Attachment A Amendment Application Concordance

Transcription

Attachment A
Amendment Application Concordance Tables, Requested EPEA
Approval Changes and Existing Approvals
Concordance Table
Alberta Energy Regulator
Draft Directive 023: Oil Sands Project Applications
Devon NEC Corporation
Pike 1 Project
Application for Amendment
March 2015
Table A-1: Concordance Table – Draft Directive 023: Oil Sands Project Applications
Draft Directive 023 Information Requirements
Section of Draft
Directive 023
3
Location
in Application
Description
General Application Requirements
3.1
Introduction
Section 1.1
3.2
Applicant Eligibility
Section 1.2
3.3
Project Description Requirements
Sections 1.1, 1.2, 1.3 and 1.4
4
Stakeholder Involvement
Section 5.0
5
Socio-economic Requirements
Section 4.14
6
Environmental Requirements
7
6.2
Land Use
Section 4.10
6.3
Soils
Section 4.7
6.4
Vegetation and Wetlands
Section 4.8
6.5
Wildlife
Section 4.9
6.6
Hydrology
Section 4.4
6.7
Surface Water Quality
Section 4.5
6.8
Fisheries
Section 4.6
6.9
Hydrogeology and Water Source
Section 4.3
6.10
Air Quality and Emissions
Section 4.1
Insitu Applications
7.6
Reserves
Section 2.2
7.11
Disposal Schemes
Section 2.2.3
7.13
Facilities
Section 2.5
Note:
Sections from the Draft Directive 023 excluded from the table above remain unchanged from the Approved Project (AER Approval No. 12301).
Attachment A – Concordance Table: AER Draft Directive 023 – Page 1
Concordance Table
Environmental Protection and Enhancement Act
Guide to Content for Industrial Approval Applications
Pike 1 Project
March 2015
Table A-2: Concordance Table – Environmental Protection and Enhancement Act Guide to Content for Industrial Approval Applications
EPEA Guide to Content for Industrial Approval Applications Information Requirements
Section of Guide
Location
in Application
Description
Part 3
AMENDMENTS
17
Confirm Applicant Identification
17.1
Applicant`s name using the Authorization of Application Approval Form (Appendix A), including full Alberta registered
name of the corporation.
Section 1.2
17.2
Mailing address of the person responsible.
Section 1.2
17.3
Mailing address of applicable plant or regional office.
Section 1.2
17.4
For each contact on the application, provide the following information:
•
name and signature;
•
title and corporate department;
•
telephone number;
•
fax number; and
•
email address.
Section 1.2
17.5
18
19
For amendments that are solely for the transfer of responsibility of the approval holder to a new entity fill out the
special form in Appendix A.
Confirm Plant or Facility Identification
N/A
18.1
Classification of this facility under the Activities Designation Regulation. Highlight if the proposed changes to the facility
affect the classification of the plant or facility.
Section 1.4.2
18.2
Location of the plant or facility, including:
•
legal land description; and
•
latitude and longitude coordinates.
Section 2.1
18.3
Map showing the direction and distance of the plant or facility to nearby towns, cities, villages, or residences and
special areas (e.g., recreation areas, camps or protected areas), other plants and facilities, and wetlands or
watercourses or other potential locations of receptors.
Section 1.1
18.4
Physical size and capacity of the plant or facility site and area that has been, or has a reasonable potential to be
affected by the activity, including maps and scaled diagrams.
Section 1.3, Section 2.4
Project Background for the Proposed Changes
19.1
Government approved regional initiatives or plans that pertain to the area with requirements that relate to environment
and resource management for the proposed changes to the activity.
Section 3.0
19.2
Hearing results or decisions which set or modify the environmental requirements.
Section 1.4.3
19.3
The date the Environmental Impact Assessment (EIA) report was accepted by the Director.
Section 1.4.1
Attachment A – Concordance Table: EPEA Guide to Content for Industrial Approval Applications – Page 1
Pike 1 Project
March 2015
Location
in Application
Section of Guide
Description
19 (cont)
19.4
Authorizations related to the proposed changes identified in this application and their date of issuance (Leases,
Permits, or Approvals).
Section 1.4.1
19.5
For activities that require financial security, identify if the amount is affected by the proposed change. Provide an
updated calculation for security, and include the assumptions and justification for their use in the calculation.
Section 1.6
19.6
Proposed project or estimate timelines and major milestones for the proposed changes.
Section 1.3
19.7
If public consultation or stakeholder engagement has been, or will be, conducted outside of this approval amendment
process for the proposed changes, provide the following information:
•
target audience(s);
•
type, purpose, and frequency of consultation or engagement; and
•
identified environmental concerns and how they were, or will be addressed in the project design.
Section 5.0
20
Update to Current Setting and its Environmental Condition
20.1
Identify which aspects of the setting or environmental conditions require updating based on the proposed changes to
the activity.
Section 4.0
20.2
Describe the current setting and current environmental conditions for these aspects.
Section 4.0
20.3
For all government regional initiatives or plans identified in 19.1, approved or under development, identify and
comment on changes over the last approval period to any term, conditions or commitments that relate to the
environment.
Section 3.0
20.4
21
For all government regional initiatives or plans identified in 19.1, approved or under development, describe and
highlight any changes to the plant or facility`s obligations, potential obligations or opportunities.
Changes to Design and Operation
Section 3.0
21.1
Proposed changes to the plant or facility`s process and provide a process diagram of the specific industrial processes
related to the proposed change in industrial activity. Include both the processing operations and the controlled
processes. The changes need to be described as both the incremental changes and resulting total releases from the
previous application and shall include:
•
raw materials, products and by-products. Include maximum and normal operating and upset design quantities
used or produced per unit of time. Provide all other pertinent capacity measurements for the site;
•
major equipment and unit capacities; and
•
mass balances.
Section 2.5, Attachment B
21.2
Proposed changes in the nature or type of substances that will be generated in a typical operating day at the plant or
facility, and explain both the incremental change and the projected totals.
Section 2.9, Section 4.1
21.3
Alternatives examined in the proposed changes to the overall plant or facility processes to optimize efficiency and
minimize anticipated substance releases and/or waste generation and criteria used in selection, include supporting
energy balances.
N/A
21.4
How the proposed project`s overall footprint on land will be minimized.
Section 2.1
Pike 1 Project
March 2015
Location
in Application
Section of Guide
Description
21 (cont)
21.5
Scale diagrams of the plant or facility site and highlight changes required for this amendment application. On the
diagrams, identify changes to pollution prevention and control infrastructure and equipment associated with collection
and storage of product or feedstock, waste, wastewater, or runoff or permanent disposal.
Section 2.5.3
21.6
Design and specification details of the proposed changes and control systems.
Section 2.5.9, Section 2.8,
Section 2.9
21.7
Proposed changes to monitoring to evaluate the performance of collection and storage elements, and any leak
detection systems, that will be used for each containment area or tank identified in 21.6, include both new and
impacted existing areas.
Section 2.5.9
21.8
Process flow diagrams for the proposed changes to the existing treatment and release control systems for the
substances identified in each wastewater stream, with mass balances and flow directions. Explain both the incremental
change and the projected totals. Include:
•
wastewater reuse or minimization opportunities;
•
anticipated volumes, rates, and amounts of each wastewater or runoff stream; and
•
the physical size, location and capacity of wastewater treatment systems.
Section 2.8
21.9
The suitability and capacity of the proposed changes to the existing treatment and release control systems for the
substances identified in each wastewater stream and for each proposed disposal alternative:
a) for releases to watercourses;
b) for proposed wastewater, runoff sludge releases to land;
c) for wastewater or runoff disposal by deepwell injection; and
d) for wastewater or runoff release to municipal facilities or sludges to landfills.
Section 2.2.3, Section 2.8
21.10
For the systems identified in 21.8 and 21.9, provide a scale diagram, showing any proposed changes to the location of
treatment facilities to the location of treatment facilities and disposal locations (latitude and longitude coordinates) with
consideration of factors identified in Section 20.
Section 2.5.3, Section 2.8.4
21.11
For the systems identified in 21.8 to 21.10, identify any changes in locations and describe any proposed changes to
monitoring for performance evaluation of the treatment, reuse, and wastewater minimization elements.
Section 2.2.3, Section 2.8.4
21.12
For 21.8 to 21.10, identify any changes in locations and describe any proposed changes to monitoring and evaluation
to monitoring and evaluation of the quality, quantity and whole effluent toxicity, for the release of treated wastewater.
No Change from the Approved
Project1
21.13
Proposed changes to the location or to the monitoring and evaluation of any ambient monitoring.
Project1
21.14
For the systems identified in 21.8 to 21.9, provide data, calculations, models and reliable literature sources for each
wastewater stream proposed for release and the associated release or disposal method.
Section 4.3, Attachment E
21.15
Referencing 21.1 and 21.2, describe the proposed changes in the nature or types of substances that will be directly or
indirectly released to the air in a typical operating day at the plant or facility.
Section 4.1, Attachment C
Pike 1 Project
March 2015
Location
in Application
Section of Guide
Description
21 (cont)
21.16
For each air emission stream that is proposed in this application to change, identify:
•
the volume(s) and concentrations generated, per unit time or the release substance;
•
normal and maximum emission rate per unit time and per unit of production based on the design and
throughput of the industrial site;
•
whether the emissions are continuous or intermittent, and the frequency (if intermittent); and
•
estimates of seasonal and/or monthly variability for each stream.
21.17
Proposed modifications to the application of process technology, environmental control systems, and management
practices that will be used to minimize substance release to the environment.
Section 2.5, Section 4.1,
Attachment C
21.18
Update the following details for all:
•
reciprocating or turbine engines;
•
all fired heaters (including space heaters), treaters, and boilers;
•
incinerators; and
•
flare stacks.
Section 2.5, Section 4.1,
Attachment C
21.19
Details for any changes to the flare pits onsite.
N/A
21.20
All proposed changes in fugitive emissions related to the site.
Section 4.1.3
21.21
Changes in area, or non-point, emission sources related to the industrial site.
21.22
Suitability and capacity of the proposed changes to treatment and release control systems using a dispersion modeling
run to show the maximum ground level concentration.
21.23
Updated scale diagrams of the plant, plant site, and the surrounding area with regard to air emissions, and include the
location and distance between them all.
21.24
For 21.17 to 21.22, describe proposed changes to the existing monitoring or proposal for new monitoring for
performance evaluation of the modified or new treatment and control equipment (source) systems.
Project1
21.25
Proposed changes to the location or to the monitoring and evaluation of the ambient air quality.
Project1
21.26
For air emissions, provide data, calculations, models, and reliable literature sources for each wastewater stream
proposed to release for the associated release or disposal method.
21.27
Proposed changes to be made to the identified existing monitoring programs, operating procedures, management
systems, emergency preparation, and contingency plans.
Project1
21.28
New proposed monitoring programs, operating procedures, management systems, emergency preparation, and
contingency plans.
Project1
Pike 1 Project
March 2015
Section of Guide
22
Location
in Application
Description
Reclamation
22.1
Plan that shows the footprint of disturbed land, presenting each proposed reclamation footprint section and highlighting
each phase of reclamation.
Section 6.1.1
22.2
Approximate timeline for each phase of reclamation.
Section 6.2.2
22.3
Plan for dismantling.
Section 6.2.2
22.4
Plan for decontamination.
Section 6.2.2
22.5
How all wastes generated during reclamation will be managed.
Project1
22.6
How dust, odours, contaminants, and noise will be controlled to protect offsite neighbors.
Project1
22.7
How runoff will be managed during reclamation, and changes from current methods for managing runoff.
Project1
22.8
Land reclamation that has already taken place.
N/A
22.9
End land-use and land capability ratings.
Section 6.2.2
22.10
Proposed reclamation of landform, drainage, and watercourses.
Project1
22.11
Effectiveness of any new alternatives for any proposed “engineered” watercourses (e.g., streams, lakes, wetlands).
Project1
22.12
Plan for replacing reclaimed soil that is compatible with the proposed end land use.
Section 6.2.2
22.13
Plan for revegetating the site.
Section 6.2.1
22.14
Stakeholder involvement, including who will be involved, at what point(s), and in what manner.
Section 5.0
22.15
Contact information and means for which questions or concerns may be directed to the facility prior to, or during
reclamation activities.
Section 1.2
Notes:
N/A – not applicable.
1 AER EPEA Approval No. 308463-00-00.
Requested EPEA Approval Changes
Pike 1 Project
March 2015
Table A-3: Requested EPEA Approval Changes
Condition
3.4
Table 3.1
Air Emission Limits
Requested Condition Revision
Change the Plant (after sulphur removal) sulphur dioxide limit to 2.42 tonnes per day.
Replace reference to 92.6 MW steam generators with 92.5 MW steam generators. No
change to the oxides of nitrogen (expressed as NO2 from 8.8 kilograms per hour).
No change to the oxides of nitrogen (expressed as NO2) of 0.9 kilograms per hour for
the glycol heaters.
Replace reference to 4.1 MW flash treaters with 2.05 MW flash treaters. No change to
the oxides of nitrogen (expressed as NO2) of 0.2 kilograms per hour.
3.7
Table 3.2
Air Emission Source
Monitoring and
Reporting
Replace reference to seven 92.6 MW steam generators per phase with six 92.5 MW
steam generators per phase.
Change the CEMS instrumentation requirements from any two of the seven 92.6 MW
steam generators per phase to any two of the six 92.5 MW steam generators per
phase.
Change the manual stack survey requirements from any of the five 92.6 MW steam
generators per phase without a CEM to any of the five 92.5 MW steam generators per
phase without a CEM.
Change the manual stack survey requirements from each of the six 9.15 MW glycol
heaters to each of the four 9.15 MW glycol heaters.
Change the manual stack survey requirements from each of the three 4.1 MW flash
treaters to each of the two 2.05 MW flash treaters.
Schedule IV,
Condition 1 (a), (b),
(c), (d), (f)
Air Emissions
(a) Replace reference to twenty-one 92.6 MW steam generator exhaust stacks with
twelve 92.5 MW steam generator exhaust stacks.
(b) Replace reference to six 9.15 MW glycol heater exhaust stacks with four
9.15 MW glycol heater exhaust stacks.
(c) Replace reference to six 4.1 MW flash treater exhaust stacks with four 2.05 MW
flash treater exhaust stacks.
(d) Replace reference to six 1.5 MW diesel-fired emergency generator exhaust
stacks with four 1.5 MW diesel-fired emergency generator exhaust stacks.
(e) Remove the low pressure flare stack.
Attachment A: Requested EPEA Approval Changes – Page 1
Pike 1 Project
March 2015
Condition
Schedule IV,
Condition 2
Table 1
Stack Heights
Replace reference to twenty-one 92.6 MW steam generator exhaust stacks (stack
heights 28.9 m) with twelve 92.5 MW steam generator exhaust stacks (stack heights
27.0 m).
Replace reference to six 9.15 MW glycol heater exhaust stacks (stack heights 6.7 m)
with four 9.15 MW glycol heater exhaust stacks (stack heights 6.7 m).
Replace reference to six 4.1 MW flash treater exhaust stacks (stack heights 6.0 m)
with four 2.05 MW flash treater exhaust stacks (stack heights 6.0 m).
Replace reference to six 1.5 MW diesel-fired emergency generator exhaust stacks
(stack heights 5.7 m) with four 1.5 MW emergency power generator exhaust stacks
(stack heights 5.7 m).
Replace reference to one high pressure flare stack (stack height 41.1 m) with two
high pressure flare stacks (stack heights 41.1 m).
Remove reference to the low pressure flare stack.
Schedule V
Condition 2 (b)
Industrial
Wastewater,
Produced Water and
Boiler Blowdown
(a) Remove reference to the evaporator(s).
Schedule IV,
Condition 3
Industrial Runoff from
the Plant Developed
Area
Replace the reference to the two industrial runoff ponds with one industrial runoff
pond.
Schedule VI,
Condition 1
Groundwater
Monitoring Program
Proposal
The Approval holder shall submit an updated Groundwater Monitoring Program
proposal by a date specified by the Director.
Schedule VII,
Condition 2 (a), (b)
Soil Monitoring
Program Proposal
(a) Change the requirement for the first soil monitoring event on or before
November 30, 2017 to a revised date per the discretion of the Director.
Schedule VII,
Condition 6 (a), (b)
Soil Monitoring
Program Report
(a) Change the requirement for the first Soil Monitoring Program Report on or before
(b) Change the requirement for the second soil monitoring event on or before
(b) Change the requirement for the second Soil Monitoring Program Report on or
before November 30, 2023 to a revised date per the discretion of the Director.
Pike 1 Project
March 2015
Condition
Schedule VIII,
Condition 17 (a), (b),
(c)
Comprehensive
Wildlife Reports
Change the requirement for the approval holder to submit:
(a) The first Comprehensive Wildlife Report on or before May 15, 2016 to a revised
date per the discretion of the Director.
(b) The second Comprehensive Wildlife Report on or before May 15, 2019 to a
revised date per the discretion of the Director.
(c) The third Comprehensive Wildlife Report on or before May 15, 2022 to a revised
date per the discretion of the Director.
Schedule IX,
Condition 26
Project-Level
Conservation,
Reclamation and
Closure Plan
Change the requirement for the Project-Level Conservation, Reclamation and Closure
Plan to the Director on or before June 30, 2016 to a revised date per the discretion of
the Director.
Schedule IX,
Condition 39
Wetland Reclamation
Trial Program
Proposal
Change the requirement for the approval holder to submit the project specific Wetland
Reclamation Trial Program proposal to the Director on or before December 31, 2019
to a revised date per the discretion of the Director.
Schedule IX,
Condition 44
Reclamation
Monitoring Program
Proposal
Change the requirement for the approval holder to submit the Reclamation Monitoring
Program proposal to the Director on or before December 31, 2018 to a revised date
per the discretion of the Director.
Existing EPEA Approval, Commercial Scheme Approval and
Order in Council
APPROVAL
ALBERTA ENERGY REGULATOR
ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT
R.S.A. 2000, c.E-12, as amended.
00308463-00-00
APPROVAL NO.:
001-00308463
APPLICATION NO.:
November 6, 2014
EFFECTIVE DATE:
October 31, 2024
EXPIRY DATE:
APPROVAL HOLDER:
ACTIVITY: Construction, operation and reclamation of the.
Pike 1 Project enhanced recovery in-situ oil sands or heavy oil processing plant and oil
production site
is subject to the attached terms and conditions, and Schedules I to XI.
Steve Cook
Approvals Manager, Authorizations Branch
Alberta Energy Regulator
November 6, 2014
APPROVAL NO.
308463-00-00
Page 1 of 47
………………….
TERMS AND CONDITIONS ATTACHED TO APPROVAL
DEFINITIONS
1.1
All definitions from the Act and the regulations apply except where expressly defined in
this approval and Schedule I.
GENERAL
2.1
The approval holder shall:
(a)
construct;
(b)
operate;
(c)
maintain; and
(d)
reclaim;
the plant in accordance with this approval.
2.2
The approval holder shall comply with the terms and conditions, and Schedules I to XI,
attached hereto and forming part of this approval.
2.3
The approval holder shall construct the plant as described in the application, unless
otherwise authorized in writing by the Director.
2.4
The approval holder shall notify the Director in writing at least 14 days before
commencing operations of the plant.
AIR EMISSIONS
3.1
The approval holder shall not release any air effluent streams to the atmosphere except
as authorized by this approval.
3.2
The approval holder shall control fugitive emissions and any air emission source not
specified in condition 1 of Schedule IV in accordance with condition 3.3, unless
3.3
With respect to fugitive emissions and any air emission source not specified in condition
1 of Schedule IV, the approval holder shall not release a substance or cause to be
released a substance that causes or may cause any of the following:
(a)
impairment, degradation or alteration of the quality of natural resources;
(b)
material discomfort, harm or adverse effect to the well being or health of a
person; or
APPROVAL NO.
308463-00-00
Page 2 of 47
………………….
(c)
3.4
harm to property or to the vegetative or animal life.
Releases of the following substances to the atmosphere shall not exceed the limits
specified in TABLE 3.1.
TABLE 3.1:
AIR EMISSION LIMITS
AIR EMISSION SOURCE
SUBSTANCE
LIMIT
Plant
(prior to sulphur removal)
Sulphur Dioxide
2.0 tonnes per day
Plant
(after sulphur removal)
Sulphur Dioxide
1.2 tonnes per day
Each of the 92.6 MW steam
generators
Oxides of nitrogen
(expressed as NO2)
8.8 kilograms per
hour
Each of the 9.15 MW glycol heaters
Oxides of nitrogen
(expressed as NO2)
0.9 kilograms per
hour
Each of the 4.1 MW flash treaters
Oxides of nitrogen
(expressed as NO2)
0.2 kilograms per
hour
3.5
The approval holder shall not operate the process equipment unless and until the
associated pollution abatement equipment is operating.
3.6
The approval holder shall monitor the air emission sources as specified in TABLE 3.2,
unless otherwise authorized in writing by the Director.
3.7
The approval holder shall report to the Director the results of the air emission source
monitoring as required in TABLE 3.2, unless otherwise authorized in writing by the
Director.
APPROVAL NO.
308463-00-00
Page 3 of 47
………………….
TABLE 3.2:
AIR EMISSION SOURCE MONITORING AND REPORTING
AIR EFFLUENT
STREAM/ AIR
EMISSION
SOURCE
Produced gas
and residue or
fuel gas to the
flare stacks,
steam generators,
glycol heaters
and flash treaters
Produced gas at
the central
processing facility
Each of the flare
stacks, steam
generators, glycol
heaters and flash
treaters
Each of the seven
92.6 MW steam
generators per
phase
Any two of the
seven 92.6 MW
steam generators
per phase
Any of the five
92.6 MW steam
generators per
phase without a
CEM
MONITORING
REPORTING
PARAMETER
METHOD OF
MONITORING
FREQUENCY
MONTHLY
ANNUALLY
Volumetric flow
rates
Measured or
Estimated
Continuously
No
No
Hydrogen
sulphide
Total
hydrocarbons
Gas Analysis
Monthly
Yes
No
Calculated
Daily
Yes,
tonnes
per day
Yes,
tonnes per
year
Manual Stack
Survey
Once within
twelve months
of
commissioning
Yes
Yes
Manual Stack
Survey
Twice per
year
Yes
Yes
CEM, as per
CEMS Code
Continuously
Yes
Yes
Manual Stack
Survey
Once per year
on a rotating
basis
Yes
Yes
Lower heating
value
Sulphur dioxide
Oxides of
nitrogen
(expressed as
NO2)
Oxides of
nitrogen
(expressed as
NO2)
Oxides of
nitrogen
(expressed as
NO2), flow rate
and temperature
Oxides of
nitrogen
(expressed as
NO2)
APPROVAL NO.
308463-00-00
Page 4 of 47
………………….
AIR EFFLUENT
STREAM/ AIR
EMISSION
SOURCE
MONITORING
REPORTING
PARAMETER
METHOD OF
MONITORING
FREQUENCY
MONTHLY
ANNUALLY
Each of the six
9.15 MW glycol
heaters
Oxides of
nitrogen
(expressed as
NO2)
Manual Stack
Survey
Once within
twelve months
of
commissioning
Yes
Yes
Each of the three
4.1 MW flash
treaters
Oxides of
nitrogen
(expressed as
NO2)
Manual Stack
Survey
Once within
twelve months
of
commissioning
Yes
Yes
3.8
The approval holder shall notify the Director in writing a minimum of two weeks prior to
any manual stack survey that is required to be conducted by this approval.
3.9
The approval holder shall submit the monthly CEMS Code data required in condition 3.6
electronically to the Alberta Environment File Transfer Protocol (FTP) site, which is used
for the electronic submission of continuous emissions monitoring information.
3.10
The approval holder shall monitor ambient air parameters as specified in TABLE 3.3,
3.11
The approval holder shall report to the Director the results of the ambient air monitoring
as required in TABLE 3.3, unless otherwise authorized in writing by the Director.
APPROVAL NO.
308463-00-00
Page 5 of 47
………………….
TABLE 3.3:
AMBIENT AIR MONITORING AND REPORTING
MONITORING
STATION
One continuous
ambient air
monitoring
station, as per Air
Monitoring
Directive
Eight passive
exposure
monitoring
station(s), as per
Air Monitoring
Directive
PARAMETER
MONITORING
PERIOD
REPORTING
MONTHLY
ANNUALLY
Sulphur dioxide
concentrations,
hydrogen
sulphide
concentrations,
nitrogen dioxide
concentrations,
wind speed and
wind direction
Six months prior to
commencing
operations, and for
12 months per
year, thereafter
Yes
Yes
Total
hydrocarbons
concentration
Six months prior to
commencing
operations, and
continuously,
during the first
year of operation
Yes
Yes
Nitrogen dioxide
concentrations,
sulphur dioxide
concentrations,
and hydrogen
sulphide
concentrations
Monthly
Yes
Yes
APPROVAL NO.
308463-00-00
Page 6 of 47
………………….
3.12
In addition to the annual reporting requirement in TABLE 3.2 and TABLE 3.3, the annual
Air Emission Report shall include, at a minimum, all of the following information:
(a)
information related to the plant operation;
(b)
the performance of air pollution control equipment;
(c)
any trends in the emissions data;
(d)
information on any upgrades or modifications to the air pollution control and
monitoring equipment;
(e)
a summary of contraventions reported pursuant to condition 1 of Schedule II;
(f)
any other information as required in writing by the Director.
WATER
4.1
The approval holder shall not release any substances from the plant to the surrounding
watershed except as authorized by this approval.
PARTICIPATION IN REGIONAL INITIATIVES
5.1
The approval holder shall participate in the following regional monitoring programs and
initiatives:
(a)
Cumulative Environmental Management Association (CEMA);
(b)
Wood Buffalo Environmental Association (WBEA);
(c)
Alberta Biodiversity Monitoring Institute (ABMI); and
(d)
Ecological Monitoring Committee for the Lower Athabasca (EMCLA).
DATED
November 6 , 2014
APPROVALS MANAGER
APPROVAL NO.
308463-00-00
Page 7 of 47
………………….
SCHEDULE I
DEFINITIONS
1.
In all parts of this approval:
(a)
“Act” means the Environmental Protection and Enhancement Act, R.S.A. 2000,
c.E-12, as amended;
(b)
“affected lands” means land which have received substances released from the
plant;
(c)
“air effluent stream” means any substance in a gaseous medium released by or
from a plant;
(d)
“annulus gas” means gas from the annulus of the oil and gas well casing;
(e)
“application” means the written submissions from the approval holder to the
Director in respect of application number 001-308463 and any subsequent
applications where amendments are issued for this approval;
(f)
“CEMS Code” means the Continuous Emission Monitoring System (CEMS)
Code, Alberta Environmental Protection, Pub.No.Ref: 107, 1998, as amended;
(g)
“central processing facility” means those buildings, structures, pollution
abatement equipment, process and storage facilities and land used in and for the
processing of bitumen or heavy oil, located on parts of Sections 26, 27, 34 and
35, Township 74, Range 6, West of the 4th Meridian;
(h)
“chemical” means any substance that is added or used as part of the treatment
process;
(i)
“commencing construction” means the act of removing vegetation and salvaging
topsoil and/or subsoil;
(j)
“commencing operation” means to start up the plant, process unit or equipment
for the first time with the introduction of feed material, electrical or thermal energy
and the simultaneous production of products for which the plant, process unit or
equipment was designed excluding predetermined period of commissioning or
testing;
(k)
“continuous monitoring” means sampling or flow measurement through
equipment that creates an uninterrupted output of the analysis or flow
measurement;
(l)
“day”, when referring to sampling, means any sampling period of 24 consecutive
hours;
APPROVAL NO.
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SCHEDULE I
DEFINITIONS
(m)
“decommissioning” means the dismantling and decontamination of a plant
undertaken subsequent to the termination or abandonment of any activity or any
part of any activity regulated under the Act;
(n)
“decontamination” means the treatment or removal of substances from the plant
and affected lands;
(o)
“deep organic soil” means soil with surface organic horizons, as defined in The
Canadian System of Soil Classification (Third Edition), Agriculture and Agri-Food
Canada, Publication 1646, 1998, as amended, that are greater than 40 cm in
depth;
(p)
“Director” means an authorized employee of the Alberta Energy Regulator;
(q)
“dismantling” means the removal of buildings, structures, process and pollution
abatement equipment, vessels, storage facilities, material handling facilities,
railways, roadways, pipelines and any other installations that are being or have
been used or held for or in connection with the plant;
(r)
“disturbed land” means any land disturbed by the approval holder in any manner
in association with the activity which is subject of this approval;
(s)
“domestic wastewater” means wastewater that is the composite of liquid and
water-carried wastes associated with the use of water for drinking, cooking,
cleaning, washing, hygiene, sanitation or other domestic purposes, together with
any infiltration and inflow wastewater, that is released into a wastewater
collection system;
(t)
“domestic wastewater system” means the parts of the plant that collect, store or
treat domestic wastewater;
(u)
“estimate” means a technical evaluation based on the sources contributing to the
release, including, but not limited to, pump capabilities, water meters, and batch
release volumes;
(v)
“fugitive emissions” means emissions of substances to the atmosphere other
than ozone depleting substances, originating from a plant source other than a
flue, vent, or stack but does not include sources which may occur due to breaks
or ruptures in process equipment;
(w)
“grab” when referring to a sample, means an individual sample collected in less
than 30 minutes and which is representative of the substance sampled;
(x)
“grade” means the rise or fall of land surface over a specified distance, measured
in the same units;
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SCHEDULE I
DEFINITIONS
(y)
“industrial runoff” means precipitation that falls on or traverses the plant
developed area;
(z)
“industrial runoff control system” means the parts of the plant that collect, store or
treat industrial runoff from the plant;
(aa)
“industrial wastewater” means the composite of liquid wastes and water-carried
wastes, any portion of which results from any industrial process carried on at the
plant;
(bb)
“industrial wastewater control system” means the parts of the plant that collect,
store or treat industrial wastewater;
(cc)
“ISO/IEC 17025” means the international standard, developed and published by
International Organization for Standardization (ISO), specifying management and
technical requirements for laboratories;
(dd)
“land reclamation” means the stabilization, contouring, maintenance,
conditioning, reconstruction, and revegetation of the surface of the land to a state
that permanently returns the plant to a land capability equivalent to its
predisturbed state;
(ee)
“manual stack survey” means a survey conducted in accordance with the Alberta
Stack Sampling Code, Alberta Environment, 1995, as amended;
(ff)
“mineral soil” means a soil consisting of soil horizons that contain 17% or less
organic C by weight as defined in The Canadian System of Soil Classification
(Third Edition), Agriculture and Agri-Food Canada, Publication 1646, 1998, as
amended;
(gg)
“monitoring system” means all equipment used for sampling, conditioning,
analyzing or recording data in respect of any parameter listed or referred to in
this approval including equipment used for continuous monitoring;
(hh)
“month” means calendar month;
(ii)
“net or lower heating value” means the quantity of heat evolved on complete
combustion where the combustion products remain as vapour at 15qC;
(jj)
“pad materials” means all geotextile and fill materials used to construct plant
facilities;
(kk)
“plant” means all buildings, structures, process and pollution abatement
equipment, vessels, storage facilities, material handling facilities, roadways,
railways, pipelines, camps, well pads, borrow pits and other installations, and
includes the land, located on Townships 73, 74 and 75, Ranges 5, 6 and 7,
APPROVAL NO.
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SCHEDULE I
DEFINITIONS
West of the 4th Meridian, as described in the application, that is being or has
been used or held for or in connection with the Pike 1 enhanced recovery in-situ
oil sands or heavy oil processing plant and oil production site;
(ll)
“plant developed area” means the areas of the plant used for the storage,
treatment, processing, transport, or handling of raw material, intermediate
product, by-product, finished product, process chemicals, or waste material;
(mm) “produced gas” means all gas associated with the production and treatment of oil
or bitumen including, but not limited to, gas liberated at storage tanks, heaters,
treaters, produced water facilities;
(nn)
“QA/QC” means quality assurance and quality control;
(oo)
“reclaimed soil” means soils that have had one or more of their natural horizons
removed and replaced;
(pp)
“recontoured areas” means disturbed land that has been decommissioned,
contoured and decompacted;
(qq)
“regulations” means the regulations enacted pursuant to the Act, as amended;
(rr)
“representative grab” means a sample consisting of equal volume portions of
water collected from at least four sites between 0.20-0.30 metres below the water
surface within a pond;
(ss)
“self-sustaining” means the degree at which a reclaimed ecosystem can maintain
itself without requiring external support or human intervention;
(tt)
“shallow organic soil” means soil with surface organic horizons, as defined in The
Canadian System of Soil Classification (Third Edition), Agriculture and Agri-Food
Canada, Publication 1646, 1998, as amended, that are less than 40 cm in depth;
(uu)
“soil” means mineral or organic earthen materials that can, have, or are being
altered by weathering, biological processes or human activity;
(vv)
“species at risk” means any species:
(i)
identified by the Alberta Wildlife Act as ‘Endangered’, ‘Threatened’ or
‘Species of Special Concern’,
(ii)
listed in The General Status of Alberta Wild Species, 2005, as ‘At Risk’,
‘May Be At Risk’ or ‘Sensitive’,
(iii)
classified as 'at risk' by the Committee on the Status of Endangered
Wildlife in Canada (COSEWIC), or
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SCHEDULE I
DEFINITIONS
(iv)
(ww)
listed under Schedule 1 of the Canadian Species at Risk Act;
“subsoil” means the layer of soil directly below the topsoil layer and consists of:
(i)
B-horizons as defined in The Canadian System of Soil Classification
(Third Edition), Agriculture and Agri-Food Canada, Publication 1646,
1998, as amended, and rated as good, fair or poor as described in the
Soil Quality Criteria Relative to Disturbance and Reclamation, Alberta
Agriculture, 1987, as amended, or
(ii)
the replaced subsurface layer in a reclaimed soil, and rated as good, fair
or poor as described in the Soil Quality Criteria Relative to Disturbance
and Reclamation, Alberta Agriculture, 1987, as amended;
(xx)
“tank” means a stationary device, designed to contain an accumulation of a
substance, which is constructed primarily of non-earthen materials that provide
structural support including wood, concrete, steel, and plastic;
(yy)
“topsoil” means the uppermost layer of soil and consists of one or more of the
following:
(zz)
(i)
all organic horizons (L, F, H and O) as defined in The Canadian System
of Soil Classification (Third Edition), Agriculture and Agri-Food Canada,
Publication 1646, 1998, as amended,
(ii)
A-horizons as defined in The Canadian System of Soil Classification
(Third Edition), Agriculture and Agri-Food Canada, Publication 1646,
1998, as amended, and rated as good, fair or poor as described in the
Soil Quality Criteria Relative to Disturbance and Reclamation, Alberta
Agriculture, 1987, as amended, or
(iii)
the replaced surface layer in a reclaimed soil, and rated as good, fair or
poor as described in the Soil Quality Criteria Relative to Disturbance and
Reclamation, Alberta Agriculture, 1987, as amended;
“volume estimate” means a technical evaluation based on the sources
contributing to the release, including, but not limited to, pump capabilities, water
meters, and batch release volumes;
(aaa) “water body” means any location where water flows or is present, whether or not
the flow or the presence of water is continuous, intermittent or occurs only during
a flood and includes but, not limited to, wetlands and aquifers;
(bbb) “weeds” means vegetation defined as noxious or prohibited noxious by the Weed
Control Act, 2011, as amended;
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SCHEDULE I
DEFINITIONS
(ccc)
“week” means any consecutive 7-day period;
(ddd) “well pad” means those wells, pumps, buildings, structures, process and storage
facilities and land used in and for the production of bitumen or heavy oil;
(eee) “wetland” means land that is saturated long enough to promote formation of
water altered soils, growth of water tolerant vegetation and various kinds of
biological activity that are adapted to wet environments; and
(fff)
“year” means calendar year.
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SCHEDULE II
GENERAL CONDITIONS
1.
The approval holder shall immediately report to the Director by telephone any
contravention of the terms and conditions of this approval at 1-780-422-4505.
2.
The approval holder shall submit a written report to the Director within 7 days of the
reporting pursuant to condition 1 of Schedule II.
3.
The terms and conditions of this approval are severable. If any term or condition of this
approval or the application of any term or condition is held invalid, the application of such
term or condition to other circumstances and the remainder of this approval shall not be
affected thereby.
4.
The approval holder shall immediately notify the Director in writing if any of the following
events occur:
(a)
the approval holder is served with a petition into bankruptcy;
(b)
the approval holder files an assignment in bankruptcy or Notice of Intent to make
a proposal;
(c)
a receiver or receiver-manager is appointed;
(d)
an application for protection from creditors is filed for the benefit of the approval
holder under any creditor protection legislation; or
(e)
any of the assets which are the subject matter of this approval are seized for any
reason.
5.
If the approval holder monitors for any substances or parameters which are the subject
of operational limits as set out in this approval more frequently than is required and uses
procedures authorized in this approval, then the approval holder shall provide the results
of such monitoring as an addendum to the reports required by this approval.
6.
The approval holder shall submit all monthly reports required by this approval to be
compiled or submitted to the Director on or before the end of the month following the
month in which the information was collected, unless otherwise authorized in writing by
the Director or specified in this approval.
7.
The approval holder shall submit all annual reports required by this approval to be
compiled or submitted to the Director on or before March 31 of the year following the
year in which the information was collected, unless otherwise authorized in writing by the
Director or specified in this approval.
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SCHEDULE III
ANALYTICAL REQUIREMENTS
1.
(a)
record; and
(b)
retain
all the following information in respect of any sampling conducted or analyses performed
in accordance with this approval for a minimum of ten years, unless otherwise
authorized in writing by the Director:
2.
(i)
the place, date and time of sampling,
(ii)
the dates the analyses were performed,
(iii)
the analytical techniques, methods or procedures used in the analyses,
(iv)
the names of the persons who collected and analyzed each sample, and
(v)
the results of the analyses.
With respect to any sample required to be taken pursuant to this approval, the approval
holder shall ensure that:
(a)
collection;
(b)
preservation;
(c)
storage;
(d)
handling; and
(e)
analysis
shall be conducted in accordance with the following, unless otherwise authorized in
writing by the Director:
(i)
for air:
(A)
the Alberta Stack Sampling Code, Alberta Environment, 1995, as
amended,
(B)
the Methods Manual for Chemical Analysis of Atmospheric
Pollutants, Alberta Environment, 1993, as amended,
(C)
the Air Monitoring Directive, Alberta Environment, 1989, as
amended, and
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SCHEDULE III
(D)
(ii)
for industrial wastewater, industrial runoff, groundwater and domestic
wastewater parameters:
(A)
(iii)
(iv)
3.
the CEMS Code;
the Standard Methods for the Examination of Water and
Wastewater, published jointly by the American Public Health
Association, American Water Works Association, and the Water
Environment Federation, 2010, as amended;
for soil:
(A)
the Soil Monitoring Directive, Alberta Environment, 2009, as
amended, and
(B)
the Soil Quality Criteria Relative to Disturbance and Reclamation,
Alberta Agriculture, 1987, as amended;
(C)
the Directive for Monitoring the Impact of Sulphur Dust on Soils,
Alberta Environment and Water, December 2011, as amended;
for waste:
(A)
the Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, USEPA, SW-846, September 1986, as amended,
(B)
the Methods Manual for Chemical Analysis of Water and Wastes,
Alberta Environmental Centre, Alberta, 1996, AECV96-M1, as
amended,
(C)
the Toxicity Characteristic Leaching Procedure (TCLP), USEPA
Regulation 40 CFR261, Appendix II, Method No. 1311, as
amended, or
(D)
the Standard Methods for the Examination of Water and
Wastewater, published jointly by the American Public Health
Association, American Water Works Association, and the Water
Environment Federation, 2010, as amended.
In addition to other requirements in this approval the approval holder shall:
(a)
monitor; and
(b)
report
the information required by:
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SCHEDULE III
4.
(i)
condition 3.6;
(ii)
condition 3.7;
(iii)
condition 0; and
(iv)
condition 0.
The information required in 3, shall at a minimum, comply with:
(a)
the Alberta Stack Sampling Code, Alberta Environment, 1995, as amended;
(b)
the Continuous Emissions Monitoring Systems (CEMS) Code, Alberta
Environmental Protection Environmental Service, 1998, as amended;
(c)
the Air Monitoring Directive – AMD 1989, Environment Protection Services,
Standards and Approvals Division, June 26, 1989, as amended; and
(d)
the Electronic Reporting of Continuous Emissions Monitoring (CEMS)
Information User Manual, Alberta Environment, 2003, as amended.
5.
The approval holder shall analyse all samples that are required to be obtained by this
approval in a laboratory accredited pursuant to ISO/IEC 17025, as amended, for the
specific parameter(s) to be analyzed, unless otherwise authorized in writing by the
Director.
6.
The term sample as used in condition 5 of Schedule III does not include samples
directed to continuous monitoring equipment, unless specifically required in writing by
the Director.
7.
The approval holder shall comply with the terms and conditions of any written
authorization issued by the Director under condition 5 of Schedule III.
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SCHEDULE IV
AIR EMISSIONS
1.
2.
The approval holder shall only release air effluent streams to the atmosphere from the
following air emission sources:
(a)
the twenty-one 92.6 MW steam generator exhaust stacks;
(b)
the six 9.15 glycol heater exhaust stacks;
(c)
the six 4.1 MW flash treater exhaust stacks;
(d)
the six 1.5 MW diesel-fired emergency generator exhaust stacks;
(e)
the high pressure flare stack;
(f)
the low pressure flare stack;
(g)
the space ventilation exhaust stacks;
(h)
the space heater exhaust stacks;
(i)
the water softening tank vents; and
(j)
any other source authorized in writing by the Director.
The approval holder shall construct and maintain the following stacks according to the
height requirements specified in TABLE 1 of Schedule IV, unless otherwise authorized in
writing by the Director.
TABLE 1:
STACK HEIGHTS
STACK
MINIMUM HEIGHT
ABOVE GRADE
(meters)
The twenty-one 92.6 MW steam generators exhaust stacks
28.9
The six 9.15 MW glycol heater exhaust stacks
6.7
The six 4.1 MW flash treater exhaust stacks
6.0
The six 1.5 MW diesel-fired emergency generator exhaust
stacks
5.7
The high pressure flare stack
41.1
The low pressure flare stack
25.0
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SCHEDULE IV
AIR EMISSIONS
3.
The net or lower heating value of the combined gas stream released to the central
processing facility flare stacks shall be maintained, at a minimum, at 12 MJ/m3 when
adjusted for 101.325 kPa and 15°C by adding residue gas to the flare gas.
4.
Annulus gas and produced gas shall be collected and burned as fuel, incinerated or
flared.
5.
The approval holder shall ensure that all oil production tanks are connected to the
vapour recovery system.
6.
All aboveground storage tanks containing liquid hydrocarbons or organic compounds
shall conform to the Environmental Guidelines for Controlling Emissions of Volatile
Organic Compounds from Aboveground Storage Tanks, Canadian Council of Ministers
of the Environment, PN 1180, 1995, as amended.
7.
The approval holder shall use the gas sweetening process units, once installed, to
remove hydrogen sulphide from the gas stream or sour fuel gas stream.
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SCHEDULE V
INDUSTRIAL WASTEWATER AND INDUSTRIAL RUNOFF
1.
The approval holder shall manage:
(a)
industrial wastewater; and
(b)
industrial runoff;
as described in the application, unless otherwise authorized in writing by the Director.
2.
The approval holder shall direct industrial wastewater, produced water and boiler
blowdown as follows:
(a)
to the central processing facility water recycle treatment unit;
(b)
to the evaporator(s);
(c)
to the two boiler blowdown ponds;
(d)
to an Alberta Energy Regulator approved disposal well; or
(e)
to an Alberta Energy Regulator approved Waste Processing and Disposal
Facility;
3.
The approval holder shall direct all industrial runoff from the plant developed area to the
associated industrial runoff control system. At the central processing facility, this is
specifically the two industrial runoff ponds.
4.
The approval holder shall direct all industrial runoff from the well pads to the industrial
runoff control system at each well pad.
5.
The approval holder shall only release industrial runoff from the industrial runoff control
system at the central processing facility and at the well pads.
LIMITS
6.
Releases from the industrial runoff control system shall not exceed the limits for the
parameters specified in TABLE 1 of Schedule V.
TABLE 1: INDUSTRIAL RUNOFF CONTROL SYSTEMS LIMITS
PARAMETER
LIMITS
Discharge Volume
--
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SCHEDULE V
7.
pH
> 6.0 and < 9.5 pH units
Oil and Grease
No visible sheen
Chloride
< 500 mg/L
The approval holder shall not release any industrial runoff in a manner which will cause
flooding or erosion.
MONITORING AND REPORTING
8.
The approval holder shall monitor the industrial runoff control systems as specified in
TABLE 2 of Schedule V, unless otherwise authorized in writing by the Director.
9.
The approval holder shall report to the Director the results of the industrial runoff control
system monitoring as required in TABLE 2 of Schedule V, unless otherwise authorized in
TABLE 2:
INDUSTRIAL RUNOFF CONTROL SYSTEM MONITORING AND
REPORTING
MONITORING
REPORTING
PRIOR TO RELEASE
DURING RELEASE
PARAMETER
FREQUENCY
SAMPLE TYPE FREQUENCY
SAMPLE
SAMPLE
TYPE
LOCATION
Discharge
volume (in
cubic meters)
-
-
Once/day
Volume
estimate
A/B
pH
Once
Representative
grab
Once/day
Grab
A/B
Oil and
Grease
Once
Representative
grab
Once/day
Grab
A/B
Chloride (in
mg/L)
Once
Representative
grab
Once/day
Grab
A/B
ANNUALLY
Yes
A = Discharge point of industrial runoff control system (industrial runoff pond)
B = Discharge point of industrial runoff control system (well pads)
10.
In addition to the annual reporting in TABLE 2 of Schedule V, the annual Industrial
Wastewater and Industrial Runoff Report shall include, at a minimum, all of the following
information:
(a)
an assessment of the performance of:
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SCHEDULE V
(i)
the industrial wastewater control system,
(ii)
the industrial runoff control system, and
(iii)
pollution abatement equipment;
(b)
an overview of the operation of the plant;
(c)
a summary and evaluation of management and disposal of industrial wastewater
for the previous year;
(d)
a summary and evaluation of management and disposal of industrial runoff for
the previous year; and
(e)
a summary and evaluation of management and disposal of domestic wastewater
for the previous year, as per Schedule X.
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SCHEDULE VI
GROUNDWATER
1.
The approval holder shall submit a Groundwater Monitoring Program proposal to the
Director on or before January 31, 2015, unless otherwise authorized in writing by the
Director.
2.
The Groundwater Monitoring Program proposal shall include, at a minimum, all the
following:
(a)
a conceptual development of the regional and local groundwater monitoring
network;
(b)
a description of the regional hydrogeology;
(c)
a hydrogeologic description and interpretation of the plant;
(d)
a map of groundwater flow patterns;
(e)
a map and description of surface water drainage patterns for the plant;
(f)
a lithologic description and maps, including cross-sections, of the surficial and
the upper bedrock geologic materials at the plant;
(g)
a site map showing the location and type of current and historical potential
sources of groundwater contamination;
(h)
a cross-section(s) showing depth to water table, patterns of groundwater
movement and hydraulic gradients at the plant;
(i)
the hydraulic conductivity of all surficial and bedrock materials at the plant;
(j)
a map showing the location of existing and additional proposed groundwater
monitor wells at the plant;
(k)
lithologs of all boreholes drilled at the plant;
(l)
construction and completion details of existing groundwater monitor wells;
(m)
a rationale for proposed groundwater monitor well locations and proposed
completion depths of those wells;
(n)
a description of groundwater monitoring well development protocols;
(o)
a list of parameters to be monitored and the monitoring frequency for each
groundwater monitor well or group of groundwater monitor wells at the plant;
(p)
details of a plan to gather information on existing groundwater quality at the plant
prior to commencing operations;
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SCHEDULE VI
GROUNDWATER
(q)
a description of the groundwater sampling and analytical QA/QC procedures;
(r)
details of a groundwater response plan specifying actions to be taken should
contaminants be identified through the Groundwater Monitoring Program or in the
event of a well casing failure;
(s)
a proposal to:
(i)
monitor and report any anomalous increases in water level at monitoring
wells as soon as they are discovered,
(ii)
address the potential that the approval holder’s operations may have on
liberating or introducing arsenic, petroleum hydrocarbons or other
constituents into groundwater, and
(iii)
monitor groundwater levels and groundwater quality for the protection of
the Empress Channel, the Muriel Lake Aquifer, the Bonnyville Aquifer, the
Ethel Lake Aquifer, the Terrace Sand Aquifer and the Sand River Aquifer;
(t)
any other information relevant to groundwater quality at the plant; and
(u)
3.
If the Groundwater Monitoring Program proposal is found deficient by the Director, the
approval holder shall correct all deficiencies identified in writing by the Director, by the
date specified in writing by the Director.
4.
The approval holder shall implement the Groundwater Monitoring Program as authorized
in writing by the Director.
5.
The approval holder shall collect the samples extracted from the groundwater monitor
wells using scientifically acceptable purging, sampling and preservation procedures so
that a representative groundwater sample is obtained.
6.
(a)
protect from damage; and
(b)
keep locked except when being sampled
all groundwater monitor wells, unless otherwise authorized in writing by the Director.
7.
The approval holder shall conduct at least five groundwater sampling events to establish
baseline conditions for:
(a)
new facilities;
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SCHEDULE VI
GROUNDWATER
(b)
expansion areas which were not covered in prior sampling events; and
(c)
previously non-assessed relevant, non-saline hydrostratigraphic units at existing
facilities;
8.
The approval holder shall conduct the sampling events referred to in condition 7 of
Schedule VI at intervals of no less than one month and must demonstrate stable
groundwater conditions.
9.
If a representative groundwater sample cannot be collected because the groundwater
monitor well is damaged or is no longer capable of producing a representative
groundwater sample, the approval holder shall:
(a)
clean, repair or replace the groundwater monitoring well; and
(b)
collect and analyse a representative groundwater sample prior to the next
scheduled sampling event;
10.
11.
In addition to the sampling information recorded in condition 2 of Schedule III, the
approval holder shall record the following sampling information for all groundwater
samples collected:
(a)
a description of purging and sampling procedures;
(b)
the static elevations, above sea level and depth below ground surface, of fluid
phases in the groundwater monitoring well prior to purging;
(c)
the temperature of each sample at the time of sampling;
(d)
the pH of each sample at the time of sampling; and
(e)
the specific conductance of each sample at the time of sampling.
The approval holder shall carry out remediation of the groundwater in accordance with
the following:
(a)
Alberta Tier 1 Soil and Groundwater Remediation Guidelines, Alberta
Environment, May 2014, as amended; and
(b)
Alberta Tier 2 Soil and Groundwater Remediation Guidelines, Alberta
Environment, May 2014, as amended.
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SCHEDULE VI
GROUNDWATER
12.
The approval holder shall submit an annual Groundwater Monitoring Report to the
Director by March 31 of each year.
13.
The Groundwater Monitoring Report shall include, at a minimum, all of the following:
(a)
a completed Record of Site Condition Form, Alberta Environment, 2009, as
amended;
(b)
a legal description of the plant and a map illustrating the plant boundaries;
(c)
a topographic map of the plant;
(d)
a description of the industrial activity and processes;
(e)
a map showing the location of all surface and groundwater users, and, a listing
describing surface water and water well use details, within at least a five
kilometre radius of the plant;
(f)
a general hydrogeological characterization of the region within a three kilometre
radius of the plant;
(g)
a detailed hydrogeological characterization of the , including an interpretation of
groundwater flow patterns;
(h)
a cross-section(s) showing depth to water table, patterns of groundwater
movement and hydraulic gradients at the plant;
(i)
borehole logs and completion details for groundwater monitoring wells;
(j)
a map showing locations of all known buried channels within at least five
kilometres of the plant;
(k)
a map of surface drainage within the plant and surrounding area including nearby
waterbodies;
(l)
a map of groundwater monitoring well locations and a table summarizing the
existing groundwater monitoring program for the plant;
(m)
a summary of any changes to the Groundwater Monitoring Program made since
the last groundwater monitoring report;
(n)
analytical data recorded as required in conditions 4 and 9(b) of Schedule VI;
(o)
a summary of fluid elevations recorded as required in condition 10(b) of Schedule
VI and an interpretation of changes in fluid elevations;
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SCHEDULE VI
GROUNDWATER
(p)
an interpretation of QA/QC program results;
(q)
an interpretation of all the data in this report, including the following:
(r)
(s)
14.
(i)
diagrams indicating the location and extent of any contamination,
(ii)
a description of probable sources of contamination, and
(iii)
a site map showing the location and type of current and historical
potential sources of groundwater contamination;
a summary and interpretation of the data collected since the Groundwater
Monitoring Program began including:
(i)
control charts which indicate trends in concentrations of parameters, and
(ii)
the migration of contaminants;
a description of the following:
(i)
contaminated groundwater remediation techniques employed,
(ii)
source elimination measures employed,
(iii)
risk assessment studies undertaken, and
(iv)
risk management studies undertaken;
(t)
a proposed sampling schedule for the following year(s);
(u)
a description of any contaminant remediation, risk assessment or risk
management action conducted at the plant;
(v)
recommendations for changes to the Groundwater Monitoring Program to make it
more effective; and
(w)
If the Groundwater Monitoring Report is found deficient by the Director, the approval
holder shall correct all deficiencies identified in writing by the Director, by the date
specified in writing by the Director.
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SCHEDULE VII
SOIL
1.
In addition to any other requirements specified in this approval, the approval holder shall
conduct all of the following activities related to soil monitoring and soil management
required by this approval in accordance with the Soil Monitoring Directive, Alberta
Environment, 2009, as amended:
(a)
designing and developing proposals for the Soil Monitoring Program;
(b)
designing and developing proposals for the Soil Management Program;
(c)
all other actions, including sampling, analysing, and reporting, associated with
the Soil Monitoring Program; and
(d)
all other actions, including sampling, analysing and reporting, associated with the
Soil Management Program.
MONITORING AND REPORTING
2.
The approval holder shall submit a Soil Monitoring Program proposal to the Director
according to the following schedule:
(a)
for the first soil monitoring event, on or before, November 30, 2017; and
(b)
for the second soil monitoring event, on or before November 30, 2022;
3.
If any Soil Monitoring Program proposal is found deficient by the Director, the approval
4.
The approval holder shall implement the Soil Monitoring Program as authorized in
5.
If an authorization or a deficiency letter is not issued within 120 days of the applicable
date required by condition 2 of Schedule VII, the approval holder shall implement the
Soil Monitoring Program:
6.
(a)
in accordance with the program as set out in the proposal submitted by the
approval holder; and
(b)
within 270 days after the applicable date required by condition 2 of Schedule VII.
The approval holder shall submit each Soil Monitoring Program Report obtained from the
soil monitoring referred to in conditions 4 and 5 of Schedule VII to the Director according
to the following schedule:
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SOIL
(a)
for the first Soil Monitoring Program Report, on or before November 30, 2018;
and
(b)
for the second Soil Monitoring Program Report, on or before November 30, 2023;
7.
If any Soil Monitoring Program Report is found deficient by the Director, the approval
SOIL MANAGEMENT PROGRAM
8.
If the Soil Monitoring Program, or any other soil monitoring, reveals that there are
substances present in the soil at concentrations greater than any of the applicable
concentrations set out in the standards in the Soil Monitoring Directive, Alberta
Environment, 2009, as amended, the approval holder shall develop a Soil Management
Program proposal.
9.
If a Soil Management Program proposal is required pursuant to condition 8 of
Schedule VII, the approval holder shall submit a Soil Management Program proposal to
the Director according to the following schedule:
(a)
for Soil Management Program proposal that is triggered by the findings from the
first soil monitoring event, on or before the date in condition 6(a) of Schedule VII;
(b)
for Soil Management Program proposal that is triggered by the findings from a
second soil monitoring event, on or before the date in condition 6(b) of Schedule
VII; or
(c)
for any other soil monitoring event not specified in this approval, within six
months of completion of the soil monitoring event.
10.
If any Soil Management Program proposal is found deficient by the Director, the
approval holder shall correct all deficiencies identified in writing by the Director, by the
11.
The approval holder shall implement the Soil Management Program as authorized in
12.
If the approval holder is required to implement a Soil Management Program pursuant to
condition 11 of Schedule VII, the approval holder shall submit an annual Soil
Management Program Report to the Director, unless otherwise authorized in writing by
the Director.
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SCHEDULE VII
SOIL
13.
If any Soil Management Program Report is found deficient by the Director, the approval
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SCHEDULE VIII
WILDLIFE
1.
In addition to any other requirements specified in this approval, the approval holder shall
conduct wildlife mitigation in accordance with the Integrated Standards and Guidelines
Enhanced Approval Process (EAP), Alberta Environment and Sustainable Resource
Development, March 28, 2013, as amended, unless otherwise authorized in writing by
the Director.
2.
The approval holder shall take all steps necessary, as described in the application, to
prevent wildlife from coming into contact with the industrial wastewater control system,
3.
The approval holder shall develop a Wildlife Mitigation Program when one or more of the
following occurs:
(a)
the approval holder is unable to conduct mitigation in accordance with condition 1
of Schedule VIII or any part thereof;
(b)
the project includes above-ground pipelines;
(c)
species at risk occur or have a high potential to occur within the plant, which are
not in accordance with condition 1 of Schedule VIII; or
(d)
any other project effects on wildlife identified in the application, that require
mitigation beyond what is described by the documents listed in condition 1 of
Schedule VIII;
4.
If a Wildlife Mitigation Program is required pursuant to condition 3 of Schedule VIII, the
approval holder shall submit a Wildlife Mitigation Program proposal to the Director on or
before March 31, 2015, unless otherwise authorized in writing by the Director.
5.
The Wildlife Mitigation Program proposal referred to in condition 4 of Schedule VIII shall
address, at a minimum, all of the following for the discrepancies identified in condition 3
of Schedule VIII:
(a)
a description of the alternative mitigation strategies that will be implemented to
meet the Desired Outcomes as stated in the Integrated Standards and
Guidelines Enhanced Approval Process (EAP), Alberta Environment and
Sustainable Resource Development, March 28, 2013, as amended;
(b)
a description of the mitigation strategies planned to facilitate wildlife movement
and habitat use including, at a minimum, all of the following:
(i)
a description of project above-ground pipelines including:
(A)
a map of the above-ground pipelines,
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WILDLIFE
(ii)
(B)
clearance under the pipe,
(C)
width of rack and right-of-way corridor, and
(D)
length of above-ground pipelines,
mitigation strategies that consider physical and behavioural
characteristics of wildlife and address:
(A)
line of sight issues,
(B)
adequacy of vegetation cover (i.e. type and extent), and
(C)
relationship of infrastructure to natural movement corridors (i.e.
riparian areas), and temporal and spatial migration patterns of
wildlife;
(c)
detailed descriptions of mitigation measures to minimize project effects on
species at risk throughout the life of the project;
(d)
description of the mitigation strategies that will be implemented to address any
project-level effects and site-specific issues;
(e)
detailed descriptions of mitigation measures to minimize project-induced impacts
to fisheries and aquatic habitat at a defined sub-tertiary watershed scale; and
(f)
6.
If the Wildlife Mitigation Program proposal is found deficient by the Director, the approval
holder shall correct all deficiencies identified in writing by the Director by the date
7.
The approval holder shall implement the Wildlife Mitigation Program as authorized in
8.
The approval holder shall monitor the long-term cumulative effects on biodiversity and
wildlife in the region, in cooperation with other oil sands developers, and coordinated
with efforts undertaken with the Alberta Biodiversity Monitoring Institute, unless
9.
In cooperation with the Provincial Woodland Caribou Management Coordinator and the
regional Alberta Fish and Wildlife Program Manager, the approval holder shall submit a
Woodland Caribou Mitigation Plan and Monitoring Program proposal to the Director on
or before March 31, 2015, unless otherwise authorized in writing by the Director.
10.
The Woodland Caribou Mitigation Plan and Monitoring Program proposal shall include,
at a minimum, all of the following:
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WILDLIFE
(a)
an outline of the actions which will be implemented to mitigate the effects of the
project on Woodland Caribou;
(b)
a description of how the approval holder will contribute to the monitoring of
woodland caribou, consistent with provincially recognized priorities;
(c)
a description of the approval holder's alignment with the Woodland Caribou
Policy for Alberta, Alberta Sustainable Resource Development, 2011, as
amended, including the following government-led initiatives:
(d)
(i)
maintaining and restoring caribou habitat,
(ii)
management efforts that will recognize habitat changes naturally in type
and location over time,
(iii)
prudent management of the land base and associated development, and
(iv)
effectively managing wildlife populations; and
11.
If the Woodland Caribou Mitigation Plan and Monitoring Program proposal is found
deficient by the Director, the approval holder shall correct all deficiencies identified in
writing by the Director by the date specified in writing by the Director.
12.
The approval holder shall implement the Woodland Caribou Mitigation Plan and
Monitoring Program as authorized in writing by the Director.
13.
The approval holder shall submit a Wildlife Monitoring Program proposal to the Director
on or before March 31, 2015, unless otherwise authorized in writing by the Director.
14.
The Wildlife Monitoring Program proposal shall, for monitoring not addressed by
conditions 8 or 12 of Schedule VIII, describe the methods that will be applied:
(a)
(b)
to assess the effectiveness of the mitigation in relation to:
(i)
the Sensitive Species Inventory Guidelines, 2010, as amended, for
relevant species,
(ii)
the effects of linear disturbances, including above-ground pipe,
(iii)
the occurrence of species at risk, and
(iv)
industrial wastewater control systems;
site specific project effects predicted in the application;
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SCHEDULE VIII
WILDLIFE
(c)
to monitor fisheries and aquatic habitat at a defined sub-tertiary watershed scale;
and
(d)
15.
If the Wildlife Monitoring Program proposal is found deficient by the Director, the
approval holder shall correct all deficiencies identified in writing by the Director by the
16.
The approval holder shall implement the Wildlife Monitoring Program as authorized in
17.
The approval holder shall submit a Comprehensive Wildlife Report to the Director
according to the following schedule:
(a)
for the first Comprehensive Wildlife Report, on or before May 15, 2016;
(b)
for the second Comprehensive Wildlife Report, on or before May 15, 2019; and
(c)
for the third Comprehensive Wildlife Report, on or before May 15, 2022;
18.
19.
The Comprehensive Wildlife Report shall include, at a minimum, all of the following:
(a)
the methods and results of the monitoring, conducted pursuant to conditions 12
and 16 of Schedule VIII;
(b)
mitigation implemented pursuant to conditions 7 and 12 of Schedule VIII;
(c)
effectiveness of the mitigation implemented pursuant to conditions 7 and 12 of
Schedule VIII;
(d)
authorized adaptive management measures taken or planned;
(e)
changes proposed to the monitoring programs;
(f)
changes proposed to the mitigation programs; and
(g)
If the Comprehensive Wildlife Report is found deficient by the Director, the approval
holder shall correct all deficiencies identified in writing by the Director by the date
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SCHEDULE IX
CONSTRUCTION, DECOMMISSIONING AND RECLAMATION
CONSTRUCTION
1.
The approval holder shall ensure that woody debris removal allows for all topsoil to be:
(a)
conserved; and
(b)
stockpiled
in accordance with this approval, unless otherwise authorized in writing by the Director.
2.
The approval holder shall salvage topsoil for land reclamation as follows:
(a)
(b)
(c)
salvage all topsoil from:
(i)
mineral soils,
(ii)
shallow organic soils, or
(iii)
reclaimed soils;
from areas of deep organic soil where pad materials will be left in place during
land reclamation:
(i)
salvage topsoil to a minimum depth of 40 cm, or
(ii)
submit to the Director, for written authorization, an alternate plan for
obtaining topsoil prior to commencing construction; or
no topsoil salvage from areas of deep organic soil where pad materials will be
removed during land reclamation;
unless otherwise authorized in writing by the Director
3.
The approval holder shall salvage subsoil from any:
(a)
central processing facility; or
(b)
well pad
located on:
(i)
mineral soils,
(ii)
shallow organic soils, or
(iii)
reclaimed soils;
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SCHEDULE IX
4.
Subject to condition 3 of Schedule IX, the approval holder shall salvage all subsoil:
(a)
separately from topsoil; and
(b)
to a maximum thickness of 30 cm;
5.
(a)
conserve; and
(b)
stockpile
all salvaged topsoil and subsoil separately from:
6.
7.
(i)
each other, or
(ii)
other materials.
The topsoil stockpiles referred to in condition 5 of Schedule IX shall be:
(a)
on undisturbed topsoil or on a material that will not cause the mixing, loss or
degradation of the topsoil;
(b)
on stable foundations;
(c)
accessible and retrievable;
(d)
contoured to allow for vegetation and stabilization;
(e)
identified with a permanent signpost; and
(f)
controlled for weeds.
The subsoil stockpiles referred to in condition 5 of Schedule IX shall be:
(a)
on areas where the topsoil has been removed;
(b)
on stable foundations;
(c)
accessible and retrievable;
(d)
contoured to allow for vegetation and/or stabilization;
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SCHEDULE IX
8.
9.
(e)
identified with a permanent signpost; and
(f)
controlled for weeds.
The approval holder shall take all steps necessary to prevent wind or water erosion of all
stockpiles including, but not limited to, one or more of the following:
(a)
establishing a vegetative cover; or
(b)
use of silt fences, tackifiers, mulches, tarps or other erosion control products; or
(c)
any other steps authorized in writing by an Inspector.
The approval holder shall immediately suspend salvage of:
(a)
topsoil; or
(b)
subsoil
if directed to do so in writing by an Inspector, or when:
(i)
wet or frozen conditions,
(ii)
high wind velocities, or
(iii)
any other field condition or operation
will result in mixing, loss or degradation of the topsoil or subsoil.
10.
The approval holder shall recommence salvage of:
(a)
topsoil; or
(b)
subsoil
only when the field conditions in condition 9 of Schedule IX no longer exist or if directed
to do so in writing by an Inspector.
11.
The approval holder shall implement drainage control measures to minimize erosion and
sedimentation.
12.
The approval holder shall submit a Pre-Disturbance Assessment and Conservation &
Reclamation Plan to the Director:
(a)
prior to commencing construction; or
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SCHEDULE IX
(b)
as otherwise notified in writing by the Director.
13.
The approval holder shall prepare the Pre-Disturbance Assessment and Conservation &
Reclamation Plan in accordance with the Guidelines for Submission of a PreDisturbance Assessment and Conservation & Reclamation Plan Under an
Environmental Protection and Enhancement Act Approval For an Enhanced Recovery
In-Situ Oil Sands and Heavy Oil Processing Plant and Oil Production Site, Alberta
Environment, 2009, as amended, unless otherwise authorized in writing by the Director.
14.
In addition to the requirements specified in condition 13 of Schedule IX, the PreDisturbance Assessment and Conservation & Reclamation Plan shall include:
(a)
a revegetation plan that addresses, at a minimum, all the following:
(i)
information that takes into consideration the Guidelines for Reclamation
to Forest Vegetation in the Athabasca Oil Sands Region, 2nd Edition,
2009, as amended, if applicable,
(ii)
species list, seeding rates and methods, and
(iii)
information about surrounding vegetation;
(b)
a discussion about how the Conservation and Reclamation Plan relates to the
Project-Level Conservation, Reclamation and Closure Plan authorized under
condition 29 of Schedule IX; and
(c)
any other information as required in writing by the Director;
15.
The approval holder shall implement the Pre-Disturbance Assessment and Conservation
& Reclamation Plan as submitted, unless otherwise notified in writing by the Director.
16.
The approval holder shall only implement changes to a submitted Pre-Disturbance
Assessment and Conservation & Reclamation Plan upon submission of a revised PreDisturbance Assessment and Conservation & Reclamation Plan, unless otherwise
notified in writing by the Director.
DECOMMISSIONING
17.
The approval holder shall apply for an amendment to this approval by submitting a:
(a)
Decommissioning Plan; and
(b)
Land Reclamation Plan;
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SCHEDULE IX
to the Director.
18.
The approval holder shall submit the:
(a)
Decommissioning Plan; and
(b)
Land Reclamation Plan
referred to in condition 17 of Schedule IX within six months of:
(i)
the plant as a whole, or
(ii)
any central processing facility,
ceasing operation, except for repairs and maintenance, unless otherwise authorized in
DECOMMISSIONING PLAN
19.
