340 627 20.4 1.22 3.0 1033 0.00 0.01 0.030 0.003 CO2 Incinerator (IN-239) 358773 5957339 627 27.4 2.03 3.7 1073 0.60 0.08 0.034 0.046 Chlor-alkali Cooling Towers (CT-CA) 358749 5956636 627 20.4 9.10 10.2 293 0.00 0.00 0.000 0.120 EOEG Cooling Towers (CT-EOEG) 356287 5956501 627 20.4 9.10 10.2 293 0.00 0.00 0.000 0.008 Ethylene Craking Furnace #1 (H-121) 359035 5957312 627 51.0 2.10 7.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #2 (H-122) 359041 5957315 627 51.0 2.10 7.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #3 (H-123) 359060 5957325 627 51.0 2.10 7.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #4 (H-124) 359067 5957328 627 51.0 2.10 7.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #5 (H-125) 359086 5957338 627 51.0 2.10 7.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #6 (H-126) 359092 5957340 627 51.0 2.10 7.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #7 (H-127) 359105 5957352 627 55.0 1.90 10.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #8 (H-128) 359118 5957359 627 55.0 1.90 10.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #9 (H-129) 359131 5957365 627 55.0 1.90 10.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #10 (H-130) 359144 5957371 627 55.0 1.90 10.3 394 0.00 0.20 0.027 0.020 Ethylene Craking Furnace #11 (H-131) 359157 5957378 627 55.0 1.90 10.3 394 0.00 0.20 0.027 0.020 HCS Wells Dowtherm Furnace (H-371) 357602 5957168 627 14.5 0.76 23.0 474 0.00 0.01 0.000 0.002 LHC Cooling Towers (CT13-LHC) 359176 5957925 627 20.4 9.10 10.2 293 0.00 0.00 0.000 0.019 Loading Incinerator (IN-498) 358910 5957030 627 17.1 1.88 1.0 1173 0.00 0.010 0.002 0.005 New Furnace (Poly F-502) 357314 5955731 627 45.0 1.45 11.6 493 0.00 0.100 0.068 0.020 Package Boilers #1 (B 905A) 359071 5957416 627 16.1 2.10 3.8 453 0.00 0.08 0.018 0.005 Package Boilers #2 (B 905B) 359081 5957397 627 16.1 2.10 3.8 453 0.00 0.08 0.018 0.005 Polyethylene Flare (Poly FS-106) 357267 5955950 627 42.7 0.91 34.0 1273 0.00 0.00 0.008 0.00 Polyethylene Expansion Furnace (Poly F-501) 357321 5955766 627 48.0 1.45 11.1 493 0.00 0.090 0.058 0.017 Polyethylene Furnace (Poly F-500) 357297 5955769 627 32.0 1.12 11.6 493 0.00 0.060 0.036 0.012 Power and Utilities GT/HRSG Unit #1 (GT/HRU-101) 356676 5956358 627 30.5 4.57 18.7 392 0.00 4.320 2.838 0.235 Power and Utilities GT/HRSG Unit #2 (GT/HRU-201) 356690 5956330 627 30.5 4.57 18.7 392 0.00 4.320 2.838 0.235 Spent Caustic Incinerator (FX-707) 359092 5957374 627 40.0 0.61 10.6 356 0.00 0.040 0.010 0.021 Tank Vent Incinerator (IN-473) 359307 5957338 627 17.1 1.32 3.1 1173 0.00 0.030 0.007 0.017 Vinyl Chloride Monomer Furnace #1 (F-201) 357107 5956030 627 16.2 0.91 34.0 509 0.00 0.070 0.012 0.014 Vinyl Chloride Monomer Furnace #2 (F-202) 357112 5956032 627 15.2 0.91 23.0 474 0.00 0.070 0.012 0.014 Vinyl Chloride Monomer Furnace #3 (F-203) 357125 5956038 627 15.2 0.91 23.0 474 0.00 0.070 0.012 0.014 Vinyl Chloride Monomer Furnace #4 (F-204) 357129 5956040 627 16.2 0.91 34.0 509 0.00 0.070 0.012 0.014 Vinyl Hot Oil Furnace (F-400) 357091 5956021 627 22.0 1.22 5.0 378 0.00 0.050 0.000 0.010 Vinyl Thermal Oxidizer (F-600) 357092 5956317 627 27.4 0.76 40.0 365 0.00 0.080 0.002 0.044 Vinyl Vent Burner #1 (F-390) 357122 5956274 627 27.4 0.91 14.0 343 0.00 0.010 0.001 0.000 Vinyl Vent Burner #2 (F-391) 357123 5956274 627 27.4 0.91 14.0 343 0.00 0.010 0.001 0.000 Total 0.60 11.86 6.31 1.10





UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

ERCO Worldwide, Bruderheim Sodium Chlorate Plant

Boiler Exhaust Vent 375474 5963118 637 13.5 0.91 14.1 472 0.00 0.012 0.010 0.001 Scrubber Vent 1 (horizontal) 375490 5963086 637 12.0 0.75 1.0 310 0.00 0.00 0.00 0.009 Scrubber Vent 2 (horizontal) 375496 5963104 637 17.8 0.75 1.0 311 0.00 0.00 0.00 0.007 Silo Baghouse A 375490 5963088 637 27.0 0.25 1.6 313 0.00 0.00 0.00 0.001 Total 0.00 0.012 0.01 0.017 Keyera Energy, Fort Saskatchewan Fractionation Facility Gas Turbine (3,022 kW) 357380 5957660 632 6.1 0.91 43.3 593 0.00 0.123 0.032 0.006 Gas Turbine (3,022 kW) 357390 5957660 632 6.1 0.91 43.3 593 0.00 0.123 0.032 0.006 Gas Turbine (3,022 kW) 357400 5957660 632 6.1 0.91 43.3 593 0.00 0.123 0.032 0.006 Gas Turbine (3,022 kW) 357370 5957660 632 6.1 0.91 43.3 593 0.00 0.123 0.032 0.006 Gas Turbine (3,022 kW) 357410 5957660 632 6.1 0.91 43.3 593 0.00 0.123 0.032 0.006 Glycol Heater (879 kW) 357322 5957632 632 6.7 0.29 35.8 653 0.00 0.008 0.007 0.001 Hot Oil Furnace (21,664 kW) 357331 5957706 632 41.1 1.85 15.0 288 1.90 0.208 0.175 0.016 Salt Bath/Regeneration Gas Heater (403 kW) 357373 5957640 632 6.1 0.87 35.8 603 0.00 0.004 0.003 0.000 Total 1.90 0.84 0.34 0.05 Marsulex, Fort Saskatchewan Chemical Plant Waste Gas Incinerator Stack 356423 5954504 625 64.0 1.10 2.2 275 0.99 0.004 0.003 0.00 Newalta Corporation, Redwater Disposal Facility Cleaver Brooks Boiler 362791 5980104 625 4.9 0.51 7.1 523 0.00 0.01 0.008 0.001 Volcano Boiler 362791 5980109 625 4.6 0.51 4.3 523 0.00 0.01 0.008 0.001 Total 0.00 0.02 0.02 0.002 Prospec Chemicals, Fort Saskatchewan Xanthate Plant Recuperative Thermal Oxidizer (RTO) 353136 5957717 645 9.5 0.50 2.6 567 0.161 0.004 0.05 0.00 Provident Energy, Redwater Fractionation Facility Acid Gas/Waste Gas Incinerator 359687 5965181 639 15.5 1.60 6.5 280 0.769 0.030 0.025 0.002 Ethane Regen Gas Heater #1 359690 5965216 639 9.5 0.80 3.8 725 0.00 0.007 0.006 0.001 Glycol Regen Heater (raincapped) 359691 5965224 639 14.6 0.50 0.1 725 0.00 0.002 0.002 0.00 Propane Regen Gas Heater 359696 5965206 639 9.4 0.60 3.9 725 0.00 0.004 0.004 0.000 General Flare 359719 5965116 639 54.9 1.80 3.9 1273 0.00 0.055 0.046 0.004 Brine Pond Excess Gas Burner (raincapped) 359566 5965074 639 2.0 6.00 0.1 300 0.00 0.00 0.00 0.00 Total 0.77 0.10 0.083 0.008


December 2006

Page 5A-71



UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Redwater Water Disposal Company, Redwater Waste Disposal Facility

Pump Station Jaco Redwater 8-36 360500 5982200 624 9.8 0.15 1.0 524 0.01 0.00 0.00 0.00 Pump Station Jaco Amelia 7-12 369700 5975100 629 9.8 0.15 1.8 798 0.01 0.00 0.00 0.00 Disposal Well Incinerator S4 367400 5970600 619 14.0 0.71 2.0 1114 0.27 0.00 0.00 0.00 Total 0.29 0.00 0.00 0.00 Shell Canada, Scotford Bitumen Upgrader Vacuum Column Feed Heater 361672 5963406 615 68.0 1.53 19.8 293 0.003 0.208 0.105 0.013 RHC 222 Heaters (common stack) 361647 5963227 615 65.0 1.84 15.2 288 0.002 0.106 0.035 0.008 RHC 223 Heaters (common stack) 361643 5963117 615 65.0 1.84 15.2 288 0.002 0.106 0.035 0.008 SRU Tail Gas Incinerator 361711 5963045 615 90.0 3.37 17.5 291 27.994 0.190 0.086 0.020 Cogeneration Unit Stack 362031 5963119 615 38.1 4.57 25.3 298 0.005 2.108 0.783 0.151 Atmospheric Column Feed Heater 361684 5963471 615 66.0 2.00 20.5 294 0.005 0.506 0.283 0.035 Train #1 Steam Methane Reformer Stack 361977 5962927 615 50.0 4.00 10.0 283 0.017 1.140 0.353 0.044 Train #2 Steam Methane Reformer Stack 362021 5963035 615 50.0 4.00 10.0 283 0.017 1.140 0.353 0.044 Vapour Combustion Unit 361144 5962928 615 12.0 2.00 0.3 273 0.004 0.018 0.025 0.002 Acid Gas Flare 361538 5962841 615 87.6 5.92 0.2 273 0.000 0.005 0.027 0.001 Stage 1 Hydrocarbon Flare 361783 5963610 615 78.1 7.40 0.1 273 0.000 0.003 0.018 0.000 Stage 2 Hydrocarbon Flare 361783 5963626 615 77.1 7.40 0.1 273 0.000 0.001 0.004 0.000 AHS Vacuum Heater 361577 5963540 615 38.1 2.01 20.6 294 0.011 0.146 0.118 0.011 AHS Hot Oil Heater 361580 5963639 615 40.5 1.55 20.9 294 0.008 0.056 0.070 0.006 Total 28.07 5.73 2.29 0.35 Shell Canada Products, Scotford Oil Refinery Crude Distillation (H-1101) 362000 5962574 624 45.7 1.41 18.5 292 0.017 0.226 0.114 0.014 Continuous Catalytic Reformer (H-3201/02/03/04B/04C) 361735 5962437 624 46.0 1.43 36.9 310 0.035 0.788 0.579 0.133 Naphtha Hydrotreater (H-3101) 361812 5962408 624 45.7 0.69 20.0 293 0.003 0.023 0.006 0.002 Steam/Methane Reformer Hydrogen Plant (H-2101/02) 362020 5962810 624 45.7 2.77 20.8 294 0.006 1.071 0.118 0.015 Hydroealylation (H-4201A/B) 362036 5962406 624 45.7 0.86 18.4 291 0.006 0.037 0.027 0.006 Hydrocracker 1 (H-2201/02) 361742 5962835 624 45.7 0.91 15.6 289 0.006 0.050 0.031 0.059 Hydrocracker 2 (H-2301/02) 361740 5962755 624 45.7 0.91 15.6 289 0.006 0.050 0.031 0.059 Hydrocracker Fractionation (H-2401/02) 361736 5962686 624 45.7 1.29 16.5 290 0.013 0.210 0.155 0.036 Distillate Hydrogeneration (H-2501) 361944 5962632 624 45.7 0.49 15.4 288 0.001 0.007 0.001 0.008 Hot Oil Heater (H-1501) 361907 5962571 624 45.7 1.07 11.2 284 0.006 0.042 0.021 0.003 Boiler House (H-5101A/B) 362165 5962447 624 45.7 1.22 20.8 294 0.014 0.215 0.109 0.014 DHT Heater (H-2001) 361980 5962633 624 45.7 0.78 15.0 288 0.003 0.013 0.004 0.002 Continuous Flare 361642 5962835 624 62.4 8.74 0.1 273 0.00 0.002 0.00 0.00 Total 0.117 2.734 1.197 0.35





UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Shell Chemicals Canada, Scotford Styrene & MEG Plant

Reactor Feed Heater HS-101 362804 5963770 624 62.2 1.59 4.3 463 0.00 0.149 0.099 0.012 Regeneration Heater HS-102 362804 5963781 624 30.6 0.51 3.4 823 0.00 0.003 0.005 0.00 Heaters HS-103, HS-104 and HS-105 362922 5963792 624 76.2 1.65 11.2 413 0.001 0.211 0.163 0.015 Steam Superheaters HS-201 and HS-219 362817 5963732 624 78.0 2.74 5.0 473 0.00 0.644 0.403 0.036 Boiler HB-301A 362723 5963823 624 30.5 1.91 6.4 378 0.001 0.185 0.125 0.063 Boiler HB-301B 362723 5963792 624 30.5 1.91 6.1 378 0.001 0.055 0.092 0.008 Boiler HB-301C 362723 5963809 624 30.5 1.91 6.4 378 0.001 0.185 0.125 0.063 CO2 Stripper Vent 362690 5963554 624 54.4 0.45 8.2 281 0.00 0.00 0.00 0.00 Total 0.004 1.432 1.013 0.197 Sherritt International Corporation, Fort Saskatchewan Fertilizer Plant Phosphate Granulation Common Stack 355753 5954476 628 30.5 1.93 11.7 322 0.00 0.021 0.004 0.008 Ammonia I Primary Reformer Stack 355426 5954754 621 21.0 1.65 10.2 445 0.001 0.147 0.069 0.002 AmSO4 Dryer Scrubber Tank Stack 355559 5954625 624 18.2 0.61 19.8 311 0.00 0.004 0.001 0.003 Powerhouse Boiler #1 355556 5954741 623 23.0 2.13 2.5 444 0.001 0.639 0.115 0.003 Powerhouse Boiler #2 355550 5954730 623 23.0 2.13 2.5 444 0.001 0.914 0.115 0.003 Powerhouse Boiler #3 355596 5954734 623 19.0 1.22 15.2 432 0.00 0.001 0.001 0.00 Sulphide Precipitation H2S Scrubber Flare 355616 5954665 624 26.7 2.38 42.4 1273 0.002 0.00 0.00 0.00 Sulphuric Acid Tail Gas Scrubber Stack 355767 5954573 626 61.0 1.52 12.4 350 1.008 0.00 0.00 0.00 Phosphoric Acid Teller Scrubber Stack 355795 5954534 626 36.9 0.74 8.2 299 0.028 0.00 0.00 0.00 Ammonia I Clark Compressor Engine #2 355502 5954833 622 11.0 0.46 25.1 673 0.00 0.77 0.032 0.001 Ammonia I Clark Compressor Engine #3 355490 5954841 622 11.0 0.46 25.1 673 0.00 0.77 0.032 0.001 Ammonia I Clark Compressor Engine #4 355477 5954848 621 11.0 0.46 25.1 673 0.00 0.77 0.032 0.001 Ammonia I Clark Compressor Engine #5 355464 5954856 621 11.0 0.46 13.1 673 0.00 0.77 0.032 0.001 Ammonia I Clark Compressor Engine #6 355452 5954864 621 13.0 0.61 23.8 673 0.00 0.77 0.032 0.001 Ammonia Storage Flare 355419 5954935 620 27.4 0.15 0.2 1273 0.00 0.683 0.573 0.052 Ammonia Unit Flare 355356 5954958 621 18.3 0.40 0.04 1273 0.00 0.978 0.821 0.074 Cobalt Sintering Furnaces (Former Coinage) 355366 5954673 622 11.6 0.40 11.5 444 0.00 0.015 0.002 0.00 Powerhouse Clark Compressor Engine 355570 5954710 623 8.3 0.30 0.4 673 0.00 0.005 0.001 0.00 Nickel Dryer and Sintering Furnaces 355730 5954632 625 7.3 0.35 24.7 444 0.00 0.024 0.004 0.001 Total 1.041 7.283 1.868 0.148 TransAlta Cogeneration, Fort Saskatchewan Cogeneration Power Plant Cogeneration Power Plant Exhaust Stack 356090 5956376 621 32.3 4.57 20.2 391 0.030 1.872 0.690 0.02 TransCanada Energy, Redwater Cogeneration Power Plant Cogeneration Unit (40 MW GE LM 6000) 359928 5965167 639 30.0 3.00 23.6 297 0.000 0.523 0.120 0.01


December 2006

Page 5A-73

Table 5A-68: Detailed Stack and Emission Parameters for the Additional Future Case Stack Emissions


UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Aux Sable Canada, Heartland Offgas Project

Heat Medium Heater (14 MMBtu/h) 365520 5965780 619 4.6 0.61 8.3 281 0.00 0.04 0.04 0.00



Total 0.00 0.13 0.11 0.01

HAZCO Environmental Services, Bruderheim Sulpur Forming Facility

Boiler #1 (150 HP) 376945 5962383 636 14.0 0.41 7.5 280.5 0.00 0.01 0.01 0.00

Rotoform Stack #1 377035 5962383 636 14.0 0.39 16.7 289.7 0.00 0.00 0.00 0.01

Rotoform Stack #2 377101 5962359 636 14.0 0.39 16.7 289.7 0.00 0.00 0.00 0.01

Total 0.00 0.01 0.01 0.02

North West Upgrading, North West Upgrader Project

ACU Heater 360770 5968434 630 60.0 3.04 32.0 579 0.01 4.89 0.05 0.27

VCU Heater 360707 5968434 630 50.0 1.31 37.0 678 0.00 0.59 0.01 0.04

(HC)3 F-101 Heater 360552 5968350 630 50.0 1.21 31.0 563 0.00 0.02 0.01 0.00

(HC)3 F-102 Heater 360552 5968306 630 50.0 1.16 37.0 681 0.00 0.47 0.01 0.04

(HC)3 F-103 Heater 360552 5968262 630 50.0 0.60 39.0 714 0.00 0.11 0.00 0.01

(HC)3 F-104 Heater 360552 5968218 630 50.0 0.54 39.0 710 0.00 0.10 0.00 0.01

HCK Heater 360858 5968337 630 50.0 0.87 33.0 610 0.00 0.03 0.00 0.00

Naph/DistllHTU HTR 360858 5968293 630 50.0 0.91 29.0 534 0.00 0.02 0.01 0.00

Vac Resid Heater 360809 5968527 630 50.0 0.90 32.0 579 0.00 0.25 0.00 0.02

SRU Incinerator 360325 5968173 630 85.0 2.00 47.3 923 26.23 0.00 0.00 0.00

ACU Heater 361179 5968417 630 60.0 3.04 32.0 579 0.01 4.89 0.05 0.27

VCU Heater 361116 5968417 630 50.0 1.31 37.0 678 0.00 0.59 0.01 0.04



Table 5-68: Detailed Stack and Emission Parameters for the Additional Future Case Stack Emissions (cont’d)


UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

North West Upgrading, North West Upgrader Project (cont’d)

(HC)3 F-101 Heater 360965 5968337 630 50.0 1.21 31.0 563 0.00 0.02 0.01 0.00

(HC)3 F-102 Heater 360965 5968293 630 50.0 1.16 37.0 681 0.00 0.47 0.01 0.04

(HC)3 F-103 Heater 360965 5968249 630 50.0 0.60 39.0 714 0.00 0.11 0.00 0.01

(HC)3 F-104 Heater 360965 5968205 630 50.0 0.54 39.0 710 0.00 0.10 0.00 0.01

HCK Heater 361265 5968324 630 50.0 0.87 33.0 610 0.00 0.03 0.00 0.00


Vac Reside Heater 361216 5968510 630 50.0 0.90 32.0 579 0.00 0.25 0.00 0.02

ACU Heater 361592 5968403 630 60.0 3.04 32.0 579 0.01 4.89 0.05 0.27

VCU Heater 361529 5968403 630 50.0 1.31 37.0 678 0.00 0.59 0.01 0.04

(HC)3 F-101 Heater 361374 5968324 630 50.0 1.21 31.0 563 0.00 0.02 0.01 0.00

(HC)3 F-102 Heater 361374 5968280 630 50.0 1.16 37.0 681 0.00 0.47 0.01 0.04

(HC)3 F-103 Heater 361374 5968236 630 50.0 0.60 39.0 714 0.00 0.11 0.00 0.01

(HC)3 F-104 Heater 361374 5968192 630 50.0 0.54 39.0 710 0.00 0.10 0.00 0.01

HCK Heater 361672 5968311 630 50.0 0.87 33.0 610 0.00 0.03 0.00 0.00


Vac Resid Heater 361628 5968496 630 50.0 0.90 32.0 579 0.00 0.25 0.00 0.02

Total 26.28 19.42 0.28 1.16


December 2006

Page 5A-75



UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Shell Canada, Scotford Bitumen Upgrader Vacuum Column Feed Heater 361672 5963406 615 68.0 1.53 19.8 292.8 0.03 0.44 0.35 0.03 RHC 222 Heaters (common stack) 361647 5963227 615 65.0 1.84 15.2 288.2 0.02 0.15 0.20 0.02 RHC 223 Heaters (common stack) 361643 5963117 615 65.0 1.84 15.2 288.2 0.02 0.15 0.20 0.02 SRU Tail Gas Incinerator 361711 5963045 615 90.0 3.37 15.0 288 21.48 0.14 0.12 0.01 Cogeneration Unit Stack 362031 5963119 615 38.1 4.57 25.3 298.3 0.13 1.97 0.80 0.15 Atmospheric Column Feed Heater 361684 5963471 615 66.0 2.00 20.5 293.5 0.04 0.59 0.48 0.04 Train #1 Steam Methane Reformer Stack 361977 5962927 615 50.0 4.00 10.0 283 0.07 1.13 0.92 0.08 Train #2 Steam Methane Reformer Stack 362021 5963035 615 50.0 4.00 10.0 283 0.07 1.13 0.92 0.08 Vapour Combustion Unit 361144 5962928 615 12.0 2.00 0.3 273.3 0.00 0.02 0.02 0.00 Acid Gas Flare 361538 5962841 615 87.6 5.92 0.2 273.2 0.00 0.01 0.03 0.00 Stage 1 Hydrocarbon Flare 361783 5963610 615 78.1 7.40 0.1 273.1 0.00 0.00 0.02 0.00 Stage 2 Hydrocarbon Flare 361783 5963626 615 77.1 7.40 0.1 273.1 0.00 0.00 0.00 0.00 AHS Vacuum Heater 361577 5963540 615 38.1 2.01 20.6 293.6 0.01 0.16 0.15 0.01 AHS Hot Oil Heater 361580 5963639 615 40.5 1.55 20.9 293.9 0.01 0.11 0.10 0.01 Atmospheric Column Feed Heater 361795 5964133 615 66.0 2.00 20.5 473 0.04 0.27 0.22 0.02 Vacuum Column Feed Heater 361847 5964181 614 68.0 1.53 19.8 478 0.01 0.17 0.13 0.01 RHC Heaters (common stack) 361791 5963983 615 65.0 1.84 15.2 688 0.01 0.11 0.14 0.01 SRU Tail Gas Incinerator 361684 5963786 615 90.0 3.03 18.0 673 2.48 0.08 0.07 0.01 HMU Steam Reformer Stack 362040 5963975 614 50.0 4.00 10.0 478 0.09 1.50 1.15 0.10 SDA Hot Oil Heater 361555 5963820 616 40.5 1.55 20.9 478 0.01 0.16 0.14 0.01 SDA Vacuum Column Heater 361605 5963819 615 38.1 2.01 20.6 473 0.01 0.13 0.11 0.01 Vapour Combustion Unit 361246 5964150 617 19.8 1.22 0.3 1253 0.00 0.02 0.02 0.00 Acid Gas Flare 361764 5963784 615 88.5 5.81 0.4 1273 0.00 0.01 0.04 0.00 Hydrocarbon Flare 362067 5964194 614 97.8 11.62 0.1 1273 0.00 0.00 0.02 0.00 Package Steam Boiler 361936 5963861 614 30.5 1.83 10.7 423 0.03 0.39 0.34 0.03 Total 24.55 8.82 6.71 0.68





UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Sherritt International Corporation, Fort Saskatchewan Fertilizer Plant

Phosphate Granulation Common Stack 355753 5954476 628 30.5 1.93 11.7 322 0.00 0.02 0.00 0.01

Ammonia I Primary Reformer Stack 355426 5954754 621 21.0 1.65 10.2 445 0.00 0.15 0.08 0.00

AmSO4 Dryer Scrubber Tank Stack 355559 5954625 624 18.2 0.61 19.8 311 0.00 0.00 0.00 0.00

Powerhouse Boiler #1 355556 5954741 623 23.0 2.13 2.5 444 0.00 0.67 0.15 0.00



Sulphide Precipitation H2S Scrubber Flare 355616 5954665 624 26.7 2.38 42.4 1273 0.00 0.00 0.00 0.00

Sulphuric Acid Tail Gas Scrubber Stack 355767 5954573 626 61.0 1.52 12.4 350 1.01 0.00 0.00 0.00

Phosphoric Acid Teller Scrubber Stack 355795 5954534 626 36.9 0.74 8.2 299 0.03 0.00 0.00 0.00

Ammonia I Clark Compressor Engine #2 355502 5954833 622 11.0 0.46 25.1 673 0.00 0.80 0.04 0.00





Ammonia Storage Flare 355419 5954935 620 27.4 0.15 0.2 1273 0.00 0.69 0.58 0.05

Ammonia Unit Flare 355356 5954958 621 18.3 0.40 0.04 1273 0.00 1.09 0.91 0.08

Cobalt Sintering Furnaces (Former Coinage) 355366 5954673 622 11.6 0.40 11.5 444 0.00 0.02 0.00 0.00

Powerhouse Clark Compressor Engine 355570 5954710 623 8.3 0.30 0.4 673 0.00 0.01 0.00 0.00

Nickel Dryer and Sintering Furnaces 355730 5954632 625 7.3 0.35 24.7 444 0.00 0.02 0.01 0.00

Total 1.04 7.64 2.09 0.16


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UTM E (m)

UTM N (m)

Elevation (m ASL)

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temp

(K) SO2 (t/d)

NOx (t/d)

CO (t/d)

PM2.5 (t/d)

Synenco Energy, Northern Lights Upgrader Project

Atmospheric Tower Heater 362738 5972409 627 45.0 2.39 12.0 285 0.03 0.34 0.30 0.03

Vacuum Furnace 362720 5972409 627 45.0 1.98 12.0 285 0.02 0.24 0.21 0.02

SDA Heater #1 362591 5972405 627 45.0 1.98 12.0 285 0.02 0.23 0.21 0.02

SDA Heater #2 362610 5972405 627 45.0 1.98 12.0 285 0.02 0.23 0.21 0.02

RCD Unionfiner Feed Preheater 362860 5972019 627 45.0 1.04 8.0 281 0.00 0.02 0.03 0.00

Distillate Feed Preheater 362877 5972019 627 45.0 0.70 8.0 281 0.00 0.01 0.01 0.00

Unicracker Feed Preheater 362895 5972018 627 45.0 0.76 8.0 281 0.00 0.01 0.01 0.00

RCD Unionfiner Feed Preheater 362874 5972443 627 45.0 1.04 8.0 281 0.00 0.02 0.03 0.00

Distillate Feed Preheater 362891 5972443 627 45.0 0.70 8.0 281 0.00 0.01 0.01 0.00

Unicracker Feed Preheater 362909 5972442 627 45.0 0.76 8.0 281 0.00 0.01 0.01 0.00

Sulphur Recovery Unit 362659 5972036 627 85.0 2.28 30.0 303 28.77 0.05 0.07 0.01

Gasification 1 362436 5972799 627 45.0 3.31 30.0 303 1.10 3.97 3.70 0.14

Gasification 2 362434 5972683 627 45.0 3.31 30.0 303 1.10 3.97 3.70 0.14

Aux Boiler 1 362500 5972678 627 30.0 1.00 53.4 326.4 0.00 0.13 0.54 0.03

Aux Boiler 2 362500 5972663 627 30.0 1.00 53.4 326.4 0.00 0.13 0.54 0.03

Total 31.08 9.39 9.57 0.43

Sturgeon Upgrader Project Volume 2: Environmental andSection 5A: Source & Emission Inventory Socio-economic Impact Assessment


5A.5.34 Fugitive Industrial Emissions Fugitive emissions sources, due to their nature, are more difficult to quantify, and the following provides an overview of how the fugitive industrial emissions were obtained.

Table 5A-69 provides the fugitive emission parameters for the Base Case on a facility that were used for this assessment. The Base Case includes existing and approved industrial facilities.

For new facilities or for facilities that are proposing an expansion, the fugitive emission parameters for the additional Future Case facilities are provided in Table 5A-70. The parameters in Table 5A-70 replace the parameters in Table 5A-69 for the identified facilities; for all other facilities, the Base Case parameters are still applicable.

5A.6 Non-Industrial Sources

5A.6.1 Regional Study Area Emissions The regional study area also includes non-industrial emission sources that are comprised of commercial emissions, residential heating emissions, and traffic emissions. These non-industrial sources can be and were treated collectively as area sources.