The Decommissioning Plan referred to in condition 17 of Schedule IX shall include, at a
minimum, all of the following:
(a)
a plan for dismantling the plant;
(b)
a comprehensive study to determine the nature, degree and extent of
contamination at the plant and affected lands;
(c)
a plan to manage all wastes at the plant;
(d)
evaluation of remediation technologies proposed to be used at the plant and
affected lands;
(e)
a plan for decontamination of the plant and affected lands in accordance with the
following:
(i)
for soil or groundwater, Alberta Tier 1 Soil and Groundwater Remediation
Guidelines, Alberta Environment, 2010, as amended,
(ii)
for soil or groundwater, Alberta Tier 2 Soil and Groundwater Remediation
Guidelines, Alberta Environment, 2010, as amended,
(iii)
for drinking water, Canadian Environmental Quality Guidelines, CCME
PN1299, 1999, as amended, and
(iv)
for surface water, Surface Water Quality Guidelines for Use in Alberta,
Alberta Environment, 1999, as amended;
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SCHEDULE IX
(f)
confirmatory testing to indicate compliance with the remediation objectives;
(g)
a plan for maintaining and operating contaminant monitoring systems;
(h)
a schedule for activities (a) through (g) above; and
(i)
LAND RECLAMATION PLAN
20.
The Land Reclamation Plan referred to in condition 17 of Schedule IX shall include, at a
(a)
the final use of the reclaimed area and how equivalent land capability will be
achieved;
(b)
removal of infrastructure;
(c)
re-establishment of drainage and how it will be integrated with adjacent land;
(d)
a description of reclaimed topography and how the reclaimed landforms will
approximate the natural landforms adjacent to the plant;
(e)
a soil replacement plan;
(f)
erosion control;
(g)
a revegetation plan that includes, at a minimum, all of the following:
(i)
species list, seed source and quality, seeding rates and methods,
(ii)
information about areas where reforestation will occur,
(iii)
justification for areas where reforestation is not proposed,
(iv)
fertilization rates and methods,
(v)
a vegetation management plan, and
(vi)
wildlife habitat plans where applicable;
(h)
techniques and procedures for returning disturbed lands to equivalent wildlife
habitat capability;
(i)
reclamation sequence and schedule; and
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SCHEDULE IX
(j)
RECLAMATION
GENERAL
21.
The approval holder shall conduct land reclamation activities on all disturbed land in an
on-going and progressive manner.
22.
The approval holder shall reclaim disturbed land in a manner that results in a return of
land capability equivalent to what existed prior to disturbance.
23.
The approval holder shall remove all watercourse crossings as part of land reclamation,
24.
The approval holder shall reclaim all roads, including:
(a)
removal of culverts and other structures;
(b)
recontouring;
(c)
re-establishment of drainage;
(d)
decompaction of subsoil;
(e)
replacement of topsoil; and
(f)
revegetation;
25.
The approval holder shall progressively re-establish surface drainage during land
reclamation such that it is integrated with the adjacent land.
LANDSCAPE AND CLOSURE PLANNING
26.
The approval holder shall submit a Project-Level Conservation, Reclamation and
Closure Plan to the Director on or before June 30, 2016, unless otherwise authorized in
27.
The Project-Level Conservation, Reclamation and Closure Plan shall include, at a
(a)
identification of specific conservation and reclamation practices, plans and
objectives for specific geographical areas based on environmental and
landscape features;
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SCHEDULE IX
(b)
consideration of environmental constraints and associated commitments;
(c)
inclusion of all current and future disturbance areas;
(d)
integration of landforms, topography, vegetation, water bodies, and watercourses
with adjacent undisturbed areas and adjacent reclamation areas; and
(e)
28.
If the Project-Level Conservation, Reclamation and Closure Plan is found deficient by
the Director, the approval holder shall correct all deficiencies identified in writing by the
Director by the date specified in writing by the Director.
29.
The approval holder shall implement the Project-Level Conservation, Reclamation and
Closure Plan as authorized in writing by the Director.
CONTOURING AND MATERIALS PLACEMENT
30.
The approval holder shall contour disturbed land such that the reclaimed landforms
approximate the natural landforms in the areas adjacent to the plant.
31.
The approval holder shall ensure that reclaimed slopes are no steeper than 3:1, unless
32.
The approval holder shall cap any unsuitable material, as described in the Soil Quality
Criteria Relative to Disturbance and Reclamation, Alberta Agriculture, 1987, as
amended, where unsuitability is not related to contamination, with 1.0 metre of soil
material having a good, fair or poor rating, as described in the Soil Quality Criteria
Relative to Disturbance and Reclamation, Alberta Agriculture, 1987, as amended, prior
to subsoil and topsoil replacement.
33.
The approval holder shall replace all salvaged subsoil on recontoured areas:
(a)
where the subsoil was salvaged from; and
(b)
prior to topsoil replacement;
34.
The approval holder shall replace all topsoil that was salvaged or allocated under
condition 2(b) of Schedule IX on areas where pad materials will be left in place during
land reclamation, unless otherwise authorized in writing by the Director.
35.
Subject to condition 34 of Schedule IX, the approval holder shall replace all salvaged
topsoil on recontoured areas such that the average depth of the replaced topsoil in the
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reclaimed soil for each reclamation area is equivalent to or greater than 80% of the
original topsoil depth, unless otherwise authorized in writing by the Director.
36.
The approval holder shall immediately suspend replacement of:
(a)
topsoil; or
(b)
subsoil
if directed to do so in writing by an Inspector, or when:
(i)
wet or frozen conditions,
(ii)
high wind velocities, or
(iii)
any other field condition or operation
will result in mixing, loss or degradation of topsoil or subsoil.
37.
The approval holder shall recommence replacement of:
(a)
topsoil; or
(b)
subsoil
only when the field conditions in condition 36 of Schedule IX no longer exist or if directed
to do so in writing by an Inspector.
38.
The approval holder shall maintain a weed control program until new vegetation is
established and is self-sustaining.
RESEARCH
39.
The approval holder shall submit a project specific Wetland Reclamation Trial Program
proposal to the Director on or before December 31, 2019, unless otherwise authorized in
40.
The Wetland Reclamation Trial Program proposal shall include, at a minimum, all of the
following:
(a)
trial plans for the removal or partial removal of pad materials from well pads and
roads located in wetland ecosystems with emphasis on dominant wetland
ecosystems that have been disturbed;
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(b)
trial plans for reclamation of other types of disturbed land located in wetland
ecosystems with emphasis on dominant wetland ecosystems that have been
disturbed;
(c)
the reclamation of the areas specified in (a) and (b) to pre-disturbance wetland
ecosystems or a similar self-sustaining wetland ecosystem as appropriate;
(d)
the possible reuse of the bed and fill material removed from the areas specified
in (a) as construction or backfill material;
(e)
trial plans for reclamation of wet borrow pits to an open water body and/or a selfsustaining wetland ecosystem;
(f)
a monitoring program; and
(g)
41.
If the Wetland Reclamation Trial Program proposal is found deficient by the Director, the
42.
The approval holder shall implement the Wetland Reclamation Trial Program as
authorized in writing by the Director.
43.
(a)
participate in; and
(b)
contribute to
regional multi-stakeholder forum(s) that includes development of wetland reclamation
strategies, to the satisfaction of the Director.
MONITORING
44.
The approval holder shall submit a Reclamation Monitoring Program proposal to the
Director on or before December 31, 2018, unless otherwise authorized in writing by the
Director.
45.
The Reclamation Monitoring Program proposal shall include, at a minimum, all of the
following:
(a)
a monitoring plan to assess soils, vegetation and wildlife on reclaimed areas that
includes, but not limited to, all of the following:
(i)
proposed methodology, and
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(ii)
monitoring schedule;
(b)
performance measures to assess reclamation success;
(c)
how corrective measures will be identified and implemented;
(d)
how the data will be used in adaptive management for future reclaimed areas;
and
(e)
46.
If the Reclamation Monitoring Program proposal is found deficient by the Director, the
47.
The approval holder shall implement the Reclamation Monitoring Program as authorized
in writing by the Director.
REPORTING
48.
The approval holder shall submit an annual Conservation and Reclamation Report to the
Director.
49.
The approval holder shall prepare the annual Conservation and Reclamation Report in
accordance with the Guidelines for Submission of an Annual Conservation and
Reclamation Report Under an Environmental Protection and Enhancement Act Approval
for an Enhanced Recovery In-Situ or Heavy Oil Processing Plant and Oil Production
Site, Alberta Environment, 2011, as amended, unless otherwise authorized in writing by
the Director.
50.
In addition to the requirements specified in condition 49 of Schedule IX, the annual
Conservation and Reclamation Report shall include, at a minimum, all of the following:
(a)
(b)
a summary on the status of the following:
(i)
Project-Level Conservation, Reclamation and Closure Plan,
(ii)
Wetland Reclamation Trial Program,
(iii)
activities required under condition 43 of Schedule IX, and
(iv)
Reclamation Monitoring Program; and
APPROVAL NO.
308463-00-00
Page 45 of 47
………………….
SCHEDULE X
DOMESTIC WASTEWATER
1.
The approval holder shall not release any substances from the domestic wastewater
system to the surrounding watershed except as authorized by this approval.
2.
The approval holder shall direct all domestic wastewater at the plant to a septic tank with
subsequent disposal to a domestic wastewater treatment facility holding a current
approval under the Act.
3.
The approval holder shall only dispose of sludge produced by the domestic wastewater
system at a domestic wastewater treatment facility holding a current approval under the
Act.
APPROVAL NO.
308463-00-00
Page 46 of 47
………………….
SCHEDULE XI
WETLANDS AND WATER BODIES
1.
The approval holder shall submit a Wetland Monitoring Program proposal to the Director
on or before December 31, 2015, unless otherwise authorized in writing by the Director.
2.
The Wetland Monitoring Program proposal shall include, at a minimum, all of the
following:
(a)
a plan to monitor natural wetlands and water bodies for natural variability;
(b)
a plan to determine and monitor the potential effects on wetland ecosystems
from:
(c)
(i)
roads, well pads or other infrastructure constructed within wetland
ecosystems,
(ii)
surface water withdrawals,
(iii)
groundwater withdrawals, and
(iv)
any additional disturbances that may affect wetland ecosystems;
a plan to monitor the potential effects on water bodies within the project area
having the greatest potential to be impacted (i.e. representative water bodies)
from:
(i)
seepage, drainage and discharge from the project site,
(ii)
road, well pads or other infrastructure constructed within or adjacent to
water bodies,
(iii)
surface water withdrawals,
(iv)
groundwater withdrawals, and
(v)
any additional disturbances that may affect water bodies;
(d)
a plan to monitor water bodies upstream and downstream from potential impacts
for surface water quality and quantity and any other appropriate response
variables;
(e)
corrective measures and a schedule of implementation, where appropriate, to
protect affected wetlands and water bodies;
(f)
reporting schedule; and
(g)
APPROVAL NO.
308463-00-00
Page 47 of 47
………………….
SCHEDULE XI
WETLANDS AND WATER BODIES
3.
If the Wetland and Water Body Monitoring Program proposal is found deficient by the
Director, the approval holder shall correct all deficiencies identified in writing by the
Director by the date specified in writing by the Director.
4.
The approval holder shall implement the Wetland and Water Body Monitoring Program
as authorized in writing by the Director.
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Attachment B
Process Flow Schematics
Pike 1 Amendment 2015
Production Treating Schematic
January 9, 2015
FigureB2.5-1_ProdTreatingSchematic.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Figure
B2.5-1
Produced Gas
System Schematic
January 9, 2015
Figure
B2.5-2
FigureB2.5-_ProdGasSystemSchematic.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Produced Water Deoiling
System Schematic
January 9, 2015
Figure
B2.5-3
FigureB2.5-3_ProdWaterDeoilingSchematic.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Produced Water Treatment
System Schematic
January 9, 2015
Figure
B2.5-4
FigureB2.5-4_ProdWaterTreatmentSch.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Steam Generation Schematic
January 9, 2015
Figure
B2.5-5
FigureB2.5-5_SteamGenerationSch.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Oil Storage Tank Schematic
January 9, 2015
Figure
B2.5-6
FigureB2.5-6_OilStorageTankSch.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
VRU System Schematic
January 9, 2015
Figure
B2.5-7
FigureB2.5-7_VapourRecoverySch.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Fuel Gas Schematic
January 9, 2015
Figure
B2.5-8
FigureB2.5-8_FeulGasSchematic.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Produced Gas System
(Detailed PFD For SRU)
January 8, 2015
Figure
B2.5-9
Figure2.5-4_ProdGasSystem.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Fuel Gas System
(Detailed PFD For SRU)
January 8, 2015
Figure
B2.5-10
Figure2.5-5_FuelGasSystem.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Sulphur Removal Unit Compressor
Package (Detailed PFD For SRU)
January 8, 2015
Figure
B2.5-11
Figure2.5-6_SulpherRemovalUnit.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Flare System and Vapor Removal
System (Detailed PFD For SRU)
January 8, 2015
Figure
B2.5-12
Figure2.5-7_FlareVaporSystem.mxd
PROVIDED BY:
DEVON CANADA
FINAL MAPPING BY:
DEVON CANADA
Attachment C
Air Quality Modeling and Emissions Parameters
Attachment C1
Air Modeling Parameters
Pike 1 Project
March 2015
1.1
CALPUFF Model Options
The CALPUFF control file defines 17 input groups as identified in Table C1-1.
Table C1-1: Input Groups in the CALPUFF Control File
Input
Group
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Description
Input and output file names
General run control parameters
Technical options
Species list
Grid control parameters
Output options
Sub grid scale complex terrain inputs
Dry deposition parameters for gases
Dry deposition parameters for particles
Miscellaneous dry deposition for parameters
Wet deposition parameters
Chemistry parameters
Diffusion and computational parameters
Point source parameters
Area source parameters
Line source parameters
Volume source parameters
Discrete receptor information
Applicable to
the Project
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes
From NOx, NO2 concentrations were calculated using the ozone-limiting method described in
the ESRD modeling guidelines as well as the overly conservative Total Conversion Method.
CALPUFF input parameters were selected according to the AQMG. Tables C1-2 to C1-11
identify the key input parameters, default options, and values used for the current project.
Table C1-2: General Run Control Parameters (Input Group 1)
Parameter
METRUN
IBYR
IBMO
IBDY
IBHR
XBTZ
NSPEC
NSE
ITEST
MRESTART
NRESPD
METFM
AVET
PGTIME
IOUTU
IOVERS
Default
0
5
3
2
0
0
1
60
60
1
Project
0
2002
1
1
0
7.0
8
5
2
0
0
1
60
60
1
2
2
Description
All model periods in met file(s) will be run
Starting year
Starting month
Starting day
Starting hour
Base time zone (MST = 7.0)
Number of chemical species
Number of chemical species to be emitted
Program is executed after SETUP phase
Does not read or write a restart file
Restart file written only at last period
Meteorological data format 1= CALMET binary file (CALMET.MET)
Averaging time (minutes)
PG Averaging time (minutes)
Output units for binary concentration and flux file 1 =mass –g/m3 (conc) or
g/m2/s (dep)
Output Dataset format for binary concentration and flux files 2= Dataset
Version 2.2
Attachment C1 – Page 1
Pike 1 Project
March 2015
Table C1-3: Technical Options (Input Group 2)
Parameter
MGAUSS
MCTADJ
MCTSG
MSLUG
MTRANS
MTIP
MBDW
MSHEAR
MSPLIT
MCHEM
MAQCHEM
MMLWC
Default
1
3
0
0
1
1
1
0
0
1
0
1
Project
1
3
0
0
1
1
2
0
0
1
0
1
MWET
MDRY
MTILT
MDISP
1
1
0
3
1
1
0
2
MTURBVW
MDISP2
3
3
3
3
MTAULY
0
0
MTAUADV
0
0
MCTURB
1
1
MROUGH
MPARTL
MPARTLBA
MTINV
MPDF
MSGTIBL
MBCON
MSOURCE
MFOG
MREG
0
1
1
0
0
0
0
0
0
1
0
1
1
0
1
0
0
0
0
0
Description
Gaussian distribution used in near field
Terrain adjustment method (3 = Partial plume path adjustment)
Subgrid-scale complex terrain (0 = not modeled)
Near-field puffs not modeled as elongated
Transitional plume rise modeled
Stack tip downwash used
Method used to simulate building downwash (2 = PRIME method)
Vertical wind shear not modeled
Puff splitting is not allowed
Transformation rates computed internally using MESOPUFF II scheme
Aqueous phase transformation not modeled
Liquid Water Content using gridded cloud water data read from CALMET
water content output files
Wet removal modeled
Dry deposition modeled
Gravitational settling (plume tilt) not modeled
Dispersion coefficients from internally calculated sigma v, sigma w using
micrometeorological variables (u*, w*, L, etc.)
Use both σv and σw from PROFILE.DAT to compute σy and σz (n/a)
Back-up method used to compute dispersion when measured turbulence
data are missing (used only if MDISP = 1 or 5) This parameter is not used
because MDISP = 2 for the project.
Draxler default 617.284 (s) used for Lagrangian timescale for Sigma-y
(used only if MDISP=1,2 or MDISP2=1,2)
Method used for Advective-Decay timescale for Turbulence (used only if
MDISP=2 or MDISP2=2)
Standard CALPUFF subroutines used to compute turbulence sigma-v &
sigma-w using micrometeorological variables(Used only if MDISP = 2 or
MDISP2 = 2)
PG σy and σz not adjusted for roughness
partial plume penetration of elevated inversion for point sources
partial plume penetration of elevated inversion for buoyant area sources
Strength of temperature inversion computed from default gradients
PDF used for dispersion under convective conditions
Sub-grid TIBL module not used for shore line
Boundary conditions (concentration) not modeled
No Individual source contributions saved
Do not configure for FOG model output
Do not test options specified to see if they conform to regulatory values
Table C1-4: Species List-Chemistry Options (Subgroup 3a)
CSPEC
SO2
SO4-2
NOx
HNO3
NO3CO
PM2.5
Modeled
(0=no, 1=yes)
Emitted
(0=no, 1=yes)
1
1
1
1
1
1
1
1
0
1
0
0
1
1
Dry Deposition
(0=none,
1=computed-gas,
2=computed particle,
3=user-specified)
1
2
1
1
2
0
2
Output Group
Number
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table C1-5: Map Projection Grid Control Parameters (Input Group 4)
Parameter
Default
Project
PMAP
IUTMZN
UTMHEM
DATUM
NX
NY
NZ
DGRIDKM
ZFACE
UTM
N
WGS-84
-
XORIGKM
-
UTM
12
N
NAR-B
61
77
12
2.5
0,20,40,80,
120,280,520,880,
1320,1820,2380,
3000, 4000
440.0
YORIGKM
-
6070.0
IBCOMP
JBCOMP
IECOMP
JECOMP
LSAMP
IBSAMP
JBSAMP
IESAMP
JESAMP
MESHDN
T
1
1
1
61
77
F
2
2
60
76
1
-
Description
Map projection: Universal Transverse Mercator
UTM Zone (1 to 60)
Northern hemisphere UTM projection
NIMA Datum Region - Canada
Number of X grid cells in meteorological grid
Number of Y grid cells in meteorological grid
Number of vertical layers in meteorological grid
Grid spacing (km)
Cell face heights in meteorological grid (m)
Reference X coordinate for SW corner of grid cell (1,1) of meteorological
grid (km)
Reference Y coordinate for SW corner of grid cell (1,1) of meteorological
grid (km)
lower left corner of the computational grid
lower left corner of the computational grids
upper right corner of the computational grid
upper right corner of the computational grid
Sampling grid is not used
X index of lower left corner of the sampling grid
Y index of lower left corner of the sampling grid
X index of upper right corner of the sampling grid
Y index of upper right corner of the sampling grid
Nesting factor of the sampling grid
Table C1-6: Dry Deposition Parameters for Gases (Input Group 7)
Species
SO2
NOx
HNO3
Default
0.1509
1 000.0
8.0
0.0
0.04
0.1656
1.0
8.0
5.0
3.5
0.1628
1.0
18.0
0.0
0.00000008
Project
0. 1509
1 000.0
8.0
0.0
0.04
0.1656
1.0
8.
5.
3.5
0.1628
1.0
18.
0.
0.00000008
Description
Diffusivity (cm2/s)
Alpha star
Reactivity
Mesophyll resistance (s/cm)
Henry’s Law coefficient
Diffusivity (cm2/s)
Alpha star
Reactivity
Diffusivity (cm2/s)
Alpha star
Reactivity
Pike 1 Project
March 2015
Table C1-7: Size Parameters for Dry Deposition of Particles (Input Group 8)
Species
SO4 2
SO4 2
NO3 NO3 PM2.5
PM2.5
Default
0.48
2.0
0.48
2.0
0.48
1.5
Project
0.48
2.0
0.48
2.0
0.48
1.5
Description
Geometric mass mean diameter of SO4 2[µm]
Geometric standard deviation of SO4 2 [µm]
Geometric mass mean diameter of NO3 -[µm]
Geometric standard deviation of NO3 - [µm]
Geometric mass mean diameter of PM2.5 [µm]
Geometric standard deviation of PM2.5 [µm]
Table C1-8: Miscellaneous Dry Deposition Parameters (Input Group 9)
Parameters
RCUTR
RGR
REACTR
NINT
IVEG
Default
30
10
8
9
1
Project
30
10
8
9
1
Description
Reference cuticle resistance (s/cm)
Reference ground resistance (s/cm)
Reference pollutant reactivity
Number of particle size intervals for effective particle deposition velocity
Vegetation in non-irrigated areas is active and unstressed
Table C1-9: Wet Deposition Parameters
Species
SO2
SO4-2
NOx
HNO3
NO3PM2.5
Default
0.00003
0.0
0.0001
0.00003
0.0
0.0
0.00006
0.0
0.0001
0.00003
0.0001
0.00003
Project
0.00003
0.0
0.0001
0.00003
0.0
0.0
0.00006
0.0
0.0001
0.00003
0.0001
0.00003
Description
Scavenging coefficient for liquid precipitation [s-1]
Scavenging coefficient for frozen precipitation [s-1]
Table C1-10: Chemistry Parameters (Input Group 11)
Parameters
MOZ
BCKO3
MNH3
MAVGNH3
BCKNH3
RNITE1
RNITE2
RNITE3
MH2O2
BCKH2O2
Default
1
12*80
0
1
12*10
0.2
2
2
1
12*1
Project
1
12*80
0
1
12*10
0.2
2
2
1
12*1
BCKPMF
-
-
OFRAC
VCNX
NDECAY
0
0
Description
Read hourly ozone concentrations from the OZONE.DAT data file
Background monthly O3 concentration (ppb)
Use monthly background NH3 concentration (ppb)
Average NH3 values over vertical extent of puff
Background NH3 concentration (ppb)
Nighttime NO2 loss rate in percent/hour
Nighttime NOX loss rate in percent/hour
Nighttime HNO3 loss rate in percent/hour
Background H2O2 concentrations
Background monthly H2O2 concentrations (Aqueous phase transformations
not modeled)
Fine particulate concentration for Secondary Organic Aerosol Option (used
only if MCHEM=4 in the Project MCHEM =3)
Organic fraction of fine particulate for SOA Option (used only if MCHEM=4)
VOC/NOx ratio for SOA Option (used only if MCHEM=4)
No half-life decay specification blocks provided
Pike 1 Project
March 2015
Table C1-11: Miscellaneous Dispersion and Computational Parameters (Input Group 12)
Parameters
Default
Project
550
550
MHFTSZ
0
0
JSUP
5
5
CONK1
0.01
0.01
CONK2
0.1
0.1
Vertical dispersion constant for neutral/stable conditions
TBD
0.5
0.5
IURB2
10
10
IURB2
19
19
XMXLEN
1
1
Use ISC transition point for determining the transition point
between the Schulman-Scire to Huber-Snyder Building
Downwash scheme
Lower range of land use categories for which urban dispersion
is assumed
Upper range of land use categories for which urban dispersion
is assumed
Maximum length of emitted slug in meteorological grid units
XSAMLEN
1
1
MXNEW
99
99
MXSAM
99
99
NCOUNT
2
2
SYMIN
1
1
SZMIN
1
1
SVMIN
6*0.5 for Land,
6*0.37 for Water
6*0.5 for Land, 6*0.37
for Water
minimum turbulence velocities for each stability class over
land and over water (m/s)
SWMIN
.20, .12, .08, .06,
.03, .016 for
Land and Water
.20, .12, .08, .06, .03,
.016 for Land and
Water
minimum turbulence velocities for each stability class over
land and over water (m/s)
SZCAP_M
5.0E06
5.0E06
CDIV
0.0, 0.0
0.0, 0.0
4
4
SYDEP
NLUTIBL
WSCALM
Description
Horizontal size of a puff in metres beyond which the time
dependant dispersion equation of Heffter is used
Do not use Heffter formulas for sigma z
Stability class used to determine dispersion rates for puffs
above boundary layer
Vertical dispersion constant for stable conditions
Maximum travel distance of slug or puff in meteorological grid
units during one sampling unit
Maximum number of puffs or slugs released from one source
during one time step
Maximum number of sampling steps during one time step for a
puff or slug
Number of iterations used when computing the transport wind
for a sampling step that includes transitional plume rise
Minimum sigma y in metres for a new puff or slug
Minimum sigma z in metres for a new puff or slug
Maximum sigma z (m) allowed to avoid numerical problem in
calculating virtual time or distance
Divergence criteria for dw/dz in met cells
Search radius (number of cells) for nearest land and water
cells used in the subgrid TIBL module
Minimum wind speed allowed for non-calm conditions (m/s)
0.5
0.5
XMAXZI
3 000
3 000
XMINZI
50
50
WSCAT
1.54
1.54
wind speed category 1 [m/s]
3.09
3.09
5.14
5.14
8.23
8.23
10.80
10.80
0.020
0.020
potential temperature gradient for E stability [K/m]
0.035
0.035
potential temperature gradient for F stability [K/m]
10
10
PTG0
SL2PF
NSPLIT
IRESPLIT
3
3
Hour 17=1
Hour 17=1
ZISPLIT
100
100
ROLDMAX
0.25
0.25
Maximum mixing height in metres
Minimum mixing height in metres
Slug-to-puff transition criterion factor equal to sigma y/length of
slug
Number of puffs that result every time a puff is split
Time(s) of day when split puffs are eligible to be split once
again
Minimum allowable last hour’s mixing height for puff splitting
Maximum allowable ratio of last hour’s mixing height and
maximum mixing height experienced by the puff for puff
splitting
Pike 1 Project
March 2015
Parameters
Default
Project
NSPLITH
5
5
SYSPLITH
1
1
SHSPLITH
2
2
CNSPLITH
1.0E-7
1.0E-7
EPSSLUG
1.00E-04
1.00E-04
EPSAREA
1.00E-06
1.00E-06
1.0
1.0
DRISE
Stability Class
A
B
C
D
E
F
Stability Class
A
B
C
D
E
F
SVMIN
Minimum turbulence (σv) (m/s)
0.5
0.5
0.5
0.5
0.5
0.5
PLX0
Wind speed profile exponent
0.07
0.07
0.1
0.15
0.35
0.55
Description
Number of puffs that result every time a puff is horizontally
split
Minimum sigma-y of puff before it may be horizontally split
Minimum puff elongation rate due to wind shear before it may
be horizontally split
Minimum concentration of each species in puff before it may
be horizontally split
Fractional convergence criterion for numerical SLUG sampling
iteration
Fractional convergence criterion for numerical AREA sampling
iteration
Trajectory step length for numerical rise
Parameter
Parameter
SWMIN
Minimum turbulence (σw) (m/s)
0.2
0.12
0.08
0.06
0.03
0.016
PPC
Plume path coefficient
0.5
0.5
0.5
0.5
0.35
0.35
Appendix C2
Emission Sources Information – Criteria Air Contaminants
Pike 1 Project
March 2015
APPENDIX C2: EMISSION SOURCES INFORMATION
– CRITERIA AIR CONTAMINANTS
TABLE OF CONTENTS
PAGE
1.0
INTRODUCTION ............................................................................................................. 1
2.0
INDUSTRIAL FACILITIES .............................................................................................. 2
3.0
PROJECT EMISSIONS ................................................................................................. 28
4.0
SMALL GAS PRODUCTION AND PROCESSING FACILITIES ................................... 30
5.0
COMMUNITIES AND HIGHWAYS ................................................................................ 42
LIST OF TABLES
Table C2-1:
Table C2-2:
Table C2-3:
Table C2-4:
Existing and Approved Air Emissions Included in the Baseline and
Application Scenarios ..................................................................................... 3
Project Air Emissions Included in the Application Scenario .......................... 29
Gas Production and Processing Facility Emissions Included in the
Baseline, Application, and Planned Development Scenarios ........................ 31
Community and Highway Emissions Included in the Baseline and
Application Scenarios ................................................................................... 42
Attachment C2 – Table of Contents
Pike 1 Project
March 2015
1.0
INTRODUCTION
This appendix lists the emission source characteristics and emission rate details of the criteria
air contaminants, including sulphur dioxide (SO2), NOx, carbon monoxide (CO), and PM2.5 within
the air quality regional study area (AQRSA). The air quality impacts as a result of emissions of
SO2, NOx, CO and PM2.5 are assessed and provided in the main report.
The facility emissions within the AQRSA that were included in the baseline and application
scenarios of this air quality assessment are presented on a company-by-company basis.
Most of the documented emission sources fall into the following three general categories:

Fully integrated oil sands mining, bitumen extraction and bitumen upgrading facilities.
The facilities primary fuel type is a combination of processed (pipeline spec) natural gas
and desulphurized “refinery-type” fuel gas (containing negligible hydrogen sulphide
(H2S)) in gas turbine/heat recovery steam generators/electricity co-generation facilities
and additional steam boilers/generators and heaters. The major SO2 emission source for
these types of facilities is the sulphur recovery facility, which is part of the processing
plant facility. SO2 emissions from the mining fleet equipment are considered to be a
minor contributor to the facility total since low-sulphur diesel fuel or low-sulphur synthetic
diesel produced on site is utilized in internal combustion engines. In regards to NOx
emissions, NOx from processing plant facilities (combustion sources) and the mining
fleet (internal combustion engines) are considered equally significant.

Steam assisted gravity drainage (SAGD) operations, primarily using processed natural
gas fuel (containing negligible H2S) and small quantities of produced gas (containing
some H2S) in steam boilers/generators and heaters. For this type of industrial
development, the only significant major SO2 and NOx emission sources are the steam
boilers/generators. Compared to integrated mining and bitumen extraction/upgrading
facilities, SAGD facilities emit less SO2 and NOx on a bitumen production basis.

Oil sands mining and bitumen extraction facilities using predominantly processed natural
gas fuel (containing negligible H2S) in gas turbine/heat recovery steam generators/
electricity co-generation facilities and “supplemental” steam boilers/generators and
heaters. In comparison to the other two types of facilities mentioned above, these
facilities emit predominantly NOx, with emissions apportioned more or less equally
between those from the processing plant facilities (combustion sources) and those from
the mining fleet (internal combustion engines). SO2 emissions from the mining fleet are
considered minor since the mining fleet equipment uses low-sulphur diesel fuel.
This appendix also presents the estimated emissions from a number of communities and
highways, as well as a summary of small gas production and processing facilities in the region.
All of the listed facilities and projects are located within the AQRSA and have been selected for
inclusion in the air quality assessment.
Pike 1 Project
March 2015
2.0
INDUSTRIAL FACILITIES
Table C2-1 shows the sources included in modeling for major industrial facilities in the AQRSA.
Table C2-2 shows sources located at small gas production and processing facilities. Table C2-3
shows emission parameters for community and highway sources.
Pike 1 Project
March 2015
Table C2-1: Existing and Approved Air Emissions Included in the Baseline and Application Scenarios
Point Sources
Operator
Facility
Hangingstone
SAGD Project
Athabasca
Oil Sands
Corp.
(AOSC)
UTM E
UTM N
Elevation
(masl)
Stack
Height (m)
Stack
Diameter
(m)
Exit
Velocity
(m/s)
Exit Temp
(K)
SO2
NOX
CO
PM2.5
Steam Generator 1
473867
6259490
453
36.0
2.44
26.4
443
0.12
0.43
1.35
0.04
Steam Generator 2
473833
6259505
453
36.0
2.44
26.4
443
0.12
0.43
1.35
0.04
Glycol Heater
473936
6259520
453
12.5
0.59
26.5
473
0.00
0.03
0.12
0.00
HP Flare
474130
6259381
453
41.0
Area Sources
2.32
0.1
1262
0.00
0.00
0.00
0.00
Emission Source
Emission
Source
Facility
Hangingstone
SAGD
Plant
Fugitive
NW
UTM E
(m)
NW
UTM N
(m)
NE
UTM E
(m)
NE
UTM N
(m)
SE
UTM E
(m)
SE
UTM N
(m)
SW
UTM E
(m)
SW
UTM N
(m)
Area
(m2)
Elevation
(masl)
SO2
(t/d)
NOX
(t/d)
CO
(t/d)
PM2.5
(t/d)
473 692
6 259 724
474 192
6 259 724
474 192
6 259 224
473 692
6 259 224
250 000
453
0
0
0
0.051
0.23
0.89
2.82
0.074
Athabasca Oil Sands Corp. Air Emission Totals for the Baseline and Application Cases
Area Sources
Facility
Canadian Air
Force
Cold Lake Air
Weapons
Range
Emission
Source
NW
UTM E
(m)
NW
UTM N
(m)
NE
UTM E
(m)
NE
UTM N
(m)
SE
UTM E
(m)
SE
UTM N
(m)
SW
UTM E
(m)
SW
UTM N
(m)
Fugitive
558302
6063870
485626
6063870
485626
6136546
558302
6136546
Area
(m2)
Elevation
(masl)
SO2
(t/d)
NOX
(t/d)
CO
(t/d)
PM2.5
(t/d)
52818009
76
680
0.53
9.99
40.2
0.21
0.53
9.99
40.2
0.21
Canadian Air Force Air Emission Totals for the Baseline and Application Cases
Operator
Canadian
Natural
Resources
Ltd.
Facility
Burnt Lake
Emission Source
Glycol Heater
Steam Generator 1
Steam Generator 2
Steam Generator 3
UTM E
UTM N
Elevation
(masl)
541478
541396
541402
541408
6072986
6072999
6072999
6072999
672
672
672
672
Stack
Height
(m)
10.5
13.5
13.5
13.5
Stack
Diameter
(m)
0.50
1.10
1.10
1.10
Exit
Velocity
(m/s)
11.6
6.1
6.1
6.1
Exit
Temp
(K)
448
423
423
423
SO2
NOX
CO
PM2.5
0.00
0.40
0.40
0.40
0.12
0.32
0.32
0.32
0.10
0.27
0.27
0.27
0.01
0.03
0.03
0.03
Pike 1 Project
March 2015
Operator
Facility
Primrose North 14-8-68-4W4
Primrose East
Canadian
Natural
Resources
Ltd. (cont)
Kirby North 2010
Kirby South in-situ
Kirby South 2
Emission Source
FGD Stack 1
FGD Stack 2
Glycol Heater (4 MW)
OTSG 8 (37 MW)
OTSG 7 (37 MW)
OTSG 6 (37 MW)
OTSG 5 (37 MW)
OTSG 4 (77 MW)
OTSG 3 (77 MW)
OTSG 2 (77 MW)
OTSG 1 (77 MW)
FGD Stack 1
FGD Stack 2
FGD Stack 3
Steam Generator 1
Steam Generator 2
Glycol Heater
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Glycol Heater
HP Flare (47m H, 0.6 m D)
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Glycol Heater
HP Flare (47m H, 0.6 m D)
UTM E
526706
526715
526764
526754
526751
526748
526745
526729
526724
526720
526716
541466
541441
541416
485225
485236
485270
498263
498263
498263
498312
498312
498312
498262
498663
497450
497474
497498
497450
497474
497506
497764
Stack
Stack
Exit
Exit
Height
Diameter
Velocity Temp
(m)
(m)
(m/s)
(K)
6081204
685
30.0
2.64
13.0
330
6081181
685
30.0
2.64
13.0
330
6081140
685
7.6
0.48
7.8
393
6081146
685
26.1
1.50
11.8
441
6081155
685
26.1
1.50
11.8
441
6081163
685
26.1
1.50
11.8
441
6081172
685
26.1
1.50
11.8
441
6081178
685
29.4
1.68
19.2
420
6081190
685
29.4
1.68
19.2
420
6081202
685
29.4
1.68
19.2
420
6081213
685
29.4
1.68
19.2
420
6071727
679
30.0
2.64
25.9
330
6071727
679
30.0
2.64
25.9
330
6071727
679
30.0
2.64
25.9
330
6146592
677
27.0
1.60
20.0
423
6146603
677
27.0
1.60
20.0
423
6146607
677
8.0
0.90
8.0
523
6132807
707
45.5
1.98
17.2
467
6132791
707
45.5
1.98
17.2
467
6132775
707
45.5
1.98
17.2
467
6132807
707
45.5
1.98
17.2
467
6132791
707
45.5
1.98
17.2
467
6132775
707
45.5
1.98
17.2
467
6132828
707
31.4
0.91
13.7
609
6132984
706
45.5
2.39
0.4
1273
6133407
709
45.5
1.98
17.2
467
6133407
709
45.5
1.98
17.2
467
6133407
708
45.5
1.98
17.2
467
6133338
709
45.5
1.98
17.2
467
6133338
709
45.5
1.98
17.2
467
6133339
709
31.4
1.30
7.0
488
6133168
708
44.7
2.82
0.1
1263
Air Emission Totals for the Baseline and Application Cases
UTM N
Elevation
(masl)
SO2
NOX
CO
PM2.5
0.60
0.60
0.00
0.15
0.15
0.15
0.15
0.32
0.32
0.32
0.32
0.60
0.60
0.60
0.04
0.04
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
8.16
0.70
0.70
0.04
0.37
0.37
0.37
0.37
0.34
0.34
0.34
0.34
0.70
0.70
0.70
0.29
0.29
0.01
0.47
0.47
0.47
0.47
0.47
0.47
0.03
0.00
0.41
0.41
0.41
0.41
0.41
0.03
0.00
21.9
0.22
0.22
0.17
0.17
0.17
0.17
0.17
0.17
0.17
0.17
0.17
0.22
0.22
0.16
0.26
0.26
0.02
0.40
0.40
0.40
0.40
0.40
0.40
0.04
0.01
0.35
0.35
0.35
0.35
0.35
0.04
0.00
15.0
0.20
0.20
0.00
0.01
0.01
0.01
0.01
0.03
0.03
0.03
0.03
0.20
0.20
0.14
0.02
0.02
0.00
0.04
0.04
0.04
0.04
0.04
0.04
0.00
0.00
0.03
0.03
0.03
0.03
0.03
0.00
0.00
1.62
Pike 1 Project
March 2015
Operator
Facility
Christina Lake
Thermal Phase 1A/1B
Christina Lake
Thermal Phase 1C
Christina Lake
Thermal Phase 1D
Cenovus Energy
Christina Lake
Thermal Phase 1C/1D
Christina Lake
Thermal Phase 1C/1D/1E
Christina Lake
Thermal Phase 1E
Christina Lake
Thermal Phase 1F
Christina Lake
Thermal Phase 1G
Christina Lake
Thermal Phase 1E/F/G
Stack
Diameter
(m)
1.37
0.91
1.68
0.59
1.68
1.68
1.68
1.68
0.91
1.68
1.68
1.68
1.68
0.91
0.31
0.31
Exit
Velocity
(m/s)
27.0
22.0
23.3
13.9
24.5
24.5
24.5
24.5
9.6
24.5
24.5
24.5
24.5
9.6
30.5
30.5
Exit
Temp
(K)
463
463
463
474
488
488
488
488
474
488
488
488
488
474
512
512
SO2
NOX
CO
PM2.5
575
575
576
576
576
576
576
576
577
576
577
577
577
577
576
576
Stack
Height
(m)
26.6
13.8
32.9
6.7
32.0
32.0
32.0
32.0
9.2
32.0
32.0
32.0
32.0
9.2
3.3
3.3
0.05
0.02
0.07
0.00
0.07
0.07
0.07
0.07
0.00
0.07
0.07
0.07
0.07
0.00
0.00
0.00
0.25
0.06
0.32
0.02
0.32
0.32
0.32
0.32
0.03
0.32
0.32
0.32
0.32
0.03
0.01
0.01
0.79
0.29
1.01
0.07
1.01
1.01
1.01
1.01
0.12
1.01
1.01
1.01
1.01
0.12
0.04
0.04
0.02
0.01
0.03
0.00
0.03
0.03
0.03
0.03
0.00
0.03
0.03
0.03
0.03
0.00
0.00
0.00
6159805
6159818
577
577
32.0
32.0
1.83
1.83
26.3
26.3
442
442
0.09
0.09
0.46
0.46
1.42
1.42
0.04
0.04
507092
507084
507077
507070
507436
507429
507486
6159752
6159766
6159779
6159792
6159817
6159831
6159780
577
577
577
577
577
577
577
32.0
32.0
32.0
32.0
32.0
32.0
32.0
1.68
1.68
1.68
1.68
1.68
1.68
3.34
24.5
24.5
24.5
24.5
24.5
24.5
22.7
488
488
488
488
488
488
473
0.07
0.07
0.07
0.07
0.07
0.07
0.06
0.32
0.32
0.32
0.32
0.32
0.32
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.41
0.03
0.03
0.03
0.03
0.03
0.03
0.06
507471
6159808
577
32.0
3.34
22.7
473
0.06
1.01
1.41
0.06
507412
507405
507397
507390
507383
507568
507578
507623
6159861
6159874
6159887
6159901
6159914
6159773
6159778
6159709
578
578
578
578
578
578
578
577
32.0
32.0
32.0
32.0
32.0
3.3
3.3
9.2
1.68
1.68
1.68
1.68
1.68
0.31
0.31
0.91
24.5
24.5
24.5
24.5
24.5
30.5
30.5
9.6
488
488
488
488
488
512
512
474
0.07
0.07
0.07
0.07
0.07
0.00
0.00
0.00
0.32
0.32
0.32
0.32
0.32
0.01
0.01
0.03
1.01
1.01
1.01
1.01
1.01
0.04
0.04
0.12
0.03
0.03
0.03
0.03
0.03
0.00
0.00
0.00
UTM E
UTM N
Elevation
(masl)
OTSG (B-101)
OTSG (B-102)
OTSG (B-1725)
Glycol Heater (H-522)
OTSG (B-2100)
OTSG (B-2200)
OTSG (B-2300)
OTSG (B-2400)
OTSG (B-2500)
OTSG (B-2600)
OTSG (B-2700)
OTSG (B-2800)
Flash Treater (H-5070A)
Flash Treater (H-5070B)
506880
506874
507036
506939
507169
507162
507155
507147
507380
507130
507123
507116
507109
507387
507259
507249
6159498
6159489
6159450
6159483
6159613
6159626
6159639
6159652
6159601
6159682
6159691
6159709
6159722
6159605
6159598
6159595
OTSG (B-2360)
OTSG (B-2460)
507062
507055
OTSG (B-3100)
OTSG (B-3200)
OTSG (B-3300)
OTSG (B-3400)
OTSG (B-3160)
OTSG (B-3260)
Cogenerator Unit (GT2900, B-3360)
Cogenerator Unit (GT2900, B-3460)
OTSG (B-3500)
OTSG (B-3550)
OTSG (B-3600)
OTSG (B-3650)
OTSG (B-3700)
Flash Treater (H-5270A)
Flash Treater (H-5270B)
Emission Source
Pike 1 Project
March 2015
Operator
Facility
Christina Lake
Thermal Phase 1G
Cenovus Energy
(cont)
Narrows Lake
Thermal Phase 1
Stack
Diameter
(m)
0.91
Exit
Velocity
(m/s)
9.6
Exit
Temp
(K)
474
SO2
NOX
CO
PM2.5
577
Stack
Height
(m)
9.2
0.00
0.03
0.12
0.00
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6167162
6166983
6166992
6167004
562
562
562
562
562
562
562
562
562
562
562
562
562
562
562
563
563
563
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
32.0
9.2
9.2
3.3
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
0.91
0.91
0.31
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
24.5
9.6
9.6
30.5
488
488
488
488
488
488
488
488
488
488
488
488
488
488
488
474
474
512
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.00
0.00
0.00
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.03
0.03
0.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
0.12
0.12
0.04
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.00
0.00
0.00
507495
6166992
563
3.3
0.31
30.5
512
0.00
0.01
0.04
0.00
507847
507885
507930
504641
505441
504431
505881
506218
505881
505081
504451
504293
504387
505229
6167022
6167053
6167058
6172293
6172293
6171597
6171565
6172061
6170766
6170689
6170888
6170802
6169881
6169659
562
562
562
569
569
570
569
569
563
563
563
563
563
563
6.4
6.3
29.0
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
0.71
0.26
0.91
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
12.2
4.6
15.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
483
873
811
773
773
773
773
773
773
773
773
773
773
773
0.00
0.00
1.64
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.04
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.07
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
UTM E
UTM N
Elevation
(masl)
Glycol Heater (H-7300B)
507614
6159704
Steam Generator(B-2100)
Steam Generator (B-2250)
Steam Generator (H-7100)
Steam Generator (H-7110)
Slop Oil Treater Reheater
(H-5070A)
Slop Oil Treater Reheater
(H- 5070B)
Process Glycol Heater
SRU Preheater
Sulphur Incinerator
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
507435
507415
507395
507375
507355
507315
507295
507275
507255
507235
507195
507175
507155
507135
507115
507565
507565
507495
Emission Source
Pike 1 Project
March 2015
Operator
Cenovus Energy
(cont)
Facility
Narrows Lake
Thermal Phase 1
(cont)
Emission Source
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
UTM E
UTM N
Elevation
(masl)
505019
503546
501066
500248
500352
498808
499170
500173
499385
499648
497109
497596
497791
497976
498146
499338
499545
499509
499511
499512
500224
500679
500337
500710
500369
501272
501748
501773
501884
500971
501073
501257
503433
502802
502571
502380
502872
6169325
6168771
6169915
6169866
6169571
6168912
6168360
6167870
6167584
6166781
6166593
6166578
6166676
6166751
6166578
6165857
6165671
6164798
6164108
6163567
6163318
6163304
6165654
6165708
6164257
6163912
6164030
6164426
6164766
6164109
6164311
6164309
6165060
6165118
6164943
6164450
6164570
564
565
562
563
563
563
561
561
562
562
561
562
562
562
562
573
573
569
566
600
601
602
573
574
568
564
565
565
566
569
570
565
567
567
566
565
566
Stack
Height
(m)
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
Stack
Diameter
(m)
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
Exit
Velocity
(m/s)
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
Exit
Temp
(K)
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Cenovus Energy
(cont)
Facility
Narrows Lake
Thermal Phase 1
(cont)
Emission Source
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
UTM E
UTM N
Elevation
(masl)
503097
503459
503697
504560
506851
506227
508046
506724
506007
504660
504453
504667
504461
505197
505249
505456
506730
507066
512845
512578
513956
513165
513162
512537
511094
512534
510690
512325
510506
509990
509664
509090
509694
510940
510302
507872
508398
6164568
6164645
6164603
6166889
6166586
6166331
6166150
6165617
6165617
6166089
6165965
6165768
6165169
6164757
6165618
6165784
6164371
6164423
6164717
6165887
6166238
6166078
6166654
6166831
6166771
6167521
6168448
6168348
6166391
6165940
6168359
6167958
6167622
6167779
6167972
6168352
6167732
566
566
566
561
563
561
559
559
564
563
563
563
562
563
563
564
558
558
559
560
565
560
561
560
563
560
560
559
563
559
560
560
561
561
561
560
561
Stack
Height
(m)
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
Stack
Diameter
(m)
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
Exit
Velocity
(m/s)
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
Exit
Temp
(K)
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Cenovus Energy
(cont)
Facility
Narrows Lake
Thermal Phase 1
(cont)
Emission Source
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Turbine
Well Pad Line Heater
UTM E
UTM N
Elevation
(masl)
507534
509669
509763
507219
508662
507975
508748
510056
510237
510369
512142
500953
511047
510532
510630
510366
510377
504086
503243
503827
503038
504643
505443
504433
505883
506220
505883
505083
504453
504295
504388
505230
505020
503547
501068
500249
500354
6167819
6166658
6166882
6167697
6169856
6169416
6169687
6169136
6168796
6169067
6169008
6169691
6167592
6168466
6168297
6167166
6166943
6170594
6169344
6169931
6168508
6172326
6172326
6171631
6171598
6172094
6170799
6170723
6170921
6170835
6169915
6169692
6169359
6168805
6169948
6169899
6169604
561
563
562
562
564
565
564
565
565
565
562
562
562
560
560
562
563
563
564
563
562
569
569
570
569
569
563
563
563
563
563
563
564
565
562
563
563
Stack
Height
(m)
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
6.1
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
Stack
Diameter
(m)
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.61
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
Exit
Velocity
(m/s)
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
Exit
Temp
(K)
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
773
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Cenovus Energy
(cont)
Facility
Narrows Lake
Thermal Phase 1
(cont)
Emission Source
UTM E
UTM N
Elevation
(masl)
498810
499171
500175
499387
499650
497111
497598
497793
497978
498148
499339
499547
499510
499513
499513
500226
500680
500338
500712
500370
501273
501749
501775
501885
500973
501075
501259
503434
502804
502573
502382
502874
503098
503461
503699
504562
506852
6168946
6168394
6167903
6167617
6166814
6166626
6166611
6166709
6166784
6166612
6165890
6165705
6164832
6164142
6163600
6163351
6163337
6165688
6165741
6164290
6163946
6164063
6164459
6164799
6164142
6164344
6164342
6165093
6165151
6164976
6164483
6164603
6164601
6164679
6164636
6166922
6166619
563
561
561
562
562
561
562
562
562
562
574
573
569
567
600
601
602
573
574
569
564
565
565
566
569
570
565
567
567
566
565
566
566
566
566
561
563
Stack
Height
(m)
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
Stack
Diameter
(m)
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
Exit
Velocity
(m/s)
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
Exit
Temp
(K)
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Cenovus Energy
(cont)
Facility
Narrows Lake
Thermal Phase 1
(cont)
Emission Source
UTM E
UTM N
Elevation
(masl)
506228
508047
506726
506009
504662
504454
504669
504463
505198
505250
505458
506732
507068
512847
512579
513957
513167
513163
512538
511096
512536
510692
512327
510508
509992
509666
509091
509696
510942
510303
507874
508399
507536
509671
509765
507220
508664
6166364
6166183
6165650
6165650
6166123
6165998
6165802
6165203
6164790
6165651
6165818
6164405
6164456
6164750
6165921
6166271
6166111
6166687
6166865
6166804
6167554
6168482
6168381
6166425
6165973
6168392
6167991
6167655
6167812
6168006
6168385
6167765
6167852
6166692
6166916
6167730
6169889
561
559
559
564
563
563
563
562
563
563
564
558
558
559
560
568
560
561
560
563
560
560
559
563
559
560
560
561
561
561
560
561
561
563
562
562
564
Stack
Height
(m)
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
Stack
Diameter
(m)
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
Exit
Velocity
(m/s)
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
Exit
Temp
(K)
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Facility
Narrows Lake
Thermal Phase 1
(cont)
Cenovus Energy
(cont)
Foster Creek
1A-E
Stack
Diameter
(m)
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
0.36
3.40
3.40
0.51
Exit
Velocity
(m/s)
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
4.0
21.0
21.0
12.0
Exit
Temp
(K)
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
959
448
448
448
SO2
NOX
CO
PM2.5
565
566
565
565
565
562
562
562
560
560
562
563
563
564
563
562
667
667
667
Stack
Height
(m)
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
4.6
26.0
26.0
22.0
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.08
0.08
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.92
0.92
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.20
1.20
0.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.06
0.06
0.00
6102363
667
21.0
0.51
12.0
448
0.00
0.00
0.02
0.00
6102529
6102519
6102562
6102552
6102493
6102588
6102590
6102630
6102875
6102492
6102768
6102756
6102594
6102876
6102884
6102893
667
667
667
667
667
667
667
667
668
667
667
667
667
667
667
667
27.0
27.0
27.0
27.0
27.0
8.2
7.7
8.0
6.6
6.6
6.6
6.6
8.2
27.0
27.0
27.0
1.40
1.40
1.40
1.40
1.40
0.76
0.61
0.61
0.41
0.41
0.41
0.41
0.61
1.70
1.70
1.70
16.0
16.0
16.0
16.0
16.0
12.0
2.0
4.6
3.6
3.6
3.6
3.6
2.4
21.0
21.0
21.0
447
447
447
447
447
533
533
533
533
533
533
533
533
488
488
488
0.07
0.07
0.07
0.07
0.07
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.20
0.20
0.20
0.20
0.20
0.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.32
0.32
0.32
0.58
0.58
0.58
0.58
0.58
0.09
0.01
0.02
0.01
0.01
0.01
0.01
0.02
1.00
1.00
1.00
0.02
0.02
0.02
0.02
0.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.03
0.03
0.03
Emission Source
UTM E
UTM N
Elevation
(masl)
Cogen #1
Cogen #2
Cogen Air Handling Heater
AH-1201
Cogen Air Handling Heater
AH-1202
Steam Generator B-0201
Glycol Heater H-0501
Fuel Gas Heater H-0502
Hot Oil Heater H-0503
Well Pad Heater (H-2001)
Fuel Gas Heater H-0514
507977
508750
510058
510239
510371
512144
500954
511049
510534
510632
510368
510379
504087
503244
503828
503040
529663
529643
529650
6169449
6169720
6169169
6168829
6169101
6169042
6169724
6167626
6168499
6168330
6167199
6166976
6170628
6169377
6169965
6168541
6102406
6102368
6102408
529620
529736
529729
529685
529680
529713
529716
529797
529662
530439
529885
528916
528805
529792
529793
529780
529768
Pike 1 Project
March 2015
Operator
Facility
Foster Creek
1A-E
Cenovus Energy
(cont)
Foster Creek
SRF
Stack
Diameter
(m)
1.70
0.91
1.70
1.70
1.70
1.70
1.70
1.70
0.91
0.20
0.20
0.51
Exit
Velocity
(m/s)
21.0
4.1
21.0
21.0
21.0
21.0
21.0
21.0
4.1
4.8
4.8
3.8
Exit
Temp
(K)
488
580
488
488
488
488
488
488
580
479
479
505
SO2
NOX
CO
PM2.5
667
667
667
667
667
667
667
667
667
667
667
667
Stack
Height
(m)
27.0
8.2
30.0
30.0
30.0
30.0
30.0
30.0
8.2
6.4
6.4
8.2
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.32
0.02
0.32
0.32
0.32
0.32
0.32
0.32
0.02
0.00
0.00
0.00
1.00
0.09
1.00
1.00
1.00
1.00
1.00
1.00
0.09
0.02
0.02
0.02
0.03
0.00
0.03
0.03
0.03
0.03
0.03
0.03
0.00
0.00
0.00
0.00
6102932
667
8.6
0.61
3.2
562
0.00
0.00
0.02
0.00
529378
6102854
667
10.0
0.51
2.0
475
0.00
0.00
0.01
0.00
529383
6102859
667
9.0
0.51
2.0
475
0.00
0.00
0.00
0.00
529350
6102907
667
11.0
0.41
2.1
475
0.00
0.00
0.01
0.00
529333
6102903
667
11.0
0.41
2.1
475
0.00
0.00
0.01
0.00
529359
6102859
667
9.1
0.31
2.2
475
0.00
0.00
0.01
0.00
530273
6102801
667
14.0
0.81
12.0
499
0.00
0.02
0.08
0.00
530277
6102801
667
14.0
0.81
12.0
499
0.00
0.02
0.08
0.00
530256
6102864
667
14.0
0.51
8.2
447
0.00
0.01
0.02
0.00
530240
530240
530240
530269
6102835
6102839
6102843
6102801
667
667
667
667
6.3
6.3
6.3
29.0
0.26
0.26
0.26
0.90
0.8
0.8
0.8
7.6
873
873
873
811
0.00
0.00
0.00
0.94
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.02
0.00
0.00
0.00
0.00
Emission Source
UTM E
UTM N
Elevation
(masl)
Glycol Heater H-0501B
Glycol Heater H- 0501C
Glycol Heater H-0564-1
Glycol Heater H-0564-2
Disposal Water Heater
|(H-0519)
Tricanter Glycol Heater
(H-0900)
Heated Source Water
Tank Heater (H-0603A)
Heated Source Water
Tank Heater (H-0603B)
Slop/Clean Oil Tank
T202C Heater (H-1204A)
Slop/Clean Oil Tank
T202C Heater (H-1204B)
Brine Tank Heater
(H-0605)
Process Glycol Boiler
(H-5970A)
Process Glycol Boiler
(H-5970B)
Utility Glycol Boiler
(H-5770)
Air Preheater A (H-5914A)
Air Preheater B (H-5914B)
Air Preheater C (H-5914C)
SRU Incinerator (S-5950)
529755
529764
529828
529836
529845
529853
529862
529870
529753
529485
529485
529850
6102901
6102798
6102817
6102830
6102842
6102855
6102868
6102880
6102840
6102503
6102502
6102561
529374
Pike 1 Project
March 2015
Operator
Facility
Foster Creek
F
Cenovus Energy
(cont)
Foster Creek
G
Foster Creek
H
Emission Source
Steam Generator
FC3-B-0201
Steam Generator
FC3-B-0202
Steam Generator
FC3-B-0203
Steam Generator
FC3-B-0204
Glycol Heater
FC3-H-0501A
Glycol Heater
FC3-H-0501B
Glycol Heater Pilot
Flash Treater
FC3-V-0304A
Steam Generator
FC3-B-0205
Steam Generator FC3-B0206
Glycol Heater FC3-H0501C
Flash Treater FC3-V0304B
Glycol Heater FC3-H0501D
Stack
Diameter
(m)
1.70
Exit
Velocity
(m/s)
21.0
Exit
Temp
(K)
490
SO2
NOX
CO
PM2.5
667
Stack
Height
(m)
30.0
0.03
0.32
1.00
0.03
6103310
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529347
6103310
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529362
6103310
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529196
6103027
667
9.5
0.90
6.1
468
0.00
0.03
0.12
0.00
529196
6103020
667
9.5
0.90
6.1
468
0.00
0.03
0.12
0.00
529360
529324
6102940
6103225
667
667
5.3
6.7
0.22
0.61
2.4
9.7
672
970
0.00
0.00
0.01
0.01
0.06
0.04
0.00
0.00
529397
6103311
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529412
6103311
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529427
6103311
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529442
6103311
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529196
6103017
667
9.5
0.90
6.1
468
0.00
0.03
0.12
0.00
529284
6103224
667
6.7
0.61
9.7
970
0.00
0.01
0.04
0.00
529477
6103311
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529492
6103312
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529507
6103312
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529522
6103312
667
30.0
1.70
21.0
490
0.03
0.32
1.00
0.03
529196
6103008
667
9.5
0.90
6.1
468
0.00
0.03
0.12
0.00
UTM E
UTM N
Elevation
(masl)
529317
6103310
529332
Pike 1 Project
March 2015
Operator
Facility
Foster Creek
Osprey
Cenovus Energy
(cont)
Foster Creek
1A-E
Foster Creek
SRF
Foster Creek
FGH
Stack
Diameter
(m)
0.76
Exit
Velocity
(m/s)
14.0
Exit
Temp
(K)
450
SO2
NOX
CO
PM2.5
684
Stack
Height
(m)
8.0
0.00
0.05
0.27
0.01
6098707
684
8.2
0.25
2.0
475
0.00
0.00
0.00
0.00
531658
6098701
684
8.2
0.25
2.0
475
0.00
0.00
0.00
0.00
530026
529282
530026
6102848
6102840
6102848
667
667
667
30.0
20.0
29.0
1.70
1.70
3.20
0.1
0.1
0.1
1 266
1 269
1 273
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
530281
6102892
667
28.0
1.70
0.1
1 267
0.00
0.00
0.00
0.00
530281
6102892
667
29.0
0.99
0.1
1 257
0.00
0.00
0.00
0.00
529190
6103529
667
27.0
9.00
0.1
1 281
0.00
0.01
0.03
0.00
529184
6103529
667
29.0
2.60
0.1
1 271
0.00
0.00
0.00
0.00
5.56
29.2
77.6
2.09
Emission Source
UTM E
UTM N
Elevation
(masl)
Osprey Steam Generator
(CSSH-0800)
BFW Tank Heater (CSSH-0300A)
BFW Tank Heater (CSSH-0300B)
CPF HP Flare (S-505)
CPF LP Flare (S-503)
CPF Pop Tank Vent Flare
(S-504)
SRF Emergency Flare HP
(S-5955)
SRF Emergency Flare LP
(S-5955)
Phase F/G/H HP Flare
(FC3-S-0501)
Phase F/G/H LP Flare
(FC3-S-0503)
531670
6098682
531659
Operator
Facility
Algar Expansion
Connacher Oil and
Gas Limited
Great Divide
(Pod 1)
Emission Source
Steam Generator 1
(73.2MW)
Steam Generator 2
(73.2 MW)
Utility Boiler
Glycol Heater
Cogen
Steam Generator 1
(67.4 MW)
Steam Generator 2
(67.4 MW)
Utility Boiler (3.69 MW)
Glycol Heater (3.22 MW)
Treater (1.47 MW)
Stack
Diameter
(m)
1.47
Exit
Velocity
(m/s)
12.4
Exit
Temp
(K)
413
SO2
NOX
CO
PM2.5
745
Stack
Height
(m)
30.0
0.99
0.25
0.79
0.02
6218979
745
30.0
1.47
12.4
413
0.99
0.25
0.79
0.02
445669
455674
455573
448529
6218822
6218822
6219011
6219128
632
745
745
666
8.5
8.2
15.2
30.0
0.51
0.61
1.83
1.83
4.8
3.4
8.9
14.3
425
368
473
561
0.00
0.00
0.00
0.99
0.01
0.01
0.32
0.21
0.04
0.05
0.19
0.19
0.00
0.00
0.00
0.02
448557
6219145
666
30.0
1.68
14.3
561
0.99
0.21
0.19
0.02
448609
448638
448579
6219097
6219007
6219017
666
665
665
8.2
8.2
11.8
0.51
0.61
0.25
8.9
5.2
4.0
495
438
588
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
UTM E
UTM N
Elevation
(masl)
455618
6218994
455626
Pike 1 Project
March 2015
Operator
Connacher Oil and
Gas Limited (cont)
Operator
Facility
Great Divide Algar
Expansion (Pod 2)
Facility
Surmont Phase 1
ConocoPhillips
Canada Resources
Corp.
Surmont Pilot
Surmont Phase 2
Emission Source
Steam Boiler
Steam Boiler
Steam Boiler
Steam Boiler
Steam Boiler
Utility Boiler
Glycol Heater
Cogen
UTM E
455590
455572
455563
455581
455598
455684
455689
455560
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6218965
745
30.0
1.83
12.0
423
6218955
745
30.0
1.83
12.0
423
6218930
745
30.0
1.83
12.0
423
6218940
745
30.0
1.83
12.0
423
6218950
745
30.0
1.83
12.0
423
6218793
745
8.5
0.76
4.3
425
6218793
745
8.2
0.91
3.1
368
6219035
745
20.0
2.13
8.9
473
UTM N
Elevation
(masl)
SO2
NOX
CO
PM2.5
0.31
0.31
0.31
0.31
0.31
0.00
0.00
0.00
5.53
0.37
0.37
0.37
0.37
0.37
0.02
0.02
0.27
3.46
1.16
1.16
1.16
1.16
1.16
0.08
0.09
0.33
8.55
0.03
0.03
0.03
0.03
0.03
0.00
0.00
0.01
0.24
Stack
Diameter
(m)
0.76
0.90
0.39
1.68
1.68
1.68
1.68
0.91
0.91
1.20
0.91
0.91
0.91
0.91
0.76
0.90
Exit
Velocity
(m/s)
20.0
7.8
3.7
20.1
20.1
20.1
20.1
8.3
8.3
2.1
83.0
83.0
83.0
83.0
20.0
7.8
Exit
Temp
(K)
1 273
652
811
469
469
469
469
423
423
1 273
423
423
423
423
1 273
652
SO2
NOX
CO
PM2.5
664
664
664
664
664
664
664
628
628
628
628
628
628
628
617
615
Stack
Height
(m)
48.8
15.0
10.2
27.0
27.0
27.0
27.0
13.3
13.3
12.2
10.0
11.0
11.0
5.0
48.8
15.0
0.01
0.01
0.00
0.10
0.10
0.10
0.10
0.00
0.00
0.08
0.00
0.00
0.00
0.00
0.01
0.01
0.02
0.02
0.00
0.26
0.26
0.26
0.26
0.09
0.09
0.00
0.00
0.00
0.00
0.00
0.02
0.05
0.00
0.02
0.00
0.27
0.27
0.27
0.27
0.04
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.02
0.00
0.00
0.00
0.02
0.02
0.02
0.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6227741
615
15.0
0.90
7.8
652
0.01
0.05
0.02
0.00
504058
6227749
615
15.0
0.90
7.8
652
0.01
0.05
0.02
0.00
504144
504118
504200
504118
6227407
6227777
6227777
6227792
615
616
616
616
10.2
27.0
27.0
27.0
0.39
1.68
1.68
1.68
3.7
20.1
20.1
20.1
811
469
469
469
0.00
0.10
0.10
0.10
0.00
0.26
0.26
0.26
0.00
0.27
0.27
0.27
0.00
0.02
0.02
0.02
Emission Source
UTM E
UTM N
Elevation
(masl)
Continuous Flare FS-701
Glycol Trim Heater H-601
Slop Treater X-240
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Boiler B-101 14.65 MW
Boiler B-121 1.2 MW
Flare
H-401 312 kW Glycol
H-501 312 kW Glycol
H-502 312 kW Glycol
H-53 200 kW
Continuous Flare 2FS-701
Glycol Trim Heater 2H601A
Glycol Trim Heater 2H601B
Glycol Trim Heater 2H601C
Slop Treater 2X-240
Steam Generator 531A
Steam Generator 531B
Steam Generator 531C
503418
503440
503448
503363
503363
503434
503434
501840
501840
501840
501840
501840
501840
501840
504488
504058
6227513
6227633
6227575
6227513
6227528
6227513
6227528
6230040
6230040
6230040
6230040
6230040
6230040
6230040
6227645
6227733
504058
Pike 1 Project
March 2015
Operator
ConocoPhillips
Canada Resources
Corp. (cont)
Operator
Facility
Surmont Phase 2
(cont)
Facility
Jackfish 1
Devon ARL Corp.
Jackfish 2
Emission Source
Steam Generator 531D
Steam Generator 531E
Steam Generator 531F
Steam Generator 531G
Steam Generator 531H
Steam Generator 531I
Steam Generator 531J
Steam Generator 531K
Steam Generator 531L
Steam Generator 531M
Steam Generator 531N
Sulphur Plant Incinerator
Emission Source
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Glycol Trim Heater 1
Flash Treater
Flash Treater
Continuous Flare
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
UTM E
504200
504118
504200
504118
504200
504118
504200
504118
504200
504118
504200
504344
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6227792
616
27.0
1.68
20.1
469
6227807
616
27.0
1.68
20.1
469
6227807
616
27.0
1.68
20.1
469
6227822
616
27.0
1.68
20.1
469
6227822
616
27.0
1.68
20.1
469
6227837
616
27.0
1.68
20.1
469
6227837
616
27.0
1.68
20.1
469
6227852
616
27.0
1.68
20.1
469
6227852
616
27.0
1.68
20.1
469
6227867
616
27.0
1.68
20.1
469
6227867
616
27.0
1.68
20.1
469
6227647
617
30.5
0.92
0.9
923
UTM N
Elevation
(masl)
UTM E
UTM N
Elevation
(masl)
507855
507846
507838
507830
507821
507813
508036
508028
508008
508009
508148
500046
500039
500032
500026
500019
500012
500194
500189
6153524
6153515
6153507
6153498
6153490
6153481
6153691
6153684
6153514
6153512
6153476
6153269
6153259
6153249
6153239
6153229
6153219
6153465
6153457
632
632
632
632
632
632
633
633
632
632
633
665
665
665
665
665
665
665
665
Stack
Height
(m)
28.9
28.9
28.9
28.9
28.9
28.9
6.7
6.7
6.0
6.0
40.3
28.9
28.9
28.9
28.9
28.9
28.9
6.7
6.7
Stack
Diameter
(m)
1.83
1.83
1.83
1.83
1.83
1.83
0.71
0.71
0.15
0.15
12.38
1.83
1.83
1.83
1.83
1.83
1.83
0.71
0.71
Exit
Velocity
(m/s)
15.5
15.5
15.5
15.5
15.5
15.5
27.7
27.7
23.2
23.2
0.0
15.5
15.5
15.5
15.5
15.5
15.5
27.7
27.7
Exit
Temp
(K)
443
443
443
443
443
443
399
399
443
443
2 777
443
443
443
443
443
443
399
399
SO2
NOX
CO
PM2.5
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.08
2.08
0.26
0.26
0.26
0.26
0.26
0.26
0.26
0.26
0.26
0.26
0.26
0.00
5.17
0.27
0.27
0.27
0.27
0.27
0.27
0.27
0.27
0.27
0.27
0.27
0.12
5.10
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.00
0.45
SO2
NOX
CO
PM2.5
0.33
0.33
0.33
0.33
0.33
0.33
0.00
0.00
0.00
0.00
0.00
0.33
0.33
0.33
0.33
0.33
0.33
0.00
0.00
0.35
0.35
0.35
0.35
0.35
0.35
0.02
0.02
0.01
0.01
0.00
0.35
0.35
0.35
0.35
0.35
0.35
0.02
0.02
0.22
0.22
0.22
0.22
0.22
0.22
0.02
0.02
0.00
0.00
0.00
0.22
0.22
0.22
0.22
0.22
0.22
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.00
0.00
0.00
0.00
0.00
0.02
0.02
0.02
0.02
0.02
0.02
0.00
0.00
Pike 1 Project
March 2015
Operator
Facility
Jackfish 2 (cont)
Devon ARL Corp.
(cont)
Jackfish 3
Operator
Excelsior Energy
Limited
Facility
Hangingstone
Insitu Combustion
Emission Source
Flash Treater1
Flash Treater2
Continuous Flare
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Glycol Trim Heater
Glycol Trim Heater
Flash Treater
Flash Treater
Continuous Flare
Emission Source
Vent
Incinerator
Incinerator
Incinerator
Incinerator
Hp Flare
Lp Flare
OTSG
OTSG
UTM E
500199
500200
500343
503235
503247
503259
503271
503283
503295
502989
502999
503133
503133
503062
UTM E
482882
482901
482901
482901
482901
483067
483022
482957
482960
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6153286
665
6.0
0.15
23.2
443
6153285
665
6.0
0.15
23.2
443
6153272
665
40.0
12.39
0.0
2 777
6151932
663
28.9
1.83
15.5
443
6151932
663
28.9
1.83
15.5
443
6151932
663
28.9
1.83
15.5
443
6151932
663
28.9
1.83
15.5
443
6151932
663
28.9
1.83
15.5
443
6151932
663
28.9
1.83
15.5
443
6151940
663
6.7
0.71
27.7
399
6151940
663
6.7
0.71
27.7
399
6152050
663
6.0
0.15
23.2
443
6152048
663
6.0
0.15
23.2
443
6152174
663
40.0
12.39
0.0
2 777
UTM N
Elevation
(masl)
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6254293
531
42.0
0.31
74.0
623
6254297
531
36.0
1.52
4.7
811
6254295
531
36.0
1.52
4.7
811
6254292
530
36.0
1.52
4.7
811
6254290
530
36.0
1.52
4.7
811
6255039
545
18.0
4.31
0.0
2 273
6254943
543
12.0
5.71
0.0
2 273
6255015
545
10.7
0.40
8.5
473
6255015
545
10.7
0.76
9.5
473
UTM N
Elevation
(masl)
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.33
0.33
0.33
0.33
0.33
0.33
0.00
0.00
0.00
0.00
0.00
6.00
0.01
0.01
0.00
0.35
0.35
0.35
0.35
0.35
0.35
0.02
0.02
0.01
0.01
0.00
6.51
0.00
0.00
0.00
0.22
0.22
0.22
0.22
0.22
0.22
0.02
0.02
0.00
0.00
0.00
4.17
0.00
0.00
0.00
0.02
0.02
0.02
0.02
0.02
0.02
0.00
0.00
0.00
0.00
0.00
0.38
SO2
NOX
CO
PM2.5
1.03
0.26
0.26
0.26
0.26
0.01
0.00
0.00
0.00
2.06
0.00
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.02
0.05
2.42
0.03
0.03
0.03
0.03
0.00
0.00
0.02
0.10
2.66
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.005
Pike 1 Project
March 2015
Operator
Facility
Whitesands Pilot
(including three
wells expansion)
Grizzly Oil Sands
Algar Lake SAGD
Operator
Facility
BlackGold Phase1
Harvest Operations
Corp.
Operator
Husky Energy Inc.
BlackGold
Expansion
Facility
Caribou Lake
Thermal
Demonstration
Emission Source
UTM E
Flare Stack
Steam Generator (2.2 MW)
Glycol Boiler (2 MW)
Glycol Boiler (2 MW)
Incinerator
Steam Generator 87 MW
Steam Generator 87 MW
Co-gen 5.9 MW
Co-gen 5.9 MW
Flare Stack 1
Flare Stack 2
483874
484000
483894
483894
483964
450756
450788
450769
450801
450683
450715
Emission Source
UTM E
Steam Generator
Slop Oil Heater
Glycol Heater
Steam Generator
Steam Generator
Glycol Heater
Slop Oil Heater
HP Flare
LP Flare
Emission Source
Steam Generator 1
Steam Generator 2
Glycol Heater
Emergency Generator
Flare
500933
500973
501108
500958
501015
501139
500830
500783
500783
UTM E
525137
525151
525105
525138
524930
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6168345
621
12.3
0.15
0.5
2 738
6168220
621
6.6
0.40
11.1
723
6168325
621
5.5
0.60
1.7
773
6168315
621
5.5
0.60
1.7
773
6168182
621
20.1
1.60
16.3
1 179
6246276
532
22.0
1.80
18.3
444
6246189
548
22.0
1.80
18.3
444
6246242
548
18.0
1.00
11.0
453
6246156
548
18.0
1.00
11.0
453
6246210
548
28.0
0.20
1.0
1 273
6246132
548
28.0
0.20
1.0
1 273
UTM N
Elevation
(masl)
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6159367
611
30.0
1.50
27.0
756
6159400
611
15.0
0.40
27.0
739
6159561
611
15.0
0.40
27.0
739
6159367
611
30.0
1.50
27.0
756
6159367
612
30.0
1.50
27.0
756
6159567
611
15.0
0.40
27.0
739
6159314
611
15.0
0.40
27.0
739
6159311
611
36.3
0.40
27.0
1 086
6159311
611
36.3
0.40
27.0
1 086
UTM N
Elevation
(masl)
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6090343
696
30.0
1.67
25.5
423
6090343
696
30.0
1.67
25.5
423
6090330
696
12.0
0.46
20.5
523
6090292
696
6.0
0.20
100.0
718
6090335
697
30.8
2.38
0.1
1 273
UTM N
Elevation
(masl)
SO2
NOX
CO
PM2.5
0.18
0.00
0.00
0.00
2.00
0.53
0.53
0.00
0.00
0.00
0.00
3.23
0.01
0.03
0.00
0.00
0.00
0.14
0.14
0.07
0.07
0.00
0.00
0.46
0.01
0.02
0.00
0.00
0.00
0.34
0.34
0.03
0.34
0.00
0.00
1.08
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.00
0.00
0.05
SO2
NOX
CO
PM2.5
0.30
0.00
0.00
0.30
0.30
0.00
0.00
0.00
0.00
0.90
0.34
0.02
0.01
0.34
0.34
0.01
0.15
0.15
0.02
1.39
0.29
0.01
0.01
0.29
0.29
0.01
0.00
0.00
0.00
090
0.04
0.00
0.00
0.04
0.04
0.00
0.00
0.00
0.00
0.12
SO2
NOX
CO
PM2.5
0.20
0.20
0.00
0.00
0.00
0.39
0.33
0.33
0.01
0.15
0.00
0.83
0.36
0.36
0.03
0.08
0.00
0.83
0.02
0.02
0.00
0.00
0.00
0.05
Pike 1 Project
March 2015
Operator
Facility
Hangingstone
Demonstration
Japan Canada Oil
Sands Ltd.
Hangingstone
Commercial
Emission Source
Steam Generator B-201A
Steam Generator B-201B
Glycol Heater H-701
Line Heater H-702
Glycol Heater H-755
LP Flare FS-702
Continuous
HP Flare FS-701N
Continuous
LP Flare 804 Continuous
HP Flare 801 Continuous
OTSG1
OTSG2
OTSG3
OTSG4
OTSG5
OTSG6
OTSG7
Heat Medium Heater #1
Heat Medium Heater #2
HP Flare
LP Flare
Stack
Diameter
(m)
0.91
0.91
0.46
0.46
1.37
1.07
0.41
1.37
4.33
Exit
Velocity
(m/s)
21.6
21.6
20.5
7.7
23.6
12.7
35.0
23.6
0.1
Exit
Temp
(K)
533
533
563
563
479
498
563
479
2 697
SO2
NOX
CO
PM2.5
555
555
555
555
554
554
554
554
555
Stack
Height
(m)
12.0
12.0
9.0
12.0
30.0
30.0
9.0
30.0
20.0
0.00
0.00
0.00
0.00
0.80
0.23
0.00
0.80
0.09
0.04
0.04
0.01
0.00
0.18
0.18
0.02
0.18
0.00
0.06
0.06
0.01
0.00
0.20
0.06
0.01
0.20
0.01
0.01
0.01
0.00
0.00
0.02
0.00
0.00
0.02
0.00
555
26.0
5.33
0.0
2 660
0.08
0.00
0.01
0.00
0.00
0.00
1.00
1.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
4.00
0.00
0.00
0.30
0.30
0.30
0.30
0.30
0.30
0.30
0.02
0.02
0.00
0.00
2.82
0.00
0.01
1.30
1.30
1.29
1.29
1.29
1.29
1.29
0.03
0.03
0.00
0.00
9.72
0.00
0.00
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.00
0.00
0.00
0.00
0.23
UTM E
UTM N
Elevation
(masl)
460387
460382
460343
460404
460798
460821
460765
460814
460357
6241760
6241756
6241775
6241716
6241554
6241496
6241527
6241554
6241841
460371
6241850
460786
460786
461357
461372
461387
461402
461417
461432
461447
461597
461597
461122
461122
6241399
554
18.3
6.89
0.0
2 779
6241400
554
18.3
8.67
0.0
2 779
6237163
622
30.0
1.66
26.1
478
6237163
622
30.0
1.66
26.1
478
6237163
622
30.0
1.66
26.0
478
6237163
622
30.0
1.66
26.0
478
6237163
622
30.0
1.66
26.0
478
6237163
622
30.0
1.66
26.0
478
6237163
622
30.0
1.66
26.0
478
6237108
622
6.0
0.60
15.1
473
6237118
622
6.0
0.60
15.1
473
6237053
601
44.9
15.15
0.0
2 780
6237053
601
45.6
5.18
0.0
2780
Pike 1 Project
March 2015
Operator
Facility
Christina Lake
Phase 1 (Pilot)
Christina Lake
Phase 2
Christina Lake
Phase 2B
MEG Energy Corp.
Christina Lake
Phase 3A
Emission Source
OTSG
Glycol Heater
LP Flare Continuous
HP Flare Continuous
OTSG
Cogen
Glycol Heater
Slop Treater
Slop Treater
HP Flare Continuous
Steam Generator 1
Steam Generator 2
Steam Generator 3
Cogen
Glycol Heater
Amine Preheater
Flare
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Steam Generator 7
Steam Generator 8
Steam Generator 9
Steam Generator 10
Steam Generator 11
Steam Generator 12
Steam Generator 13
Steam Generator 14
Glycol Heater 1
Glycol Heater 2
Slop Treater 1A
Slop Treater 1B
Slop Treater 2A
Slop Treater 2B
UTM E
UTM N
Elevation
(masl)
517796
517828
517870
517850
517772
517704
517818
517867
517867
517874
517373
517378
517383
517632
517639
517917
517860
525543
525543
525543
525543
525543
525543
525543
525542
525543
525543
525543
525543
525542
525542
525800
525801
526028
526028
526097
526097
6168843
6168816
6168764
6168732
6168836
6168835
6168886
6168901
6168900
6169058
6169140
6169122
6169105
6168815
6169235
6168990
6169109
6162802
6162785
6162767
6162750
6162732
6162714
6162696
6162595
6162578
6162560
6162542
6162525
6162507
6162489
6162663
6162627
6162662
6162661
6162662
6162661
573
573
573
571
573
573
573
573
573
573
574
574
573
573
573
573
573
607
607
607
607
607
607
606
606
606
606
606
606
606
606
606
606
606
606
606
606
Stack
Height
(m)
30.0
7.5
13.2
31.5
30.0
24.0
5.0
9.0
9.0
55.2
30.0
30.0
30.0
24.0
15.0
15.0
55.2
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
15.0
15.0
15.0
15.0
15.0
15.0
Stack
Diameter
(m)
1.38
0.51
2.40
2.88
1.68
5.18
1.02
0.61
0.61
5.75
1.96
1.96
1.96
5.18
1.52
0.31
7.19
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.96
1.52
1.52
0.61
0.61
0.61
0.61
Exit
Velocity
(m/s)
20.7
4.5
0.2
0.1
19.7
21.4
5.8
5.3
5.3
0.0
17.0
17.0
17.0
21.4
9.5
76.3
0.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
10.2
10.2
5.7
5.7
5.7
5.7
Exit
Temp
(K)
445
434
1 273
1 273
445
437
434
533
533
1 273
444
444
444
437
618
533
1 273
444
444
444
444
444
444
444
444
444
444
444
444
444
444
618
618
533
533
533
533
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.33
0.12
0.00
0.00
0.28
1.96
0.03
0.00
0.00
0.00
0.33
0.33
0.33
1.96
0.02
0.02
0.00
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.06
0.06
0.00
0.00
0.00
0.00
0.18
0.01
0.01
0.01
0.25
1.43
0.03
0.01
0.01
0.01
0.29
0.29
0.29
1.43
0.07
0.03
0.01
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.08
0.08
0.01
0.01
0.01
0.01
0.02
0.00
0.00
0.00
0.02
0.12
0.00
0.00
0.00
0.00
0.03
0.03
0.03
0.12
0.01
0.00
0.00
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.01
0.01
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Facility
Christina Lake
Phase 3A (cont)
MEG Energy Corp.
(cont)
Christina Lake
Phase 3B
Christina Lake
Emission Source
Amine Preheater 1
Amine Preheater 2
Flare 1
Flare 2
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Steam Generator 7
Steam Generator 8
Steam Generator 9
Steam Generator 10
Steam Generator 11
Steam Generator 12
Steam Generator 13
Steam Generator 14
Glycol Heater 1
Glycol Heater 2
Slop Treater 1A
Slop Treater 1B
Slop Treater 2A
Slop Treater 2B
Amine Preheater 1
Amine Preheater 2
Flare 1
Flare 2
SRU Incinerator 1
SRU Incinerator 2
SRU Incinerator 3
UTM E
525844
525843
526002
526002
506443
506443
506443
506443
506443
506443
506443
506442
506442
506442
506443
506443
506443
506442
506700
506701
506928
506928
506997
506997
506745
506745
506902
506902
517929
517950
517967
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6162684
606
15.0
0.31
29.8
533
6162609
606
15.0
0.31
29.8
533
6162859
607
55.2
7.19
0.0
1 273
6162432
605
55.2
7.19
0.0
1 273
6174903
587
30.0
1.96
17.0
444
6174885
587
30.0
1.96
17.0
444
6174867
587
30.0
1.96
17.0
444
6174850
587
30.0
1.96
17.0
444
6174832
587
30.0
1.96
17.0
444
6174814
587
30.0
1.96
17.0
444
6174796
587
30.0
1.96
17.0
444
6174695
587
30.0
1.96
17.0
444
6174678
587
30.0
1.96
17.0
444
6174660
587
30.0
1.96
17.0
444
6174642
587
30.0
1.96
17.0
444
6174625
587
30.0
1.96
17.0
444
6174607
587
30.0
1.96
17.0
444
6174589
587
30.0
1.96
17.0
444
6174763
587
15.0
1.52
10.2
618
6174727
587
15.0
1.52
10.2
618
6174762
586
15.0
0.61
5.7
533
6174761
586
15.0
0.61
5.7
533
6174762
586
15.0
0.61
5.7
533
6174761
586
15.0
0.61
5.7
533
6174783
586
15.0
0.31
29.8
533
6174708
587
15.0
0.31
29.8
533
6174959
586
55.2
7.19
0.0
1 273
6174532
587
55.2
7.19
0.0
1 273
6168916
573
45.7
0.61
6.9
873
6168923
573
80.0
0.41
18.3
873
6168927
573
80.0
0.41
18.3
873
UTM N
Elevation
(masl)
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
0.84
0.84
2.80
0.01
0.01
0.00
0.00
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.06
0.06
0.00
0.00
0.00
0.00
0.01
0.01
0.00
0.00
0.00
0.00
0.00
17.3
0.02
0.02
0.01
0.01
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.29
0.08
0.08
0.01
0.01
0.01
0.01
0.02
0.02
0.01
0.01
0.00
0.00
0.00
13.1
0.00
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.16
Pike 1 Project
March 2015
Operator
Facility
Long Lake North
Phase 1
Long Lake North
Phase 1 (cont)
Nexen Inc./OPTI
Canada Inc.
Long Lake South
Phase 1
Emission Source
Steam Super Heater 1
(24 MW)
((24 MW))
(7 MW)
SRU Incinerator 1
SRU Incinerator 2
Thermal Oil Heater 1 (17
MW)
Thermal Oil Heater 2 (17
MW)
Utility Boiler 1 (51 MW)
Vacuum Tower Heater 1
(54 MW)
(54 MW)
(54 MW)
(54 MW)
Cogen
Continuous Flare
Glycol Trim Heater
(33.9MW)
Line Heater 1
Line Heater 2
Steam Generator 1 (92
MW)
Steam Generator 10
Steam Generator 11
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Steam Generator 7
Stack
Diameter
(m)
1.89
Exit
Velocity
(m/s)
6.5
Exit
Temp
(K)
578
SO2
NOX
CO
PM2.5
483
Stack
Height
(m)
30.0
0.03
0.06
0.07
0.01
6250844
472
30.0
1.89
6.5
578
0.03
0.06
0.07
0.01
503729
6251027
474
30.0
1.02
6.2
523
0.01
0.02
0.02
0.00
503410
503732
503567
6251145
6250845
6251482
474
474
482
115.0
115.0
30.0
1.52
1.52
1.47
30.0
30.0
7.4
811
811
611
8.40
8.40
0.02
0.04
0.04
0.04
0.03
0.03
0.06
0.00
0.00
0.01
503719
6251037
474
30.0
1.47
7.4
611
0.02
0.04
0.06
0.01
503307
503295
504024
503468
6251379
6251391
6250887
6251604
483
483
472
482
30.0
30.0
30.0
30.0
1.51
1.51
1.51
2.84
29.5
29.5
29.5
6.0
416
416
416
628
0.12
0.12
0.12
0.06
0.18
0.18
0.18
0.19
0.36
0.36
0.36
0.17
0.03
0.03
0.03
0.02
503477
6251596
482
30.0
2.84
6.0
628
0.06
0.19
0.17
0.02
503871
6251113
471
30.0
2.84
6.0
628
0.06
0.19
0.17
0.02
503862
6251105
471
30.0
2.84
6.0
628
0.06
0.19
0.17
0.02
500465
501160
500689
6239611
6239853
6239602
555
561
557
30.0
37.5
30.0
5.18
3.85
1.80
18.2
0.0
6.0
433
1 273
422
0.59
0.00
0.00
2.44
0.00
0.12
1.83
0.00
0.10
0.13
0.00
0.01
500941
504806
500521
6240033
6246080
6239541
560
473
555
7.4
7.4
30.0
0.51
0.51
1.68
1.4
1.4
18.8
477
477
464
0.00
0.00
0.09
0.00
0.00
0.32
0.00
0.00
0.28
0.00
0.00
0.03
500624
500642
500539
500557
500575
500593
500554
500572
6239578
6239568
6239530
6239520
6239509
6239499
6239619
6239608
556
556
555
555
556
556
556
556
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
464
464
464
464
464
464
464
464
0.09
0.09
0.09
0.09
0.09
0.09
0.09
0.09
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
UTM E
UTM N
Elevation
(masl)
503336
6251343
503984
Pike 1 Project
March 2015
Operator
Facility
Long Lake South
Phase 1 (cont)
Nexen Inc./OPTI
Canada Inc.
(cont)
Long Lake South
Phase 2
Stack
Diameter
(m)
1.68
1.68
5.18
5.18
3.73
1.80
Exit
Velocity
(m/s)
18.8
18.8
18.2
18.2
10.4
6.0
Exit
Temp
(K)
464
464
433
433
1 273
422
SO2
NOX
CO
PM2.5
556
556
561
562
525
563
Stack
Height
(m)
30.0
30.0
30.0
30.0
47.2
30.0
0.09
0.09
0.59
0.59
3.78
0.00
0.32
0.32
2.44
2.44
0.11
0.01
0.28
0.28
1.83
1.83
0.59
0.10
0.03
0.03
0.13
0.13
0.01
0.01
6240903
6240393
526
562
7.4
30.0
0.51
1.68
1.4
18.8
477
464
0.00
0.09
0.05
0.41
0.00
0.28
0.00
0.03
501102
501120
501117
501134
501152
501170
500465
501160
500689
6240383
6240372
6240471
6240462
6240451
6240441
6239611
6239853
6239602
562
562
562
562
562
562
555
561
557
30.0
30.0
30.0
30.0
30.0
30.0
30.0
37.5
30.0
1.68
1.68
1.68
1.68
1.68
1.68
5.18
3.85
1.80
18.8
18.8
18.8
18.8
18.8
18.8
18.2
0.0
6.0
464
464
464
464
464
464
433
1 273
422
0.09
0.09
0.09
0.09
0.09
0.09
0.59
0.00
0.00
0.41
0.41
0.41
0.41
0.41
0.41
2.44
0.00
0.12
0.28
0.28
0.28
0.28
0.28
0.28
1.83
0.00
0.10
0.03
0.03
0.03
0.03
0.03
0.03
0.13
0.00
0.01
500941
504806
500521
6240033
6246080
6239541
560
473
555
7.4
7.4
30.0
0.51
0.51
1.68
1.4
1.4
18.8
477
477
464
0.00
0.00
0.09
0.00
0.00
0.32
0.00
0.00
0.28
0.00
0.00
0.03
500624
500642
500539
500557
500575
500593
500554
500572
500590
500606
500993
501033
6239578
6239568
6239530
6239520
6239509
6239499
6239619
6239608
6239598
6239588
6240485
6240460
556
556
555
555
556
556
556
556
556
556
561
562
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
5.18
5.18
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.8
18.2
18.2
464
464
464
464
464
464
464
464
464
464
433
433
0.09
0.09
0.09
0.09
0.09
0.09
0.09
0.09
0.09
0.09
0.59
0.59
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
0.32
2.44
2.44
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.28
1.83
1.83
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.13
0.13
Emission Source
UTM E
UTM N
Elevation
(masl)
Steam Generator 8
Steam Generator 9
Cogen 1
Cogen 2
Continuous Flare
Glycol Trim Heater
(3.75 MW)
Line Heater (19.5 MW)
Steam Generator 1
(117.2 MW)
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Steam Generator 7
Cogen
Continuous Flare
Glycol Trim Heater
(33.9MW)
Line Heater 1
Line Heater 2
Steam Generator 1 (92
MW)
Steam Generator 10
Steam Generator 11
Steam Generator 2
Steam Generator 3
Steam Generator 4
Steam Generator 5
Steam Generator 6
Steam Generator 7
Steam Generator 8
Steam Generator 9
Cogen 1
Cogen 2
500590
500606
500993
501033
501688
501217
6239598
6239588
6240485
6240460
6240726
6240475
501474
501084
Pike 1 Project
March 2015
Operator
Nexen Inc./OPTI
Canada Inc.
(cont)
Operator
Stack
Diameter
(m)
3.73
1.80
Exit
Velocity
(m/s)
10.4
6.0
Exit
Temp
(K)
1 273
422
SO2
NOX
CO
PM2.5
525
563
Stack
Height
(m)
47.2
30.0
3.78
0.00
0.11
0.01
0.59
0.10
0.01
0.01
526
562
7.4
30.0
0.51
1.68
1.4
18.8
477
464
0.00
0.09
0.05
0.41
0.00
0.28
0.00
0.03
0.09
0.09
24.7
0.41
0.41
15.5
0.28
0.28
13.5
0.03
0.03
1.06
Facility
Emission Source
UTM E
UTM N
Elevation
(masl)
501688
501217
6240726
6240475
Long Lake South
Phase 2 (cont)
Continuous Flare
Glycol Trim Heater (3.75
MW)
Line Heater (19.5 MW)
Steam Generator 1 (117.2
MW)
Steam Generator 2
Steam Generator 3
501474
501084
6240903
6240393
501102
501120
6240383
562
30.0
1.68
18.8
464
6240372
562
30.0
1.68
18.8
464
Emission Source
UTM E
UTM N
Elevation
(masl)
Glycol Heater
HP Flare Continuous
LP Flare Continuous
Slop Treater
OTSG 1
OTSG 2
OTSG 3
OTSG 4
OTSG 5
OTSG 6
OTSG 7
OTSG 8
Sulphur Plant Process
Heater
Glycol Heater
HP Flare Continuous
LP Flare Continuous
Slop Treater
OTSG 1
OTSG 2
OTSG 3
OTSG 4
Heater
484327
484464
484464
484524
484246
484245
484245
484246
484344
484344
484344
484344
484396
6203124
6203024
6203025
6203207
6203282
6203270
6203258
6203246
6203282
6203270
6203259
6203246
6203236
485127
485264
485264
485324
485144
485144
485144
485144
485196
6203124
6203024
6203025
6203207
6203282
6203270
6203259
6203246
6203236
Facility
Kai Kos Dehseh Corner 1
StatoilHydro
Canada Ltd.
Kai Kos Dehseh Corner 2
Stack
Diameter
(m)
0.76
3.78
1.89
0.32
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
0.76
Exit
Velocity
(m/s)
5.1
0.0
0.0
11.0
16.7
16.7
16.7
16.7
16.7
16.7
16.7
16.7
5.1
Exit
Temp
(K)
616
1 273
1 273
532
444
444
444
444
444
444
444
444
616
SO2
NOX
CO
PM2.5
709
710
710
709
709
709
709
709
709
709
709
709
709
Stack
Height
(m)
16.0
32.4
32.3
10.0
27.0
27.0
27.0
27.0
27.0
27.0
27.0
27.0
16.0
0.00
0.00
0.00
0.00
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.00
0.01
0.00
0.00
0.00
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.01
0.00
0.00
0.00
0.00
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.00
0.00
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.00
710
710
710
710
710
710
710
710
710
16.0
32.4
32.3
10.0
27.0
27.0
27.0
27.0
16.0
0.76
3.78
1.89
0.32
1.68
1.68
1.68
1.68
0.76
5.1
0.0
0.0
11.0
16.7
16.7
16.7
16.7
5.1
616
1 273
1 273
532
444
444
444
444
616
0.00
0.00
0.00
0.00
0.06
0.06
0.06
0.06
0.00
0.01
0.00
0.00
0.00
0.33
0.33
0.33
0.33
0.01
0.00
0.00
0.00
0.00
0.20
0.20
0.20
0.20
0.00
0.00
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.00
Pike 1 Project
March 2015
Operator
Facility
Kai Kos Dehseh Corner Expansion
Kai Kos Dehseh Corner Expansion
West
StatoilHydro
Canada Ltd.
(cont)
Kai Kos Dehseh Leismer
Demo/Commercial
Kai Kos Dehseh Leismer Expansion
Stack
Height
(m)
16.0
32.4
32.3
10.0
16.0
32.4
32.3
10.0
27.0
27.0
27.0
27.0
16.0
32.0
32.0
10.0
27.0
27.0
27.0
27.0
27.0
27.0
27.0
27.0
16.0
Stack
Diameter
(m)
0.76
3.78
1.89
0.32
0.76
3.78
1.89
0.32
1.68
1.68
1.68
1.68
0.76
3.78
1.89
0.32
1.68
1.68
1.68
1.68
1.68
1.68
1.68
1.68
0.76
Exit
Velocity
(m/s)
5.1
0.0
0.0
11.0
5.1
0.0
0.0
11.0
16.7
16.7
16.7
16.7
5.1
0.0
0.0
11.0
16.7
16.7
16.7
16.7
16.7
16.7
16.7
16.7
5.1
Exit
Temp
(K)
616
1 273
1 273
532
616
1 273
1 273
532
444
444
444
444
616
1 273
1 273
532
444
444
444
444
444
444
444
444
616
Emission Source
UTM E
UTM N
Elevation
(masl)
Glycol Heater
HP Flare Continuous
LP Flare Continuous
Slop Treater
Glycol Heater
HP Flare Continuous
LP Flare Continuous
Slop Treater
OTSG 1
OTSG 2
OTSG 3
OTSG 4
Glycol Heater
HP Flare Continuous
LP Flare Continuous
Slop Treater
OTSG 1
OTSG 2
OTSG 3
OTSG 4
OTSG 5
OTSG 6
OTSG 7
OTSG 8
Heater
Glycol Heater
HP Flare Continuous
LP Flare Continuous
Slop Treater
484077
484214
484214
484274
480309
480446
480446
480507
480326
480326
480327
480327
471809
471946
471946
472007
471728
471728
471728
471728
471826
471826
471827
471827
471878
6203674
6203574
6203575
6203757
6210317
6210217
6210218
6210399
6210475
6210463
6210451
6210439
6185646
6185545
6185546
6185728
6185804
6185792
6185780
6185768
6185804
6185792
6185780
6185768
6185758
708
708
708
723
701
701
701
701
701
701
701
701
643
643
643
642
642
642
642
642
642
642
642
642
642
472609
472746
472746
472807
6185646
642
16.0
0.76
5.1
616
6185545
642
32.0
3.78
0.0
1 273
6185545
642
32.0
1.89
0.0
1 273
6185728
642
10.0
0.32
11.0
532
SO2
NOX
CO
PM2.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.06
0.06
0.06
0.06
0.00
0.00
0.00
0.00
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.00
0.01
0.00
0.00
0.00
0.01
0.00
0.00
0.00
0.33
0.33
0.33
0.33
0.01
0.00
0.00
0.00
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.28
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.20
0.20
0.20
0.20
0.00
0.00
0.00
0.00
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.00
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.03
0.00
0.00
0.00
0.00
0.00
1.43
0.01
0.00
0.00
0.00
7.66
0.00
0.00
0.00
0.00
4.87
0.00
0.00
0.00
0.00
0.61
Pike 1 Project
March 2015
Operator
Suncor Energy Inc.
Facility
Meadow Creek
Phase1
Meadow Creek
Expansion
Emission Source
Cogen 1
Cogen 2
Glycol Heater 1
Glycol Heater 2
Steam Generator 1
Steam Generator 2
Steam Generator 3
Steam Generator 4
Cogen
steam generators
UTM E
482144
482144
481869
481869
481880
482251
482251
482162
482162
468656
468756
Stack
Stack
Exit
Exit
Height
Diameter
Velocity
Temp
(m)
(m)
(m/s)
(K)
6242326
720
30.5
6.10
23.6
478
6242261
720
30.5
6.10
23.6
478
6242361
721
8.1
0.69
20.6
478
6242354
721
8.1
0.69
20.6
478
6242339
721
7.8
0.25
10.5
478
6242013
721
27.0
1.76
20.6
478
6242025
721
27.0
1.76
20.6
478
6242013
721
27.0
1.76
20.6
478
6242025
721
27.0
1.76
20.6
478
6246028
567
30.5
6.10
23.6
478
6246128
581
27.0
1.76
20.6
478
UTM N
Elevation
(masl)
SO2
NOX
CO
PM2.5
0.35
0.35
0.03
0.03
0.00
0.19
0.19
0.19
0.19
0.69
0.79
2.99
2.98
2.98
0.03
0.03
0.00
0.29
0.29
0.29
0.29
5.94
1.24
14.4
2.14
2.14
0.05
0.05
0.00
0.31
0.31
0.31
0.31
4.29
1.33
11.2
0.18
0.18
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.36
0.12
0.96
Pike 1 Project
March 2015
3.0
PROJECT EMISSIONS
Table C2-2 provides a summary of the emissions from the Devon Pike facility included in the
application scenario.
Pike 1 Project
March 2015
Table C2-2: Project Air Emissions Included in the Application Scenario
Facility
Pike
Phase 1a
Pike
Phase 1b
UTM E
(m)
UTM N
(m)
Elevation
(masl)
Rated
Power
(MW)
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)
OTSG 1
511075
6144568
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 2
511066
6144560
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 3
511057
6144552
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 4
511048
6144544
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 5
511039
6144537
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 6
511030
6144529
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
Glycol Heater 1
511270
6144718
642
9.15
6.7
0.710
27.7
399
0.00
0.02
0.10
0.00
Glycol Heater 2
511262
6144711
642
9.15
6.7
0.710
27.7
399
0.00
0.02
0.10
0.00
Flash Treater Stack 1
511229
6144543
642
0.15
23.2
443
0.00
0.00
0.00
0.00
511227
6144544
642
4.1
(Total)
6.00
6.00
0.15
23.2
443
0.00
0.00
0.00
0.00
Flare Stack (Normal Purge)
511364
6144494
642
n/a
41.2 (40.0)
0.41 (1.70)
0.42 (0.1)
2 777 (1187)
0.00
0.00
0.00
0.00
OTSG 7
510644
6144770
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 8
510635
6144762
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 9
510626
6144755
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 10
510617
6144747
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 11
510608
6144739
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
OTSG 12
510599
6144732
642
92.5
27.0
1.83
15.5
443
0.20
0.21
1.00
0.03
Glycol Heater 3
510839
6144921
642
9.15
6.7
0.710
27.7
399
0.00
0.02
0.10
0.00
Glycol Heater 4
510831
6144914
642
9.15
6.7
0.710
27.7
399
0.00
0.02
0.10
0.00
510798
510796
6144746
6144747
642
642
4.1
(Total)
6.00
6.00
0.15
0.15
23.2
23.2
443
443
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Flare Stack (Normal Purge)
510933
6144697
642
n/a
41.2 (40.0)
0.41 (1.70)
0.42 (0.1)
Emission Source
2 777 (1187)
0.00
0.00
0.00
0.00
Devon Pike Point Source Emission Totals for the Application and Planned Development Scenarios (not including emergency generators)
2.42
2.39
12.39
0.36
Fugitive Emissions Totals for the Application and Planned Development Scenarios
0.00
0.00
0.00
0.00
Note:
Numbers in brackets are pseudo parameters for flares.
Pike 1 Project
March 2015
4.0
SMALL GAS PRODUCTION AND PROCESSING FACILITIES
The emissions from several gas compression and processing facilities located within the
AQRSA are included in both the Baseline and Application scenarios.
Table C2-3 presents a summary of the emissions included in the Baseline and Application
scenarios.
Pike 1 Project
March 2015
Table C2-3: Gas Production and Processing Facility Emissions
Included in the Baseline, Application, and Planned Development Scenarios
Operator
Facility
C.S. Thornbury Burnt Pine
04-20-083-11W4
C.S. Thornbury Burnt Pine
North 11-34-083-11W4
C.S. Thornbury
Hangingstone
07-09-082-12W4
AltaGas
Services Inc.
C.S. Winefred North
07-15-078-04W4
C.S. Winefred South
08-04-077-05W4
C.S.
G.P. Thornbury East
Sweet Gas Plant 15-12
Emissions Source
1100 kW Compressor
Engine
52 kW Reboiler
298 kW Compressor
Engine
298 kW Compressor
Engine
164 kW Compressor
Engine
447 kW Compressor
Engine (Waukesha 2895)
70kW Generator
(Cat 3302 TA)
70kW Generator
(Cat 3306 TA)
Dehydrator Reboiler
552kW Compressor
Engine
Cat G3304 NA
Cat G3516 TA
Waukesha L7042 GSI
Cat G3306 TA
Cat G3306 TA
Cat G3306 TA
Waukesha L7042 GSI
Waukesha L7042 GSI
Waukesha L7042 GSI
Compressor
Compressor
629
Stack
Height
(m)
10
Stack
Diameter
(m)
0.5
Exit
Velocity
(m/s)
25
Exit
Temp
(K)
673
6228868
6232874
629
664
10
10
0.5
0.5
25
25
455560
6223183
736
10
0.5
449399
6216374
734
10
449399
6216374
734
449399
6216374
449399
UTM E
(m)
UTM N
(m)
Elevation
(masl)
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
455870
6228868
0
0.0372
0.0052
0
455870
459584
673
673
0
0
0.0008
0.0104
0.0007
0.0014
0
0
25
673
0
0.0104
0.0014
0
0.5
25
673
0
0.0467
0.0069
0.0001
10
0.5
25
673
0
0.1253
0.0173
0.0001
734
10
0.5
25
673
0
0.0173
0.1253
0.0004
6216374
734
10
0.5
25
673
0
0.0173
0.1253
0.0004
449399
6216374
734
10
0.5
25
673
0
0.006
0.0056
0
529516
529516
529516
518602
518602
518602
518602
518602
518602
449199
443978
6179016
6179016
6179016
6165939
6165939
6165939
6165939
6165939
6165939
6216577
6197984
567
567
567
567
567
567
567
567
567
734
687
10
10
22.9
3.4
3.4
3.4
22.9
22.9
15.3
10
10
0.5
0.5
0.3
0.1
0.1
0.1
0.3
0.3
0.3
0.5
0.5
2.9
40.7
46.1
46.5
46.5
46.5
46.1
46.1
43.2
6.2
25
773
773
880
839
839
839
880
880
874
773
773
0
0
0
0
0
0
0
0
0
0
0
0.0361
0.544
0.532
0.048
0.048
0.048
0.638
0.638
0.532
0.24
0.19
0.0093
0.1304
0.127
0.0037
0.0037
0.0037
0.0496
0.0496
0.0413
0.02
0.48
0
0.0003
0.0003
0.0001
0.0001
0.0001
0.0046
0.0046
0.0013
0
0.001
Pike 1 Project
March 2015
Operator
Facility
00/08-33-074- 06W4 C.S.
Kirby South 10-25-07305W4M C.S.
BP Canada
Energy
Company
Leismer 06-36-077-09
W4M C.S.
Leismer 07-05-074-04
W4M C.S.
Leismer 08-20-077-08
W4M C.S.
Leismer 10-19-077-08
W4M C.S.
Leismer 13-13-077-08
W4M C.S.
Leismer 13-33-077-09
W4M C.S.
Leismer 15-26-077-09
W4M C.S.
Primrose 11-8-74-5W4
C.S.
Stack
Diameter
(m)
0.50
0.46
0.46
0.46
0.30
0.30
0.20
0.20
0.20
0.41
1.07
0.50
Exit
Velocity
(m/s)
17.5
39.8
39.8
39.8
25.0
25.0
30.3
30.3
30.3
36.9
48.4
25.0
Exit
Temp
(K)
773
766
766
766
673
673
829
829
829
899
769
673
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
642
670
670
670
670
670
670
670
670
670
670
567
Stack
Height
(m)
10.0
21.0
21.0
21.0
9.1
9.1
14.0
14.0
14.0
8.5
13.4
14.0
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.18
1.14
1.14
1.14
0.01
0.00
0.55
0.55
0.55
0.05
0.23
0.21
0.01
0.16
0.15
0.08
0.00
0.00
0.01
0.01
0.01
0.03
0.04
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6136791
641
14.0
0.50
25.0
673
0.00
0.02
0.04
0.00
487456
6170984
584
8.5
0.50
25.7
773
0.00
0.02
0.03
0.00
Ford Industrial Ford 460
485484
6171547
575
8.5
0.50
25.0
673
0.00
0.00
0.00
0.00
Cat 3306
492746
6170164
570
10.0
0.50
6.4
773
0.00
0.07
0.00
0.00
Waukesha F-18
478121
6175059
587
10.0
0.50
12.8
773
0.00
0.29
0.01
0.00
Cummins G855
483064
6173180
581
10.0
0.50
25.0
673
0.00
0.06
0.01
0.00
White Superior 16SGT
Comp Engine
Comp Engine
Comp Engine
Waukesha L5790GL
Comp Engine
Waukesha L5790GL
Comp Engine
Waukesha L5790GL
Comp Engine
Kirby North Dehydrator
Heat Medium Boiler
516427
6139030
633
20.8
0.46
39.7
773
0.00
3.37
0.09
0.00
516427
6139030
633
20.8
0.46
39.7
773
0.00
3.37
0.09
0.00
516427
6139030
633
20.8
0.46
39.7
773
0.00
3.37
0.09
0.00
516427
6139030
633
8.6
0.30
43.9
644
0.00
0.13
0.04
0.00
516427
6139030
633
8.6
0.30
43.9
644
0.00
0.13
0.04
0.00
516427
6139030
633
8.6
0.30
43.9
644
0.00
0.13
0.04
0.00
516427
516427
6139030
6139030
633
633
7.6
6.1
0.61
0.31
1.2
5.6
477
477
0.00
0.00
0.01
0.01
0.00
0.00
0.00
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
Cat G3412TA
Cooper Superior 16SGT
Heat Medium Boiler
Reboiler
Waukesha F3521 G
Waukesha F3521 G
Waukesha F3521 G
Waukesha L7044 GSI
Centre Type H
Cat G379TA
509104
523574
523574
523574
523574
523574
523574
523574
523574
523574
523574
483877
6145080
6134466
6134466
6134466
6134466
6134466
6134466
6134466
6134466
6134466
6134466
6173990
Waukesha 5790GL
526532
Waukesha L36GL
Emissions Source
Pike 1 Project
March 2015
Operator
BP Canada
Energy
Company
(cont)
Facility
Leismer 16-23-77-9W4
C.S.
Cowpar Sour Gas 11-19080-04W4M
Canadian
Natural
Resources Ltd.
Kettle River Gas 15-14083-05W4M G.P.
Newby Sour Gas 07-02085-06W4M G.P.
Emissions Source
MEP 12 cyl.
MEP 12 cyl.
MEP 12 cyl.
Superior 16 SGTB(engine)
Heat Medium Boiler
Heat Medium Boiler
Glycol Reboiler
104 KW Generator
150 KW TEG Regenerator
176 KW Amine Reboiler
31 KW pump Exhaust
Stack
492 KW Glycol Heater
557 KW Boiler Exhaust
Stack (88 kW???)
Stack (88 kW???)
Stack (88 kW???)
Acid Gas Flare Stack
Waukesha F11 G (378
kW??)
Waukesha F11 G (378
kW??)
Waukesha F11 G (378
kW??)
Waukesha L7042 GL
Waukesha L7042 GL
Waukesha L7042 GL
Waukesha L7042 GL
100 kw power Generator
1100 kW Compressor
Engine
205 KW Reboiler
Flare Stack
67 KW dehydrator
Stack
Diameter
(m)
0.66
0.66
0.61
0.46
0.51
0.51
0.31
0.50
0.50
0.50
0.50
Exit
Velocity
(m/s)
34.3
34.3
40.2
43.5
1.5
1.0
2.8
25.0
25.0
25.0
25.0
Exit
Temp
(K)
672
672
672
691
477
477
477
673
673
673
673
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
579
579
579
579
579
579
579
475
475
475
475
Stack
Height
(m)
12.2
12.2
14.8
12.2
5.5
5.5
5.6
12.2
5.5
5.5
5.5
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.47
1.47
0.73
0.10
0.00
0.00
0.00
0.14
0.20
0.00
0.04
0.33
0.33
0.33
0.34
0.00
0.00
0.00
0.00
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6200560
6228483
475
477
10.0
10.0
0.50
0.50
25.0
25.0
673
673
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
520207
6228483
477
10.0
0.50
25.0
673
0.00
0.00
0.00
0.00
520207
6228483
477
10.0
0.50
25.0
673
0.00
0.00
0.00
0.00
520207
520207
6228483
6228483
477
477
22.9
10.0
0.25
0.50
20.0
2.5
1273
773
0.40
0.00
0.06
0.04
0.01
0.01
0.00
0.00
520207
6228483
477
10.0
0.50
2.5
773
0.00
0.04
0.01
0.00
520207
6228483
477
10.0
0.50
2.5
773
0.00
0.04
0.01
0.00
520207
520207
520207
520207
510363
510363
6228483
6228483
6228483
6228483
6243820
6243820
477
477
477
477
475
475
6.1
6.1
6.1
6.1
9.1
9.0
0.50
0.50
0.50
0.50
0.50
0.50
45.0
45.0
45.0
45.0
25.0
25.0
773
773
773
773
673
673
0.00
0.00
0.00
0.00
0.00
0.00
0.05
0.05
0.05
0.05
0.01
0.07
0.14
0.14
0.14
0.14
0.00
0.04
0.00
0.00
0.00
0.00
0.00
0.00
510363
510363
510363
6243820
6243820
6243820
475
475
475
9.1
20.0
10.0
0.50
0.25
0.50
25.0
20.0
25.0
673
1237
673
0.00
1.08
0.00
0.00
0.00
0.00
0.00
0.03
0.00
0.00
0.00
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
482577
482577
482577
482577
482577
482577
482577
523589
523601
523597
523593
6171800
6171800
6171800
6171800
6171800
6171800
6171800
6200560
6200560
6200560
6200560
523605
520207
Pike 1 Project
March 2015
Operator
Facility
Chard 10-02-080-06W4M
C.S.
Chard 07-14 C.S.
Clyden C.S. 09-23-07309W4M
Cowpar Sour Gas 11-19080-04W4M G.P.
Canadian
Natural
Resources Ltd.
(cont)
Hardy 10-22-078-05W4M
C.S.
Janvier/Chard 16-01-7906W4M C.S.
Wiau Lake 09-06-07408W4M C.S.
Near Wolf Lake and
Primrose C.S.
Stack
Diameter
(m)
0.50
0.50
0.50
0.50
0.50
0.50
0.50
0.50
Exit
Velocity
(m/s)
23.6
23.7
39.6
39.6
39.6
39.6
25.0
38.8
Exit
Temp
(K)
773
773
773
773
773
773
773
773
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
508
508
508
508
508
508
534
662
Stack
Height
(m)
18.0
10.0
10.0
10.0
10.0
10.0
10.0
10.0
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.09
0.03
0.21
0.21
0.21
0.21
0.06
0.05
0.08
0.08
0.13
0.13
0.13
0.13
0.10
0.12
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6200560
6200560
6200560
6200560
6200560
475
475
475
475
475
10.0
10.0
10.0
10.0
10.0
0.18
0.50
0.50
0.50
0.50
20.0
25.0
25.0
25.0
25.0
1273
673
673
673
673
0.50
0.00
0.00
0.00
0.00
0.46
0.14
0.20
0.00
0.04
0.04
0.00
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
523605
519552
6200560
6181119
475
577
10.0
10.0
0.50
0.50
25.0
6.3
673
773
0.00
0.00
0.00
0.14
0.00
0.02
0.00
0.00
Dehydrator Reboiler
G3306 TA Compressor
Engine
G3306TA Compressor
Engine
G3412TA Compressor
Engine
Heater Reboiler
White 8G825 Compressor
Engine
White 8G825 Compressor
Engine
Compressor
513240
513240
6186152
6186152
538
538
10.0
6.6
0.15
0.13
3.2
35.6
487
809
0.00
0.00
0.00
0.11
0.00
0.00
0.00
0.00
513240
6186152
538
6.6
0.13
35.6
809
0.00
0.11
0.00
0.00
513240
6186152
538
9.5
0.20
42.2
823
0.00
0.24
0.00
0.00
513240
513240
6186152
6186152
538
538
4.9
14.6
0.10
0.25
3.3
43.9
505
977
0.00
0.00
0.00
0.58
0.00
0.00
0.00
0.00
513240
6186152
538
14.6
0.25
43.9
977
0.00
0.58
0.00
0.00
486375
6137409
679
7.6
0.25
31.3
863
0.00
0.00
0.00
0.00
Primrose East– Field
Compressor 1
Primrose – Field
Compressor 4
Primrose – Field
Compressor 5
533900
6070290
674
6.7
0.10
43.0
830
0.00
0.06
0.00
0.00
520802
6074255
661
5.0
0.10
61.6
811
0.00
0.09
0.00
0.00
532609
6078774
701
2.1
0.05
46.3
811
0.00
0.02
0.00
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
Compressor Engine
Waukesha F3521 GL
Waukesha L7042 GSI
Waukesha L7042 GSI
Waukesha L7042 GSI
Waukesha L7042 GSI
Compressor
Compressor Engine
511175
511175
511175
511175
511175
511175
510959
483109
6195915
6195915
6195915
6195915
6195915
6195915
6198486
6132567
Acid Gas Flare Stack
104 KW Generator
150 KW TEG Regenerator
176 KW Amine Reboiler
31 KW pump Exhaust
Stack
492 KW Glycol Heater
Compressor Engine
523609
523589
523601
523597
523593
Emissions Source
Pike 1 Project
March 2015
Operator
Facility
Near Wolf Lake and
Primrose C.S. (cont)
Canadian
Natural
Resources Ltd.
(cont)
Clyde lake 04-35-71-10
W4 C.S.
Grouse East 04-24 C.S.
Clyde 08-22 C.S.
Chard 11-28 C.S.
Chard S Leismer 06-18
C.S.
Thornbury North 11-31
C.S.
Clyden C.S. 09-03
Rio Alto Exploration Ltd. 820 C.S.
Talisman Heart Lake C.S.
Mills 14-06 C.S.
Heart Lake 10-20 C.S.
Hangingstone 12-28-8410w4 C.S.
MILLS 16-06-72-11W4
U#7534 C.S.
Chard 07-14 C.S.
Stack
Diameter
(m)
0.05
Exit
Velocity
(m/s)
46.3
Exit
Temp
(K)
811
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
686
Stack
Height
(m)
3.7
0.00
0.02
0.00
0.00
6079183
700
5.5
0.10
61.6
811
0.00
0.09
0.00
0.00
535461
6079198
703
3.7
0.25
37.9
886
0.00
0.39
0.00
0.00
537899
6080840
693
2.1
0.10
61.6
811
0.00
0.09
0.00
0.00
537899
6080840
693
2.1
0.05
46.3
811
0.00
0.02
0.00
0.00
543202
6080894
703
3.7
0.20
43.1
721
0.00
0.03
0.00
0.00
543202
6080894
703
7.9
0.05
46.3
811
0.00
0.02
0.00
0.00
537047
6085693
722
3.7
0.10
61.6
811
0.00
0.09
0.00
0.00
517081
6086385
694
2.1
0.05
46.3
811
0.00
0.02
0.00
0.00
472023
6115628
673
6.7
0.50
25.0
773
0.00
0.67
1.12
0.00
Compressor
Compressor
Compressor
Compressor
473808
451560
507298
494228
6141515
6161519
6192408
6188757
672
682
509
573
2.1
3.7
2.1
10.0
0.50
0.50
0.50
0.50
25.0
25.0
25.0
25.0
773
773
773
773
0.00
0.00
0.00
0.00
0.30
0.41
0.14
0.23
0.51
0.07
0.24
0.39
0.00
0.00
0.00
0.00
Compressor
455057
6194251
683
10.0
0.50
25.0
773
0.00
0.27
0.45
0.00
Compressor
Compressor
Compressor
Compressor
Compressor
Compressor
Compressor
441832
505480
525427
459293
455961
468679
467033
6166835
6240981
6244291
6093786
6108919
6093710
6241044
682
519
442
646
583
625
626
10.0
10.0
10.0
10.0
10.0
10.0
10.0
0.50
0.50
0.50
0.50
0.50
0.50
0.50
25.0
6.3
47.4
25.0
25.0
25.0
25.0
773
773
773
773
773
773
773
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.08
0.11
0.05
0.06
0.11
0.45
0.14
0.14
0.02
0.15
0.10
0.08
0.76
0.23
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Compressor
456954
6118581
609
10.0
0.50
25.0
773
0.00
0.07
0.12
0.00
Compressor
510959
6198486
534
10.0
0.50
25.0
773
0.00
0.06
0.10
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
Primrose – Field
Compressor 6
Primrose – Field
Compressor 7
Primrose – Field
Compressor 8
Primrose – Field
Compressor 9
Primrose – Field
Compressor 10
Primrose – Field
Compressor 11
Primrose – Field
Compressor 12
Primrose – Field
Compressor 13
Primrose – Field
Compressor 14
Compressor
528122
6079152
533429
Emissions Source
Pike 1 Project
March 2015
Operator
Canadian
Natural
Resources Ltd.
(cont)
Facility
Newby Sour G.P.
9-25 Gathering System
Caribou 05-35 C.S.
Caribou 10-27 C.S.
Caribou 13-15 C.S.
Caribou 16-16 C.S.
Cenovus
Energy
Caribou North 11-08 C.S.
Primrose 10-13 C.S.
Primrose 11-02 C.S.
Primrose 11-12 C.S.
Emissions Source
Wauk. F11GL
Wauk. F11GL
Wauk. F11GL
Wauk. L7042GS
Wauk. L7042GS
Wauk. L7042GS
Wauk. L7042GS
Compressor
Facility - FC 21
Facility - FC 16
Facility - FC 07
Facility - FC 08
Superior 1
Superior 2
Superior 3
Superior 4
Superior 5
Superior 6
Superior 7
Superior 8
Superior 9
Cat 1
Cat 2
Cat 3
Cat 4
Cat 5
Dehydrator 1
Dehydrator 2
Dehydrator 3
Facility - FC 22
Facility - FC 25
Facility - FC 24
UTM E
(m)
UTM N
(m)
Elevation
(masl)
520417
520427
520437
520447
520457
520467
520477
524378
531477
530740
529810
529407
526843
526828
526855
526816
526841
526804
526867
526855
526790
526881
526866
526774
526874
526891
527144
527154
527164
494264
521641
533059
6228335
6228345
6228355
6228365
6228375
6228385
6228395
6085544
6106028
6085442
6102030
6101620
6099985
6099952
6099971
6099943
6099959
6099934
6099979
6099995
6099922
6099989
6100006
6099932
6099915
6099927
6099912
6099912
6099912
6111184
6127425
6129110
478
478
478
478
478
478
478
708
666
706
667
667
676
676
676
676
676
676
676
676
676
676
676
676
676
676
676
676
676
635
691
693
Stack
Height
(m)
6.1
6.1
6.1
9.1
9.1
9.1
9.1
10.0
10.0
6.7
6.8
3.7
7.8
8.8
8.8
8.8
8.8
8.8
8.8
6.9
8.8
6.4
6.4
6.9
8.8
6.4
6.4
6.6
6.4
3.7
3.7
6.7
Stack
Diameter
(m)
0.50
0.50
0.50
0.50
0.50
0.50
0.50
0.50
0.30
0.13
0.13
0.13
0.41
0.41
0.51
0.41
0.41
0.51
0.41
0.31
0.41
0.61
0.61
0.15
0.61
0.61
0.40
0.40
0.40
0.13
0.13
0.25
Exit
Velocity
(m/s)
2.5
2.5
2.5
45.0
45.0
45.0
45.0
25.0
47.1
34.0
35.0
35.0
30.6
30.6
29.6
30.6
30.6
29.6
30.6
10.1
30.6
35.9
35.9
39.7
35.9
35.9
3.6
3.6
3.6
35.0
23.6
31.0
Exit
Temp
(K)
773
773
773
773
773
773
773
773
738
813
811
811
632
632
632
632
632
632
632
632
632
728
728
763
728
728
533
533
533
811
830
886
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.04
0.04
0.04
0.05
0.05
0.05
0.05
0.08
0.12
0.12
0.11
0.11
0.03
0.03
0.05
0.03
0.03
0.05
0.03
0.03
0.03
0.06
0.06
0.21
0.03
0.06
0.00
0.00
0.00
0.11
0.09
0.15
0.01
0.01
0.01
0.14
0.14
0.14
0.14
0.14
0.06
0.06
0.01
0.01
0.13
0.13
0.19
0.13
0.13
0.19
0.13
0.10
0.13
0.20
0.20
0.02
0.11
0.20
0.00
0.00
0.00
0.06
0.06
0.20
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.00
0.01
0.01
0.01
0.00
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
Pike 1 Project
March 2015
Operator
Facility
Primrose North
C.S.12-01
Cenovus
Energy (cont)
Primrose C.S. 05-19
Primrose C.S. 07-08
Caribou 07-31 C.S.
Fisher C.S. 07-25
Fisher C.S. 08-11
Fisher Gas Battery 11-14
C.S.
Kirby C.S. 11-13
Chard 02-04-078-06W4M
C.S.
Chard 11-02-78-07W4
Booster C.S.
Hangingstone 05-13-8411W4M Booster C.S.
Devon Canada
Corp
Kirby North 11-03-76-06
Booster C.S.
Kirby North 13-05-76-06
Booster C.S.
Kirby South 07-02-75-06
Booster C.S.
Booster C.S.
Booster C.S.
Leismer Stn 4 Booster 1117-77-07W4M C.S.
Stack
Diameter
(m)
0.30
0.30
0.41
0.46
0.46
0.46
0.50
0.50
0.13
0.50
0.50
0.50
Exit
Velocity
(m/s)
16.0
16.0
18.6
31.8
31.8
31.8
25.0
25.0
35.0
25.0
25.0
25.0
Exit
Temp
(K)
749
749
649
673
673
673
773
773
811
773
773
773
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
706
706
706
706
706
706
645
690
685
668
729
715
Stack
Height
(m)
7.2
7.2
9.6
12.5
12.5
12.4
10.0
10.0
6.8
10.0
10.0
10.0
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.06
0.06
0.05
0.07
0.07
0.07
0.09
0.06
0.06
0.10
0.09
0.12
1.43
0.00
0.00
0.00
0.00
0.00
0.14
0.09
0.00
0.17
0.16
0.09
0.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6111543
6175417
666
581
10.0
10.0
0.50
0.50
25.0
10.5
773
773
0.00
0.00
0.07
0.23
0.12
0.03
0.00
0.00
501285
6176231
565
10.0
0.50
10.4
773
0.00
0.17
0.03
0.00
Cat G3306TA
Cat G3306TA
Cat G3306TA
Cat G3412
Cat G3412
Waukesha 7042 GSI
Catalytic Converter
Waukesha F7042 GSI
Waukesha F7042 GSI
Cat 3412 Turbo
462278
475691
474109
469198
469198
469198
6237500
6230930
6239435
6236234
6236234
6236234
622
717
677
699
699
699
10.0
10.0
10.0
10.0
10.0
10.0
0.50
0.50
0.50
0.20
0.20
0.31
7.1
7.1
7.1
73.0
73.0
37.4
773
773
773
772
772
862
0.00
0.00
0.00
0.00
0.00
0.00
0.09
0.09
0.09
0.03
0.03
0.05
0.02
0.02
0.02
0.07
0.07
0.12
0.00
0.00
0.00
0.00
0.00
0.00
469198
469198
509457
6236234
6236234
6156810
699
699
589
10.0
6.9
6.9
0.31
0.31
0.50
37.4
37.4
20.1
862
862
773
0.00
0.00
0.00
0.52
0.52
0.32
0.12
0.12
0.06
0.00
0.00
0.00
Waukesha 7042 GSI
505784
6157210
605
11.6
0.50
43.8
773
0.00
0.04
0.14
0.00
Cat 3406 Turbo
511525
6146696
651
11.6
0.50
10.5
773
0.00
0.08
0.03
0.00
Waukesha 3521 GSI
Turbo
Waukesha H24GL
518064
6148339
653
11.6
0.50
19.0
773
0.00
0.26
0.06
0.00
523720
6144328
647
10.0
0.50
17.2
773
0.00
0.03
0.06
0.00
Waukesha L5790GL
496406
6169752
560
10.0
0.50
32.1
773
0.00
0.04
0.10
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
SK500
SK501
SK503
SK700A
SK700B
SK700C
Compressor
Compressor
Facility - FC 18
Compressor
Compressor
Compressor
513069
513069
513069
513069
513069
513069
485780
487697
535480
514170
532737
541336
6127392
6127392
6127392
6127392
6127392
6127392
6102960
6128872
6077178
6104573
6089915
6092234
Compressor
Cat G3406 Turbo
523076
508197
Cat G3406 Turbo
Emissions Source
Pike 1 Project
March 2015
Operator
Leismer Stn 8 Booster 735-77-06W4M C.S.
Waukesha L5790GL
501693
6174206
562
Stack
Height
(m)
10.0
Pony Creek 10-14-08008W4M C.S.
West Surmont 06-09-8208W4M Booster C.S.
Cat G3516TA
Cat G3516TA
Cat G3406TA
491392
491392
497517
6198887
6198887
6216281
642
642
733
10.0
10.0
10.0
0.50
0.50
0.50
34.9
34.9
7.1
773
773
773
0.00
0.00
0.00
0.04
0.04
0.09
0.11
0.11
0.02
0.00
0.00
0.00
Waukesha L7042 GSI
Waukesha L7042 GSI
Waukesha L7042 GSI
Waukesha L7042 GSI
Cat G3306TA
486562
486562
486562
486562
489408
6218730
6218730
6218730
6218730
6221146
720
720
720
720
734
10.0
10.0
10.0
10.0
10.0
0.50
0.50
0.50
0.50
0.50
39.6
39.6
39.6
39.6
7.1
773
773
773
773
773
0.00
0.00
0.00
0.00
0.00
0.30
0.30
0.30
0.30
0.09
0.13
0.13
0.13
0.13
0.02
0.00
0.00
0.00
0.00
0.00
Compressor
Waukesha 9390 GL
turbocharged Natural gas
engine
Waukesha 3521 GL
turbocharged gas
Waukesha 3521 GSI
engine
Waukesha 3521 GSI
engine
Glycol heater
Glycol heater
Utility Boiler
MEP 10 naturally aspirated
10 cylinder natural gas
engines
engines
engines
engines
487543
517659
6235738
6147122
731
648
10.0
11.0
0.50
0.34
7.1
57.5
773
679
0.00
0.00
0.09
0.07
0.02
0.58
0.00
0.00
517659
6147122
648
11.0
0.25
41.1
683
0.00
0.03
0.22
0.00
517659
6147122
648
11.0
0.25
34.5
878
0.00
0.32
0.22
0.00
517659
6147122
648
11.0
0.25
34.5
878
0.00
0.32
0.22
0.00
517659
517659
517659
494777
6147122
6147122
6147122
6167325
648
648
648
572
4.6
4.3
4.6
13.8
0.25
0.15
0.25
0.59
1.1
1.5
4.8
35.8
946
946
946
644
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.60
0.00
0.00
0.00
0.03
0.00
0.00
0.00
0.00
494777
6167325
572
13.8
0.59
35.8
644
0.00
0.60
0.03
0.00
494777
6167325
572
13.8
0.59
35.8
644
0.00
0.60
0.03
0.00
494777
6167325
572
13.8
0.59
35.8
644
0.00
0.60
0.03
0.00
Facility
West Surmont 15-17-08208W4M C.S.
West Surmont 6-27-8208W4M Booster C.S.
Cat 3306TA C.S.
Devon Canada
Corp (cont)
Kirby South 11-04 C.S.
Leismer 03-07 C.S.
Emissions Source
UTM E
(m)
UTM N
(m)
Elevation
(masl)
Stack
Diameter
(m)
0.50
Exit
Velocity
(m/s)
32.1
Exit
Temp
(K)
773
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
0.00
0.04
0.10
0.00
Pike 1 Project
March 2015
Operator
Facility
Leismer 03-07 C.S.
(cont)
Devon Canada
Corp (cont)
Hangingstone Sweet 1110-084-10W4M C.S.
Hangingstone C.S.
E Construction
Ltd
Devon Home Leismer G.P.
EnCana Corp.
Leismer C.S.08-13
Leismer C.S.11-27
Caribou 02-21 C.S.
Caribou 04-05 C.S.
Caribou 06-21 C.S.
Caribou 06-22 C.S.
Caribou 07-17 C.S.
Caribou 07-18 C.S.
Caribou 08-12 C.S.
Caribou 10-08 C.S.
Caribou South 15-01 C.S.
Clyde Lake 08-09 C.S.
Primrose 01-04 C.S.
Primrose 08-16 C.S.
Primrose 09-02 C.S.
Primrose 09-26 C.S.
Stack
Diameter
(m)
0.59
Exit
Velocity
(m/s)
33.5
Exit
Temp
(K)
644
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
572
Stack
Height
(m)
13.8
0.00
0.13
0.03
0.00
6167325
572
13.8
0.59
33.5
644
0.00
0.13
0.03
0.00
494777
494777
494777
494777
475691
6167325
6167325
6167325
6167325
6230930
572
572
572
572
717
6.4
6.4
5.8
5.8
10.0
0.38
0.38
0.26
0.26
0.50
32.8
32.8
8.1
8.1
7.1
728
728
728
728
773
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.00
0.00
0.09
0.00
0.00
0.00
0.00
0.02
0.00
0.00
0.00
0.00
0.00
Caterpillar G3306TA
474109
6239435
677
10.0
0.50
7.1
773
0.00
0.09
0.02
0.00
Cat G3412
Cat G3412
Waukesha 7042 GSl
Catalytic Converter
Waukesha F7042 GSI
Waukesha F7042 GSI
Comp.
Compressor
469198
469198
489198
6236234
6236234
6236234
699
699
727
6.9
6.9
11.6
0.20
0.20
0.31
73.0
73.0
37.4
772
772
862
0.00
0.00
0.00
0.03
0.03
0.05
0.07
0.07
0.12
0.00
0.00
0.00
469198
469198
497530
499254
6236234
6236234
6216275
6170967
699
699
733
563
11.6
11.6
10.0
6.4
0.31
0.31
0.50
0.50
37.4
37.4
25.0
25.0
882
862
773
773
0.00
0.00
0.00
0.00
0.52
0.52
0.58
0.12
0.12
0.12
0.45
0.28
0.00
0.00
0.00
0.00
Compressor
Compressor
Facility - FC 19
Facility - FC 06
Facility - FC 09
Facility - FC 20
Facility - FC 15
Facility - FC 01
Facility - FC 17
Facility - FC 14
Caribou South Gas Plant
Facility - FC 12 and 13
Facility - FC 10
Facility - FC 23
Facility - FC 11
Facility - FC 05
483700
479500
529057
526640
518875
530280
537371
516056
524636
537381
524250
479940
509428
519220
502641
493623
6188700
6192500
6102373
6097505
6102718
6102781
6081780
6091357
6089793
6080578
6089020
6118916
6107140
6120525
6117758
6094982
641
681
667
682
677
667
718
700
695
695
694
673
642
683
659
666
10.0
10.0
10.0
10.0
5.6
7.0
10.0
6.8
6.8
5.6
12.2
6.9
6.8
6.7
8.3
7.0
0.50
0.50
0.13
0.25
0.13
0.13
0.13
0.25
0.13
0.13
1.52
0.30
0.13
0.25
0.36
0.25
25.0
25.0
34.0
31.0
35.0
34.0
34.0
31.0
35.0
34.0
32.3
21.5
35.0
31.0
37.0
31.0
673
673
813
886
811
813
813
886
811
813
733
886
811
886
649
886
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.10
0.07
0.24
0.15
0.11
0.12
0.24
0.15
0.11
0.12
0.66
0.19
0.22
0.15
0.05
0.15
0.06
0.32
0.12
0.18
0.10
0.06
0.12
0.20
0.06
0.06
1.45
0.21
0.11
0.20
0.06
0.18
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.07
0.00
0.00
0.00
0.00
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
engines
engines
Heat Medium boilers
Heat Medium boilers
Glycol Reboiler
Glycol Reboiler
Caterpillar G3306TA
494777
6167325
494777
Emissions Source
Pike 1 Project
March 2015
Operator
Facility
Emissions Source
Primrose North C.S.12-01
Caribou 05-20 C.S.
EnCana Corp.
(cont)
Harvest
Operations
Corp.
Husky Energy
Inc.
Imperial Oil
Resources Ltd.
Iteration Energy
Ltd.
MEG Energy
Corp.
Northstar
Energy
Corporation
Paramount
Energy
Operating Corp.
SK 900
Facility - FC 02
Cat G3306 ATTAC
Cat G3306 ATTAC
Caribou 06-32 G.P.
Cat G3306 ATTAC
Cat G3306 ATTAC
Cat 6
Caribou North 11-08 G.P.
Cat 7
Caribou 06-15 C.S.
Compressor
Moore 08-13 C.S.
Compressor
Primrose North C.S.12-01 Glycol Dehy
Tweedie G.P.
Comp.
Picne G.P.
Comp.
Primrose North C.S.12-01 Utility Glycol Heater
Caribou Gas Battery 05-16 Compressor
C.S.
Wappau10-3-74-12W4M Compressor
C.S.
C.S. Thornbury North 14- Compressor Engine
09-082-12W4M
Kirby 02-30-074-08W4M Compressor Engine
C.S.
Devenish C.S.
Compressor
Cat G3306 TA
Cat G3306 TA
Winefred South 08-04-077- Cat G3306 TA
05W4 C.S.
Waukesha L7042 GSI
Waukesha L7042 GSI
Waukesha L7042 GSI
Compressor Engine
C.S. 10-14- 080-08W4M
C.S. 15-17- 082-08W4M
C.S.
C.S.