Emission data for Alberta are available on a Census Division Basis, and the regional study area falls within Census Division 11. The Environment Canada emission data for 2000 (the most recently available) for the Census Division were spatially allocated to nominal 4 x 4 km grid cells. Specifically, the emissions that were spatially allocated are as follows:

• Mobile sources include roadway, highway, railroads, off-road vehicles and aircraft. Roadway, highway and railroad emissions were allocated to each grid cell based on the length of the road and rail system with each cell. Off-road use emissions were allocated based on the activity assigned to each cell (e.g. agricultural).

• Non-mobile sources include residential and commercial fuel use. Emissions were allocated to each grid cell based on the level of activities assigned to that cell (e.g. population).

The emission rates for these 4 x 4 km grids are expressed on a per day basis and they are assumed to be uniformly distributed within time. This is somewhat simplistic in that residential heating emission will be based on the cold winter season, and traffic emission will be based on high traffic periods of the day.

The emission values are provided as a series of tables and plots. The results are as follows:

• SO2 emissions (Figure 5A-2) • NOx emissions (Figure 5A-3) • CO emissions (Figure 5A-4) • PM2.5 emissions (Figure 5A-5)


December 2006

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Table 5A-69: Detailed Fugitive Emission Parameters for the Base Case Area Emissions

Operator Agrium Products

Inc. Agrium Products

Inc. ARC Resources

Ltd. BA Energy BP Canada Energy

Company Bunge Canada

Facility Fort Saskatchewan

Fertilizer Plant Redwater Fertilizer

Plant

Redwater Gas Conservation

Plant

Heartland Bitumen Upgrader

Fort Saskatchewan Fractionation Plant

Fort Sask. Oilseed Processing Plant

Model ID AFSF2 ARWF31 ARCR9 BAHBU1 BPFS10 BCFS2 NE UTM E (m) 355300 362400 363500 365499 357750 352150 NE UTM N (m) 5955200 5968100 5980300 5965483 5959150 5955350 SW UTM E (m) 355200 362300 363400 365183 357650 352050 SW UTM N (m) 5955100 5968000 5980200 5965238 5959050 5955250 Area (m2) 10,000 10,000 10,000 77,420 10,000 10,000 Base Elevation (m ASL) 626 626 617 619 626 640 Effective Height (m) 10.0 10.0 10.0 10.0 10.0 10.0 Initial Sigma z (m) 10.0 10.0 10.0 10.0 10.0 10.0 Emission Rates (t/d) VOC 0.036 0.586 0.208 0.0822 0.238 0.0226 PM2.5 0.00 0.00 0.00 0.00 0.00 0.039 H2S 0.00 0.00 0.00279 0.0126 0.00 0.00 Benzene 0.00 0.00 0.00 0.00105 0.00197 0.00 C5-C8 aliphatics 0.00 0.00 0.00 0.0363 0.00 0.00 C9-C18 aliphatics 0.00 0.00 0.00 0.0128 0.00 0.00 C9-C16 Aromatics 0.00 0.00 0.00 0.000713 0.00 0.00 Ethylbenzene 0.00 0.00 0.00 0.00144 0.00 0.00 Hexane 0.00 0.00 0.0124 0.00 0.00 0.0135 Toluene 0.00 0.00 0.00135 0.00557 0.00072 0.00 Xylenes 0.00 0.00 0.0017 0.00248 0.00 0.00



Table 5-69: Detailed Fugitive Emission Parameters for the Base Case Area Emissions (cont’d)

Operator Dow Chemical

Canada Inc. Keyera Energy Ltd. Marsulex Inc. Provident

Energy Limited Shell Canada

Shell Canada Products Limited

Shell Chemicals

Canada Limited


Chemical Plant

Fort Saskatchewan Fractionation


Chemical Plant

Redwater Fractionation

Facility Scotford Upgrader

Scotford Oil Refinery

Scotford Styrene &

MEG Model ID DCFS37 KEFS9 MFSC2 PERW7 SSBU15 SSOR14 SSSM9 NE UTM E (m) 357350 357350 356450 359700 362131 362200 363200 NE UTM N (m) 5956300 5957700 5954550 5965150 5963739 5962800 5963950 SW UTM E (m) 357150 357250 356350 359600 361044 361100 362800 SW UTM N (m) 5955700 5957600 5954450 5965050 5962741 5962300 5963700 Area (m2) 120,000 10,000 10,000 10,000 1,084,826 550,000 100,000 Base Elevation (m ASL) 627 632 625 643 622 616 629 Effective Height (m) 10.0 10.0 10.0 10.0 10.0 10.0 10.0 Initial Sigma z (m) 10.0 10.0 10.0 10.0 10.0 10.0 10.0 Emission Rates (t/d) VOC 0.158 1.53 0.00 0.0714 0.66 0.262 0.07 H2S 0.000326 0.000384 0.0000383 0.00 0.031 0.00266 0.00 CS2 0.00 0.00259 0.00 0.00 0.00 0.00 0.00 COS 0.00 0.0045 0.00 0.00 0.00 0.00 0.00 Acetaldehyde 0.0000137 0.00 0.00 0.00 0.00 0.00 0.00 Anthracene 0.00 0.00 0.00 0.00 0.00 0.00000546 0.00 Ammonia 0.00 0.00 0.00 0.00 0.000437 0.00 0.00337 Benzene 0.000452 0.00562 0.00 0.00 0.00498 0.00366 0.0181 Benzo(a)anthracene 0.00 0.00 0.00 0.00 0.00 0.000000052 0.00 Benzo(a)pyrene 0.00 0.00 0.00 0.00 0.00 0.00000003 0.00 Benzo (b)fluoranthene 0.00 0.00 0.00 0.00 0.00 0.0000000274 0.00 Benzo(g,h,i)perylene 0.00 0.00 0.00 0.00 0.00 0.00000417 0.00 Benzo(k)fluoranthene 0.00 0.00 0.00 0.00 0.00 0.0000000383 0.00 C5-C8 aliphatics 0.00 0.00 0.00 0.00 0.288 0.00 0.00 C9-C18 aliphatics 0.00 0.00 0.00 0.00 0.0024 0.000902 0.00 C9-C16 Aromatics 0.0000246 0.00 0.00 0.00 0.00585 0.000587 0.00 Chrysene 0.00 0.00 0.00 0.00 0.000000000904 0.00 0.00 Cyclohexane 0.00 0.0135 0.00 0.000734 0.00 0.000454 0.00 Dibenz(a,h)anthracene 0.00 0.00 0.00 0.00 0.00 0.0000000411 0.00 Ethylbenzene 0.00 0.000137 0.00 0.00 0.000672 0.00157 0.0136 Fluoranthene 0.00 0.00 0.00 0.00 0.00 0.000000099 0.00 Formaldehyde 0.00 0.00 0.00 0.00 0.00 0.00 0.000587 Hexane 0.000186 0.059 0.00 0.00492 0.361 0.0142 0.00 Indeno(1,2,3-cd)pyrene 0.00 0.00 0.00 0.00 0.00 0.00000038 0.00 Naphthalene 0.0000384 0.00 0.00 0.00 0.0000455 0.000587 0.00 Phenanthrene 0.00 0.00 0.00 0.00 0.0000000112 0.000012 0.00 Pyrene 0.00 0.00 0.00 0.00 0.0000000017 0.0000015 0.00 Styrene 0.0000329 0.00 0.00 0.00 0.000000331 0.00 0.0295 Toluene 0.0000767 0.0037 0.00 0.000252 0.00355 0.0101 0.000986 Xylenes 0.00 0.00108 0.00 0.0000712 0.00127 0.0146 0.0000492