Chard C.S.14-32-7905W4M
Compressor Engine
Compressor Engine
Compressor Engine
Compressor Engine
Stack
Diameter
(m)
0.40
0.13
0.13
0.13
0.13
0.13
0.61
0.61
0.50
0.50
0.41
0.50
0.50
0.56
0.50
Exit
Velocity
(m/s)
11.9
23.6
35.0
35.0
35.0
35.0
35.9
35.9
25.0
25.0
4.0
25.0
25.0
0.8
25.0
Exit
Temp
(K)
668
830
811
811
811
811
728
728
773
773
811
773
773
699
773
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
706
694
681
681
681
681
676
676
667
716
706
592
588
706
663
Stack
Height
(m)
7.2
3.7
6.8
6.8
6.8
6.8
6.4
6.4
10.0
10.0
5.9
10.0
10.0
5.8
10.0
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.03
0.07
0.11
0.11
0.11
0.11
0.04
0.04
0.03
0.12
0.00
0.18
0.19
0.01
0.13
0.00
0.00
0.02
0.02
0.02
0.02
0.07
0.07
0.06
0.17
0.00
0.11
0.32
0.00
0.08
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6137651
656
10.0
0.30
20.0
773
0.00
0.40
0.11
0.00
448802
6217386
737
10.0
0.50
37.9
773
0.00
0.06
0.12
0.00
485989
6143073
660
10.0
0.50
17.0
773
0.00
0.12
0.11
0.00
485988
518602
518602
518602
518602
518602
518602
491392
6143072
6165939
6165939
6165939
6165939
6165939
6165939
6198887
660
567
567
567
567
567
567
642
10.0
3.4
3.4
3.4
22.9
22.9
15.3
10.0
0.50
0.10
0.10
0.10
0.30
0.30
0.30
0.50
25.0
46.5
46.5
46.5
46.1
46.1
43.2
37.9
773
839
839
839
880
880
874
773
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.12
0.05
0.05
0.05
0.64
0.64
0.53
0.17
0.11
0.00
0.00
0.00
0.05
0.05
0.04
0.12
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
486562
487543
486562
515664
6218730
6235738
6218730
6194251
720
731
720
462
10.0
10.0
10.0
10.0
0.50
0.50
0.50
0.50
37.9
6.3
37.9
25.0
773
773
773
673
0.00
0.00
0.00
0.00
0.16
0.11
0.24
0.07
0.12
0.02
0.12
0.01
0.00
0.00
0.00
0.00
UTM E
(m)
UTM N
(m)
Elevation
(masl)
513069
516810
526798
526798
526798
526798
526976
526976
530027
534243
513069
442801
456102
513069
517759
6127392
6093232
6096546
6096546
6096546
6096546
6100136
6100136
6101436
6082236
6127392
6101690
6108361
6127392
6111115
451854
Pike 1 Project
March 2015
Operator
Facility
Compressor Engine
Compressor Engine
Compressor Engine
Compressor Engine
Compressor Engine
Compressor Engine
Kettle C.S.15-2-81-06W4M Compressor Engine
Compressor Engine
Generator Engine
Generator Engine
Compressor Engine
Compressor Engine
Leismer C.S.06-23-79Compressor Engine
10W4M
Compressor Engine
Generator Engine
Quigley C.S.07-02-083Compressor Engine
06W4M
C.S.
Comp.
C.S.
Comp.
C.S.
Comp.
C.S.
Comp.
Corner C.S.14-4-8109W4M
Paramount
Energy
Operating Corp.
(cont)
Emissions Source
Stack
Height
(m)
10.0
10.0
15.4
8.0
8.0
8.0
8.0
8.0
8.0
8.0
10.0
10.0
10.0
10.0
10.0
12.4
Stack
Diameter
(m)
0.50
0.50
0.44
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.50
0.50
0.50
0.50
0.50
0.43
Exit
Velocity
(m/s)
61.7
25.0
31.3
26.8
26.8
26.8
26.8
26.8
26.8
26.8
47.5
34.9
51.4
25.0
25.0
27.6
Exit
Temp
(K)
773
673
683
672
672
672
672
672
672
672
773
773
773
773
773
683
UTM E
(m)
UTM N
(m)
Elevation
(masl)
477974
477850
477850
511146
511146
511146
511146
511146
511146
511146
471359
477480
477480
477480
477480
510225
6205816
6205850
6205850
6205572
6205572
6205572
6205572
6205572
6205572
6205572
6190475
6189226
6189226
6189226
6189226
6224400
698
698
698
508
508
508
508
508
508
508
666
669
669
669
669
530
467424
470268
472762
473593
6210328
697
10.0
0.50
10.4
773
6209906
703
10.0
0.50
7.1
773
6218386
703
10.0
0.50
12.8
773
6221618
713
10.0
0.50
12.8
773
SO2
(t/d)
NOx
(t/d)
CO
(t/d)
PM2.5
(t/d)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.37
0.01
0.20
0.14
0.10
0.14
0.14
0.09
0.01
0.01
0.06
0.35
0.20
0.03
0.03
0.26
0.20
0.00
0.18
0.03
0.02
0.03
0.03
0.02
0.00
0.00
0.15
0.11
0.16
0.03
0.03
0.03
0.00
0.00
0.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.98
0.15
0.12
0.19
0.19
55.7
0.03
0.02
0.04
0.04
26.3
0.00
0.00
0.00
0.00
0.40
Pike 1 Project
March 2015
5.0
COMMUNITIES AND HIGHWAYS
The emissions from communities and highways located within the AQRSA are included in each
of the emission scenarios. Table C2-4 presents a summary of the emission data.
Table C2-4: Community and Highway Emissions
Included in the Baseline and Application Scenarios
SO2
(t/d)
NOX
(t/d)
CO
(t/d)
PM2.5
(t/d)
Anzac
0.004
0.036
0.170
0.030
Janvier/Chard
0.004
0.028
0.135
0.024
HWY 63a
0.022
0.723
4.713
0.236
HWY 63b
0.001
0.057
0.377
0.017
HWY 881
0.022
0.378
1.637
0.172
0.054
1.221
7.032
0.479
Source
Total
Attachment D
Amended Noise Assessment
Pike 1 Project
March 2015
ATTACHMENT D: AMENDED NOISE ASSESSMENT
TABLE OF CONTENTS
PAGE
1.0
INTRODUCTION ............................................................................................................... 1
2.0
DESCRIPTION .................................................................................................................. 1
3.0
MEASUREMENT AND MODELING METHODS .............................................................. 3
3.1
Baseline Noise Monitoring ..................................................................................... 3
3.2
Sound Level Measurements .................................................................................. 3
3.3
General Modeling Parameters............................................................................... 4
3.4
Noise Sources ....................................................................................................... 5
3.5
Modeling Confidence ............................................................................................. 6
4.0
PERMISSIBLE SOUND LEVELS ..................................................................................... 6
5.0
RESULTS AND DISCUSSION ......................................................................................... 7
5.1
Baseline Case Results .......................................................................................... 7
5.2
Application Case Results ...................................................................................... 7
5.3
Cumulative Case Results .................................................................................... 12
5.4
Noise Mitigation Measures .................................................................................. 12
5.4.1
Specific Noise Mitigation ..................................................................... 12
5.4.2
General Noise Mitigation ..................................................................... 15
5.4.3
Construction Noise .............................................................................. 16
6.0
CONCLUSION ................................................................................................................ 16
7.0
REFERENCES ................................................................................................................ 17
Attachment D – Table of Contents
Pike 1 Project
March 2015
TABLE OF CONTENTS (cont)
PAGE
LIST OF TABLES
Table D-1:
Table D-2:
Table D-3:
Table D-4:
Basic Night-Time Sound Levels (as per AER Directive 038) ............................ 6
Baseline Case Modeled Night-Time Sound Levels .......................................... 8
Application Case Modeled Night-Time Sound Levels..................................... 10
Cumulative Case Modeled Night-Time Sound Levels .................................... 13
LIST OF FIGURES
Figure D-1:
Figure D-2:
Figure D-3:
Figure D-4:
Study Area ........................................................................................................ 2
Baseline Case Noise Modeling LeqNight (without ASL) .................................... 9
Application Case Noise Modeling LeqNight (without ASL) .............................. 11
Cumulative Case Noise Modeling LeqNight (without ASL) .............................. 14
LIST OF ATTACHMENTS
Attachment D1:
Attachment D2:
Attachment D3:
Attachment D4:
Attachment D5:
Attachment D6:
The Assessment of Environmental Noise (General)
Sound Levels of Familiar Noise Sources
Noise Modeling Parameters
Permissible Sound Level Determination
Cumulative Case Noise Source Order-Ranking
Noise Impact Assessment
Attachment D – Table of Contents
Pike 1 Project
March 2015
1.0
INTRODUCTION
aci Acoustical Consultants Inc., of Edmonton AB, was retained by Devon NEC Corporation
(Devon) to conduct a noise impact assessment for the proposed Pike 1 Project Amendment
Application (the Amended Project) in northeast Alberta. The purpose of the work was to update
a previously generated computer noise model (generated for the 2013 Pike 1 Project
Application) with the amended facility layout and equipment design and determining the
Baseline, Application, and Cumulative Case conditions. The noise levels were compared to the
applicable noise criteria as specified by the Alberta Energy Regulator (AER) Directive 038:
Noise Control.
2.0
DESCRIPTION
Devon is proposing to construct and operate the Amended Project which will produce 70 000
bitumen barrels per day (bbl/d). The Amended Project will include a central processing facility
(CPF) with two Phases (Phase 1a and Phase 1b) as well as 52 well pads located throughout the
study area. The Amended Project is located approximately 25 km southeast of Conklin, Alberta,
as indicated in Figure D-1. The Amended Project spans Townships 73 to 75 and Ranges 4 to 7
west of the fourth meridian, with the CPF located in NW 26, NE 27, SE 34, SW 35 Township 77,
Range 6, west of the fourth meridian. The noise local study area (LSA) includes all areas within
1 500 m of the Amended Project noise sources. The well pads will be dispersed throughout the
noise LSA. The regional study area (RSA) includes all areas within the LSA as well as the
existing and approved Jackfish project facilities and the Jackfish Storage Tank Facility (STF) to
the north. Devon currently operates the Jackfish project, which combines the former Jackfish 1,
2 and 3 projects under an amending EPEA approval issued in November 2011. For purposes of
clarity, map figures distinguish between the Jackfish 1, 2 and 3 CPFs.
Relative to the Amended Project, the closest noise source associated with the Jackfish project
is approximately 5 km from the nearest Amended Project well pad. As such, the relative
contribution from the Jackfish project on the noise environment at the 1 500 m AER
Directive 038 boundary is relatively minor. Regardless, the Jackfish project components are
included in the NIA for Baseline Case and Cumulative Case noise sources for completeness
and increased accuracy of the noise modeling results. No other significant noise sources are
close enough to have a significant impact on the noise climate at the Amended Project’s
1 500 m AER Directive 038 boundary.
Secondary Highway 881 is the nearest major roadway, located approximately 10 km west of the
western-most Amended Project well pad. As such, it is too far from the Amended Project to be
of concern for noise.
The community of Conklin is located approximately 25 km northwest of the Amended Project.
The community is well outside the noise assessment LSA. Given the large distance between the
Amended Project and Conklin, the existing sound environment at Conklin will remain
unchanged due to the Amended Project.
Attachment D – Page 1
Pike 1 Project
March 2015
Figure D-1: Study Area
Pike 1 Project
March 2015
Kirby Lake and Hay Lake are located approximately 3 km and 5 km northeast of the Amended
Project, respectively. Both locations are outside the noise assessment LSA and have not been
included in the study.
There are no residential receptors, as defined within the AER Directive 038, within 1 500 m of
the Amended Project. Hence, it is the noise levels at a distance of 1 500 m that will determine
compliance relative to the AER Directive 038. There is a trapper’s cabin located within 1 500 m
of the Amended Project, which is in use for approximately two weeks per year. Although the
trapper’s cabin does not meet the minimum occupancy criteria of six weeks per year to be
classified as a seasonably occupied dwelling (AER Directive 038), it has been included in the
noise assessment and noise mitigation discussions.
Topographically the land in the area has varying elevation and includes lakes and other small
bodies of water. There is an elevation change of approximately 76 m within a 1 500 m radius of
the Amended Project. Digital topographical information was provided by the client for use in the
noise model. Vegetation within the area is composed mainly of dense, tall trees and dense
brush and grasses (based on site observations). As a result, given the large size of the study
area, the quantity of vegetative sound absorption is considered significant.
3.0
MEASUREMENT AND MODELING METHODS
3.1
Baseline Noise Monitoring
There are no existing industrial noise sources within 5 km of the Amended Project noise
sources and no permanent residences within 1 500 m of the Amended Project. As such,
Baseline noise monitoring was not conducted. This conforms with the requirements of the AER
Directive 038.
3.2
Sound Level Measurements
As part of the original noise study, short term sound level measurements were conducted at the
Jackfish 1 CPF and associated well pads in August 2011. The sound level measurements were
conducted at measured distances from typical noise sources at the CPF and various well pads
as well as at the CPF fence-line. The sound level measurements were conducted for at least
30-second Leq sample durations obtaining both the broadband A-weighted and 1/3 octave band
sound levels. Data from the sound level measurements was then used to determine the sound
power levels of some of the noise sources for use in the computer noise model. The data was
also used as a calibration/verification of the noise modeling results. Refer to Attachment D1 for
a description of the acoustical terminology and Attachment D2 for a list of common noise
sources. All sound level measurement instrumentation was calibrated prior to and after
conducting the sound level measurements.
Pike 1 Project
March 2015
3.3
General Modeling Parameters
The computer noise modeling was conducted using the CADNA/A (version 4.4.145) software
package. CADNA/A allows for the modeling of various noise sources such as road, rail, and
various stationary sources. In addition, topographical features such as land contours,
vegetation, and bodies of water can be included. Finally, meteorological conditions such as
temperature, relative humidity, wind-speed and wind-direction can be included in the
calculations. Note that all modeling methods used exceed the requirements of the AER
Directive 038.
The calculation method used for noise propagation follows the ISO Standard 9613-2. All
receiver locations were assumed as being downwind from the source(s). In particular, as stated
in Section 5 of the ISO document:
“Downwind propagation conditions for the method specified in this part of IS0
9613 are as specified in 5.4.3.3 of IS0 1996-2:1987, namely
- wind direction within an angle of ± 450 of the direction connecting the centre
of the dominant sound source and the centre of the specified receiver region,
with the wind blowing from source to receiver, and
- wind speed between approximately 1 m/s and 5 m/s, measured at a height of
3 m to 11 m above the ground.
The equations for calculating the average downwind sound pressure level
LAT(DW) in this part of IS0 9613, including the equations for attenuation given in
clause 7, are the average for meteorological conditions within these limits. The
term average here means the average over a short time interval, as defined in
3.1.
These equations also hold, equivalently, for average propagation under a welldeveloped moderate ground-based temperature inversion, such as commonly
occurs on clear, calm nights”.
Due to the significant amount of vegetation, vegetative sound absorption was included in the
noise model in the form of a ground sound absorption coefficient of 0.5. As a result, all sound
level propagation calculations are considered representative of summertime conditions for the
trapper's cabin and all surrounding theoretical 1 500 m receptors.
As part of the study, three modeling scenarios were conducted, including:
1)
Baseline Case: this included all noise sources, buildings, and tanks associated with the
adjacent Jackfish Project.
2)
Application Case: this included all noise sources, buildings, and tanks associated with
the Amended Project alone, without the Baseline Case noise sources, buildings, and
tanks.
3)
Cumulative Case: this included all noise sources, buildings, and tanks associated with
the Baseline and Application Cases.
Pike 1 Project
March 2015
The computer noise modeling results were calculated in two ways. First, sound levels were
calculated at specific receiver locations (i.e., trapper's cabin and theoretical 1 500 m receptors).
Next, the sound levels were calculated using a 50 m x 50 m grid over the entire study area. This
provided color noise contours for easier visualization of the results.
3.4
Noise Sources
The noise data for the Jackfish noise sources was based on a combination of equipmentspecific sound level measurements conducted during the site visit in August 2011 and from data
obtained from equipment-specific information as well as from assessments carried out for other
projects using similar operating equipment combined with aci in-house information and
calculations using methods presented in various texts. Similarly, the noise levels for equipment
associated with the Amended Project were obtained from equipment-specific information as well
as from assessments carried out for other projects using similar operating equipment combined
with aci in-house information and calculations using methods presented in various texts. All
sound power levels (PWLs) used in the modeling are considered conservative. The data are
provided in Attachment D3.
It is important to highlight that the Amended Project is planned for construction in two phases:
Phase 1a and Phase 1b. Initial production will start with four well pads. Additional well pads will
come online every one to two years thereafter. Depleted well pads will be decommissioned as
the Amended Project progresses. It is anticipated that a maximum of 17 well pads will be in
operation at any given time. However, to ensure a conservative approach to assessing the
Amended Project’s noise effects, both CPF Phases 1a and 1b and all well pads (52) were
modeled as operational at the same time.
All noise sources have been modeled as point sources at their appropriate heights1. Sound
power levels for all stationary noise sources were modeled using octave-band information.
Buildings and tanks were included in the modeling calculations because of their ability to
provide shielding as well as reflection for noise2. Refer to Attachment D3 for building and tank
dimensions.
Finally, the AER Directive 038 requires the assessment to include background ambient noise
levels in the model. As specified in the AER Directive 038, in most rural areas of Alberta where
there is an absence of industrial noise sources the average night-time ambient noise level is
approximately 35 dBA. This is known as the average ambient sound level (ASL-Night). This
value was used as the ambient condition in the modeling with the various Jackfish and
Amended Project related noise sources added.
1
The heights for many of the sources are generally slightly higher than actual. This makes the model more conservative.
2
Exterior building and tank walls were modeled with an absorption coefficient of 0.21 which is generally highly reflective.
Pike 1 Project
March 2015
3.5
Modeling Confidence
As previously mentioned, the algorithms used for the noise modeling follow the ISO 9613
Standard. The published accuracy for this Standard is ±3 dBA between 100 m to 1 000 m.
Accuracy levels beyond 1 000 m are not published. Experience based on similar noise models
conducted over large distances shows that, as expected, as the distance increases, the
associated accuracy in prediction decreases. Experience has shown that environmental factors
such as wind, temperature inversions, topography and ground cover all have increasing effects
over distances larger than approximately 1 500 m.
4.0
PERMISSIBLE SOUND LEVELS
Environmental noise levels from various sources (industrial, roads, railways, etc.) are commonly
described in terms of equivalent sound levels or Leq. This is the level of a steady sound having
the same acoustic energy, over a given time period, as the fluctuating sound. In addition, this
energy averaged level is A–weighted to account for the reduced sensitivity of average human
hearing to low frequency sounds. These Leq in dBA, which are the most common environmental
noise measure, are often given for day-time (07:00 to 22:00) LeqDay and night-time (22:00 to
07:00) LeqNight while other criteria use the entire 24-hour period as Leq24.
The document directly applicable to the Permissible Sound Levels (PSLs) for this study is the
AER Directive 038 (2007). This document sets the PSL at the receiver location based on
population density and relative distances to heavily traveled road and rail as shown in
Table D-1. There are no permanent residential receptors within 1 500 m of the Amended
Project. However, for information purposes, the trapper's cabin has been included in the
assessment. The trapper's cabin has a population density of less than 9 per quarter section of
land and is located more than 500 m from a heavily traveled road. As such, the PSLs are an
LeqNight of 40 dBA and an LeqDay of 50 dBA. In addition, AER Directive 038 specifies that
new or modified facilities must meet a PSL-Night of 40 dBA at 1 500 m from the facility fenceline if there are no closer dwellings. As such, the PSLs at a distance of 1 500 m are an LeqNight
of 40 dBA and an LeqDay of 50 dBA. Refer to Attachment D4 for a detailed determination of
the permissible sound levels.
Table D-1: Basic Night-Time Sound Levels (as per AER Directive 038)
Proximity to Transportation
Dwelling Density per Quarter Section of Land
1-8 Dwellings
9-160 Dwellings
>160 Dwellings
Category 1
40 dBA
43 dBA
46 dBA
Category 2
45 dBA
48 dBA
51 dBA
Category 3
50 dBA
53 dBA
56 dBA
Notes:
Category 1: Dwelling units more than 500 m from heavily travelled roads and/or rail lines and not subject
to frequent aircraft flyovers.
Category 2: Dwelling units more than 30 m but less than 500 m from heavily travelled roads and/or rail
lines and not subject to frequent aircraft flyovers.
Category 3: Dwelling units less than 30 m from heavily travelled roads and/or rail lines and not subject to
frequent aircraft flyovers.
Pike 1 Project
March 2015
The PSLs provided are related to noise associated with activities and processes at the
Amended Project and are not related to vehicle traffic on nearby highways (or access roads).
This includes all traffic related to the construction and operation of the Amended Project. Noises
from traffic sources are not covered by any regulations or guidelines at the municipal, provincial,
or federal levels. As such, an assessment of the noises related to vehicle traffic was not
conducted. In addition, construction noise is not specifically regulated by the AER Directive 038.
However, construction noise mitigation recommendations are provided in Section 5.4.3.
5.0
RESULTS AND DISCUSSION
5.1
Baseline Case Results
The results of the Baseline Case noise modeling are presented in Table D-2 and illustrated in
Figure D-2. The Baseline Case noise sources operate 24/7, so only the night-time results are
displayed. The noise levels associated with the Baseline Case noise sources in addition to the
ASLs are projected to be below the PSLs for the trapper's cabin and the theoretical 1 500 m
receptor locations. In addition to the broadband A-weighted (dBA) sound levels, the modeling
results at the trapper's cabin and the theoretical 1 500 m receptor locations indicated
C-weighted (dBC) sound levels will be less than 20 dB above the dBA sound levels, as shown in
Table D-2. As specified in AER Directive 038, if the dBC – dBA sound levels are less than
20 dB, the noise is not considered to have a low frequency tonal component.
5.2
Application Case Results
The results of the Application Case noise modeling are presented in Table D-3 and illustrated in
Figure D-3. The Application Case noise sources operate 24/7, so only the night-time results are
displayed. The noise levels associated with the Application Case noise sources in addition to
the ASLs are projected to be below the PSLs for the trapper's cabin and the theoretical 1 500 m
20 dB, the noise is not considered to have a low frequency tonal component.
It is important to note that the results provided in Table D-3 and Figure D-3 include noise
mitigation at the well pad nearest to the trapper's cabin (730 m to the west). Without the noise
mitigation at the nearest well pad, the modeled noise levels at the trapper's cabin are 39.8 dBA
+ 35 dBA (ASL) = 41.1 dBA which exceeds the PSL of 40 dBA. The details of the noise
mitigation are provided in Section 5.4.1.
Pike 1 Project
March 2015
Table D-2: Baseline Case Modeled Night-Time Sound Levels
ASLNight
(dBA)
Baseline
Case
LeqNight
(dBA)
Trappers cabin
(730 m from
Amended Project)
35.0
0.0
R-001
R-002
R-003
R-004
R-005
R-006
R-007
R-008
R-009
R-010
R-011
R-012
R-013
R-014
R-015
R-016
R-017
R-018
R-019
R-020
R-021
R-022
R-023
R-024
R-025
R-026
R-027
R-028
R-029
R-030
R-031
R-032
R-033
R-034
R-035
R-036
R-037
R-038
R-039
R-040
R-041
R-042
R-043
R-044
R-045
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
15.4
12.5
8.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
9.6
0.6
0.0
0.0
0.0
10.4
14.1
17.9
23.1
22.5
24.5
24.5
22.5
21.1
16.8
14.3
15.5
16.0
17.0
17.9
18.6
Receptor
ASL +
PSLBaseline Case
Night
LeqNight
(dBA)
(dBA)
Residential Receptors
35.0
Compliant
Baseline
Case
LeqNight
(dBC)
Yes
0.0
0.0
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
32.8
30.9
27.7
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
29.1
20.0
0.0
0.0
0.0
30.0
32.8
35.3
39.6
39.4
40.8
40.6
38.8
38.9
34.4
33.1
34.6
35.1
35.4
35.3
38.5
17.4
18.4
19.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
19.5
19.4
0.0
0.0
0.0
19.6
18.7
17.4
16.5
16.9
16.3
16.1
16.3
17.8
17.6
18.8
19.1
19.1
18.4
17.4
19.9
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
40.0
Theoretical 1 500 m Receptors
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.0
40.0
35.1
40.0
35.3
40.0
35.2
40.0
35.4
40.0
35.4
40.0
35.2
40.0
35.2
40.0
35.1
40.0
35.0
40.0
35.0
40.0
35.1
40.0
35.1
40.0
35.1
40.0
35.1
40.0
dBC –
dBA
Tonal
Pike 1 Project
March 2015
Jackfish Well
Pads (Typical)
STF
Jackfish 1 CPF
Jackfish 3 CPF
R-001
Jackfish 2 CPF
R-045
R-040
Pike 1 CPF
Location
R-035
R-005
1 500 m Boundary
R-030
R-010
trapper's
cabin
R-025
R-020
R-015
Figure D-2: Baseline Case Noise Modeling LeqNight (without ASL)
Pike 1 Project
March 2015
Table D-3: Application Case Modeled Night-Time Sound Levels
ASLNight
(dBA)
Application
Case
LeqNight
(dBA)
Trappers cabin
(730 m from
Amended Project)
35.0
37.6
R-001
R-002
R-003
R-004
R-005
R-006
R-007
R-008
R-009
R-010
R-011
R-012
R-013
R-014
R-015
R-016
R-017
R-018
R-019
R-020
R-021
R-022
R-023
R-024
R-025
R-026
R-027
R-028
R-029
R-030
R-031
R-032
R-033
R-034
R-035
R-036
R-037
R-038
R-039
R-040
R-041
R-042
R-043
R-044
R-045
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
29.6
30.3
33.5
29.5
29.3
27.0
29.1
26.5
28.8
30.0
31.2
31.7
26.4
29.6
28.9
25.9
26.3
29.9
34.5
35.0
29.4
27.2
28.8
29.8
32.2
29.6
26.1
25.1
25.2
26.9
33.5
28.0
27.5
30.2
27.4
27.7
28.9
29.8
33.7
30.5
36.4
33.0
33.6
30.1
28.8
Receptor
ASL +
PSLApplication
Night
Case LeqNight
(dBA)
(dBA)
39.5
Compliant
Application
Case
LeqNight
(dBC)
dBC –
dBA
Tonal
Yes
46.8
9.2
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
44.5
44.8
45.6
40.6
40.0
38.1
38.8
36.7
38.5
41.5
40.2
41.4
39.6
39.8
39.1
36.9
38.1
41.2
45.7
46.1
42.7
39.3
41.4
41.4
44.0
41.5
37.2
35.9
39.0
36.6
42.9
37.4
40.3
42.4
38.3
39.4
40.3
41.9
46.4
44.8
52.4
46.2
46.0
42.4
40.8
14.9
14.5
12.1
11.1
10.7
11.1
9.7
10.2
9.7
11.5
9.0
9.7
13.2
10.2
10.2
11.0
11.8
11.3
11.2
11.1
13.3
12.1
12.6
11.6
11.8
11.9
11.1
10.8
13.8
9.7
9.4
9.4
12.8
12.2
10.9
11.7
11.4
12.1
12.7
14.3
16.0
13.2
12.4
12.3
12.0
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
40.0
36.1
40.0
36.3
40.0
37.3
40.0
36.1
40.0
36.0
40.0
35.6
40.0
36.0
40.0
35.6
40.0
35.9
40.0
36.2
40.0
36.5
40.0
36.7
40.0
35.6
40.0
36.1
40.0
36.0
40.0
35.5
40.0
35.5
40.0
36.2
40.0
37.8
40.0
38.0
40.0
36.1
40.0
35.7
40.0
35.9
40.0
36.1
40.0
36.8
40.0
36.1
40.0
35.5
40.0
35.4
40.0
35.4
40.0
35.6
40.0
37.3
40.0
35.8
40.0
35.7
40.0
36.2
40.0
35.7
40.0
35.7
40.0
36.0
40.0
36.1
40.0
37.4
40.0
36.3
40.0
38.8
40.0
37.1
40.0
37.4
40.0
36.2
40.0
35.9
40.0
Pike 1 Project
March 2015
Jackfish Well
Pads (Typical)
STF
Jackfish 1 CPF
Jackfish 3 CPF
R-001
R-045
Jackfish 2 CPF
R-040
R-035
Pike 1 CPF
Location
R-005
1 500 m Boundary
R-030
R-010
trapper's
cabin
R-025
R-020
R-015
Figure D-3: Application Case Noise Modeling LeqNight (without ASL)
Pike 1 Project
March 2015
5.3
Cumulative Case Results
The results of the Cumulative Case noise modeling are presented in Table D-4 and illustrated in
Figure D-4. The Cumulative Case noise sources operate 24/7, so only the night-time results are
displayed. The noise levels associated with the Cumulative Case noise sources in addition to
the ASLs are projected to be below the PSLs for the trapper's cabin and the theoretical 1 500 m
20 dB, the noise is not considered to have a low frequency tonal component. The order ranked
noise source contributions for the trapper's cabin and the theoretical 1 500 m receptor with the
highest modeled noise levels (R-041) are provided in Attachment D5.
As with the Application Case, the results for the Cumulative Case, provided in Table D-4 and
Figure D-4, include noise mitigation at the well pad nearest to the trapper's cabin. Without the
noise mitigation, the modeled noise levels at the trapper's cabin are 39.8 dBA + 35 dBA (ASL) =
41.1 dBA which exceeds the PSL of 40 dBA. The details of the noise mitigation are provided in
Section 5.4.1.
5.4
Noise Mitigation Measures
5.4.1
Specific Noise Mitigation
The results of the Application Case and Cumulative Case noise modeling indicated that no
additional noise mitigation is required for the Amended Project to meet the AER Directive 038
PSLs at all of the theoretical 1 500 m receptor locations. However, noise mitigation is required in
order to achieve noise levels that are below the PSL-Night of 40 dBA at the trapper's cabin. The
noise model results were used to determine that the dominant Amended Project noise source at
the trapper's cabin is the nearest well pad (approximately 730 m to the west).
Based on the sound level measurements conducted at the existing similar Jackfish well pads,
the dominant noise sources on the well pad sites are the air compressor and three large pumps
located within adjacent buildings. During the summer months, the building doors are left open
for ventilation. In the direction of the doors, the noise levels are much louder than they are on
the other side of the buildings (i.e., opposite the open doors). There is at least a 10 dBA
reduction on the side of the buildings opposite the open doors. All of the Amended Project well
pads were modeled with the loudest sound level (i.e., assuming the noise levels directly on-axis
with the open doors) in all directions because the orientation of any specific Amended Project
well pad is yet to be determined. Based on the location of the well pad nearest to the trapper's
cabin, the noise mitigation recommendation is to orient the well pad such that the open doors
point in the opposite direction relative to the cabin (i.e., point the open doors to the west). This
will likely yield at least a 10 dBA reduction in noise from this specific well pad at the trapper’s
cabin while not resulting in higher noise levels at any of the theoretical 1 500 m receptor
locations. In an effort to be conservative, only a 5 dBA reduction was applied to this specific well
pad for the condition that has been modeled in the Application Case and Cumulative Case.
Based on the site observations and sound level measurements conducted for the existing
Jackfish well pads, this level of noise mitigation is readily achievable.
Pike 1 Project
March 2015
Table D-4: Cumulative Case Modeled Night-Time Sound Levels
ASLNight
(dBA)
Cumulative
Case
LeqNight
(dBA)
Trappers cabin
(730m from
Amended Project)
35.0
37.6
R-001
R-002
R-003
R-004
R-005
R-006
R-007
R-008
R-009
R-010
R-011
R-012
R-013
R-014
R-015
R-016
R-017
R-018
R-019
R-020
R-021
R-022
R-023
R-024
R-025
R-026
R-027
R-028
R-029
R-030
R-031
R-032
R-033
R-034
R-035
R-036
R-037
R-038
R-039
R-040
R-041
R-042
R-043
R-044
R-045
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
35.0
29.8
30.4
33.5
29.5
29.3
27.0
29.1
26.5
28.8
30.0
31.2
31.7
26.4
29.6
28.9
25.9
26.3
29.9
34.5
35.0
29.4
27.2
28.8
29.8
32.2
29.6
26.1
25.1
25.2
27.0
33.6
28.4
28.8
30.9
29.2
29.4
29.8
30.4
33.8
30.6
36.5
33.1
33.7
30.3
29.2
Receptor
ASL +
PSLCumulative
Night
Case LeqNight
(dBA)
(dBA)
39.5
Compliant
Cumulative
Case
LeqNight
(dBC)
dBC –
dBA
Tonal
Yes
46.8
9.2
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
44.8
45.0
45.7
40.6
40.0
38.1
38.8
36.7
38.5
41.5
40.2
41.4
39.6
39.8
39.1
36.9
38.1
41.2
45.7
46.1
42.7
39.3
41.4
41.4
44.2
41.6
37.2
35.9
39.0
37.6
43.3
39.4
43.0
44.2
42.7
43.0
42.6
43.7
46.7
45.1
52.4
46.5
46.3
43.2
42.8
15.0
14.6
12.2
11.1
10.7
11.1
9.7
10.2
9.7
11.5
9.0
9.7
13.2
10.2
10.2
11.0
11.8
11.3
11.2
11.1
13.3
12.1
12.6
11.6
12.0
12.0
11.1
10.8
13.8
10.6
9.7
11.0
14.2
13.3
13.5
13.6
12.8
13.3
12.9
14.5
15.9
13.4
12.6
12.9
13.6
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
40.0
36.1
40.0
36.3
40.0
37.3
40.0
36.1
40.0
36.0
40.0
35.6
40.0
36.0
40.0
35.6
40.0
35.9
40.0
36.2
40.0
36.5
40.0
36.7
40.0
35.6
40.0
36.1
40.0
36.0
40.0
35.5
40.0
35.5
40.0
36.2
40.0
37.8
40.0
38.0
40.0
36.1
40.0
35.7
40.0
35.9
40.0
36.1
40.0
36.8
40.0
36.1
40.0
35.5
40.0
35.4
40.0
35.4
40.0
35.6
40.0
37.4
40.0
35.9
40.0
35.9
40.0
36.4
40.0
36.0
40.0
36.1
40.0
36.1
40.0
36.3
40.0
37.5
40.0
36.3
40.0
38.8
40.0
37.2
40.0
37.4
40.0
36.3
40.0
36.0
40.0
Pike 1 Project
March 2015
Jackfish Well
Pads (Typical)
STF
Jackfish 1 CPF
Jackfish 3 CPF
R-001
Jackfish 2 CPF
R-040
R-045
Pike 1 CPF
Location
R-035
R-005
1 500 m Boundary
R-030
R-010
trapper's
cabin
R-025
R-020
R-015
Figure D-4: Cumulative Case Noise Modeling LeqNight (without ASL)
Pike 1 Project
March 2015
It is also important to note that the well pads near the trapper's cabin are not part of the initial
well pad development for the Amended Project and the exact locations, timing, and orientations
for the well pads near the trapper's cabin will not be determined until they are required to
maintain production. The noise model indicates that the noise levels at the trapper's cabin
should be below 40 dBA until well pads start to encroach within approximately 1 200 m. At such
time, Devon will revisit the noise model to determine the specific noise mitigation required to
maintain a noise level below 40 dBA at the trapper’s cabin based on more detailed well pad
locations and pad site orientation.
5.4.2
General Noise Mitigation
The following assumptions for the operations of the Amended Project were made in the noise
model, and are similar to some of those applied in assessment of the operating and approved
Jackfish Projects:
•
all potential non-emergency noise generating equipment will be designed to meet a
maximum noise emission performance specification of 85 dBA at 1 m;
•
each building in the proposed Amended Project will be similar to those of the
corresponding buildings in the operating and approved Jackfish Projects. The building
ventilation openings (i.e., air intake and exhaust openings) will be fitted with appropriate
acoustic silencers, louvers, or plenums where applicable to reduce outdoor sound
transmission from indoor equipment. The walls and roofs will be designed to meet a
minimum STC rating of 35. Additionally, the building doors (man and equipment doors)
will be treated with insulation and weather stripping. Man-doors will have a minimum
STC rating of 35 while equipment roll doors will have a minimum STC rating of 25. All
buildings housing indoor noise generating equipment will be sealed to grade to trap all
the noise from escaping to the outdoors. Where practical, the windows and doors will
remain closed during normal operation in order to reduce outdoor sound transmission
from indoor equipment. All flanking path and penetrations from plumbing, heating ducts,
and electrical wire in the buildings will be properly insulated and covered so that noise
does not escape through them;
•
most of the electric pumps, air compressors, and vapor recovery compressor together
with their associated electric motors will be located inside buildings. Any pump located
outdoors will meet a maximum noise emission level of 85 dBA at 1 m;
•
as with the Jackfish Projects, Devon will ensure the procurement of low noise cooler
fans for the facility. The cooling fans will use variable speed fans. Because the speed of
the fans can be varied depending on the real time cooling requirements, they are more
efficient than fixed speed fans. Additionally, when operating at less than full speed,
variable speed fans produce less noise than comparable fixed speed fans;
•
to minimize the likelihood of structure-borne noise that may be induced from the
vibration of indoor equipment, Devon will install vibration isolation pads, resilient mounts
on equipment, resilient pipe support systems, and dampers where appropriate; and
Pike 1 Project
March 2015
•
5.4.3
for a conservative estimate of the maximum disturbance during normal operation, all the
sound sources at the CPF and well pads were assumed to operate at peak power during
the daytime and nighttime periods.
Construction Noise
Although there are no specific construction noise level limits detailed by AER Directive 038,
there are general recommendations for construction noise mitigation. This includes all activities
associated with construction of the station. The document states:
“Licensees must take the following mitigating measures to reduce the
impact of construction noise on nearby dwellings:
-
Conduct construction activity between the hours of 07:00 and 22:00 to
reduce the potential impact of construction noise;
-
Advise nearby residents of significant noise-causing activities and
schedule these events to reduce disruption to them;
-
Ensure all internal combustion engines are fitted with appropriate
muffler systems; and
Should a noise complaint be filed during construction, the licensee must
respond expeditiously and take action to ensure that the complaint has
been addressed.”
6.0
CONCLUSION
The Baseline Case noise levels, that include the adjacent Jackfish Project noise sources (with
the average ambient sound levels [ASLs] of 35 dBA included) are projected to be below the
AER Directive 038 PSLs of 40 dBA LeqNight at the trapper's cabin and the theoretical 1 500 m
receptors. The Application Case noise levels associated with the Amended Project-only noise
sources (with the ASLs of 35 dBA included) are projected to be below the AER Directive 038
PSLs of 40 dBA LeqNight for the trapper's cabin and the theoretical 1 500 m receptors. The
Cumulative Case noise levels associated with the Jackfish and Amended Project noise sources
(with the ASLs of 35 dBA included) are projected to be below the AER Directive 038 PSLs of
40 dBA LeqNight at the trapper's cabin and the theoretical 1 500 m receptors. In addition, the
dBC sound levels are projected to be less than 20 dB greater than the dBA sound levels at the
trapper's cabin and the theoretical 1 500 m receptors for the Baseline, Application and
Cumulative Cases. As specified in AER Directive 038, if the dBC – dBA sound levels are less
than 20 dB, the noise is not considered to have a low frequency tonal component.
It is important to note that the results for the Application Case and Cumulative Case include
noise mitigation at the well pad nearest to the trapper's cabin (730 m to the west). Without the
noise mitigation at the nearest well pad, the modeled noise levels at the trapper's cabin for both
the Application Case and Cumulative Case are 39.8 dBA + 35 dBA (ASL) = 41.1 dBA which
exceeds the PSL of 40 dBA. The current planned noise mitigation is to orient the nearest well
Pike 1 Project
March 2015
pad such that the building doors point to the west, away from the trapper's cabin, which should
readily provide the required noise mitigation.
It is also important to note that the well pads near the trapper's cabin are not part of the initial
well pad development for the Amended Project and the exact locations, timing, and orientations
for the well pads near the trapper's cabin will not be determined until they are required to
maintain production. The noise model indicates that the noise levels at the trapper's cabin
should be below 40 dBA until well pads start to encroach within approximately 1 200 m. At such
time, Devon will revisit the noise model to determine the specific noise mitigation required to
maintain a noise level below 40 dBA at the trapper’s cabin based on more detailed well pad
locations and pad site orientation.
A short form (AER Directive 038) noise impact assessment is presented in Attachment D6.
7.0
REFERENCES
Alberta Energy Regulator (AER). 2007. Directive 038 on Noise Control, Calgary, Alberta.
International Organization for Standardization (ISO). 1993. Standard 9613-1, Acoustics –
Attenuation of Sound during Propagation Outdoors – Part 1: Calculation of Absorption of
Sound by the Atmosphere, Geneva Switzerland.
International Organization for Standardization (ISO). 1996. Standard 9613-2, Acoustics –
Attenuation of Sound During Propagation Outdoors – Part 2: General Method of
Calculation, Geneva Switzerland.
International Organization for Standardization (ISO). 2003., Standard 1996-1, Acoustics –
Description, Measurement and Assessment of Environmental Noise – Part 1: Basic
Quantities and Assessment Procedures, Geneva Switzerland.
Attachment D1
The Assessment of Environmental Noise (General)
Pike 1 Project
March 2015
Sound Pressure Level
Sound pressure is initially measured in Pascal’s (Pa). Humans can hear several orders of
magnitude in sound pressure levels, so a more convenient scale is used. This scale is known as
the decibel (dB) scale, named after Alexander Graham Bell (telephone guy). It is a base
10 logarithmic scale. When we measure pressure we typically measure the RMS sound
pressure.
P 2 
SPL = 10 log 10  RMS2  = 20 log10
 Pref 
Where:
 PRMS 


 Pref 
SPL = Sound Pressure Level in dB,
PRMS = Root Mean Square measured pressure (Pa),
Pref = Reference sound pressure level (Pref = 2x10-5 Pa = 20 μPa).
This reference sound pressure level is an internationally agreed upon value. It represents the
threshold of human hearing for “typical” people based on numerous testing. It is possible to
have a threshold which is lower than 20 μPa which will result in negative dB levels. As such,
zero dB does not mean there is no sound!
In general, a difference of 1 to 2 dB is the threshold for humans to notice that there has been a
change in sound level. A difference of 3 dB (factor of 2 in acoustical energy) is perceptible and a
change of 5 dB is strongly perceptible. A change of 10 dB is typically considered a factor of 2.
This is quite remarkable when considering that 10 dB is 10-times the acoustical energy!
Attachment D1 – Page 1
Pike 1 Project
March 2015
Frequency
The range of frequencies audible to the human ear ranges from approximately 20 Hz to 20 kHz.
Within this range, the human ear does not hear equally at all frequencies. It is not very sensitive
to low frequency sounds, is very sensitive to mid frequency sounds and is slightly less sensitive
to high frequency sounds. Due to the large frequency range of human hearing, the entire
spectrum is often divided into 31 bands, each known as a 1/3 octave band.
The internationally agreed upon center frequencies and upper and lower band limits for the
1/1 (whole octave) and 1/3 octave bands are as follows:
Lower Band
Limit
Whole Octave
Center
Frequency
Upper Band
Limit
11
16
22
22
31.5
44
44
63
88
88
125
177
177
250
355
355
500
710
710
1 000
1 420
1 420
2 000
2 840
2 840
4 000
5 680
5 680
8 000
11 360
11 360
16 000
22 720
Lower Band
Limit
1/3 Octave
Center
Frequency
Upper Band
Limit
14.1
17.8
22.4
28.2
35.5
44.7
56.2
70.8
89.1
112
141
178
224
282
355
447
562
708
891
1 122
1 413
1 778
2 239
2 818
3 548
4 467
5 623
7 079
8 913
11 220
14 130
17 780
16
20
25
31.5
40
50
63
80
100
125
160
200
250
315
400
500
630
800
1 000
1 250
1 600
2 000
2 500
3 150
4 000
5 000
6 300
8 000
10 000
12 500
16 000
20 000
17.8
22.4
28.2
35.5
44.7
56.2
70.8
89.1
112
141
178
224
282
355
447
562
708
891
1 122
1 413
1 778
2 239
2 818
3 548
4 467
5 623
7 079
8 913
11 220
14 130
17 780
22 390
Pike 1 Project
March 2015
Human hearing is most sensitive at approximately 3 500 Hz which corresponds to the
¼ wavelength of the ear canal (approximately 2.5 cm). Because of this range of sensitivity to
various frequencies, we typically apply various weighting networks to the broadband measured
sound to more appropriately account for the way humans hear. By default, the most common
weighting network used is the so-called “A-weighting”. It can be seen in the figure that the low
frequency sounds are reduced significantly with the A-weighting.
Combination of Sounds
When combining multiple sound sources the general equation is:
 n SPL i 
Σ SPL n = 10 log 10  Σ 10 10 
i =1


Examples:
•
Two sources of 50 dB each add together to result in 53 dB;
•
Three sources of 50 dB each add together to result in 55 dB;
•
Ten sources of 50 dB each add together to result in 60 dB; and
•
One source of 50 dB added to another source of 40 dB results in 50.4 dB.
It can be seen that, if multiple similar sources exist, removing or reducing only one source will
have little effect.
Pike 1 Project
March 2015
Sound Level Measurements
Over the years a number of methods for measuring and describing environmental noise have
been developed. The most widely used and accepted is the concept of the Energy Equivalent
Sound Level (Leq) which was developed in the US (1970s) to characterize noise levels near
US Air-force bases. This is the level of a steady state sound which, for a given period of time,
would contain the same energy as the time varying sound. The concept is that the same amount
of annoyance occurs from a sound having a high level for a short period of time as from a sound
at a lower level for a longer period of time.
The Leq is defined as:
L eq
dB

1 T P 2
1 T

dT 
= 10 log 10   10 10 dT  = 10 log 10  
2
0
 T 0 Pref

T

We must specify the time period over which to measure the sound (i.e., 1-second, 10-seconds,
15-seconds, 1-minute, 1-day, etc.). A Leq is meaningless if there is no time period
associated.
In general, there a few very common Leq sample durations that are used in describing
environmental noise measurements. These include:
•
Leq24
•
LeqNight – measured over the night-time (typically 22:00 – 07:00);
•
LeqDay
– measured over the day-time (typically 07:00 – 22:00); and
•
LDN
– same as Leq24 with a 10 dB penalty added to the night-time.
– measured over a 24-hour period;
Statistical Descriptor
Another method of conveying long term noise levels utilizes statistical descriptors. These are
calculated from a cumulative distribution of the sound levels over the entire measurement
duration and then determining the sound level at xx % of the time.
Industrial Noise Control, Lewis Bell, Marcel Dekker, Inc. 1994
Pike 1 Project
March 2015
The most common statistical descriptors are:
•
Lmin – minimum sound level measured;
•
L01
– sound level that was exceeded only 1% of the time;
•
L10
– sound level that was exceeded only 10% of the time;
– Good measure of intermittent or intrusive noise
– Good measure of Traffic Noise;
•
L50
– sound level that was exceeded 50% of the time (arithmetic average);
– Good to compare to Leq to determine steadiness of noise;
•
L90
– sound level that was exceeded 90% of the time;
– Good indicator of typical “ambient” noise levels;
•
L99
•
Lmax – maximum sound level measured.
– sound level that was exceeded 99% of the time; and
These descriptors can be used to provide a more detailed analysis of the varying noise climate:
•
If there is a large difference between the Leq and the L50 (Leq can never be any lower than
the L50) then it can be surmised that one or more short duration, high level sound(s)
occurred during the time period; and
•
If the gap between the L10 and L90 is relatively small (less than 15 to 20 dBA) then it can
be surmised that the noise climate was relatively steady.
Sound Propagation
In order to understand sound propagation, the nature of the source must first be discussed. In
general, there are three types of sources. These are known as ‘point’, ‘line’, and ‘area’. This
discussion will concentrate on point and line sources since area sources are much more
complex and can usually be approximated by point sources at large distances.
Point Source
As sound radiates from a point source, it dissipates through geometric spreading. The basic
relationship between the sound levels at two distances from a point source is:
 r2 
∴ SPL1 − SPL2 = 20 log10  
r 
 1
Where: SPL1 = sound pressure level at location 1, SPL2 = sound pressure level at location 2,
r1 = distance from source to location 1, r2 = distance from source to location 2.
Pike 1 Project
March 2015
Thus, the reduction in sound pressure level for a point source radiating in a free field is 6 dB per
doubling of distance. This relationship is independent of reflectivity factors provided they are
always present. Note that this only considers geometric spreading and does not take into
account atmospheric effects. Point sources still have some physical dimension associated with
them, and typically do not radiate sound equally in all directions in all frequencies. The
directionality of a source is also highly dependent on frequency. As frequency increases,
directionality increases.
Examples (note no atmospheric absorption):
•
a point source measuring 50 dB at 100 m will be 44 dB at 200 m;
•
a point source measuring 50 dB at 100 m will be 40.5 dB at 300 m;
•
a point source measuring 50 dB at 100 m will be 38 dB at 400 m; and
•
a point source measuring 50 dB at 100 m will be 30 dB at 1 000 m.
Line Source
A line source is similar to a point source in that it dissipates through geometric spreading. The
difference is that a line source is equivalent to a long line of many point sources. The basic
relationship between the sound levels at two distances from a line source is:
 r2 
SPL1 − SPL 2 = 10 log 10  
 r 
 1
The difference from the point source is that the ‘20’ term in front of the ‘log’ is now only 10.
Thus, the reduction in sound pressure level for a line source radiating in a free field is 3 dB per
doubling of distance.
Examples (note no atmospheric absorption):
•
a line source measuring 50 dB at 100 m will be 47 dB at 200 m;
•
a line source measuring 50 dB at 100 m will be 45 dB at 300 m;
•
a line source measuring 50 dB at 100 m will be 44 dB at 400 m; and
•
a line source measuring 50 dB at 100 m will be 40 dB at 1 000 m.
Atmospheric Absorption
As sound transmits through a medium, there is an attenuation (or dissipation of acoustic energy)
which can be attributed to three mechanisms:
1)
Viscous Effects - Dissipation of acoustic energy due to fluid friction which result in
thermodynamically irreversible propagation of sound.
2)
Heat Conduction Effects - Heat transfer between high and low temperature regions in
the wave which result in non-adiabatic propagation of the sound.
Pike 1 Project
March 2015
3)
Inter Molecular Energy Interchanges - Molecular energy relaxation effects which result
in a time lag between changes in translational kinetic energy and the energy associated
with rotation and vibration of the molecules.
The following table illustrates the attenuation coefficient of sound at standard pressure
(101.325 kPa) in units of dB/100 m.
Temperature
oC
30
20
10
0
Frequency (Hz)
Relative Humidity
(%)
125
250
500
1 000
2 000
4 000
20
0.06
0.18
0.37
0.64
1.40
4.40
50
0.03
0.10
0.33
0.75
1.30
2.50
90
0.02
0.06
0.24
0.70
1.50
2.60
20
0.07
0.15
0.27
0.62
1.90
6.70
50
0.04
0.12
0.28
0.50
1.00
2.80
90
0.02
0.08
0.26
0.56
0.99
2.10
20
0.06
0.11
0.29
0.94
3.20
9.00
50
0.04
0.11
0.20
0.41
1.20
4.20
90
0.03
0.10
0.21
0.38
0.81
2.50
20
0.05
0.15
0.50
1.60
3.70
5.70
50
0.04
0.08
0.19
0.60
2.10
6.70
90
0.03
0.08
0.15
0.36
1.10
4.10
•
As frequency increases, absorption tends to increase.
•
As Relative Humidity increases, absorption tends to decrease.
•
There is no direct relationship between absorption and temperature.
•
The net result of atmospheric absorption is to modify the sound propagation of a
point source from 6 dB/doubling-of-distance to approximately 7 – 8 dB/doublingof-distance (based on anecdotal experience).
Pike 1 Project
March 2015
120
Sound Pressure Level (dB)
100
80
Base
60
1 kHz
500 Hz
250 Hz
125 Hz
1600
1800
2000
2 kHz
40
4 kHz
20
8 kHz
0
0
200
400
600
800
1000
1200
distance (m)
1400
Atmospheric Absorption at 10oC and 70% RH
Pike 1 Project
March 2015
Meteorological Effects
There are many meteorological factors which can affect how sound propagates over large
distances. These various phenomena must be considered when trying to determine the relative
impact of a noise source either after installation or during the design stage.
Wind
•
Can greatly alter the noise climate away from a source depending on direction.
•
Sound levels downwind from a source can be increased due to refraction of sound back
down towards the surface. This is due to the generally higher velocities as altitude
increases.
•
Sound levels upwind from a source can be decreased due to a “bending” of the sound
away from the earth’s surface.
•
Sound level differences of ±10 dB are possible depending on severity of wind and
distance from source.
•
Sound levels crosswind are generally not disturbed by an appreciable amount.
•
Wind tends to generate its own noise, however, and can provide a high degree of
masking relative to a noise source of particular interest.
Temperature
•
Temperature effects can be similar to wind effects.
•
Typically, the temperature is warmer at ground level than it is at higher elevations.
•
If there is a very large difference between the ground temperature (very warm) and the
air aloft (only a few hundred meters) then the transmitted sound refracts upward due to
the changing speed of sound.
•
If the air aloft is warmer than the ground temperature (known as an inversion) the
resulting higher speed of sound aloft tends to refract the transmitted sound back down
towards the ground. This essentially works on Snell’s law of reflection and refraction.
•
Temperature inversions typically happen early in the morning and are most common
over large bodies of water or across river valleys.
•
Sound level differences of ±10 dB are possible depending on gradient of temperature
and distance from source.
Pike 1 Project
March 2015
Rain
•
Rain does not affect sound propagation by an appreciable amount unless it is very
heavy.
•
The larger concern is the noise generated by the rain itself. A heavy rain striking the
ground can cause a significant amount of highly broadband noise. The amount of noise
generated is difficult to predict.
•
Rain can also affect the output of various noise sources such as vehicle traffic.
Summary
•
In general, these wind and temperature effects are difficult to predict.
•
Empirical models (based on measured data) have been generated to attempt to account
for these effects.
•
Environmental noise measurements must be conducted with these effects in mind.
Sometimes it is desired to have completely calm conditions, other times a “worst case”
of downwind noise levels are desired.
Topographical Effects
Similar to the various atmospheric effects outlined in the previous section, the effect of various
geographical and vegetative factors must also be considered when examining the propagation
of noise over large distances.
Topography
•
One of the most important factors in sound propagation.
•
Can provide a natural barrier between source and receiver (i.e., if berm or hill in
between).
•
Can provide a natural amplifier between source and receiver (i.e., large valley in
between or hard reflective surface in between).
•
Must look at location of topographical features relative to source and receiver to
determine importance (i.e., small berm 1 km away from source and 1 km away from
receiver will make negligible impact).
Grass
•
Can be an effective absorber due to large area covered.
•
Only effective at low height above ground. Does not affect sound transmitted direct from
source to receiver if there is line of sight.
•
Typically, less absorption than atmospheric absorption when there is line of sight.
Pike 1 Project
March 2015
•
Approximate rule of thumb based on empirical data is:
Ag =18log10 ( f ) − 31
(dB / 100m)
Where: Ag is the absorption amount
Trees
•
Provide absorption due to foliage.
•
Deciduous trees are essentially ineffective in the winter
•
Absorption depends heavily on density and height of trees
•
No data found on absorption of various kinds of trees.
•
Large spans of trees are required to obtain even minor amounts of sound reduction.
•
In many cases, trees can provide an effective visual barrier, even if the noise attenuation
is negligible.
Tree/Foliage attenuation from ISO 9613-2:1996
Bodies of Water
•
Large bodies of water can provide the opposite effect to grass and trees.
•
Reflections caused by small incidence angles (grazing) can result in larger sound levels
at great distances (increased reflectivity, Q).
•
Typically, air temperatures are warmer high aloft since air temperatures near water
surface tend to be more constant. Result is a high probability of temperature inversion.
•
Sound levels can “carry” much further.
Pike 1 Project
March 2015
Snow
•
Covers the ground for approximately 1/2 of the year in northern climates.
•
Can act as an absorber or reflector (and varying degrees in between).
•
Freshly fallen snow can be quite absorptive.
•
Snow that has been sitting for a while and hard packed due to wind can be quite
reflective.
•
Falling snow can be more absorptive than rain, but does not tend to produce its own
noise.
•
Snow can cover grass which might have provided some means of absorption.
•
Typically, sound propagates with less impedance in winter due to hard snow on ground
and no foliage on trees/shrubs.
Attachment D2
Pike 1 Project
March 2015
Used with Permission Obtained from the AER Directive 038 (February 2007)
Source3
Sound Level ( dBA)
_____________________________________________________________________________________________
Bedroom of a country home . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
Soft whisper at 1.5 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
Quiet office or living room . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . .
40
Moderate rainfall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
Inside average urban home . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
Quiet street . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
Normal conversation at 1 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
60
Noisy office . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
60
Noisy restaurant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
70
Highway traffic at 15 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
75
Loud singing at 1 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
75
Tractor at 15 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
78-95
Busy traffic intersection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
80
Electric typewriter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
80
Bus or heavy truck at 15 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88-94
Jackhammer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88-98
Loud shout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
90
Freight train at 15 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
95
Modified motorcycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
95
Jet taking off at 600 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100
Amplified rock music . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
110
Jet taking off at 60 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
120
Air-raid siren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
130
3
Cottrell, Tom, 1980, Noise in Alberta, Table 1, p.8, ECA80 - 16/1B4 (Edmonton: Environment Council of Alberta).
Pike 1 Project
March 2015
Sound Levels Generated by Common Appliances
Used with Permission Obtained from the AER Directive 038 (February 2007)
Source4
Sound level at 3 feet (dBA)
_____________________________________________________________________________________________
Freezer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
38-45
Refrigerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hair clipper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34-53
47
50
Electric toothbrush . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
48-57
Humidifier . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
41-54
Clothes dryer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
51-65
Air conditioner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50-67
Electric shaver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
47-68
Water faucet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hair dryer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62
58-64
Clothes washer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
48-73
Dishwasher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59-71
Electric can opener . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
60-70
Food mixer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59-75
Electric knife . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
65-75
Electric knife sharpener . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
72
Sewing machine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
70-74
Vacuum cleaner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
65-80
Food blender . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
65-85
Coffee mill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
75-79
Food waste disposer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
69-90
Edger and trimmer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home shop tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hedge clippers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric lawn mower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
81
64-95
85
80-90
Reif, Z. F., and Vermeulen, P. J., 1979, “Noise from domestic appliances, construction, and industry,” Table 1, p.166, in Jones, H.
W., ed., Noise in the Human Environment, vol. 2, ECA79-SP/1 (Edmonton: Environment Council of Alberta).
Attachment D3
Pike 1 Project
March 2015
Jackfish 1 Noise Source Sound Power Levels (Re 10-12 Watts)
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
SG-1320 A
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 B
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 C
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 D
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 E
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 F
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 A
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 B
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 C
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 D
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 E
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 F
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 A
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 B
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 C
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 D
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 E
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 F
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
H-2650 A
Glycol Heater Casing
Glycol Area
2
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 B
Glycol Area
2
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 A
Glycol Heater Stack
Glycol Area
7
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 B
Glycol Heater Stack
Glycol Area
7
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 A
Glycol Heater Draft Fan
Glycol Area
2
Axial Fan
20
1
95.2
0.0
95.2
H-2650 B
Glycol Area
2
Axial Fan
20
1
95.2
0.0
95.2
E-2600 A
Glycol Coolers (each pair)
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 B
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 C
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 D
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 E
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 F
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 G
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 H
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
Tag
Pike 1 Project
March 2015
Tag
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
E-2600 I
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 J
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 K
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 L
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
HP BFW Pumps
Steam Gen Bldg
2
Centrifugal
1 864
3
112.4
18.8
93.6
LP BFW Booster Pumps
Steam Gen Bldg
2
Centrifugal
336
3
110.2
18.8
91.4
Disposal Injection Pump
Water Trt Bldg
2
Centrifugal
448
2
108.8
18.8
90.0
Oil Products Pumps
Water Trt Bldg
2
Centrifugal
187
2
107.6
18.8
88.8
Glycol Circulation Pumps
Glycol Building
2
Centrifugal
93
4
109.7
18.8
90.9
Eductor Supply Pump
Disposal Wtr Pmp
Bldg
2
Centrifugal
75
2
106.4
18.8
87.6
Desand Flush Pump
Disposal Wtr Pmp
Bldg
2
Centrifugal
75
1
103.4
18.8
84.6
VRU Compressor
VRU Building
2
Reciprocating
200
1
113.9
22.6
91.3
Transformer 10 MVA
Electrical
5
Transformer
10 MVA
1
96.8
0.0
96.8
Transformer 6.5 MVA
Electrical
5
Transformer
6.5 MVA
1
92.8
0.0
92.8
Pike 1 Project
March 2015
Jackfish 1 Noise Source Octave Band Sound Power Levels (Re 10-12 Watts)
Description
31.5
Hz
63
Hz
125
Hz
250
Hz
500
Hz
1 000
Hz
2 000
Hz
4 000
Hz
8 000
Hz
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
Glycol Heater Stack
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
Glycol Heater Stack
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
96.0
99.0
99.0
96.0
93.0
89.0
86.0
83.0
75.0
96.0
99.0
99.0
96.0
93.0
89.0
86.0
83.0
75.0
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
HP BFW Pumps
104.6
105.6
106.6
107.6
106.6
108.6
105.6
101.6
95.6
102.4
103.4
104.4
105.4
104.4
106.4
103.4
99.4
93.4
101.0
102.0
103.0
104.0
103.0
105.0
102.0
98.0
92.0
Oil Products Pumps
99.8
100.8
101.8
102.8
101.8
103.8
100.8
96.8
90.8
101.9
102.9
103.9
104.9
103.9
105.9
102.9
98.9
92.9
Eductor Supply Pump
98.6
99.6
100.6
101.6
100.6
102.6
99.6
95.6
89.6
Desand Flush Pump
95.6
96.6
97.6
98.6
97.6
99.6
96.6
92.6
86.6
VRU Compressor
104.0
100.0
105.0
104.0
102.0
105.0
110.0
107.0
100.0
Transformer 10 MVA
93.4
99.4
101.4
96.4
96.4
90.4
85.4
80.4
73.4
Transformer 6.5 MVA
89.4
95.4
97.4
92.4
92.4
86.4
81.4
76.4
69.4
Pike 1 Project
March 2015
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
SG-1320 A
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 B
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 C
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 D
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 E
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 F
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 A
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 B
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 C
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 D
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 E
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 F
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 A
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 B
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 C
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 D
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 E
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
Tag
SG-1320 F
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
H-2650 A
Glycol Area
2
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 B
Glycol Area
2
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 A
Glycol Heater Stack
Glycol Area
7
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 B
Glycol Heater Stack
Glycol Area
7
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 A
Glycol Area
2
Axial Fan
20
1
95.2
0.0
95.2
H-2650 B
Glycol Area
2
Axial Fan
20
1
95.2
0.0
95.2
E-2600 A
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 B
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 C
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 D
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 E
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 F
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 G
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
Pike 1 Project
March 2015
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
E-2600 H
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 I
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 J
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 K
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 L
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
HP BFW Pumps
Steam Gen Bldg
2
Centrifugal
1 864
3
112.4
18.8
93.6
Steam Gen Bldg
2
Centrifugal
336
3
110.2
18.8
91.4
Water Trt Bldg
2
Centrifugal
448
2
108.8
18.8
90.0
Tag
Oil Products Pumps
Water Trt Bldg
2
Centrifugal
187
2
107.6
18.8
88.8
Glycol Building
2
Centrifugal
93
4
109.7
18.8
90.9
Eductor Supply Pump
Disposal Wtr Pmp
Bldg
2
Centrifugal
75
2
106.4
18.8
87.6
Desand Flush Pump
Disposal Wtr Pmp
Bldg
2
Centrifugal
75
1
103.4
18.8
84.6
91.3
VRU Compressor
VRU Building
2
Reciprocating
200
1
113.9
22.6
Transformer 10 MVA
Electrical
5
Transformer
10 MVA
1
96.8
0.0
96.8
Transformer 6.5 MVA
Electrical
5
Transformer
6.5 MVA
1
92.8
0.0
92.8
Pike 1 Project
March 2015
Description
31.5
Hz
63
Hz
125
Hz
250
Hz
500
Hz
1 000
Hz
2 000
Hz
4 000
Hz
8 000
Hz
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Casing
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Stack
109.6
108.6
103.6
97.6
96.6
94.6
92.6
92.6
92.6
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
OTSG Draft Fan
100.0
103.0
103.0
100.0
97.0
93.0
90.0
87.0
79.0
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
Glycol Heater Stack
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
Glycol Heater Stack
89.0
89.0
88.0
86.0
83.0
80.0
77.0
74.0
71.0
96.0
99.0
99.0
96.0
93.0
89.0
86.0
83.0
75.0
96.0
99.0
99.0
96.0
93.0
89.0
86.0
83.0
75.0
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
105.8
108.8
108.8
105.8
102.8
98.8
95.8
92.8
84.8
HP BFW Pumps
104.6
105.6
106.6
107.6
106.6
108.6
105.6
101.6
95.6
102.4
103.4
104.4
105.4
104.4
106.4
103.4
99.4
93.4
101.0
102.0
103.0
104.0
103.0
105.0
102.0
98.0
92.0
Oil Products Pumps
99.8
100.8
101.8
102.8
101.8
103.8
100.8
96.8
90.8
101.9
102.9
103.9
104.9
103.9
105.9
102.9
98.9
92.9
Eductor Supply Pump
98.6
99.6
100.6
101.6
100.6
102.6
99.6
95.6
89.6
Desand Flush Pump
95.6
96.6
97.6
98.6
97.6
99.6
96.6
92.6
86.6
VRU Compressor
104.0
100.0
105.0
104.0
102.0
105.0
110.0
107.0
100.0
Transformer 10 MVA
93.4
99.4
101.4
96.4
96.4
90.4
85.4
80.4
73.4
Transformer 6.5 MVA
89.4
95.4
97.4
92.4
92.4
86.4
81.4
76.4
69.4
Pike 1 Project
March 2015
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
SG-1320 A
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 B
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 C
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 D
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 E
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 F
OTSG Casing
Steam Gen Bldg
3
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 A
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 B
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 C
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 D
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 E
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 F
OTSG Stack
Steam Gen Bldg
29
Boiler
94 400
1
101.1
0.0
101.1
SG-1320 A
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 B
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 C
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 D
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 E
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
SG-1320 F
OTSG Draft Fan
Steam Gen Bldg
5
Axial Fan
100
1
99.2
0.0
99.2
H-2650 A
Glycol Area
2
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 B
Glycol Area
2
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 A
Glycol Heater Stack
Glycol Area
7
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 B
Glycol Heater Stack
Glycol Area
7
Boiler
1 BHP
1
85.7
0.0
85.7
H-2650 A
Glycol Area
2
Axial Fan
20
1
95.2
0.0
95.2
Tag
H-2650 B
Glycol Area
2
Axial Fan
20
1
95.2
0.0
95.2
E-2600 A
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 B
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 C
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 D
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 E
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 F
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
Pike 1 Project
March 2015
Tag
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
E-2600 G
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 H
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 I
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 J
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 K
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
E-2600 L
Glycol Area
5
Axial Fan
30
2
105.0
0.0
105.0
HP BFW Pumps
Steam Gen Bldg
2
Centrifugal
1 864
3
112.4
18.8
93.6
Steam Gen Bldg
2
Centrifugal
336
3
110.2
18.8
91.4
Water Trt Bldg
2
Centrifugal
448
2
108.8
18.8
90.0
P-010-A/B/C
P-020
K-050 A/B
Oil Products Pumps
Water Trt Bldg
2
Centrifugal
187
2
107.6
18.8
88.8
Glycol Building
2
Centrifugal
93
4
109.7
18.8
90.9
Eductor Supply Pump
Disposal Wtr Pmp
Bldg
2
Centrifugal
75
2
106.4
18.8
87.6
Desand Flush Pump
Disposal Wtr Pmp
Bldg
2
Centrifugal
75
1
103.4
18.8
84.6
VRU Compressor
VRU Building
2
Reciprocating
200
1
113.9
22.6
91.3
Transformer 10 MVA
Electrical
5
Transformer
10 MVA
1
96.8
0.0
96.8
Transformer 6.5 MVA
Electrical
5
Transformer
6.5 MVA
1
92.8
0.0
92.8
108.6
Group Pump
Well pad
3
Centrifugal
400.0
2
108.6
0.0
Test Pump
Well pad
2
Centrifugal
187.0
1
104.6
10.0
94.6
Instrument Air Compressor
Well pad
3
Reciprocating
22.0
1
104.3
0.0
104.3
Well-pair (each)
Well pad
2
Piping / Valves
N/A
1
88.2
0
88.2
Pike 1 Project
March 2015
Description
OTSG Casing
OTSG Casing
OTSG Casing
OTSG Casing
OTSG Casing
OTSG Casing
OTSG Stack
OTSG Stack
OTSG Stack
OTSG Stack
OTSG Stack
OTSG Stack
OTSG Draft Fan
OTSG Draft Fan
OTSG Draft Fan
OTSG Draft Fan
OTSG Draft Fan
OTSG Draft Fan
Glycol Heater Stack
Glycol Heater Stack
HP BFW Pumps
Oil Products Pumps
Eductor Supply Pump
Desand Flush Pump
VRU Compressor
Transformer 10 MVA
Transformer 6.5 MVA
Group Pump
Test Pump
Well-pair (each)
31.5
Hz
109.6
109.6
109.6
109.6
109.6
109.6
109.6
109.6
109.6
109.6
109.6
109.6
100.0
100.0
100.0
100.0
100.0
100.0
89.0
89.0
89.0
89.0
96.0
96.0
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
104.6
102.4
101.0
99.8
101.9
98.6
95.6
104.0
93.4
89.4
100.8
86.8
94.4
85.0
63
Hz
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
103.0
103.0
103.0
103.0
103.0
103.0
89.0
89.0
89.0
89.0
99.0
99.0
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
105.6
103.4
102.0
100.8
102.9
99.6
96.6
100.0
99.4
95.4
101.8
87.8
90.4
79.7
125
Hz
103.6
103.6
103.6
103.6
103.6
103.6
103.6
103.6
103.6
103.6
103.6
103.6
103.0
103.0
103.0
103.0
103.0
103.0
88.0
88.0
88.0
88.0
99.0
99.0
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
108.8
106.6
104.4
103.0
101.8
103.9
100.6
97.6
105.0
101.4
97.4
102.8
88.8
95.4
81.3
250
Hz
97.6
97.6
97.6
97.6
97.6
97.6
97.6
97.6
97.6
97.6
97.6
97.6
100.0
100.0
100.0
100.0
100.0
100.0
86.0
86.0
86.0
86.0
96.0
96.0
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
105.8
107.6
105.4
104.0
102.8
104.9
101.6
98.6
104.0
96.4
92.4
103.8
89.8
94.4
72.4
500
Hz
96.6
96.6
96.6
96.6
96.6
96.6
96.6
96.6
96.6
96.6
96.6
96.6
97.0
97.0
97.0
97.0
97.0
97.0
83.0
83.0
83.0
83.0
93.0
93.0
102.8
102.8
102.8
102.8
102.8
102.8
102.8
102.8
102.8
102.8
102.8
102.8
106.6
104.4
103.0
101.8
103.9
100.6
97.6
102.0
96.4
92.4
102.8
88.8
92.4
78.8
1 000
Hz
94.6
94.6
94.6
94.6
94.6
94.6
94.6
94.6
94.6
94.6
94.6
94.6
93.0
93.0
93.0
93.0
93.0
93.0
80.0
80.0
80.0
80.0
89.0
89.0
98.8
98.8
98.8
98.8
98.8
98.8
98.8
98.8
98.8
98.8
98.8
98.8
108.6
106.4
105.0
103.8
105.9
102.6
99.6
105.0
90.4
86.4
104.8
90.8
95.4
78.8
2 000
Hz
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
90.0
90.0
90.0
90.0
90.0
90.0
77.0
77.0
77.0
77.0
86.0
86.0
95.8
95.8
95.8
95.8
95.8
95.8
95.8
95.8
95.8
95.8
95.8
95.8
105.6
103.4
102.0
100.8
102.9
99.6
96.6
110.0
85.4
81.4
101.8
87.8
100.4
81.5
4 000
Hz
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
87.0
87.0
87.0
87.0
87.0
87.0
74.0
74.0
74.0
74.0
83.0
83.0
92.8
92.8
92.8
92.8
92.8
92.8
92.8
92.8
92.8
92.8
92.8
92.8
101.6
99.4
98.0
96.8
98.9
95.6
92.6
107.0
80.4
76.4
97.8
83.8
97.4
83.5
8 000
Hz
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
79.0
79.0
79.0
79.0
79.0
79.0
71.0
71.0
71.0
71.0
75.0
75.0
84.8
84.8
84.8
84.8
84.8
84.8
84.8
84.8
84.8
84.8
84.8
84.8
95.6
93.4
92.0
90.8
92.9
89.6
86.6
100.0
73.4
69.4
91.8
77.8
90.4
79.6
Pike 1 Project
March 2015
STF Noise Source Sound Power Levels (Re 10-12 Watts)
Model/Type
Rating
(kW)
#
Units
Equipment
Sound Power
Level
(dBA)
Building
Attenuation
(dBA)
Overall
Sound
Power Level
(dBA)
Description
Location
Height
(m)
Blend Booster Pump
TSF Site
2
Centrifugal
261
1
104.4
0
104.4
Blend Booster Pump
TSF Site
2
Centrifugal
261
1
104.4
0
104.4
Blend Booster Pump
TSF Site
2
Centrifugal
261
1
104.4
0
104.4
Diluent Booster Pump
TSF Site
2
Centrifugal
186
1
104.8
0
104.8
TSF Site
2
Centrifugal
186
1
104.8
0
104.8
TSF Site
2
Centrifugal
186
1
104.8
0
104.8
STF Noise Source Octave Band Sound Power Levels (Re 10-12 Watts)
Description
31.5
Hz
63
Hz
125
Hz
250
Hz
500
Hz
1 000
Hz
2 000
Hz
4 000
Hz
8 000
Hz
Blend Booster Pump
93.8
94.8
95.8
97.8
97.8
100.8
97.8
93.8
87.8
Blend Booster Pump
93.8
94.8
95.8
97.8
97.8
100.8
97.8
93.8
87.8
Blend Booster Pump
93.8
94.8
95.8
97.8
97.8
100.8
97.8
93.8
87.8
94.2
95.2
96.2
98.2
98.2
101.2
98.2
94.2
88.2
94.2
95.2
96.2
98.2
98.2
101.2
98.2
94.2
88.2
94.2
95.2
96.2
98.2
98.2
101.2
98.2
94.2
88.2
Pike 1 Project
March 2015
Pike 1 Phase 1a/1b Noise Source Sound Power Levels (Re 10-12 Watts)
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
Oil Removal Filter Agitator
BU-3000
2
Motor
44.7
1
103.0
19.3
83.7
AG-3180 B
BU-3000
2
Motor
44.7
1
103.0
19.3
83.7
AG-3180 C
BU-3000
2
Motor
44.7
1
103.0
19.3
83.7
AG-3340 A
Lime Softener Filter Agitator
BU-3000
2
Motor
44.7
1
103.0
19.3
83.7
AG-3340 B
BU-3000
2
Motor
44.7
1
103.0
19.3
83.7
AG-3340 C
Tag
AG-3180 A
BU-3000
2
Motor
44.7
1
103.0
19.3
83.7
E-2600 A
Glycol Aerial Cooler
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 B
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 C
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 D
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 E
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 F
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 G
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 H
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 J
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 K
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
E-2600 L
Glycol Area
7.5
Aerial Cooler
37.0
2
104.8
0.0
104.8
Emergency Generator
BU-1650
4
Diesel Genset
1 500.0
1
122.1
15.8
106.3
H-2650 A
Glycol Trim Heater Stack
Glycol Area
6.7
Heater
933 BHP
1
97.6
0.0
97.6
K-2650 A
Glycol Trim Heater Combustion
Air Blower
Glycol Area
3
Blower Fan
44.7
1
99.4
0.0
99.4
H-2650 B
Glycol Area
6.7
Heater
933 BHP
1
97.6
0.0
97.6
K-2650 B
Air Blower
Glycol Area
3
Blower Fan
44.7
1
99.4
0.0
99.4
K-2700 A
SRU Gas Compressor
BU-2710
2
Reciprocating
59.7
1
108.7
22.6
86.1
K-2700 B
SRU Gas Compressor
BU-2720
2
Reciprocating
59.7
1
108.7
22.6
86.1
K-2700 C
SRU Gas Compressor
BU-2730
2
Reciprocating
59.7
1
108.7
22.6
86.1
P-1100 A
LP BFW Pump
BU-1000
2
Centrifugal
596.8
1
106.1
18.8
87.3
P-1100 B
LP BFW Pump
BU-1000
2
Centrifugal
596.8
1
106.1
18.8
87.3
P-1100 C
LP BFW Pump
BU-1000
2
Centrifugal
596.8
1
106.1
18.8
87.3
GE-1650 A/B
Pike 1 Project
March 2015
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
P-1110 A
Backwash Regen Pump
BU-1000
2
Centrifugal
93.0
1
103.7
18.8
84.9
P-1110 B
Backwash Regen Pump
BU-1000
2
Centrifugal
93.0
1
103.7
18.8
84.9
P-1110 C
Backwash Regen Pump
BU-1000
2
Centrifugal
93.0
1
103.7
18.8
84.9
P-1170 A
HP BFW Pump
BU-1000
2
Centrifugal
2 237.0
1
107.8
18.8
89.0
Tag
P-1170 B
HP BFW Pump
BU-1000
2
Centrifugal
2 237.0
1
107.8
18.8
89.0
P-1170 C
HP BFW Pump
BU-1000
2
Centrifugal
2 237.0
1
107.8
18.8
89.0
Utility BFW Pumps
BU-1000
2
Centrifugal
30.0
2
105.2
18.8
86.4
84.2
P-1800 A/B
P-2190
FWKO Interface Recycle Pump
BU-2000
2
Centrifugal
55.0
1
103.0
18.8
P-2240
HP Liquids Relief Pump
BU-2000
2
Centrifugal
11.1
1
100.9
18.8
82.1
P-2600 A
Glycol Circulation Pump
BU-2040
2
Centrifugal
298.4
1
105.2
18.8
86.4
P-2600 B
BU-2040
2
Centrifugal
298.4
1
105.2
18.8
86.4
P-2600 C
BU-2040
2
Centrifugal
298.4
1
105.2
18.8
86.4
Recycle Tank Pumps
BU-3000
2
Centrifugal
22.0
2
104.8
18.8
86.0
P-3100 A/B
P-3120 A/B
Skim Oil Pumps
BU-1000
2
Centrifugal
14.9
2
104.3
18.8
85.5
P-3140 A
IGF Eductor Supply Pump
Near BU-3040
2
Centrifugal
75.0
1
103.4
0.0
103.4
P-3140 B
Near BU-3040
2
Centrifugal
75.0
1
103.4
0.0
103.4
P-3160 A
IGF Discharge Pump
Near BU-3040
2
Centrifugal
93.3
1
103.7
0.0
103.7
P-3160 B
IGF Discharge Pump
Near BU-3040
2
Centrifugal
93.3
1
103.7
0.0
103.7
P-3160 C
IGF Discharge Pump
Near BU-3040
2
Centrifugal
93.3
1
103.7
0.0
103.7
P-3170 A/B
IGF Froth Pumps
BU-3000
2
Centrifugal
14.9
2
104.3
18.8
85.5
P-3190 A/B
HLS Feed Pumps
BU-3020
2
Centrifugal
112.0
2
107.0
18.8
88.2
P-3220 A/B
Sludge Pumps
BU-3000
2
Centrifugal
22.4
2
104.9
18.8
86.1
P-3380 A
WAC Feed Pump
BU-3000
2
Centrifugal
186.5
1
104.6
18.8
85.8
P-3380 B
WAC Feed Pump
BU-3000
2
Centrifugal
186.5
1
104.6
18.8
85.8
P-3380 C
WAC Feed Pump
BU-3000
2
Centrifugal
186.5
1
104.6
18.8
85.8
87.3
P-3390 A/B/C
Neutralized Waste Pumps
BU-3000
2
Centrifugal
14.9
3
106.1
18.8
P-3460 A/B
Lime Slurry Pumps
BU-3000
2
Centrifugal
29.8
2
105.2
18.8
86.4
P-3480 A/B
Magox Slurry Pumps
BU-3000
2
Centrifugal
29.8
2
105.2
18.8
86.4
P-3590 A
Disposal Water Injection Pump
BU-4020
2
Centrifugal
149.0
1
104.3
18.8
85.5
P-3590 B
BU-4020
2
Centrifugal
149.0
1
104.3
18.8
85.5
Sludge Transfer Pumps
BU-3000
2
Centrifugal
22.4
2
104.9
18.8
86.1
P-3740 A/B
Pike 1 Project
March 2015
Tag
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
P-3770 A/B/C
Blowdown Water Booster Pumps
BU-1000
2
Centrifugal
22.5
3
106.6
18.8
87.8
P-3780 A
Blowdown Water Injection Pump
BU-1000
2
Centrifugal
336.0
1
105.4
18.8
86.6
P-3780 B
BU-1000
2
Centrifugal
336.0
1
105.4
18.8
86.6
Slop Oil Pumps
BU-3040
2
Centrifugal
30.0
2
105.2
18.8
86.4
P-4110 A/B/C
Dilbit Recycle Pumps
BU-4400
2
Centrifugal
74.5
3
108.2
18.8
89.4
P-4130 A
Diluent Supply Pump
BU-4400
2
Centrifugal
223.8
1
104.8
18.8
86.0
P-4130 B
Diluent Supply Pump
BU-4400
2
Centrifugal
223.8
1
104.8
18.8
86.0
P-4400 A
Shipping Booster Pumps
BU-4400
2
Centrifugal
261.0
1
105.0
18.8
86.2
P-4400 B
BU-4400
2
Centrifugal
261.0
1
105.0
18.8
86.2
P-4400 C
BU-4400
2
Centrifugal
261.0
1
105.0
18.8
86.2
Flash Treater Recycle Pump
BU-8240
2
Centrifugal
18.6
1
101.6
18.8
82.8
Dilbit Transfer Pump
BU-8240
2
Centrifugal
22.4
1
101.9
18.8
83.1
Blowdown Pond Pump
Pond
2
Centrifugal
30.0
1
102.2
0.0
102.2
P-3800 A/B
P-8250
P-8260
P-8430 A
P-8430 B
Blowdown Pond Pump
Pond
2
Centrifugal
30.0
1
102.2
0.0
102.2
P-8430 C
Blowdown Pond Pump
Pond
2
Centrifugal
30.0
1
102.2
0.0
102.2
P-8900 A/B/C
Gas Boot Sales Oil Pump
BU-8900
2
Centrifugal
93.0
3
108.5
18.8
89.7
Light Hydrocarbon Recycle Pump
BU-8900
2
Centrifugal
75.0
2
106.4
18.8
87.6
K-1600 A
BU-1600
3
Reciprocating
1 311.2
1
122.1
22.6
99.5
K-1600 B
BU-1600
3
Reciprocating
1 311.2
1
122.1
22.6
99.5
PK-3740
Sludge Centrifuge
BU-3000
2
Centrifuge
103.7
1
106.7
19.3
87.4
H-8240A
Flash Treater Heater Stack
BU-8240
8.5
Heater
210 BHP
1
95.0
0.0
95.0
H-8240A
BU-8240
8.5
Heater
210 BHP
1
95.0
0.0
95.0
K-8600 A
VRU Compressor
BU-8600
3
Reciprocating
318.4
1
115.9
22.6
93.3
K-8800 A
Gas Boot Compressor
BU-8800
2
Reciprocating
150.0
2
115.7
22.6
93.1
HP Steam Generator Stack
BU-1000
27
Heater
92 500.0
1
101.0
0.0
101.0
K-1350 A
OTSG Combustion Air Blower
BU-1000
3
Blower Fan
261.0
1
101.4
0.0
101.4
MU-1000 A
Steam Gen Bldg Air Make-Up
Unit
BU-1000
12
Make-Up Fan
30.0
1
98.0
0.0
98.0
SG-1320 B
BU-1000
27
Heater
92 500.0
1
101.0
0.0
101.0
K-1350 B
BU-1000
3
Blower Fan
261.0
1
101.4
0.0
101.4
MU-1000 B
Unit
BU-1000
12
Make-Up Fan
30.0
1
98.0
0.0
98.0
P-8920 A/B
SG-1320 A
Pike 1 Project
March 2015
Tag
SG-1320 C
Description
Location
Height
(m)
Model/Type
Rating
(kW)
# Units
Equipment Sound
Power Level
(dBA)
Building
Attenuation
(dBA)
Overall Sound
Power Level
(dBA)
BU-1000
27
Heater
92 500.0
1
101.0
0.0
101.0
K-1350 C
BU-1000
3
Blower Fan
261.0
1
101.4
0.0
101.4
MU-1000 C
Unit
BU-1000
12
Make-Up Fan
30.0
1
98.0
0.0
98.0
SG-1320 D
BU-1000
27
Heater
92 500.0
1
101.0
0.0
101.0
K-1350 D
BU-1000
3
Blower Fan
261.0
1
101.4
0.0
101.4
MU-1000 D
Unit
BU-1000
12
Make-Up Fan
30.0
1
98.0
0.0
98.0
SG-1320 E
BU-1000
27
Heater
92 500.0
1
101.0
0.0
101.0
K-1350 E
BU-1000
3
Blower Fan
261.0
1
101.4
0.0
101.4
MU-1000 E
Unit
BU-1000
12
Make-Up Fan
30.0
1
98.0
0.0
98.0
SG-1320 F
BU-1000
27
Heater
92 500.0
1
101.0
0.0
101.0
K-1350 F
BU-1000
3
Blower Fan
261.0
1
101.4
0.0
101.4
MU-1000 F
Unit
BU-1000
12
Make-Up Fan
30.0
1
98.0
0.0
98.0
N/A
Transformer
Substation
4
Transformer
42.0
1
101.2
0.0
101.2
N/A
Transformer
Substation
4
Transformer
42.0
1
101.2
0.0
101.2
Transformer
Substation
4
Transformer
42.0
1
101.2
0.0
101.2
Overall Well pad (Typical 10 wellpairs)
Well pad
3
N/A
N/A
1
111.3
0
110.4
N/A
Pike 1 Project
March 2015
Pike 1 Phase 1a/1b Noise Source Octave Band Sound Power Levels (Re 10-12 Watts)
Description
Emergency Generator
Air Blower
Air Blower
SRU Gas Compressor
SRU Gas Compressor
SRU Gas Compressor
LP BFW Pump
LP BFW Pump
LP BFW Pump
Backwash Regen Pump
Backwash Regen Pump
Backwash Regen Pump
HP BFW Pump
HP BFW Pump
HP BFW Pump
Utility BFW Pumps
FWKO Interface Recycle Pump
HP Liquids Relief Pump
Recycle Tank Pumps
Skim Oil Pumps
IGF Discharge Pump
IGF Discharge Pump
IGF Discharge Pump
IGF Froth Pumps
HLS Feed Pumps
Sludge Pumps
WAC Feed Pump
WAC Feed Pump
WAC Feed Pump
Neutralized Waste Pumps
31.5
Hz
90.3
90.3
90.3
90.3
90.3
90.3
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
115.8
100.9
63
Hz
90.3
90.3
90.3
90.3
90.3
90.3
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
115.8
100.9
125
Hz
93.3
93.3
93.3
93.3
93.3
93.3
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
108.6
120.8
99.9
250
Hz
95.3
95.3
95.3
95.3
95.3
95.3
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
105.6
123.8
97.9
500
Hz
98.3
98.3
98.3
98.3
98.3
98.3
102.6
102.6
102.6
102.6
102.6
102.6
102.6
102.6
102.6
102.6
102.6
118.8
94.9
1 000
Hz
98.3
98.3
98.3
98.3
98.3
98.3
98.6
98.6
98.6
98.6
98.6
98.6
98.6
98.6
98.6
98.6
98.6
116.8
91.9
2 000
Hz
97.3
97.3
97.3
97.3
97.3
97.3
95.6
95.6
95.6
95.6
95.6
95.6
95.6
95.6
95.6
95.6
95.6
113.8
88.9
4 000
Hz
92.3
92.3
92.3
92.3
92.3
92.3
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
92.6
107.8
85.9
8 000
Hz
84.3
84.3
84.3
84.3
84.3
84.3
84.6
84.6
84.6
84.6
84.6
84.6
84.6
84.6
84.6
84.6
84.6
101.8
82.9
100.2
103.2
103.2
100.2
97.2
93.2
90.2
87.2
79.2
100.9
100.9
99.9
97.9
94.9
91.9
88.9
85.9
82.9
100.2
103.2
103.2
100.2
97.2
93.2
90.2
87.2
79.2
98.8
98.8
98.8
98.3
98.3
98.3
95.9
95.9
95.9
100.0
100.0
100.0
97.4
95.2
93.1
97.4
97.4
97.4
97.0
96.5
95.6
95.6
95.9
95.9
95.9
96.5
99.2
97.1
96.8
96.8
96.8
98.3
94.8
94.8
94.8
99.3
99.3
99.3
96.9
96.9
96.9
101.0
101.0
101.0
98.4
96.2
94.1
98.4
98.4
98.4
98.0
97.5
96.6
96.6
96.9
96.9
96.9
97.5
100.2
98.1
97.8
97.8
97.8
99.3
99.8
99.8
99.8
100.3
100.3
100.3
97.9
97.9
97.9
102.0
102.0
102.0
99.4
97.2
95.1
99.4
99.4
99.4
99.0
98.5
97.6
97.6
97.9
97.9
97.9
98.5
101.2
99.1
98.8
98.8
98.8
100.3
98.8
98.8
98.8
101.3
101.3
101.3
98.9
98.9
98.9
103.0
103.0
103.0
100.4
98.2
96.1
100.4
100.4
100.4
100.0
99.5
98.6
98.6
98.9
98.9
98.9
99.5
102.2
100.1
99.8
99.8
99.8
101.3
96.8
96.8
96.8
100.3
100.3
100.3
97.9
97.9
97.9
102.0
102.0
102.0
99.4
97.2
95.1
99.4
99.4
99.4
99.0
98.5
97.6
97.6
97.9
97.9
97.9
98.5
101.2
99.1
98.8
98.8
98.8
100.3
99.8
99.8
99.8
102.3
102.3
102.3
99.9
99.9
99.9
104.0
104.0
104.0
101.4
99.2
97.1
101.4
101.4
101.4
101.0
100.5
99.6
99.6
99.9
99.9
99.9
100.5
103.2
101.1
100.8
100.8
100.8
102.3
104.8
104.8
104.8
99.3
99.3
99.3
96.9
96.9
96.9
101.0
101.0
101.0
98.4
96.2
94.1
98.4
98.4
98.4
98.0
97.5
96.6
96.6
96.9
96.9
96.9
97.5
100.2
98.1
97.8
97.8
97.8
99.3
101.8
101.8
101.8
95.3
95.3
95.3
92.9
92.9
92.9
97.0
97.0
97.0
94.4
92.2
90.1
94.4
94.4
94.4
94.0
93.5
92.6
92.6
92.9
92.9
92.9
93.5
96.2
94.1
93.8
93.8
93.8
95.3
94.8
94.8
94.8
89.3
89.3
89.3
86.9
86.9
86.9
91.0
91.0
91.0
88.4
86.2
84.1
88.4
88.4
88.4
88.0
87.5
86.6
86.6
86.9
86.9
86.9
87.5
90.2
88.1
87.8
87.8
87.8
89.3
Pike 1 Project
March 2015
Description
Lime Slurry Pumps
Magox Slurry Pumps
Sludge Transfer Pumps
Blowdown Water Booster Pumps
Slop Oil Pumps
Diluent Supply Pump
Diluent Supply Pump
Flash Treater Recycle Pump
Dilbit Transfer Pump
Blowdown Pond Pump
Blowdown Pond Pump
Blowdown Pond Pump
Sludge Centrifuge
VRU Compressor
Gas Boot Compressor
Unit
Unit
Unit
Unit
Unit
Unit
Transformer
Transformer
Transformer
Overall Well pad (Typical 10 wellpairs)
31.5
Hz
97.4
97.4
96.5
96.5
97.1
98.8
97.6
97.6
97.4
100.4
97.0
97.0
97.2
97.2
97.2
93.8
94.1
94.4
94.4
94.4
100.7
98.6
112.2
112.2
94.0
98.3
98.3
106.0
105.8
109.5
102.2
63
Hz
98.4
98.4
97.5
97.5
98.1
99.8
98.6
98.6
98.4
101.4
98.0
98.0
98.2
98.2
98.2
94.8
95.1
95.4
95.4
95.4
101.7
99.6
108.2
108.2
94.0
98.3
98.3
102.0
101.8
108.5
105.2
125
Hz
99.4
99.4
98.5
98.5
99.1
100.8
99.6
99.6
99.4
102.4
99.0
99.0
99.2
99.2
99.2
95.8
96.1
96.4
96.4
96.4
102.7
100.6
113.2
113.2
97.0
97.3
97.3
107.0
106.8
103.5
105.2
250
Hz
100.4
100.4
99.5
99.5
100.1
101.8
100.6
100.6
100.4
103.4
100.0
100.0
100.2
100.2
100.2
96.8
97.1
97.4
97.4
97.4
103.7
101.6
112.2
112.2
99.0
95.3
95.3
106.0
105.8
97.5
102.2
500
Hz
99.4
99.4
98.5
98.5
99.1
100.8
99.6
99.6
99.4
102.4
99.0
99.0
99.2
99.2
99.2
95.8
96.1
96.4
96.4
96.4
102.7
100.6
110.2
110.2
102.0
92.3
92.3
104.0
103.8
96.5
99.2
1 000
Hz
101.4
101.4
100.5
100.5
101.1
102.8
101.6
101.6
101.4
104.4
101.0
101.0
101.2
101.2
101.2
97.8
98.1
98.4
98.4
98.4
104.7
102.6
113.2
113.2
102.0
89.3
89.3
107.0
106.8
94.5
95.2
2 000
Hz
98.4
98.4
97.5
97.5
98.1
99.8
98.6
98.6
98.4
101.4
98.0
98.0
98.2
98.2
98.2
94.8
95.1
95.4
95.4
95.4
101.7
99.6
118.2
118.2
101.0
86.3
86.3
112.0
111.8
92.5
92.2
4 000
Hz
94.4
94.4
93.5
93.5
94.1
95.8
94.6
94.6
94.4
97.4
94.0
94.0
94.2
94.2
94.2
90.8
91.1
91.4
91.4
91.4
97.7
95.6
115.2
115.2
96.0
83.3
83.3
109.0
108.8
92.5
89.2
8 000
Hz
88.4
88.4
87.5
87.5
88.1
89.8
88.6
88.6
88.4
91.4
88.0
88.0
88.2
88.2
88.2
84.8
85.1
85.4
85.4
85.4
91.7
89.6
108.2
108.2
88.0
80.3
80.3
102.0
101.8
92.5
81.2
98.8
101.8
101.8
98.8
95.8
91.8
88.8
85.8
77.8
109.5
102.2
108.5
105.2
103.5
105.2
97.5
102.2
96.5
99.2
94.5
95.2
92.5
92.2
92.5
89.2
92.5
81.2
98.8
101.8
101.8
98.8
95.8
91.8
88.8
85.8
77.8
109.5
102.2
108.5
105.2
103.5
105.2
97.5
102.2
96.5
99.2
94.5
95.2
92.5
92.2
92.5
89.2
92.5
81.2
98.8
101.8
101.8
98.8
95.8
91.8
88.8
85.8
77.8
109.5
102.2
108.5
105.2
103.5
105.2
97.5
102.2
96.5
99.2
94.5
95.2
92.5
92.2
92.5
89.2
92.5
81.2
98.8
101.8
101.8
98.8
95.8
91.8
88.8
85.8
77.8
109.5
102.2
108.5
105.2
103.5
105.2
97.5
102.2
96.5
99.2
94.5
95.2
92.5
92.2
92.5
89.2
92.5
81.2
98.8
101.8
101.8
98.8
95.8
91.8
88.8
85.8
77.8
109.5
102.2
108.5
105.2
103.5
105.2
97.5
102.2
96.5
99.2
94.5
95.2
92.5
92.2
92.5
89.2
92.5
81.2
98.8
101.8
101.8
98.8
95.8
91.8
88.8
85.8
77.8
100.8
100.8
100.8
103.8
103.8
103.8
105.8
105.8
105.8
100.8
100.8
100.8
100.8
100.8
100.8
94.8
94.8
94.8
89.8
89.8
89.8
84.8
84.8
84.8
77.8
77.8
77.8
102.7
102.5
103.9
104.5
103.5
105.5
104.5
101.5
95.6
Pike 1 Project
March 2015
Jackfish 1, 2, 3 Building Dimensions
Tag
Building Name
Length (m)
Width (m)
Height (m)
29.0
89.4
10.8
Steam Generator MCC Building
29.5
14.3
5.3
Instrument Air Compressor Building
12.2
4.7
5.1
Standby Power Generator Building
6.8
15.0
4.4
Process Building
41.8
7.2
6.2
Glycol Building
7.0
12.0
5.0
BU-3000
Water Treatment Building
66.2
31.8
9.7
BU-3020
ORF Building
12.1
34.2
8.3
BU-3040
Disposal Water Pump Building
6.7
48.6
6.7
BU-3060
Barrel Dock Storage Building
3.0
14.5
5.0
BU-4000
Diluent Pump Building
6.9
24.0
6.7
BU-1000
Steam Generator Building
BU-1010
BU-1600
BU-1650
BU-2000
BU-2040
BU-4020
Disposal Water Injection Pump Building
6.7
18.0
7.1
BU-4400
Shipping Booster Pump Building
30.5
7.0
7.7
BU-4410
Electrical Building
11.3
5.8
6.2
BU-7000
Warehouse Building
22.0
32.5
7.0
BU-7010
Operation Office Building
44.6
40.3
6.5
BU-7020
Communication Trailer
4.4
11.7
5.0
BU-7200
Potable Water Building
14.7
6.3
7.6
BU-8240
Flash Treater Building
14.8
6.8
7.4
BU-8300
FKOD Building
6.7
7.2
5.6
BU-8500
Water Treatment MCC Building
14.1
22.4
5.4
BU-8600
VRU Compressor Building
7.0
14.7
8.2
BU-8800
Gas Boot Compressor Building
5.4
12.5
6.1
BU-8900
Crude Stabilization Pump Building
16.5
6.9
7.5
Height (m)
Note:
The buildings are the same for each of the three Jackfish Phases.
STF Building Dimensions
Tag
Length (m)
Width (m)
B-022
Integrity Metering Building
Building Name
5.5
5.0
3.0
B-023
Fire Water Building
15.0
6.0
3.0
B-024
MCC / Electrical Building
15.0
7.0
3.0
Pike 1 Project
March 2015
Pike 1 Phase 1a/1b Building Dimensions
Tag
Building Name
BU-1000
Length (m)
Width (m)
Height (m)
85.1
28.5
10.8
Steam Generation Building
BU-1010
Electrical Building
29.1
13.9
8.6
BU-1600
Instrument Air Compressor Building
12.3
4.7
5.1
BU-1650
Standby Power Generator Building
6.6
14.8
6.7
BU-2000
Process Building
41.6
7.0
6.2
BU-2040
Glycol Building
12.5
7.0
5.0
BU-2710
SRU Compression Building
9.2
6.1
5.9
BU-2720
9.2
6.1
5.9
BU-2730
9.2
6.1
5.9
BU-2810
SRU Contactor Building
16.2
7.2
5.0
BU-3000
Water Treatment Building
66.7
41.0
9.7
BU-3020
ORF Building
12.1
34.4
8.3
BU-3040
Disposal Water Pump Building
6.9
48.3
6.7
BU-4000
Diluent Pump Building
7.0
24.0
6.7
BU-4020
Disposal Water Injection Pump Building
6.7
18.0
7.1
BU-4400
Shipping Booster Pump Building
30.4
7.0
7.7
BU-4410
Electrical Building
11.3
5.8
6.2
BU-8240
Flash Treater Building
14.7
7.0
7.4
BU-8300
FKOD Building
6.5
7.1
5.6
BU-8500
Electrical Building
13.9
22.1
8.6
BU-8600
VRU Compressor Building
7.0
14.8
8.2
BU-8800
Gas Boot Compressor Building
5.5
12.2
6.1
BU-8900
Crude Stabilization Pump Building
16.4
6.9
7.5
Note:
The buildings are the same for each of Phase 1a and Phase 1b.
Building Sound Level Attenuation
Description
Typical Building
31.5
Hz
63
Hz
125
Hz
250
Hz
500
Hz
1 000
Hz
2 000
Hz
4 000
Hz
8 000
Hz
3
6
9
12
15
20
25
30
30
Jackfish 1, 2, 3 Tank Dimensions
Tag
Tank Name
T-1100
Diameter (m)
Height (m)
21.0
12.2
Recycle Tank
11.3
12.2
T-3110
Skim Tank
36.9
6.4
T-3190
De-Oiled Produced Water Storage Tank
25.8
14.6
T-3390
16.0
9.8
T-3770
11.6
9.8
Slop Tank
11.6
9.8
T-4100
Shipping Tank
14.6
12.2
T-4110A
Off-Spec Tank A
21.1
14.6
T-4110B
Off-Spec Tank B
21.1
14.6
T-4130
Diluent Storage
14.6
12.2
T-3100
T-3800
Note:
The tanks are the same for each of the three Jackfish Phases.
Pike 1 Project
March 2015
STF Tank Dimensions
Tag
S-100A
Tank Name
Diameter (m)
Height (m)
58.1
18.3
Blend Storage Tank
S-100B
Blend Storage Tank
58.1
18.3
S-100C
Diluent Storage Tank
29.3
18.3
S-300A
Fire Water Storage Tank
3.7
5.0
Pike 1 Phase 1a/1b Tank Dimensions
Tag
Tank Name
Diameter (m)
Height (m)
T-1100
BFW Storage Tank
21.0
7.0
T-2100
Reverse Demulsifier Tank
3.7
6.1
T-2150
Demulsifier Tank
3.7
6.1
T-2640
Glycol Makeup Tank
6.1
5.0
T-2830
Fresh Scavenger Tank
4.6
9.8
T-2840
Spent Scavenger Tank
4.6
9.8
T-2850
Methanol Tank (Note1)
3.4
3.7
T-3100
Recycle Tank
11.3
12.2
T-3110
Skim Tank
36.9
6.4
T-3190
Deoiled Produced Water Storage Tank
25.8
14.6
T-3390
Neutralization Tank
11.6
5.6
T-3580
Neutralized Waste Surge Tank
7.0
5.0
T-3770
Blowdown Disposal Water Storage Tank
11.0
5.6
T-3800
Slop Tank
11.6
9.8
T-4100
Shipping Tank
14.6
12.2
T-4110A
Off-spec Tank A
21.1
14.6
T-4110B
Off-spec Tank B
21.1
14.6
T-4130
Diluent Storage Tank
14.6
12.2
T-8420
Startup Blowdown Tank
7.2
5.0
Note:
The tanks are the same for each of Phase 1a and Phase 1b.
Parameter
Value
Modeling Software
CADNA/A (Version 4.4.145)
Standard Followed
ISO 9613-2
Ground Sound Absorption Coefficient
Wind Speed
Wind Direction
Temperature
Humidity
Topography
0.5
1 - 5 m/s (3.6 - 18 km/hr)
Downwind from all sources to all receptors
10 °C
70%
Used Digital Topographical Information Provided by Client
Attachment D4
Permissible Sound Level Determination
Pike 1 Project
March 2015
Theoretical 1 500 m and Residential Receptors
Basic Sound Level
Night-Time
Day-Time
40
40
40
40
0
n/a
n/a
+10
0
+ 10
0
0
0
0
0
0
0
0
0
0
Dwelling Density
(Per Quarter Section of Land)
Proximity to
Transportation
Category 1
Category 2
Category 3
1 - 8 Dwellings
40
45
50
9 - 160
Dwellings
43
48
53
> 160 Dwellings
46
51
56
Basic Sound Level (dBA)
Time of Day Adjustment
Adjustment
(dBA)
0
+10
Time of Day
Night-time adjustment for hours 22:00 - 07:00
Day-time adjustment for hours 07:00 - 22:00
Time of day adjustment (dBA)
Class A Adjustments
Class
Reason for Adjustment
A1
Seasonal Adjustment (Winter)
Adjustment
(dBA)
0 to +5
Ambient Monitoring Adjustment
-10 to +10
A2
Sum of A1 and A2 cannot exceed maximum of 10 dBA Leq
Class A Adjustment (dBA)
Class B Adjustments
Class
Duration of Activity
B1
≤ 1 Day
Adjustment
(dBA)
+ 15
B2
≤ 7 Days
+ 10
B3
≤ 60 Days
+5
0
0
B4
> 60 Days
0
0
0
0
0
40
50
Can only apply one of B1, B2, B3, or B4
Class B Adjustment (dBA)
Total Permissible Sound Level (PSL) [dBA]
Attachment D5
Cumulative Case Noise Source Order-Ranking
Pike 1 Project
March 2015
Theoretical 1 500 m Receptor R-041
Noise Source
Emergency Generator
Emergency Generator
Overall Well pad (Typical 10 well-pairs)
Glycol Trim Heater Combustion Air Blower
Location
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
dBA
24.1
21.5
21.5
21.5
21.5
21.5
21.5
21.5
21.4
19.7
19.7
19.7
19.7
19.7
19.7
19.7
19.7
19.6
19.6
18.6
18.6
17.9
17.9
17.3
17.3
17.3
17.2
17.2
17.2
17.0
15.9
15.8
15.8
15.3
14.9
31.5 Hz
41.1
33.7
33.7
33.7
33.7
33.7
33.7
33.7
33.7
32.3
32.3
32.3
32.3
32.3
32.3
32.3
32.3
23.5
23.5
29.2
23.5
22.1
22.1
30.3
30.3
30.2
30.2
30.2
30.2
22.0
19.4
28.7
37.6
28.3
31.9
63 Hz
37.9
36.5
36.5
36.5
36.5
36.5
36.5
36.5
36.5
35.1
35.1
35.1
35.1
35.1
35.1
35.1
35.1
26.6
26.6
26.0
26.5
25.2
25.2
33.1
33.1
33.1
33.1
33.0
33.0
25.0
19.0
31.5
30.4
31.1
30.8
125 Hz
31.1
29.1
29.1
29.1
29.1
29.1
29.1
29.1
29.1
27.6
27.6
27.6
27.6
27.6
27.6
27.6
27.6
25.9
25.8
26.8
25.5
24.5
24.5
24.1
24.1
24.1
24.0
24.0
24.0
24.1
19.1
22.5
23.4
22.1
24.2
250 Hz
29.5
24.1
24.1
24.1
24.1
24.1
24.1
24.1
24.1
22.5
22.5
22.5
22.5
22.5
22.5
22.5
22.5
22.2
22.2
25.0
21.3
20.9
20.9
18.8
18.8
18.7
18.7
18.6
18.6
19.9
17.6
17.1
17.0
16.7
15.5
500 Hz
21.2
19.8
19.8
19.9
19.9
19.9
19.9
19.9
19.8
18.1
18.1
18.1
18.1
18.1
18.1
18.1
18.1
19.5
19.5
14.5
17.8
17.7
17.7
16.2
16.2
16.2
16.1
16.1
16.1
16.4
14.2
14.6
12.6
14.2
13.3
1 000 Hz
12.6
14.2
14.2
14.2
14.2
14.3
14.3
14.3
14.2
11.9
11.9
11.9
11.9
11.9
11.9
11.9
11.9
11.7
11.7
3.3
11.7
9.4
9.4
10.6
10.6
10.5
10.5
10.5
10.4
9.4
12.0
9.3
11.1
8.6
7.7
2 000 Hz
-7.0
-0.5
-0.5
-0.5
-0.4
-0.4
-0.3
-0.3
-0.5
-4.9
-4.8
-4.8
-4.8
-4.8
-4.8
-4.7
-4.7
-3.3
-3.3
-18.6
-3.3
-7.7
-7.7
-4.4
-4.5
-4.5
-4.6
-4.6
-4.7
-7.7
-2.4
-5.2
-0.7
-6.5
-6.5
4 000 Hz
-58.9
-44.7
-44.7
-44.6
-44.6
-44.5
-44.4
-44.4
-44.8
-57.9
-57.8
-57.8
-57.8
-57.7
-57.7
-57.7
-57.7
-47.7
-47.7
-78.6
-47.6
-60.7
-60.7
-49.9
-50.0
-50.2
-50.4
-50.6
-50.7
-60.7
-52.0
-48.5
-50.2
-52.1
-48.9
Pike 1 Project
March 2015
Noise Source
Steam Gen Bldg Air Make-Up Unit
IGF Discharge Pump
Blowdown Pond Pump
IGF Discharge Pump
Location
Pike1 Phase 1b
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike 1 Well pad
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1b
Pike 1 Well pad
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1b
Pike1 Phase 1b
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1a
dBA
14.9
14.9
14.9
14.8
14.8
14.8
14.8
14.7
14.7
14.6
14.6
14.6
14.5
14.1
14.1
14.0
13.4
13.4
13.4
13.3
13.3
13.2
12.9
12.7
12.7
12.3
12.2
12.2
12.2
12.0
11.7
11.5
11.4
11.3
11.3
11.2
31.5 Hz
31.9
18.6
18.5
31.9
31.9
31.9
31.8
26.6
26.6
26.6
26.6
26.6
18.4
29.2
29.2
29.2
30.7
30.7
30.7
30.7
30.6
27.2
13.2
13.0
17.1
11.8
27.7
27.8
16.8
12.8
13.2
16.3
16.3
18.4
16.2
18.4
63 Hz
30.8
18.3
18.2
30.7
30.7
30.7
30.7
29.5
29.4
29.4
29.4
29.4
18.0
29.0
29.0
29.0
29.5
29.5
29.5
29.5
29.5
27.9
14.1
13.8
16.7
12.6
27.6
27.6
16.4
13.4
14.1
15.9
15.9
21.2
15.8
21.2
125 Hz
24.2
18.4
18.3
24.2
24.1
24.1
24.1
22.9
22.9
22.9
22.8
22.8
18.1
20.2
20.2
20.2
23.0
23.0
23.0
23.0
23.0
23.0
13.8
13.6
16.8
12.3
18.7
18.7
16.5
12.6
13.8
16.0
15.9
20.0
15.8
20.0
250 Hz
15.5
16.8
16.8
15.5
15.5
15.4
15.4
17.3
17.2
17.2
17.1
17.1
16.5
16.6
16.6
16.5
14.2
14.2
14.2
14.2
14.2
14.2
13.2
13.0
15.1
13.7
15.0
15.0
14.7
14.1
13.0
14.2
14.1
15.3
14.0
15.2
500 Hz
13.3
13.2
13.2
13.2
13.2
13.2
13.2
13.0
13.0
12.9
12.9
12.8
12.9
12.4
12.4
12.4
11.8
11.8
11.8
11.7
11.7
11.7
10.3
10.2
11.3
10.5
10.6
10.6
10.7
10.5
9.7
10.1
10.0
9.7
9.9
9.7
1 000 Hz
7.6
10.8
10.8
7.6
7.6
7.5
7.5
7.3
7.3
7.3
7.2
7.2
10.3
7.8
7.8
7.8
5.6
5.6
5.6
5.5
5.5
5.5
10.2
10.0
8.1
8.7
5.5
5.5
7.4
8.0
8.1
6.4
6.4
1.4
6.2
1.3
2 000 Hz
-6.6
-4.8
-5.0
-6.6
-6.7
-6.7
-6.8
-7.5
-7.5
-7.6
-7.7
-7.7
-5.7
-6.7
-6.7
-6.7
-10.3
-10.4
-10.4
-10.4
-10.5
-10.5
-5.6
-5.7
-10.2
-7.0
-11.1
-11.0
-11.6
-8.1
-7.5
-13.6
-13.7
-15.8
-14.0
-15.9
4 000 Hz
-49.0
-59.1
-60.7
-49.1
-49.3
-49.5
-49.7
-52.2
-52.4
-52.5
-52.7
-52.9
-61.9
-49.9
-49.9
-49.9
-60.0
-60.1
-60.2
-60.3
-60.4
-60.5
-53.8
-53.9
-76.0
-55.0
-63.1
-63.1
-80.6
-56.5
-55.4
-86.7
-86.7
-69.3
-87.8
-69.4
Pike 1 Project
March 2015
Noise Source
IGF Discharge Pump
Blowdown Pond Pump
Blowdown Pond Pump
IGF Discharge Pump
IGF Discharge Pump
IGF Discharge Pump
Gas Boot Compressor
Blowdown Pond Pump
Blowdown Pond Pump
Blowdown Pond Pump
Location
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1a
Pike1 Phase 1b
Pike 1 Well pad
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1b
Pike 1 Well pad
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1a
Pike 1 Well pad
Pike 1 Well pad
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1a
dBA
11.2
11.2
11.1
11.1
11.0
10.4
10.4
10.0
10.0
10.0
9.9
9.8
9.7
9.7
9.7
9.7
9.6
9.6
9.6
9.4
9.3
9.3
9.3
9.2
9.0
9.0
8.9
8.7
8.4
8.4
8.4
8.2
8.1
8.0
8.0
7.7
31.5 Hz
18.4
12.8
18.4
18.4
18.4
11.7
11.7
15.2
26.1
15.5
15.2
11.9
11.5
11.9
15.2
15.3
11.9
15.1
15.1
11.4
16.7
16.7
25.6
15.0
25.6
14.9
31.1
14.7
10.3
10.3
10.3
14.4
14.3
14.3
14.3
15.0
63 Hz
21.2
13.7
21.2
21.2
21.2
12.6
12.6
18.1
18.9
15.0
18.1
12.7
12.0
12.7
18.1
14.8
12.7
18.1
18.1
11.9
19.5
19.5
18.5
14.5
18.5
14.4
23.9
14.2
11.1
11.1
11.1
13.9
13.8
13.8
13.8
17.8
125 Hz
20.0
13.4
20.0
19.9
19.9
12.3
12.3
17.2
20.0
15.0
17.1
12.5
11.1
12.5
17.1
14.8
12.4
17.1
17.1
10.7
18.2
18.2
19.2
14.5
19.2
14.4
16.6
14.2
10.9
10.9
10.9
13.9
13.8
13.7
13.7
16.6
250 Hz
15.2
12.8
15.0
15.0
14.9
12.0
12.0
13.1
14.3
13.0
13.0
11.8
12.5
11.7
12.8
12.8
11.6
12.7
12.6
12.3
13.3
13.3
13.3
12.4
13.2
12.2
11.3
12.0
10.4
10.4
10.4
11.7
11.5
11.4
11.5
11.6
500 Hz
9.6
9.5
9.6
9.6
9.5
8.6
8.7
9.1
6.8
8.7
8.8
8.2
8.3
8.0
8.6
8.4
7.9
8.3
8.5
8.0
7.8
7.8
5.9
7.9
5.9
7.7
6.0
7.4
6.8
6.8
6.9
7.0
6.8
6.7
6.7
6.3
1 000 Hz
1.3
7.4
1.2
1.2
1.2
6.7
6.7
2.8
0.5
4.5
2.7
5.8
5.1
5.6
2.6
4.1
5.5
2.6
2.5
4.8
-0.5
-0.5
1.6
3.4
-0.3
3.1
2.9
2.7
4.3
4.3
4.4
2.1
1.8
1.6
1.7
-2.1
2 000 Hz
-15.9
-8.9
-16.0
-16.0
-16.1
-9.0
-9.0
-14.3
-13.1
-17.5
-14.5
-11.9
-13.1
-12.1
-14.6
-18.4
-12.1
-14.6
-14.7
-13.3
-17.2
-17.2
-12.5
-19.7
-14.2
-20.4
-8.9
-21.2
-13.5
-13.4
-13.4
-22.5
-23.1
-23.4
-23.3
-19.4
4 000 Hz
-69.5
-59.2
-69.6
-69.7
-69.8
-57.0
-57.0
-67.9
-68.1
-100.0
-68.0
-68.0
-70.2
-68.2
-68.2
-100.0
-68.3
-68.4
-68.6
-70.3
-69.3
-69.3
-70.2
-100.0
-71.4
-100.0
-58.5
-100.0
-70.2
-70.2
-70.1
-100.0
-100.0
-100.0
-100.0
-73.2
Pike 1 Project
March 2015
Noise Source
Transformer
Transformer
Transformer
VRU Compressor
VRU Compressor
Gas Boot Compressor
HP BFW Pump
HP BFW Pump
HP BFW Pump
Sludge Centrifuge
Location
Pike1 Substation
Pike1 Substation
Pike1 Substation
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1b
Pike 1 Well pad
Pike1 Phase 1a
Pike1 Phase 1a
Pike1 Phase 1b
Pike 1 Well pad
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1b
Pike 1 Well pad
Pike1 Phase 1b
Pike 1 Well pad
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1a
Pike1 Phase 1a
Pike 1 Well pad
Pike1 Phase 1a
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike 1 Well pad
Pike 1 Well pad
Pike1 Phase 1b
Pike1 Phase 1b
Pike1 Phase 1b
Pike 1 Well pad
dBA
7.4
7.3
7.2
7.2
6.6
6.3
6.1
5.7
5.7
5.5
5.4
5.0
4.6
4.4
4.3
4.1
4.1
3.4
3.2
2.5
2.2
2.0
1.6
1.6
1.5
1.1
1.1
1.0
0.7
0.6
0.6
0.1
0.1
31.5 Hz
14.1
14.1
14.0
13.9
13.5
15.7
13.2
14.4
14.4
15.5
12.8
12.6
12.4
24.1
12.3
20.5
12.2
11.8
11.7
18.9
18.8
11.1
13.7
14.7
15.0
14.5
14.5
10.6
10.4
11.6
8.4
13.9
10.1
63 Hz
16.8
16.8
16.7
13.3
13.0
15.6
12.7
14.2
14.2
15.3
12.3
12.0
11.8
21.9
11.7
13.3
11.6
11.2
11.0
11.7
11.6
10.4
11.5
12.5
12.9
12.3
12.3
9.9
9.7
9.5
5.2
11.7
9.4
125 Hz
17.5
17.4
17.4
13.2
12.8
13.4
12.5
12.1
12.1
13.1
12.1
11.8
11.6
10.6
11.4
14.1
11.3
10.8
10.7
12.4
12.4
10.0
8.2
9.3
9.6
9.1
9.1
9.3
9.1
6.2
4.0
8.4
8.7
250 Hz
10.1
10.0
9.9
10.9
10.3
9.8
10.0
8.3
8.3
9.2
9.4
9.1
8.8
5.4
8.5
8.3
8.4
7.8
7.6
6.4
6.5
6.6
6.4
5.8
5.7
5.3
5.3
5.8
5.5
4.4
3.4
4.5
5.0
500 Hz
6.8
6.7
6.6
5.9
5.3
5.0
4.8
5.2
5.2
4.2
4.0
3.6
3.2
2.1
2.9
1.0
2.7
2.0
1.6
-1.0
-1.1
0.4
-0.1
-0.3
-0.4
-0.8
-0.9
-0.8
-1.2
-0.3
1.0
-1.9
-1.9
1 000 Hz
-5.1
-5.2
-5.3
0.6
-0.4
-1.3
-1.1
-1.5
-1.6
-2.6
-2.3
-2.9
-3.5
-1.1
-3.9
-4.8
-4.2
-5.3
-5.8
-5.4
-7.3
-7.7
-7.6
-6.7
-7.3
-7.5
-7.5
-9.6
-10.1
-7.4
-7.9
-9.1
-11.2
2 000 Hz
-29.9
-30.2
-30.4
-25.7
-27.7
-15.3
-29.2
-16.9
-17.0
-18.2
-31.7
-33.0
-34.3
-20.7
-35.3
-17.3
-35.9
-38.3
-39.3
-18.9
-21.9
-43.5
-30.4
-25.9
-27.7
-27.5
-27.6
-47.6
-48.9
-28.4
-26.5
-30.9
-51.3
4 000 Hz
-100.0
-100.0
-100.0
-100.0
-100.0
-59.9
-100.0
-71.8
-71.8
-65.5
-100.0
-100.0
-100.0
-70.5
-100.0
-68.5
-100.0
-100.0
-100.0
-80.3
-81.6
-100.0
-100.0
-74.6
-78.3
-78.4
-78.6
-100.0
-100.0
-81.2
-80.0
-88.8
-100.0
Notes:
Octave band sound levels are linear (i.e., not A-weighted).
Only those noise sources with dBA sound level contributions greater than or equal to zero shown.
Pike 1 Project
March 2015
Trapper's Cabin
Noise Source
dBA
31.5 Hz
63 Hz
125 Hz
250 Hz
500 Hz
1 000 Hz
2 000 Hz
Pike 1 Well pad
Location
32.5
33.5
33.3
27.3
26.3
27.4
30.2
24.4
4 000 Hz
1.7
Pike 1 Well pad
31.7
34.8
34.6
27.9
27.0
27.7
29.7
21.0
-12.7
Pike 1 Well pad
29.4
33.4
33.1
26.4
25.3
25.8
27.4
17.2
-22.1
Pike 1 Well pad
27.2
32.2
31.8
25.0
23.8
24.1
25.2
13.6
-31.6
Pike 1 Well pad
18.7
20.1
19.8
20.6
19.8
16.9
15.2
1.2
-51.8
Pike 1 Well pad
17.8
27.1
26.6
19.3
17.2
16.1
14.7
-5.8
-85.1
Pike 1 Well pad
17.3
19.3
18.9
19.7
18.7
15.6
13.5
-1.8
-59.8
Pike 1 Well pad
17.1
19.1
18.7
19.5
18.5
15.4
13.3
-2.2
-61.1
Pike 1 Well pad
17.0
19.1
18.8
19.5
18.5
15.4
13.2
-2.4
-61.4
Pike 1 Well pad
15.2
18.0
17.6
18.2
17.0
13.7
11.1
-6.3
-72.6
Emergency Generator
Pike1 Phase 1a
14.8
25.9
22.6
23.5
21.3
10.2
-3.0
-32.2
-100.0
Emergency Generator
Pike1 Phase 1b
14.5
25.7
22.3
23.3
21.0
9.8
-3.5
-33.3
-100.0
Pike 1 Well pad
13.4
17.0
16.6
17.1
15.7
12.1
8.8
-10.6
-84.6
Pike 1 Well pad
13.0
16.8
16.4
16.9
15.4
11.7
8.3
-11.7
-87.6
Pike 1 Well pad
11.1
15.8
15.3
15.7
14.0
9.9
5.7
-16.7
-100.0
Pike 1 Well pad
10.7
15.5
15.1
15.4
13.7
9.5
5.2
-17.7
-100.0
Pike1 Phase 1a
10.6
18.5
21.2
20.2
14.9
8.7
-1.6
-26.2
-100.0
Pike1 Phase 1a
10.5
18.5
21.2
20.1
14.9
8.7
-1.6
-26.3
-100.0
Pike1 Phase 1a
10.5
18.5
21.2
20.1
14.8
8.6
-1.6
-26.3
-100.0
Pike1 Phase 1a
10.5
18.5
21.2
20.1
14.8
8.6
-1.7
-26.4
-100.0
Pike1 Phase 1a
10.5
18.5
21.1
20.1
14.8
8.6
-1.7
-26.5
-100.0
Pike1 Phase 1a
10.4
18.5
21.1
20.1
14.8
8.6
-1.7
-26.6
-100.0
Pike1 Phase 1a
10.4
18.4
21.1
20.1
14.8
8.5
-1.8
-26.6
-100.0
Pike1 Phase 1a
10.4
18.4
21.1
20.0
14.7
8.5
-1.8
-26.7
-100.0
Pike1 Phase 1a
10.4
18.4
21.1
20.0
14.7
8.5
-1.8
-26.8
-100.0
Pike1 Phase 1a
10.4
18.4
21.1
20.0
14.7
8.5
-1.9
-26.8
-100.0
Pike1 Phase 1a
10.3
18.4
21.1
20.0
14.7
8.4
-1.9
-26.9
-100.0
Pike1 Phase 1b
10.3
18.4
21.0
20.0
14.6
8.4
-2.0
-27.1
-100.0
Pike1 Phase 1b
10.3
18.3
21.0
20.0
14.6
8.4
-2.0
-27.1
-100.0
Pike1 Phase 1b
10.3
18.3
21.0
19.9
14.6
8.3
-2.0
-27.2
-100.0
Pike1 Phase 1b
10.2
18.3
21.0
19.9
14.6
8.3
-2.1
-27.2
-100.0
Pike1 Phase 1b
10.2
18.3
21.0
19.9
14.6
8.3
-2.1
-27.3
-100.0
Pike1 Phase 1b
10.2
18.3
21.0
19.9
14.5
8.3
-2.1
-27.4
-100.0
Pike1 Phase 1b
10.2
18.3
21.0
19.9
14.5
8.3
-2.2
-27.4
-100.0
Pike 1 Project
March 2015
Noise Source
dBA
31.5 Hz
63 Hz
125 Hz
250 Hz
500 Hz
1 000 Hz
2 000 Hz
4 000 Hz
Pike1 Phase 1b
Location
10.2
18.3
20.9
19.9
14.5
8.2
-2.2
-27.5
-100.0
Pike1 Phase 1b
10.1
18.3
20.9
19.8
14.5
8.2
-2.2
-27.6
-100.0
Pike1 Phase 1b
10.1
18.2
20.9
19.8
14.5
8.2
-2.3
-27.6
-100.0
Pike1 Phase 1b
10.1
18.2
20.9
19.8
14.5
8.2
-2.3
-27.7
-100.0
Pike1 Phase 1a
9.9
27.6
26.3
20.3
11.3
8.1
0.2
-22.5
-100.0
Pike1 Phase 1a
9.9
27.7
26.4
20.3
11.3
8.2
0.2
-22.4
-100.0
Pike 1 Well pad
9.9
15.1
14.6
14.9
13.1
8.7
4.2
-19.8
-100.0
Pike1 Phase 1a
9.8
27.6
26.3
20.2
11.2
8.0
0.0
-22.9
-100.0
Pike1 Phase 1a
9.8
27.6
26.3
20.2
11.2
8.0
0.0
-22.8
-100.0
Pike1 Phase 1a
9.8
27.6
26.3
20.3
11.2
8.1
0.1
-22.6
-100.0
Pike1 Phase 1a
9.7
27.5
26.2
20.2
11.1
7.9
-0.1
-23.0
-100.0
Pike1 Phase 1b
9.7
27.5
26.2
20.1
11.1
7.9
-0.2
-23.2
-100.0
Pike 1 Well pad
9.7
15.0
14.5
14.8
12.9
8.5
3.9
-20.4
-100.0
Pike1 Phase 1b
9.6
27.4
26.1
20.1
11.0
7.8
-0.3
-23.5
-100.0
Pike1 Phase 1b
9.6
27.5
26.2
20.1
11.0
7.8
-0.3
-23.4
-100.0
Pike 1 Well pad
9.6
15.0
14.5
14.8
12.9
8.5
3.8
-20.6
-100.0
Pike1 Phase 1b
9.5
27.4
26.1
20.0
10.9
7.7
-0.5
-23.8
-100.0
Pike1 Phase 1b
9.5
27.4
26.1
20.0
10.9
7.7
-0.4
-23.7
-100.0
Pike1 Phase 1b
9.5
27.4
26.1
20.0
11.0
7.7
-0.4
-23.6
-100.0
Pike1 Phase 1b
9.3
22.4
25.1
18.6
12.5
7.4
-0.6
-24.5
-100.0
Pike1 Phase 1b
9.3
22.4
25.1
18.6
12.5
7.4
-0.5
-24.4
-100.0
Transformer
Pike1 Substation
8.9
14.8
17.5
18.5
11.5
8.6
-3.0
-27.5
-100.0
Transformer
Pike1 Substation
8.8
14.7
17.4
18.5
11.4
8.5
-3.1
-27.8
-100.0
Transformer
Pike1 Substation
8.7
14.6
17.3
18.4
11.3
8.4
-3.3
-28.0
-100.0
Pike 1 Well pad
8.5
14.4
13.8
14.0
11.9
7.3
2.1
-24.0
-100.0
Pike 1 Well pad
8.1
22.5
21.8
13.8
10.3
7.2
1.9
-32.3
-100.0
Pike1 Phase 1a
8.0
15.6
18.3
17.3
12.2
6.3
-3.5
-27.0
-100.0
Pike1 Phase 1a
7.9
15.5
18.2
17.2
12.2
6.1
-3.8
-27.5
-100.0
Pike1 Phase 1a
7.9
15.5
18.2
17.2
12.2
6.1
-3.7
-27.5
-100.0
Pike1 Phase 1a
7.9
15.5
18.2
17.2
12.2
6.2
-3.6
-27.3
-100.0
Pike1 Phase 1a
7.9
15.6
18.3
17.3
12.1
6.2
-3.6
-27.2
-100.0
Pike1 Phase 1a
7.9
15.6
18.3
17.3
12.1
6.2
-3.5
-27.1
-100.0
Pike1 Phase 1b
7.7
15.3
18.0
17.0
11.9
6.0
-4.1
-28.3
-100.0
Pike1 Phase 1b
7.6
15.3
18.0
17.0
11.9
5.9
-4.2
-28.5
-100.0
Pike1 Phase 1b
7.6
15.4
18.0
17.0
12.0
5.8
-4.1
-28.2
-100.0
Pike1 Phase 1b
7.6
15.4
18.1
17.0
11.8
5.9
-4.1
-28.2
-100.0
Pike 1 Project
March 2015
Noise Source
dBA
31.5 Hz
63 Hz
125 Hz
250 Hz
500 Hz
1 000 Hz
2 000 Hz
4 000 Hz
Pike1 Phase 1b
Location
7.6
15.4
18.1
17.1
11.9
5.9
-4.0
-28.0
-100.0
Pike1 Phase 1b
7.5
15.3
18.0
16.9
11.9
5.8
-4.4
-28.5
-100.0
Pike 1 Well pad
7.5
13.9
13.3
13.4
11.2
6.3
0.7
-26.8
-100.0
IGF Discharge Pump
Pike1 Phase 1a
7.3
9.2
9.9
9.9
8.9
6.6
2.6
-21.4
-100.0
IGF Discharge Pump
Pike1 Phase 1a
7.1
9.2
9.9
9.8
8.8
6.5
2.3
-22.0
-100.0
Pike 1 Well pad
6.7
13.4
12.8
12.9
10.5
5.5
-0.5
-29.4
-100.0
Pike1 Phase 1a
6.4
8.9
9.6
9.8
8.6
4.6
2.3
-21.6
-100.0
IGF Discharge Pump
Pike1 Phase 1b
6.2
9.3
10.0
10.0
8.8
5.1
1.2
-22.3
-100.0
Pike1 Phase 1b
6.0
8.7
9.4
9.7
8.4
4.3
1.8
-22.5
-100.0
Pike 1 Well pad
6.0
13.1
12.5
12.5
10.0
4.8
-1.5
-31.5
-100.0
Pike1 Phase 1a
5.8
8.9
9.6
9.8
8.6
4.6
0.6
-23.2
-100.0
Pike1 Phase 1b
5.8
13.0
15.7
14.6
9.3
5.0
-5.3
-30.4
-100.0
Pike1 Phase 1b
5.8
8.7
9.4
9.4
8.3
4.0
1.5
-23.2
-100.0
Pike1 Phase 1b
5.6
22.5
15.2
16.2
10.0
2.2
-5.6
-26.2
-100.0
Pike1 Phase 1a
5.1
22.2
14.9
15.9
9.6
1.5
-6.7
-28.1
-100.0
Pike1 Phase 1a
5.1
22.3
14.9
15.9
9.7
1.5
-6.7
-28.1
-100.0
Pike 1 Well pad
5.1
12.6
12.0
12.0
9.3
3.8
-2.9
-34.4
-100.0
Pike1 Phase 1a
4.9
13.0
15.7
14.6
9.3
3.0
-7.4
-32.5
-100.0
Pike1 Phase 1a
4.9
13.0
15.7
14.6
9.3
3.0
-7.3
-32.4
-100.0
Pike1 Phase 1b
4.8
22.1
14.7
15.7
9.4
1.1
-7.2
-29.1
-100.0
Pike1 Phase 1b
4.7
12.8
15.5
14.4
9.0
2.7
-7.7
-33.2
-100.0
Blowdown Pond Pump
Pike1 Phase 1b
4.7
7.5
8.2
8.1
7.0
2.9
0.5
-23.9
-100.0
Pike1 Phase 1a
4.6
12.2
14.9
13.9
8.9
2.9
-7.1
-30.8
-100.0
Pike1 Phase 1a
4.6
12.2
14.9
13.9
8.9
2.9
-7.1
-30.7
-100.0
Pike1 Phase 1a
4.6
12.2
14.9
13.9
8.9
2.9
-7.0
-30.6
-100.0
Pike1 Phase 1a
4.6
12.3
14.9
14.0
8.8
2.9
-7.0
-30.6
-100.0
Pike1 Phase 1a
4.6
12.3
15.0
14.0
8.8
2.9
-7.0
-30.5
-100.0
Pike 1 Well pad
4.6
12.3
11.7
11.6
8.8
3.2
-3.8
-36.4
-100.0
Pike1 Phase 1a
4.5
12.1
14.8
13.8
8.9
2.8
-7.1
-30.7
-100.0
Pike 1 Well pad
4.5
12.2
11.6
11.5
8.7
3.2
-3.8
-36.3
-100.0
IGF Discharge Pump
Pike1 Phase 1b
4.4
8.9
9.4
9.0
7.3
2.2
0.0
-25.2
-100.0
Pike1 Phase 1b
4.1
11.9
14.6
13.6
8.3
2.3
-7.8
-32.2
-100.0
Pike1 Phase 1b
4.1
12.0
14.6
13.6
8.4
2.4
-7.7
-31.8
-100.0
Blowdown Pond Pump
Pike1 Phase 1a
4.0
7.5
8.2
8.2
6.9
2.8
-1.4
-24.0
-100.0
Blowdown Pond Pump
Pike1 Phase 1a
4.0
7.5
8.2
8.2
6.9
2.8
-1.4
-24.0
-100.0
Blowdown Pond Pump
Pike1 Phase 1a
4.0
7.5
8.2
8.2
6.9
2.8
-1.4
-24.0
-100.0
Pike 1 Project
March 2015
Noise Source
dBA
31.5 Hz
63 Hz
125 Hz
250 Hz
500 Hz
1 000 Hz
2 000 Hz
Pike1 Phase 1b
Location
4.0
11.9
14.6
13.6
8.3
2.3
-7.9
-32.3
4 000 Hz
-100.0
Pike 1 Well pad
4.0
12.0
11.4
11.2
8.3
2.6
-4.8
-38.4
-100.0
Pike 1 Well pad
3.9
12.0
11.3
11.2
8.3
2.5
-4.9
-38.7
-100.0
Blowdown Pond Pump
Pike1 Phase 1b
3.7
7.4
8.1
8.0
6.7
2.5
-1.7
-26.4
-100.0
Pike 1 Well pad
3.7
11.9
11.2
11.1
8.1
2.3
-5.2
-39.3
-100.0
Pike 1 Well pad
3.3
11.7
11.0
10.8
7.8
1.8
-5.9
-40.8
-100.0
Pike1 Phase 1a
2.5
13.7
13.3
11.3
7.0
0.7
-8.7
-33.7
-100.0
Pike1 Phase 1a
2.4
13.6
13.3
11.2
6.9
0.6
-8.7
-33.9
-100.0
Pike 1 Well pad
2.3
11.2
10.5
10.2
6.9
0.7
-7.6
-44.5
-100.0
Pike1 Phase 1b
2.2
13.5
13.1
11.1
6.7
0.4
-9.1
-34.7
-100.0
Pike1 Phase 1b
2.2
13.5
13.1
11.1
6.7
0.4
-9.1
-34.7
-100.0
Pike1 Phase 1b
2.2
13.5
13.2
11.1
6.7
0.4
-9.1
-34.6
-100.0
IGF Discharge Pump
Pike1 Phase 1b
2.2
8.5
8.4
7.2
4.8
-1.2
-1.3
-26.3
-100.0
IGF Discharge Pump
Pike1 Phase 1a
2.1
9.0
9.4
8.6
6.3
0.5
-5.1
-30.5
-100.0
Blowdown Pond Pump
Pike1 Phase 1b
2.1
7.3
7.8
7.5
5.8
0.9
-4.5
-31.0
-100.0
Pike 1 Well pad
2.0
11.0
10.3
10.0
6.7
0.3
-8.2
-45.7
-100.0
Pike 1 Well pad
1.6
10.8
10.1
9.8
6.4
-0.1
-8.8
-47.1
-100.0
Pike 1 Well pad
1.6
10.8
10.1
9.7
6.4
-0.1
-8.8
-47.2
-100.0
Pike 1 Well pad
1.6
10.8
10.1
9.8
6.4
-0.1
-8.8
-47.1
-100.0
Pike 1 Well pad
1.4
10.7
10.0
9.6
6.2
-0.4
-9.2
-48.1
-100.0
Pike 1 Well pad
1.1
10.6
9.8
9.4
5.9
-0.8
-9.8
-49.3
-100.0
Pike 1 Well pad
1.0
10.5
9.8
9.4
5.8
-0.8
-9.9
-49.6
-100.0
Pike 1 Well pad
0.8
10.4
9.7
9.2
5.7
-1.0
-10.2
-50.2
-100.0
Pike1 Phase 1a
0.6
11.5
11.2
9.2
4.9
-1.1
-10.1
-34.2
-100.0
Pike1 Phase 1a
0.6
11.5
11.2
9.2
5.0
-1.0
-10.1
-34.2
-100.0
Pike1 Phase 1b
0.5
11.4
11.1
9.1
4.9
-1.2
-10.2
-34.4
-100.0
Pike1 Phase 1b
0.4
11.3
11.0
9.0
4.8
-1.3
-10.5
-35.0
-100.0
Notes:
Octave band sound levels are linear (i.e., not A-weighted).