December 2006

Page 5A-81

Table 5A-70: Detailed Fugitive Emission Parameters for the Future Case Area Emissions

Operator Access Pipeline Inc. North West Upgrading

Inc. Shell Canada Synenco Energy

Inc. Terasen

Pipelines

Facility Redwater Trim Blending

Facility North West Upgrader

Project Phase I Scotford Upgrader

Northern Lights Upgrader Project

Heartland Storage Tank

Terminal Model ID APRWB NWUP29 SSBU15 SENLU16 TPHST UTM Zone 12 12 12 12 12 Area Source Locations NE UTM E (m) 360644 361783 362131 362800 365861 NE UTM N (m) 5967438 5968617 5963739 5972500 5966529 SW UTM E (m) 360144 360251 361044 362600 365295 SW UTM N (m) 5966938 5967763 5962741 5972300 5966029 Area (m2) 250000 1308328 1084826 40000 283000 Base Elevation (m ASL) 630 630 622 627 619 Effective Height (m) 10 10 10 10 10 Initial Sigma z (m) 10 10 10 10 10 Emission Rates (t/d) VOC 0.0239 0.301 1.23 1.11 0.10515 H2S 0.00000105 0.00315 0.033 0.00777 0.000108 CS2 0.00 0.00358 0.00 0.00841 0.00 Mercaptan Group 0.00 0.0000219 0.00 0.0000517 0.00 Thiopene Group 0.00 0.0137 0.00 0.0338 0.00 Aliphatic Alcohols 0.00 0.00262 0.00 0.00642 0.00 Aliphatic Aldehydes 0.00 0.00245 0.00 0.00599 0.00 Aliphatic Ketones 0.00 0.00393 0.00 0.00961 0.00 Ammonia 0.00 0.00 0.00286 0.00 0.00 1,3-butadiene 0.000243 0.000249 0.00 0.000509 0.00 Benzene 0.000229 0.00289 0.024 0.00701 0.00101 C5-C8 aliphatics 0.00 0.1667 0.538 0.405 0.00 C9-C18 aliphatics 0.00 0.0574 0.00292 0.14 0.00 C9-C16 Aromatics 0.00 0.006041 0.011 0.148 0.00 Chrysene 0.00 0.00 0.0000000009 0.00 0.00 Cyclohexane 0.00 0.00000274 0.00 0.00 0.00 Ethylbenzene 0.000638 0.00671 0.00323 0.0164 0.0000202 Hexane 0.000719 0.00663 0.361 0.0161 0.00 Naphthalene 0.00 0.00 0.00009 0.00 0.0000000612 Phenanthrene 0.00 0.00 0.000000000112 0.00 0.00 Pyrene 0.00 0.00 0.000000000017 0.00 0.00 Styrene 0.00 0.00 0.000000331 0.00 0.00 Toluene 0.00195 0.0236 0.0261 0.0576 0.000572 Xylenes 0.00122 0.0108 0.0055 0.0262 0.000091



310000 320000 330000 340000 350000 360000 370000 380000 390000 400000UTM mE

5920000

5930000

5940000

5950000

5960000

5970000

5980000

5990000

6000000

6010000

UTM

mN

SO2 (t/d) 0 to 0.02 0.02 to 0.1 0.1 to 0.3 0.3 to 0.6 0.6 to 2

Fort Saskatchewan

SO2 Emissions (Tonne/day)

Figure 5A-2: SOx Emissions from Community Source Based on 2000 Emission Data


December 2006

Page 5A-83

310000 320000 330000 340000 350000 360000 370000 380000 390000 400000UTM mE

5920000

5930000

5940000

5950000

5960000

5970000

5980000

5990000

6000000

6010000U

TM m

N

NOx (t/d) 0 to 0.1 0.1 to 0.5 0.5 to 1 1 to 2 2 to 17

Fort Saskachewan

NOx Emissions (Tonne/day)

Figure 5A-3: NOx Emissions from Community Source Based on 2000 Emission Data



310000 320000 330000 340000 350000 360000 370000 380000 390000 400000UTM mE

5920000

5930000

5940000

5950000

5960000

5970000

5980000

5990000

6000000

6010000

UTM

mN

CO (t/d) 0 to 0.5 0.5 to 1 1 to 5 5 to 10 10 to 54

Fort Saskatchewan

CO Emissions (tonne/day)

Figure 5A-4: CO Emissions from Community Source Based on 2000 Emission Data


December 2006

Page 5A-85

310000 320000 330000 340000 350000 360000 370000 380000 390000 400000UTM mE

5920000

5930000

5940000

5950000

5960000

5970000

5980000

5990000

6000000

6010000U

TM m

N

PM2.5 (t/d) 0 to 0.02 0.02 to 0.05 0.05 to 0.2 0.2 to 1 1 to 2.5

Fort Saskatchewan

PM2.5 Emissions (tonne/day)