Only those noise sources with dBA sound level contributions greater than or equal to zero shown.
Attachment D6
Noise Impact Assessment
Pike 1 Project
March 2015
Licensee:
Facility name:
Pike 1 Project Amendment Application
Type:
Steam Assisted Gravity Drainage
Legal location:
Townships 73 to 75, Ranges 04 to 07 - W4M
Contact:
Erin Sumner
Telephone: (403) 213-8146
1. Permissible Sound Level (PSL) Determination (Directive 038, Section 2)
(Note that the PSL for a pre-1988 facility undergoing modifications may be the sound pressure level (SPL) that
currently exists at the residence if no complaint exists and the current SPL exceeds the calculated PSL from
Section 2.1.)
Complete the following for the nearest or most impacted residence(s):
Distance
Direction
Daytime
Class A
from
from
BSL (dBA) adjustment adjustment
Facility
Facility
(dBA)
(dBA)
Class B
adjustment
(dBA)
Nighttime
PSL (dBA)
Daytime
PSL(dBA)
730 m
East
40
10
0
0
40
50
1 500 m
All
Directions
40
10
0
0
40
50
2. Sound Source Identification
For the new and existing equipment, identify major sources of noise from the facility, their associated sound power
level (PWL) or sound pressure level (SPL), the distance (far or free field) at which it was calculated or measured, and
whether the sound data are from vendors, field measurement, theoretical estimates, etc.
Predicted
New Equipment
Listed in
Appendix III
Predicted
Existing
Equipment/Facility
Listed in
Appendix III
OR
X PWL (dBA)
X SPL (dBA)
X PWL (dBA)
X SPL (dBA)
Measured
X PWL (dBA)
X SPL (dBA)
OR
Data source
Measurements /
Calculations
Distance
calculated or
measured (m)
Measured
X PWL (dBA)
X SPL (dBA)
Data source
Measurements /
Calculations
Distance
calculated or
measured (m)
3. Operating Conditions
When using manufacturer’s data for expected performance, it may be necessary to modify the data to account for
actual operating conditions (for example, indicate conditions such as operating with window/doors open or closed).
Describe any considerations and assumptions used in conducting engineering estimates:
Equipment assumed to be operating at all times at maximum capacity
Pike 1 Project
March 2015
4. Modelling Parameters
If modelling was conducted, identify the parameters used (see Section 3.5.1):
Ground absorption 0.6, Temperature 100C, Relative Humidity 70%, all receptors downwind,
Following ISO 9613
5. Predicted Sound Level/Compliance Determination
Identify the predicted overall (cumulative) sound level at the nearest of most impacted residence. Typically, only the
nighttime sound level is necessary, as levels do not often change from daytime to nighttime. However, if there are
differences between day and night operations, both levels must be calculated.
Predicted sound level to the nearest or most impacted residence from new facility (including any existing facilities):
Theoretical 1 500 m Receptor
Modeled Leq-Night = 36.5 dBA,
ASL = 40.0 dBA, Overall Leq-Night = 38.8 dBA,
PSL-Night: 45 dBA
ASL = 35.0 dBA, Overall Leq-Night = 39.5 dBA,
PSL-Night: 40 dBA
Trapper's cabin
Modeled Leq-Night = 37.6 dBA,
Is the predicted sound level less than the permissible sound level? YES
If YES, go to number 7
Mitigation is required to obtain modeled noise level of 37.6 dBA at trapper's cabin. Current mitigation
recommendation is to orient the nearest well pad (730 m to the west of the trapper's cabin) such that the building
doors point west. The noise model indicates that the noise levels at the trapper's cabin should be below 40 dBA until
well pads start to encroach within approximately 1 200 m. At such time, Devon will revisit the noise model to
determine the specific noise mitigation required to maintain a noise level below 40 dBA at the trapper’s cabin based
on more detailed well pad locations and pad site orientation.
6. Compliance Determination/Attenuation Measures
(a) If 5 is NO, identify the noise attenuation measures the licensee is committing to:
Predicted sound level to the nearest or most impacted residence from the facility (with noise attenuation measures):
N/A
If YES, go to number 7
Is the predicted sound level less than the permissible sound level? YES
(b) If 6 (a) is NO or the licensee is not committing to any noise attenuation measures, the facility is not in
compliance. If further attenuation measures are not practical, provide the reasons why the measures proposed to
reduce the impacts are not practical.
Note: If 6 (a) is NO, the Noise Impact Assessment must be included with the application filed as non-routine.
7. Explain what measures have been taken to address construction noise.
Advising nearby residents of significant noise sources and appropriately scheduling
Mufflers on all internal combustion engines
Taking advantage of acoustical screening
Limiting vehicle access during night-time
8. Analyst’s Name : Steven Bilawchuk, M.Sc., P.Eng.
Company: ACI Acoustical Consultants Inc.
Title: Director
Telephone: (780) 414-6373
Date: March 18, 2015
Attachment E
Amended Hydrogeology Assessment
Pike 1 Project
March 2015
ATTACHMENT E – HYDROGEOLOGY ASSESSMENT
TABLE OF CONTENTS
PAGE
1.0
INTRODUCTION ............................................................................................................... 1
2.0
STUDY AREA ................................................................................................................... 2
3.0
ASSESSMENT APPROACH ............................................................................................ 3
3.1
Hydrogeology Issues ............................................................................................. 3
3.2
Selection of Valued Environmental Components .................................................. 3
4.0
METHODS ........................................................................................................................ 5
4.1
Geologic Mapping ................................................................................................. 5
4.2
Grand Rapids C Salinity Mapping ......................................................................... 6
4.3
Groundwater Withdrawal and Wastewater Disposal Assessment......................... 8
4.4
Aquifer Productivity Assessment ......................................................................... 14
4.5
Groundwater-Surface Water Flux Assessment ................................................... 15
4.6
Assessment of Disposal Fluid Migration.............................................................. 15
5.0
BASELINE CASE ........................................................................................................... 17
5.1
Hydrogeological Setting Grand Rapids C Aquifer ............................................... 17
5.1.1 Hydrogeologic Mapping ........................................................................... 17
5.1.2 Salinity Mapping ...................................................................................... 18
5.1.3 Conceptualization of Groundwater Flow and Distribution of Total
Dissolved Solids in the Grand Rapids C Aquifer ..................................... 19
5.2
Groundwater Withdrawal and Wastewater Disposal ........................................... 20
5.2.1 Surface Waterbodies and Near-Surface Water Table ............................. 44
5.2.2 Ethel Lake Aquifer ................................................................................... 46
5.2.3 Bonnyville Sand Aquifer........................................................................... 46
5.2.4 Empress Terrace Aquifer ......................................................................... 46
5.2.5 Grand Rapids C Aquifer........................................................................... 47
5.2.6 Basal McMurray Aquifer .......................................................................... 47
6.0
APPLICATION CASE ..................................................................................................... 49
6.1
6.1.1 Water Supply and Wastewater Disposal Usage ...................................... 49
Attachment E – Table of Contents
Pike 1 Project
March 2015
PAGE
6.1.6
6.1.7
6.1.8
Grand Rapids C Aquifer........................................................................... 52
Basal McMurray Aquifer .......................................................................... 55
Summary of Application Case Impact Ratings due to Groundwater
Withdrawal and Wastewater Disposal ..................................................... 56
7.0
PLANNED DEVELOPMENT CASE................................................................................ 57
7.1
7.1.1 Water Supply and Wastewater Disposal Usage ...................................... 57
7.1.6 Grand Rapids C Aquifer........................................................................... 84
7.1.7 Basal McMurray Aquifer .......................................................................... 85
7.1.8 Summary of Planned Development Case Impact Ratings due to
Groundwater Withdrawal and Wastewater Disposal ............................... 86
8.0
MONITORING ................................................................................................................. 88
9.0
REFERENCES ................................................................................................................ 89
Pike 1 Project
March 2015
PAGE
LIST OF TABLES
Table E-1:
Table E-2:
Table E-3:
Table E-4:
Table E-5:
Table E-6:
Table E-7:
Table E-8:
Table E-9:
Table E-10:
Table E-11:
Table E-12:
Table E-13:
Table E-14:
Table E-15:
Table E-16:
Table E-17:
Table E-18:
Table E-19:
Table E-20:
Table E-21:
Table E-22:
Table E-23:
Table E-24:
Table E-25:
Measured Dried TDS Values from the Grand Rapids C Aquifer ......................... 7
Theoretical Observation Points in Numerical Model ......................................... 10
Proposed Source and Disposal Well Locations ................................................ 11
Proposed Testing and Monitoring Well Locations ............................................. 12
Amended Pike 1 Total Projected Water Use Rates .......................................... 13
Surface Water Stations ..................................................................................... 15
Baseline Case – Projected Groundwater Withdrawal Rates
(m3/d), Ethel Lake Aquifer ................................................................................. 21
(m3/d), Empress Terrace Aquifer ...................................................................... 22
(m3/d), Empress Channel Aquifer...................................................................... 23
(m3/d), Empress Channel Aquifer...................................................................... 24
(m3/d), Grand Rapids C Aquifer ........................................................................ 25
(m3/d), Grand Rapids C Aquifer ........................................................................ 28
(m3/d), Upper and Middle Clearwater Aquifers ................................................. 31
(m3/d), Upper and Middle Clearwater Aquifers ................................................. 34
Baseline Case – Projected Groundwater Withdrawal and
Wastewater Disposal Rates (m3/d), Basal McMurray Aquifer ........................... 37
Baseline Case – Projected Groundwater Withdrawal and
Wastewater Disposal Rates (m3/d), Basal McMurray Aquifer ........................... 40
(m3/d) – Grosmont Aquifer ................................................................................ 43
Predicted Change in Groundwater Discharge to Surface
Waterbodies ...................................................................................................... 44
Predicted Change in Hydraulic Head ................................................................ 45
Maximum Particle Travel Distances Starting from Disposal
Wells – Base Effective Porosity 0.3 .................................................................. 53
Effective Porosities and Maximum Particle Travel Distances ........................... 54
Maximum Particle Travel Distance Starting 4000 mg/L TDS
Contour ............................................................................................................. 54
Application Case – Impact Due to Groundwater Withdrawal and
Wastewater Disposal ........................................................................................ 56
Planned Development Case – Projected Groundwater
Withdrawal Rates, Ethel Lake Aquifer............................................................... 58
Withdrawal Rates, Bonnyville Sand Aquifer ...................................................... 59
Pike 1 Project
March 2015
PAGE
Table E-26:
Table E-27:
Table E-28:
Table E-29:
Table E-30:
Table E-31:
Table E-32:
Table E-33:
Table E-34:
Table E-35:
Withdrawal Rates, Empress Terrace Aquifer .................................................... 60 Planned Development Case – Projected Groundwater
Withdrawal Rates, Empress Channel Aquifer ................................................... 61 Planned Development Case – Projected Groundwater
Withdrawal Rates, Grand Rapids C Aquifer ...................................................... 64 Planned Development Case – Projected Groundwater
Withdrawal Rates, Grand Rapids C Aquifer ...................................................... 67 Planned Development Case – Projected Groundwater
Withdrawal Rates, Upper and Middle Clearwater Aquifers ............................... 70 Planned Development Case – Projected Groundwater
Withdrawal Rates, Upper and Middle Clearwater Aquifers ............................... 73 Planned Development Case – Projected Groundwater
Withdrawal Rates, Basal McMurray Aquifer...................................................... 76 Planned Development Case – Projected Groundwater
Withdrawal Rates, Basal McMurray Aquifer...................................................... 79 Planned Development Case – Projected Wastewater Disposal
Rates, Devonian................................................................................................ 82 Planned Development Case – Impact Due to Groundwater
Withdrawal and Wastewater Disposal............................................................... 87 LIST OF FIGURES
Figure E-1: Figure E-2: Figure E-3: Figure E-4: Figure E-5: Figure E-6: Figure E-7: Figure E-8: Figure E-9: Figure E-10: Figure E-11: Figure E-12: Figure E-13: Figure E-14: Figure E-15: Figure E-16: Figure E-17: Hydrogeology Regional and Local Study Areas................................................ 91 Cross Plot of Measured vs. Petrophysically Calculated TDS
from the Grand Rapids C Aquifer ...................................................................... 92 Proposed Source and Disposal Well Locations ................................................ 93 Proposed Monitoring and Testing Well Locations ............................................. 94 Proposed Withdrawal and Disposal Rates over Time ....................................... 95 Surface Waterbodies and Topography ............................................................. 96 Structure Map of the Grand Rapids B Aquitard................................................. 97 Structure Map of the Grand Rapids C Aquifer .................................................. 98 Gross Isopach Map of the Grand Rapids B Aquitard ........................................ 99 Grand Rapids C Net Porous Isopach Map ...................................................... 100 Regional Cross-section A – A' ........................................................................ 101 Regional Cross-section B – B' ........................................................................ 102 Grand Rapids C Total Dissolved Solids (mg/L) Map....................................... 103 Simulated Pre-Development Hydraulic Heads Grand Rapids C
Aquifer ............................................................................................................. 104 Simulated Pre-Development Hydraulic Heads Grand Rapids C
Aquifer ............................................................................................................. 105 Source and Disposal Rates – Baseline Case ................................................. 106 Existing, Approved and Planned Projects ....................................................... 107
Pike 1 Project
March 2015
PAGE
Figure E-18: Figure E-19: Figure E-20: Figure E-21: Figure E-22: Figure E-23: Figure E-24: Figure E-25: Figure E-26: Figure E-27: Figure E-28: Figure E-29: Figure E-30: Figure E-31: Figure E-32: Figure E-33: Figure E-34: Figure E-35: Figure E-36: Figure E-37: Figure E-38: Figure E-39: Figure E-40: Figure E-41: Figure E-42: Figure E-43: Simulated Change in Groundwater Discharge to Surface
Waterbodies (Streams) vs. Time..................................................................... 108 Simulated Change in Groundwater Discharge to Surface
Waterbodies (Lakes) vs. Time ........................................................................ 109 Simulated Change in Hydraulic Head vs. Time – Near-Surface
Water Table..................................................................................................... 110 Simulated Change in Hydraulic Head vs. Time – Ethel Lake
Aquifer ............................................................................................................. 111 Simulated Change in Hydraulic Head vs. Time – Bonnyville
Sand Aquifer ................................................................................................... 112 Simulated Change in Hydraulic Head vs. Time – Empress
Terrace Aquifer ............................................................................................... 113 Simulated Change in Hydraulic Head vs. Time – Grand Rapids
C Aquifer ......................................................................................................... 114 Simulated Change in Hydraulic Head – Baseline Case – Grand
Rapids C Aquifer – 2036 ................................................................................. 115 Simulated Change in Hydraulic Head vs. Time – Basal
McMurray Aquifer ............................................................................................ 116 Simulated Change in Hydraulic Head – Baseline Case – Basal
McMurray Aquifer – 2036 ................................................................................ 117 Source and Disposal Rates – Application Case.............................................. 118 Simulated Change in Hydraulic Head – Application Case –
Grand Rapids C Aquifer – 2036 ...................................................................... 119 Simulated Hydraulic Pressure Head at 08-21-074-05..................................... 120 Simulated Hydraulic Pressure Head at 11-33-074-05..................................... 121 Simulated Changes in Hydraulic Head at 13-36-074-07 ................................. 122 Simulated Changes in Hydraulic Head at 13-24-074-07 ................................. 123 Simulated Changes in Hydraulic Head at 09-10-075-05 ................................. 124 Forward Pathlines starting from Disposal Wells Application
Case; Grand Rapids C Aquifer........................................................................ 125 Comparison of Forward Pathlines using Base Effective
Porosities of 0.3, 0.2 and 0.1; Disposal Well 11-33-074-05 ............................ 126 Comparison of Forward Pathlines using Base Effective
Porosities of 0.3, 0.2 and 0.1; Disposal Well 08-21-074-05 ............................ 127 Forward Pathlines in Cross-section and Plan Views with Timeof-Travel; Disposal Well 11-33-074-05............................................................ 128 Forward Pathlines in Cross-section and Plan Views with Timeof-Travel; Disposal Well 08-21-074-05............................................................ 129 Simulated Change in Hydraulic Head – Application Case –
Basal McMurray Aquifer – 2036 ...................................................................... 130 Source and Disposal Rates – Planned Development Case ............................ 131 Simulated Change in Hydraulic Head – Planned Development
Case – Grand Rapids C Aquifer – 2036.......................................................... 132 Simulated Change in Hydraulic Head – Planned Development
Case – Basal McMurray Aquifer – 2036 ......................................................... 133
Pike 1 Project
March 2015
1.0
INTRODUCTION
This hydrogeology assessment has been prepared to evaluate the potential environmental
effects of the Amended Project, and to determine whether design changes associated with the
Amended Project affects the conclusions of the hydrogeology assessment conducted for the
Approved Project (Devon 2012). Changes in facility design of the Amended Project have
resulted in revisions to the water balance forecast for both source water and wastewater
disposal originally described and assessed for the Approved Project. The Amended Project
includes additional water source well locations to accommodate an increase in source water
demands. Disposal into a highly saline area of the Grand Rapids C Aquifer has been
incorporated into the Amended Project scheme to accommodate an increase in wastewater
disposal. Reallocation of wastewater disposal to Grand Rapids C Aquifer will also be used to
alleviate pressure build up in the Basal McMurray Aquifer, which might otherwise impact
bitumen resource recovery.
This assessment follows the hydrogeology assessment that was completed in support of the
Project Application with the updated planned water use for the Amended Project. It describes
baseline hydrogeological conditions and identifies and evaluates components of the Amended
Project that could potentially affect groundwater from a local and regional perspective. The
assessment includes an updated cumulative effects assessment based on projects that were
submitted and approved since the Project Application.
Attachment E – Page 1
Pike 1 Project
March 2015
2.0
STUDY AREA
The local study area (LSA) and regional study area (RSA) for the hydrogeology assessment are
shown on Figure E-1, and remain unchanged from the original application (for convenience,
figures for the hydrogeology assessment are located at the end of this section).
The hydrogeology LSA encompasses an area within Townships (Twp) 73 to 75 and Ranges
(Rge) 4 to 7 west of the fourth Meridian (W4M), which is approximately 1 140 km2. The
hydrogeology LSA occurs within the Winefred Lake and Christina Lake watersheds. The main
tributary to Winefred Lake is Sandy River and the main tributaries to Christina Lake are
Birch Creek and Sunday Creek.
The geology LSA encompasses an area within Twps 73 to 75 and Rges 4 to 7 W4M. The
geology LSA is contained within the hydrogeology LSA.
The RSA was defined on the basis of interpreted regional geology and groundwater flow
patterns. The extent of the RSA encompasses an area of approximately 30 000 km2 and is
defined by the following boundaries:
•
north – the Clearwater River, extending from the Saskatchewan border to the confluence
of the Athabasca River and the eastward flowing section of the Athabasca River to the
confluence of the Clearwater River;
•
east – the Saskatchewan border extending from the centre of Twp 69 to the
Clearwater River;
•
south – the centre of Twp 69 extending from the Saskatchewan border to the
Athabasca River; and
•
west – the northerly flowing portion of the Athabasca River, extending from the
centre of Twp 69 to 87.
Pike 1 Project
March 2015
3.0
ASSESSMENT APPROACH
The Amended Project can potentially affect groundwater through the operation of surface
facilities, groundwater withdrawal for steam generation, potable/utility and drilling requirements,
wastewater disposal and steam generation during the operation of steam assisted gravity
drainage (SAGD) wells. This section provides a summary of the objectives and assessment
criteria used for the hydrogeology assessment.
3.1
Hydrogeology Issues
Through the construction, production and post-production phases of the Amended Project, the
following components have the potential to affect groundwater resources:
•
operation of surface facilities has the potential to affect shallow groundwater quality
through the accidental release of fluids including: produced water, bitumen, diluents and
process related chemicals. Details regarding the infrastructure and fluids required for the
proposed facility were included in Section 2.0;
•
groundwater withdrawal and wastewater disposal have the potential to affect water table
elevations and hydraulic heads, which can in turn affect groundwater flux to or from
surface waterbodies. Wastewater disposal also has the potential to affect groundwater
quality due to wastewater migration; and
•
the injection of steam for SAGD production has the potential to affect groundwater
quality in the adjacent aquifers and aquitards due to the resulting thermal effects
surrounding the wellbores.
Only the planned groundwater withdrawal and wastewater disposal is changed as part of the
Amended Project due to changes in water efficiency of the water treatment facilities. The
potential impact from all other factors remains unchanged from the Project Application and are
not re-assessed as part of this work.
3.2
Selection of Valued Environmental Components
The seven hydrogeology valued environmental components previously selected remain
unchanged. They are listed below:
•
Surface Waterbodies – to correlate hydrogeology and surface water quantity
assessments;
•
Near-Surface Water Table – contains the shallowest water level below the Project Area
ground surface, within the Grand Centre Aquitard across most of the hydrogeology LSA.
Where eroded, it is within the Marie Creek Aquitard;
•
Ethel Lake Aquifer – the shallowest aquifer present below the Project Area;
•
Bonnyville Sand Aquifer – proposed utility and potable water source for the Amended
Project;
Pike 1 Project
March 2015
•
Empress Terrace Aquifer – proposed utility and potable water source for the Amended
Project;
•
Grand Rapids C Aquifer – proposed saline makeup water source and wastewater
disposal aquifer for the Amended Project; and
•
Basal McMurray Aquifer – a combination of proposed saline makeup water source and
wastewater disposal aquifer for the Amended Project.
A key modification is the proposed use of the Grand Rapids C Aquifer as a saline makeup water
source and wastewater disposal aquifer for the Amended Project. To support this Amendment
Application, and future regulatory applications, Devon has conducted work to evaluate the
suitability of the Grand Rapids C Aquifer as a wastewater disposal zone.
Recent work has identified that the Grand Rapids C Aquifer is saline beneath the Amended
Project, with hydrogeological properties and characteristics that make it locally well suited for
disposal. However, on a regional basis, the Grand Rapids C Aquifer has been identified by the
Alberta Energy Regulator (AER) as being above the base of groundwater protection (BGWP).
The BGWP was developed by the Alberta Geological Survey (AGS) in 2007 to provide the best
estimate of the depth at which saline groundwater (>4 000 mg/L total dissolved solids, TDS)
was likely to occur using the data available at the time. Recognizing that local variations exist
that are not captured by a regional assessment, the AER has developed a process for
redefining the BGWP at a given location based on information provided under Bulletin 2007-10.
Supplemental information (EUB 2007), characterization and assessment work provided in this
Amendment Application are intended to assess the overall suitability of the Grand Rapids C
Aquifer for disposal in the Project Area, as well as the specific requirements of Bulletin 2007-10.
Assessment of the Grand Rapids C Aquifer disposal zone comprises the following key
elements:
•
geologic mapping of the disposal zone;
•
geologic mapping of the overlying unit providing primary hydraulic containment;
•
salinity mapping of the proposed disposal zone;
•
assessment of the impact of disposal on groundwater resources;
•
assessment of the impact of disposal on groundwater quality; and
•
increased monitoring.
Development of the Grand Rapids C Aquifer for disposal will require the drilling, testing and
licencing of individual disposal wells as per the regulatory requirements of AER Directives 051:
Injection and Disposal Wells – Well Classifications, Completions, Logging, and Testing
Requirements and AER Directive 065: Resources Applications for Oil and Gas Reservoirs. The
licencing application process will provide additional assessment on specific locations as to the
suitability of the Grand Rapids C Aquifer for disposal, and ensure that any future disposal is
done safely within appropriate pressure limits and with an appropriate level of monitoring.
Pike 1 Project
March 2015
4.0
METHODS
Specific methods used to assess and evaluate the magnitude of potential impacts on the valued
environmental components compared to baseline conditions are discussed in the following
subsections.
4.1
Geologic Mapping
Detailed geologic mapping in the geology LSA was provided in the Project Application.
Additional mapping has been conducted, using open hole wireline logs, to assess the suitability
of the Grand Rapids C Aquifer for disposal. This includes mapping of the primary hydraulic
containment unit overlying the Grand Rapids C Aquifer, the Grand Rapids B Aquitard.
In the Project Application, the Grand Rapids Aquifer was described as comprising three major
coarsening upwards units (A, B and C). The Grand Rapids C Aquifer was identified as
equivalent to the Lower Grand Rapids, while the A and B units were grouped into an Upper
Grand Rapids hydrostratigraphic unit. For the Amendment Application, further definition of
hydrostratigraphic units within the Upper Grand Rapids is provided.
The Grand Rapids A and B consist of several sands bounded by shales and silty beds. These
beds can be divided into equivalent hydrostratigraphic units referred to as the Grand Rapids A
and B Aquifer and Aquitards, respectively, as illustrated on the type log in Figure E-9. The
Grand Rapids B Aquitard refers to the low permeability shale units between the Grand Rapids C
and B Aquifers, while the Grand Rapids A Aquitard refers to the shale units between the Grand
Rapids A and B Aquifers.
Updated geologic maps provided in the Amendment Application include structure and gross
isopach maps of the Grand Rapids B Aquitard, as well as structure and net porous sand
isopach maps of the Grand Rapids C Aquifer. Additionally, two regional structural cross sections
are also provided. Results of the geologic mapping are discussed in detail in Section 5.1.
The Grand Rapids B Aquitard and Grand Rapids C Aquifer were mapped over the entire Pike
Lands, and extended out to cover approximately 28 townships (Twp 073 to 076, Rge 02 to
08W4). Where well density allowed, the hydrostratigraphic units were correlated at a resolution
of one well per section; however, limited well control prevented this further to the east. A total of
776 well logs were used to correlate and map these hydrostratigraphic units.
The top of the Grand Rapid B Aquitard is defined as the upper limit of the fining upwards
sequence that directly overlies the thick sand unit forming the Grand Rapids C Aquifer. It can
also be expressed as the base of the overlying Grand Rapids B sand unit. Correlating the Grand
Rapids B Aquitard surface from well logs was based largely on the gamma ray log (GR),
calculated shale volume (VSH) and porosity log (Neutron/Density). The Grand Rapids B
Aquitard top was picked where log response indicated a transition from a fine-grained, shale
zone, into a coarser and more porous sand unit. A Grand Rapids B Aquitard structure map was
prepared using the correlated shale surface.
Pike 1 Project
March 2015
Similarly, a Grand Rapids C Aquifer top was correlated over the same area using the same well
logs. The top of the Grand Rapids C Aquifer is defined as the transition from a thick, relatively
clean sand package to a more clay-rich (higher GR and VSH) zone with reduced porosity. The
Grand Rapids C Aquifer top was picked where log response indicated a hydrostratigraphic
transition from a predominantly aquifer to aquitard setting. A Grand Rapids C Aquifer structure
map was prepared using the correlated sand surface.
Using the structure maps from the Grand Rapids B Aquitard and Grand Rapids C Aquifer, a
gross isopach map of the Grand Rapids B Aquitard was constructed. The isopach map
represents the interpreted thickness of the primary hydraulic containment unit overlying the
Grand Rapids C Aquifer. In some instances, the uppermost Grand Rapids C Aquifer displays
lower quality aquifer, with greater amounts of silts and shales. The thickness of the transitional
zone is not included in the Grand Rapids B Aquitard isopach. As such, the results of the Grand
Rapids B Aquitard isopach map is believed to be conservative, and in most cases represents an
‘effective’ aquitard thickness.
The Grand Rapids C Aquifer isopach map was updated in early 2014, and represents a net
porous sand thickness. The map was updated since the Project Application to include newly
acquired well data, as well as, provide greater geologic detail around the Sunday Creek
Channel. The net porous sand isopach was calculated within the interval between the top of the
Grand Rapids C Aquifer and Clearwater Shale, using a GR cutoff of 75 API or less and a
density porosity cutoff of 27% or greater.
4.2
Grand Rapids C Aquifer Salinity Mapping
Additional mapping is provided in the Amendment Application relating to the characterization of
groundwater quality within the Grand Rapids C Aquifer.
The primary objective was to map formation water salinity, as TDS, in the Grand Rapids C
Aquifer to characterize the formation fluid as being saline or non-saline, and to determine the
range of TDS and distribution. The mapping was achieved through the use of resistivity
measurements from well logs.
The determination of formation water salinity in the Grand Rapids C Aquifer is based on
petrophysically-derived TDS values, by first calculating water resistivity (Rw) from well logs using
Archie’s method,
=
∅
×
where:
∅ is total porosity,
is true resistivity (measured from the deep resistivity curve),
A and M are Archie coefficients for electrical rock properties tortuosity and cementation,
respectively.
Pike 1 Project
March 2015
Archie coefficients for electrical properties were not analyzed from core data; thus, a value of
1.7 for M (corresponding to a high porosity), and a value of 1.0 for A (corresponding to
unconsolidated sand) were used.
Water resistivity, Rw, was then converted to a calculated TDS value using the following industry
accepted equation,
= 10
.
.
.
This method assumes the zone analyzed is largely shale-free and 100% water saturated.
Therefore, intervals showing an increase in clay content or evidence suggesting the presence of
gas were excluded. Figure E-2 shows a cross plot of lab measured TDS versus calculated TDS
from petrophysics for the Grand Rapids C Aquifer. Table E-1 summaries measured TDS values
from water samples collected from the Grand Rapids C Aquifer. The measured TDS values
were determined from dried gravimetric analytical techniques, in accordance with Alberta
Environment and Sustainable Resource Development (ESRD) selected method for measuring
TDS (ESRD 2010). The cross plot indicates that the data show a strong correlation between the
measured TDS from water samples and the petrophysical calculated TDS values, with a
coefficient of determination (R2) of 0.96. The calculated TDS distribution mapped in the Grand
Rapids C Aquifer is discussed under Section 5.1 Hydrogeologic Setting Grand Rapids C
Aquifer.
Table E-1: Measured Dried TDS Values
from the Grand Rapids C Aquifer
Sample Location
1AA/16-32-074-05
100/01-23-073-06
100/10-04-074-05
1F1/03-11-075-06
1F1/15-15-075-06
1F1/05-17-075-06
1F1/03-10-075-06
1F1/12-15-075-06
1F1/13-24-074-07
1F1/13-36-074-07
100/01-10-075-06
100/11-25-074-07
1F2/14-30-073-07
1F1/11-22-075-06
1F1/03-27-075-06
1F1/01-28-075-06
1F1/04-16-075-06
100/01-23-075-06
100/12-19-075-05
1F2/15-19-075-06
1AA/09-10-075-05
TDS Value (mg/L)
42 500
54 400
30 000
13 900
6 140
4 230
12 000
6 370
9 000
7 500
9 060
9 620
2 240
3 700
2 900
4 200
5 060
4 790
4 300
3 000
5 400
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March 2015
4.3
Groundwater Withdrawal and Wastewater Disposal Assessment
The assessment of the effect of groundwater withdrawal and wastewater disposal was
completed using a numerical model of groundwater flow. This work assumes that a
representative elementary volume (Bear 1972) of the porous medium exists and can represent
the effective hydraulic behaviour of the medium. Groundwater flow within the study area was
interpreted to be normal gravity driven flow and can be represented by the fluid continuity
equation:
∂ 
∂h  ∂  ∂h  ∂  ∂h 
∂h
 Kx
 +  K y  +  K z  = S s
∂ ×  ∂ ×  ∂y  ∂y  ∂z  ∂z 
∂t
where:
x, y, z =
Cartesian coordinates (L),
h
=
hydraulic head (L),
Ss
=
specific storage (L-1),
K
=
hydraulic conductivity (L/t),
t
=
time.
The above equation is derived with the assumption that the principle directions of the hydraulic
conductivity tensor are uniform throughout the model domain and coincide with the axes of the
coordinate system (x, y, z). The major assumptions within the continuity equation and in its
application are that groundwater flow follows Darcy’s Law and the fluid throughout the model
domain has a constant density. Furthermore, in solving the fluid continuity equation it is
assumed that the hydraulic properties of saturated units (K and Ss) do not vary over time and
are independent of hydraulic head.
Groundwater flow was simulated in this study using the three dimensional FEFLOW v.6.2
simulator developed by DHI/Wasy GmbH (2014). FEFLOW was used to solve for mass
conservative groundwater flow within fully saturated porous media using finite element
discretization of the media. A summary of the numerical model, model construction and
calibration process is included in the Project Application (Devon 2012 and 2013).
An updated characterization of the Sunday Creek incision and the Grand Rapids C Aquifer
isopach map was incorporated in the numerical model to assess the migration of wastewater.
To assess the changes in hydraulic head directly at a simulated disposal or withdrawal well, the
simulated hydraulic head values were corrected for discretization errors (MacMillan and
Schumacher 2014).
Pike 1 Project
March 2015
The impact to valued environmental components for each of the potential receptors was
predicted by incorporating the projected pumping/disposal schedule into the model and
simulating the change in hydraulic head and groundwater flux within the hydrogeologic system
over a period of 100 years.
For each valued environmental component, the simulated changes in hydraulic head versus
time were plotted for selected theoretical observation points in the hydrogeology LSA (Obs1,
Obs2, Obs3 and/or Obs4; Table E-2). These four observation points were selected to be on
different sides of the Project Area in the vicinity of proposed source and disposal well locations
(Table E-3; Figure E-3) and to coincide with existing or proposed monitoring wells (Table E-4).
Due to the addition of Grand Rapids C Aquifer disposal, two additional disposal well locations
(102/11-33 and 103/08-21) have been identified (Table E-3; Figure E-4). It is expected that two
Grand Rapids C Aquifer wells (102/11-33 and 103/08-21) will provide sufficient injectivity for
disposal of the Amended Project forecast disposal volumes. Three contingent Grand Rapids C
Aquifer disposal wells (07-28, 11-34 and 10-04) have been identified in the event that future
injectivity testing (as per AER Directives 51 and 65) results in lower individual well injectivity
than expected.
Additional monitoring has been included in the Grand Rapids B sand for the Amended Project
(Table E-4) to monitor effects of disposal into the underlying Grand Rapids C Aquifer.
Maps of the Grand Rapids C and Basal McMurray Aquifers predicted drawdown are presented
for the year 2036. This year was selected to demonstrate the areal distribution of drawdown
near the end of the Amended Project water withdrawal and wastewater disposal schedule,
shortly after the rates have reached their maximum (Table E-5; Figure E-5). The same year was
chosen for the Baseline, Application and Planned Development Cases, for comparison
purposes.
The assessment methods described in this section are unchanged from the Project Application,
except for the incorporation of the updated representation of the Sunday Creek Channel incision
and the Grand Rapids C Aquifer isopach for the particle tracking simulations.
Pike 1 Project
March 2015
Table E-2: Theoretical Observation Points in Numerical Model
Aquifers
Obs Point #
Location
UTM
Easting (NAD27, 12)
UTM
Northing (NAD27, 12)
Relative Location
Surface
Location
Ethel
Lake
Bonnyville
Sand
Empress
Terrace
Grand
Rapids
C
McMurray
Obs1
11-33-074-05W4
517990
6145386
Northeast side of Project Area (on line
between Twp 074 and Twp 075); closest to
MEG CLRP
x
x
x
x
x
x
Obs2
13-24-074-07W4
503103
6142416
West side of Project Area; closest to CNRL
Kirby
x
x
x
not
present
x
not
present
Obs3
01-23-073-05W4
512556
6131386
South of Project Area in south end of the
McMurray pre-Cretaceous channel
x
not
present
/mapped
not present
/mapped
not
present
/mapped
x
x
Obs4
14-09-075-06W4
507912
6149055
North of the Project Area; closest to Devon
Jackfish projects
x
not
present
x
x
x
x
Note:
Symbol x denotes theoretical observation points that were used for a particular aquifer or at surface.
Pike 1 Project
March 2015
Table E-3: Proposed Source and Disposal Well Locations
Aquifer
Location
Status
Well Label on
Figure
Easting
(NAD27, 12)
Northing
(NAD27, 12)
CPF
Empress Terrace
07-34-074-06W4
Proposed
EMP/7-34
510508
6144914
Drilling
Bonnyville Sand
12-30-074-05W4
Hypothetical*
BNY/12-30
514457
6143661
F1/13-36-074-07W4
Existing
F1/13-36
502908
6145477
Water Use Type
Utility and Potable
Freshwater
Withdrawal
Grand Rapids C
Saline Source
Withdrawal
F1/13-24-074-07W4
Existing
F1/13-24
503106
6142354
F1/09-10-075-05W4
Proposed
F1/09-10
520308
6148397
06-05-074-05W4
Proposed
06-05
516620
6136796
06-31-073-05W4
Proposed
06-31
514604
6135079
11-25-073-06W4
Proposed
11-25
513410
6133764
Grand Rapids C
11-33-074-05W4
08-21-074-05W4
11-34-073-06W4
10-04-074-05W4
Proposed
Proposed
Contingent
Contingent
102/11-33
103/08-21
11-34
10-4
517991
519036
509917
518594
6145336
6141666
6135657
6137317
McMurray
100/11-33-074-05W4
102/08-21-074-05W4
Existing
Existing
100/11-33
102/08-21
517991
519036
6145336
6141666
Makeup
McMurray
Wastewater
Disposal
Blowdown
Regen
Pike 1 Project
March 2015
Table E-4: Proposed Testing and Monitoring Well Locations
Grand
Rapids
B
Grand
Rapids
C
Location
Type
Quaternary
02/13-24-074-07W4
open
x
00/13-24-074-07W4
open
00/11-25-074-07W4
open
02/11-33-074-05W4
open
x
03/08-21-074-05W4
open
x
F1/11-33-074-05W4
VWP
x
02/13-26-074-06W4
VWP
x
00/15-02-075-06W4
VWP
x
00/13-36-074-07W4
VWP
02/11-25-073-06W4
VWP
x
00/12-27-073-07W4
VWP
x
00/12-08-075-05W4
VWP
00/04-09-075-05W4
VWP
00/04-20-074-05W4
VWP
00/01-23-073-05W4
VWP
00/06-31-073-05W4
Clearwater
A
Clearwater
B
Clearwater
C
Wabiskaw
McMurray
x
x
Proposed
Well Label
or
on Figure
Existing
UTM
Easting
(NAD27, 12)
UTM
Northing
(NAD27, 12)
Proposed
02/13-24
503103
6142416
Proposed
00/13-24
503106
6142355
Proposed
00/11-25
503494
6143837
Proposed* 02/11-33
517991
6145336
Proposed* 03/08-21
519036
6141666
Existing
F1/11-33
517990
6145386
Existing
02/13-26
511362
6143980
Existing
00/15-02
511520
6147090
x
Existing
00/13-36
502958
6145484
x
Existing
02/11-25
513410
6133764
Existing
00/12-27
499835
6133761
x
x
Proposed
00/12-08
515560
6148743
x
x
x
Proposed
00/04-09
517262
6147641
x
x
x
Proposed
00/04-20
516005
6141145
x
Proposed
00/01-23
512556
6131386
VWP
x
x
x
Proposed
00/06-31
514683
6135204
00/16-05-074-05W4
VWP
x
x
x
Proposed
00/16-05
517414
6137719
00/13-16-074-05W4
VWP
x
x
x
Proposed
00/13-16
517778
6140693
00/08-10-075-05W4
VWP
x
x
Proposed
00/08-10
520313
6148028
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Note:
* Grand Rapids B monitoring wells to be installed on the Grand Rapids C ion disposal well leases.
Symbol x denotes existing and proposed monitored zone(s) at each monitoring well location.
Pike 1 Project
March 2015
Table E-5: Amended Pike 1 Total Projected Water Use Rates
Year
Utility and Potable
Freshwater Withdrawal
(m3/d)
CPF
Drilling
Saline Source
Withdrawal
(m3/d)
Makeup
Wastewater Disposal
(m3/d)
Blowdown
Regen
2012
0
0
0
0
2013
0
0
0
0
0
0
2014
0
41
0
0
0
2015
0
41
0
0
0
2016
30
41
0
0
0
2017
46
73
0
0
0
2018
68
32
1 719
-1 137
-84
2019
68
32
5 666
-3 749
-276
2020
68
32
7 895
-5 224
-385
2021
68
41
8 021
-5 308
-391
2022
68
41
8 120
-5 373
-396
2023
68
41
8 086
-5 350
-395
2024
68
41
8 091
-5 354
-395
2025
68
49
8 090
-5 353
-395
2026
68
41
8 053
-5 329
-393
2027
68
41
8 057
-5 332
-393
2028
68
81
8 090
-5 353
-395
2029
68
32
8 089
-5 352
-395
2030
68
32
8 103
-5 362
-395
2031
68
41
8 083
-5 348
-395
2032
68
73
7 983
-5 283
-389
2033
68
32
8 088
-5 351
-395
2034
68
41
7 983
-5 281
-390
2035
68
41
6 680
-4 420
-326
2036
68
32
4 438
-2 936
-216
2037
68
0
2 912
-1 927
-142
2038
68
0
2 121
-1 404
-104
2039
68
0
1 592
-1 054
-77
2040
68
0
1 346
-891
-66
2041
68
0
1 333
-882
-65
2042
68
0
1 333
-882
-65
2043
0
0
1 273
-842
-62
2044
0
0
903
-598
-44
2045
0
0
462
-306
-22
2046
0
0
222
-146
-11
2047
0
0
59
-39
-3
2048
0
0
0
0
0
2049
0
0
0
0
0
2050
0
0
0
0
0
Pike 1 Project
March 2015
4.4
Aquifer Productivity Assessment
The method for the aquifer assessment has not changed from the Project Application and is
summarized here for convenience. The simulated change in hydraulic head as a result of water
withdrawal and disposal was interpreted in terms of aquifer productivity.
The predicted percent change in aquifer productivity (%AP) due to a change in hydraulic head
(∆s) in the aquifer can be estimated as:
% AP =
Δs
HA
* 100
The magnitude of the potential impact on aquifer productivity was assessed using the following
three levels:
•
low effect – if the predicted %AP is less than 15%, the effect may be detectable;
however, potential conflicts with other users would likely not result;
•
moderate effect – if the predicted %AP is between 15% and 30%, the effect would likely
be detectable; however, conflicts with other users would likely not result; and
•
high effect – if the predicted %AP is greater than 30%, potential conflicts with other
users could result.
In the instance that high effects are predicted, the lateral extent of the impact, duration of the
impact and the location of other potential users need to be considered to determine the final
impact rating of the withdrawal.
Model predictions of the drawdown of the Near-Surface Water Table valued environmental
component were also evaluated as part of the assessment. This drawdown represents a change
in the water table elevation within the near-surface glacial till. The magnitude of these predicted
drawdowns are not amendable to evaluation as a percent change in aquifer productivity
because the drawdown occurs in a low permeability till and not an aquifer. The magnitude of
simulated drawdown at ground surface is recognized to be highly correlated to the change in
flux to Surface Waterbodies (Section 4.5) in that, if wetlands or lower-order streams were
represented in the model, these drawdowns might not occur, yet the change in flux to Surface
Waterbodies would be larger. In order to provide an evaluation of the magnitude of these
drawdowns, the predicted drawdown was compared to an assumed natural seasonal, or interyear, fluctuation in water table elevation. Based on historical groundwater monitoring within the
hydrogeology LSA (Devon 2011a) a water table fluctuation of 2 m was assumed to be
representative. The water table fluctuation of 2 m was then used in place of the available head
when evaluating the magnitude of drawdown in the Near-Surface Water Table.
Pike 1 Project
March 2015
4.5
Groundwater-Surface Water Flux Assessment
The potential effects from groundwater withdrawal to surface waterbodies with respect to
surface water quantity were evaluated using the numerical model of groundwater flow. The
predicted effects to surface waterbodies were expressed as a simulated change to
groundwater-surface water discharge over time.
The simulated change to groundwater discharge was assessed at seven surface water stations
in the vicinity of the Amended Project (Table E-6). Locations of surface waterbodies and their
respective monitoring stations for the Amendment Application are identified on a 1:250 000
scale regional topography map (Government of Canada 1997; Figure E-6). Comparatively,
locations of constant head boundaries at surface representing the monitored surface
waterbodies in the numerical model of groundwater flow overlain on the finite element mesh
were shown in the Project Application.
Table E-6: Surface Water Stations
Surface Water
Station #
SW1
SW2
SW3
SW4
SW5
SW6
SW7
Station Name
Monday Creek Basin
Kirby Lake Basin
East Side Sand River
West Side Sand River
Kirby Lake
Hay Lake
Winefred Lake
UTM Easting
(NAD27, 12)
506662
511389
528647
512178
514298
511347
530477
UTM Northing
(NAD27, 12)
6157242
6157625
6144785
6140778
6148414
6150250
6160187
The change in groundwater flux or discharge (∆Q), for each of the surface water stations was
calculated as:
ΔQ = Qi − Qsim
where:
Qi
Qsim
=
=
steady state simulated flux in groundwater-surface water discharges,
simulated flux in groundwater-surface water discharges at a specified time.
Under steady state conditions, surface water levels in the hydrogeology LSA are in dynamic
equilibrium with precipitation, evaporation, evapotranspiration, runoff and groundwater
discharge or recharge. If the groundwater flux to or from a surface waterbody is altered due to
Project operations, there are potential impacts on that surface waterbody. The induced flux was
quantified as part of the hydrogeology assessment and the predicted effects were assessed in
the surface water quantity assessment in Section 4.4.
4.6
Assessment of Disposal Fluid Migration
Particle tracking was used to assess the disposal of fluids into the Grand Rapids C Aquifer and
the migration of disposal fluids in the subsurface. Particle tracking computes paths and travel
time for imaginary “particles” of water moving through a groundwater system. A streamline
Pike 1 Project
March 2015
represents the path of a particle in a flow field assumed to be at steady state, whereas a
pathline follows a particle in a transient flow field. Pathlines and streamlines are coincident in a
steady flow field. Streamlines and pathlines can be calculated forwards or backwards from the
starting point. Based on Zheng and Bennett (2002), the pathlines of groundwater flow are
governed by the following equation:
= ( , )
where:
p
v
t
=
=
=
position vector (xi+yj+zk),
seepage velocity vector (vxi+vyj+vzk),
time.
The solution for a particle location at any time t can be expressed as:
( )= ( )+
( , )
where:
p(t0)
P(t)
=
=
position of a particle at time t0,
position of particle at time t.
If the velocity distribution is sufficiently simple, the equation can be integrated directly; otherwise
numerical integration algorithms are needed. A numerical procedure generally involves defining
an initial position for a fluid particle (t = t0), and finding subsequent position along the particles
path through a series of finite time steps. This solution process is commonly referred to as
particle tracking.
Advective velocity is derived by dividing Darcy velocity by effective porosity:
( , )=
( , )
( )
=
( )
( )
( , )
where:
( , )
= Darcy velocity,
( ) = hydraulic conductivity,
( , ) = hydraulic gradient,
( )= effective porosity.
The spatial and temporal velocity field is needed to solve the particle tracking equations. When
a numerical model is used for the head distributions, a velocity interpolation scheme and a
particle tracking scheme are required to derive pathlines. The technical details of velocity
interpolation and particle tracking schemes are documented in multiple references, including
Zheng and Bennett (2002) and Pollock (1994).
Pike 1 Project
March 2015
5.0
BASELINE CASE
The Baseline Case was modified to include updated information about groundwater withdrawal
and fluid disposal rates of approved projects in the hydrogeology RSA and LSA. The physical
and geological settings assessment remains unchanged. The hydrogeological setting
assessment remains unchanged with the exception of updates to the geologic mapping in the
Grand Rapids C Aquifer.
5.1
Hydrogeological Setting Grand Rapids C Aquifer
Additional hydrogeologic mapping of the Grand Rapids Formation was conducted, specifically
the shale unit (Grand Rapids B Aquitard) overlying the Grand Rapids C Aquifer. Updated
structure and isopach maps of the Grand Rapids C Aquifer and B Aquitard are presented on
Figures E-7, E-8, E-9, and E-10. Two structural cross sections illustrating the distribution of the
Grand Rapids C Aquifer and B Aquitard are presented on Figures E-11 and E-12. A type log
depicting typical wireline responses for each of the mapped hydrogeologic units is included on
the figure margins.
5.1.1
Hydrogeologic Mapping
Additional effort was committed to understanding the hydrogeologic setting of the Grand
Rapids B Aquitard directly overlying the Grand Rapids C Aquifer. The Grand Rapids B Aquitard
will provide primary hydraulic containment of any waters disposed of into the Grand Rapids C
Aquifer. Mapping of the Grand Rapids B Aquitard was undertaken to identify its thickness and
lateral continuity relative to the expected area of impact within the Grand Rapids C Aquifer.
A structure map of the surface of the Grand Rapids B Aquitard was constructed and is
presented on Figure E-7. The results of this map indicate a structurally high area at an elevation
of approximately 360 masl in the northwest and extending down into T.74, R.4W4. Generally, to
the west of this high, the structure appears to dip gently in a southwest direction. An obvious
structural feature is present, running approximately north-south in R.4W4, where there is an
abrupt drop in the structural elevation of the Grand Rapids B Aquitard. This escarpment is
interpreted to coincide with the dissolution edge of Devonian salt deposits, primarily the Prairie
Evaporite, and can be attributed to the structural lowering of the Grand Rapids B Aquitard.
A structure map of the Grand Rapids C Aquifer (Figure E-8) was also constructed, largely to
provide a base surface for preparing the Grand Rapids B Aquitard isopach map. Very similar
structural trends are observed between both Grand Rapids units with structure dipping gently in
a west - southwest direction. The structural lowering of the Grand Rapids C Aquifer, due to
Devonian salt dissolution, is consistent with observations from the Grand Rapids B Aquitard.
Pike 1 Project
March 2015
Over the Project Area, the Grand Rapids B Aquitard is present and laterally extensive, forming
an intervening ‘blanket shale’ between the Grand Rapids C Aquifer and the overlying sand units
in the Grand Rapids. A gross isopach map of the Grand Rapids B Aquitard (Figure E-9) indicate
thicknesses range from less than 5 m to greater than 35 m. Generally however, the Grand
Rapids B Aquitard maintains a thickness of 10 m or greater.
An isolated area where the Grand Rapids B Aquitard does appear to be absent is locally within
the thalweg of the Sunday Creek Channel. Only in the deepest incisions of the Sunday Creek
Channel, where the entire Grand Rapids has been eroded, is the Grand Rapids B Aquitard not
present. These deep cuts are confined to the NE corner of Section 15, 22 and the SW corner of
Section 26, in Twp 075, Rge 06W4. In these areas, the Empress Formation sand and gravels
are in direct contact with the Grand Rapids C Aquifer, and, locally, are believed to be in
hydraulic communication. Figures E-11 and E-12 present regional cross sections that illustrate
the stratigraphic relationship of these units. Also, a type log is displayed in the margin of the
structure and isopach maps for reference.
A linear feature trending north-south along Rge 05W4 is observed as a thickening of the Grand
Rapids B Aquitard. This is interpreted to represent an area where the Grand Rapids B and C
sands have not developed, and are comprised almost entirely of silts and clays (i.e., mud-filled
channel). While the absence of sand in the both the Grand Rapids B and C has created a
‘thickening’ of the Grand Rapids B Aquitard, a corresponding area of ‘thinning’ on the Grand
Rapids C Aquifer net sand isopach is created (Figure E-10).
A second linear feature running north-south in Rge 06W4 represents a local area where the
uppermost interval in the Grand Rapids C Aquifer displays poor aquifer quality, in comparison to
adjacent well logs. The interval of reduced aquifer quality was not included in the Grand
Rapids C Aquifer net porous isopach map (Figure E-10). Hence, this area is represented by an
apparent ‘thinning’ of the Grand Rapids C Aquifer.
Also displayed on the Grand Rapids B Aquitard isopach map is the simulated difference in
hydraulic head (Grand Rapids C Aquifer) between the modeled application and Baseline Case
(as presented in sections 5.2 and 6.1 [Groundwater Withdrawal and Waste Water Disposal]).
This difference in hydraulic head represents the predicted area of influence caused by disposal
into the Grand Rapids C Aquifer at peak disposal in year 2024. Including the predicted area of
influence on the Grand Rapids B Aquitard provides assurance that the primary containment unit
has been mapped over an appropriate areal extent.
5.1.2
Salinity Mapping
Salinity mapping was initiated in the Grand Rapids C Aquifer in order to better understand the
TDS distribution within the zone, and to assist in directing the appropriate adjustment to the
BGWP.
Pike 1 Project
March 2015
A salinity map derived from well logs has been prepared for the Grand Rapids C Aquifer, and is
provided on Figure E-13. Over the majority of the Project Area, the Grand Rapids C Aquifer is
observed to be saline with calculated TDS values ranging from 10 000 to greater than
30 000 mg/L. The highest salinities are observed to be concentrated in the central area of the
Pike Land boundary, and along the southern boundary edge. The TDS distribution in the Grand
Rapids C Aquifer also suggests a freshening trend to the north and west, toward the Christina
and Sunday Creek channels. The high salinity region is attributed to a hydrogeologic area
where formation water is relatively stagnant, with very little flow occurring in this region of the
aquifer. The two proposed Grand Rapids C Aquifer disposal wells have been located in this high
salinity, low groundwater flow region.
5.1.3
Conceptualization of Groundwater Flow and Distribution of Total Dissolved
Solids in the Grand Rapids C Aquifer
Increased vertical flow of groundwater from the Quaternary aquifers into the Mannville aquifers
occurs in areas where the Empress channels (Wiau, Sunday Creek and Christina Lake
channels) are eroded into the Colorado Group, which is an important regional barrier to vertical
groundwater flow. Simulated pre development hydraulic heads which are consistent with the
conceptualization of groundwater flow in the Grand Rapids C Aquifer are shown on Figure E-14.
South of the Pike Project in Twps 072 and 073, east of Rge 05, the incised Wiau Channel
causes mounding hydraulic heads in the Grand Rapids C Aquifer. To the north, in areas of the
Jackfish project in Twp 075 and 076, the Sunday Creek channel incision also causes higher
hydraulic pressures in the Grand Rapids C Aquifer. Hydraulic pressures in the Grand Rapids C
Aquifer decrease away from the incision zones as illustrated on Figure E-14. The area between
the two zones of higher hydraulic pressures is interpreted to be characterized by lower
horizontal groundwater flow velocities and represents a zone of relative flow stagnation.
The hydraulic head distributions are also shown in cross section on Figure E-15; the assumed
magnitudes of groundwater flow are shown qualitatively on the cross section. This
conceptualization of groundwater flow patterns is supported by observed TDS concentration
and resistivity distributions in the aquifer as outlined in the Project Application. The areas
adjacent to the Sunday Creek and Wiau channel incisions are characterized by low TDS values
indicating that low TDS groundwater inflow from shallower Quaternary aquifers diluted the
originally saline groundwater in the Grand Rapids C Aquifer. High TDS and low resistivity values
in the areas between the high hydraulic pressure zones (Twp 074, Rges 05 and 06) are
interpreted to be representative of saline formation pore waters.
The hypothesis of a TDS distribution driven by groundwater flow patterns was tested by using
the existing model of groundwater flow and assigning an initial concentration of 0 mg/L to all
groundwater in the Quaternary and Neogene hydrogeologic units and an initial concentration of
35 000 mg/L to all groundwater in older hydrogeologic units. The steady state flow field was
then used to simulate mass transport over time. The numerical model of groundwater flow was
built to simulate groundwater flow only and does not have a sufficient mesh refinement to avoid
numerical dispersion and oscillation. As such, the model suffered from unrealistically high
Pike 1 Project
March 2015
vertical dispersion, which also affects how the simulated TDS distribution evolves over time.
Nevertheless, the simulated lateral distribution of TDS in the Grand Rapids C Aquifer
(Figure E-14), shown after a simulation period of 13 700 years, is comparable to the interpreted
TDS distribution (Devon 2012). The simulated TDS values are low in areas of and near the
Empress Channel incisions and increase in zones of relative groundwater flow stagnation.
5.2
Groundwater Withdrawal and Wastewater Disposal
Existing and approved groundwater withdrawal and wastewater disposal rates from over
15 projects in the hydrogeology RSA were compiled for the Baseline Case, sorted by
hydrostratigraphic unit, summarized over time on Figure E-16 and listed in Tables E-7 to E-17.
The projects within the hydrogeology LSA include the Devon Jackfish projects, the Cenovus
Christina Lake Thermal project and the CNRL Kirby project (Figure E-17). Groundwater
pumping or disposal and aquifer recovery was simulated for a 100-year period from 2000 to
2100, inclusive. The Devon Jackfish project withdrawal rates for the Grand Rapids C and Basal
McMurray Aquifers and disposal rates in the Basal McMurray Aquifer have been updated for the
Amendment Application based on Devon’s current water use forecasts.
Groundwater withdrawals from the aquifers have the potential to decrease hydraulic head,
compared to present-day conditions. By contrast, wastewater disposal has the potential to
increase hydraulic heads. Groundwater withdrawal and wastewater disposal can also affect the
flow of groundwater to surface waterbodies. Results of modeling undertaken to define the
Baseline Case water level and flow conditions are discussed in this section.
Pike 1 Project
March 2015
Table E-7: Baseline Case – Projected Groundwater
Withdrawal Rates (m3/d), Ethel Lake Aquifer
MEG Energy Corp.
Year
Christina Lake Regional Project - Phase 1 & 2
MEG 2008
1/1/2000
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
0
0
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
0
Pike 1 Project
March 2015
Withdrawal Rates (m3/d), Empress Terrace Aquifer
Year
Canadian Natural
Resources Limited
Devon Canada
Corporation
MEG Energy Corp.
Kirby North Expansion
Project
Jackfish 1, 2 and 3
Projects
Christina Lake Regional
Project - Phase 3B
CNRL 2011
Devon 2010
MEG 2010
1/1/2000
0
0
0
1/1/2006
0
104
0
1/1/2007
0
123
0
1/1/2008
0
86
0
1/1/2009
0
144
0
1/1/2010
0
198
0
1/1/2011
0
498
0
1/1/2012
0
498
0
1/1/2013
0
498
0
1/1/2014
0
377
191
1/1/2015
0
377
191
1/1/2016
1 958
377
191
1/1/2017
850
377
191
1/1/2018
850
377
191
1/1/2019
901
377
191
1/1/2020
1 450
377
191
1/1/2021
1 450
377
191
1/1/2022
1 450
377
191
1/1/2023
1 450
377
191
1/1/2024
1 450
377
191
1/1/2025
1 450
377
191
1/1/2026
1 450
377
191
1/1/2027
1 450
377
191
1/1/2028
1 450
377
191
1/1/2029
1 450
377
191
1/1/2030
1 450
377
191
1/1/2031
1 450
377
191
1/1/2032
1 450
377
191
1/1/2033
1 421
341
191
1/1/2034
1 164
341
191
1/1/2035
832
341
191
1/1/2036
622
341
191
1/1/2037
581
314
191
1/1/2038
220
314
191
1/1/2039
0
314
0
Pike 1 Project
March 2015
Withdrawal Rates (m3/d), Empress Channel Aquifer
Year
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
1/1/2042
1/1/2043
1/1/2044
1/1/2045
1/1/2046
1/1/2056
1/1/2057
Athabasca Oil Sands
Corp. (ELE)
Canadian Natural
Resources Limited
Hangingstone Project
Kirby South/Central
Expansion Project
AOSC 2011
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 270
744
744
744
744
744
744
744
744
744
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
CNRL 2011
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 449
750
750
750
750
750
750
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 122
765
471
0
0
0
0
0
0
0
0
0
0
0
Cenovus FCCL Ltd.
Christina Lake
Thermal Project Phases 1A to 1G
EnCana 2009
0
0
790
2 398
2 810
2 878
102
1 308
478
478
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
450
0
0
0
0
0
0
Cenovus FCCL Ltd.
Narrows Lake Project
Cenovus 2010
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
0
Pike 1 Project
March 2015
Withdrawal Rates (m3/d), Empress Channel Aquifer
Japan Canada Oil Sands
Ltd. (JACOS)
Year
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
1/1/2042
1/1/2043
1/1/2044
1/1/2045
1/1/2046
1/1/2056
1/1/2057
JACOS 2010
0
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
0
0
0
MEG Energy Corp.
Christina Lake Regional
Project - Phase 3A
MEG 2010
0
0
0
0
0
0
0
0
0
0
0
0
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
0
0
0
0
0
0
0
0
0
0
0
0
0
Nexen Inc.
Long Lake Project
OPTI/Nexen 2003&2006
0
0
0
0
0
0
0
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
0
0
Pike 1 Project
March 2015
Table E-11: Baseline Case – Projected Groundwater Withdrawal Rates (m3/d), Grand Rapids C Aquifer
Year
BlackPearl
Resources
Inc.
Canadian Natural
Resources
Limited
Cenovus
FCCL Ltd.
Blackrod Pilot
Kirby
South/Central
Expansion
Project
Foster Creek
Project
Algar
Project
Great Divide
Project - Pod 1
BlackPearl
Resources
2009
CNRL 2011
Matrix 2009
and
Cenovus 2010
Connacher
2010
Connacher
2010
ConocoPhillips
Surmont Project
Partnership
Devon
Canada
Corporation
Great Divide Expansion
Surmont Project
- Pilot, Phase
1&2
Jackfish 1, 2
and 3
Projects
Connacher
2010
ConocoPhillips
2010
Devon 2015
Forecast
Connacher Oil and Gas Limited
1/1/2000
0
0
0
0
0
0
309
0
1/1/2001
0
0
0
0
0
0
390
0
1/1/2002
0
0
0
0
0
0
455
0
1/1/2003
0
0
0
0
0
0
562
0
1/1/2004
0
0
48
0
0
0
626
0
1/1/2005
0
0
475
0
0
0
557
0
1/1/2006
0
0
2 958
0
0
0
548
0
1/1/2007
0
0
5 165
0
800
0
1 208
355
1/1/2008
0
0
5 196
0
800
0
2 053
1 387
1/1/2009
0
0
8 624
903
800
0
2 088
1 809
1/1/2010
0
0
8 624
903
800
0
1 991
2 598
1/1/2011
201
0
8 624
903
800
0
2 078
3 931
1/1/2012
201
0
8 624
903
800
1 315
1 918
4 570
1/1/2013
201
0
15 111
903
800
1 315
1 314
3 045
1/1/2014
0
1 282
15 111
903
800
1 315
3 067
3 734
1/1/2015
0
870
15 111
903
800
1 315
3 637
7 147
1/1/2016
0
1 121
15 111
903
800
1 315
5 500
7 682
1/1/2017
0
1 278
15 111
903
800
1 315
6 134
7 682
1/1/2018
0
1 479
15 111
903
800
1 315
4 978
7 682
1/1/2019
0
1 247
15 111
903
800
1 315
4 204
7 682
Pike 1 Project
March 2015
BlackPearl
Resources
Inc.
Canadian Natural
Resources
Limited
Cenovus
FCCL Ltd.
Blackrod Pilot
Kirby
South/Central
Expansion
Project
Foster Creek
Project
Algar
Project
Great Divide
Project - Pod 1
BlackPearl
Resources
2009
CNRL 2011
Matrix 2009
and
Cenovus 2010
Connacher
2010
Connacher
2010
1/1/2020
0
1 336
15 111
903
1/1/2021
0
639
15 111
1/1/2022
0
0
15 111
1/1/2023
0
0
15 111
903
800
1 315
4 960
7 682
1/1/2024
0
634
15 111
903
800
1 315
4 547
7 682
1/1/2025
0
129
15 111
903
800
1 315
4 646
7 682
1/1/2026
0
0
15 111
903
800
1 315
4 122
7 682
1/1/2027
0
69
15 111
903
800
1 315
4 776
7 682
1/1/2028
0
68
15 111
903
800
1 315
4 647
7 682
1/1/2029
0
0
15 111
903
800
1 315
4 604
7 682
1/1/2030
0
0
15 111
903
800
1 315
4 783
7 682
1/1/2031
0
0
15 111
903
800
1 315
5 186
7 682
1/1/2032
0
0
15 111
903
0
1 315
5 525
7 682
1/1/2033
0
0
15 111
903
0
0
4 921
5 119
1/1/2034
0
0
15 111
903
0
0
4 744
4 019
1/1/2035
0
0
15 111
0
0
0
4 779
4 019
1/1/2036
0
0
15 111
0
0
0
4 816
1 888
1/1/2037
0
0
15 111
0
0
0
4 868
1 888
1/1/2038
0
0
15 111
0
0
0
5 030
1 888
1/1/2039
0
0
0
0
0
0
4 366
1 888
1/1/2040
0
0
0
0
0
0
4 202
0
1/1/2041
0
0
0
0
0
0
4 913
0
1/1/2042
0
0
0
0
0
0
4 737
0
1/1/2043
0
0
0
0
0
0
4 869
0
Year
ConocoPhillips
Surmont Project
Partnership
Devon
Canada
Corporation
Surmont Project
- Pilot, Phase
1&2
Jackfish 1, 2
and 3
Projects
Connacher
2010
ConocoPhillips
2010
Devon 2015
Forecast
800
1 315
4 254
7 682
903
800
1 315
4 068
7 682
903
800
1 315
4 089
7 682
Pike 1 Project
March 2015
Year
1/1/2044
1/1/2045
1/1/2046
1/1/2047
1/1/2048
1/1/2049
1/1/2050
1/1/2051
1/1/2052
1/1/2053
1/1/2054
1/1/2055
1/1/2056
1/1/2057
1/1/2058
1/1/2059
1/1/2060
BlackPearl
Resources
Inc.
Canadian Natural
Resources
Limited
Cenovus
FCCL Ltd.
Blackrod Pilot
Kirby
South/Central
Expansion
Project
Foster Creek
Project
Algar
Project
Great Divide
Project - Pod 1
BlackPearl
Resources
2009
CNRL 2011
Matrix 2009
and
Cenovus 2010
Connacher
2010
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
ConocoPhillips
Surmont Project
Partnership
Devon
Canada
Corporation
Surmont Project
- Pilot, Phase
1&2
Jackfish 1, 2
and 3
Projects
Connacher
2010
Connacher
2010
ConocoPhillips
2010
Devon 2015
Forecast
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4 773
4 149
3 916
2 950
2 217
1 701
1 400
915
432
329
328
221
204
146
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-12: Baseline Case – Projected Groundwater Withdrawal Rates (m3/d), Grand Rapids C Aquifer
Year
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
Grizzly
Oil Sands
Nexen Inc.
Grizzly
Algar
Long Lake
Project
Grizzly
Oil Sands
2010
OPTI/Nexen
2003 and
2006
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 500
714
714
714
714
714
0
0
0
0
0
0
0
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
Suncor
Energy Oil
Sand
Limited Part
Statoil Canada Ltd.
Kai Kos Dehseh
Project - Corner
Kai Kos Dehseh
Project - Leismer
Commercial
Kai Kos
Dehseh Project
- Leismer
Expansion
Kai Kos Dehseh
Project Thornbury
Kai Kos Dehseh
Project Thornbury
Expansion
PetroCanada 2001
North American 2007
0
0
0
0
0
0
0
0
0
0
0
0
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
0
0
0
0
0
0
0
0
0
0
980
980
980
980
980
980
980
980
980
980
0
0
0
0
0
0
0
0
0
0
0
980
980
980
980
980
980
980
980
980
Meadow
Creek
Project
0
0
0
0
0
0
0
0
0
0
0
0
0
1 960
1 960
1 960
1 960
1 960
1 960
1 960
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
980
980
980
0
0
0
0
0
0
0
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
Pike 1 Project
March 2015
Year
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
1/1/2042
1/1/2043
Grizzly
Oil Sands
Nexen Inc.
Grizzly
Algar
Long Lake
Project
Grizzly
Oil Sands
2010
OPTI/Nexen
2003 and
2006
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
714
0
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
7 788
Suncor
Energy Oil
Sand
Limited Part
Statoil Canada Ltd.
Kai Kos Dehseh
Project - Corner
Kai Kos Dehseh
Project - Leismer
Commercial
Kai Kos
Dehseh Project
- Leismer
Expansion
Kai Kos Dehseh
Project Thornbury
Kai Kos Dehseh
Project Thornbury
Expansion
PetroCanada 2001
North American 2007
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
0
0
0
0
0
0
0
980
980
980
980
980
980
980
980
980
980
0
0
0
0
0
0
0
0
0
0
0
0
0
0
980
980
980
980
980
980
980
980
980
980
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Meadow
Creek
Project
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
0
0
0
0
0
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
0
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
2 172
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Year
1/1/2044
1/1/2045
1/1/2046
1/1/2047
1/1/2048
1/1/2049
1/1/2050
1/1/2051
1/1/2052
1/1/2053
1/1/2054
1/1/2055
1/1/2056
1/1/2057
1/1/2058
1/1/2059
1/1/2060
Grizzly
Oil Sands
Nexen Inc.
Grizzly
Algar
Long Lake
Project
Grizzly
Oil Sands
2010
OPTI/Nexen
2003 and
2006
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
7 788
7 788
7 788
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Suncor
Energy Oil
Sand
Limited Part
Statoil Canada Ltd.
Kai Kos Dehseh
Project - Corner
Kai Kos Dehseh
Project - Leismer
Commercial
Kai Kos
Dehseh Project
- Leismer
Expansion
Kai Kos Dehseh
Project Thornbury
Kai Kos Dehseh
Project Thornbury
Expansion
PetroCanada 2001
North American 2007
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Meadow
Creek
Project
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-13: Baseline Case – Projected Groundwater Withdrawal Rates (m3/d),
Upper and Middle Clearwater Aquifers
CNRL 2011
Middle Clearwater
Christina Lake
EnCana 2009
Middle Clearwater
ConocoPhillips 2010
Upper Clearwater
Harvest Operations
Corp.
Black Gold Project Phase 1 and
Expansion
KNOC 2009
Middle Clearwater
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 548
1 083
1 337
1 616
0
0
0
0
0
2 662
3 164
2 662
2 662
694
700
2 096
2 108
4 986
3 465
4 059
4 928
5 027
5 038
5 104
0
0
0
0
0
0
0
292
1 088
1 811
1 113
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
0
0
0
0
0
0
0
0
0
0
0
0
248
552
566
1 129
1 698
1 699
1 701
1 701
Canadian Natural
Resources Limited
Year
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
Kirby North
Expansion Project
Cenovus FCCL Ltd.
ConocoPhillips
Canada
Surmont Project Pilot, Phase 1&2
MEG Energy Corp.
Christina Lake
Regional Project Phase 1,2,3A&3B
MEG 2008
Upper Clearwater
0
0
0
0
0
0
0
292
1 088
1 811
1 113
2 672
6 548
6 584
10 502
10 538
10 580
10 580
10 580
10 580
Pike 1 Project
March 2015
CNRL 2011
Middle Clearwater
Christina Lake
EnCana 2009
Middle Clearwater
ConocoPhillips 2010
Upper Clearwater
Harvest Operations
Corp.
Expansion
KNOC 2009
Middle Clearwater
2 432
3 020
2 644
2 273
2 690
2 838
2 970
2 239
1 688
1 432
1 372
783
193
0
0
0
0
0
0
0
0
0
0
5 082
5 104
5 082
5 093
5 104
5 082
5 104
5 104
5 104
5 104
5 104
5 104
5 104
4 400
2 970
2 288
1 001
352
352
352
352
352
352
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 672
2 227
0
0
0
0
0
0
1 701
1 701
1 701
1 701
1 701
1 701
1 701
1 701
1 701
1 701
1 701
1 699
1 700
1 698
1 699
1 534
1 270
1 060
816
539
305
0
0
Canadian Natural
Resources Limited
Year
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
1/1/2042
Kirby North
Expansion Project
Cenovus FCCL Ltd.
ConocoPhillips
Canada
MEG Energy Corp.
Christina Lake
MEG 2008
Upper Clearwater
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
10 580
9 458
7 874
5 275
1 248
216
0
0
0
0
Pike 1 Project
March 2015
CNRL 2011
Middle Clearwater
Christina Lake
EnCana 2009
Middle Clearwater
ConocoPhillips 2010
Upper Clearwater
Harvest Operations
Corp.
Expansion
KNOC 2009
Middle Clearwater
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Canadian Natural
Resources Limited
Year
1/1/2043
1/1/2044
1/1/2045
1/1/2046
1/1/2047
1/1/2048
1/1/2049
1/1/2050
1/1/2051
1/1/2052
1/1/2053
1/1/2054
1/1/2055
1/1/2056
1/1/2057
1/1/2058
1/1/2059
1/1/2060
Kirby North
Expansion Project
Cenovus FCCL Ltd.
ConocoPhillips
Canada
MEG Energy Corp.
Christina Lake
MEG 2008
Upper Clearwater
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-14: Baseline Case – Projected Groundwater Withdrawal Rates (m3/d),
Statoil Canada Ltd.
Year
Kai Kos Dehseh
Project - Corner
Expansion
Middle Clearwater
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 960
1 960
1 960
1 960
1 960
1 960
Kai Kos Dehseh Project Hangingstone
Kai Kos Dehseh Project Northwest Leismer
North American 2007
Upper Clearwater
Middle Clearwater
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
980
980
980
980
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
980
980
Kai Kos Dehseh
Project - South
Leismer
Middle Clearwater
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Statoil Canada Ltd.
Year
Kai Kos Dehseh
Project - Corner
Expansion
Middle Clearwater
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
1/1/2042
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
1 960
0
0
0
North American 2007
Upper Clearwater
Middle Clearwater
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
0
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
980
Kai Kos Dehseh
Project - South
Leismer
Middle Clearwater
0
0
0
0
0
0
0
0
0
980
980
980
980
980
980
980
980
980
980
980
980
980
980
Pike 1 Project
March 2015
Statoil Canada Ltd.
Year
Kai Kos Dehseh
Project - Corner
Expansion
Middle Clearwater
1/1/2043
1/1/2044
1/1/2045
1/1/2046
1/1/2047
1/1/2048
1/1/2049
1/1/2050
1/1/2051
1/1/2052
1/1/2053
1/1/2054
1/1/2055
1/1/2056
1/1/2057
1/1/2058
1/1/2059
1/1/2060
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
North American 2007
Upper Clearwater
Middle Clearwater
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
980
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Kai Kos Dehseh
Project - South
Leismer
Middle Clearwater
980
980
980
980
980
980
980
980
980
980
980
980
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-15: Baseline Case – Projected Groundwater Withdrawal and
Wastewater Disposal Rates (m3/d), Basal McMurray Aquifer
Canadian Natural Resources
Limited
Year
Kirby North Project, Kirby South
Project Phase 1 and Expansion
CNRL 2011
Extraction
Injection
Cenovus FCCL Ltd.
Christina Lake Thermal Project Phases 1A to 1G
Foster Creek Project - Phases
1A to 1H
Cenovus 2010
Matrix 2009 & Cenovus 2010
Extraction
Injection
Extraction
Injection
Narrows Lake
Cenovus 2010
Extraction
Injection
1/1/2000
0
0
0
0
0
0
0
0
1/1/2001
0
0
0
0
0
-862
0
0
1/1/2002
0
0
0
-670
0
-4 284
0
0
1/1/2003
0
0
0
-2 687
0
-4 804
0
0
1/1/2004
0
0
0
-2 963
0
-4 100
0
0
1/1/2005
0
0
0
-3 149
0
-4 488
0
0
1/1/2006
0
0
0
-2 996
0
-6 074
0
0
1/1/2007
0
0
0
-2 197
566
-7 135
0
0
1/1/2008
0
0
0
-2 339
679
-6 472
0
0
1/1/2009
0
0
0
-1 679
2 880
-13 000
0
0
1/1/2010
0
0
0
-1 150
2 880
-13 000
0
0
1/1/2011
0
0
0
-2 544
2 880
-13 000
0
0
1/1/2012
0
-2 109
0
-2 557
2 880
-13 000
0
0
1/1/2013
0
-3 088
0
-5 437
2 880
-21 000
0
0
1/1/2014
564
-1 855
3 462
-7 371
2 880
-21 000
0
0
1/1/2015
801
-4 639
4 060
-8 567
2 880
-21 000
0
0
1/1/2016
1 648
-3 093
4 935
-10 316
2 880
-21 000
0
0
1/1/2017
2 129
-2 182
5 025
-10 497
2 880
-21 000
465
-642
1/1/2018
2 380
-4 914
5 040
-10 533
2 880
-21 000
1 083
-1 196
1/1/2019
2 490
-7 597
5 100
-10 649
2 880
-21 000
1 710
-1 765
Pike 1 Project
March 2015
Limited
Year
CNRL 2011
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
Cenovus FCCL Ltd.
1A to 1H
Cenovus 2010
Narrows Lake
Cenovus 2010
Extraction
Injection
Extraction
Injection
Extraction
Injection
Extraction
Injection
2 931
7 009
6 589
6 950
7 064
6 571
6 691
6 827
6 501
5 537
5 206
4 106
2 838
2 567
1 879
1 003
404
152
25
0
0
0
-5 579
-4 042
-4 440
-4 319
-4 171
-4 264
-4 449
-4 246
-3 750
-3 619
-3 410
-3 176
-2 771
-2 472
-1 680
-827
-324
-126
-9
0
0
0
5 080
5 100
5 085
5 095
5 100
5 080
5 100
5 105
5 100
5 100
5 100
5 100
5 105
4 400
2 970
2 285
1 000
350
350
350
350
350
-10 609
-10 652
-10 624
-10 644
-10 654
-10 614
-10 654
-10 657
-10 650
-10 654
-10 649
-10 652
-10 654
-9 252
-6 394
-5 022
-5 494
-3 956
-2 903
-2 243
-1 790
-1 527
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
2 880
0
0
0
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
-21 000
0
0
0
2 295
2 337
2 355
2 367
2 373
2 373
2 370
2 364
2 370
2 364
2 364
2 358
2 349
2 349
2 340
2 337
2 337
2 328
2 322
2 322
2 325
2 319
-2 301
-2 338
-2 358
-2 356
-2 356
-2 354
-2 354
-2 360
-2 358
-2 352
-2 358
-2 356
-2 360
-2 358
-2 360
-2 360
-2 362
-2 364
-2 362
-2 362
-2 362
-2 362
Pike 1 Project
March 2015
Limited
Year
CNRL 2011
Extraction
Cenovus FCCL Ltd.
1A to 1H
Cenovus 2010
Injection
Extraction
Injection
Extraction
Injection
Narrows Lake
Cenovus 2010
Extraction
Injection
1/1/2042
0
0
350
-1 410
0
0
2 316
-2 364
1/1/2043
0
0
0
0
0
0
2 310
-2 364
1/1/2044
0
0
0
0
0
0
2 031
-2 094
1/1/2045
0
0
0
0
0
0
0
-7 256
1/1/2046
0
0
0
0
0
0
0
-5 926
1/1/2047
0
0
0
0
0
0
0
-5 529
1/1/2048
0
0
0
0
0
0
0
-4 794
1/1/2049
0
0
0
0
0
0
0
-4 088
1/1/2050
0
0
0
0
0
0
0
-2 957
1/1/2051
0
0
0
0
0
0
0
-1 784
1/1/2052
0
0
0
0
0
0
0
-1 161
1/1/2053
0
0
0
0
0
0
0
-755
1/1/2054
0
0
0
0
0
0
0
-419
1/1/2055
0
0
0
0
0
0
0
-278
1/1/2056
0
0
0
0
0
0
0
-230
1/1/2057
0
0
0
0
0
0
0
0
1/1/2058
0
0
0
0
0
0
0
0
1/1/2059
0
0
0
0
0
0
0
0
1/1/2060
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-16: Baseline Case – Projected Groundwater Withdrawal and
Wastewater Disposal Rates (m3/d), Basal McMurray Aquifer
Year
ConocoPhillips
Surmont Project
Partnership
Devon Canada
Corporation
Japan
Canada Oil
Sands Ltd.
(JACOS)
MEG Energy Corp.
Nexen Inc.
Statoil Canada Ltd.
Suncor
Energy Oil
Sand
Limited Part
Jackfish 1, 2 and 3
Projects
Hangingstone
Project
Christina Lake
Long Lake
Project
Kai Kos Dehseh
Project
Meadow
Creek
Project
ConocoPhillips
2010
Devon 2015 Forecast
JACOS 2010
MEG 2008
OPTI/Nexen
2006
North American 2007
PetroCanada
2001
Extraction
Injection
Injection
Extraction
Injection
Injection
Extraction
Injection
Extraction
Injection
1/1/2000
0
0
0
0
0
0
0
0
0
0
1/1/2001
0
0
0
-320
0
0
0
0
0
0
1/1/2002
0
0
0
-320
0
0
0
0
0
0
1/1/2003
0
0
0
-320
0
0
0
0
0
0
1/1/2004
0
0
0
-320
0
0
0
0
0
0
1/1/2005
0
0
0
-320
0
0
0
0
0
0
1/1/2006
0
0
0
-320
0
0
0
0
0
0
1/1/2007
-388
0
-297
-320
0
-219
0
0
0
-290
1/1/2008
-803
0
-1 169
-320
0
-912
0
0
0
-290
1/1/2009
-571
0
-1 222
-320
0
-1 535
0
0
0
-290
1/1/2010
-778
0
-1 596
-320
0
-1 089
0
950
-950
-290
1/1/2011
-968
0
-2 173
-320
0
-2 614
17 800
1 900
-1 900
-290
1/1/2012
-979
0
-2 435
-320
4 574
-6 273
17 800
3 800
-3 800
-290
1/1/2013
-1 241
0
-2 142
-320
4 722
-7 843
17 800
5 700
-5 700
-290
1/1/2014
-1 467
371
-3 050
-320
9 631
-11 714
17 800
7 600
-7 600
-290
1/1/2015
-2 428
2 500
-3 880
-320
9 779
-13 284
17 800
7 600
-7 600
-290
1/1/2016
-3 248
2 500
-4 109
-320
10 114
-13 496
17 800
8 550
-8 550
-290
1/1/2017
-3 830
2 500
-4 109
-320
10 114
-13 496
17 800
9 500
-9 500
-290
1/1/2018
-3 895
2 500
-4 109
-320
10 114
-13 496
17 800
10 450
-10 450
-290
1/1/2019
-3 941
2 500
-4 109
-320
10 114
-13 496
17 800
10 450
-10 450
-290
Pike 1 Project
March 2015
Year
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
ConocoPhillips
Surmont Project
Partnership
Devon Canada
Corporation
Japan
Canada Oil
Sands Ltd.
(JACOS)
MEG Energy Corp.
Nexen Inc.
Statoil Canada Ltd.
Suncor
Energy Oil
Sand
Limited Part
Jackfish 1, 2 and 3
Projects
Hangingstone
Project
Christina Lake
Long Lake
Project
Kai Kos Dehseh
Project
Meadow
Creek
Project
ConocoPhillips
2010
Devon 2015 Forecast
JACOS 2010
MEG 2008
OPTI/Nexen
2006
North American 2007
PetroCanada 2001
injection
extraction
injection
injection
extraction
injection
extraction
extraction
injection
injection
-3 929
-3 596
-3 333
-3 963
-4 048
-3 984
-3 469
-3 972
-4 022
-4 024
-3 976
-3 975
-3 991
-4 045
-4 049
-3 958
-3 959
-3 990
-3 947
-3 979
-3 999
-3 932
2 500
2 500
2 500
2 500
2 500
2 500
2 500
2 500
2 500
2 500
2 500
2 500
2 500
1 500
1 500
1 500
1 500
1 500
1 500
1 500
0
0
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-4 109
-2 571
-2 571
-2 571
-1 364
-1 364
-1 364
-1 364
0
0
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
-320
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
10 114
8 749
6 817
4 151
1 760
459
0
0
0
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-13 496
-12 027
-9 948
-7 080
-1 893
-494
0
0
0
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
10 450
10 450
10 450
10 450
10 450
10 450
10 450
10 450
10 450
9 500
9 500
9 500
9 500
9 500
9 500
9 500
9 500
7 600
5 700
3 800
3 800
2 850
-10 450
-10 450
-10 450
-10 450
-10 450
-10 450
-10 450
-10 450
-10 450
-9 500
-9 500
-9 500
-9 500
-9 500
-9 500
-9 500
-9 500
-7 600
-5 700
-3 800
-3 800
-2 850
-290
-290
-290
-290
-290
-290
-290
-290
-290
-290
-290
-290
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Year
ConocoPhillips
Surmont Project
Partnership
Devon Canada
Corporation
Japan
Canada Oil
Sands Ltd.
(JACOS)
MEG Energy Corp.
Nexen Inc.
Statoil Canada Ltd.
Suncor
Energy Oil
Sand
Limited Part
Jackfish 1, 2 and 3
Projects
Hangingstone
Project
Christina Lake
Long Lake
Project
Kai Kos Dehseh
Project
Meadow
Creek
Project
ConocoPhillips
2010
Devon 2015 Forecast
JACOS 2010
MEG 2008
OPTI/Nexen
2006
North American 2007
PetroCanada 2001
injection
1/1/2042
1/1/2043
1/1/2044
1/1/2045
1/1/2046
1/1/2047
1/1/2048
1/1/2049
1/1/2050
1/1/2051
1/1/2052
1/1/2053
1/1/2054
1/1/2055
1/1/2056
1/1/2057
1/1/2058
1/1/2059
1/1/2060
-3 931
-3 937
-3 961
-3 897
-3 782
-2 603
-1 747
-1 515
-1 548
-1 124
-813
-715
-1 367
-972
-859
-666
0
0
0
extraction
injection
injection
extraction
injection
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-320
-320
-320
-320
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
extraction
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
17 800
0
0
0
0
0
0
0
0
0
0
extraction
1 900
950
950
950
950
950
950
950
950
950
950
950
0
0
0
0
0
0
0
injection
injection
-1 900
-950
-950
-950
-950
-950
-950
-950
-950
-950
-950
-950
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Withdrawal Rates (m3/d) – Grosmont Aquifer
Black Pearl Resources Inc.
Year
Blackrod Pilot
BlackPearl Resources 2009
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2060
0
0
0
0
0
0
0
0
0
0
0
0
300
600
0
0
Pike 1 Project
March 2015
5.2.1
Surface Waterbodies and Near-Surface Water Table
The predicted change in groundwater discharge to surface waterbodies for the Baseline Case is
presented over time on Figure E-18 (streams) and Figure E-19 (lakes). The maximum predicted
change for each surface observation point is listed in Table E-18.
These predictions were evaluated with respect to surface water quantity in Section 4.4 of the
Amendment Application. The evaluation of surface water quantity was then used to assess
potential impacts to surface water quality in Section 4.5 and related implications for aquatic
resources (Section 4.6). The surface waterbodies and their corresponding monitoring points are
listed in Table E-6 and are shown on Figure E-4.
Table E-18: Predicted Change in
Groundwater Discharge to Surface Waterbodies
ObsName
Monday Creek
Kirby Creek
FeFlowID
Steady
State
Flow
(m3/d)
Monday
2 011
Baseline
Application
Planned
Development
Max
Change
(m3/d)
Date of
Max
Change
Max
Change
(m3/d)
Date of
Max
Change
Max
Change
(m3/d)
Date of
Max
Change
-225
3/17/2035
-233
3/17/2035
-227
1/16/2035
11/15/2037
Kirby_B
-425
-48
5/17/2038
-47
11/15/2037
-44
Sand River East
Sand_R_E
-57
-34
9/16/2038
-31
9/16/2037
-29
7/17/2037
Sand River West
Sand_R_W
927
-46
7/16/2036
-46
5/17/2036
-45
5/17/2036
3/17/2039
Kirby Lake
Kirby_L
-11
-6.7
5/17/2040
-6.4
11/16/2039
-5.9
Hay Lake
Hay_L
-429
-20
9/16/2038
-19
3/17/2038
-18
11/15/2037
Winefred
-877
-370
11/15/2037
-358
7/17/2037
-334
5/17/2037
Winefred Lake
The simulated change in hydraulic head in the Near-Surface Water Table within the Grand
Centre or Marie Creek Aquitards at four theoretical observation points is presented over time on
Figure E-20. Maximum predicted drawdowns for each applicable observation point are in
Table E-19. The maximum drawdown within the Near-Surface Water Table of 0.4 m is observed
at Obs2 in 2063, on the west side of the Project Area. This is equivalent to 22% of the estimated
natural variation in groundwater levels throughout the year. The simulated drawdown at Obs1
and Obs3 is 0.1 m (aquifer productivity reduction of between 3.2 and 6.3%). The simulated
drawdown at Obs4 is 0.2 m (aquifer productivity reduction of 11.3%). Aquitards, such as the
Grand Centre or the Marie Creek, are not used as water source aquifers and as such were not
evaluated for a change in aquifer productivity.
Pike 1 Project
March 2015
Table E-19: Predicted Change in Hydraulic Head
Baseline Case
Application Case
Change in
Aquifer
Date of Max
Productivity
Change
(%)**
1/1/2100
-3.1
Planned Development Case
Change in
Aquifer
Date of Max
Productivity
Change
(%)**
1/1/2100
-2.9
Theoretical Observation Point
Name
Steady State
Head
(masl)
Approx.
Elevation of
Formation
Top at the
Project (masl)
Available
Head
(m)*
Max
Drawdown (m)
Near-Surface Water Level- Obs1
---
---
2.0
-0.1
1/1/2100
Change in
Aquifer
Productivity
(%)**
-3.2
0.1
-0.1
Near-Surface Water Level - Obs2
---
---
2.0
-0.4
10/1/2063
-22
-0.5
7/17/2063
-23
-1.0
-0.4
3/2/2062
-22
0
---
---
2.0
-0.1
1/1/2100
-6.3
-0.1
1/1/2100
-6.4
-0.1
-0.1
1/1/2100
-6.2
0.1
Date of Max
Change
Max Drawdown
(m)
-0.1
Difference
from Baseline
(%)
Max
Drawdown (m)
Difference
from Baseline
(%)
0.3
---
---
2.0
-0.2
1/1/2100
-11.3
-0.2
1/1/2100
-12
-0.5
-0.2
1/1/2100
-11
0.0
Ethel Lake - Obs1
621
575
46
-2.1
9/16/2038
-4.5
-1.9
1/15/2037
-4.1
0.4
-1.8
7/16/2036
-3.8
0.7
Ethel Lake - Obs2
620
575
45
-0.8
1/16/2036
-1.7
-0.8
2/15/2036
-1.8
-0.1
-0.8
1/16/2036
-1.7
0.0
Bonnyville - Obs1
618
540
78
-2.4
8/16/2038
-3.1
-2.2
1/15/2037
-2.8
0.3
-2.0
5/17/2036
-2.6
0.5
Bonnyville - Obs2
622
540
82
-2.2
9/16/2035
-2.7
-2.3
10/1/2035
-2.8
-0.1
-2.2
9/1/2035
-2.7
0.0
Bonnyville - Obs4
645
540
105
-2.8
1/1/2036
-2.6
-2.9
1/16/2036
-2.7
-0.1
-2.7
1/1/2036
-2.6
0.0
Empress Terrace - Obs1
615
495
120
-3.4
9/1/2038
-2.9
-3.0
1/16/2036
-2.5
0.3
-2.8
1/16/2036
-2.3
0.5
Empress Terrace - Obs4
619
495
124
-6.0
11/1/2035
-4.8
-6.2
12/1/2035
-5.0
-0.2
-5.9
10/1/2035
-4.7
0.1
Grand Rapids C - Obs1
493
340
153
-71
12/31/2032
-46
-43
12/31/2017
-28
18
-40
12/31/2017
-26
20
497
340
157
-61
12/31/2032
-39
-81
12/31/2032
-52
-13
-75
12/31/2032
-48
-9
496
340
156
-51
3/2/2033
-32
-49
3/2/2033
-31
1
-39
2/14/2033
-25
8
499
340
159
-109
12/31/2032
-69
-112
12/31/2032
-71
-2
-107
12/31/2032
-67
2
McMurray - Obs1
428
170
258
52
9/16/2014
20
56
10/1/2019
22
2
62
10/1/2019
24
4
McMurray - Obs3
420
170
250
-43
6/16/2028
-17.3
-94
6/16/2028
-38
-20
-89
6/16/2028
-36
-18
McMurray - Obs4
427
170
257
76
9/16/2014
30
76
9/16/2014
30
0.0
73
9/16/2014
28
-1.2
Notes:
--- Not applicable.
*
Assigned available head values to Near-Surface Water Table is the estimated natural variation in groundwater levels throughout the year.
** Change in aquifer productivity for Near-Surface Water Table is the maximum drawdown compared to the estimated natural variation in groundwater levels.
Pike 1 Project
March 2015
5.2.2
Ethel Lake Aquifer
The simulated change in hydraulic head in the Ethel Lake Aquifer at two theoretical observation
points is presented over time on Figure E-21. Within the Project Area, the Ethel Lake Aquifer
had a predicted maximum drawdown of 2.1 m at Obs1 in 2038 and 0.8 m at Obs2 in 2036
(Table E-19). Given that there is approximately 50 m of available head, this represents a
predicted maximum decrease in aquifer productivity of 4.5% and 1.7%, respectively. The
drawdown in the Ethel Lake Aquifer in the Project Area is interpreted to be the result of the
vertical propagation of pressure decreases due to groundwater withdrawal from underlying
aquifers including the Empress Terrace Aquifer, the Empress Channel Aquifer and the
Mannville Aquifers (via the Empress Channel incision through the Colorado Group Aquitard).
5.2.3
Bonnyville Sand Aquifer
The simulated change in hydraulic head in the Bonnyville Sand Aquifer at three theoretical
observation points is presented over time on Figure E-22. Within the Project Area, the
Bonnyville Sand Aquifer had a predicted maximum drawdown of 2.4 m at Obs1 in 2038 and
2.2 m at Obs2 in 2035 (Table E-19). Given that there is approximately 80 m of available head at
Obs1 and Obs2, this represents a predicted maximum decrease in aquifer productivity of 3.1%
and 2.7%, respectively. North of the Project Area at Obs4, the Bonnyville Sand Aquifer had a
predicted maximum drawdown of 2.8 m in 2036. Given approximately 105 m of available head
at Obs4, this represents a decrease in aquifer productivity of 2.6%.
There are no simulated groundwater users of the Bonnyville Sand Aquifer in the Baseline Case.
The drawdown in the Bonnyville Sand Aquifer is interpreted to be the result of the vertical
propagation of pressure decreases due to groundwater withdrawal from underlying aquifers
including the Empress Terrace Aquifer, the Empress Channel Aquifer and the Mannville
Aquifers (via the Empress Channel incision through the Colorado Group Aquitard).
5.2.4
Empress Terrace Aquifer
The simulated change in hydraulic head in the Empress Terrace Aquifer at two theoretical
observation points is presented over time on Figure E-23. The Empress Terrace Aquifer had a
predicted maximum drawdown of 3.4 m at Obs1 in 2038 on the east side of the Project Area
and 6.0 m at Obs4 in 2035 north of the Project Area (Table E-19). Given that there is
approximately 120 m of available head, this represents a predicted maximum decrease in
aquifer productivity of 2.9% and 4.8%, respectively.
Simulated groundwater users of the Empress Terrace Aquifer in the Baseline Case include the
Devon Jackfish projects and the CNRL Kirby project. The drawdown in the Empress Terrace
Aquifer is interpreted to be the result of the horizontal propagation of pressure from these users
of this aquifer in the hydrogeology LSA, as well as from vertical propagation of pressure
decreases due to groundwater withdrawal from underlying aquifers including the Empress
Channel Aquifer and the Mannville Aquifers (via the Empress Channel incision through the
Colorado Group Aquitard).
Pike 1 Project
March 2015
5.2.5
Grand Rapids C Aquifer
Within the RSA Baseline Case, the Grand Rapids C Aquifer is used for 13 different projects
(Table E-11 and Table E-12). The simulated change in hydraulic head in the Grand Rapids C
Aquifer at four theoretical observation points is presented over time on Figure E-24. The Grand
Rapids C Aquifer had a predicted maximum drawdown of 109 m at Obs4 in 2032 north of the
Project Area (Table E-19). Given that there is approximately 160 m of available head, this
represents a predicted maximum decrease in aquifer productivity of 69%. Within the Project
Area, the maximum predicted drawdown within the Grand Rapids C Aquifer at Obs1 and Obs2
ranged from 61 to 71 m, representing a maximum decrease in aquifer productivity of 39% to
46%. South of the Project Area, the maximum predicted drawdown at Obs3 is 51 m,
representing a decrease in aquifer productivity of 32%.
A drawdown map for the simulated change in hydraulic head between 01 January 2000 and
2036 is shown on Figure E-25. Within the hydrogeology LSA, the drawdown within the Grand
Rapids C Aquifer in 2036 is simulated to be greater than 50 m. (Figure E-25). The temporary
and reversible effects of water withdrawal on hydraulic heads is illustrated by the marked
decreases in simulated drawdown in 2036 (Figure E-24), when the Devon Jackfish projects are
scheduled to stop withdrawing from the Grand Rapids C Aquifer.
Outside of the hydrogeology LSA, drawdown greater than 50 m is predicted in the vicinity of the
Cenovus Foster Creek project, the ConocoPhillips Surmont project and the Statoil Corner
project.
A secondary component of the simulated drawdown in the Grand Rapids C Aquifer is due to the
modeled vertical propagation of pressure decreases by groundwater withdrawal from overlying
and underlying aquifers, such as the Empress Channel, Upper Clearwater, Middle Clearwater
and the Basal McMurray Aquifers.
5.2.6
Basal McMurray Aquifer
The Basal McMurray Aquifer is used for saline water withdrawal and/or wastewater disposal in
the Baseline Case in the RSA by more than 10 projects. The pattern of hydraulic head changes
predicted in the Basal McMurray Aquifer is affected by the pumping schedules from more than
10 projects using this aquifer in the RSA, as well as the presence/absence of the aquifer on the
east and west sides of the hydrogeology LSA. More water disposal than withdrawal takes place
in the Basal McMurray Aquifer initially in the simulation (from 2001 to 2038), while withdrawal
increases later in time (from 2039 to 2051).The effects of both withdrawing and disposing into
the same aquifer dampen the overall simulated hydraulic head changes in the RSA.
The simulated change in hydraulic head in the Basal McMurray Aquifer at three theoretical
observation points is presented over time on Figure E-26. The Basal McMurray Aquifer had a
predicted maximum hydraulic head increase of 76 m at Obs4 in 2014 north of the Project Area
predicted maximum increase in aquifer productivity of 30%. Within the Project Area, the
Pike 1 Project
March 2015
maximum predicted hydraulic head increase within the Basal McMurray Aquifer at Obs1 was
52 m in 2019, representing a maximum increase in aquifer productivity of 20%. South of the
Project Area, the maximum predicted hydraulic head change within the Basal McMurray Aquifer
at Obs3 was a drawdown of 43 m, representing a maximum decrease in aquifer productivity of
17%. The hydraulic head at the three Basal McMurray Aquifer observation points within the
hydrogeology LSA is predicted to recover to within 20 m of initial values by 2040 (less than 10%
change in aquifer productivity).
2036 is shown on Figure E-8. Hydraulic heads increase in the southern part of the RSA and in
the vicinity of the hydrogeology LSA were predicted, while there were hydraulic heads decrease
towards the northern part of the RSA (Figure E-7). In 2036, the largest predicted hydraulic head
decreases over 50 m were simulated for Twps 75 and 76, Rge 6.
Pike 1 Project
March 2015
6.0
APPLICATION CASE
This section describes the potential impacts associated with groundwater withdrawal and
wastewater disposal. The potential impacts from other project development and operations
including surface facilities and SAGD pads have not changed from the Project Application. The
effects of groundwater withdrawal and wastewater disposal are evaluated according to the
potential changes expected for each of the valued environmental components with respect to
near-surface groundwater levels, hydraulic heads and groundwater quality.
6.1
Groundwater withdrawal and wastewater disposal has the potential to affect groundwater
quantities, levels, flow patterns and quality within the valued environmental components. The
Application Case assessment considered existing and approved projects from the Baseline
Case and the Amended Project proposed potable and saline water withdrawal rates and
wastewater disposal rates, for a period of 100 years (from 2000 to 2100).
6.1.1
Water Supply and Wastewater Disposal Usage
The Project groundwater withdrawal and wastewater disposal rates have been summarized in
Table E-5 and graphed by water use type over time on Figure E-3. Groundwater withdrawal and
wastewater disposal rates for each project in the hydrogeology RSA for the Application Case
are summarized by aquifer on Figure E-28. These rates include the existing and approved
projects (as described in the Baseline Case section, Tables E-7 to E-17) in addition to the
projected Amended Project rates. Proposed well locations for the Amended Project, as
simulated in the Application Case, are listed in Table E-3.
Projected utility and potable water withdrawal rates from the Empress Terrace Aquifer for the
CPF are up to 68 m3/d for a period of 27 years from 2016 to 2042 and for drilling are
32 to 81 m3/d for a period of 23 years from 2014 to 2036. Due to the small magnitude of these
rates they were not included in the numerical modeling assessment. Projected saline water
withdrawal rates from the Grand Rapids C and Basal McMurray Aquifers are up to 8 120 m3/d
for a period of 29 years from 2018 to 2048. Projected wastewater disposal rates into the Basal
McMurray and Grand Rapids C Aquifers are up to 5 373 m3/d for blowdown and up to 396 m3/d
for regeneration from 2018 to 2047.
6.1.2
The predicted change in groundwater discharge to surface waterbodies for the Application Case
is presented over time on Figure E-19 (streams) and Figure E-20 (lakes). The maximum
predicted change for each surface observation point is listed in Table E-19. These predictions
were evaluated with respect to surface water quantity in Section 4.4 of the Amendment
Application. The evaluation by surface water quantity was then used to assess potential impacts
to surface water quality (Section 4.5) and related implications for aquatic resources
(Section 4.6).
Pike 1 Project
March 2015
Table E-19.The maximum drawdown within the Near-Surface Water Table of 0.5 m is observed
at Obs2 in 2063, on the west side of the Project Area. This is equivalent to 23% of the estimated
natural variation in groundwater levels throughout the year, 1% greater than the Baseline Case
(Table E-19). The simulated drawdown at Obs1 and Obs3 is 0.1 m (aquifer productivity
reduction of between 3.1 and 6.4%). The simulated drawdown at Obs4 is 0.2 m (aquifer
productivity reduction of 12%).
The predicted effect of the Amended Project on the Near-Surface Water Table is negative and
is considered local in geographic extent, moderate in magnitude, long-term in duration and there
is moderate confidence in this assessment. The final impact rating to the Near-Surface Water
Table is low due to the local geographic extent and reversibility of the effects.
6.1.3
Ethel Lake Aquifer
points is presented over time on Figure E-22. Within the Project Area, the Ethel Lake Aquifer
had a predicted maximum drawdown of 1.9 m at Obs1 in 2037 and 0.8 m at Obs2 in 2036
predicted maximum decrease in aquifer productivity of 4.1% and 1.8%, respectively. These
changes in productivity are 0.4% less than the Baseline Case at Obs 1 and 0.1% greater than
the Baseline Case at Obs 2.
Except for the local MEG Ethel Lake Aquifer drawdown from a source well, the drawdown in the
Ethel Lake Aquifer in the Project Area is interpreted to be the result of the vertical propagation of
pressure decreases due to groundwater withdrawal from underlying aquifers including the
Empress Terrace Aquifer, the Empress Channel Aquifer and the Mannville Aquifers (through the
Empress Channel incision through the Colorado Group Aquitard).
The predicted effect of the Amended Project on the Ethel Lake Aquifer is negative and is
considered local in geographic extent, low in magnitude, long-term in duration and there is good
confidence in this assessment. The final impact rating to the Ethel Lake Aquifer is low.
6.1.4
Bonnyville Sand Aquifer had a predicted maximum drawdown of 2.2 m at Obs1 in 2037 and
2.3 m at Obs2 in 2035 (Table E-19). Given that there is approximately 80 m of available head at
Obs1 and Obs2, this represents a predicted maximum decrease in aquifer productivity of 2.8%.
These changes in productivity are 0.3% less than the Baseline Case at Obs 1and 0.1% greater
than the Baseline Case at Obs 2.
Pike 1 Project
March 2015
North of the Project Area at Obs4, the Bonnyville Sand Aquifer had a predicted maximum
drawdown of 2.9 m in 2036. Given approximately 105 m of available head at Obs4, this
represents a decrease in aquifer productivity of 2.7%. This change in productivity is 0.1%
greater than the Baseline Case.
There are no simulated groundwater users of the Bonnyville Sand Aquifer in the Application
Case. The drawdown in the Bonnyville Sand Aquifer is interpreted to be the result of the vertical
propagation of pressure decreases due to groundwater withdrawal from underlying aquifers
including the Empress Terrace Aquifer, the Empress Channel Aquifer and the Mannville
Aquifers (via the Empress Channel incision through the Colorado Group Aquitard).
The predicted effect of the Amended Project on the Bonnyville Sand Aquifer is negative is
considered regional in geographic extent, low in magnitude, long-term in duration and there is
good confidence with this assessment. The final impact rating to the Bonnyville Sand Aquifer is
low.
6.1.5
Simulated groundwater users of the Empress Terrace Aquifer in the Application Case include
the Devon Jackfish projects, the Amended Project and the CNRL Kirby project. The simulated
change in hydraulic head in the Empress Terrace Aquifer at two theoretical observation points is
presented over time on Figure E-24. The Empress Terrace Aquifer had a predicted maximum
drawdown of 3.0 m at Obs1 in 2036 on the east side of the Project Area and 6.2 m at Obs4 in
2035 north of the Project Area (Table E-19). Given that there is approximately 120 m of
available head, this represents a predicted maximum decrease in aquifer productivity of 2.5%
and 5.0%, respectively. These changes in productivity are 0.3% less than the Baseline Case at
Obs1and 0.2% greater than the Baseline Case at Obs4.
The drawdown in the Empress Terrace Aquifer is interpreted to be the result of the horizontal
propagation of pressure from users of this aquifer in the hydrogeology LSA, as well as from
vertical propagation of pressure decreases due to net groundwater withdrawal from underlying
aquifers including the Empress Channel Aquifer and the Mannville Aquifers (via the Empress
Channel incision through the Colorado Group Aquitard). The increase in aquifer productivity at
Obs1 relative to the Baseline Case is inferred to be caused by pressure propagation from the
simulated Grand Rapids C Aquifer wastewater disposal.
The negative effects are considered regional because a measurable decrease in hydraulic
heads in the Empress Terrace Aquifer is predicted to occur outside of the hydrogeology LSA as
a result of groundwater withdrawal. The potential impact is considered low in magnitude and
long-term in duration. Based on the simulated results, there is a good understanding of cause
and effect and residual impact; therefore, the confidence of this assessment is good. The final
impact rating to the Empress Terrace Aquifer is low.
Pike 1 Project
March 2015
6.1.6
Within the RSA Application Case, the Grand Rapids C Aquifer is used for 17 different projects in
addition to the Amended Project (Table E-11 and Table E-12). Wastewater disposal and
groundwater withdrawal is planned for the Amended Project. The simulated change in hydraulic
head in the Grand Rapids C Aquifer at four theoretical observation points is presented over time
on Figure E-25. The Grand Rapids C Aquifer had a predicted maximum drawdown of 112 m at
Obs4 in 2032 north of the Project Area (Table E-19). Given that there is approximately 160 m of
available head, this represents a predicted maximum decrease in aquifer productivity of 71%.
This change in productivity is 2% greater than the Baseline Case.
Within the Project Area, the maximum predicted drawdown within the Grand Rapids C Aquifer
ranged from 43 m in 2017 at Obs1 to 81 m in 2032 at Obs2, representing a decrease in aquifer
productivity of 28% to 52%. This change in productivity is 18% less than Baseline Case at Obs1
and 13% greater than the Baseline Case at Obs2.
South of the Project Area, the maximum predicted drawdown within the Grand Rapids C Aquifer
at Obs3 is 49 m, representing a decrease in aquifer productivity of 31%. This change in
productivity is 1% less than the Baseline Case.
2036 is shown on Figure E-29. Within the central part of the hydrogeology LSA, the drawdown
within the Grand Rapids C Aquifer in 2036 is simulated to be greater than 50 (Figure E-29).
Drawdown cones small in areal extent (less than 1 km wide) and greater than 100 m in
magnitude are predicted in the immediate vicinity of some of the Amended Project saline source
wells. In the outer parts of the hydrogeology LSA, simulated drawdowns are between 30 and
50 m. In the vicinity of the simulated Amended Project disposal wells, drawdowns are less than
30 m. The temporary and reversible effects of water withdrawal and wastewater disposal on
hydraulic heads is illustrated by the marked decreases in simulated drawdown in 2036
(Figure E-25), when the Devon Jackfish projects and the Amended Project are scheduled to
reduce withdrawal from the Grand Rapids C Aquifer.
Outside of the hydrogeology LSA, drawdown greater than 50 m is predicted in the vicinity of the
ConocoPhillips Surmont project and the Statoil Corner project. These drawdowns are largely
unchanged compared to the Baseline Case. Drawdowns greater than 50 m to the south are
caused by simulated withdrawal at the Cenovus Foster Creek.
and underlying aquifers, such as the Empress Channel, Upper Clearwater and Middle
Clearwater Aquifers and the Basal McMurray Aquifer.
Pike 1 Project
March 2015
The regional potential impact is considered negative, moderate in magnitude and mid-term in
duration. The greatest potential negative effect is situated within the hydrogeology LSA,
therefore, considered local. The positive impact caused by wastewater disposal is considered
local. Based on the simulated results, there is a good understanding of cause and effect and
residual impact. The confidence of this assessment is good. Due to the depth of this aquifer, the
local extent of the high magnitude effects, the reversibility of the effects and the confidence in
this assessment, the final impact rating to the Grand Rapids C Aquifer is moderate.
Groundwater Withdrawal and Fluid Disposal Feasibility Assessment
The simulated changes in hydraulic head at the proposed Grand Rapids C Aquifer disposal and
withdrawal wells were used to assess the feasibility of the Application Case water use plan. The
simulated pressure heads in meters of equivalent freshwater head are shown on Figure E-30
and Figure E-31. At all simulated disposal wells and for both cases, the simulated pressure
heads remain below the formation fracture pressure limit of 410 m of equivalent freshwater
head. The pressure limit was defined based on a 90% fracture pressure limit as defined in
Directive 051 and a conservatively assumed minimum stress gradient of 15 kPa/m. The actual
fracture pressure limit will be assessed through future injectivity tests on the individual disposal
wells (as per Class IB injection well testing requirements of AER Directives 051 and 065).
At the proposed withdrawal wells the changes in hydraulic heads are shown on Figures E-32 to
E-34. The available head estimates for the Grand Rapids C Aquifer in the LSA are greater than
150 m (Table E-19). The simulated changes in hydraulic head are below these thresholds.
Wastewater Migration
Particle tracking was used to assess the lateral and vertical migration of fluids that are planned
to be disposed into the Grand Rapids C Aquifer. Particles were released in areas surrounding
the injection locations at the beginning of disposal in year 2018 and were then tracked over the
remaining simulation period, which ended in year 2140. The simulated results using an effective
porosity of 30% are shown in plan-view on Figure E-35. The maximum lateral particle travel
distance during the simulation period is 419 m at both simulated disposal locations (Table E-20).
Table E-20: Maximum Particle Travel Distances
Starting from Disposal Wells – Base Effective Porosity 0.3
Disposal Well
11-33-074-05
08-21-074-05
Maximum Travel Distance (m)
419
419
Pike 1 Project
March 2015
The computed particle travel distances over the 122 year simulation period are less than 3% of
the distance to the Sunday Creek incision and approximately 10% of the distance of Devon’s
nearest Grand Rapids C Aquifer source well. Hence, the risk that disposal fluids could migrate
to the Sunday Creek incision or Devon’s Grand Rapids C Aquifer source wells is considered
negligible. The effects of different effective porosity values on simulated particle pathlines for the
Application Case are shown on Figures E-36 and E-37. Maximum travel distances at well 08-21074-05 increase from 419 m for an effective porosity of 30% to 773 m for an effective porosity of
10% (Table E-21).
Table E-21: Effective Porosities and Maximum Particle Travel Distances
Disposal Well
08-21-074-05
08-21-074-05
08-21-074-05
11-33-074-05
11-33-074-05
11-33-074-05
Base Effective Porosity
0.3
0.2
0.1
0.3
0.2
0.1
419
534
773
419
538
808
Maximum travel distances at well 11-33-074-05 increase from 419 m for an effective porosity of
30% to 808 m for an effective porosity of 10%. Two cross sections were created to show the
simulated vertical particle movements in the hydraulic system (Figures E-38 and E-39). The
cross sections were aligned parallel to the radial particle paths away from the disposal wells.
There is no indication that the simulated particles cross the upper or lower aquifer boundaries
and move into underlying or overlying hydrostratigraphic units.
Disposal was simulated to occur for a period of 30 years, from 2018 to 2048. Particle travel
times plotted on Figures E-38 and E-39, show that most particles stopped moving when the
disposal ceased. To assess the effect of proposed wastewater disposal on the saline/non-saline
interface in the Grand Rapids C Aquifer, particles were released in year 2018 on the 4 000 mg/L
TDS contour line. The maximum travel distances of the released particles were than tracked.
The maximum travel distances away from the 4 000 mg/L TDS contour line are summarized in
Table E-22 Using an effective porosity of 30%, the maximum particle displacement was
estimated to be approximately 53 m. Particle tracking was also conducted using 10% and 20%
effective porosity for sensitivity analysis and results are summarized in Table E-22. Using an
effective porosity of 10% led to a maximum particle displacement of 165 m.
Table E-22: Maximum Particle Travel Distance
Starting 4000 mg/L TDS Contour
Effective Porosity
0.3
53
0.2
90
0.1
165
Pike 1 Project
March 2015
The impact of the evaluated wastewater disposal into the Grand Rapids C Aquifer is assessed
to be local, long term and high in magnitude. The final impact assessment is considered to be
low because of the localized geographic extent of the impact.
6.1.7
The Basal McMurray Aquifer is used for saline water withdrawal and/or wastewater disposal in
the Application Case in the RSA by more than 12 projects in addition to the Amended Project.
More water disposal than withdrawal takes place in the Basal McMurray Aquifer earlier in the
model simulation (from 2001 to 2038), while more withdrawal takes place later on (from 2039 to
2051). The effects of both withdrawing and disposing into the same aquifer dampen the overall
simulated hydraulic head changes in the RSA.
observation points is presented over time on Figure E-27. Within the Project Area, the maximum
predicted change in hydraulic head within the Basal McMurray Aquifer at Obs1 was an increase
of 56 m in 2019 (Table E-19). Given that there is approximately 260 m of available head, this
represents a predicted maximum increase in aquifer productivity of 22%. This change in
North of the Project Area at Obs4, the Basal McMurray Aquifer had a predicted maximum
increase in hydraulic head of 76 m in 2014, representing a predicted maximum increase in
aquifer productivity of 30%. This change in productivity is equal to the Baseline Case.
South of the Project Area, the maximum predicted change in hydraulic head within the Basal
McMurray Aquifer at Obs3 was a drawdown of 94 m, representing a maximum decrease in
aquifer productivity of 38%. This decrease in productivity is 20% greater than the Baseline
Case.
Similar to the Baseline Case, the hydraulic head at the three Basal McMurray Aquifer
observation points within the hydrogeology LSA is predicted to recover to within 20 m of initial
values by 2040 (less than 10% change in aquifer productivity).
2036 is shown on Figure E-40. Hydraulic head increases in the southern part of the RSA were
predicted, while there were hydraulic head decreases greater than 50 m in the Project Area, and
in Twps 075 and 076, Rge 05 (Figure E-40).
The potential impact of withdrawing and disposing into the Basal McMurray Aquifer is
considered moderate in magnitude and regional in extent. The direction of impact is considered
mainly negative because of decreasing hydraulic heads and is mid-term in duration. Based on
the simulated results, there is a good understanding of cause and effect and residual impact.
The confidence of this assessment is good. Due to the depth of this aquifer, the local extent of
the high magnitude effects, the reversibility of the effects and the confidence in this assessment,
the final impact rating to the Basal McMurray Aquifer is moderate.
Pike 1 Project
March 2015
An assessment for the wastewater migration in the McMurray caused by the Approved Project
disposal was provided in the Project Application. The assessed McMurray disposal volume was
reduced for this Amendment Application, which would result in reduced lateral migration of
wastewater in the aquifer. The conclusions of the impact assessment for the Approved Project
are unchanged for the Amended Project.
6.1.8
Summary of Application Case Impact Ratings due to Groundwater Withdrawal
and Wastewater Disposal
The following table summarizes the impact rating for each valued environmental component
from groundwater withdrawal and wastewater disposal, based on the Application Case results
(Table E-23).
Table E-23: Application Case – Impact Due to
Valued
Environmental
Component
Attribute
Direction
of Impact
Geographic
Extent
Magnitude
of Impact
Duration of
Impact
Confidence
Final Impact
Rating
Low
Surface
Waterbodies
Water levels
Near-Surface
Water Table
Water levels
Negative
Local
Moderate
Long-term
Moderate
Water quality
Neutral
n/a
n/a
n/a
Good
n/a
Ethel Lake Aquifer
Hydraulic
heads
Negative
Local
Low
Long-term
Good
Low
Water quality
Bonnyville Sand
Aquifer
Hydraulic
heads
Water quality
Empress Terrace
Aquifer
Hydraulic
heads
Water quality
Grand Rapids C
Aquifer
Basal McMurray
Aquifer
See Surface Water Quantity (Section 4.4)
Water quality
Hydraulic
heads
See Surface Water Quality (Section 4.5)
Neutral
n/a
n/a
n/a
Good
n/a
Negative
Regional
Low
Long-term
Good
Low
Neutral
n/a
n/a
n/a
Good
n/a
Negative
Regional
Low
Long-term
Good
Low
Neutral
n/a
n/a
n/a
Good
n/a
Negative
Regional
Moderate
Mid-term
Good
Moderate
Water quality
Negative
Local
High
Long-term
Good
Low
Hydraulic
heads
Negative
Regional
Moderate
Mid-term
Good
Moderate
Water quality
Negative
Local
High
Long-term
Good
Low
Note:
n/a Not applicable.
Pike 1 Project
March 2015
7.0
PLANNED DEVELOPMENT CASE
7.1
The following sections describe the results of the simulated effects on hydraulic heads from the
cumulative water use in the RSA, including existing and approved projects, the Amended
Project, and planned projects that have been publically disclosed up to six months prior to the
submission of this Amendment Application. The closest planned development project to the
Amended Project is Cenovus Christina Lake Phase H, (which are also part of the CLRWMA
[Christina Lake Regional Water Management Agreement]), Cenovus Foster Creek Phase J,
Conoco Phillips Canada Surmont Phase 3, MEG Surmont, CNRL Grouse, Athabasca Oil Corp.
Hangingstone, Grizzly May River, and Surmont Energy Wildwood Pilot are the other projects
under review that were included in the planned development simulation.
7.1.1
Water Supply and Wastewater Disposal Usage
For the PDC, the withdrawal and disposal rates are presented in Tables E-24 to E-34 by aquifer,
are summarized on Figure E-41 and are based on publicly available data for the projects.
The simulation was run for 100 years (2000 to 2100). The locations of Amended Project
withdrawal and disposal wells used in the simulation are presented in Table E-3 and are the
same as those simulated in the Application Case. The locations of existing, approved and
planned projects are shown on Figure E-19.
Pike 1 Project
March 2015
Table E-24: Planned Development Case – Projected
Groundwater Withdrawal Rates, Ethel Lake Aquifer
MEG Energy Corp.
Year
Christina Lake Regional Project Phase 1 & 2
MEG 2008
1/1/2000
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
0
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
218
0
Pike 1 Project
March 2015
Groundwater Withdrawal Rates, Bonnyville Sand Aquifer
Year
Devon Canada Corp.
Pike 1 Amended Project
1/1/2000
0
1/1/2014
41
1/1/2015
41
1/1/2016
41
1/1/2017
73
1/1/2018
32
1/1/2019
32
1/1/2020
32
1/1/2021
41
1/1/2022
41
1/1/2023
41
1/1/2024
41
1/1/2025
49
1/1/2026
41
1/1/2027
41
1/1/2028
81
1/1/2029
32
1/1/2030
32
1/1/2031
41
1/1/2032
73
1/1/2033
32
1/1/2034
41
1/1/2035
41
1/1/2036
32
1/1/2037
0
Pike 1 Project
March 2015
Groundwater Withdrawal Rates, Empress Terrace Aquifer
Year
1/1/2000
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
1/1/2020
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
1/1/2040
1/1/2041
1/1/2042
1/1/2043
Canadian Natural
Resources Limited
Devon Canada
Corporation
MEG Energy Corp.
Devon Canada Corp.
Kirby North
Expansion Project
Jackfish 1, 2 and 3
Projects
Christina Lake
Regional Project Phase 3B
Pike 1 Project
CNRL 2011
Devon 2010
MEG 2010
Pike 1 Amended Project
0
0
0
0
0
0
0
0
0
0
0
1 958
850
850
901
1 450
1 450
1 421
1 164
832
622
581
220
0
0
0
0
0
0
104
123
86
144
198
498
498
498
377
377
377
377
377
377
377
377
341
341
341
341
314
314
314
0
0
0
0
0
0
0
0
0
0
0
0
0
191
191
191
191
191
191
191
191
191
191
191
191
191
191
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
30
46
68
68
68
68
68
68
68
68
68
68
68
68
68
68
0
Pike 1 Project
March 2015
Table E-27: Planned Development Case – Projected Groundwater Withdrawal Rates, Empress Channel Aquifer
Athabasca
Oil Corp.
Year
1/1/2000
1/1/2001
1/1/2002
1/1/2003
1/1/2004
1/1/2005
1/1/2006
1/1/2007
1/1/2008
1/1/2009
1/1/2010
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
Japan
Canada Oil
Sands Ltd.
(JACOS)
MEG
Energy
Corp.
Nexen Inc.
Grizzly Oil
Sands
Narrows
Lake
Project
Hangingstone
Project
Christina
Lake
Regional
Project Phase 3A
Long Lake
Project
May River
Project
Cenovus
2010
JACOS 2010
MEG 2010
OPTI/Nexen
2003&2006
Petrobank
2008
0
0
0
0
0
0
0
0
0
0
0
0
191
191
191
191
191
191
191
191
0
0
0
0
0
0
0
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
106
1 228
889
750
Limited
Cenovus
FCCL Ltd.
Cenovus
FCCL Ltd.
Hangingstone
Project
Kirby
South/Central
Expansion
Project
Grouse
Christina
Lake
Thermal
Project Phases 1A
to 1H
AOSC 2013
CNRL 2011
CNRL 2011b
Cenovus
2013
0
0
0
0
0
0
0
0
0
0
0
0
0
300
1 315
1 171
1 066
1 280
1 198
1 379
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 449
750
750
750
750
750
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
886
846
600
0
0
973
2 838
2 935
4 275
151
1 959
410
659
410
290
450
343
340
340
340
340
340
340
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
200
200
200
0
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
Pike 1 Project
March 2015
Athabasca
Oil Corp.
Year
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
1/1/2039
Japan
Canada Oil
Sands Ltd.
(JACOS)
MEG
Energy
Corp.
Nexen Inc.
Grizzly Oil
Sands
Narrows
Lake Project
Hangingstone
Project
Christina
Lake
Regional
Project Phase 3A
Long Lake
Project
May River
Project
Cenovus
2013
Cenovus
2010
JACOS 2010
MEG 2010
OPTI/Nexen
2003&2006
Petrobank
2008
340
340
340
340
340
340
340
340
340
340
340
340
340
340
340
340
340
340
340
340
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
191
0
0
0
0
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
1 211
750
750
750
750
750
750
750
750
750
750
750
750
750
750
750
750
750
750
750
750
Limited
Cenovus
FCCL Ltd.
Hangingstone
Project
Kirby
South/Central
Expansion
Project
Grouse
Christina
Lake
Thermal
Project Phases 1A
to 1H
AOSC 2013
CNRL 2011
CNRL
2011b
1 386
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
750
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 150
1 122
765
471
0
0
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
500
0
Cenovus
FCCL Ltd.
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
1 400
Pike 1 Project
March 2015
Athabasca
Oil Corp.
Year
1/1/2040
1/1/2041
1/1/2042
1/1/2043
1/1/2044
1/1/2045
1/1/2046
1/1/2047
1/1/2048
1/1/2049
1/1/2050
1/1/2051
1/1/2052
1/1/2053
1/1/2054
1/1/2055
1/1/2056
1/1/2057
1/1/2058
1/1/2059
1/1/2060
Japan
Canada Oil
Sands Ltd.
(JACOS)
MEG
Energy
Corp.
Nexen Inc.
Grizzly Oil
Sands
Narrows
Lake Project
Hangingstone
Project
Christina
Lake
Regional
Project Phase 3A
Long Lake
Project
May River
Project
Cenovus
2013
Cenovus
2010
JACOS 2010
MEG 2010
OPTI/Nexen
2003&2006
Petrobank
2008
340
340
340
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 211
1 211
1 211
1 211
1 211
1 211
1 211
0
0
0
0
0
0
0
0
0
0
0
0
0
0
750
750
750
750
750
681
651
529
407
320
226
193
184
151
0
0
0
0
0
0
0
Limited
Cenovus
FCCL Ltd.
Hangingstone
Project
Kirby
South/Central
Expansion
Project
Grouse
Christina
Lake
Thermal
Project Phases 1A
to 1H
AOSC 2013
CNRL 2011
CNRL
2011b
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 154
1 145
1 135
1 125
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Cenovus
FCCL Ltd.
1 400
1 400
1 400
1 400
1 400
1 400
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-28: Planned Development Case – Projected Groundwater Withdrawal Rates, Grand Rapids C Aquifer
Year
BlackPearl
Resources
Inc.
Canadian
Natural
Resources
Limited
Cenovus
FCCL Ltd.
ConocoPhillips
Surmont
Project
Partnership
Devon
Canada
Corporation
Grizzly Oil
Sands
MEG
Energy
Corp.
Nexen Inc.
Blackrod Pilot
Kirby
South/Central
Expansion
Project
Foster Creek
Project
Phases A to
J
Algar
Project
Great
Divide
Project Pod 1
Great
Divide Expansion
Surmont
Project - Pilot,
Phase 1,2&3
Jackfish 1,
2 and 3
Projects
Grizzly
Algar
Surmont
Long Lake
Project
BlackPearl
Resources
2009
CNRL 2011
Cenovus
2013
Connacher
2010
Connacher
2010
Connacher
2010
ConocoPhillips
2014
Devon 2015
Forecast
Grizzly Oil
Sands
2010
MEG
Energy
2013
OPTI/Nexen
2003 &
2006
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
1/1/2000
0
0
0
0
0
0
309
0
0
0
0
1/1/2001
0
0
0
0
0
0
390
0
0
0
0
1/1/2002
0
0
0
0
0
0
455
0
0
0
0
1/1/2003
0
0
0
0
0
0
562
0
0
0
0
1/1/2004
0
0
48
0
0
0
626
0
0
0
0
1/1/2005
0
0
475
0
0
0
557
0
0
0
0
1/1/2006
0
0
2 958
0
0
0
548
0
0
0
0
1/1/2007
0
0
5 165
0
800
0
1 208
355
0
0
7 788
1/1/2008
0
0
5 196
0
800
0
2 053
1 387
0
0
7 788
1/1/2009
0
0
8 209
903
800
0
2 088
1 809
0
0
7 788
1/1/2010
0
0
8 606
903
800
0
1 991
2 598
0
0
7 788
1/1/2011
201
0
6 903
903
800
0
2 078
3 931
0
0
7 788
1/1/2012
201
0
7 800
903
800
1 315
1 918
4 570
0
0
7 788
1/1/2013
201
0
7 800
903
800
1 315
1 314
3 045
0
0
7 788
1/1/2014
0
1 282
7 800
903
800
1 315
2 419
3 734
1 500
775
7 788
1/1/2015
0
870
7 800
903
800
1 315
5 003
7 147
714
775
7 788
1/1/2016
0
1 121
7 800
903
800
1 315
7 461
7 682
714
775
7 788
1/1/2017
0
1 278
7 800
903
800
1 315
8 505
7 682
714
775
7 788
1/1/2018
0
1 479
7 800
903
800
1315
8 102
7 682
714
775
7 788
1/1/2019
0
1 247
7 800
903
800
1 315
7 525
7 682
714
775
7 788
1/1/2020
0
1 336
7 800
903
800
1 315
9 082
7 682
714
773
7 788
Pike 1 Project
March 2015
Year
BlackPearl
Resources
Inc.
Canadian
Natural
Resources
Limited
Cenovus
FCCL Ltd.
ConocoPhillips
Surmont
Project
Partnership
Devon
Canada
Corporation
Grizzly Oil
Sands
MEG
Energy
Corp.
Nexen Inc.
Blackrod Pilot
Kirby
South/Central
Expansion
Project
Foster Creek
Project
Phases A to
J
Algar
Project
Great
Divide
Project Pod 1
Great
Divide Expansion
Surmont
Project - Pilot,
Phases 1,2
and3
Jackfish 1,
2 and 3
Projects
Grizzly
Algar
Surmont
Long Lake
Project
BlackPearl
Resources
2009
CNRL 2011
Cenovus
2013
Connacher
2010
Connacher
2010
Connacher
2010
ConocoPhillips
2014
Devon 2015
Forecast
Grizzly Oil
Sands
2010
MEG
Energy
2013
OPTI/Nexen
2003 and
2006
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
1/1/2021
0
639
7 800
903
800
1 315
9 362
7 682
714
75
7 788
1/1/2022
0
0
7 800
903
800
1 315
11 368
7 682
714
75
7 788
1/1/2023
0
0
7 800
903
800
1 315
10 845
7 682
714
75
7 788
1/1/2024
0
634
7 800
903
800
1 315
11 853
7 682
714
75
7 788
1/1/2025
0
129
7 800
903
800
1 315
11 734
7 682
714
75
7 788
1/1/2026
0
0
7 800
903
800
1 315
11 298
7 682
714
75
7 788
1/1/2027
0
69
7 800
903
800
1 315
10 544
7 682
714
75
7 788
1/1/2028
0
68
7 800
903
800
1 315
9 626
7 682
714
75
7 788
1/1/2029
0
0
7 800
903
800
1 315
8 422
7 682
714
75
7 788
1/1/2030
0
0
7 800
903
800
1 315
8 725
7 682
714
75
7 788
1/1/2031
0
0
7 800
903
800
1 315
8 660
7 682
714
75
7 788
1/1/2032
0
0
7 800
903
0
1 315
10 107
7 682
714
75
7 788
1/1/2033
0
0
7 800
903
0
0
10 027
5 119
714
75
7 788
1/1/2034
0
0
7 800
903
0
0
9 387
4 019
714
75
7 788
1/1/2035
0
0
7 800
0
0
0
9 642
4 019
714
75
7 788
1/1/2036
0
0
7 800
0
0
0
8 941
1 888
714
75
7 788
1/1/2037
0
0
7 800
0
0
0
9 379
1 888
714
75
7 788
1/1/2038
0
0
7 800
0
0
0
10 266
1 888
714
75
7 788
1/1/2039
0
0
7 800
0
0
0
9 965
1 888
714
75
7 788
1/1/2040
0
0
7 800
0
0
0
9 716
0
714
75
7 788
Pike 1 Project
March 2015
Year
BlackPearl
Resources
Inc.
Canadian
Natural
Resources
Limited
Cenovus
FCCL Ltd.
ConocoPhillips
Surmont
Project
Partnership
Devon
Canada
Corporation
Grizzly Oil
Sands
MEG
Energy
Corp.
Nexen Inc.
Blackrod Pilot
Kirby
South/Central
Expansion
Project
Foster Creek
Project
Phases A to
J
Algar
Project
Great
Divide
Project Pod 1
Great
Divide Expansion
Surmont
Project - Pilot,
Phase 1,2&3
Jackfish 1,
2 and 3
Projects
Grizzly
Algar
Surmont
Long Lake
Project
BlackPearl
Resources
2009
CNRL 2011
Cenovus
2013
Connacher
2010
Connacher
2010
Connacher
2010
ConocoPhillips
2014
Devon 2015
Forecast
Grizzly Oil
Sands
2010
MEG
Energy
2013
OPTI/Nexen
2003 & 2006
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
1/1/2041
0
0
7 800
0
0
0
9 912
0
714
75
7 788
1/1/2042
0
0
7 800
0
0
0
10 061
0
714
0
7 788
1/1/2043
0
0
7 800
0
0
0
10 646
0
0
0
7 788
1/1/2044
0
0
7 800
0
0
0
11 544
0
0
0
7 788
1/1/2045
0
0
0
0
0
0
11 001
0
0
0
7 788
1/1/2046
0
0
0
0
0
0
10 798
0
0
0
7 788
1/1/2047
0
0
0
0
0
0
10 239
0
0
0
0
1/1/2048
0
0
0
0
0
0
9 786
0
0
0
0
1/1/2049
0
0
0
0
0
0
8 648
0
0
0
0
1/1/2050
0
0
0
0
0
0
8 757
0
0
0
0
1/1/2051
0
0
0
0
0
0
8 785
0
0
0
0
1/1/2052
0
0
0
0
0
0
9 856
0
0
0
0
1/1/2053
0
0
0
0
0
0
9 914
0
0
0
0
1/1/2054
0
0
0
0
0
0
8 625
0
0
0
0
1/1/2055
0
0
0
0
0
0
4 582
0
0
0
0
1/1/2056
0
0
0
0
0
0
4 648
0
0
0
0
1/1/2057
0
0
0
0
0
0
3 350
0
0
0
0
1/1/2058
0
0
0
0
0
0
1 422
0
0
0
0
1/1/2059
0
0
0
0
0
0
354
0
0
0
0
1/1/2060
0
0
0
0
0
0
2 154
0
0
0
0
Pike 1 Project
March 2015
Table E-29: Planned Development Case – Projected Groundwater Withdrawal Rates, Grand Rapids C Aquifer
Statoil Canada Ltd.
Year
Kai Kos
Dehseh
Project Corner
Kai Kos
Dehseh
Project Leismer
Commercial
Kai Kos
Dehseh
Project Leismer
Expansion
Kai Kos Dehseh
Project - Thornbury
Kai Kos Dehseh
Project Thornbury
Expansion
North American 2007
Extraction
Extraction
Extraction
Extraction
Extraction
Suncor Energy
Oil Sand Limited
Part
Surmont
Energy Ltd.
Devon Canada
Corporation
Meadow Creek
Project
Wildwood Pilot
Pike 1 Project
Petro-Canada
2001
Surmont 2013
Pike 1 Amended
Project
Extraction
Extraction
Extraction
Injection
1/1/2000
0
0
0
0
0
0
0
0
0
1/1/2001
0
0
0
0
0
0
0
0
0
1/1/2002
0
0
0
0
0
0
0
0
0
1/1/2003
0
0
0
0
0
0
0
0
0
1/1/2004
0
0
0
0
0
0
0
0
0
1/1/2005
0
0
0
0
0
0
0
0
0
1/1/2006
0
0
0
0
0
0
0
0
0
1/1/2007
0
0
0
0
0
2 172
0
0
0
1/1/2008
0
0
0
0
0
2 172
0
0
0
1/1/2009
0
0
0
0
0
2 172
0
0
0
1/1/2010
0
980
0
0
0
2 172
0
0
0
1/1/2011
0
980
980
0
0
2 172
0
0
0
1/1/2012
1 960
980
980
0
0
2 172
0
0
0
1/1/2013
1 960
980
980
1 960
0
2 172
0
0
0
1/1/2014
1 960
980
980
1 960
0
2 172
0
0
0
1/1/2015
1 960
980
980
1 960
0
2 172
1 201.096
0
0
1/1/2016
1 960
980
980
1 960
0
2 172
939
0
0
1/1/2017
1 960
980
980
1 960
980
2 172
939
0
0
1/1/2018
1 960
980
980
1 960
980
2 172
939
1 719
-910
1/1/2019
1 960
980
980
1 960
980
2 172
939
3 700
-2 999
1/1/2020
1 960
980
980
1 960
980
2 172
939
3 700
-4 179
Pike 1 Project
March 2015
Statoil Canada Ltd.
Year
Kai Kos
Dehseh
Project Corner
Kai Kos
Dehseh
Project Leismer
Commercial
Kai Kos
Dehseh
Project Leismer
Expansion
Kai Kos Dehseh
Project - Thornbury
Kai Kos Dehseh
Project Thornbury
Expansion
North American 2007
Extraction
Suncor Energy
Oil Sand Limited
Part
Surmont
Energy Ltd.