Figure 5A-5: PM2.5 Emissions from Community Source Based on 2000 Emission Data



The emission rates provided are based on 2000 emission estimates. These values were assumed to represent the Base Case and the Future Case. As the population increases, the levels of activity will increase which will tend to increase emissions, all things being equal. The potential emission increases, however, will be offset by the implementation of more effective technology. The Environment Canada emission projections for Alberta tend to support this premise. For example, NOx emissions associated with residential fuel combustion are projected to decrease slightly from 6907 t/a in 2000, to 6687 t/a in 2015. NOx emission associated with light-duty gasoline trucks and vehicles are projected to decrease from 42,753 t/a in 2000 to 21,818 t/a in 2015. On this basis, the 2000 emission values could overstate the future emissions in the region.

5A.6.2 Census Management Division 11 Area Emissions Cheminfo services recently completed a forecast of common air contaminated emission in Alberta for the period 1995 to 2020 (Cheminfo 2002). This study was undertaken for the Alberta Clean Air Strategic Alliance (CASA). A summary of Census Division 11 projection for 2010 is provided in Table 5A-71.

Census Division 11 includes the Cities of Edmonton, Fort Saskatchewan, industrial area, and the power plants in the Wabamun area. The following comments can be made relating to the Census Division emissions (CD):

• Most of the SO2 emissions in the CD are due to the Power Generation, Oil Sands and Upstream Oil & Gas industrial sections. The oil sands projection does not reflect the currently approved and Upgrader in the Fort Saskatchewan area.

• Most of the NOx emissions in the CD are due to the Power Generation, Transportation, and Upstream Oil & Gas sections.

• Most of the PM2.5 emissions are due to Power Generation and Paved Dust sources.

• Most of the VOC emissions are due to Upstream Oil & Gas activities.

• Most of the CO emissions are due to Transportation (motor vehicles).

• Most of the NH3 emissions are due to Agricultural activities associated with livestock.

The Cheminfo report indicates that the levels of uncertainty in emission inventory and projection values vary by source category and pollutant. Typically, levels of accuracy are as follows: ±5 percent for SOx, ±20 percent for NOx, and ±30 percent for CO. “Large” uncertainties (the values are unstated) are associated with VOC and PM emissions.


December 2006

Page 5A-87

Table 5A-71: Summary of Census Division 11 Air Emission for 2010 Contaminant

(t/d) Source Category SOx NOx CO PM2.5 VOC NH3

Cement and Concrete 0.008 4.515 0.290 0.164 0.038 0.000 Chemicals 8.025 47.575 1.819 0.345 27.926 14.164 Mining 0.258 0.175 0.000 1.477 0.090 0.047 Iron and Steel 0.047 0.630 0.036 0.236 0.005 0.005 Non-Ferrous Refinery 11.455 1.274 0.068 0.036 0.005 0.003 Oil Sands 33.301 9.101 1.800 0.200 1.000 0.011 Petroleum Refining 23.318 11.501 2.953 2.858 2.134 0.058 Pulp and Paper 0.000 0.000 0.000 0.000 0.000 0.285 Upstream Oil & Gas 30.630 70.378 11.310 0.389 197.277 0.000 Manufacturing 0.148 14.707 145.619 7.915 0.537 0.345 Power Generation 166.852 181.893 17.677 13.885 2.477 0.652 Commercial 0.381 4.816 0.899 0.452 0.230 0.025 Residential 0.468 6.474 73.888 10.126 43.932 0.085 Transportation Total 6.912 92.208 299.175 3.638 28.893 2.145 Road Dust-Paved 0.000 0.000 0.000 6.773 0.000 0.000 Road Dust-Unpaved 0.000 0.000 0.000 14.962 0.000 0.000 Incineration 0.003 0.000 0.000 0.000 0.047 0.000 Smoking 0.000 0.000 0.301 0.063 0.000 0.000 Structural Fires 0.000 0.000 1.641 0.737 0.795 0.000 Dry Cleaning 0.000 0.000 0.000 0.000 0.167 0.000 Fuel Marketing 0.000 0.000 0.000 0.000 13.159 0.000 General Solvent Use 0.000 0.000 0.000 0.000 37.227 0.000 Printing 0.000 0.000 0.000 0.000 2.260 0.000 Surface Coating 0.000 0.000 0.000 0.000 7.323 0.000 Agricultural (Livestock) 0.030 0.000 0.000 0.622 0.000 72.066 Agricultural (Tilling) 0.000 0.000 0.000 1.775 0.000 0.000 Agricultural (Pesticide/Fertilizer) 0.000 0.000 0.000 0.129 0.000 18.907 Construction 0.000 0.000 0.000 5.290 0.000 0.000 Landfill 0.000 0.000 0.000 0.014 0.403 0.000 Meat Cooking 0.000 0.000 0.000 0.126 0.000 0.000 Mine Tailing 0.000 0.000 0.000 0.022 0.000 0.000 Total (t/d) 282 445 557 72 366 109



5A.7 References B.A. Energy Inc. 2004. Volume 2: Environmental Impact. BA Energy Heartland Upgrader

Application. Submitted to AENV and the EUB, May 2004.

ChemInfo Services Inc. 2002. Forecast of Common Air Contaminants in Alberta (1995 to 2020). Prepared for Clean Air Strategic Alliance (CASA). Toronto, ON.

North West Upgrading Inc. 2006. North West Upgrader Project: Integrated Application for Approval. Volume II Environmental Report #1. Air Quality. 538 pages. Submitted to AENV and the EUB. January 2006.

Shell Canada Limited. 2005. Environment Impact Assessment: Scotford Upgrader Expansion Project. Section 5 Air. Submitted to AENV and the EUB.

Documents

APPENDIX 5A SOURCE AND EMISSION INVENTORY · 1. Conventional stacks are defined by location, base elevation, stack height, stack diameter, gas exit velocity, gas exit temperature,