Devon Canada
Corporation
Meadow Creek
Project
Wildwood Pilot
Pike 1 Project
Petro-Canada
2001
Surmont 2013
Pike 1 Amended
Project
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Injection
1/1/2021
1 960
980
980
1 960
980
2 172
939
3 700
-4 246
1/1/2022
1 960
980
980
1 960
980
2 172
100
3 700
-4 299
1/1/2023
1 960
980
980
1 960
980
2 172
100
3 700
-4 280
1/1/2024
1 960
980
980
1 960
980
2 172
0
3 700
-4 283
1/1/2025
1 960
980
980
1 960
980
2 172
0
3 700
-4 014
1/1/2026
1 960
980
980
1 960
980
2 172
0
3 700
-3 997
1/1/2027
1 960
980
980
1 960
980
2 172
0
3 700
-3 999
1/1/2028
1 960
980
980
1 960
980
2 172
0
3 700
-4 015
1/1/2029
1 960
980
980
1 960
980
2 172
0
3 700
-4 014
1/1/2030
1 960
0
0
1 960
980
2 172
0
3 700
-4 021
1/1/2031
1 960
0
0
1 960
980
2 172
0
3 700
-4 011
1/1/2032
1 960
0
0
1 960
980
0
0
3 700
-3 962
1/1/2033
1 960
0
0
1 960
980
0
0
3 700
-4 013
1/1/2034
1 960
0
0
1 960
980
0
0
3 700
-3 961
1/1/2035
1 960
0
0
1 960
980
0
0
3 700
-3 315
1/1/2036
1 960
0
0
1 960
980
0
0
3 699
-2 202
1/1/2037
0
0
0
1 960
980
0
0
2 912
-1 445
1/1/2038
0
0
0
1 960
980
0
0
2 121
-1 053
1/1/2039
0
0
0
0
980
0
0
1 592
-791
1/1/2040
0
0
0
0
980
0
0
1 346
-668
Pike 1 Project
March 2015
Statoil Canada Ltd.
Year
Kai Kos
Dehseh
Project Corner
Kai Kos
Dehseh
Project Leismer
Commercial
Kai Kos
Dehseh
Project Leismer
Expansion
Kai Kos Dehseh
Project - Thornbury
Kai Kos Dehseh
Project Thornbury
Expansion
North American 2007
Extraction
Suncor Energy
Oil Sand Limited
Part
Surmont
Energy Ltd.
Devon Canada
Corporation
Meadow Creek
Project
Wildwood Pilot
Pike 1 Project
Petro-Canada
2001
Surmont 2013
Pike 1 Amended
Project
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Extraction
Injection
1/1/2021
1 960
980
980
1 960
980
2 172
939
3 700
-4 246
1/1/2022
1 960
980
980
1 960
980
2 172
100
3 700
-4 299
1/1/2023
1 960
980
980
1 960
980
2 172
100
3 700
-4 280
1/1/2024
1 960
980
980
1 960
980
2 172
0
3 700
-4 283
1/1/2025
1 960
980
980
1 960
980
2 172
0
3 700
-4 014
1/1/2026
1 960
980
980
1 960
980
2 172
0
3 700
-3 997
1/1/2027
1 960
980
980
1 960
980
2 172
0
3 700
-3 999
1/1/2028
1 960
980
980
1 960
980
2 172
0
3 700
-4 015
1/1/2029
1 960
980
980
1 960
980
2 172
0
3 700
-4 014
1/1/2030
1 960
0
0
1 960
980
2 172
0
3 700
-4 021
1/1/2031
1 960
0
0
1 960
980
2 172
0
3 700
-4 011
1/1/2032
1 960
0
0
1 960
980
0
0
3 700
-3 962
1/1/2033
1 960
0
0
1 960
980
0
0
3 700
-4 013
1/1/2034
1 960
0
0
1 960
980
0
0
3 700
-3 961
1/1/2035
1 960
0
0
1 960
980
0
0
3 700
-3 315
1/1/2036
1 960
0
0
1 960
980
0
0
3 699
-2 202
1/1/2037
0
0
0
1 960
980
0
0
2 912
-1 445
1/1/2038
0
0
0
1 960
980
0
0
2 121
-1 053
1/1/2039
0
0
0
0
980
0
0
1 592
-791
1/1/2040
0
0
0
0
980
0
0
1 346
-668
Pike 1 Project
March 2015
Table E-30: Planned Development Case – Projected Groundwater Withdrawal Rates,
Canadian Natural Resources Limited
Year
Grouse Project
Project
Cenovus FCCL Ltd.
ConocoPhillips Canada
Harvest Operations Corp.
Christina Lake Thermal
Project - Phases 1A to 1H
Surmont Project - Pilot,
Phase 1,2&3
Black Gold Project Phase 1 and Expansion
Canadian Natural 2012
CNRL 2011
Cenovus 2013
ConocoPhillips 2014
KNOC 2009
Middle Clearwater
Middle Clearwater
Middle Clearwater
Upper Clearwater
Middle Clearwater
1/1/2000
0
0
0
0
0
1/1/2001
0
0
0
0
0
1/1/2002
0
0
0
0
0
1/1/2003
0
0
0
0
0
1/1/2004
0
0
0
0
0
1/1/2005
0
0
2 662
0
0
1/1/2006
0
0
3 173
0
0
1/1/2007
0
0
1 697
0
0
1/1/2008
0
0
2 829
0
0
1/1/2009
0
0
1 106
0
0
1/1/2010
0
0
1 173
108
0
1/1/2011
0
0
2 997
268
0
1/1/2012
0
0
2 108
193
248
1/1/2013
0
0
4 377
208
552
1/1/2014
0
0
2 630
250
566
1/1/2015
0
0
2 684
1 501
1 129
1/1/2016
2 409
1 548
2 681
3 883
1 698
1/1/2017
3 784
1 083
2 653
3 875
1 699
1/1/2018
1 683
1 337
2 730
3 875
1 701
1/1/2019
1 771
1 616
2 720
3 877
1 701
Pike 1 Project
March 2015
Year
Grouse Project
Project
Cenovus FCCL Ltd.
Phase 1,2&3
CNRL 2011
Cenovus 2013
ConocoPhillips 2014
KNOC 2009
Middle Clearwater
Middle Clearwater
Middle Clearwater
Upper Clearwater
Middle Clearwater
1/1/2020
2 264
2 432
2 760
3 883
1 701
1/1/2021
3 388
3 020
2 780
3 875
1 701
1/1/2022
3 113
2 644
2 770
3 875
1 701
1/1/2023
3 399
2 273
2 790
3 877
1 701
1/1/2024
3 570
2 690
2 800
4 568
1 701
1/1/2025
3 465
2 838
2 810
4 458
1 701
1/1/2026
3 905
2 970
2 800
4 366
1 701
1/1/2027
3 905
2 239
2 790
4 310
1 701
1/1/2028
4 187
1 688
2 800
4 285
1 701
1/1/2029
4 477
1 432
2 790
4 272
1 701
1/1/2030
4 268
1 372
2 770
4 328
1 701
1/1/2031
3 674
783
2 770
4 265
1 699
1/1/2032
3 382
193
2 770
4 258
1 700
1/1/2033
3 025
0
2 760
4 192
1 698
1/1/2034
2 475
0
2 760
4 086
1 699
1/1/2035
1 342
0
2 770
4 070
1 534
1/1/2036
516
0
2 750
4 008
1 270
1/1/2037
11
0
2 740
4 126
1 060
1/1/2038
0
0
2 740
4 198
816
1/1/2039
0
0
2 750
4 287
539
1/1/2040
0
0
2 610
4 276
305
1/1/2041
0
0
2 490
4 277
0
1/1/2042
0
0
2 370
4 258
0
Pike 1 Project
March 2015
Year
Grouse Project
Project
Cenovus FCCL Ltd.
Phase 1,2&3
CNRL 2011
Cenovus 2013
ConocoPhillips 2014
KNOC 2009
Middle Clearwater
Middle Clearwater
Middle Clearwater
Upper Clearwater
Middle Clearwater
1/1/2043
0
0
0
4 242
0
1/1/2044
0
0
0
4 300
0
1/1/2045
0
0
0
4 351
0
1/1/2046
0
0
0
4 283
0
1/1/2047
0
0
0
4 252
0
1/1/2048
0
0
0
4 205
0
1/1/2049
0
0
0
4 136
0
1/1/2050
0
0
0
4 083
0
1/1/2051
0
0
0
3 508
0
1/1/2052
0
0
0
3 514
0
1/1/2053
0
0
0
3 527
0
1/1/2054
0
0
0
2 599
0
1/1/2055
0
0
0
655
0
1/1/2056
0
0
0
664
0
1/1/2057
0
0
0
479
0
1/1/2058
0
0
0
203
0
1/1/2059
0
0
0
51
0
1/1/2060
0
0
0
308
0
1/1/2061
0
0
0
254
0
1/1/2062
0
0
0
130
0
1/1/2063
0
0
0
68
0
1/1/2064
0
0
0
0
0
Pike 1 Project
March 2015
Table E-31: Planned Development Case – Projected Groundwater Withdrawal Rates,
MEG Energy Corp.
Year
Surmont Energy
Ltd.
Statoil Canada Ltd.
Christina Lake
Regional Project
- Phase
1,2,3A&3B
Surmont
MEG 2008
MEG Energy
2013
Upper Clearwater
Upper Clearwater
Kai Kos Dehseh
Project - Corner
Expansion
Kai Kos Dehseh
Project Hangingstone
Kai Kos Dehseh
Project Northwest
Leismer
Kai Kos Dehseh
Project - South
Leismer
Wildwood - Pilot
North American 2007
Middle Clearwater
Upper Clearwater
Surmont 2013
Middle Clearwater
Middle Clearwater
Upper Clearwater
1/1/2000
0
0
0
0
0
0
0
1/1/2001
0
0
0
0
0
0
0
1/1/2002
0
0
0
0
0
0
0
1/1/2003
0
0
0
0
0
0
0
1/1/2004
0
0
0
0
0
0
0
1/1/2005
0
0
0
0
0
0
0
1/1/2006
0
0
0
0
0
0
0
1/1/2007
292
0
0
0
0
0
0
1/1/2008
1 088
0
0
0
0
0
0
1/1/2009
1 811
0
0
0
0
0
0
1/1/2010
1 113
0
0
0
0
0
0
1/1/2011
2 672
0
0
0
0
0
0
1/1/2012
6 548
0
0
0
0
0
0
1/1/2013
6 584
0
0
0
0
0
0
1/1/2014
10 502
0
1 960
0
0
0
0
1/1/2015
10 538
0
1 960
0
0
0
390
1/1/2016
10 580
0
1 960
980
0
0
100
1/1/2017
10 580
3 063
1 960
980
0
0
100
1/1/2018
10 580
3 063
1 960
980
980
0
100
1/1/2019
10 580
3 063
1 960
980
980
0
100
Pike 1 Project
March 2015
MEG Energy Corp.
Year
Surmont Energy
Ltd.
Statoil Canada Ltd.
Christina Lake
Regional Project
- Phase
1,2,3A&3B
Surmont
MEG 2008
MEG Energy
2013
Upper Clearwater
Kai Kos Dehseh
Project - Corner
Expansion
Kai Kos Dehseh
Kai Kos Dehseh
Project Northwest
Leismer
Kai Kos Dehseh
Project - South
Leismer
Wildwood - Pilot
North American 2007
Upper Clearwater
Surmont 2013
Upper Clearwater
Middle Clearwater
1/1/2020
10 580
3 063
1 960
980
Middle Clearwater
980
Middle Clearwater
0
Upper Clearwater
100
1/1/2021
10 580
3 063
1 960
980
980
0
100
1/1/2022
10 580
3 063
1 960
980
980
0
939
1/1/2023
10 580
3 063
1 960
980
980
0
939
1/1/2024
10 580
3 063
1 960
980
980
0
1 039
1/1/2025
10 580
3 063
1 960
980
980
0
1 039
1/1/2026
10 580
3 063
1 960
980
980
0
1 039
1/1/2027
10 580
3 063
1 960
980
980
0
1 039
1/1/2028
10 580
3 063
1 960
980
980
0
1 039
1/1/2029
10 580
3 063
1 960
980
980
980
1 039
1/1/2030
10 580
3 063
1 960
980
980
980
1 039
1/1/2031
10 580
3 063
1 960
980
980
980
1 039
1/1/2032
10 580
3 063
1 960
980
980
980
1 039
1/1/2033
10 580
3 063
1 960
980
980
980
1 039
1/1/2034
9 458
3 063
1 960
980
980
980
1 039
1/1/2035
7 874
3 063
1 960
980
980
980
693
1/1/2036
5 275
3 063
1 960
980
980
980
346
1/1/2037
1 248
3 063
1 960
980
980
980
173
1/1/2038
216
3 063
1 960
980
980
980
0
1/1/2039
0
3 063
1 960
980
980
980
0
1/1/2040
0
3 063
0
980
980
980
0
1/1/2041
0
3 063
0
980
980
980
0
1/1/2042
0
0
0
0
980
980
0
Pike 1 Project
March 2015
MEG Energy Corp.
Year
Surmont Energy
Ltd.
Statoil Canada Ltd.
Christina Lake
Regional Project
- Phase
1,2,3A&3B
Surmont
MEG 2008
MEG Energy
2013
Kai Kos Dehseh
Project - Corner
Expansion
Kai Kos Dehseh
Kai Kos Dehseh
Project Northwest
Leismer
Kai Kos Dehseh
Project - South
Leismer
Wildwood - Pilot
North American 2007
Surmont 2013
Upper Clearwater
Upper Clearwater
Middle Clearwater
Upper Clearwater
Middle Clearwater
1/1/2043
0
0
0
0
980
Middle Clearwater
980
Upper Clearwater
0
1/1/2044
0
0
0
0
0
980
0
1/1/2045
0
0
0
0
0
980
0
1/1/2046
0
0
0
0
0
980
0
1/1/2047
0
0
0
0
0
980
0
1/1/2048
0
0
0
0
0
980
0
1/1/2049
0
0
0
0
0
980
0
1/1/2050
0
0
0
0
0
980
0
1/1/2051
0
0
0
0
0
980
0
1/1/2052
0
0
0
0
0
980
0
1/1/2053
0
0
0
0
0
980
0
1/1/2054
0
0
0
0
0
980
0
1/1/2055
0
0
0
0
0
0
0
1/1/2056
0
0
0
0
0
0
0
1/1/2057
0
0
0
0
0
0
0
1/1/2058
0
0
0
0
0
0
0
1/1/2059
0
0
0
0
0
0
0
1/1/2060
0
0
0
0
0
0
0
1/1/2061
0
0
0
0
0
0
0
1/1/2062
0
0
0
0
0
0
0
1/1/2063
0
0
0
0
0
0
0
1/1/2064
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-32: Planned Development Case – Projected Groundwater Withdrawal Rates, Basal McMurray Aquifer
Year
ConocoPhillips
Surmont
Project
Partnership
Athabasca Oil Corp.
Canadian Natural
Resources Limited
Kirby North Project, Kirby
South Project Phase 1
and Expansion
Foster Creek Project Phases 1A to 1J
Narrows Lake
Surmont
Project - Pilot,
Phase 1,2&3
AOSC 2013
CNRL 2011
Cenovus 2013
Cenovus 2013
Cenovus 2010
ConocoPhillips
2014
Extraction
Injection
Extraction
Injection
Cenovus FCCL Ltd.
Extraction
Injection
Extraction
Injection
Extraction
Injection
Injection
1/1/2000
0
0
0
0
0
0
0
0
0
0
0
1/1/2001
0
0
0
0
0
0
0
-862
0
0
0
1/1/2002
0
0
0
0
0
-1 377
0
-4 284
0
0
0
1/1/2003
0
0
0
0
0
-3 359
0
-4 804
0
0
0
1/1/2004
0
0
0
0
0
-3 945
0
-4 100
0
0
0
1/1/2005
0
0
0
0
0
-4 313
0
-4 488
0
0
0
1/1/2006
0
0
0
0
0
-4 192
0
-6 074
0
0
0
1/1/2007
0
0
0
0
0
-2 839
566
-7 135
0
0
-388
1/1/2008
0
0
0
0
0
-2 536
679
-6 472
0
0
-803
1/1/2009
0
0
0
0
0
-1 832
1 674
-9 271
0
0
-571
1/1/2010
0
0
0
0
0
-1 229
2 038
-10 106
0
0
-778
1/1/2011
0
0
0
0
0
-3 212
1 910
-10 634
0
0
-968
1/1/2012
0
0
0
-2 109
0
-2 558
600
-13 821
0
0
-979
1/1/2013
0
0
0
-3 088
0
-4 450
600
-13 821
0
0
-1 241
1/1/2014
0
-82
564
-1 855
0
-5 196
2 400
-15 675
0
0
-1 233
1/1/2015
0
-126
801
-4 639
0
-4 469
2 400
-17 090
0
0
-2 732
-4 921
1/1/2016
0
-128
1 648
-3 093
349
-12 926
2 400
-18 525
0
0
1/1/2017
1 690
-1 818
2 129
-2 182
57
-13 399
600
-18 525
465
-642
-6 544
1/1/2018
5 085
-2 396
2 380
-4 914
111
-11 790
2 400
-20 956
1 083
-1 196
-6 678
1/1/2019
2 892
-843
2 490
-7 597
93
-17 381
600
-20 956
1 710
-1 765
-6 669
Pike 1 Project
March 2015
Year
ConocoPhillips
Surmont
Project
Partnership
Athabasca Oil Corp.
Canadian Natural
Resources Limited
Kirby North Project,
Kirby South Project
Phase 1 and Expansion
Narrows Lake
Surmont
Project - Pilot,
Phase 1,2&3
AOSC 2013
CNRL 2011
Cenovus 2013
Cenovus 2013
Cenovus 2010
ConocoPhillips
2014
Cenovus FCCL Ltd.
Extraction
Injection
Extraction
Injection
Injection
Extraction
Injection
Extraction
Injection
Injection
1/1/2020
4 536
-1 271
2 931
-5 579
Extraction
75
-16 920
600
-20 956
2 295
-2 301
-6 970
1/1/2021
4 159
-1 374
7 009
-4 042
78
-19 476
600
-20 956
2 337
-2 338
-7 205
1/1/2022
3 750
-1 403
6 589
-4 440
78
-20 976
600
-20 956
2 355
-2 358
-7 677
1/1/2023
3 750
-1 403
6 950
-4 319
0
-24 600
600
-20 956
2 367
-2 356
-7 849
1/1/2024
3 750
-1 403
7 064
-4 171
66
-24 456
600
-20 956
2 373
-2 356
-8 374
1/1/2025
3 750
-1 403
6 571
-4 264
0
-24 684
600
-20 956
2 373
-2 354
-8 470
1/1/2026
3 750
-1 403
6 691
-4 449
66
-22 848
600
-20 956
2 370
-2 354
-8 496
1/1/2027
3 750
-1 403
6 827
-4 246
78
-21 552
600
-20 956
2 364
-2 360
-8 507
1/1/2028
3 750
-1 403
6 501
-3 750
0
-25 260
600
-20 956
2 370
-2 358
-8 353
1/1/2029
3 750
-1 403
5 537
-3 619
75
-21 336
600
-20 956
2 364
-2 352
-7 563
1/1/2030
3 750
-1 403
5 206
-3 410
75
-16 728
600
-20 956
2 364
-2 358
-7 835
1/1/2031
3 750
-1 403
4 106
-3 176
75
-16 236
600
-20 956
2 358
-2 356
-8 063
1/1/2032
3 750
-1 403
2 838
-2 771
75
-16 896
600
-20 956
2 349
-2 360
-8 549
1/1/2033
3 750
-1 403
2 567
-2 472
84
-15 228
600
-20 956
2 349
-2 358
-8 533
1/1/2034
3 750
-1 403
1 879
-1 680
84
-14 520
600
-20 956
2 340
-2 360
-8 429
1/1/2035
3 750
-1 403
1 003
-827
75
-15 720
600
-20 956
2 337
-2 360
-8 365
1/1/2036
3 750
-1 403
404
-324
84
-14 712
600
-20 956
2 337
-2 362
-8 336
1/1/2037
3 750
-1 403
152
-126
792
-13 212
600
-20 956
2 328
-2 364
-8 417
1/1/2038
3 750
-1 403
25
-9
1 041
-12 936
600
-20 956
2 322
-2 362
-8 480
1/1/2039
3 750
-1 403
0
0
87
-14 184
600
-20 956
2 322
-2 362
-8 499
1/1/2040
3 750
-1 403
0
0
108
-16 500
600
-20 956
2 325
-2 362
-8 484
Pike 1 Project
March 2015
Year
ConocoPhillips
Surmont Project
Partnership
Athabasca Oil Corp.
Canadian Natural
Resources Limited
Kirby North Project, Kirby
South Project Phase 1 and
Expansion
Narrows Lake
Surmont Project Pilot, Phase 1,2&3
AOSC 2013
CNRL 2011
Cenovus 2013
Cenovus 2013
Cenovus 2010
ConocoPhillips
2014
Cenovus FCCL Ltd.
Extraction
Injection
Extraction
Injection
Extraction
Injection
Extraction
Extraction
Injection
Injection
1/1/2041
3 750
-1 403
0
0
126
-13 572
600
-20 956
Injection
2 319
-2 362
-8 459
1/1/2042
3 750
-1 403
0
0
0
-13 728
600
-20 956
2 316
-2 364
-8 435
1/1/2043
3 750
-1 403
0
0
0
0
600
-20 956
2 310
-2 364
-8 407
1/1/2044
3 750
-1 403
0
0
0
0
600
-20 956
2 031
-2 094
-8 453
1/1/2045
3 750
-1 403
0
0
0
0
0
0
0
-7 256
-8 407
1/1/2046
3 750
-1 403
0
0
0
0
0
0
0
-5 926
-8 394
1/1/2047
3 750
-1 403
0
0
0
0
0
0
0
-5 529
-8 419
1/1/2048
3 750
-1 403
0
0
0
0
0
0
0
-4 794
-8 375
1/1/2049
3 750
-1 403
0
0
0
0
0
0
0
-4 088
-8 152
1/1/2050
3 750
-1 403
0
0
0
0
0
0
0
-2 957
-7 827
1/1/2051
3 750
-1 403
0
0
0
0
0
0
0
-1 784
-7 039
1/1/2052
2 712
-1 072
0
0
0
0
0
0
0
-1 161
-6 822
1/1/2053
1 657
-734
0
0
0
0
0
0
0
-755
-6 678
1/1/2054
443
-347
0
0
0
0
0
0
0
-419
-5 040
1/1/2055
0
0
0
0
0
0
0
0
0
-278
-1 761
1/1/2056
0
0
0
0
0
0
0
0
0
-230
-1 762
1/1/2057
0
0
0
0
0
0
0
0
0
0
-1 522
1/1/2058
0
0
0
0
0
0
0
0
0
0
-1 067
1/1/2059
0
0
0
0
0
0
0
0
0
0
-726
1/1/2060
0
0
0
0
0
0
0
0
0
0
-719
1/1/2061
0
0
0
0
0
0
0
0
0
0
-592
1/1/2062
0
0
0
0
0
0
0
0
0
0
-314
1/1/2063
0
0
0
0
0
0
0
0
0
0
-172
1/1/2064
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Table E-33: Planned Development Case – Projected Groundwater Withdrawal Rates, Basal McMurray Aquifer
Year
Devon Canada
Corporation
Grizzly Oil
Sands
Japan
Canada Oil
Sands Ltd.
(JACOS)
Jackfish 1, 2 and 3
Projects
May River
Project
Hangingstone
Project
Christina Lake
Devon 2015
Forecast
Petrobank
2008
JACOS 2010
MEG 2008
Injection
Injection
Extraction Injection
Nexen Inc.
Statoil Canada Ltd.
Suncor
Energy Oil
Sand
Limited
Part
Surmont
Long Lake
Project
Kai Kos Dehseh
Project
Meadow
Creek
Project
Pike 1 Project
MEG Energy 2013
OPTI/Nexen
2006
North American
2007
PetroCanada
2001
Pike 1 Amended
Project
Extraction
Injection
MEG Energy Corp.
Extraction Injection Extraction Injection
Devon Canada
Corporation
1/1/2000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2001
0
0
0
-320
0
0
0
0
0
0
0
0
0
0
1/1/2002
0
0
0
-320
0
0
0
0
0
0
0
0
0
0
1/1/2003
0
0
0
-320
0
0
0
0
0
0
0
0
0
0
1/1/2004
0
0
0
-320
0
0
0
0
0
0
0
0
0
0
1/1/2005
0
0
0
-320
0
0
0
0
0
0
0
0
0
0
1/1/2006
0
0
0
-320
0
0
0
0
0
0
0
0
0
0
1/1/2007
0
-297
0
-320
0
-219
0
0
0
0
0
-290
0
0
1/1/2008
0
-1 169
0
-320
0
-912
0
0
0
0
0
-290
0
0
1/1/2009
0
-1 222
0
-320
0
-1 535
0
0
0
0
0
-290
0
0
1/1/2010
0
-1 596
0
-320
0
-1 089
0
0
0
950
-950
-290
0
0
1/1/2011
0
-2 173
-100
-320
0
-2 614
0
0
17 800
1 900
-1 900
-290
0
0
1/1/2012
0
-2 435
-100
-320
4 574
-6 273
0
0
17 800
3 800
-3 800
-290
0
0
1/1/2013
0
-2 142
-100
-320
4 722
-7 843
0
0
17 800
5 700
-5 700
-290
0
0
1/1/2014
371
-3 050
-100
-320
9 631
-11 714
0
0
17 800
7 600
-7 600
-290
0
0
1/1/2015
2 500
-3 880
-100
-320
9 779
-13 284
0
0
17 800
7 600
-7 600
-290
0
0
1/1/2016
2 500
-4 109
-100
-320
10 114
-13 496
0
0
17 800
8 550
-8 550
-290
0
0
1/1/2017
2 500
-4 109
-100
-320
10 114
-13 496
2 092
-1 466.71
17 800
9 500
-9 500
-290
0
0
1/1/2018
2 500
-4 109
-100
-320
10 114
-13 496
1 030
-1 812.54
17 800
10 450
-10 450
-290
0
-311
1/1/2019
2 500
-4 109
-100
-320
10 114
-13 496
5 928
-3 285.53
17 800
10 450
-10 450
-290
1 966
-1 026
Pike 1 Project
March 2015
Year
Devon Canada
Corporation
Grizzly Oil
Sands
Japan
Canada Oil
Sands Ltd.
(JACOS)
Jackfish 1, 2 and 3
Projects
May River
Project
Hangingstone
Project
Christina Lake
Surmont
Devon 2015 Forecast
Petrobank
2008
JACOS 2010
MEG 2008
MEG Energy 2013
MEG Energy Corp.
Nexen Inc.
Statoil Canada Ltd.
Suncor
Energy
Oil Sand
Limited
Part
Long Lake
Project
Kai Kos Dehseh
Project
Meadow
Creek
Project
Pike 1 Project
PetroCanada
2001
Pike 1 Amended
Project
Injection
OPTI/Nexen
North American 2007
2006
Devon Canada
Corporation
Injection
Injection
Extraction
Injection
Extraction
1/1/2020
2 500
-4 109
-100
-320
10 114
-13 496
4 865
-3 631.36
17 800
10 450
-10 450
-290
4 195
-1 430
1/1/2021
2 500
-4 109
-100
-320
10 114
-13 496
9 765
-5 104.35
17 800
10 450
-10 450
-290
4 321
-1 453
1/1/2022
2 500
-4 109
-100
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 420
-1 471
1/1/2023
2 500
-4 109
-100
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 386
-1 465
1/1/2024
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 391
-1 466
1/1/2025
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 390
-1 733
1/1/2026
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 353
-1 725
1/1/2027
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 357
-1 726
1/1/2028
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
10 450
-10 450
-290
4 390
-1 733
1/1/2029
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
9 500
-9 500
-290
4 389
-1 733
1/1/2030
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
9 500
-9 500
-290
4 403
-1 736
1/1/2031
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
9 500
-9 500
-290
4 383
-1 732
1/1/2032
2 500
-4 109
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
9 500
-9 500
0
4 283
-1 710
1/1/2033
1 500
-2 571
0
-320
10 114
-13 496
8 442
-5 449.6
17 800
9 500
-9 500
0
4 388
-1 733
1/1/2034
1 500
-2 571
0
-320
8 749
-12 027
8 442
-5 449.6
17 800
9 500
-9 500
0
4 283
-1 710
1/1/2035
1 500
-2 571
0
-320
6 817
-9 948
8 442
-5 449.6
17 800
9 500
-9 500
0
2 980
-1 431
1/1/2036
1 500
-1 364
0
-320
4 151
-7 080
8 442
-5 449.6
17 800
9 500
-9 500
0
739
-950
1/1/2037
1 500
-1 364
0
-320
1 760
-1 893
8 442
-5 449.6
17 800
7 600
-7 600
0
0
-624
1/1/2038
1 500
-1 364
0
-320
459
-494
8 442
-5 449.6
17 800
5 700
-5 700
0
0
-455
1/1/2039
1 500
-1 364
0
-320
0
0
8 442
-5 449.6
17 800
3 800
-3 800
0
0
-341
1/1/2040
0
0
0
-320
0
0
8 442
-5 449.6
17 800
3 800
-3 800
0
0
-288
Pike 1 Project
March 2015
Year
Devon Canada
Corporation
Grizzly Oil
Sands
Japan
Canada Oil
Sands Ltd.
(JACOS)
Jackfish 1, 2 and 3
Projects
May River
Project
Hangingstone
Project
Christina Lake
Surmont
Devon 2015 Forecast
Petrobank
2008
JACOS 2010
MEG 2008
MEG Energy 2013
MEG Energy Corp.
Nexen Inc.
Statoil Canada Ltd.
Suncor
Energy
Oil Sand
Limited
Part
Long Lake
Project
Kai Kos Dehseh
Project
Meadow
Creek
Project
Pike 1 Project
PetroCanada
2001
Pike 1 Amended
Project
Injection
OPTI/Nexen
North American 2007
2006
Extraction
Devon Canada
Corporation
Injection
Injection
1/1/2041
0
0
0
-320
0
0
8 442
-5 449.6
17 800
2 850
-2 850
0
0
-285
1/1/2042
0
0
0
-320
0
0
0
0
17 800
1 900
-1 900
0
0
-285
1/1/2043
0
0
0
-320
0
0
0
0
17 800
950
-950
0
0
-273
1/1/2044
0
0
0
-320
0
0
0
0
17 800
950
-950
0
0
-193
1/1/2045
0
0
0
-320
0
0
0
0
17 800
950
-950
0
0
-99
1/1/2046
0
0
0
0
0
0
0
0
17 800
950
-950
0
0
-47
1/1/2047
0
0
0
0
0
0
0
0
17 800
950
-950
0
0
-13
1/1/2048
0
0
0
0
0
0
0
0
17 800
950
-950
0
0
0
1/1/2049
0
0
0
0
0
0
0
0
17 800
950
-950
0
0
0
1/1/2050
0
0
0
0
0
0
0
0
17 800
950
-950
0
0
0
1/1/2051
0
0
0
0
0
0
0
0
0
950
-950
0
0
0
1/1/2052
0
0
0
0
0
0
0
0
0
950
-950
0
0
0
1/1/2053
0
0
0
0
0
0
0
0
0
950
-950
0
0
0
1/1/2054
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2055
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2056
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2057
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2058
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2059
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2060
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2061
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2062
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2063
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1/1/2064
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pike 1 Project
March 2015
Wastewater Disposal Rates, Devonian
Blackrod Pilot
BlackPearl Resources 2009
Limited
Grouse Project
Extraction
Injection
Black Pearl Resources Inc.
Year
1/1/2000
1/1/2011
1/1/2012
1/1/2013
1/1/2014
1/1/2015
1/1/2016
1/1/2017
1/1/2018
1/1/2019
1/1/2020
1/1/2021
1/1/2022
1/1/2023
1/1/2024
1/1/2025
1/1/2026
1/1/2027
1/1/2028
1/1/2029
1/1/2030
1/1/2031
1/1/2032
1/1/2033
1/1/2034
1/1/2035
1/1/2036
1/1/2037
1/1/2038
0
0
300
600
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-2 624
-2 848
-656
-796
-928
-1 128
-1 192
-1 276
-1 357
-1 400
-1 460
-1 484
-1 543
-1 632
-1 568
-1 632
-1 584
-1 456
-1 228
-792
-477
-232
-80
1/1/2039
0
0
Pike 1 Project
March 2015
7.1.2
The predicted change in groundwater discharge to Surface Waterbodies for the PDC is
presented over time on Figure E-20 (streams) and Figure E-21 (lakes). The maximum predicted
change for each surface observation point is listed in Table E-19. These predictions were
evaluated with respect to surface water quantity in Section 4.4 of the Amendment Application.
The evaluation by surface water quantity was then used to assess potential impacts to surface
water quality (Section 4.5) and related implications for aquatic resources (Section 4.6).
Table E-19. The maximum drawdown within the Near-Surface Water Table of 0.45 m is
observed at Obs2 in 2062, on the west side of the Project Area. This is equivalent to 22% of the
estimated natural variation in groundwater levels throughout the year, and equal to the Baseline
Case. The simulated drawdown at Obs1 and Obs3 is 0.1 m (aquifer productivity reduction of
between 2.9 and 6.2%). The simulated drawdown at Obs4 is 0.2 m (aquifer productivity
reduction of 11%).
The predicted effect in the PDC for the Near-Surface Water Table is negative and is considered
local in geographic extent, moderate in magnitude, long-term in duration and there is moderate
confidence in this assessment. The final impact rating to the Near-Surface Water Table is low
due to the local geographic extent and reversibility of the effects.
7.1.3
Ethel Lake Aquifer
points is presented over time on E-21. Within the Project Area, the Ethel Lake Aquifer had a
predicted maximum drawdown of 1.8 m at Obs1 in 2036 and 0.8 m at Obs2 in 2036
predicted maximum decrease in aquifer productivity of 3.8% and 1.7%, respectively. These
changes in productivity are 0.7% less than the Baseline Case at Obs 1 and equal to the
Baseline Case at Obs 2.
The predicted effect in the PDC for the Ethel Lake Aquifer is negative and is considered regional
in geographic extent, low in magnitude, long-term in duration and there is good confidence with
this assessment. The final impact rating to the Ethel Lake Aquifer is low.
7.1.4
Bonnyville Sand Aquifer had a predicted maximum drawdown of 2 m at Obs1 in 2036 and 2.2 m
at Obs2 in 2035 (Table E-19). Given that there is approximately 78 m of available head at Obs4
and 80 m at Obs2, this represents a predicted maximum decrease in aquifer productivity of
2.6% and 2.7%, respectively. These changes in productivity are almost equal to the Baseline
Case.
Pike 1 Project
March 2015
North of the Project Area at Obs4, the Bonnyville Sand Aquifer had a predicted maximum
drawdown of 2.7 m in 2036. Given approximately 105 m of available head at Obs4, this
represents a decrease in aquifer productivity of 2.6%. This change in productivity is equal to the
Baseline Case.
The predicted effect in the PDC for the Bonnyville Sand Aquifer by the Amended Project is
negative and is considered regional in geographic extent, low in magnitude, long-term in
duration and there is good confidence with this assessment. The final impact rating to the
Bonnyville Sand Aquifer is low.
7.1.5
Simulated groundwater users of the Empress Terrace Aquifer in the PDC include the Devon
Jackfish projects, the Amended Project, the CNRL Kirby project and the MEG Christina Lake
Regional project. The simulated change in hydraulic head in the Empress Terrace Aquifer at two
theoretical observation points is presented over time on Figure E-25. The Empress Terrace
Aquifer had a predicted maximum drawdown of 2.8 m at Obs1 in 2036 on the east side of the
Project Area and 5.9 m at Obs4 in 2035 north of the Project Area (Table E-19). Given that there
is approximately 120 m of available head, this represents a predicted maximum decrease in
aquifer productivity of 2.3% and 4.7%, respectively. These changes in productivity are 0.5% and
0.1% less than the Baseline Case.
The drawdown in the Empress Terrace Aquifer is interpreted to be the result of the horizontal
propagation of pressure from these users of this aquifer in the hydrogeology LSA, as well as
from vertical propagation of pressure decreases due to net groundwater withdrawal from
underlying aquifers including the Empress Channel Aquifer and the Mannville Aquifers (via the
Empress Channel incision through the Colorado Group Aquitard).
The predicted effect in the PDC for the Empress Terrace Aquifer is negative and is considered
regional in geographic extent, low in magnitude, long-term in duration. The potential impact is
considered low in magnitude and long-term in duration. Based on the simulated results, there is
a good understanding of cause and effect and residual impact; therefore, the confidence of this
assessment is good. The final impact rating to the Empress Terrace Aquifer is low.
7.1.6
Within the RSA PDC, the Grand Rapids C Aquifer is used for 19 different projects in addition to
the Amended Project (Table E-28 and Table E-29). The simulated change in hydraulic head in
the Grand Rapids C Aquifer at four theoretical observation points is presented over time on
Figure E-26.
Within the Project Area, the maximum predicted drawdown within the Grand Rapids C Aquifer at
Obs1 and Obs2 was 40 and 75 m, respectively, representing a decrease in aquifer productivity
of 26% to 48%. This change in productivity is 20% less than Baseline Case at Obs1 and 9%
greater than the Baseline Case at Obs2.
Pike 1 Project
March 2015
South of the Project Area, the maximum predicted drawdown within the Grand Rapids C Aquifer
North of the Project Area, the maximum predicted drawdown within the Grand Rapids C Aquifer
2036 is shown on Figure E-42. Within the central part of the hydrogeology LSA, the drawdown
within the Grand Rapids C Aquifer in 2036 is simulated to be greater than 50 (Figure E-42).
Drawdown cones small in areal extent (less than 1 km wide) and greater than 100 m in
magnitude are predicted in the immediate vicinity of some of the Amended Project saline source
wells. The outer parts of the hydrogeology LSA have simulated drawdowns that are between
30 and 50 m. In the vicinity of the simulated Amended Project disposal wells, drawdown is less
than 30 m. The temporary and reversible effects of water withdrawal on hydraulic heads is
illustrated by the marked decreases in simulated drawdown in 2036 (Figure E-25), when the
Devon Jackfish projects and the Amended Project are scheduled to reduce withdrawal from the
Grand Rapids C Aquifer.
and underlying aquifers, such as the Empress Channel, Upper Clearwater and Middle
Clearwater Aquifers and the Basal McMurray Aquifer.
Within the hydrogeology LSA, the regional potential impact of withdrawing and disposing into
the Grand Rapids C Aquifer is considered moderate in magnitude for a mid-term duration. The
moderate potential negative impact extends beyond the hydrogeology LSA, and is therefore
considered regional. The positive impact caused by wastewater disposal is local. Based on the
simulated results, there is a good understanding of cause and effect and residual impact.
The confidence of this assessment is good. The final impact rating to the Grand Rapids C
Aquifer is moderate.
7.1.7
The Basal McMurray Aquifer is used for saline water withdrawal and/or wastewater disposal by
more than 15 projects in the hydrogeology RSA for the PDC, in addition to the Amended Project
(Table E-32 and Table E-33). More water disposal than withdrawal takes place in the Basal
McMurray Aquifer earlier in the model simulation (from 2001 to 2038), while more withdrawal
takes place later on (from 2039 to 2051; Figure E-41).The effects of both withdrawing and
disposing into the same aquifer dampen the overall simulated hydraulic head changes in the
RSA.
observation points is presented over time on Figure E-26. Within the Project Area, the maximum
Pike 1 Project
March 2015
predicted hydraulic head change within the Basal McMurray Aquifer at Obs1 was an increase of
62 m in 2019 (Table E-19). Given that there is approximately 260 m of available head, this
represents a predicted maximum increase in aquifer productivity of 24%. This change in
North of the Project Area, the Basal McMurray Aquifer had a predicted maximum hydraulic head
change of 73 m at Obs4 in 2014, representing a predicted maximum increase in aquifer
productivity of 28%. This change in productivity is 1.2% greater than the Baseline Case.
South of the Project Area, the maximum predicted hydraulic head decrease within the Basal
McMurray Aquifer at Obs3 was 89 m, representing a maximum decrease in aquifer productivity
of 36%. This change in productivity is 18% greater than the Baseline Case.
Similar to the Baseline Case, the hydraulic head at the three Basal McMurray Aquifer
observation points within the hydrogeology LSA is predicted to recover to within 20 m of initial
values by 2040 (less than 10% change in aquifer productivity).
2036 is shown on Figure E-43. Hydraulic head increases in the southern part of the RSA were
predicted, while there were hydraulic head decreases greater than 50 m in the Project Area at
the Amended Project source wells (Figure E-43).
Within the hydrogeology LSA, the potential impact of withdrawing and disposing into the Basal
McMurray Aquifer is considered moderate in magnitude and regional in extent. The direction of
impact is considered mainly negative because of the decrease in hydraulic head and is
mid-term in duration. Based on the simulated results, there is a good understanding of cause
and effect and residual impact. The confidence of this assessment is good. Based on the depth
of this aquifer, the local extent and reversibility of the effects and the confidence in this
assessment, the final impact rating to the Basal McMurray Aquifer is moderate.
7.1.8
Summary of Planned Development Case Impact Ratings due to Groundwater
Withdrawal and Wastewater Disposal
The following table summarizes the impact rating for each valued environmental component
from groundwater withdrawal and wastewater disposal, based on the PDC results (Table E-35).
Pike 1 Project
March 2015
Table E-35: Planned Development Case – Impact Due to
Valued
Environmental
Component
Attribute
Direction of
Impact
Geographic
Extent
Magnitude
of Impact
Duration of
Impact
Confidence
Final Impact
Rating
Surface
Waterbodies
Water levels
See Surface Water Quantity (Section 4.4)
Water quality
See Surface Water Quality (Section 4.5)
Near-Surface
Water Table
Water levels
Negative
Local
Moderate
Long-term
Moderate
Water quality
n/a
n/a
n/a
n/a
n/a
n/a
Negative
Local
Low
Long-term
Good
Low
Ethel Lake Aquifer Hydraulic heads
Water quality
Bonnyville Sand
Aquifer
Empress Terrace
Aquifer
Grand Rapids C
Aquifer
Basal McMurray
Aquifer
Hydraulic heads
Water quality
Hydraulic heads
Water quality
Hydraulic heads
Water quality
Hydraulic heads
Water quality
Low
n/a
n/a
n/a
n/a
n/a
n/a
Negative
Regional
Low
Long-term
Good
Low
n/a
n/a
n/a
n/a
n/a
n/a
Negative
Regional
Low
Long-term
Good
Low
n/a
n/a
n/a
n/a
n/a
n/a
Negative
Regional
Moderate
Mid-term
Good
Moderate
n/a
n/a
n/a
n/a
n/a
n/a
Negative
Regional
Moderate
Mid-term
Good
Moderate
n/a
n/a
n/a
n/a
n/a
n/a
Note:
n/a = Not applicable.
7.1.8.1
Wastewater disposal is predicted to impact water quality only in a local area around the disposal
wells as outlined in the Application Case. This component of the Amended Project was
therefore, not assessed as part of the PDC.
Pike 1 Project
March 2015
8.0
MONITORING
Devon will responsibly manage the Amended Project makeup water usage and wastewater
disposal as stated in the Project Application. However, further Grand Rapids monitoring is
proposed due to the addition of the Grand Rapids C Aquifer as a wastewater disposal zone. The
additional monitoring components include:
•
monitoring hydraulic head (pressures) within the Grand Rapids C Aquifer, Basal
McMurray Aquifer and other strategic formations using the proposed monitoring
locations listed in Table E-4;
•
additional water sampling from the Grand Rapids C Aquifer will take place at the two
proposed disposal wells to confirm the chemical nature of the water.
•
pressure monitoring with the Grand Rapids B sand will take place at two well locations
near the proposed disposal wells. These monitoring wells will be perforated over the
Grand Rapids B sand and flowed to provide a representative water sample. Laboratory
analysis will be performed to determine the chemical nature of the water. Pressure
monitoring gauges will be suspended in each well and continuously monitored once the
disposal wells are placed into operation. Subsequent water samples will be collected in
the event of any pressure excursion correlated with disposal activities.
Pike 1 Project
March 2015
9.0
REFERENCES
Alberta Energy and Utilities Board (EUB). 2007. Bulletin 2007-10: ST55-2007: Alberta's Base of
Groundwater Protection (BGWP) Information. April 2007.
http://www.aer.ca/documents/bulletins/Bulletin-2007-10.pdf.
Alberta Environment (AENV). 2011. Guide to Preparing Environmental Impact Assessment
Reports in Alberta - Updated February 2011. Alberta Environment, Environmental
Assessment Team, Edmonton, Alberta. EA Guide 2009-2. 26 pp. Devon NEC
Corporation (Devon). 2011a. Application for Approval of the Devon Jackfish 3 Project,
Volume 5 - Supplemental Information Request #2. Submitted to Energy and Resources
Conservation Board and Alberta Environment. August 2011.
Devon NEC Corporation (Devon). 2012. Application for Approval of the Pike 1 Project.
Volumes 1 to 5. Submitted to the Energy Resources Conservation Board
(Approval 12301) and Alberta Environment and Sustainable Resource Development
(Approval 308463-00-00). June 2012.
DHI/Wasy. 2014. Feflow Interactive Graphics based Finite Element Simulation System for
Subsurface Flow and Transport Processes. Copyright © 1979 2010 by WASY GmbH. v.
6.2 (3-D + 2-D). Berlin Bohnsdorf, Germany. February 2007.
Farvolden, R.N. 1959. Groundwater Supply in Alberta. Unpublished report, Research Council of
Alberta.
Government of Canada. 1997. Waterhen River. Topographic Map 073K. Edition 1.0.
Scale 1:250,000. Ottawa, Ontario. July 22, 1997.
MacMillan G.J. and J. Schumacher. 2014. Correction of discretization errors simulated at supply
wells. Groundwater Early View September 2014.
Pollock, D.W., 1994, User’s Guide for MODPATH/MODPATH-PLOT, Version 3: A particle
tracking post-processing package for MODFLOW, the U. S. Geological Survey
finite-difference ground-water flow model, U.S. Geological Survey Open File Report
94-464.
Zheng, C and G.D. Bennett. 2002. Applied Contaminant Transport Modeling, Second Edition,
published by John Wiley and Sons Inc., New York.
Figures
Due to website sizing constraints the Hydrogeology figures have been removed from the online
version of the Pike 1 Amendment Application (March 2015). Should you require copies of these
figures, please contact:
Email: thermal.projects@dvn.com
Phone: Thermal Projects Information Line 1-877-255-7595
Attachment F
Hydrological Indicator Data
Table F-1
Sandy River Upstream
Sandy River at Winefred Lake
Monday Creek
Kirby & Hay Lake Drainage
Amendment
Amendment
Amendment
Amendment
Update Case
Update Case
Update Case
Case
Case
Case
Case
Mean Annual Runoff from Precipitation (mm)
125.1
124.7
124.6
124.4
125.3
125.4
125.4
126.2
0.71
0.71
0.71
0.71
Correction Factor
Corrected Mean Annual Runoff (mm)
89.3
89.0
88.2
88.1
88.7
88.8
88.6
89.2
-0.35%
-0.14%
0.08%
0.65%
Amendment Mean Annual Runoff Increase (%)
* negeative percentages indicate a decrease in mean annual runoff
Update Case
* values from Mean Annual Runoff Changes-Amendment.xlsx\Annual Runoff
Table F-2
3
Volume (dam )
3
22317
Update Mean Annual Runoff (dam )
22239
Amendment Mean Annual Runoff (dam3)
-0.35%
Amendment Mean Annual Runoff Increase (%)
* negeative percentages indicate a decrease in mean annual runoff
Discharge
3
(m /s)
0.71
0.71
Volume
3
(dam )
48108
48041
Discharge
3
(m /s)
1.53
1.52
-0.14%
Monday Creek
Volume
3
(dam )
14809
14821
Discharge
3
(m /s)
0.47
0.47
0.08%
Kirby & Hay Lake Drainage
Volume
3
(dam )
10976
11048
Discharge
3
(m /s)
0.35
0.35
0.65%
* values from Mean Annual Runoff Changes-Amendment.xlsx\Annual Runoff
Table F-3
Upper Sandy River
Rainfall Return Period
Condition
Update Case
Amendment Case
Difference
% Difference
Update Case
Amendment Case
1:100
Difference
% Difference
* negeative values indicate a decrease in volume and peak discharge
1:10
Volume
3
(dam )
1674
1664
-10
-0.60%
5173
5154
-19
-0.37%
Peak
Discharge
3
(m /s)
17.7
17.6
-0.1
-0.57%
54.9
54.7
-0.2
-0.37%
Sandy River at Winefred
Lake
Peak
3
Volume (dam ) Discharge
3
(m /s)
3599
41.5
3593
41.5
-6
0
-0.17%
0.00%
11144
129.2
11140
129.2
-4
0
-0.04%
0.00%
Monday Creek
Volume
3
(dam )
1142
1141
-1
-0.09%
3510
3510
0
0.00%
Peak
Discharge
3
(m /s)
20
20
0
0.00%
63.8
63.8
0
0.00%
Kirby Lake and Hay Lake
Drainage
Peak
Volume
Discharge
3
(dam )
3
(m /s)
858
17.6
863
17.7
5
0.1
0.58%
0.56%
2619
57.4
2628
57.6
9
0.2
* values from Project_Amendment.hms
0.34%
0.35%
Table F-4
Month
3
Update (m /s)
November
December
January
February
Mean Winter Flow
% Decrease In Flow
0.28
0.09
0.05
0.04
0.11
-0.14%
Amendment
Amendment
Update (m3/s)
(m3/s)
(m3/s)
0.28
0.61
0.61
0.09
0.20
0.21
0.05
0.11
0.11
0.04
0.07
0.07
0.11
0.25
0.25
-0.25%
Monday Creek
Update
Amendment
(m3/s)
(m3/s)
0.19
0.19
0.06
0.06
0.03
0.03
0.02
0.02
0.08
0.08
-0.48%
Kirby Lake
Update
(m3/s)
0.14
0.05
0.03
0.02
0.06
Amendment
(m3/s)
0.14
0.05
0.03
0.02
0.06
-0.24%
* values from Mean Annual Runoff Changes-Amendment.xlsx\Low Flow
Table F-5
Parameter
Area
Mean Annual
1:10 Year Rainfall Event
1:100 Year Rainfall Event
Low Flows
Amendment
Update Case
Case
2
249
Total (km )
2
232
233
Undisturbed (km )
2
17
16
Disturbed (km )
3
22317
22239
Volume (dam )
3
0.71
0.71
Flow (m /s)
-0.35%
Increase (%)
3
1674
1664
Volume (dam )
3
17.7
17.6
Flow (m /s)
-0.57%
Increase (%)
5173
5154
Volume (dam3)
3
54.9
54.7
Flow (m /s)
-0.37%
Increase (%)
3
0.11
0.11
Mean Winter Flow (m /s)
-0.14%
Decrease (%)
Kirby and Hay Lake
Sandy River at Winefred
Monday Creek
Drainage
Lake
Amendment
Amendment
Amendment
Update Case
Update Case
Update Case
Case
Case
Case
540
168
124
500
502
155
155
104
104
40
38
13
13
20
20
48108
48041
14809
14820
10976
11048
1.53
1.52
0.47
0.47
0.35
0.35
-0.14%
0.07%
0.65%
3599
3593
1142
1141
858
863
41.5
41.5
20
20
17.6
17.7
0.00%
0.00%
0.56%
11144
11140
3510
35010
2619
2628
129.2
129.2
63.8
63.8
57.4
57.6
0.00%
0.00%
0.35%
* 1:10 and 1:100 year values from Project_Amendment.hms
0.25
0.25
0.08
0.08
0.06
0.06
* mean annual values from Mean Annual Runoff Changes-Amendment.xlsx\Annual Runoff
-0.25%
-0.48%
-0.24%
* low flow values from Mean Annual Runoff Changes-Amendment.xlsx\Low Flow
* negeative percentages indicate a decrease in flow
Page 1 of 1
Attachment G
Site TSR5 Water Quality Data
Table G-1: Baseline Water Quality Results for Unnamed Tributary to the Sandy River #5
Site TSR5
Parameter
Units
Spring
26-May-12
Field Measured
Temperature
pH
Specific Conductivity
Dissolved Oxygen (DO)
°C
pH units
µS/cm
mg/L (ppm)
Conventional Parameters and Major Ions
pH
pH Units
Specific Conductivity
µS/cm
Total Dissolved Solids
mg/L (ppm)
(TDS)
Total Suspended Solids
mg/L (ppm)
(TSS)
Turbidity
NTU
Hardness
mg/L (ppm)
Alkalinity
mg/L (ppm)
Calcium
mg/L (ppm)
Magnesium
mg/L (ppm)
Potassium
mg/L (ppm)
Sodium
mg/L (ppm)
Bicarbonate
mg/L (ppm)
Carbonate
mg/L (ppm)
Chloride
mg/L (ppm)
Sulphate
mg/L (ppm)
Nutrients and Organics
Ammonia-Nitrogen
mg/L (ppm)
Nitrate-Nitrogen
mg/L (ppm)
Nitrite-Nitrogen
mg/L (ppm)
Total Kjeldahl Nitrogen
mg/L (ppm)
Phosphorus, Total
mg/L (ppm)
Biochemical Oxygen
mg/L (ppm)
Demand
Carbon (Total Organic)
mg/L (ppm)
Phenol (Total)
mg/L (ppm)
Naphthenic Acids
mg/L (ppm)
Hydrocarbons
Benzene
mg/L (ppm)
Toluene
mg/L (ppm)
Ethylbenzene
mg/L (ppm)
Total Xylenes
mg/L (ppm)
VH (C6-C10)
mg/L (ppm)
F2 - EPH (C10-C16)
mg/L (ppm)
F1 - VPH (C6-C10)
mg/L (ppm)
Polycyclic Aromatic Hydrocarbons
Acenaphthene
µg/L
Acenaphthylene
µg/L
Acridine
µg/L
Anthracene
µg/L
Benz[a]anthracene
µg/L
Benzo[a]pyrene
µg/L
Benzo[b]flouranthene
µg/L
Benzo[g,h,i]perylene
µg/L
Benzo[k]flouranthene
µg/L
Chrysene
µg/L
Dibenz[a,h]anthracene
µg/L
Fluoranthene
µg/L
Fluorene
µg/L
Indeno[1,2,3,-cd]pyrene
µg/L
Napthalene
µg/L
Phenanthrene
µg/L
Pyrene
µg/L
Quinoline
µg/L
Total Metals
Aluminum (Al)
Antimony (Sb)
Arsenic (As)
Barium (Ba)
Beryllium (Be)
Boron (B)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Copper (Cu)
Iron (Fe)
Lead (Pb)
Manganese (Mn)
Mercury (Hg)
Molybdenum (Mo)
Nickel (Ni)
Selenium (Se)
Silver (Ag)
Thallium (Tl)
Uranium
Vanadium
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
Summer
10-Aug-12
Guidelines
Fall
Aquatic Life
Winter
17-Oct-12 10-Mar-13
CCME
(2012)
Drinking Water
AENV (1999)
Acute
Chronic
Health Canada
(2012)
6.5c1
15 d1
6.5 to 8.5
-
6.5 to 8.5 b1
-
-
6.5 to 8.5
-
-
-
-
≤500 d1
120
-
-
-
d1
≤200
≤250 d1
≤500 d1
1.3 - 32.6 b3
-
0.05
10 d3
1 d3
-
0.004
-
-
0.005
-
-
< 0.001
< 0.001
< 0.001
< 0.002
< 0.050
< 0.030
< 0.050
0.37
0.002
0.09
-
-
-
0.005
≤0.0024 d1
≤0.024 d1
d1
≤0.3
-
< 0.01
< 0.01
< 0.07
< 0.007
< 0.006
< 0.005
< 0.08
< 0.02
< 0.08
< 0.01
< 0.02
< 0.04
< 0.02
< 0.02
< 0.07
< 0.01
< 0.02
< 0.06
< 0.01
< 0.01
< 0.07
< 0.007
< 0.006
< 0.005
< 0.08
< 0.02
< 0.08
< 0.01
< 0.02
< 0.04
< 0.02
< 0.02
< 0.07
< 0.01
< 0.02
< 0.06
5.8
4.4
0.012
0.018
0.015
0.04
3
1.1
0.04
0.025
3.4
-
-
-
27
< 0.05
0.2
28
< 0.1
6
< 0.015
< 0.3
0.09
0.2
1450
< 0.05
122
< 0.005
< 0.05
0.17
< 0.6
< 0.05
< 0.05
< 0.05
< 0.1
9
< 0.05
0.4
36
< 0.1
4
< 0.015
< 0.3
0.1
< 0.1
1020
< 0.05
88
< 0.005
0.1
0.11
< 0.6
< 0.05
< 0.05
< 0.05
< 0.1
5 or 100
5
1,500
0.02 a6
a5
1
a7
2
300
1 a8
0.026
73
56 a9
1
0.1
0.8
-
8.1 to 47b4
0.013
-
7c2
0.005
-
100 d4
6 d2
10 d2
d2
1,000
d2
5,000
5 d2
50 d2
≤1,000 d1
≤300 d1
10
≤50 d1
d2
1
10 d2
20
-
11.0
7.6
172
9.3
16.6
8.1
340
8.9
3.8
8.2
289
10.8
0.0
7.2
243
8.0
b1
6.5 to 9.0 6.5 to 8.5
6.5 or 9.5 a1
5.0
8.2
170
8.3
327
8.0
303
7.7
234
6.5 to 9.0
-
109
244
200
152
<2
3
80
91
22
6
< 0.5
2.7
111
<1
1.1
0.6
<2
6
194
189
55
14
0.6
3.1
230
<1
0.7
< 0.5
3
5
164
165
44
14
0.9
4.1
201
<1
4.3
4.6
6
5
136
128
37
11
1.7
2.4
156
<1
0.8
1.4
< 0.02
< 0.05
< 0.03
0.2
< 0.02
< 0.02
< 0.05
< 0.03
0.3
0.03
< 0.02
< 0.05
< 0.03
0.3
0.03
< 0.02
< 0.05
< 0.03
0.3
0.04
<2.0
10
< 0.002
<0.1
<2.0
14
< 0.002
<0.1
<2.0
24
< 0.002
1.4
13
< 0.002
0.4
< 0.001
< 0.001
< 0.001
< 0.002
< 0.050
< 0.030
< 0.050
< 0.001
< 0.001
< 0.001
< 0.002
< 0.050
< 0.030
< 0.050
< 0.001
< 0.001
< 0.001
< 0.002
< 0.050
< 0.030
< 0.050
< 0.01
< 0.01
< 0.07
< 0.007
< 0.006
< 0.005
< 0.08
< 0.02
< 0.08
< 0.01
< 0.02
< 0.04
< 0.02
< 0.02
< 0.07
< 0.01
< 0.02
< 0.06
< 0.01
< 0.01
< 0.07
< 0.007
< 0.006
< 0.005
< 0.08
< 0.02
< 0.08
< 0.01
< 0.02
< 0.04
< 0.02
< 0.02
< 0.07
< 0.01
< 0.02
< 0.06
<2
< 0.05
0.2
31
< 0.1
10
< 0.015
< 0.3
< 0.02
0.1
280
< 0.05
30
< 0.005
0.1
< 0.05
< 0.6
< 0.05
< 0.05
< 0.05
< 0.1
<2
< 0.05
0.7
65
< 0.1
12
< 0.015
< 0.3
0.06
< 0.1
1470
< 0.05
138
< 0.005
0.18
0.1
< 0.6
< 0.05
< 0.05
< 0.05
< 0.1
7.0 - 48.3
2.9(a3)
0.06(a4)
-
a2
a5
d1
d1
Page 1 of 2
Site TSR5
Parameter
Units
Spring
26-May-12
Zinc (Zn)
Summer
10-Aug-12
Guidelines
Fall
Aquatic Life
Winter
17-Oct-12 10-Mar-13
CCME
(2012)
Drinking Water
AENV (1999)
µg/L
< 0.5
< 0.5
4.9
< 0.5
30
Acute
-
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
µg/L
<2
< 0.05
0.2
32
< 0.1
6
< 0.015
< 0.3
< 0.02
0.3
150
< 0.05
20
< 0.005
0.1
< 0.05
< 0.6
< 0.05
< 0.05
< 0.05
< 0.05
< 0.5
<2
< 0.05
0.6
67
< 0.1
11
< 0.015
< 0.3
0.07
< 0.1
260
< 0.05
131
< 0.005
0.26
0.3
< 0.6
< 0.05
< 0.05
0.09
< 0.05
1.6
<2
< 0.05
0.3
42
< 0.1
7
< 0.015
< 0.3
0.05
< 0.1
385
< 0.05
106
< 0.005
0.13
0.1
< 0.6
< 0.05
< 0.05
0.05
< 0.05
2
<2
< 0.05
0.3
35
< 0.1
2
< 0.015
< 0.3
0.1
0
429
< 0.05
84
< 0.005
0.1
0.1
< 0.6
< 0.05
< 0.05
< 0.05
< 0.05
1.9
-
-
Chronic
-
Health Canada
(2012)
≤5,000 d1
Dissolved Metals
Aluminum (Al)
Antimony (Sb)
Arsenic (As)
Barium (Ba)
Beryllium (Be)
Boron (B)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Copper (Cu)
Iron (Fe)
Lead (Pb)
Manganese (Mn)
Mercury (Hg)
Molybdenum (Mo)
Nickel (Ni)
Selenium (Se)
Silver (Ag)
Thallium (Tl)
Uranium
Vanadium
Zinc (Zn)
-
Notes:
Shaded and Bolded cells indicates an aquatic life guideline exceedance.
Shaded and Italicized cells indicates a drinking water guideline exceedance.
* = The method detection limit for this parameter is higher than or equal to an applicable guideline, therefore it is unknown if there is an exceedance.
Part 1. Water Quality Guidelines for the Protection of Aquatic Life
Canadian Environmental Quality Guidelines - CEQG (CCME 2007)
a1 = Guideline is based on temperature preferences of biota. In this case, the cold water biota guidelines for both early life and other life stages are
shown.
a2 = Guideline is dependent on temperature and pH. The value ranges between 6.98 mg/L (pH= 7.0, temperature= 15 oC) and
48.3 mg/L (pH= 6.5, temperature= 5oC).
a3 = Guideline is converted to Nitrate-N.
a4 = Guideline is converted to Nitrite-N.
a5 = Guideline = 5 μg/L at pH < 6.5, [Ca 2+] < 4 mg/L and DOC < 2 mg/L; Guideline = 100 μg/L at pH ≥ 6.5, [Ca 2+] ≥4 mg/L and DOC ≥ 2 mg/L.
a6 = Cadmium guideline = 10 [0.86 [log(hardness)] - 3.2]. Conservatively, the lowest recorded hardness for this site was used to calculate the guideline.
a7 = Guideline is for hexavalent chromium (Cr VI) because its guideline is more stringent than the trivalent chromium (Cr III) guideline of 8.9 μg/L.
a8 = Copper guideline is dependent on [CaCO3] with a minimum of 2 µg/L. Guideline = e 0.8545[ln(hardness)]-1.465*0.2. Conservatively, the lowest recorded
hardness for this site was used to calculate the guidelines.
a9 = Lead guideline is dependent on [CaCO3]. Guideline = e 1.273[ln(hardness)]-4.705. Conservatively, the lowest recorded hardness for this site was used to
calculate the guideline.
0.76[ln(hardness)]+1.06
. Conservatively, the lowest
a10 = Nickel guideline is dependent on [CaCO 3]. Nickel guideline is dependent on [CaCO3]. Guideline = e
recorded hardness for this site was used to calculate the guideline.
Alberta Acute Water
b1 = The pH is to be in the range of 6.5 to 8.5 but not altered by more than 0.5 pH units from background values.
b2 = Not to be increased by more than 10 mg/L (ppm) over background value.
b3 = USEPA Guideline. Acute values based on one-hour average concentration of total ammonia-nitrogen (mg nitrogen/L). The guideline is dependant
on pH and the presence of salmonids, ranging from 0.88 mg/L (ppm) (pH = 9.0; salmonids present) to 48.8 mg/L (ppm) (pH = 6.5; no salmonids
present). To find the corresponding guideline value, the following equations are used: [Max salmonids present] = 0.275 / (1 + 107.204 - pH) + 39.0 / (1
+ 10pH - 7.204) & [Max no salmonids present] = 0.411 / (1 + 107.204-pH) + 58.4 / (1 + 10pH - 7.204).
b4 = Acute guideline is dependant on hardness and applies to acid-extractable copper concentrations governed by the following equation:
[Max] = e[0.979123 * ln(hardness) - 8.64497]. The copper guideline ranges from 8.1 µg/L (hardness = 50 mg/L (ppm)) to 47 µg/L
(hardness = 300 mg/L (ppm)).
Alberta Chronic Water
c1 = Seven day mean. The chronic guidelines should be increased to 8.3 mg/L from mid May to the end of June to protect the emergence of mayfly
species into adults; it should be increased to 9.5 mg/L for those areas and times where embryonic and larval stages develop within gravel beds
(some salmonids).
c2 = The evaluation of chronic copper toxicity in soft water was inconclusive; the chronic guideline can therefore only be applied at water hardness
equal to or greater than 50 mg/L as CaCO 3.
Guideline for Canadian Drinking Water Quality - GCDWQ (Health Canada 2008)
d1 = Aesthetic objective.
d2 = Maximum allowable concentration (MAC).
d3 = Equivalent to 10 mg/L as nitrate-nitrogen. Where nitrate and nitrite are determined separately, levels of nitrite should not exceed 3.2 mg/L.
d4 = A health-based guideline for aluminum in drinking water has not been established. Operational guidance values of less than 100 μg/L total
aluminum for conventional treatment plants and less than 200 μg/L total aluminum for other types of treatment systems are recommended.
Page 2 of 2
Table G-2: Baseline Sediment Quality for Unnamed Tributary to the Sandy River #5
Parameter
Units
TSR5
17-Oct-12
CCME Interim Sediment
Quality Guidelines
(2002)
Texture and Carbon Content
%
%
%
% by wt
98
2
<1
0.18
-
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
< 0.005
< 0.03
< 0.01
< 0.03
< 5.0
< 5.0
< 30
< 30
< 30
-
Acenaphthene
Acenaphthylene
Anthracene
Benzo(a)anthracene
Benzo(a)pyrene
Benzo(c)phenanthrene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Benzo[b+j]fluoranthene
Chrysene
Dibenzo(a,h)anthracene
Dibenzo(a,h)pyrene
Dibenzo(a,i)pyrene
Dibenzo(a,l)pyrene
7,12 Dimethyl benzanthracene
Fluoranthene
Fluorene
Indeno(1,2,3-cd)pyrene
2-Methylnaphthalene
Naphthalene
Phenanthrene
Pyrene
Total Metals
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
µg/kg (ppb)
<50 *
<50 *
<4.6
<100
<50 *
<100
<100
<50
<50
<50
<100 *
<100
<100
<100
<100
<32
<50 *
<100
<100
<13
<46 *
<34
6.71 a1
5.87 a1
a1
46.9
31.7
31.9
Antimony (Sb)
Aluminum (Al)
Arsenic (As)
Barium (Ba)
Beryllium (Be)
Cadmium (Cd)
Calcium (Ca)
Chromium (Cr)
Cobalt (Co)
Copper (Cu)
Iron (Fe)
Lead (Pb)
Magnesium (Mg)
Manganese (Mn)
Mercury (Hg)
Molybdenum (Mo)
Nickel (Ni)
Phosphorus (P)
Potassium (K)
Selenium (Se)
Silver (Ag)
Sodium (Na)
Thallium (Tl)
Tin (Sn)
Uranium
Vanadium
Zinc (Zn)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
µg/g (ppm)
< 0.5
513
1.7
17
< 0.1
< 0.2
593
0.9
0.7
0.2
4700
< 0.5
284
115
< 0.2
< 0.5
0.6
108
53
< 0.5
8
< 0.1
< 0.5
< 0.5
1.3
< 15.0
2.8
5.9
0.6
37.3
35.7
35.0
0.17
123
Texture - Sand
Texture - Silt
Texture - Clay
Total Organic Carbon
Hydrocarbons
Benzene
Toluene
Ethylbenzene
Total Xylenes
F1 - VPH (C6-C10)
F1 - VPH (C6-C10) - BTEX
F2 - EPH (C10-C16)
F3 - EPH (C16-C34)
F4 - EPH (C34-C50)
Polycyclic Aromatic Hydrocarbons
57.1
6.22 a1
111
21.2 a1
a1
20.2
34.6 a1
41.9
53.0
Notes:
Shaded and Bolded cells indicates an aquatic life guideline exceedance.
* = The method detection limit for this parameter is higher than or equal to an applicable guideline, there
Canadian Interim Freshwater Sediment Quality Guidelines for the Prote
a1: Provisional, adoption of marine Interim sediment quality guideline
Page 1 of 1

Attachment A Amendment Application Concordance

Transcription

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